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~~2019



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

Commission File Number: 1-8182

PIONEER ENERGY SERVICES CORP.

(Exact name of registrant as specified in its charter)

~~_____________________________________________~~____________________________________________



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

1250 NEN.E. Loop 410, Suite 1000 San Antonio, Texas		78209
(Address of principal executive offices)		(Zip Code)

Registrant’s telephone number, including area code: (855) 884-0575



Securities registered pursuant to Section 12(b) of the Act
Title of each class	Trading Symbol(s)	Name of each exchange on which registered

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No o

Indicate by check mark whether the registrant has submitted electronically ~~and posted on its corporate Web site, if any,~~ every Interactive Data File required to be submitted ~~and posted~~ pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit ~~and post~~ such files). Yes x No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.



Large accelerated filer	o	Accelerated filer	x

Non-accelerated filer	o	Smaller reporting company	ox
~~(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,~~15, 2019, there were ~~77,719,021~~79,202,216 shares of common stock, par value $0.10 per share, of the registrant outstanding.

TABLE OF CONTENTS

PART I. FINANCIAL INFORMATION


ITEM 1.	FINANCIAL STATEMENTS

PIONEER ENERGY SERVICES CORP. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS


	September 30, 2017			December 31, 2016			September 30, 2019			December 31, 2018
	(unaudited)			(audited)			(unaudited)			(audited)
	(in thousands, except share data)						(in thousands, except share data)
ASSETS
Current assets:
Cash and cash equivalents	$	10,852		$	10,194		$	26,955		$	53,566
Restricted cash							998			998
Receivables:
Trade, net of allowance for doubtful accounts	71,634			38,764			81,039			76,924
Unbilled receivables	14,268			7,417			20,906			24,822
Insurance recoveries	13,491			17,003			23,186			23,656
Other receivables	3,411			8,939			7,421			5,479
Inventory	11,758			9,660			22,086			18,898
Assets held for sale	8,756			15,093			6,233			3,582
Prepaid expenses and other current assets	5,331			6,926			6,991			7,109
Total current assets	139,501			113,996			195,815			215,034
Property and equipment, at cost	1,100,513			1,058,261			1,118,488			1,118,215
Less accumulated depreciation	534,012			474,181			633,233			593,357
Net property and equipment	566,501			584,080			485,255			524,858
Other long-term assets	1,440			2,026
Operating lease assets							7,692			—
Other noncurrent assets							931			1,658
Total assets	$	707,442		$	700,102		$	689,693		$	741,550

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	32,008		$	19,208		$	32,127		$	34,134
Deferred revenues	783			1,449			1,616			1,722
Accrued expenses:
Payroll and related employee costs	19,298			14,813
Employee compensation and related costs							22,489			24,598
Insurance claims and settlements							22,991			23,593
Insurance premiums and deductibles	7,811			6,446			6,036			5,482
Insurance claims and settlements	13,084			13,667
Interest	912			5,395			1,008			6,148
Other	5,617			5,024			12,035			9,091
Total current liabilities	79,513			66,002			98,302			104,768
Long-term debt, less debt issuance costs	392,601			339,473
Long-term debt, less unamortized discount and debt issuance costs							466,887			464,552
Noncurrent operating lease liabilities							6,189			—
Deferred income taxes	8,615			8,180			4,708			3,688
Other long-term liabilities	5,185			5,049
Other noncurrent liabilities							459			3,484
Total liabilities	485,914			418,704			576,545			576,492
Commitments and contingencies (Note 9)
Commitments and contingencies (Note 11)
Shareholders’ equity:
Preferred stock, 10,000,000 shares authorized; none issued and outstanding	—			—			—			—
Common stock $.10 par value; 200,000,000 shares authorized 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
Common stock $.10 par value; 200,000,000 shares authorized; 79,202,216 and 78,214,550 shares outstanding at September 30, 2019 and December 31, 2018, respectively							8,008			7,900
Additional paid-in capital	545,032			541,823			552,453			550,548
Treasury stock, at cost; 630,688 and 515,546 shares at September 30, 2017 and December 31, 2016, respectively	(4,416		)	(3,883		)
Treasury stock, at cost; 877,047 and 789,532 shares at September 30, 2019 and December 31, 2018, respectively							(5,090		)	(4,965		)
Accumulated deficit	(326,923		)	(264,308		)	(442,223		)	(388,425		)
Total shareholders’ equity	221,528			281,398			113,148			165,058
Total liabilities and shareholders’ equity	$	707,442		$	700,102		$	689,693		$	741,550

