PIONEER ENERGY SERVICES CORP - FORM 10-Q

Attached files

file	filename
EX-32.2 - EXHIBIT 32.2 - PIONEER ENERGY SERVICES CORP	exhibit3223q2017.htm
EX-32.1 - EXHIBIT 32.1 - PIONEER ENERGY SERVICES CORP	exhibit3213q2017.htm
EX-31.2 - EXHIBIT 31.2 - PIONEER ENERGY SERVICES CORP	exhibit3123q2017.htm
EX-31.1 - EXHIBIT 31.1 - PIONEER ENERGY SERVICES CORP	exhibit3113q2017.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, 2017



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 NE 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 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
(Do not check if a small reporting company.)
(Do not check if a small reporting company.)		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 16, 2017, there were 77,719,021 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, 2017			December 31, 2016
	(unaudited)			(audited)
	(in thousands, except share data)
ASSETS
Current assets:
Cash and cash equivalents	$	10,852		$	10,194
Receivables:
Trade, net of allowance for doubtful accounts	71,634			38,764
Unbilled receivables	14,268			7,417
Insurance recoveries	13,491			17,003
Other receivables	3,411			8,939
Inventory	11,758			9,660
Assets held for sale	8,756			15,093
Prepaid expenses and other current assets	5,331			6,926
Total current assets	139,501			113,996
Property and equipment, at cost	1,100,513			1,058,261
Less accumulated depreciation	534,012			474,181
Net property and equipment	566,501			584,080
Other long-term assets	1,440			2,026
Total assets	$	707,442		$	700,102

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	32,008		$	19,208
Deferred revenues	783			1,449
Accrued expenses:
Payroll and related employee costs	19,298			14,813
Insurance premiums and deductibles	7,811			6,446
Insurance claims and settlements	13,084			13,667
Interest	912			5,395
Other	5,617			5,024
Total current liabilities	79,513			66,002
Long-term debt, less debt issuance costs	392,601			339,473
Deferred income taxes	8,615			8,180
Other long-term liabilities	5,185			5,049
Total liabilities	485,914			418,704
Commitments and contingencies (Note 9)
Shareholders’ equity:
Preferred stock, 10,000,000 shares authorized; none issued and outstanding	—			—
Common stock $.10 par value; 200,000,000 shares authorized at September 30, 2017; 77,719,021 and 77,146,906 shares outstanding at September 30, 2017 and December 31, 2016, respectively	7,835			7,766
Additional paid-in capital	545,032			541,823
Treasury stock, at cost; 630,688 and 515,546 shares at September 30, 2017 and December 31, 2016, respectively	(4,416		)	(3,883		)
Accumulated deficit	(326,923		)	(264,308		)
Total shareholders’ equity	221,528			281,398
Total liabilities and shareholders’ equity	$	707,442		$	700,102

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,
	2017			2016			2017			2016
	(in thousands, except per share data)
Revenues:
Production services	$	74,738		$	40,899		$	199,830		$	116,998
Drilling services	42,543			27,454			120,338			88,597
Total revenues	117,281			68,353			320,168			205,595

Costs and expenses:
Production services	58,304			31,912			156,678			95,503
Drilling services	28,386			19,776			81,841			51,989
Depreciation and amortization	24,623			28,663			74,355			87,409
General and administrative	17,528			14,312			51,342			46,078
Bad debt expense (recovery)	491			(359		)	(98		)	(302		)
Impairment charges	—			4,262			795			4,262
Gain on dispositions of property and equipment, net	(1,159		)	(328		)	(2,251		)	(420		)
Total costs and expenses	128,173			98,238			362,662			284,519
Loss from operations	(10,892		)	(29,885		)	(42,494		)	(78,924		)

Other (expense) income:
Interest expense, net of interest capitalized	(6,613		)	(6,678		)	(19,090		)	(19,307		)
Loss on extinguishment of debt	—			—			—			(299		)
Other (expense) income	295			245			224			574
Total other expense	(6,318		)	(6,433		)	(18,866		)	(19,032		)

Loss before income taxes	(17,210		)	(36,318		)	(61,360		)	(97,956		)
Income tax (expense) benefit	(17		)	1,698			(1,200		)	5,646
Net loss	$	(17,227	)	$	(34,620	)	$	(62,560	)	$	(92,310	)

Loss per common share—Basic	$	(0.22	)	$	(0.53	)	$	(0.81	)	$	(1.43	)

Loss per common share—Diluted	$	(0.22	)	$	(0.53	)	$	(0.81	)	$	(1.43	)

Weighted average number of shares outstanding—Basic	77,552			64,905			77,335			64,755

Weighted average number of shares outstanding—Diluted	77,552			64,905			77,335			64,755

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,
	2017			2016
	(in thousands)
Cash flows from operating activities:
Net loss	$	(62,560	)	$	(92,310	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depreciation and amortization	74,355			87,409
Allowance for doubtful accounts, net of recoveries	(98		)	(302		)
Write-off of obsolete inventory	—			21
Gain on dispositions of property and equipment, net	(2,251		)	(420		)
Stock-based compensation expense	3,225			2,998
Amortization of debt issuance costs	1,395			1,311
Loss on extinguishment of debt	—			299
Impairment charges	795			4,262
Deferred income taxes	434			(6,372		)
Change in other long-term assets	335			426
Change in other long-term liabilities	136			(833		)
Changes in current assets and liabilities:
Receivables	(38,848		)	20,910
Inventory	(2,098		)	855
Prepaid expenses and other current assets	1,594			2,726
Accounts payable	11,360			(2,425		)
Deferred revenues	(470		)	(4,353		)
Accrued expenses	1,434			(6,558		)
Net cash provided by (used in) operating activities	(11,262		)	7,644

Cash flows from investing activities:
Purchases of property and equipment	(52,806		)	(25,584		)
Proceeds from sale of property and equipment	10,407			2,743
Proceeds from insurance recoveries	3,119			—
Net cash used in investing activities	(39,280		)	(22,841		)

Cash flows from financing activities:
Debt repayments	(13,267		)	(500		)
Proceeds from issuance of debt	65,000			12,000
Debt issuance costs	—			(819		)
Proceeds from exercise of options	—			183
Purchase of treasury stock	(533		)	(124		)
Net cash provided by financing activities	51,200			10,740

Net increase (decrease) in cash and cash equivalents	658			(4,457		)
Beginning cash and cash equivalents	10,194			14,160
Ending cash and cash equivalents	$	10,852		$	9,703

Supplementary disclosure:
Interest paid	$	22,928		$	22,849
Income tax paid	$	847		$	653
Noncash investing and financing activity:
Change in capital expenditure accruals	$	1,396		$	(1,592	)

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 Segment provides contract land drilling services through our four domestic divisions which are located in the Marcellus/Utica, Eagle Ford, Permian Basin 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. Our drilling rig fleet is 100% pad-capable and consists of the following:



	Multi-well, Pad-capable
	AC rigs	SCR rigs	Total
U.S. rigs	16	—	16
Colombia rigs	—	8	8
			24

Our Production Services Segment provides a range of services to a diverse group of exploration and production companies, with our operations concentrated in the major United States onshore oil and gas producing regions in the Mid-Continent and Rocky Mountain states and in the Gulf Coast, both onshore and offshore. As of September 30, 2017, our production services fleets are as follows:



	550 HP	600 HP	Total
Well servicing rigs, by horsepower (HP) rating	113	12	125
	Onshore	Offshore	Total
Wireline units	111	6	117
Coiled tubing units	10	4	14

Revenues and Cost Recognition

Drilling Contracts—Our drilling contracts generally provide for compensation on a daywork basis. Spot market contracts generally provide for the drilling of a single well and typically permit the client to terminate on short notice. We typically enter into longer-term drilling contracts for our newly constructed rigs and/or during periods of high rig demand. We recognize revenues on daywork contracts for the days completed based on the dayrate specified in each contract.

With most drilling contracts, we receive payments contractually designated for the mobilization of rigs and other equipment. Payments received, and costs incurred for the mobilization services are deferred and recognized on a straight line basis over the related contract term. Costs incurred to relocate rigs and other drilling equipment to areas in which a contract has not been secured are expensed as incurred. 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.

Amortization of deferred revenues and costs during the three and nine months ended September 30, 2017 and 2016 (amounts in thousands) were as follows:



	Three months ended September 30,				Nine months ended September 30,
	2017		2016		2017		2016
Deferred revenues	$	562	$	597	$	1,859	$	1,177
Deferred costs	1,311		795		3,997		1,947

Our current and long-term deferred revenues and costs as of September 30, 2017 and December 31, 2016 were as follows (amounts in thousands):



	September 30, 2017		December 31, 2016
Current:
Deferred revenues	$	783	$	1,449
Deferred costs	1,360		2,290
Long-term:
Deferred revenues	$	391	$	202
Deferred costs	162		212

As of September 30, 2017, all 16 of our domestic drilling rigs are earning revenues, 13 of which are under term contracts. Of the eight rigs in Colombia, five are earning revenues, four of which are under term contracts, and an additional rig is under contract, pending operations. The term contracts in Colombia are cancelable by our clients without penalty, although the contract would still require payment for demobilization services and 30 days notice. We are actively marketing our idle drilling rigs in Colombia to various operators and we are evaluating other options, including the possibility of the sale of some or all of our assets in Colombia.

Unbilled Accounts Receivable

The asset “unbilled receivables” represents revenues we have recognized in excess of amounts billed on drilling contracts and production services completed, but not yet billed. We typically bill our clients at 15-day intervals during the performance of daywork drilling contracts and upon completion of the daywork contract. Our unbilled receivables as of September 30, 2017 and December 31, 2016 were as follows (amounts in thousands):



	September 30, 2017		December 31, 2016
Daywork drilling contracts in progress	$	13,391	$	7,042
Production services	877		375
	$	14,268	$	7,417

Prepaid Expenses and Other Current Assets

Prepaid expenses and other current assets include items such as insurance, rent deposits and 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 the current portion of deferred mobilization costs for certain drilling contracts that are recognized on a straight-line basis over the contract term.

Other Long-Term Assets

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

Other Current Liabilities

Our other accrued expenses include accruals for items such as property tax, sales tax, and professional and other fees. We routinely expense these items in the normal course of business over the periods these expenses benefit.

Other Long-Term Liabilities

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

Related-Party Transactions

During the nine months ended September 30, 2017 and 2016, the Company paid approximately $0.1 million in each period 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.

Comprehensive Income

We have not reported comprehensive income due to the absence of items of other comprehensive income in the periods presented.

