PIONEER ENERGY SERVICES CORP - FORM 10-Q

Attached files

file	filename
EX-32.2 - EXHIBIT 32.2 - PIONEER ENERGY SERVICES CORP	exhibit3223q2018.htm
EX-32.1 - EXHIBIT 32.1 - PIONEER ENERGY SERVICES CORP	exhibit3213q2018.htm
EX-31.2 - EXHIBIT 31.2 - PIONEER ENERGY SERVICES CORP	exhibit3123q2018.htm
EX-31.1 - EXHIBIT 31.1 - PIONEER ENERGY SERVICES CORP	exhibit3113q2018.htm

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 September 30, 2018



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

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 and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes 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 October 15, 2018, there were 78,214,550 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



	September 30, 2018			December 31, 2017
	(unaudited)			(audited)
	(in thousands, except share data)
ASSETS
Current assets:
Cash and cash equivalents	$	51,468		$	73,640
Restricted cash	2,000			2,008
Receivables:
Trade, net of allowance for doubtful accounts	86,372			79,592
Unbilled receivables	24,204			16,029
Insurance recoveries	23,605			13,874
Other receivables	5,499			3,510
Inventory	18,992			14,057
Assets held for sale	6,102			6,620
Prepaid expenses and other current assets	5,634			6,229
Total current assets	223,876			215,559
Property and equipment, at cost	1,098,996			1,093,635
Less accumulated depreciation	571,736			544,012
Net property and equipment	527,260			549,623
Other noncurrent assets	1,739			1,687
Total assets	$	752,875		$	766,869

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	34,747		$	29,538
Deferred revenues	1,130			905
Accrued expenses:
Payroll and related employee costs	28,161			21,023
Insurance claims and settlements	23,494			13,289
Insurance premiums and deductibles	5,433			6,742
Interest	1,684			6,624
Other	9,176			6,793
Total current liabilities	103,825			84,914
Long-term debt, less unamortized discount and debt issuance costs	463,805			461,665
Deferred income taxes	3,344			3,151
Other noncurrent liabilities	3,404			7,043
Total liabilities	574,378			556,773
Commitments and contingencies (Note 10)
Shareholders’ equity:
Preferred stock, 10,000,000 shares authorized; none issued and outstanding	—			—
Common stock $.10 par value; 200,000,000 shares authorized; 78,214,550 and 77,719,021 shares outstanding at September 30, 2018 and December 31, 2017, respectively	7,900			7,835
Additional paid-in capital	549,500			546,158
Treasury stock, at cost; 789,532 and 630,688 shares at September 30, 2018 and December 31, 2017, respectively	(4,965		)	(4,416		)
Accumulated deficit	(373,938		)	(339,481		)
Total shareholders’ equity	178,497			210,096
Total liabilities and shareholders’ equity	$	752,875		$	766,869

See accompanying notes to condensed consolidated financial statements.

PIONEER ENERGY SERVICES CORP. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(unaudited)



	Three months ended September 30,						Nine months ended September 30,
	2018			2017			2018			2017
	(in thousands, except per share data)

Revenues	$	149,332		$	117,281		$	448,592		$	320,168

Costs and expenses:
Operating costs	108,961			86,669			325,924			238,456
Depreciation and amortization	23,501			24,623			70,535			74,355
General and administrative	14,043			17,549			58,066			51,405
Bad debt expense (recovery), net	111			491			(311		)	(98		)
Impairment	239			—			2,607			795
Gain on dispositions of property and equipment, net	(1,861		)	(1,159		)	(2,922		)	(2,251		)
Total costs and expenses	144,994			128,173			453,899			362,662
Income (loss) from operations	4,338			(10,892		)	(5,307		)	(42,494		)

Other income (expense):
Interest expense, net of interest capitalized	(9,811		)	(6,613		)	(28,966		)	(19,090		)
Other income, net	498			295			1,046			224
Total other expense, net	(9,313		)	(6,318		)	(27,920		)	(18,866		)

Loss before income taxes	(4,975		)	(17,210		)	(33,227		)	(61,360		)
Income tax expense	(258		)	(17		)	(1,297		)	(1,200		)
Net loss	$	(5,233	)	$	(17,227	)	$	(34,524	)	$	(62,560	)

Loss per common share - Basic	$	(0.07	)	$	(0.22	)	$	(0.44	)	$	(0.81	)

Loss per common share - Diluted	$	(0.07	)	$	(0.22	)	$	(0.44	)	$	(0.81	)

Weighted average number of shares outstanding—Basic	78,136			77,552			77,897			77,335

Weighted average number of shares outstanding—Diluted	78,136			77,552			77,897			77,335

See accompanying notes to condensed consolidated financial statements.

PIONEER ENERGY SERVICES CORP. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited)



	Nine months ended September 30,
	2018			2017
	(in thousands)
Cash flows from operating activities:
Net loss	$	(34,524	)	$	(62,560	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depreciation and amortization	70,535			74,355
Allowance for doubtful accounts, net of recoveries	(311		)	(98		)
Gain on dispositions of property and equipment, net	(2,922		)	(2,251		)
Stock-based compensation expense	3,396			3,225
Phantom stock compensation expense	2,807			397
Amortization of debt issuance costs and discount	2,153			1,395
Impairment	2,607			795
Deferred income taxes	189			434
Change in other noncurrent assets	541			335
Change in other noncurrent liabilities	(735		)	(261		)
Changes in current assets and liabilities:
Receivables	(16,549		)	(38,848		)
Inventory	(4,934		)	(2,098		)
Prepaid expenses and other current assets	329			1,594
Accounts payable	1,527			11,360
Deferred revenues	(173		)	(470		)
Accrued expenses	(2,446		)	1,434
Net cash provided by (used in) operating activities	21,490			(11,262		)

Cash flows from investing activities:
Purchases of property and equipment	(48,778		)	(52,806		)
Proceeds from sale of property and equipment	4,665			10,407
Proceeds from insurance recoveries	980			3,119
Net cash used in investing activities	(43,133		)	(39,280		)

Cash flows from financing activities:
Debt repayments	—			(13,267		)
Proceeds from issuance of debt	—			65,000
Proceeds from exercise of options	12			—
Purchase of treasury stock	(549		)	(533		)
Net cash provided by (used in) financing activities	(537		)	51,200

Net increase (decrease) in cash, cash equivalents and restricted cash	(22,180		)	658
Beginning cash, cash equivalents and restricted cash	75,648			10,194
Ending cash, cash equivalents and restricted cash	$	53,468		$	10,852

Supplementary disclosure:
Interest paid	$	31,872		$	22,928
Income tax paid	$	2,739		$	847
Noncash investing and financing activity:
Change in capital expenditure accruals	$	3,564		$	1,396

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. In addition to our drilling rigs, we provide the drilling crews and most of the ancillary equipment needed to operate our drilling rigs. All of our rigs are equipped with 1,500 horsepower or greater drawworks. Our drilling rig fleet is 100% pad-capable and offers 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	16	—	16
International drilling	—	8	8
			24

In July 2018, we entered into a three-year term contract for the construction of a new 1,500 horsepower, AC pad-optimal rig, which we expect to deploy in early 2019 to the Permian Basin.

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 September 30, 2018, 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			104
Coiled tubing services units			8

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, 2017.

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 September 30, 2018, 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.

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). We revised our segments as of December 31, 2017 to reflect changes in the basis used by management in making decisions regarding our business for resource allocation and performance assessment. These changes reflect our current operating focus as is required by ASC Topic 280, Segment Reporting. See Note 9, Segment Information for this revised 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.

•

Revenue Recognition. In May 2014, the FASB issued ASU No. 2014-09, a comprehensive new revenue recognition standard that supersedes nearly all pre-existing revenue recognition guidance. The standard, and its related amendments, collectively referred to as ASC Topic 606, outlines a single comprehensive model for revenue recognition based on the core principle that a company will recognize revenue when promised goods or services are transferred to clients, in an amount that reflects the consideration to which an entity expects to be entitled in exchange for those goods or services.

We adopted this standard effective January 1, 2018 using the modified retrospective method, in which the standard has been applied to all contracts existing as of the date of initial application, with the cumulative effect of applying the standard recognized in retained earnings. Accordingly, revenues for reporting periods ending after January 1, 2018 are presented under ASC Topic 606, while prior period amounts have not been adjusted and continue to be reported under the previous revenue recognition guidance. In accordance with ASC Topic 606, we also adopted ASC Subtopic 340-40, Other Assets and Deferred Costs, Contracts with Customers, effective January 1, 2018, which requires that the incremental costs of obtaining or fulfilling a contract with a customer be recognized as an asset if the costs are expected to be recovered.