~~See accompanying notes to~~ ~~condensed consolidated~~ ~~financial statements.~~

PIONEER ENERGY SERVICES CORP. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(unaudited)

Three months ended 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



	Three months ended September 30,						Nine months ended September 30,
	2019			2018			2019			2018
	(in thousands, except per share data)

Revenues	$	146,398		$	149,332		$	445,809		$	448,592

Costs and expenses:
Operating costs	108,059			108,961			332,614			325,924
Depreciation	22,924			23,501			68,428			70,535
General and administrative	30,485			14,043			68,271			58,066
Bad debt expense (recovery), net	196			111			(90		)	(311		)
Impairment	—			239			1,378			2,607
Loss (gain) on dispositions of property and equipment, net	17			(1,861		)	(2,184		)	(2,922		)
Total costs and expenses	161,681			144,994			468,417			453,899
Income (loss) from operations	(15,283		)	4,338			(22,608		)	(5,307		)

Other income (expense):
Interest expense, net of interest capitalized	(10,013		)	(9,811		)	(30,003		)	(28,966		)
Other income (expense), net	(588		)	498			445			1,046
Total other expense, net	(10,601		)	(9,313		)	(29,558		)	(27,920		)

Loss before income taxes	(25,884		)	(4,975		)	(52,166		)	(33,227		)
Income tax expense	(132		)	(258		)	(1,909		)	(1,297		)
Net loss	$	(26,016	)	$	(5,233	)	$	(54,075	)	$	(34,524	)

Loss per common share - Basic	$	(0.33	)	$	(0.07	)	$	(0.69	)	$	(0.44	)

Loss per common share - Diluted	$	(0.33	)	$	(0.07	)	$	(0.69	)	$	(0.44	)

Weighted average number of shares outstanding—Basic	78,473			78,136			78,405			77,897

Weighted average number of shares outstanding—Diluted	78,473			78,136			78,405			77,897

PIONEER ENERGY SERVICES CORP. AND SUBSIDIARIES

~~See accompanying notes to~~ ~~condensed consolidated~~CONDENSED CONSOLIDATED ~~financial statements.~~STATEMENTS OF SHAREHOLDERS’ EQUITY

(unaudited)



	As of and for the nine months ended September 30, 2019
	Shares			Amount					Additional Paid In Capital			Accumulated Deficit			Total Shareholders’ Equity
	Common	Treasury		Common		Treasury			Additional Paid In Capital			Accumulated Deficit			Total Shareholders’ Equity
	(in thousands)
Balance as of December 31, 2018	79,005	(790	)	$	7,900	$	(4,965	)	$	550,548		$	(388,425	)	$	165,058
Net loss	—	—		—		—			—			(15,115		)	(15,115		)
Purchase of treasury stock	—	(84	)	—		(120		)	—			—			(120		)
Cumulative-effect adjustment due to adoption of ASC Topic 842	—	—		—		—			—			277			277
Issuance of restricted stock	326	—		33		—			(33		)	—			—
Stock-based compensation expense	—	—		—		—			867			—			867
Balance as of March 31, 2019	79,331	(874	)	$	7,933	$	(5,085	)	$	551,382		$	(403,263	)	$	150,967
Net loss	—	—		—		—			—			(12,944		)	(12,944		)
Purchase of treasury stock	—	(3	)	—		(5		)	—			—			(5		)
Issuance of restricted stock	667	—		67		—			(67		)	—			—
Stock-based compensation expense	—	—		—		—			327			—			327
Balance as of June 30, 2019	79,998	(877	)	$	8,000	$	(5,090	)	$	551,642		$	(416,207	)	$	138,345
Net loss	—	—		—		—			—			(26,016		)	(26,016		)
Issuance of restricted stock	81	—		8		—			(8		)	—			—
Stock-based compensation expense	—	—		—		—			819			—			819
Balance as of September 30, 2019	80,079	(877	)	$	8,008	$	(5,090	)	$	552,453		$	(442,223	)	$	113,148