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 will supersede nearly all existing revenue recognition guidance. The standard 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 have substantially completed our scoping and assessment of the impact of this new standard, although our assessment is still under evaluation. We do not currently expect that the adoption of this standard will have a material impact on our financial position or our results of operations, though we anticipate that it may affect the timing for the recognition of certain types of revenues derived from drilling contracts, and the timing for recognizing certain costs that are incurred to fulfill those contracts. We are continuing to evaluate the requirements of this standard as we work towards finalizing our assessment, and we continue to perform other implementation activities such as establishing new policies, procedures and controls, quantifying the adoption date adjustments and drafting disclosures.

We are required to apply this new standard beginning January 1, 2018. Two methods of transition are permitted under this standard: the full retrospective method, in which the standard would be applied retrospectively to each prior reporting period presented, subject to certain allowable exceptions; or the modified retrospective method, in which the standard would be applied to all contracts existing as of the date of initial application, with the cumulative effect of applying the standard recognized in retained earnings (the adoption date adjustments). We anticipate adopting this standard using the modified retrospective method.

•

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). This ASU is effective for us beginning January 1, 2019 and requires a modified retrospective application, although certain practical expedients are permitted.

We have performed a scoping and preliminary assessment of the impact of this new standard. As a lessor, we expect the adoption of this new standard will apply to our drilling contracts and as a result, we expect to have a lease component and a service component of our revenues derived from drilling contracts. We have not yet determined the impact this standard may have on our production services businesses. As a lessee, this standard will impact us in situations where we lease real estate and office equipment, for which we will recognize a right-of-use asset and a corresponding lease liability on our consolidated balance sheet.

We continue to evaluate the impact of this guidance and have not yet determined its impact on our financial position and results of operations. Although, the future minimum lease payments disclosed in the Liquidity and Capital Resources section included in Part I, Item 2, of this Quarterly Report on Form 10-Q provides some insight to the estimated impact of adoption for us as a lessee.


•	Stock-Based Compensation. In March 2016, the FASB issued ASU No. 2016-09, Stock Compensation: Improvements to Employee Share-Based Payment Accounting, to reduce complexity in accounting standards involving several aspects

of the accounting for employee share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows.

We adopted this ASU as of January 1, 2017 and we recognized a $3.1 million deferred tax asset for previously unrecognized tax benefits, which was then fully reserved by a valuation allowance (see Note 3, Valuation Allowances on Deferred Tax Assets). Additionally, we elected to prospectively account for forfeitures as they occur, rather than estimating future forfeitures. The total cumulative-effect impact of adoption, net of valuation allowances, was approximately $55,000 relating to our change in accounting for forfeitures, and was recognized as a reduction to retained earnings. The adoption of this ASU also results in the presentation of any excess tax benefits resulting from the exercise of stock options as operating cash flows in the statement of cash flows, which we apply retrospectively for any comparative periods affected.

Reclassifications

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

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, 2016.

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 estimate of the allowance for doubtful accounts, our determination of depreciation and amortization expenses, 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, our estimate of compensation related accruals and our estimate of sales tax audit liability.

In preparing the accompanying unaudited condensed consolidated financial statements, we have reviewed events that have occurred after September 30, 2017, through the filing of this Form 10-Q, for inclusion as necessary.

2. Property and Equipment

Capital Expenditures—Our capital expenditures were $54.2 million and $24.0 million, during the nine months ended September 30, 2017 and 2016, respectively, which includes $0.4 million and $0.2 million, respectively, of capitalized interest costs incurred. Capital expenditures during 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. Capital expenditures during 2016 consisted primarily of routine capital expenditures to maintain our drilling and production services fleets.

At September 30, 2017, capital expenditures incurred for property and equipment not yet placed in service was $6.5 million, primarily related to routine capital expenditures on domestic drilling equipment, installments on the purchase of two wireline units, and scheduled refurbishments on production services equipment. At December 31, 2016, property and equipment not yet placed in service was $9.0 million, primarily related to new drilling equipment that was ordered in 2014 which required a long lead-time for delivery, as well as deposits for the 20 well servicing rigs and four new wireline units that were on order for delivery in 2017.

During the nine months ended September 30, 2017, we recognized a net gain of $2.3 million on the disposition of various 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, for which we expect to receive insurance proceeds of $0.4 million.

Assets Held for Sale—As of September 30, 2017, our condensed consolidated balance sheet reflects assets held for sale of $8.8 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 and two coiled tubing units. During the nine months ended September 30, 2017, we recognized impairment charges of $0.8 million to adjust the carrying values of certain of these assets to their estimated fair values, based on expected sales prices, which are classified as Level 3 inputs as defined by Accounting Standards Codification (ASC) Topic 820, Fair Value Measurements and Disclosures.

During the three and nine months ended September 30, 2016, we recognized $3.3 million of impairment charges to reduce the carrying values of assets placed as held for sale to their estimated fair values, based on expected sales prices, and an additional $0.9 million of impairment charges to reduce the carrying value of a portion of the steel that was on hand for the construction of drilling rigs, which we determined was not likely to be used.

Impairments—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). Beginning in late 2014, oil prices declined significantly resulting in a downturn in our industry that persisted through 2016, affecting both drilling and production services. Despite the modest recovery in commodity prices that began in late 2016, we continue to monitor all indicators of potential impairments in accordance with ASC Topic 360, Property, Plant and Equipment.

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. For our Production Services Segment, we perform an impairment evaluation and estimate future undiscounted cash flows for the individual reporting units (well servicing, wireline and coiled tubing). For our Drilling Services Segment, we perform an impairment evaluation and estimate future undiscounted cash flows for individual domestic drilling rig assets and for our Colombian drilling rig assets as a group. 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. The amount of an impairment charge is measured as the difference between the carrying amount and the fair value of the assets.

Due to continued performance at levels lower than anticipated and a decline in our projected cash flows for the coiled tubing reporting unit, we performed an impairment evaluation of our coiled tubing business as of June 30, 2017 and concluded that no impairment was present.

If any of our assets become or remain idle for an extended amount of time, then our estimated cash flows may further decrease, and therefore the probability of a near term sale may increase. If any of the foregoing were to occur, we may incur additional impairment charges. The assumptions used in the impairment evaluation are inherently uncertain and require management judgment.

The following table summarizes impairment charges recognized during the three and nine months ended September 30, 2017 and 2016 (amounts in thousands):



	Three months ended September 30,				Nine months ended September 30,
	2017		2016		2017		2016
Assets held for sale	$	—	$	3,344	$	795	$	3,344
Domestic drilling rigs and equipment	—		918		—		918
	$	—	$	4,262	$	795	$	4,262


3.	Valuation Allowances on Deferred Tax Assets

realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible.

In performing this analysis as of September 30, 2017 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 may 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 net operating losses 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. The majority of our foreign net operating losses have an indefinite carryforward period. However, we have a valuation allowance that fully offsets our foreign deferred tax assets and mostly offsets our domestic deferred tax assets as of September 30, 2017.

During the three and nine months ended September 30, 2017, the impact of valuation allowance adjustments on deferred tax assets was $5.9 million and $19.1 million, respectively. During the three and nine months ended September 30, 2016, the impact of valuation allowance adjustments on deferred tax assets was $11.8 million and $31.6 million, respectively. The valuation allowance is the primary factor causing our effective tax rate to be significantly lower than the statutory rate of 35%. 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.

4. Debt

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



	September 30, 2017			December 31, 2016
Senior secured revolving credit facility	$	97,733		$	46,000
Senior notes	300,000			300,000
	397,733			346,000
Less unamortized debt issuance costs	(5,132		)	(6,527		)
	$	392,601		$	339,473

Senior Secured Revolving Credit Facility

We have a credit agreement, as most recently amended on June 30, 2016, with Wells Fargo Bank, N.A. and a syndicate of lenders which provides for a senior secured revolving credit facility, with sub-limits for letters of credit and swing-line loans, of up to a current aggregate commitment amount of $150 million, subject to availability under a borrowing base comprised of certain eligible cash, certain eligible receivables, certain eligible inventory, and certain eligible equipment of ours and certain of our subsidiaries, all of which matures in March 2019 (the “Revolving Credit Facility”).

Borrowings under the Revolving Credit Facility bear interest, at our option, at the LIBOR rate or at the bank prime rate, plus an applicable per annum margin of 5.50% and 4.50%, respectively. The Revolving Credit Facility requires a commitment fee due quarterly based on the average daily unused amount of the commitments of the lenders, a fronting fee due for each letter of credit issued, and a quarterly letter of credit fee due based on the average undrawn amount of letters of credit outstanding during such period.

The Revolving Credit Facility contains customary mandatory prepayments from the proceeds of certain asset dispositions or equity or debt issuances, which are applied to reduce outstanding revolving and swing-line loans and to cash-collateralize letter of credit exposure, and in certain cases, also reduce the commitment amount available. Additionally, the Revolving Credit Facility requires that if on the last business day of each week, our aggregate amount of cash at the end of the preceding day (as calculated pursuant to the Revolving Credit Facility) exceeds $20 million, we pay down the outstanding principal balance by the amount of such excess.

Our obligations under the Revolving Credit Facility are secured by substantially all of our domestic assets (including equity interests in Pioneer Global Holdings, Inc. and 65% of the outstanding voting equity interests, and 100% of non-voting equity interests, of any first-tier foreign subsidiaries owned by Pioneer Global Holdings, Inc., but excluding any equity interest in, and any assets of, Pioneer Services Holdings, LLC) and are guaranteed by certain of our domestic subsidiaries, including Pioneer Global Holdings, Inc. Borrowings under the Revolving Credit Facility are available for selective acquisitions, working capital and other general corporate purposes.

As of October 31, 2017, we had $101.7 million outstanding under our Revolving Credit Facility and $11.8 million in committed letters of credit, which resulted in borrowing availability of $36.6 million under our Revolving Credit Facility. There are no limitations on our ability to access the borrowing capacity provided there is no default, all representations and warranties are true and correct, and compliance with financial covenants under the Revolving Credit Facility is maintained. At September 30, 2017, we were in compliance with our financial covenants under the Revolving Credit Facility.