The adoption of these standards resulted in a cumulative effect adjustment of $0.1 million after applicable income taxes, which consists of the impact of the timing difference related to recognition of mobilization revenues and costs. Mobilization costs incurred are deferred and amortized over the expected period of benefit under ASC Subtopic 340-40, but were amortized over the initial contract term under the previous accounting guidance. The recognition of both mobilization revenues and costs begins when mobilization activity is completed under ASC Topic 606, but were recognized during the period of initial mobilization under the previous accounting guidance. Additionally, the opening balances of deferred mobilization costs were reclassified in accordance with ASC Subtopic 340-40, which requires classification of the entire deferred balance according to the duration of the original contract to which it relates, rather than bifurcating the asset into current and noncurrent portions.

For more information about the accounting under ASC Topic 606, and disclosures under the new standard, see Note 2, Revenue from Contracts with Customers.


•	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 current lease standard, and aligns the principles of lessor accounting with the principles of the FASB’s new revenue guidance (referenced above).

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 expect to apply the practical expedient which would allow 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 consolidated statements of operations.

As a lessee, this standard will primarily impact our accounting for real estate and office equipment leases, for which we will recognize a right-of-use asset and a corresponding lease liability on our consolidated balance sheet. The future lease obligations disclosed in Note 4, Leases, included in Part II, Item 8, of our Annual Report on Form 10-K for the year ended December 31, 2017, provides some insight to the estimated impact of adoption for us as a lessee. We are currently in the process of implementing a lease accounting system for our leases, converting our existing lease data to the new system and implementing relevant internal controls and procedures. We expect to apply this guidance prospectively, beginning January 1, 2019.

Additional Detail of Account Balances and Related-Party Transactions

Cash and Cash Equivalents — As of September 30, 2018, we had $40.4 million of cash equivalents, consisting of investments in highly-liquid money-market mutual funds. We had no cash equivalents at December 31, 2017.

Restricted Cash — 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, which we expect to complete within 12 months. Accordingly, the related restricted cash is presented as current in the accompanying condensed consolidated balance sheets.

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

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

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

Other Accrued Expenses — Our other accrued expenses include accruals for items such as property taxes, sales 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.

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

Related-Party Transactions — During both the nine months ended September 30, 2018 and 2017, the Company paid approximately $0.1 million for trucking and equipment rental services, which represented arms-length transactions, to Gulf Coast Lease Service. Joe Freeman, our Senior Vice President of Well Servicing, serves as the President of Gulf Coast Lease Service, which is owned and operated by Mr. Freeman’s two sons. Mr. Freeman does not receive compensation from Gulf Coast Lease Service, and he serves primarily in an advisory role to his sons.

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. We provide the drilling rig, crew and supplies 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 September 30, 2018 and January 1, 2018 were as follows (amounts in thousands):



	September 30, 2018		January 1, 2018
Current deferred revenues	$	1,130	$	1,287
Current deferred costs	1,136		1,072

Noncurrent deferred revenues	$	437	$	564
Noncurrent deferred costs	662		1,177

The changes in deferred revenue and cost balances during the three and nine months ended September 30, 2018 are primarily related to the amortization of deferred revenues and costs during the period, which were partially offset by the increase in deferred mobilization revenue and cost balances for the deployment of two international rigs under new term contracts in 2018. Amortization of deferred revenues and costs during the three and nine months ended September 30, 2018 and 2017 were as follows (amounts in thousands):



	Three months ended September 30,				Nine months ended September 30,
	2018		2017		2018		2017
Amortization of deferred revenues	$	720	$	562	$	1,762	$	1,859
Amortization of deferred costs	1,100		1,311		2,050		3,997

As of September 30, 2018, all 16 of our domestic drilling rigs are operating under daywork contracts, 14 of which are term contracts, and six of our eight international drilling rigs are operating under term daywork contracts. The term contracts for our international drilling rigs 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. Revenues associated with the initial mobilization and/or demobilization of drilling rigs under cancelable contracts are deferred and recognized ratably over the anticipated duration of the original contract, which is the period during which we expect our client to benefit from the mobilization of the rig, and represents a separate performance obligation because the payment for mobilization and/or demobilization creates a material right to our client during the cancelable period, for which the transaction price is allocated to the optional goods and services expected to be provided.

Remaining Performance Obligations

We have elected to apply the practical expedients in ASC Topic 606 which allow entities to omit disclosure of (i) the transaction price allocated to the remaining performance obligations associated with short-term contracts, and (ii) the estimated variable consideration related to wholly unsatisfied performance obligations, or to distinct future time increments within a series of performance obligations. Therefore, we have not disclosed the remaining amount of fixed mobilization revenue (or estimated future variable demobilization revenue) associated with short-term contracts, and we have not disclosed an estimate of the amount of future variable dayrate drilling revenue. However, the amount of fixed mobilization revenue associated with remaining performance obligations is reflected in the net unamortized balance of deferred mobilization revenues, which is presented in both current and noncurrent portions in our condensed consolidated balance sheet, and discussed in more detail in the section above entitled, Contract Asset and Liability Balances and Contract Cost Assets.

Disaggregation of Revenue

ASC Topic 606 requires disclosure of the disaggregation of revenue into categories that depict how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. We believe the disclosure of revenues by operating segment achieves the objective of this disclosure requirement. See Note 9, Segment Information, for the disaggregation of revenues by operating segment, which reflects the disaggregation of revenues by the type of services provided and by geography (international versus domestic).

Impact of ASC Topic 606 on Financial Statement Line Items and Disclosures

Our revenue recognition pattern under ASC Topic 606 is similar to revenue recognition under the previous accounting guidance, except for: (i) the timing of recognition of demobilization revenues which are estimated and recognized ratably over the term of the related contract under ASC Topic 606, and constrained when appropriate, but were previously not recognized until the activity was performed under previous guidance; (ii) the timing of recognition of mobilization revenues and costs which are recognized over the applicable amortization period beginning when the initial mobilization of the rig

is completed, but which, under previous guidance, we recognized over the related contract term beginning when the initial mobilization activity commenced, (iii) the timing of recognition of mobilization costs which are deferred and recognized ratably over the expected period of benefit, but which, under previous guidance, we recognized ratably over the term of the initial contract; and (iv) presentation of mobilization costs which are presented as either current or noncurrent according to the duration of the original contract to which it relates under ASC Topic 606, but which we bifurcated and presented both current and noncurrent portions in separate line items under previous guidance.

These differences have not had a material impact on our condensed consolidated financial position or results of operations as of and for the three and nine months ended September 30, 2018. Additionally, we have determined that any disclosures required by ASC Topic 606 which are not presented herein are either not applicable, or are not material.

3. Property and Equipment

Capital Expenditures — Our capital expenditures were $52.3 million and $54.2 million during the nine months ended September 30, 2018 and 2017, respectively, which includes $0.2 million and $0.4 million, respectively, of capitalized interest. Capital expenditures during the nine months ended September 30, 2018 primarily related to various routine expenditures to maintain our fleets and purchase new support equipment, as well as the expansion of our coiled tubing and wireline fleets, capital projects to upgrade and refurbish certain components of our international and domestic drilling rigs and begin construction of one new-build drilling rig, and vehicle fleet upgrades in all domestic business segments. Capital expenditures during the nine months ended September 30, 2017 primarily related to the acquisition of 20 well servicing rigs and expansion of our wireline fleet, upgrades to certain domestic drilling rigs, routine capital expenditures necessary to deploy rigs that were previously idle in Colombia, and other new drilling equipment.

At September 30, 2018, capital expenditures incurred for property and equipment not yet placed in service was $18.1 million, primarily related to installments of $4.0 million on the purchase of a new coiled tubing unit and new wireline unit, approximately $4.0 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. At December 31, 2017, property and equipment not yet placed in service was $6.8 million, primarily related to routine refurbishments on one international drilling rig in preparation for its deployment in 2018, installments on the purchase of three wireline units and one coiled tubing unit, and scheduled refurbishments on drilling and production services equipment.

Gain/Loss on Disposition of Property — During the nine months ended September 30, 2018, we recognized net gains of $2.9 million on the disposition of various property and equipment, including the sale of five coiled tubing units, twelve wireline units, and one drilling rig which was previously held for sale. During the nine months ended September 30, 2017, we recognized a net gain of $2.3 million on the disposition of property and equipment, including sales of certain coiled tubing equipment and vehicles, as well as the loss of drill pipe in operation, for which we were reimbursed by the client, and the disposal of two cranes that were damaged.

Assets Held for Sale — As of September 30, 2018, our condensed consolidated balance sheet reflects assets held for sale of $6.1 million, which primarily represents the fair value of two domestic SCR drilling rigs and one domestic mechanical drilling rig, as well as other drilling equipment, and three coiled tubing units. During the nine months ended September 30, 2018 and 2017, we recognized impairment charges of $2.6 million and $0.8 million, respectively, 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.

As of December 31, 2017, our condensed consolidated balance sheet reflects assets held for sale of $6.6 million, which primarily represents the fair value of three domestic SCR drilling rigs and one domestic mechanical drilling rig, as well as other drilling equipment, two wireline units and one coiled tubing unit and other spare equipment.