PIONEER ENERGY SERVICES CORP. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

(Continued)

(unaudited)



	As of and for the nine months ended September 30, 2018
	Shares			Amount					Additional Paid In Capital			Accumulated Deficit			Total Shareholders’ Equity
	Common	Treasury		Common		Treasury			Additional Paid In Capital			Accumulated Deficit			Total Shareholders’ Equity
	(in thousands)
Balance as of December 31, 2017	78,350	(631	)	$	7,835	$	(4,416	)	$	546,158		$	(339,481	)	$	210,096
Net loss	—	—		—		—			—			(11,139		)	(11,139		)
Purchase of treasury stock	—	(28	)	—		(96		)	—			—			(96		)
Cumulative-effect adjustment due to adoption of ASC Topic 606	—	—		—		—			—			67			67
Issuance of restricted stock	105	—		10		—			(10		)	—			—
Stock-based compensation expense	—	—		—		—			1,259			—			1,259
Balance as of March 31, 2018	78,455	(659	)	$	7,845	$	(4,512	)	$	547,407		$	(350,553	)	$	200,187
Net loss	—	—		—		—			—			(18,152		)	(18,152		)
Exercise of options	3	—		—		—			12			—			12
Purchase of treasury stock	—	(131	)	—		(453		)	—			—			(453		)
Issuance of restricted stock	547	—		55		—			(55		)	—			—
Stock-based compensation expense	—	—		—		—			1,097			—			1,097
Balance as of June 30, 2018	79,005	(790	)	$	7,900	$	(4,965	)	$	548,461		$	(368,705	)	$	182,691
Net loss	—	—		—		—			—			(5,233		)	(5,233		)
Stock-based compensation expense	—	—		—		—			1,039			—			1,039
Balance as of September 30, 2018	79,005	(790	)	$	7,900	$	(4,965	)	$	549,500		$	(373,938	)	$	178,497

PIONEER ENERGY SERVICES CORP. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited)


	Nine months ended September 30,						Nine months ended September 30,
	2017			2016			2019			2018
	(in thousands)						(in thousands)
Cash flows from operating activities:
Net loss	$	(62,560	)	$	(92,310	)	$	(54,075	)	$	(34,524	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depreciation and amortization	74,355			87,409
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation							68,428			70,535
Allowance for doubtful accounts, net of recoveries	(98		)	(302		)	(90		)	(311		)
Write-off of obsolete inventory	—			21			502			—
Gain on dispositions of property and equipment, net	(2,251		)	(420		)	(2,184		)	(2,922		)
Stock-based compensation expense	3,225			2,998			2,013			3,395
Amortization of debt issuance costs	1,395			1,311
Loss on extinguishment of debt	—			299
Impairment charges	795			4,262
Phantom stock compensation expense							(99		)	2,808
Amortization of debt issuance costs and discount							2,335			2,153
Impairment							1,378			2,607
Deferred income taxes	434			(6,372		)	1,020			189
Change in other long-term assets	335			426
Change in other long-term liabilities	136			(833		)
Change in other noncurrent assets							3,125			541
Change in other noncurrent liabilities							(4,163		)	(735		)
Changes in current assets and liabilities:
Receivables	(38,848		)	20,910			(2,126		)	(16,549		)
Inventory	(2,098		)	855			(3,652		)	(4,934		)
Prepaid expenses and other current assets	1,594			2,726			30			329
Accounts payable	11,360			(2,425		)	2,346			1,527
Deferred revenues	(470		)	(4,353		)	(106		)	(173		)
Accrued expenses	1,434			(6,558		)	(6,044		)	(2,446		)
Net cash provided by (used in) operating activities	(11,262		)	7,644
Net cash provided by operating activities							8,638			21,490