The financial covenants contained in our Revolving Credit Facility include the following:


•	A maximum senior consolidated leverage ratio, calculated as senior consolidated debt at the period end, which excludes unsecured and subordinated debt, divided by EBITDA for the trailing twelve month period at each quarter end, as defined in the Revolving Credit Facility. The senior consolidated leverage ratio cannot exceed the maximum amounts as follows:



w	4.00	to 1.00	on	December 31, 2017
w	3.50	to 1.00	on	March 31, 2018
w	3.25	to 1.00	on	June 30, 2018
w	2.50	to 1.00	at any time after June 30, 2018


•	A minimum interest coverage ratio, calculated as EBITDA for the trailing twelve month period at each quarter end, as defined in the Revolving Credit Facility, divided by interest expense for the same period. The interest coverage ratio cannot be less than the minimum amounts as follows:



w	1.25	to 1.00	for the quarterly period ending	December 31, 2017
w	1.50	to 1.00	at any time after December 31, 2017

The Revolving Credit Facility restricts capital expenditures to the following amounts during each forthcoming fiscal year as follows:



w	$35 million	in fiscal year 2017
w	$50 million	in fiscal year 2018
w	$50 million	in fiscal year 2019

The capital expenditure threshold for each of the fiscal years above may be increased by up to 50% of the unused portion of the capital expenditure threshold for the immediate preceding fiscal year, limited to a maximum of $5 million in 2017, and $7.5 million in each of the years 2018 and 2019. In addition to the above requirements, additional capital expenditures may be made up to the amount of net proceeds from equity issuances, or if the following conditions are satisfied:


•	the aggregate outstanding commitments under the Revolving Credit Facility do not exceed $150 million;


•	the pro forma senior leverage and total leverage ratios, calculated as defined in the Revolving Credit Facility, are less than 2.00 to 1.00 and 4.50 to 1.00, respectively.

Pursuant to the terms above, our capital expenditures are limited to a total of $101.7 million for the fiscal year 2017.

The Revolving Credit Facility has additional restrictive covenants that, among other things, limit our ability to:


•	incur additional debt or make prepayments of existing debt;


•	create liens on or dispose of our assets;


•	pay dividends on stock or repurchase stock;


•	enter into acquisitions, mergers, consolidations, sale leaseback transactions, or hedging contracts;


•	make other restricted investments;


•	conduct transactions with affiliates; and


•	limits our use of the net proceeds of any offering of our equity securities to the repayment of debt outstanding under the Revolving Credit Facility.

In addition, the Revolving Credit Facility contains customary events of default, including without limitation:


•	payment defaults;


•	breaches of representations and warranties;


•	covenant defaults;


•	cross-defaults to certain other material indebtedness in excess of specified amounts;


•	certain events of bankruptcy and insolvency;


•	judgment defaults in excess of specified amounts;


•	failure of any guaranty or security document supporting the credit agreement; and


•	change of control.

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, at any time on or after March 15, 2017 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 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 10, Guarantor/Non-Guarantor Condensed Consolidated Financial Statements.)

Debt Issuance Costs

Costs incurred in connection with the Revolving Credit Facility were capitalized and are being amortized using the straight-line method over the term of the Revolving Credit Facility which matures in March 2019. Costs incurred in connection with

the issuance of our Senior Notes were capitalized and are being amortized using the straight-line method (which approximates amortization using the interest method) over the term of the Senior Notes which mature in March 2022.


5.	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. At September 30, 2017 and December 31, 2016, our financial instruments consist primarily of cash, trade and other receivables, trade payables, phantom stock unit awards and long-term debt.

The carrying value of cash, 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, 2017 and December 31, 2016, the aggregate estimated fair value of our phantom stock unit awards was $4.6 million and $7.0 million, respectively, for which the vested portion recognized as a liability in our condensed consolidated balance sheets was $2.4 million and $2.0 million, respectively. The phantom stock unit awards, and the measurement of fair value for these awards, are described in more detail in Note 7, Stock-Based Compensation Plans.

The fair value of our long-term debt is estimated using a discounted cash flow analysis, based on rates that we believe we would currently pay for similar types of debt instruments. This discounted cash flow analysis is based on inputs defined by ASC Topic 820 as Level 2 inputs, which are observable inputs for similar types of debt instruments. The following table presents supplemental fair value information about our long-term debt at September 30, 2017 and December 31, 2016 (amounts in thousands):



	September 30, 2017				December 31, 2016
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Total debt, net of debt issuance costs	$	392,601	$	341,234	$	339,473	$	326,249


6.	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,
	2017			2016			2017			2016
Numerator (both basic and diluted):
Net loss	$	(17,227	)	$	(34,620	)	$	(62,560	)	$	(92,310	)
Denominator:
Weighted-average shares (denominator for basic earnings (loss) per share)	77,552			64,905			77,335			64,755
Diluted effect of outstanding stock options, restricted stock and restricted stock unit awards	—			—			—			—
Denominator for diluted earnings (loss) per share	77,552			64,905			77,335			64,755
Loss per common share—Basic	$	(0.22	)	$	(0.53	)	$	(0.81	)	$	(1.43	)
Loss per common share—Diluted	$	(0.22	)	$	(0.53	)	$	(0.81	)	$	(1.43	)
Potentially dilutive securities excluded as anti-dilutive	4,612			4,550			5,167			4,985


7.	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. In 2016, we granted 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. 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. We adopted ASU 2016-09 in the first quarter of 2017 and elected to prospectively recognize forfeitures when they occur, rather than estimating future forfeitures.

The following table summarizes the stock-based compensation expense recognized, by award type, and the compensation expense recognized for phantom stock unit awards during the three and nine months ended September 30, 2017 and 2016 (amounts in thousands):



	Three months ended September 30,				Nine months ended September 30,
	2017		2016		2017		2016
Stock option awards	$	249	$	192	$	726	$	573
Restricted stock awards	116		116		345		306
Restricted stock unit awards	525		625		2,154		2,119
	$	890	$	933	$	3,225	$	2,998
Phantom stock unit awards	$	878	$	307	$	397	$	1,033

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. The following table summarizes the assumptions used in the Black-Scholes option pricing model based on a weighted-average calculation for the options granted during the nine months ended September 30, 2017 and 2016:



	Nine months ended September 30,
	2017		2016
Expected volatility	76	%	70	%
Risk-free interest rates	2.1	%	1.5	%
Expected life in years	5.86		5.70
Options granted	268,185		905,966
Grant-date fair value	$4.28		$0.80

The assumptions used in the Black-Scholes option pricing model are based on multiple factors, including historical exercise patterns of homogeneous groups with respect to exercise and post-vesting employment termination behaviors, expected future exercising patterns for these same homogeneous groups and volatility of our stock price. As we have not declared dividends since we became a public company, we did not use a dividend yield. In each case, the actual value that will be realized, if any, will depend on the future performance of our common stock and overall stock market conditions. There is no assurance the value an optionee actually realizes will be at or near the value we have estimated using the Black-Scholes options-pricing model.

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.

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, 2017 and 2016:



	Nine months ended September 30,
	2017		2016
Restricted Stock:
Restricted stock awards granted	167,272		166,664
Weighted-average grant-date fair value	$	2.75	$	2.76
Time-based RSUs:
Time-based RSUs granted	96,728		260,334
Weighted-average grant-date fair value	$	5.61	$	1.48
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 2017, we determined that 121% of the target number of shares granted during 2014 were actually earned based on the Company’s achievement of the performance measures as described above. As of September 30, 2017, we estimate that

the weighted average achievement level for our outstanding performance-based RSUs granted in 2015 and 2017 will be approximately 94% of the predetermined performance conditions.

Phantom Stock Unit Awards

In 2016, we granted 1,268,068 phantom stock unit awards with a weighted-average grant-date fair value of $1.35 per share. 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 three-year performance period, 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 (which is four times the stock price on the date of grant).

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. Approximately half of the phantom stock unit awards granted 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. The remaining phantom stock unit awards are subject to performance conditions, based on our EBITDA and EBITDA return on capital employed, relative to our predetermined peer group, and the fair value of these awards is measured using a Black-Scholes pricing model. As of September 30, 2017, our achievement level for the awards granted during 2016 is estimated to be approximately 130%. The final payout percentage will be based on our performance versus the performance of our peer group, over the three year period ending December 31, 2018.

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 statement 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 as of September 30, 2017, if all other inputs were unchanged, would result in an increase in cumulative compensation expense of $0.8 million, which represents the hypothetical increase in fair value of the liability which would be recognized as compensation expense in our statement of operations.


8.	Segment Information

We have two operating segments referred to as the Production Services Segment and the Drilling Services Segment which is the basis management uses for making operating decisions and assessing performance.

Our Production Services Segment provides a range of services, including well servicing, wireline services and coiled tubing services, to a diverse group of exploration and production companies, with our operations concentrated in the major United States onshore oil and gas producing regions in the Mid-Continent and Rocky Mountain states and in the Gulf Coast, both onshore and offshore.

Our Drilling Services Segment provides contract land drilling services to a diverse group of exploration and production companies through our four 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.

The following table sets forth certain financial information for our two operating segments and corporate as of and for the three and nine months ended September 30, 2017 and 2016 (amounts in thousands):



	As of and for the three months ended September 30,				As of and for the nine months ended September 30,
	2017		2016		2017		2016
Production Services Segment:
Revenues	$	74,738	$	40,899	$	199,830	$	116,998
Operating costs	58,304		31,912		156,678		95,503
Segment margin	$	16,434	$	8,987	$	43,152	$	21,495
Identifiable assets	$	252,010	$	246,610	$	252,010	$	246,610
Depreciation and amortization	11,621		12,849		34,753		39,851
Capital expenditures	7,164		2,070		31,282		8,312

Drilling Services Segment:
Revenues	$	42,543	$	27,454	$	120,338	$	88,597
Operating costs	28,386		19,776		81,841		51,989
Segment margin	$	14,157	$	7,678	$	38,497	$	36,608
Identifiable assets	$	440,392	$	463,621	$	440,392	$	463,621
Depreciation and amortization	12,689		15,511		38,681		46,597
Capital expenditures	4,818		7,785		22,313		15,330

Corporate:
Identifiable assets	$	15,040	$	12,566	$	15,040	$	12,566
Depreciation and amortization	313		303		921		961
Capital expenditures	236		175		607		350
Total:
Revenues	$	117,281	$	68,353	$	320,168	$	205,595
Operating costs	86,690		51,688		238,519		147,492
Consolidated margin	$	30,591	$	16,665	$	81,649	$	58,103
Identifiable assets	$	707,442	$	722,797	$	707,442	$	722,797
Depreciation and amortization	24,623		28,663		74,355		87,409
Capital expenditures	12,218		10,030		54,202		23,992

The following table reconciles the consolidated margin of our two operating segments and corporate reported above to income (loss) from operations as reported on the condensed consolidated statements of operations for the three and nine months ended September 30, 2017 and 2016 (amounts in thousands):



	Three months ended September 30,						Nine months ended September 30,
	2017			2016			2017			2016
Consolidated margin	$	30,591		$	16,665		$	81,649		$	58,103
Depreciation and amortization	(24,623		)	(28,663		)	(74,355		)	(87,409		)
General and administrative	(17,528		)	(14,312		)	(51,342		)	(46,078		)
Bad debt (expense) recovery	(491		)	359			98			302
Impairment charges	—			(4,262		)	(795		)	(4,262		)
Gain on dispositions of property and equipment, net	1,159			328			2,251			420
Loss from operations	$	(10,892	)	$	(29,885	)	$	(42,494	)	$	(78,924	)

The following table sets forth certain financial information for our international operations in Colombia as of and for the three and nine months ended September 30, 2017 and 2016 (amounts in thousands):



	As of and for the three months ended September 30,				As of and for the nine months ended September 30,
	2017		2016		2017		2016
Revenues	$	7,403	$	622	$	26,379	$	1,979
Identifiable assets ⁽¹⁾	32,340		37,444		32,340		37,444


(1)	Identifiable assets for our international operations in Colombia 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.