Impairments — In accordance with ASC Topic 360, Property, Plant and Equipment, we monitor all indicators of potential impairments and 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.

Due to adverse factors currently affecting our well servicing operations, including increased competition and labor shortages in certain well servicing markets, and lower than anticipated utilization, all of which contributed to a decline in our projected cash flows for the well servicing reporting unit, we performed an impairment analysis of this reporting unit at September 30, 2018. As a result of this analysis, we concluded that this reporting unit was not at risk of impairment because the sum of the estimated future undiscounted net cash flows for our well servicing reporting unit was significantly in excess of the carrying amount.

The most significant inputs used in our impairment analysis of our well servicing operations include the projected utilization and pricing of our services, 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.


4.	Valuation Allowances on Deferred Tax Assets and Recently Enacted Tax Reform

Valuation Allowances on Deferred Tax Assets

In performing this analysis as of September 30, 2018 in accordance with ASC Topic 740, Income Taxes, we assessed the available positive and negative evidence to estimate whether sufficient future taxable income will be generated to permit the use of deferred tax assets. A significant piece of negative evidence evaluated is the cumulative loss incurred during previous years. Such negative evidence limits the ability to consider other positive evidence that is subjective, such as projections for taxable income in future years. As a result, we would recognize a benefit only to the extent that reversals of deferred income tax liabilities are expected to generate taxable income in each relevant jurisdiction in future periods which would offset our deferred tax assets.

Our domestic federal net operating losses generated through 2017 have a 20 year carryforward period and can be used to offset future domestic taxable income until their expiration, beginning in 2030, with the latest expiration in 2037. Losses generated after 2017 have an unlimited carryforward period and are limited in usage to 80% of taxable income (pursuant to the Tax Reform Act mentioned below). The majority of our foreign net operating losses generated through 2016 have an indefinite carryforward period, while losses generated after 2016 have a carryforward period of 12 years. As of September 30, 2018, we have a valuation allowance that fully offsets our foreign and domestic federal deferred tax assets.

During the three and nine months ended September 30, 2018, we released $0.6 million and provided for $5.1 million, respectively, of valuation allowance on deferred tax assets. During the three and nine months ended September 30, 2017, we provided valuation allowance adjustments on deferred tax assets of $5.9 million and $19.1 million, respectively. The valuation allowance is the primary factor causing our effective tax rate to be significantly lower than the statutory rate. The amount of the deferred tax asset considered realizable, however, would increase if cumulative losses are no longer present and additional weight is given to subjective evidence in the form of projected future taxable income.

Recently Enacted Tax Reform

On December 22, 2017, the Tax Cuts and Jobs Act of 2017 (the “Tax Reform Act”) was enacted. The legislation significantly changes U.S. tax law by, among other things, permanently reducing the U.S. corporate income tax rate from a maximum of 35% to a flat rate of 21%, repealing the alternative minimum tax (AMT), implementing a territorial tax system and imposing a repatriation tax on deemed repatriated earnings of foreign subsidiaries, limiting the current deductibility of net interest expense in excess of 30% of adjusted taxable income, and limiting net operating losses generated after 2017 to 80% of taxable income.

Territorial Tax System — To minimize tax base erosion with a territorial tax system, beginning in 2018, the Tax Reform Act provides for a new global intangible low-taxed income (GILTI) provision. Under the GILTI provision, certain foreign subsidiary earnings in excess of an allowable return on the foreign subsidiary’s tangible assets are included in U.S. taxable income. We are now subject to GILTI, but have not yet triggered an income inclusion as of September 30, 2018. Any future inclusion is expected to be offset by net operating loss carry forwards in the U.S.

Limitation on Interest Expense Deduction — The new limitation on interest expense resulted in a $22.1 million disallowance for the nine month period ended September 30, 2018; however, this adjustment is offset fully by our net operating loss carry forwards. The disallowed interest has an indefinite carry forward period and any limitations on the utilization of this interest expense carryforward have been factored into our valuation allowance analysis.

Limitation on Future Net Operating Losses Deduction — Net operating losses generated after 2017 are carried forward indefinitely and are limited to 80% of taxable income. Net operating losses generated prior to 2018 continue to be carried forward for 20 years and have no 80% limitation on utilization.

Measurement Period — Given the significance of the legislation, the SEC staff issued Staff Accounting Bulletin No. 118 (SAB 118), which allows registrants to record provisional amounts during a one year “measurement period” similar to that used when accounting for business combinations. However, the measurement period is deemed to have ended earlier when the registrant has obtained, prepared and analyzed the information necessary to finalize its accounting. During the measurement period, impacts of the law are expected to be recorded at the time a reasonable estimate for all or a portion of the effects can be made, and provisional amounts can be recognized and adjusted as information becomes available, prepared or analyzed. SAB 118 summarizes a three-step process to be applied at each reporting period to account for and qualitatively disclose: (1) the effects of the change in tax law for which accounting is complete; (2) provisional amounts (or adjustments to provisional amounts) for the effects of the tax law where accounting is not complete, but that a reasonable estimate has been determined; and (3) a reasonable estimate cannot yet be made and therefore taxes are reflected in accordance with law prior to the enactment of the Tax Reform Act.

Our accounting is complete as of September 30, 2018 and December 31, 2017 as related to the Tax Reform Act, except as it relates to the GILTI tax. Absent any further interpretive guidance, we expect to make a policy election to treat the GILTI tax as a period expense rather than to provide U.S. deferred taxes on foreign temporary differences that are expected to generate GILTI income when they reverse in future years.

5. Debt

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



	September 30, 2018			December 31, 2017
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%)	(2,855		)	(3,387		)
Less unamortized debt issuance costs	(8,340		)	(9,948		)
	$	463,805		$	461,665

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 Revolving 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 September 30, 2018, we had $9.7 million in committed letters of credit, which, after borrowing base limitations, resulted in borrowing availability of $57.6 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 11, 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.


6.	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 September 30, 2018 and December 31, 2017, the aggregate estimated fair value of our phantom stock unit awards was $10.2 million and $6.1 million, respectively, for which the vested portion recognized as a liability in our condensed consolidated balance sheets was $6.4 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 8, 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):



		September 30, 2018				December 31, 2017
	Hierarchy Level	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Senior notes	2	$	296,781	$	265,125	$	296,181	$	243,948
Senior secured term loan	3	167,024		$	180,031	165,484		171,613
		$	463,805	$	445,156	$	461,665	$	415,561


7.	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 September 30,						Nine months ended September 30,
	2018			2017			2018			2017
Numerator (both basic and diluted):
Net loss	$	(5,233	)	$	(17,227	)	$	(34,524	)	$	(62,560	)
Denominator:
Weighted-average shares (denominator for basic earnings (loss) per share)	78,136			77,552			77,897			77,335
Dilutive effect of outstanding stock options, restricted stock and restricted stock unit awards	—			—			—			—
Denominator for diluted earnings (loss) per share	78,136			77,552			77,897			77,335
Loss per common share - Basic	$	(0.07	)	$	(0.22	)	$	(0.44	)	$	(0.81	)
Loss per common share - Diluted	$	(0.07	)	$	(0.22	)	$	(0.44	)	$	(0.81	)
Potentially dilutive securities excluded as anti-dilutive	3,964			4,612			4,895			5,167


8.	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, 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 (benefit) recognized for phantom stock unit awards during the three and nine months ended September 30, 2018 and 2017 (amounts in thousands):



	Three months ended September 30,					Nine months ended September 30,
	2018			2017		2018		2017
Stock option awards	$	101		$	249	$	342	$	726
Restricted stock awards	116			116		344		345
Restricted stock unit awards	823			525		2,710		2,154
	$	1,040		$	890	$	3,396	$	3,225
Phantom stock unit awards	$	(3,722	)	$	878	$	2,807	$	397

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. There were no stock options granted during the nine months ended September 30, 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 restricted stock unit awards granted during the three months ended September 30, 2018 or 2017. The following table summarizes the number and weighted-average grant-date fair value of the restricted stock and restricted stock unit awards granted during the nine months ended September 30, 2018 and 2017:



	Nine months ended September 30,
	2018		2017
Restricted Stock:
Restricted stock awards granted	78,632		167,272
Weighted-average grant-date fair value	$	5.85	$	2.75
Time-based RSUs:
Time-based RSUs granted	788,377		96,728
Weighted-average grant-date fair value	$	3.85	$	5.61
Performance-based RSUs:
Performance-based RSUs granted	—		563,469
Weighted-average grant-date fair value	$	—	$	7.75

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 generally cliff vest after 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.