9.	Commitments and Contingencies

In connection with our operations in Colombia, our foreign subsidiaries have obtained bonds for bidding on drilling contracts, performing under drilling contracts, and remitting customs and importation duties. We have guaranteed payments of $43.4 million relating to our performance under these bonds as of September 30, 2017.

We are currently undergoing sales and use tax audits for multi-year periods and we are working to resolve all relevant issues. As of September 30, 2017 and December 31, 2016, our accrued liability was $1.1 million and $0.6 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.


10.	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, 2017, 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, 2017
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	10,780		$	(1,225	)	$	1,297		$	—		$	10,852
Receivables, net of allowance	5			87,786			15,055			(42		)	102,804
Intercompany receivable (payable)	(24,836		)	47,186			(22,350		)	—			—
Inventory	—			6,216			5,542			—			11,758
Assets held for sale	—			8,704			52			—			8,756
Prepaid expenses and other current assets	1,589			2,043			1,699			—			5,331
Total current assets	(12,462		)	150,710			1,295			(42		)	139,501
Net property and equipment	2,185			539,286			25,030			—			566,501
Investment in subsidiaries	573,721			20,198			—			(593,919		)	—
Deferred income taxes	58,545			—			—			(58,545		)	—
Other long-term assets	481			797			162			—			1,440
Total assets	$	622,470		$	710,991		$	26,487		$	(652,506	)	$	707,442
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	467		$	28,858		$	2,683		$	—		$	32,008
Deferred revenues	—			302			481			—			783
Accrued expenses	5,526			38,548			2,690			(42		)	46,722
Total current liabilities	5,993			67,708			5,854			(42		)	79,513
Long-term debt, less debt issuance costs	392,601			—			—			—			392,601
Deferred income taxes	—			67,160			—			(58,545		)	8,615
Other long-term liabilities	2,348			2,402			435			—			5,185
Total liabilities	400,942			137,270			6,289			(58,587		)	485,914
Total shareholders’ equity	221,528			573,721			20,198			(593,919		)	221,528
Total liabilities and shareholders’ equity	$	622,470		$	710,991		$	26,487		$	(652,506	)	$	707,442

	December 31, 2016
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	9,898		$	(764	)	$	1,060		$	—		$	10,194
Receivables, net of allowance	480			64,946			7,210			(513		)	72,123
Intercompany receivable (payable)	(24,836		)	35,427			(10,591		)	—			—
Inventory	—			5,659			4,001			—			9,660
Assets held for sale	—			15,035			58			—			15,093
Prepaid expenses and other current assets	1,280			4,014			1,632			—			6,926
Total current assets	(13,178		)	124,317			3,370			(513		)	113,996
Net property and equipment	2,501			556,062			25,517			—			584,080
Investment in subsidiaries	577,965			24,270			—			(602,235		)	—
Deferred income taxes	65,041			—			—			(65,041		)	—
Other long-term assets	583			1,029			414			—			2,026
Total assets	$	632,912		$	705,678		$	29,301		$	(667,789	)	$	700,102
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	546		$	16,317		$	2,345		$	—		$	19,208
Deferred revenues	—			680			769			—			1,449
Accrued expenses	9,316			34,765			1,777			(513		)	45,345
Total current liabilities	9,862			51,762			4,891			(513		)	66,002
Long-term debt, less debt issuance costs	339,473			—			—			—			339,473
Deferred income taxes	—			73,249			(28		)	(65,041		)	8,180
Other long-term liabilities	2,179			2,702			168			—			5,049
Total liabilities	351,514			127,713			5,031			(65,554		)	418,704
Total shareholders’ equity	281,398			577,965			24,270			(602,235		)	281,398
Total liabilities and shareholders’ equity	$	632,912		$	705,678		$	29,301		$	(667,789	)	$	700,102

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(unaudited, in thousands)



	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	—			80,075			6,615			—			86,690
Depreciation and amortization	313			22,882			1,428			—			24,623
General and administrative	5,737			11,424			505			(138		)	17,528
Intercompany leasing	—			(1,215		)	1,215			—			—
Bad debt 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
Income (loss) from operations	(6,050		)	(2,620		)	(2,360		)	138			(10,892		)
Other (expense) income:
Equity in earnings of subsidiaries	(4,650		)	(2,393		)	—			7,043			—
Interest expense	(6,614		)	1			—			—			(6,613		)
Other (expense) income	9			220			204			(138		)	295
Total other (expense) income	(11,255		)	(2,172		)	204			6,905			(6,318		)
Income (loss) before income taxes	(17,305		)	(4,792		)	(2,156		)	7,043			(17,210		)
Income tax (expense) benefit ¹	78			142			(237		)	—			(17		)
Net income (loss)	$	(17,227	)	$	(4,650	)	$	(2,393	)	$	7,043		$	(17,227	)


	Three months ended September 30, 2016
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Revenues	$	—		$	67,731		$	622		$	—		$	68,353
Costs and expenses:
Operating costs	—			50,061			1,627			—			51,688
Depreciation and amortization	303			26,659			1,701			—			28,663
General and administrative	5,046			9,017			387			(138		)	14,312
Intercompany leasing	—			(1,215		)	1,215			—			—
Bad debt expense	—			(359		)	—			—			(359		)
Impairment charges	—			4,262			—			—			4,262
Gain on dispositions of property and equipment, net	—			(325		)	(3		)	—			(328		)
Total costs and expenses	5,349			88,100			4,927			(138		)	98,238
Income (loss) from operations	(5,349		)	(20,369		)	(4,305		)	138			(29,885		)
Other (expense) income:
Equity in earnings of subsidiaries	(23,794		)	(4,587		)	—			28,381			—
Interest expense	(6,661		)	(14		)	(3		)	—			(6,678		)
Other (expense) income	14			217			152			(138		)	245
Total other (expense) income	(30,441		)	(4,384		)	149			28,243			(6,433		)
Income (loss) before income taxes	(35,790		)	(24,753		)	(4,156		)	28,381			(36,318		)
Income tax (expense) benefit ¹	1,170			959			(431		)	—			1,698
Net income (loss)	$	(34,620	)	$	(23,794	)	$	(4,587	)	$	28,381		$	(34,620	)

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, 2017
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Revenues	$	—		$	293,788		$	26,380		$	—		$	320,168
Costs and expenses:
Operating costs	—			218,344			20,175			—			238,519
Depreciation and amortization	921			69,027			4,407			—			74,355
General and administrative	16,507			33,818			1,431			(414		)	51,342
Intercompany leasing	—			(3,645		)	3,645			—			—
Bad debt recovery	—			(98		)	—			—			(98		)
Impairment charges	—			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
Income (loss) from operations	(17,430		)	(22,327		)	(3,151		)	414			(42,494		)
Other (expense) income:
Equity in earnings of subsidiaries	(19,518		)	(3,924		)	—			23,442			—
Interest expense	(19,110		)	20			—			—			(19,090		)
Other (expense) income	37			678			(77		)	(414		)	224
Total other (expense) income	(38,591		)	(3,226		)	(77		)	23,028			(18,866		)
Income (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 income (loss)	$	(62,560	)	$	(19,518	)	$	(3,924	)	$	23,442		$	(62,560	)


	Nine months ended September 30, 2016
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Revenues	$	—		$	203,616		$	1,979		$	—		$	205,595
Costs and expenses:
Operating costs	—			142,766			4,726			—			147,492
Depreciation and amortization	960			81,257			5,192			—			87,409
General and administrative	16,324			29,061			1,107			(414		)	46,078
Intercompany leasing	—			(3,645		)	3,645			—			—
Bad debt expense	—			(302		)	—			—			(302		)
Impairment charges	—			4,262			—			—			4,262
Gain on dispositions of property and equipment, net	—			(366		)	(54		)	—			(420		)
Total costs and expenses	17,284			253,033			14,616			(414		)	284,519
Income (loss) from operations	(17,284		)	(49,417		)	(12,637		)	414			(78,924		)
Other (expense) income:
Equity in earnings of subsidiaries	(58,421		)	(13,777		)	—			72,198			—
Interest expense	(19,220		)	(88		)	1			—			(19,307		)
Loss on extinguishment of debt	(299		)	—			—			—			(299		)
Other (expense) income	12			1,222			(246		)	(414		)	574
Total other (expense) income	(77,928		)	(12,643		)	(245		)	71,784			(19,032		)
Income (loss) before income taxes	(95,212		)	(62,060		)	(12,882		)	72,198			(97,956		)
Income tax (expense) benefit ¹	2,902			3,639			(895		)	—			5,646
Net income (loss)	$	(92,310	)	$	(58,421	)	$	(13,777	)	$	72,198		$	(92,310	)

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, 2017
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities	$	(35,376	)	$	19,768		$	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	882			(461		)	237			—			658
Beginning cash and cash equivalents	9,898			(764		)	1,060			—			10,194
Ending cash and cash equivalents	$	10,780		$	(1,225	)	$	1,297		$	—		$	10,852

	Nine months ended September 30, 2016
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities	$	(37,104	)	$	44,422		$	326		$	—		$	7,644

Cash flows from investing activities:
Purchases of property and equipment	(352		)	(24,997		)	(235		)	—			(25,584		)
Proceeds from sale of property and equipment	—			2,689			54			—			2,743
	(352		)	(22,308		)	(181		)	—			(22,841		)

Cash flows from financing activities:
Debt repayments	(500		)	—			—			—			(500		)
Proceeds from issuance of debt	12,000			—			—			—			12,000
Debt issuance costs	(819		)	—			—			—			(819		)
Proceeds from exercise of options	183			—			—			—			183
Purchase of treasury stock	(124		)	—			—			—			(124		)
Intercompany contributions/distributions	17,594			(17,524		)	(70		)	—			—
	28,334			(17,524		)	(70		)	—			10,740

Net increase (decrease) in cash and cash equivalents	(9,122		)	4,590			75			—			(4,457		)
Beginning cash and cash equivalents	17,221			(5,612		)	2,551			—			14,160
Ending cash and cash equivalents	$	8,099		$	(1,022	)	$	2,626		$	—		$	9,703


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 that are subject to risks, uncertainties and assumptions. Our actual results, performance or achievements, or industry results, as well as our expectation to refinance our existing $150 million Revolving Credit Facility, 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 revolving credit facility and our senior notes, as well as any other debt agreements we may enter into in the future, operating hazards inherent in our operations, the supply of marketable drilling rigs, well servicing rigs, coiled tubing and wireline units within the industry, the continued availability of drilling rig, well servicing rig, coiled tubing and wireline unit components, 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 and our ability to close our proposed new $175 million term loan and $75 million asset-based revolving lending facility. 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, 2016, 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. (formerly called “Pioneer Drilling Company”) provides land-based drilling services and production services to a diverse group of independent and large oil and gas exploration and production companies in the United States and internationally in Colombia. We also provide two of our services (coiled tubing and wireline services) offshore in the Gulf of Mexico. 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 and enable us to meet multiple needs of our clients.

•

Drilling Services Segment— From 1999 to 2011, we significantly expanded our fleet through acquisitions and the construction of new drilling rigs. As our industry changed with the evolution of shale drilling, we began a transformation process in 2011, by selectively disposing of our older, less capable rigs, while we continued to invest in our rig building program to construct more technologically advanced, pad-optimal rigs to meet the changing needs of our clients.

As of September 30, 2017, our drilling rig fleet is 100% pad-capable. We offer the latest advancements in pad drilling with our fleet of 16 AC rigs in the US and eight SCR rigs in Colombia, all of which have 1,500 horsepower or greater drawworks. The removal of older, less capable rigs from our fleet and the recent investments in the construction of new drilling rigs has transformed our fleet into a highly capable, pad optimal fleet focused on the horizontal drilling market. We believe this positions us to compete well, grow our presence in the significant shale basins in the US, and improve profitability as the recovery of our industry continues.

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 fleet are currently deployed through our division offices in the following regions:



		Rig Count
Marcellus/Utica		6
Eagle Ford		1
Permian Basin		7
Bakken		2
Colombia		8
		24

•

Production Services Segment— Our Production Services Segment provides a range of services to a diverse group of exploration and production companies, with our operations concentrated in the major United States onshore oil and gas producing regions in the Mid-Continent and Rocky Mountain states and in the Gulf Coast, both onshore and offshore. The primary production services we offer are the following:

•

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, 2017, 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 Arkansas, 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, 2017, we have a fleet of 117 wireline units in 17 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, 2017, our coiled tubing business consists of 10 onshore and four offshore coiled tubing units which are deployed through four locations in Texas, Louisiana and Wyoming.

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. Over the last 15 years, we have significantly expanded and transformed our business through acquisitions and organic growth. We conduct our operations through two operating segments: our Drilling Services Segment and our Production Services Segment. Financial information about our operating segments is included in Note 8, 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 NE 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 shift 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.

For additional information concerning the effects of the volatility in oil and gas prices and the effects of technological advancements and trends in our industry, see Item 1A – “Risk Factors” in Part I of our Annual Report on Form 10-K for the year ended December 31, 2016.

Market Conditions — Our industry has experienced a severe down cycle since late 2014 which persisted through 2016 with oil prices (WTI) dipping below $30 in early 2016. A modest recovery in commodity prices began in the latter half of 2016, with an average oil price during the first nine months of 2017 just below $50 per barrel, and a current oil price at September 30, 2017 of almost $52 per barrel.

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

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

With the increases in commodity prices that began in late 2016, we experienced a resulting increase in activity and pricing for our services during 2017.

Our well servicing and coiled tubing utilization rates for the quarter ended September 30, 2017 were 43% and 29%, respectively, based on total fleet count, up from 41% and 22% during the third quarter of 2016, while the number of wireline jobs completed increased by 31% as compared to the third quarter of last year.

A year ago, the utilization of our AC fleet was 81% and there was one rig working in Colombia. Since then, all of our idle domestic rigs have been placed on new contracts and the current utilization of our AC rig fleet is 100%. Of the eight rigs in Colombia, five are earning revenues, four of which are under term contracts, and an additional rig is under contract, pending operations. The term contracts in Colombia are cancelable by our clients without penalty, although the contract would still require payment for demobilization services and 30 days notice. We are actively marketing our idle drilling rigs in Colombia to various operators and we are evaluating other options, including the possibility of the sale of some or all of our assets in Colombia.

As of September 30, 2017, 22 of our 24 drilling rigs are earning revenues, 18 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
U.S. rigs:
Earning under contract	3	13	3	5	5	—	—
Colombia rigs:
Earning under contract	1	4	1	1	—	—	2
Contracted, pending operations	—	1	1	—	—	—	—
	4	18	5	6	5	—	2

Despite the recent increases in activity, current uncertainty in commodity prices could cause our clients to again reduce their spending which would negatively impact our activity and pricing. We expect a highly competitive environment to continue into 2018, but we believe our high-quality equipment, services and safety record make us well positioned to compete.

Liquidity and Capital Resources

Sources of Capital Resources

Our principal sources of liquidity currently consist of:


•	cash and cash equivalents ($10.9 million as of September 30, 2017);


•	cash generated from operations;


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


•	the unused portion of our senior secured revolving credit facility (the “Revolving Credit Facility”).

As of October 31, 2017, we had $101.7 million outstanding under our Revolving Credit Facility and $11.8 million in committed letters of credit, which resulted in borrowing availability of $36.6 million under our Revolving Credit Facility. Our Revolving Credit Facility, as most recently amended on June 30, 2016, provides for a senior secured revolving credit facility, with sub-limits for letters of credit and swing-line loans, of up to a current aggregate commitment amount of $150 million, subject to availability under a borrowing base comprised of certain eligible cash, certain eligible receivables, certain eligible inventory, and certain eligible equipment of ours and certain of our subsidiaries, all of which matures in March 2019.

Borrowings under the Revolving Credit Facility are available for selective acquisitions, working capital and other general corporate purposes. There are no limitations on our ability to access the borrowing capacity provided there is no default, all representations and warranties are true and correct, and compliance with financial covenants under the Revolving Credit Facility is maintained. Additional information regarding these covenants is provided in the Debt Compliance Requirements section below.

At September 30, 2017, we were in compliance with our financial covenants under the Revolving Credit Facility. However, unless we are able to earlier refinance our Revolving Credit Facility as described below, continued compliance with our covenants is largely dependent on our ability to generate sufficient levels of EBITDA, as defined in the Revolving Credit Facility, and/or reduce our debt levels. Additionally, the outstanding balance under our Revolving Credit Facility will become a current liability in March 2018, with the final maturity date in March 2019. We currently expect our future operating results to continue to improve as our industry continues to recover from the downturn. If our expectations for future operating results decline to a level that indicates we may become unable to comply with the financial covenants in the Revolving Credit Facility, and/or if we are unable to refinance our Revolving Credit Facility as described below, we may seek to amend such provisions to remain in compliance or we may pursue other capital sources, such as equity or other debt transactions. Although we believe that our bank lenders are well-secured under the terms of our Revolving Credit Facility, there is no assurance that the bank lenders will waive or amend our financial covenants under the Revolving Credit Facility.

We may also consider equity and/or debt offerings in the future, as appropriate, to meet our liquidity needs. On May 15, 2015, 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, 2017, $234.6 million under the shelf registration statement is available for equity or debt offerings, subject to the limitations imposed by our Revolving Credit 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 Revolving Credit Facility are adequate to cover our liquidity requirements for at least the next 12 months.

Subsequent Events Update

As of November 2, 2017, we are in advanced discussions regarding a new $175 million term loan (the “Term Loan”) and have received a commitment letter for a $75 million senior secured revolving asset-based lending facility (the “ABL Credit Facility”). We expect to use the proceeds from the issuance of the Term Loan to, among other things, fully repay and retire the Revolving Credit Facility.

For further information about our expectations regarding certain terms that will be included in the Term Loan and the ABL Credit Facility, please see Item 5, of Part II of this Quarterly Report on Form 10-Q.

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, which is the primary reason for the $11.3 million of net cash used in operating activities during the nine months ended September 30, 2017. During periods of sustained low activity and pricing, we may access additional capital through the use of available funds under our Revolving Credit Facility.

Working Capital — Our working capital was $60.0 million at September 30, 2017, compared to $48.0 million at December 31, 2016. Our current ratio, which we calculate by dividing current assets by current liabilities, was 1.8 at September 30, 2017, as compared to 1.7 at December 31, 2016. The changes in the components of our working capital were as follows (amounts in thousands), and as described below:



	September 30, 2017		December 31, 2016		Change
Cash and cash equivalents	$	10,852	$	10,194	$	658
Receivables:
Trade, net of allowance for doubtful accounts	71,634		38,764		32,870
Unbilled receivables	14,268		7,417		6,851
Insurance recoveries	13,491		17,003		(3,512		)
Other receivables	3,411		8,939		(5,528		)
Inventory	11,758		9,660		2,098
Assets held for sale	8,756		15,093		(6,337		)
Prepaid expenses and other current assets	5,331		6,926		(1,595		)
Current assets	139,501		113,996		25,505
Accounts payable	32,008		19,208		12,800
Deferred revenues	783		1,449		(666		)
Accrued expenses:
Payroll and related employee costs	19,298		14,813		4,485
Insurance premiums and deductibles	7,811		6,446		1,365
Insurance claims and settlements	13,084		13,667		(583		)
Interest	912		5,395		(4,483		)
Other	5,617		5,024		593
Current liabilities	79,513		66,002		13,511
Working capital	$	59,988	$	47,994	$	11,994

•

Cash and cash equivalents — During 2017, we used $52.8 million of cash for the purchases of property and equipment and used $11.3 million in operating activities, primarily funded by $51.7 million of net borrowings under our Revolving Credit Facility and $10.4 million of proceeds from the sale of assets, as well as $3.1 million of insurance proceeds received from drilling rig damages. Cash used in operations during 2017 was primarily for increased working capital requirements due to the recent and expected increase in activity.

•

Trade and unbilled receivables — The net increase in our total trade and unbilled receivables during 2017 is primarily due to the 64% increase in our revenues during the quarter ended September 30, 2017, as compared to the quarter ended December 31, 2016, as well as the timing of billing and collection cycles for long-term drilling contracts in Colombia. Our domestic trade receivables generally turn over within 90 days.


•	Insurance recoveries — The decrease in our insurance recoveries receivables during 2017 is primarily due to an insurance claim receivable of $3.1 million for a drilling rig that was damaged during 2016, for which the proceeds were received in early 2017.


•	Other receivables — The decrease in other receivables during 2017 is primarily due to the sale of two drilling rigs in December 2016, for which the proceeds of $6.3 million were received in January 2017. This decrease is partially offset by $0.8 million remaining of a short-term note receivable from the sales of two mechanical drilling rigs that were sold during the third quarter of 2017.