Approximately half of the performance-based RSUs outstanding are subject to a market condition based on relative total shareholder return, as compared to that of our predetermined peer group, and therefore the fair value of these awards is measured using a Monte Carlo simulation model. Compensation expense for equity awards with a market condition is reduced only for actual forfeitures; no adjustment to expense is otherwise made, regardless of the number of shares issued. The remaining performance-based RSUs are subject to performance conditions, based on our EBITDA and EBITDA return on capital employed, relative to our predetermined peer group, and therefore the fair value is based on the closing price of our common stock on the date of grant, applied to the estimated number of shares that will be awarded. Compensation expense ultimately recognized for awards with performance conditions will be equal to the fair value of the restricted stock unit award based on the actual outcome of the service and performance conditions.

In April 2018, we determined that 106% of the target number of shares granted during 2015 were actually earned based on the Company’s achievement of the performance measures as described above. As of September 30, 2018, 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

In 2016 and 2018, we granted 1,268,068 and 1,188,216 phantom stock unit awards with weighted-average grant-date fair values of $1.35 and $3.06 per share, respectively. These awards cliff-vest after 39 months from the date of grant, with vesting based on time of service, performance and market conditions. The number of 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, and 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 a maximum of $8.08 and $9.66 (which is four and three times the grant date stock price), respectively.

The fair value of these awards is measured using inputs that are defined as Level 3 inputs under ASC Topic 820, Fair Value Measurements and Disclosures. Half of the 2016 phantom stock unit awards are subject to a market condition based on relative total shareholder return, and therefore the fair values of these awards are measured using a Monte Carlo simulation model, which incorporates the estimate of our relative total shareholder return achievement level. The remaining 2016

phantom stock unit awards are subject to performance conditions, based on our relative EBITDA and EBITDA return on capital employed, and the fair values of these awards are measured using a Black-Scholes pricing model. The 2018 phantom stock unit awards will vest based upon our relative total shareholder return and relative EBITDA return on capital, both of which are subject to market conditions, and therefore, the fair value of these awards is measured using a Monte Carlo simulation model which generates a fair value that incorporates the relative estimated achievement levels. As of September 30, 2018, we estimate the achievement levels for our outstanding 2016 and 2018 phantom stock unit awards to be 188% and 100%, respectively.

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 $2.95 as of September 30, 2018, if all other inputs were unchanged, would result in an increase in cumulative compensation expense of $2.1 million, which represents the hypothetical increase in fair value of the liability for all outstanding phantom stock unit awards. The maximum payout feature of these awards would limit this volatility if the stock price exceeds the maximum payout threshold.


9.	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). We revised our segments as of December 31, 2017 to reflect changes in the basis used by management in making decisions regarding our business for resource allocation and performance assessment. These changes reflect our current operating focus as is required by ASC Topic 280, Segment Reporting. The following financial information presented as of and for the three and nine months ended September 30, 2017 have been restated to reflect this change.

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. In addition to our drilling rigs, we provide the drilling crews 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 September 30,				As of and for the nine months ended September 30,
	2018		2017		2018		2017
Revenues:
Domestic drilling	$	36,586	$	35,141	$	108,146	$	93,959
International drilling	23,131		7,402		62,515		26,379
Drilling services	59,717		42,543		170,661		120,338
Well servicing	24,369		19,103		68,645		58,854
Wireline services	52,654		46,085		171,392		118,463
Coiled tubing services	12,592		9,550		37,894		22,513
Production services	89,615		74,738		277,931		199,830
Consolidated revenues	$	149,332	$	117,281	$	448,592	$	320,168

Operating costs:
Domestic drilling	$	21,650	$	21,769	$	64,297	$	61,658
International drilling	19,013		6,617		49,038		20,183
Drilling services	40,663		28,386		113,335		81,841
Well servicing	17,193		13,988		49,443		43,116
Wireline services	40,840		35,692		130,042		91,670
Coiled tubing services	10,265		8,603		33,104		21,829
Production services	68,298		58,283		212,589		156,615
Consolidated operating costs	$	108,961	$	86,669	$	325,924	$	238,456

Gross margin:
Domestic drilling	$	14,936	$	13,372	$	43,849	$	32,301
International drilling	4,118		785		13,477		6,196
Drilling services	19,054		14,157		57,326		38,497
Well servicing	7,176		5,115		19,202		15,738
Wireline services	11,814		10,393		41,350		26,793
Coiled tubing services	2,327		947		4,790		684
Production services	21,317		16,455		65,342		43,215
Consolidated gross margin	$	40,371	$	30,612	$	122,668	$	81,712



	As of and for the three months ended September 30,				As of and for the nine months ended September 30,
	2018		2017		2018		2017
Identifiable Assets:
Domestic drilling⁽¹⁾	$	375,982	$	408,052	$	375,982	$	408,052
International drilling ^{(1) (2)}	41,807		32,340		41,807		32,340
Drilling services	417,789		440,392		417,789		440,392
Well servicing	123,933		130,039		123,933		130,039
Wireline services	96,585		94,060		96,585		94,060
Coiled tubing services	34,866		27,881		34,866		27,881
Production services	255,384		251,980		255,384		251,980
Corporate	79,702		15,070		79,702		15,070
Consolidated identifiable assets	$	752,875	$	707,442	$	752,875	$	707,442

Depreciation and Amortization:
Domestic drilling	$	10,358	$	11,261	$	30,946	$	34,274
International drilling	1,463		1,428		4,211		4,407
Drilling services	11,821		12,689		35,157		38,681
Well servicing	4,903		4,946		14,688		14,958
Wireline services	4,518		4,731		13,727		13,636
Coiled tubing services	1,991		1,944		6,137		6,159
Production services	11,412		11,621		34,552		34,753
Corporate	268		313		826		921
Consolidated depreciation and amortization	$	23,501	$	24,623	$	70,535	$	74,355

Capital Expenditures:
Domestic drilling	$	6,274	$	2,868	$	13,768	$	18,648
International drilling	264		1,951		4,177		3,665
Drilling services	6,538		4,819		17,945		22,313
Well servicing	2,989		1,653		8,441		16,000
Wireline services	3,973		3,832		12,563		11,341
Coiled tubing services	4,498		1,678		12,479		3,940
Production services	11,460		7,163		33,483		31,281
Corporate	419		236		914		608
Consolidated capital expenditures	$	18,417	$	12,218	$	52,342	$	54,202


(1)	Identifiable assets for our drilling segments include the impact of a $39.4 million and $22.6 million intercompany balance, as of September 30, 2018 and 2017, 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 September 30,						Nine months ended September 30,
	2018			2017			2018			2017
Consolidated gross margin	$	40,371		$	30,612		$	122,668		$	81,712
Depreciation and amortization	(23,501		)	(24,623		)	(70,535		)	(74,355		)
General and administrative	(14,043		)	(17,549		)	(58,066		)	(51,405		)
Bad debt recovery (expense), net	(111		)	(491		)	311			98
Impairment	(239		)	—			(2,607		)	(795		)
Gain on dispositions of property and equipment, net	1,861			1,159			2,922			2,251
Income (loss) from operations	$	4,338		$	(10,892	)	$	(5,307	)	$	(42,494	)


10.	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 $72.4 million relating to our performance under these bonds as of September 30, 2018.

We are currently undergoing sales and use tax audits for multi-year periods. As of September 30, 2018 and December 31, 2017, our accrued liability was $1.6 million and $1.2 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.


11.	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 September 30, 2018, 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)



	September 30, 2018
	Parent			Guarantor Subsidiaries		Non-Guarantor Subsidiaries			Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	48,404		$	—	$	3,064		$	—		$	51,468
Restricted cash	2,000			—		—			—			2,000
Receivables, net of allowance	5			105,907		32,981			787			139,680
Intercompany receivable (payable)	(26,935		)	66,100		(39,165		)	—			—
Inventory	—			9,636		9,356			—			18,992
Assets held for sale	—			6,102		—			—			6,102
Prepaid expenses and other current assets	1,988			1,846		1,800			—			5,634
Total current assets	25,462			189,591		8,036			787			223,876
Net property and equipment	2,098			497,418		27,744			—			527,260
Investment in subsidiaries	585,245			23,177		—			(608,422		)	—
Deferred income taxes	42,150			—		—			(42,150		)	—
Other noncurrent assets	636			482		621			—			1,739
Total assets	$	655,591		$	710,668	$	36,401		$	(649,785	)	$	752,875
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	1,643		$	26,834	$	6,270		$	—		$	34,747
Deferred revenues	—			1		1,129			—			1,130
Accrued expenses	10,214			51,603		5,344			787			67,948
Total current liabilities	11,857			78,438		12,743			787			103,825
Long-term debt, less unamortized discount and debt issuance costs	463,805			—		—			—			463,805
Deferred income taxes	—			45,494		—			(42,150		)	3,344
Other noncurrent liabilities	1,432			1,491		481			—			3,404
Total liabilities	477,094			125,423		13,224			(41,363		)	574,378
Total shareholders’ equity	178,497			585,245		23,177			(608,422		)	178,497
Total liabilities and shareholders’ equity	$	655,591		$	710,668	$	36,401		$	(649,785	)	$	752,875