•	Inventory — The increase in inventory during 2017 is primarily due to the increase in activity for our Colombian operations, as well as purchases of supplies and job materials for our coiled tubing operations.

•

Assets held for sale — As of September 30, 2017, our condensed consolidated balance sheet reflects assets held for sale of $8.8 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 and two coiled tubing units. At December 31, 2016, our assets held for sale also included the fair value of 20 older well servicing rigs that were traded in for 20 new-model rigs in the first quarter of 2017 as well as two mechanical drilling rigs and 13 wireline units, all of which were sold in 2017; however, it did not include the fair value of the coiled tubing units which were placed as held for sale during 2017.

•

Prepaid expenses and other current assets — The decrease in prepaid expenses and other current assets during 2017 is primarily due to a decrease in prepaid insurance costs because most of the insurance premiums are paid in late October of each year, and therefore we had amortization of eleven months of these October premiums at September 30, 2017, as compared to two months at December 31, 2016. Additionally, the decrease is partially due to the amortization of mobilization costs for several domestic and Colombian drilling rigs which were mobilized under new contracts in late 2016 and early 2017. For more information about rig mobilization service revenues and costs, 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.

•

Accounts payable — Our accounts payable generally turn over within 90 days. The increase in accounts payable during 2017 is primarily due to the 54% increase in our operating costs for the quarter ended September 30, 2017 as compared to the quarter ended December 31, 2016, resulting from an increase in activity, and partially due to a $1.4 million increase in our accruals for capital expenditures.


•	Accrued payroll and related employee costs — The increase in accrued payroll and related employee costs during 2017 is primarily due to timing of pay periods, as well as an 18% increase in headcount as a result of an increase in activity, and higher accruals for projected 2017 annual bonuses.


•	Insurance premiums and deductibles — The increase in insurance premiums and deductibles during 2017 is due to increases in our drilling services and production services utilization and the resulting increased workforce. The increase in utilization and our workforce led to increased actuarial claims estimates for the deductibles under these insurance policies.


•	Accrued interest — The decrease in accrued interest expense during 2017 is primarily due to the payment of interest on our Senior Notes which is due semi-annually on March 15 and September 15.

Debt and Other Contractual Obligations — The following table includes information about the amount and timing of our contractual obligations at September 30, 2017 (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	$	397,733	$	—	$	97,733	$	300,000	$	—
Interest on debt	92,569		24,962		40,044		27,563		—
Purchase commitments	4,100		4,100		—		—		—
Operating leases	10,718		3,268		3,931		1,525		1,994
Incentive compensation	14,318		4,660		9,658		—		—
	$	519,438	$	36,990	$	151,366	$	329,088	$	1,994

•

Debt — Debt obligations at September 30, 2017 consist of $300 million of principal amount outstanding under our Senior Notes which mature on March 15, 2022 and $97.7 million outstanding under our Revolving Credit Facility which is due at maturity on March 31, 2019. However, we may make principal payments to reduce the outstanding balance under our Revolving Credit Facility prior to maturity when cash and working capital is sufficient.

•

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 Revolving Credit Facility were estimated based on (1) the 6.7% interest rate that was in effect at September 30, 2017, and (2) the outstanding balance of $97.7 million at September 30, 2017 to be paid at maturity on March 31, 2019.


•	Purchase commitments — Purchase commitments primarily consist of coiled tubing inventory and equipment, remaining installments on the purchase of two new wireline units to be delivered in the first half of 2018, and routine equipment maintenance and upgrades.


•	Operating leases — Our operating leases consist of lease agreements primarily for office space, operating facilities 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 4, Debt, and Note 10, 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 Revolving Credit Facility contains customary mandatory prepayments from the proceeds of certain asset dispositions or equity or debt issuances, which are applied to reduce outstanding revolving and swing-line loans and to cash-collateralize letter of credit exposure, and in certain cases, also reduce the commitment amount available. There are no limitations on our ability to access the borrowing capacity provided there is no default, all representations and warranties are true and correct, and compliance with financial covenants under the Revolving Credit Facility is maintained.

The Revolving Credit Facility requires a maximum senior consolidated leverage ratio and a minimum interest coverage ratio, both as defined in the Revolving Credit Facility. The Revolving Credit Facility also restricts capital expenditures, and both the Revolving Credit Facility and the Indenture governing our Senior Notes contain additional restrictive covenants that limit our ability to enter into various transactions.

Our obligations under the Revolving Credit Facility are secured by substantially all of our domestic assets and are guaranteed by certain of our domestic subsidiaries. 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.

As of September 30, 2017, we were in compliance with all covenants pertaining to our Senior Notes and Revolving Credit Facility. Our senior consolidated leverage ratio was 2.94 to 1.0 and our interest coverage ratio was 1.45 to 1.0. However, unless we are able to earlier refinance our Revolving Credit Facility as described above, continued compliance with our covenants is largely dependent on our ability to generate sufficient levels of EBITDA, as defined in the Revolving Credit Facility, and/or reduce our debt levels. Additionally, the outstanding balance under our Revolving Credit Facility will become a current liability in March 2018, with the final maturity date in March 2019. We currently expect our future operating results to continue to improve as our industry continues to recover from the downturn. If our expectations for future operating results decline to a level that indicates we may become unable to comply with the financial covenants in the Revolving Credit Facility, and/or if we are unable to refinance our Revolving Credit Facility as described above, we may seek to amend such provisions to remain in compliance or we may pursue other capital sources, such as equity or other debt transactions. Although we believe that our bank lenders are well-secured under the terms of our Revolving Credit Facility, there is no assurance that the bank lenders will waive or amend our financial covenants under the Revolving Credit Facility.

Capital Expenditures — During the nine months ended September 30, 2017, we spent $52.8 million on purchases of property and equipment and placed into service property and equipment of $54.2 million. Currently, we expect to spend approximately $60 million on capital expenditures during 2017, with approximately half allocated to each of our segments. Our total planned capital expenditures for 2017 include approximately $22 million for domestic and international drilling rig upgrades, the exchange of 20 well servicing rigs which was completed in the first quarter of 2017, and the purchase of six wireline units.

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 2017 from operating cash flow in excess of our working capital requirements, proceeds from sales of certain non-strategic assets, and from borrowings under our Revolving Credit Facility, if necessary.

Results of Operations

Statements of Operations Analysis

The following table provides information about our operations for the three and nine months ended September 30, 2017 and 2016 (amounts in thousands, except average number of drilling rigs, utilization rate and revenue day information).



	Three months ended September 30,						Nine months ended September 30,
	2017			2016			2017			2016
Production Services Segment:
Revenues	$	74,738		$	40,899		$	199,830		$	116,998
Operating costs	58,304			31,912			156,678			95,503
Production Services Segment margin ⁽¹⁾	$	16,434		$	8,987		$	43,152		$	21,495

Drilling Services Segment:
Revenues	$	42,543		$	27,454		$	120,338		$	88,597
Operating costs	28,386			19,776			81,841			51,989
Drilling Services Segment margin⁽¹⁾	$	14,157		$	7,678		$	38,497		$	36,608

Average number of drilling rigs	24.0			31.0			24.0			31.0
Utilization rate	79		%	38		%	75		%	41		%
Revenue days	1,755			1,093			4,917			3,513

Average revenues per day	$	24,241		$	25,118		$	24,474		$	25,220
Average operating costs per day	16,174			18,093			16,644			14,799
Drilling Services Segment margin per day	$	8,067		$	7,025		$	7,830		$	10,421

Combined:
Revenues	$	117,281		$	68,353		$	320,168		$	205,595
Operating costs	86,690			51,688			238,519			147,492
Consolidated margin	$	30,591		$	16,665		$	81,649		$	58,103

Net loss	$	(17,227	)	$	(34,620	)	$	(62,560	)	$	(92,310	)
Adjusted EBITDA ⁽²⁾	$	14,026		$	3,285		$	32,880		$	13,321

(1) Production Services Segment margin represents production services revenue less production services operating costs. Drilling Services Segment margin represents contract drilling revenues less contract drilling operating costs. Production Services Segment margin and Drilling Services Segment margin are non-GAAP financial measures which we consider to be important supplemental measures of operating performance. Our management uses these measures to facilitate period-to-period comparisons in operating performance of our reportable segments. We believe that Production Services Segment margin and Drilling Services Segment margin are useful to investors and analysts because they provide a means to evaluate the operating performance of the segments on an ongoing basis using criteria that are used by our

internal decision makers. Additionally, the use of these measures highlights operating trends and aids in analytical comparisons. Production Services Segment margin and Drilling Services Segment margin as presented may not be comparable to other similarly titled measures reported by other companies.

(2) Adjusted EBITDA represents income (loss) before interest expense, income tax (expense) benefit, depreciation and amortization, and loss on extinguishment of debt and impairments, if any. 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 a reconciliation of net loss, as reported, to consolidated Production Services Segment margin and Drilling Services Segment margin are set forth in the following table.



	Three months ended September 30,						Nine months ended September 30,
	2017			2016			2017			2016
	(amounts in thousands)
Reconciliation of net loss and Adjusted EBITDA to consolidated margin:
Net loss	$	(17,227	)	$	(34,620	)	$	(62,560	)	$	(92,310	)
Depreciation and amortization	24,623			28,663			74,355			87,409
Impairment charges	—			4,262			795			4,262
Interest expense	6,613			6,678			19,090			19,307
Loss on extinguishment of debt	—			—			—			299
Income tax expense (benefit)	17			(1,698		)	1,200			(5,646		)
Adjusted EBITDA	14,026			3,285			32,880			13,321
General and administrative	17,528			14,312			51,342			46,078
Bad debt expense (recoveries)	491			(359		)	(98		)	(302		)
Gain on dispositions of property and equipment, net	(1,159		)	(328		)	(2,251		)	(420		)
Other (income) expense	(295		)	(245		)	(224		)	(574		)
Consolidated margin	$	30,591		$	16,665		$	81,649		$	58,103

Consolidated margin — Both our Production Services and Drilling Services Segments experienced an increase in activity during the three and nine months ended September 30, 2017, as compared to the corresponding periods in 2016, as our industry continues to recover from an industry downturn. Our consolidated margin increased 84% and 41% for the three and nine months ended September 30, 2017, respectively, as compared to the corresponding periods in 2016.

Our Production Services Segment’s revenues increased by $33.8 million, or 83%, and $82.8 million, or 71%, for the three and nine months ended September 30, 2017, respectively, as compared to the corresponding periods in 2016, while operating costs increased by $26.4 million, or 83%, and $61.2 million, or 64%, respectively. The following table provides a detail of revenues for each production services business for the three and nine months ended September 30, 2017 and 2016 (amounts in thousands, except percentages).