	December 31, 2017
	Parent			Guarantor Subsidiaries		Non-Guarantor Subsidiaries			Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	70,377		$	—	$	3,263		$	—		$	73,640
Restricted cash	2,008			—		—			—			2,008
Receivables, net of allowance	7			93,866		19,174			(42		)	113,005
Intercompany receivable (payable)	(22,955		)	49,651		(26,696		)	—			—
Inventory	—			7,741		6,316			—			14,057
Assets held for sale	—			6,620		—			—			6,620
Prepaid expenses and other current assets	1,238			3,193		1,798			—			6,229
Total current assets	50,675			161,071		3,855			(42		)	215,559
Net property and equipment	2,011			521,080		26,532			—			549,623
Investment in subsidiaries	596,927			20,095		—			(617,022		)	—
Deferred income taxes	38,028			—		—			(38,028		)	—
Other noncurrent assets	496			788		403			—			1,687
Total assets	$	688,137		$	703,034	$	30,790		$	(655,092	)	$	766,869
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	286		$	24,174	$	5,078		$	—		$	29,538
Deferred revenues	—			97		808			—			905
Accrued expenses	12,504			37,814		4,195			(42		)	54,471
Total current liabilities	12,790			62,085		10,081			(42		)	84,914
Long-term debt, less unamortized discount and debt issuance costs	461,665			—		—			—			461,665
Deferred income taxes	—			41,179		—			(38,028		)	3,151
Other noncurrent liabilities	3,586			2,843		614			—			7,043
Total liabilities	478,041			106,107		10,695			(38,070		)	556,773
Total shareholders’ equity	210,096			596,927		20,095			(617,022		)	210,096
Total liabilities and shareholders’ equity	$	688,137		$	703,034	$	30,790		$	(655,092	)	$	766,869

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(unaudited, in thousands)



	Three months ended September 30, 2018
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Revenues	$	—		$	126,202		$	23,130		$	—		$	149,332
Costs and expenses:
Operating costs	—			89,950			19,011			—			108,961
Depreciation and amortization	269			21,769			1,463			—			23,501
General and administrative	2,260			11,152			736			(105		)	14,043
Intercompany leasing	—			(1,215		)	1,215			—			—
Bad debt expense, net of recovery	—			111			—			—			111
Impairment	—			239			—			—			239
Gain on dispositions of property and equipment, net	—			(1,856		)	(5		)	—			(1,861		)
Total costs and expenses	2,529			120,150			22,420			(105		)	144,994
Income (loss) from operations	(2,529		)	6,052			710			105			4,338
Other income (expense):
Equity in earnings of subsidiaries	5,011			618			—			(5,629		)	—
Interest expense	(9,802		)	(12		)	3			—			(9,811		)
Other income	244			222			137			(105		)	498
Total other income (expense), net	(4,547		)	828			140			(5,734		)	(9,313		)
Income (loss) before income taxes	(7,076		)	6,880			850			(5,629		)	(4,975		)
Income tax (expense) benefit ¹	1,843			(1,869		)	(232		)	—			(258		)
Net income (loss)	$	(5,233	)	$	5,011		$	618		$	(5,629	)	$	(5,233	)


	Three months ended September 30, 2017
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Revenues	$	—		$	109,878		$	7,403		$	—		$	117,281
Costs and expenses:
Operating costs	—			80,054			6,615			—			86,669
Depreciation and amortization	313			22,882			1,428			—			24,623
General and administrative	5,737			11,445			505			(138		)	17,549
Intercompany leasing	—			(1,215		)	1,215			—			—
Bad debt expense, net of recovery	—			491			—			—			491
Gain on dispositions of property and equipment, net	—			(1,159		)	—			—			(1,159		)
Total costs and expenses	6,050			112,498			9,763			(138		)	128,173
Loss from operations	(6,050		)	(2,620		)	(2,360		)	138			(10,892		)
Other income (expense):
Equity in earnings of subsidiaries	(4,650		)	(2,393		)	—			7,043			—
Interest expense	(6,614		)	1			—			—			(6,613		)
Other income	9			220			204			(138		)	295
Total other income (expense), net	(11,255		)	(2,172		)	204			6,905			(6,318		)
Loss before income taxes	(17,305		)	(4,792		)	(2,156		)	7,043			(17,210		)
Income tax (expense) benefit ¹	78			142			(237		)	—			(17		)
Net loss	$	(17,227	)	$	(4,650	)	$	(2,393	)	$	7,043		$	(17,227	)

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 CONSOLIDATED STATEMENTS OF OPERATIONS

(unaudited, in thousands)



	Nine months ended September 30, 2018
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Revenues	$	—		$	386,077		$	62,515		$	—		$	448,592
Costs and expenses:
Operating costs	—			276,893			49,031			—			325,924
Depreciation and amortization	826			65,498			4,211			—			70,535
General and administrative	18,628			37,781			1,972			(315		)	58,066
Intercompany leasing	—			(3,645		)	3,645			—			—
Bad debt recovery, net of expense	—			(311		)	—			—			(311		)
Impairment	—			2,607			—			—			2,607
Gain on dispositions of property and equipment, net	—			(2,890		)	(32		)	—			(2,922		)
Total costs and expenses	19,454			375,933			58,827			(315		)	453,899
Income (loss) from operations	(19,454		)	10,144			3,688			315			(5,307		)
Other income (expense):
Equity in earnings of subsidiaries	10,081			3,305			—			(13,386		)	—
Interest expense	(28,963		)	(14		)	11			—			(28,966		)
Other income	405			664			292			(315		)	1,046
Total other income (expense), net	(18,477		)	3,955			303			(13,701		)	(27,920		)
Income (loss) before income taxes	(37,931		)	14,099			3,991			(13,386		)	(33,227		)
Income tax (expense) benefit ¹	3,407			(4,018		)	(686		)	—			(1,297		)
Net income (loss)	$	(34,524	)	$	10,081		$	3,305		$	(13,386	)	$	(34,524	)


	Nine months ended September 30, 2017
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Revenues	$	—		$	293,788		$	26,380		$	—		$	320,168
Costs and expenses:
Operating costs	—			218,281			20,175			—			238,456
Depreciation and amortization	921			69,027			4,407			—			74,355
General and administrative	16,507			33,881			1,431			(414		)	51,405
Intercompany leasing	—			(3,645		)	3,645			—			—
Bad debt recovery, net of expense	—			(98		)	—			—			(98		)
Impairment	—			795			—			—			795
Loss (gain) on dispositions of property and equipment, net	2			(2,126		)	(127		)	—			(2,251		)
Total costs and expenses	17,430			316,115			29,531			(414		)	362,662
Loss from operations	(17,430		)	(22,327		)	(3,151		)	414			(42,494		)
Other income (expense):
Equity in earnings of subsidiaries	(19,518		)	(3,924		)	—			23,442			—
Interest expense	(19,110		)	20			—			—			(19,090		)
Other income (expense)	37			678			(77		)	(414		)	224
Total other expense, net	(38,591		)	(3,226		)	(77		)	23,028			(18,866		)
Loss before income taxes	(56,021		)	(25,553		)	(3,228		)	23,442			(61,360		)
Income tax (expense) benefit ¹	(6,539		)	6,035			(696		)	—			(1,200		)
Net loss	$	(62,560	)	$	(19,518	)	$	(3,924	)	$	23,442		$	(62,560	)

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)



	Nine months ended September 30, 2018
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities	$	(43,466	)	$	60,269		$	4,687		$	—		$	21,490

Cash flows from investing activities:
Purchases of property and equipment	(762		)	(43,374		)	(4,642		)	—			(48,778		)
Proceeds from sale of property and equipment	—			4,648			17			—			4,665
Proceeds from insurance recoveries	—			965			15			—			980
	(762		)	(37,761		)	(4,610		)	—			(43,133		)

Cash flows from financing activities:
Proceeds from exercise of options	12			—			—			—			12
Purchase of treasury stock	(549		)	—			—			—			(549		)
Intercompany contributions/distributions	22,784			(22,508		)	(276		)	—			—
	22,247			(22,508		)	(276		)	—			(537		)

Net decrease in cash, cash equivalents and restricted cash	(21,981		)	—			(199		)	—			(22,180		)
Beginning cash, cash equivalents and restricted cash	72,385			—			3,263			—			75,648
Ending cash, cash equivalents and restricted cash	$	50,404		$	—		$	3,064		$	—		$	53,468

	Nine months ended September 30, 2017
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities	$	(35,837	)	$	20,229		$	4,346		$	—		$	(11,262	)

Cash flows from investing activities:
Purchases of property and equipment	(563		)	(48,490		)	(4,023		)	270			(52,806		)
Proceeds from sale of property and equipment	—			10,528			149			(270		)	10,407
Proceeds from insurance recoveries	—			3,119			—			—			3,119
	(563		)	(34,843		)	(3,874		)	—			(39,280		)

Cash flows from financing activities:
Debt repayments	(13,267		)	—			—			—			(13,267		)
Proceeds from issuance of debt	65,000			—			—			—			65,000
Purchase of treasury stock	(533		)	—			—			—			(533		)
Intercompany contributions/distributions	(14,379		)	14,614			(235		)	—			—
	36,821			14,614			(235		)	—			51,200

Net increase (decrease) in cash and cash equivalents	421			—			237			—			658
Beginning cash and cash equivalents	9,134			—			1,060			—			10,194
Ending cash and cash equivalents	$	9,555		$	—		$	1,297		$	—		$	10,852


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, including our ability to finance acquisitions, manage growth and effectively integrate acquisitions, 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, 2017, 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 16 AC rigs in the US and eight SCR rigs in Colombia, all of which have 1,500 horsepower or greater drawworks. In July 2018, we entered into a three-year term contract for the construction of a new 1,500 horsepower, AC pad-optimal rig, which we expect to deploy in early 2019 to the Permian Basin. In addition to our drilling rigs, we provide the drilling crews and most of the ancillary equipment needed to operate our drilling rigs. The drilling rigs in our current fleet are deployed through our division offices in the following regions:



		Rig Count
Domestic drilling:
Marcellus/Utica		6
Permian Basin and Eagle Ford		8
Bakken		2
International drilling		8
		24


•	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 September 30, 2018, 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 September 30, 2018, we have a fleet of 104 wireline units, with one additional unit on order for delivery in the fourth quarter of 2018. Our units are deployed through 14 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 metal pipe spooled on a large reel for 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 September 30, 2018, we have a current fleet of eight coiled tubing units, with one additional unit on order for delivery in the fourth quarter of 2018. Our units are 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. We revised our reportable business segments as of the fourth quarter of 2017 to reflect changes in the basis used by management in making decisions regarding our business for resource allocation and performance assessment. Financial information about our operating segments is included in Note 9, Segment Information, of the Notes to 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 limits 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, and other higher power ancillary equipment, which is needed in order to drill 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 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, 2017.

Market Conditions — Our industry is currently experiencing a recovery from a severe down cycle that began in late 2014 and which persisted 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, with an average of approximately $70 per barrel during the third quarter of 2018.

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:

We began 2017 with utilization of our domestic fleet at 81% and four rigs working in Colombia. Since then, utilization of our domestic fleet has increased to 100%, and six of our eight international rigs are currently earning revenues under term contracts. In July 2018, we entered into a three-year term contract for the construction of a new 1,500 horsepower, AC pad-optimal rig, which we expect to deploy in early 2019 to the Permian Basin.

As of September 30, 2018, 22 of our 24 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	2	14	2	6	5	—	1
International rigs	—	6	2	1	—	2	1
	2	20	4	7	5	2	2

The term contracts for our international drilling rigs 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 rigs in Colombia and we also continue to evaluate the possibility of selling some or all of our assets in Colombia.

During the quarter ended September 30, 2018, our well servicing rig hours and revenue days for our coiled tubing services increased by 3% each, while the number of wireline jobs completed decreased by 11%, as compared to the second quarter of 2018. Average revenue rates for our well servicing and coiled tubing services provided during this same period increased by 2% and 1% (on a per hour and per day basis, respectively), while average revenues per job for our wireline services decreased by 5%. The increases in well servicing and coiled tubing revenues corresponds with increasing demand in our industry, while the decrease in wireline services revenue was primarily a result of several of our clients’ temporary pullback 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 for our services in onshore markets, offshore activity has 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, our exposure to any decreases in activity is limited because we have term contract coverage for all of our seven drilling rigs currently operating in this region. In Colorado, a proposition to increase the required setback for new oil and gas wells was added to the November 2018 ballot which, if passed, would significantly 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 September 2018, we were operating 15 wireline units and three well servicing rigs in Colorado, which can be redeployed to other markets should the proposed setback regulations be passed and negatively impact demand.

Although we expect a highly competitive environment to continue, we believe our high-quality equipment and services and our excellent safety record make us well positioned to compete.

Liquidity and Capital Resources

Sources of Capital Resources

Our principal sources of liquidity currently consist of:


•	total cash and cash equivalents ($53.5 million as of September 30, 2018);


•	cash generated from operations ($21.5 million during the nine months ended September 30, 2018);


•	proceeds from sales of certain non-strategic assets; and


•	the unused portion of our asset-based lending facility ($57.6 million as of September 30, 2018).

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 September 30, 2018, we had $9.7 million in committed letters of credit, which, after borrowing base limitations, resulted in borrowing availability of $57.6 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 September 30, 2018, 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 certain non-strategic 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 $120.1 million at September 30, 2018, compared to $130.6 million at December 31, 2017. Our current ratio, which we calculate by dividing current assets by current liabilities, was 2.2 at September 30, 2018, as compared to 2.5 at December 31, 2017. The changes in the components of our working capital were as follows (amounts in thousands), and as described below:



	September 30, 2018		December 31, 2017		Change
Cash and cash equivalents	$	51,468	$	73,640	$	(22,172	)
Restricted cash	2,000		2,008		(8		)
Receivables:
Trade, net of allowance for doubtful accounts	86,372		79,592		6,780
Unbilled receivables	24,204		16,029		8,175
Insurance recoveries	23,605		13,874		9,731
Other receivables	5,499		3,510		1,989
Inventory	18,992		14,057		4,935
Assets held for sale	6,102		6,620		(518		)
Prepaid expenses and other current assets	5,634		6,229		(595		)
Current assets	223,876		215,559		8,317
Accounts payable	34,747		29,538		5,209
Deferred revenues	1,130		905		225
Accrued expenses:
Payroll and related employee costs	28,161		21,023		7,138
Insurance claims and settlements	23,494		13,289		10,205
Insurance premiums and deductibles	5,433		6,742		(1,309		)
Interest	1,684		6,624		(4,940		)
Other	9,176		6,793		2,383
Current liabilities	103,825		84,914		18,911
Working capital	$	120,051	$	130,645	$	(10,594	)


•	Cash and cash equivalents — The change in cash and cash equivalents during 2018 is primarily due to $48.8 million of cash used for the purchase of property and equipment, partially offset by $21.5 million of cash from operating activities and $4.7 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 2018 is primarily due to the 18% increase in our revenues during the quarter ended September 30, 2018, as compared to the quarter ended December 31, 2017. Our domestic trade receivables generally turn over within 60 days, and our Colombian trade receivables generally turn over within 120 days.


•	Insurance recoveries and Insurance claims and settlements — The increase during 2018 in both our insurance recoveries receivables and our accrued liability for insurance claims and settlements is primarily due to very high costs incurred on one significant workers’ compensation claim in excess of our $500,000 deductible, which are covered by our workers compensation insurance policy.


•	Other receivables — The increase in other receivables during 2018 is primarily due to an increase in recoverable income tax receivables attributable to the increase in activity for our international operations.


•	Inventory — The increase in inventory during 2018 is primarily due to the increase in activity for our international operations, as well as purchases of supplies and job materials for our wireline and coiled tubing operations.

•

Assets held for sale — As of September 30, 2018, our condensed consolidated balance sheet reflects assets held for sale of $6.1 million, which primarily represents the fair value of two domestic SCR drilling rigs and one domestic mechanical drilling rig, as well as other drilling equipment, and three coiled tubing units. As of December 31, 2017, our condensed consolidated balance sheet reflects assets held for sale of $6.6 million, which primarily represents the fair value of three domestic SCR drilling rigs and one domestic mechanical drilling rig, as well as other drilling equipment, two wireline units and one coiled tubing unit and other spare equipment. For additional information, see

Note 3, 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.


•	Prepaid expenses and other current assets — The decrease in prepaid expenses and other current assets during 2018 is primarily due to the amortization of prepaid insurance premiums which are generally paid annually in October, which was partially offset by an increase in various other prepaid expenses, including annual renewals of software subscriptions which were paid in September.


•	Accounts payable — Our accounts payable generally turn over within 90 days. The increase in accounts payable during 2018 is primarily due to the 18% increase in our operating costs for the quarter ended September 30, 2018 as compared to the quarter ended December 31, 2017, as well as a $3.6 million increase in our accruals for capital expenditures.

•

Accrued payroll and related employee costs — The increase in accrued payroll and related employee costs during 2018 is primarily due to the movement of the $5.7 million accrued liability for our 2016 phantom stock unit awards from noncurrent to current, as these awards are scheduled to vest in April 2019. The accrued liability for these awards also increased during 2018 due to the increase in our stock price from December 31, 2017 which is the most impactful input for the fair value measurement of these awards. For additional information about these awards, see Note 8, 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. Additionally, the increase in accrued payroll and related employee costs during 2018 is attributable to the timing of pay periods and the associated withholding and unemployment tax payments, all of which is partially offset by a decrease in annual incentive compensation associated with the payment of 2017 annual bonuses which were fully accrued at December 31, 2017 and were paid in the first quarter of 2018.