	Three months ended September 30,								Nine months ended September 30,
	2017				2016				2017				2016
Well Servicing	$	19,103	25	%	$	17,779	43	%	$	58,854	30	%	$	54,643	47	%
Wireline Services	46,085		62	%	18,412		45	%	118,463		59	%	48,266		41	%
Coiled Tubing Services	9,550		13	%	4,708		12	%	22,513		11	%	14,089		12	%
Production services revenues	$	74,738			$	40,899			$	199,830			$	116,998

The increases in our Production Services Segment’s revenues and operating costs are a result of the increased demand for our services, primarily our wireline services. The number of wireline jobs we completed increased by 31% and 46% for

the three and nine months ended September 30, 2017, respectively, as compared to the corresponding periods in 2016. The total rig hours for our well servicing fleet increased by 1% and 5%, for the three and nine months ended September 30, 2017, respectively, as compared to the corresponding periods in 2016, while pricing for these services increased by 7% and 2%. Our coiled tubing utilization increased to 29% and 25% for the three and nine months ended September 30, 2017, respectively, from 22% during both of the corresponding periods in 2016, partly due to the decrease in total fleet count during 2017 as three units were placed as held for sale at June 30, 2017.

Our Drilling Services Segment’s revenues increased by $15.1 million, or 55%, and $31.7 million, or 36%, for the three and nine months ended September 30, 2017, respectively, as compared to the corresponding periods in 2016, while operating costs increased by $8.6 million, or 44%, and $29.9 million, or 57%, respectively. The increases in our Drilling Services Segment’s revenues and operating costs primarily resulted from a 40% increase in revenue days due to the increasing demand in our industry. The increase in our Drilling Services Segment’s operating costs is also primarily a result of the increase in activity, including the increase in revenue days associated with daywork activity during 2017, versus the revenue days associated with rigs that were earning but not working during the corresponding periods in 2016, during which time the rigs incur minimal operating costs. The following table provides the percentages of our drilling revenues by contract type for the three and nine months ended September 30, 2017 and 2016:



	Three months ended September 30,				Nine months ended September 30,
	2017		2016		2017		2016
Daywork contracts (not terminated early)	100	%	94	%	100	%	84	%
Daywork contracts terminated early	—	%	6	%	—	%	15	%
Turnkey contracts	—	%	—	%	—	%	1	%

Our average revenues per day decreased by 3% for both the three and nine months ended September 30, 2017, as compared to the corresponding periods in 2016, while our average operating costs per day decreased by 11% and increased by 12% for the three and nine months ended September 30, 2017, respectively, as compared to the corresponding periods in 2016. Our average revenues per day decreased due to the expiration of term contracts during 2016 that were entered into prior to the downturn at higher revenue rates, many of which were terminated early. The decrease in revenues per day was mostly offset by an increased percentage of our revenues attributable to our Colombian operations, where we typically earn a higher dayrate. Our operating costs per day increased during the nine months ended September 30, 2017, as compared to the corresponding period in 2016, primarily due to a higher percentage of daywork revenues versus revenues earned under contracts that were terminated early, as well as the increased contribution from our Colombian operations where our operating costs per day are higher. The increase in operating costs from increased activity was partially offset by the benefits realized from our reduced cost structure, especially in Colombia, which is the primary reason for the decrease in operating costs per day during the three months ended September 30, 2017, as compared to the corresponding period in 2016.

The following table provides a detail of Drilling Services Segment revenue for our domestic and Colombian operations for the three and nine months ended September 30, 2017 and 2016 (amounts in thousands, except percentages).



	Three months ended September 30,								Nine months ended September 30,
	2017				2016				2017				2016
United States	$	35,140	83	%	$	26,832	98	%	$	93,959	78	%	$	86,618	98	%
Colombia	7,403		17	%	622		2	%	26,379		22	%	1,979		2	%
Drilling services revenues	$	42,543			$	27,454			$	120,338			$	88,597

Depreciation and amortization expense — Our depreciation and amortization expense decreased by $4.0 million and $13.1 million for the three and nine months ended September 30, 2017, respectively, as compared to the corresponding periods in 2016, primarily as a result of the impairment and dispositions of drilling and well servicing rigs and other equipment, including assets we placed as held for sale during 2016. During the three and nine months ended September 30, 2016, we recognized $1.3 million and $5.4 million, respectively, of depreciation on drilling and well servicing rigs which were subsequently sold, retired or placed as held for sale, and $0.3 million and $1.0 million, respectively, of amortization expense for certain intangible assets that were fully amortized by the end of 2016.

Impairment charges — During the nine months ended September 30, 2017 and 2016, we recognized impairment charges of $0.8 million and $4.3 million, respectively, primarily to reduce the carrying values of certain assets which were classified as held for sale, to their estimated fair value based on expected sales prices.

Interest expense — Our interest expense decreased by $0.2 million during the nine months ended September 30, 2017, as compared to the corresponding period in 2016, primarily due to reduced debt outstanding under the Revolving Credit Facility, for which the decrease was mostly offset by the increased interest rate under our Revolving Credit Facility which was amended in June 2016. Average debt outstanding under our Revolving Credit Facility was approximately $77.4 million and $96.6 million during the nine months ended September 30, 2017 and 2016, respectively, while the average interest rate on these borrowings during these periods was approximately 6.5% and 5.4%, respectively.

Income tax expense (benefit) — Our effective income tax rate for the nine months ended September 30, 2017 was lower than the federal statutory rate in the United States primarily due to valuation allowances, as well as the effect of foreign currency translation, state taxes, and other permanent differences. For more detail, see Note 3, Valuation Allowances on Deferred Tax Assets, of the Notes to Condensed Consolidated Financial Statements, included in Part I, Item 1, Financial Statements, of this Quarterly Report on Form 10-Q.

General and administrative expense — Our general and administrative expense increased by approximately $3.2 million, or 22%, and $5.3 million, or 11%, for the three and nine months ended September 30, 2017, respectively, as compared to the corresponding periods in 2016, due primarily to increased compensation costs. The increase in compensation cost was primarily due to a $4.1 million increase in salary and bonus expense during the nine months ended September 30, 2017, partially as a result of increased headcount to accommodate higher activity levels, as well as increased incentive compensation based on improved company performance. In addition, employee benefit costs increased by $0.9 million and stock compensation increased by $0.3 million. These increases in compensation cost were partially offset by a $0.6 million decrease in expense associated with our phantom stock unit awards during the nine months ended September 30, 2017.

Gain on dispositions of property and equipment, net — Our net gain of $2.3 million on the disposition of various property and equipment during the nine months ended September 30, 2017 included 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, for which we expect to receive insurance proceeds of $0.4 million. Our net gain of $0.4 million on the disposition of property and equipment during the corresponding period in 2016 was primarily for the disposal of excess drill pipe which was mostly offset by a loss on the disposition of damaged drilling equipment.

Other (expense) income — Our other income is primarily related to net foreign currency gains recognized for our Colombian operations.

Inflation

When the demand for drilling and production services increases, we may be affected by inflation, which primarily impacts:


•	wage rates for our operations personnel which increase when the availability of personnel is scarce;


•	equipment repair and maintenance costs;


•	costs to upgrade existing equipment; and


•	costs to construct new equipment.

With the recent increases in activity in our industry, we estimate that inflation has had a modest impact on our operations during the three and nine months ended September 30, 2017, which we believe will likely continue as our industry recovers from the downturn.

Critical Accounting Policies and Estimates

The preparation of financial statements in conformity with US 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. As of September 30, 2017, 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, 2016.

Revenues and Cost Recognition — Our Drilling Services Segment earns revenues by drilling oil and gas wells for our clients under daywork contracts. We recognize revenues on daywork contracts for the days completed based on the dayrate specified in each contract.

the related contract term. Costs incurred to relocate rigs and other drilling equipment to areas in which a contract has not been secured are expensed as incurred. 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.

With most term drilling contracts, we are entitled to receive a full or reduced rate of revenues from our clients if they choose to place a rig on standby or to early terminate the contract before its original expiration term. Revenues derived from rigs placed on standby or from the early termination of term drilling contracts are deferred and recognized as the amounts become fixed or determinable, over the remainder of the original term or when the rig is sold.

Our Production Services Segment earns revenues for well servicing, wireline services and coiled tubing services pursuant to master services agreements based on purchase orders, contracts or other arrangements with the client that include fixed or determinable prices. Production services jobs are generally short-term and are charged at current market rates. Production service revenue is recognized when the service has been rendered and collectability is reasonably assured.

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

Long-lived assets — 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. For our Production Services Segment, we perform an impairment evaluation and estimate future undiscounted cash flows for the individual reporting units (well servicing, wireline and coiled tubing). For our Drilling Services Segment, we perform an impairment evaluation and estimate future undiscounted cash flows for individual domestic drilling rig assets and for our Colombian drilling rig assets as a group. 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. The amount of an impairment charge is measured as the difference between the carrying amount and the fair value of the assets. The assumptions used in the impairment evaluation are inherently uncertain and require management judgment.

Deferred taxes — We provide deferred taxes for the basis differences in our property and equipment between financial reporting and tax reporting purposes and other costs such as compensation, net operating loss carryforwards, employee benefit and other accrued liabilities which are deducted in different periods for financial reporting and tax reporting purposes. For property and equipment, differences arise from differences in depreciation periods and methods and the value of assets acquired in a business acquisition where we acquire an entity rather than just its assets. For financial reporting purposes, we depreciate the various components of our drilling rigs, well servicing rigs, wireline units and coiled tubing units over 1 to 25 years and refurbishments over 3 to 5 years, while federal income tax rules require that we depreciate drilling rigs, well servicing rigs, wireline units and coiled tubing units over 5 years. Therefore, in the first 5 years of our ownership of a drilling rig, well servicing rig, wireline unit or coiled tubing unit, our tax depreciation exceeds our financial reporting depreciation, resulting in our providing deferred taxes on this depreciation difference. After 5 years, financial reporting depreciation exceeds tax depreciation, and the deferred tax liability begins to reverse.

Accounting estimates — Material estimates that are particularly susceptible to significant changes in the near term relate to our estimate of the allowance for doubtful accounts, our determination of depreciation and amortization expenses, 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, our estimate of compensation related accruals and our estimate of sales tax audit liability.

•

We estimate an allowance for doubtful accounts based on the creditworthiness of our clients as well as general economic conditions. We evaluate the creditworthiness of our clients based on commercial credit reports, trade references, bank references, financial information, production information and any past experience we have with the client. Consequently, any change in those factors could affect our estimate of our allowance for doubtful accounts. In some instances, we require new clients to establish escrow accounts or make prepayments. We had an allowance for doubtful accounts of $1.1 million and $1.7 million at September 30, 2017 and December 31, 2016, respectively.