•	Accrued insurance premiums and deductibles — The decrease in insurance premiums and deductibles during 2018 is primarily due to the decrease in our accrual for health insurance costs resulting from a decrease in our health claims and the estimated liability for the deductibles under these policies.


•	Accrued interest — The decrease in accrued interest expense during 2018 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 2018 is primarily related to an increase in accrued taxes associated with the increase in revenues for our international operations.

Debt and Other Contractual Obligations — The following table includes information about the amount and timing of our contractual obligations at September 30, 2018 (amounts 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	128,796		35,700		71,400		21,696		—
Purchase commitments	19,535		19,535		—		—		—
Operating leases	12,903		4,152		4,090		2,698		1,963
Incentive compensation	19,847		11,905		7,942		—		—
	$	656,081	$	71,292	$	83,432	$	499,394	$	1,963


•	Debt — Debt obligations at September 30, 2018 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 September 30, 2018, 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 9.9% interest rate that was in effect at September 30, 2018, and (2) the principal balance of $175 million at September 30, 2018, 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 September 30, 2018, our purchase commitments primarily pertain to $4.7 million of

remaining obligations for the construction of the new-build drilling rig which we expect to complete in early 2019, $3.9 million of remaining obligations for the purchase of one new coiled tubing unit which is on order for delivery in the fourth quarter of 2018, and various refurbishments and upgrades to our drilling and production services fleets. Other purchase commitments include committed capital expenditures for various job equipment, vehicles for our coiled tubing operations, and job supply purchases for our wireline and coiled tubing operations.


•	Operating leases — Our operating leases consist of 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.

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 5, Debt, and Note 11, Guarantor/Non-Guarantor Condensed Consolidating Financial Statements, of the Notes to 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 September 30, 2018, we were in compliance with all covenants required by our Term Loan, ABL Facility and Senior Notes.

Capital Expenditures — During the nine months ended September 30, 2018, we spent $48.8 million on purchases of property and equipment and placed into service property and equipment of $52.3 million. Currently, we expect to spend approximately $70 million on capital expenditures during 2018, which includes approximately $23 million for two large-diameter coiled tubing units, one of which was delivered in early July, three wireline units, two of which were delivered in January, high-pressure pump packages for completion operations, and the construction of the new-build drilling rig expected to be completed in 2019.

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 2018 from operating cash flow in excess of our working capital requirements, proceeds from sales of certain non-strategic assets, remaining proceeds from our Term Loan issuance, and from available borrowings under our ABL Facility, if necessary.

Results of Operations

Statements of Operations Analysis

The following table provides certain information about our operations, including a detail of each of our business segments’ revenues, operating costs and gross margin for the three and nine months ended September 30, 2018 and 2017 (amounts in thousands):



	Three months ended September 30,						Nine months ended September 30,
	2018			2017			2018			2017
Revenues:
Domestic drilling	$	36,586		$	35,141		$	108,146		$	93,959
International drilling	23,131			7,402			62,515			26,379
Drilling services	59,717			42,543			170,661			120,338
Well servicing	24,369			19,103			68,645			58,854
Wireline services	52,654			46,085			171,392			118,463
Coiled tubing services	12,592			9,550			37,894			22,513
Production services	89,615			74,738			277,931			199,830
Consolidated revenues	$	149,332		$	117,281		$	448,592		$	320,168

Operating costs:
Domestic drilling	$	21,650		$	21,769		$	64,297		$	61,658
International drilling	19,013			6,617			49,038			20,183
Drilling services	40,663			28,386			113,335			81,841
Well servicing	17,193			13,988			49,443			43,116
Wireline services	40,840			35,692			130,042			91,670
Coiled tubing services	10,265			8,603			33,104			21,829
Production services	68,298			58,283			212,589			156,615
Consolidated operating costs	$	108,961		$	86,669		$	325,924		$	238,456

Gross margin:
Domestic drilling	$	14,936		$	13,372		$	43,849		$	32,301
International drilling	4,118			785			13,477			6,196
Drilling services	19,054			14,157			57,326			38,497
Well servicing	7,176			5,115			19,202			15,738
Wireline services	11,814			10,393			41,350			26,793
Coiled tubing services	2,327			947			4,790			684
Production services	21,317			16,455			65,342			43,215
Consolidated gross margin	$	40,371		$	30,612		$	122,668		$	81,712

Consolidated:
Net loss	$	(5,233	)	$	(17,227	)	$	(34,524	)	$	(62,560	)
Adjusted EBITDA ⁽¹⁾	$	28,576		$	14,026		$	68,881		$	32,880

(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 September 30,						Nine months ended September 30,
	2018			2017			2018			2017
	(amounts in thousands)
Net loss	$	(5,233	)	$	(17,227	)	$	(34,524	)	$	(62,560	)
Depreciation and amortization	23,501			24,623			70,535			74,355
Impairment	239			—			2,607			795
Interest expense	9,811			6,613			28,966			19,090
Income tax expense	258			17			1,297			1,200
Adjusted EBITDA	28,576			14,026			68,881			32,880
General and administrative	14,043			17,549			58,066			51,405
Bad debt expense (recovery), net	111			491			(311		)	(98		)
Gain on dispositions of property and equipment, net	(1,861		)	(1,159		)	(2,922		)	(2,251		)
Other income	(498		)	(295		)	(1,046		)	(224		)
Consolidated gross margin	$	40,371		$	30,612		$	122,668		$	81,712

Consolidated gross margin — Our consolidated gross margin increased by 32% and 50% for the three and nine months ended September 30, 2018, respectively, as compared to the corresponding periods in 2017. The $9.8 million increase in consolidated gross margin during the three months ended September 30, 2018 reflects improved demand for all of our service offerings, as compared to the corresponding period in 2017, and was led by higher dayrates and activity in our international drilling operations which accounted for 34% of the increase. Of the $41.0 million increase in consolidated gross margin for the nine months ended September 30, 2018, as compared to the corresponding period in 2017, 54% is attributable to our production services segments, led by improved demand for our wireline services, while the remaining increase is attributable to our drilling services segments, led by higher domestic dayrates and activity.

•

Drilling Services — Our drilling services revenues increased by $17.2 million, or 40%, and $50.3 million, or 42%, for the three and nine months ended September 30, 2018, respectively, as compared to the corresponding periods in 2017, while operating costs increased by $12.3 million, or 43%, and $31.5 million, or 38%. The increases in our drilling services revenues and operating costs primarily resulted from a 15% and 24% increase in revenue days during the three and nine months ended September 30, 2018, as compared to the corresponding periods in 2017, primarily attributable to increased utilization of our international drilling fleet. The following table provides operating statistics for each of our drilling services segments:



	Three months ended September 30,						Nine months ended September 30,
	2018			2017			2018			2017
Domestic drilling:
Average number of drilling rigs	16			16			16			16
Utilization rate	99		%	100		%	100		%	93		%
Revenue days	1,459			1,472			4,353			4,052

Average revenues per day	$	25,076		$	23,873		$	24,844		$	23,188
Average operating costs per day	14,839			14,789			14,771			15,217
Average margin per day	$	10,237		$	9,084		$	10,073		$	7,971

International drilling:
Average number of drilling rigs	8			8			8			8
Utilization rate	76		%	38		%	79		%	40		%
Revenue days	562			283			1,733			865

Average revenues per day	$	41,158		$	26,155		$	36,073		$	30,496
Average operating costs per day	33,831			23,382			28,297			23,333
Average margin per day	$	7,327		$	2,773		$	7,776		$	7,163

Our domestic drilling fleet utilization has been fully utilized since mid-2017, allowing us to achieve the higher margins of a fully utilized fleet. Our domestic drilling average revenues per day for the three and nine months ended September 30, 2018 increased as compared to the corresponding periods in 2017, primarily due to increasing dayrates, though reduced dayrates for two rigs that were re-priced from pre-downturn rates in 2018 partially offset the overall increases. Our average domestic drilling operating costs per day for the nine months ended September 30, 2018 decreased from the corresponding period in 2017, primarily because additional costs were incurred during the first half of 2017 to deploy previously idle rigs under new contracts.

Our international drilling fleet utilization has steadily improved since the beginning of 2017, with six of eight rigs utilized at September 30, 2018, versus four rigs utilized at the beginning of 2017. This utilization improvement has been the primary reason for the increases in our international drilling average revenues, operating costs and margin per day for the three and nine months ended September 30, 2018, as compared to the corresponding periods in 2017. Our international drilling average margin per day for the three months ended September 30, 2018 also increased as compared to the corresponding period in 2017, partially due to additional costs incurred during 2017 to redeploy drilling rigs under new term contracts.