•	Our determination of the useful lives of our depreciable assets directly affects our determination of depreciation expense and deferred taxes. A decrease in the useful life of our property and equipment would increase depreciation expense and reduce deferred taxes. We provide for depreciation of our drilling, production, transportation and other equipment

on a straight-line method over useful lives that we have estimated and that range from 1 to 25 years. We record the same depreciation expense whether a drilling rig, well servicing rig, wireline unit or coiled tubing unit is idle or working. Our estimates of the useful lives of our drilling, production, transportation and other equipment are based on our almost 50 years of experience in the oilfield services industry with similar equipment.

•

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). Despite the modest recovery in commodity prices that began in late 2016, we continue to monitor all indicators of potential impairments in accordance with ASC Topic 360, Property, Plant and Equipment. Due to continued performance at levels lower than anticipated and a decline in our projected cash flows for the coiled tubing reporting unit, we performed an impairment evaluation of our coiled tubing business as of June 30, 2017 and concluded that no impairment was present.

The assumptions used in the impairment evaluation are inherently uncertain and require management judgment. Although we believe the assumptions and estimates used in our impairment analyses are reasonable and appropriate, different assumptions and estimates could materially impact the analyses and resulting conclusions. If any of our assets become or remain idle for an extended amount of time, then our estimated cash flows may further decrease, and therefore the probability of a near term sale may increase. If any of the foregoing were to occur, we may incur additional impairment charges.

•

As of September 30, 2017, we had $157.1 million of deferred tax assets related to domestic and foreign net operating losses 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 deferred tax assets and mostly offsets our domestic deferred tax assets as of September 30, 2017. The valuation allowance is the primary factor causing our effective tax rate to be significantly lower than the statutory rate of 35%. For more information, see Note 3, Valuation Allowances on Deferred Tax Assets, of the Notes to Condensed Consolidated Financial Statements, included in Part I, Item 1, Financial Statements, of this Quarterly Report on Form 10-Q.

•

Our accrued insurance premiums and deductibles as of September 30, 2017 include accruals for costs incurred under the self-insurance portion of our health insurance of approximately $2.9 million and our workers’ compensation, general liability and auto liability insurance of approximately $4.7 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 statement 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 7, 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.


•	We are currently undergoing sales and use tax audits for multi-year periods and we are working to resolve all relevant issues. As of September 30, 2017 and December 31, 2016, our accrued liability was $1.1 million and $0.6 million, respectively, based on our estimate of the sales and use tax obligations that are expected to result from these audits.

For more information, see Note 9, Commitments and Contingencies, 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, 2017, we had $97.7 million outstanding under our Revolving Credit Facility, which is our only variable rate debt. The impact of a hypothetical 1% increase or decrease in interest rates on this amount of debt would have resulted in a corresponding increase or decrease, respectively, in interest expense of approximately $0.7 million during the nine months ended September 30, 2017. 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, 2017.

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 $0.2 million for the nine months ended September 30, 2017.


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, 2017, 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, 2017 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, 2017. We did not repurchase any common shares during the quarter ended September 30, 2017.


ITEM 3.	DEFAULTS UPON SENIOR SECURITIES

Not applicable.


ITEM 4.	MINE SAFETY DISCLOSURES

Not applicable.


ITEM 5.	OTHER INFORMATION

(a) On November 2, 2017, the Company issued a press release announcing (i) advanced discussions regarding a new $175 million senior secured term loan (the “Term Loan”) and (ii) its receipt of a commitment letter for a $75 million senior secured revolving asset-based lending facility.

The closing and funding of the Term Loan will be subject to entering into definitive documentation with the lenders thereunder and the fulfillment of various conditions, including delivery of customary closing documents and legal opinions and the creation and perfection of various liens and security interests in a manner satisfactory to the lenders. Additionally, while Wells Fargo Bank, N.A., as administrative agent, sole lead arranger, and sole bookrunner, has provided the Company a commitment letter to fund a proposed senior secured revolving asset-based lending facility (the “ABL Credit Facility”), the Company has not yet entered into the proposed ABL Credit Facility, and closing and funding of the ABL Credit Facility will be subject to certain conditions, including the closing of the Term Loan, which the Company expects will occur concurrently with the ABL Credit Facility.

The following discussion reflects the Company’s expectations regarding certain terms that are expected to be included in the credit agreement that will evidence the Term Loan (the “Term Loan Credit Agreement”) and the ABL Credit Facility, though there can be no assurance that the Company will actually enter into the Term Loan or the ABL Credit Facility. The terms discussed below may not include all of the terms in the proposed Term Loan and the ABL Credit Facility that investors or potential investors may consider to be important, and the ultimate terms may differ. The Company intends to file the definitive Term Loan Credit Agreement and ABL Credit Facility promptly after they become effective.

ABL Credit Facility

The ABL Credit Facility is expected to provide for borrowings in the aggregate principal amount of up to $75 million, including a $30 million sub-limit for letters of credit, under a senior secured credit facility. Available funds would be available for general corporate purposes.

Availability under the ABL Credit Facility is expected to be determined by reference to a borrowing base. The borrowing base at any time will be comprised of a percentage of (i) eligible billed accounts, (ii) eligible unbilled accounts, and (iii) book value of eligible inventory (less certain reserves established under the credit agreement from time to time). The ABL Credit Facility will mature on the earliest of (i) the fifth anniversary of the closing date, (ii) 90 days prior to the scheduled maturity date under the Term Loan and (iii) 90 days prior to the maturity of the Senior Unsecured Notes issued by the Company under the Indenture dated March 18, 2014, between the Company and Wells Fargo, N.A. as trustee (the “Senior Notes”). Interest rates with respect to advances under the ABL Credit Facility are based on, at the Company’s option, (i) the Base Rate plus an applicable margin, or (ii) the LIBOR Rate plus an applicable margin.

The obligations under the ABL Credit Facility are expected to be shared, on a joint and several basis, by the Company and its present and future domestic subsidiaries, subject to certain exceptions. The ABL Credit Facility will be secured by (i) a first-priority perfected security interest in (a) all accounts and all amounts payable in respect of the sale, lease, assignment, license or other disposition of accounts, inventory or services rendered or to be rendered, (b) all chattel paper and rights to payment evidenced thereby, (c) all inventory, (d) all deposit accounts and securities accounts, (e) all documents, letter of credit rights, instruments, and other assets arising out of the items listed herein in (a)-(j), (f) all commercial tort claims relating to the items listed herein in (a)-(j), (g) a portion of business interruption insurance proceeds, (h) all interest, fees, charges or other amounts payable in connection with any account, (i) all payment intangibles, and (j) all substitutions, replacements, accessions, products, or proceeds for any of the foregoing, in each case of the Company and each other obligor under the ABL Credit Facility (collectively, the “ABL Priority Assets”), and (ii) a second-priority perfected security in substantially all tangible and intangible assets of the Company and each other obligor under the ABL Credit Facility, in each case, subject to certain exceptions and permitted liens.

Term Loan Credit Agreement

The Term Loan Credit Agreement is expected to provide for one drawing in the amount of $175 million (the “Term Loan”), which is to be funded on the closing date of the Term Loan. The Company expects to use the proceeds to repay the indebtedness outstanding due under the Amended and Restated Credit Agreement, dated as of June 30, 2011, as amended by the First Amendment thereto dated as of March 3, 2014, the Second Amendment thereto dated as of September 22, 2014, the Third Amendment thereto dated as of September 15, 2015, the Fourth Amendment thereto dated as of December 23, 2015, and the Fifth Amendment thereto dated as of June 30, 2016, by and among the Company, the lenders party thereto, and Wells Fargo Bank, N.A., as administrative agent, issuing lender and swing line lender, together with costs and expenses related thereto, and fees, costs and expenses related to entering into the Term Loan and ABL Credit Facility, with the remainder being used for other lawful general corporate purposes.

The Term Loan will mature on the fifth anniversary of the closing date. Notwithstanding the foregoing, in the event the aggregate indebtedness outstanding on December 14, 2021 under the Company’s existing Senior Notes exceeds $15,000,000, the Company expects that the Term Loan would be scheduled to mature on December 14, 2021. We expect interest on the outstanding principal amount of the Term Loan will accrue at either (i) the Adjusted Eurodollar Rate (subject to a floor of 1%) plus a margin of 775 basis points or (ii) the alternative Base Rate plus an applicable margin. Interest accruing at a rate based on the reserve Adjusted Eurodollar Rate is expected to be payable at the end of the applicable interest rate period (but not less frequently than each three months), with interest accruing at a rate based on the base rate payable on the last business day of each calendar quarter.

The Company expects that the Term Loan will be guaranteed by each of the Company’s direct and indirect wholly-owned domestic subsidiaries, subject to certain exceptions (the “Guarantors”). The Term Loan will be secured by a second lien on all of the ABL Priority Assets and a first lien on substantially all of the other assets of the Company and the Guarantors, in each case, subject to certain exceptions and permitted liens.


ITEM 6.	EXHIBITS

See the Index to Exhibits immediately following the signatures page.

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: November 2, 2017

Index to 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 17, 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 11, 2010, by and among Pioneer Drilling Company, the subsidiary guarantors party thereto and Wells Fargo Bank, National Association, as trustee (Form 8-K dated March 12, 2010 (File No. 1-8182, Exhibit 4.1)).

4.3*	-	Registration Rights Agreement, dated March 11, 2010, by and among Pioneer Drilling Company, the subsidiary guarantors party thereto and the initial purchasers party thereto (Form 8-K dated March 12, 2010 (File No. 1-8182, Exhibit 4.2)).

4.4*	-	First Supplemental Indenture, dated November 21, 2011, by and among Pioneer Drilling Company, the subsidiary guarantors party thereto and Wells Fargo Bank, National Association, as trustee (Form 8-K dated November 21, 2011 (File No. 1-8182, Exhibit 4.2)).

4.5*	-	Registration Rights Agreement, dated November 21, 2011, by and among Pioneer Drilling Company, the subsidiary guarantors party thereto and the initial purchasers party thereto (Form 8-K dated November 21, 2011 (File No. 1-8182, Exhibit 4.3)).

4.6*	-	Second Supplemental Indenture, dated October 1, 2012, by and among Pioneer Coiled Tubing Services, LLC, Pioneer Energy Services Corp., the other subsidiary guarantors and Wells Fargo Bank, National Association, as trustee (Form 10-Q dated November 1, 2012 (File No. 1-8182, Exhibit 4.6)).

4.7*	-	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)).

4.8*	-	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, 2017, 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.

PIONEER ENERGY SERVICES CORP - FORM 10-Q - November 2, 2017

Attached files

PIONEER ENERGY SERVICES CORP Reports