•

Production Services — Our revenues from production services increased by $14.9 million, or 20%, and $78.1 million, or 39%, for the three and nine months ended September 30, 2018, respectively, as compared to the corresponding periods in 2017, while operating costs increased by $10.0 million, or 17%, and $56.0 million, or 36%, respectively. The increases in revenues and operating costs in our production services segments are a result of the increased demand for our services, particularly those that perform completion-related activities. The following table provides operating statistics for each of our production services segments:



	Three months ended September 30,						Nine months ended September 30,
	2018			2017			2018			2017
Well servicing:
Average number of rigs	125			125			125			125
Utilization rate	51		%	43		%	49		%	44		%
Rig hours	44,155			36,108			127,800			114,697
Average revenue per hour	$	552		$	529		$	537		$	513

Wireline services:
Average number of units	104			117			107			115
Number of jobs	2,684			2,778			8,536			8,540
Average revenue per job	$	19,618		$	16,589		$	20,079		$	13,872

Coiled tubing services:
Average number of units	11			14			13			16
Revenue days	362			368			1,126			1,106
Average revenue per day	$	34,785		$	25,951		$	33,654		$	20,355

Increases in production services revenues and operating costs were led by our wireline services business segment, which experienced a significant increase in completion-related activity as wells that were drilled but not completed during the downturn created higher demand for completion services as our industry continues to recover. Although the number of wireline jobs decreased slightly, average revenue per job increased by 18% and 45% for the three and nine months ended September 30, 2018, as compared to the corresponding periods in 2017, respectively, which is largely due to a higher percentage of the work performed being attributable to completion-related jobs which earn higher revenue rates, but also incur higher costs for the job materials consumed on these types of jobs.

Our coiled tubing services business segment also experienced an increase in demand during 2018, especially for services provided using our larger diameter coiled tubing units. Although revenue days for the three and nine months ended September 30, 2018 were comparatively flat with the corresponding periods in 2017, average revenue per day increased by 34% and 65%, respectively, 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. The expansion of our coiled tubing operations into a new market in late 2017 and the closure of under-performing locations in 2018 also contributed to the improvement, as compared to the corresponding periods in 2017.

Our well servicing business segment experienced a moderate increase in demand. Well servicing utilization increased to 51% and 49% for the three and nine months ended September 30, 2018, respectively, from 43% and 44%, during the corresponding periods in 2017, respectively. These utilization improvements represent 22% and 11% increases in well servicing rig hours, respectively, while average revenue per hour also increased by 4% and 5%, respectively.

Depreciation and amortization expense — Our depreciation and amortization expense decreased by $1.1 million and $3.8 million for the three and nine months ended September 30, 2018, respectively, as compared to the corresponding periods in 2017. The decrease is almost entirely attributable to our domestic drilling operations. With our reduced domestic rig fleet size and decreased utilization during 2015 and 2016, we had sufficient drill pipe and other spare equipment on hand which allowed us to defer additional capital spending on these items during recent years.

Impairment — During the nine months ended September 30, 2018 and 2017, we recognized impairment charges of $2.6 million and $0.8 million, respectively, 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 3, 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.

Interest expense — Our interest expense increased by $9.9 million during the nine months ended September 30, 2018, as compared to the corresponding period in 2017, primarily due to the issuance of our Term Loan in November 2017, from which a portion of the proceeds were used to repay and retire our Revolving Credit Facility. As a result, our total debt outstanding increased, as did the interest rate applicable to outstanding borrowings. Debt outstanding under our Term Loan was $175 million during the nine months ended September 30, 2018, while the weighted average debt outstanding under our Revolving Credit Facility was approximately $79 million during the nine months ended September 30, 2017, with annualized weighted average interest rates applicable to these borrowings during these periods of approximately 9.7% and 5.9%, respectively.

Income tax expense — Our effective income tax rate for the nine months ended September 30, 2018 was lower than the federal statutory rate in the United States, primarily due to valuation allowances, foreign currency translation, state taxes, and other permanent differences. For more detail, see Note 4, Valuation Allowances on Deferred Tax Assets and Recently Enacted Tax Reform, of the Notes to Condensed Consolidated Financial Statements, included in Part I, Item 1, Financial Statements, of this Quarterly Report on Form 10-Q.

General and administrative expense — Our general and administrative expense decreased by $3.5 million, or 20%, and increased by $6.7 million, or 13%, for the three and nine months ended September 30, 2018, respectively, as compared to the corresponding periods in 2017. The variances during both of these comparative periods were primarily attributable to the change in the fair value of our phantom stock unit awards which caused our phantom stock compensation expense to decrease by $4.5 million during the three months ended September 30, 2018, and increase by $2.4 million for the nine months ended September 30, 2018, as compared to the corresponding periods in 2017. Our general and administrative expense for the nine months ended September 30, 2018 also increased due to higher compensation costs, including a $1.7 million increase in salary and incentive compensation, and an increase in various professional and other fees.

Gain on dispositions of property and equipment, net — Our net gain of $2.9 million on the disposition of property and equipment during the nine months ended September 30, 2018 was primarily related to the sale of various property and equipment, including the sale of five coiled tubing units, twelve wireline units, and one drilling rig which was previously held for sale. Our net gain of $2.3 million on the disposition of property and equipment during the corresponding period in 2017 was primarily for the sale of certain coiled tubing equipment and vehicles, as well as the loss of drill pipe in operation, for which we were reimbursed by the client, and the disposal of two cranes that were damaged.

Other income — The increase in our other income during the nine months ended September 30, 2018, as compared to the corresponding period in 2017, is primarily related to interest earned on the investments made during 2018 in highly-liquid money-market mutual funds, as well as the elimination of certain taxes associated with our international operations due to foreign tax reform.

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 606 discussed below, as of September 30, 2018, 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, 2017.

Revenue Recognition — In May 2014, the FASB issued ASU No. 2014-09, a comprehensive new revenue recognition standard that supersedes nearly all pre-existing revenue recognition guidance. The standard, and its related amendments, collectively referred to as ASC Topic 606, outlines a single comprehensive model for revenue recognition based on the core principle that a company will recognize revenue when promised goods or services are transferred to clients, in an amount that reflects the consideration to which an entity expects to be entitled in exchange for those goods or services.

For more information about the accounting under ASC Topic 606, and disclosures under the new standard, 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.

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.

•

In accordance with ASC Topic 360, Property, Plant and Equipment, we monitor all indicators of potential impairments and 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). Due to adverse factors currently affecting our well servicing operations, including increased competition and labor shortages in certain well servicing markets, and lower than anticipated utilization, all of which contributed to a decline in our projected cash flows for the well servicing reporting unit, we performed an impairment analysis of this reporting unit at September 30, 2018. As a result of this analysis, we concluded that this reporting unit was not at risk of impairment because the sum of the estimated future undiscounted net cash flows for our well servicing reporting unit was significantly in excess of the carrying amount.

•

As of September 30, 2018, we had $93.5 million and $11.5 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 a result, we have a valuation allowance that fully offsets our foreign and domestic federal deferred tax assets as of September 30, 2018. The valuation allowance is the primary factor causing our effective tax rate to be significantly lower than the statutory rate. For more information, see Note 4, Valuation Allowances on Deferred Tax Assets and Recently Enacted Tax Reform, of the Notes to Condensed Consolidated Financial Statements, included in Part I, Item 1, Financial Statements, of this Quarterly Report on Form 10-Q.

•

Our accrued insurance premiums and deductibles as of September 30, 2018 include accruals for costs incurred under the self-insurance portion of our health insurance of approximately $0.8 million and our workers’ compensation, general liability and auto liability insurance of approximately $4.4 million. 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. 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 costs 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 8, 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

Interest Rate Risk — We are subject to interest rate market risk on our variable rate debt. As of September 30, 2018, 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 $1.3 million during the nine months ended September 30, 2018. 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, 2018.

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 nine months ended September 30, 2018.


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 September 30, 2018, 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. There has been no change in our internal control over financial reporting that occurred during the three months ended September 30, 2018 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

Due to the nature of our business, we are, from time to time, involved in routine litigation or subject to disputes or claims related to 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 or results of operations.


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 September 30, 2018. We did not repurchase any common shares during the quarter ended September 30, 2018.


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 documents are exhibits to this Form 10-Q:



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)).

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 September 30, 2018, formatted in XBRL (eXtensible Business Reporting Language): (i) Condensed Consolidated Balance Sheets, (ii) Condensed Consolidated Statements of Operations, (iii) Condensed Consolidated Statements of Cash Flows, and (iv) Notes to Condensed Consolidated Financial Statements.

*	Incorporated by reference to the filing indicated.
**	Filed herewith.
#	Furnished herewith.

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: October 30, 2018

PIONEER ENERGY SERVICES CORP - FORM 10-Q - October 30, 2018

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PIONEER ENERGY SERVICES CORP Reports