Cash flows from investing activities:
Purchases of property and equipment	(52,806		)	(25,584		)	(40,543		)	(48,778		)
Proceeds from sale of property and equipment	10,407			2,743			4,778			4,665
Proceeds from insurance recoveries	3,119			—			641			980
Net cash used in investing activities	(39,280		)	(22,841		)	(35,124		)	(43,133		)

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			—			12
Purchase of treasury stock	(533		)	(124		)	(125		)	(549		)
Net cash provided by financing activities	51,200			10,740
Net cash used in financing activities							(125		)	(537		)

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
Net decrease in cash, cash equivalents and restricted cash							(26,611		)	(22,180		)
Beginning cash, cash equivalents and restricted cash							54,564			75,648
Ending cash, cash equivalents and restricted cash							$	27,953		$	53,468

Supplementary disclosure:
Interest paid	$	22,928		$	22,849		$	32,773		$	31,872
Income tax paid	$	847		$	653		$	3,103		$	2,739
Noncash investing and financing activity:
Change in capital expenditure accruals	$	1,396		$	(1,592	)	$	(4,267	)	$	3,564

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

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



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

Our ~~Production Services Segment provides a range of~~production services business segments provide well, wireline and coiled tubing services to ~~a diverse group of exploration~~producers primarily in Texas 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~~regions, as well as in North Dakota, Louisiana and ~~in the Gulf Coast, both onshore and offshore.~~Mississippi. As of September 30, ~~2017,~~2019, the fleet count for each of our production services ~~fleets~~business segments 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.~~



	550 HP	600 HP	Total
Well servicing rigs, by horsepower (HP) rating	112	12	124

			Total
Wireline services units			93
Coiled tubing services units			9

Basis of Presentation

The accompanying unaudited condensed consolidated financial statements include the accounts of Pioneer Energy Services Corp. and our wholly owned subsidiaries. All intercompany balances and transactions have been eliminated in consolidation. The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America for interim financial information and with the instructions to Form 10-Q and Rule 10-01 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by generally accepted accounting principles for complete financial statements. In the opinion of our management, all adjustments (consisting of normal, recurring accruals) necessary for a fair presentation have been included. We suggest that you read these unaudited condensed consolidated financial statements together with the consolidated financial statements and the related notes included in our annual report on Form 10-K for the year ended December 31, ~~2016.~~2018.

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

Subsequent Events — In preparing the accompanying unaudited condensed consolidated financial statements, we have reviewed events that have occurred after September 30, ~~2017,~~2019, through the filing of this Form 10-Q, for inclusion as necessary.

Change in Accounting Principle and Recently Issued Accounting Standards

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

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

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

Additional Detail of Account Balances

Cash Equivalents and Restricted Cash — Cash equivalents at September 30, 2019 and December 31, 2018 were $13.9 million and $40.6 million, respectively, consisting of investments in highly-liquid money-market mutual funds. Our restricted cash balance reflects the portion of net proceeds from the issuance of our senior secured term loan which are currently held in a restricted account until the completion of certain administrative tasks related to providing access rights to certain of our real property.

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

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

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

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

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

2. Revenue from Contracts with Customers

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

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

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

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

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

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

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

Contract Asset and Liability Balances and Contract Cost Assets

Contract asset and contract liability balances relate to demobilization and mobilization revenues, respectively. Demobilization revenue that we expect to receive is recognized ratably over the related contract term, but invoiced upon completion of the demobilization activity. Mobilization revenue, which is typically collected upon the completion of the initial mobilization activity, is deferred and recognized ratably over the related contract term. Contract asset and liability balances are netted at the contract level, with the net current and noncurrent portions separately classified in our condensed consolidated balance sheets, and referred to herein as “deferred revenues.”

Contract cost assets represent the costs associated with the initial mobilization required in order to fulfill the contract, which are deferred and recognized ratably over the period during which we expect to benefit from the mobilization, or the period during which we expect to satisfy the performance obligations of the related contract. Contract cost assets are presented as

either current or noncurrent, according to the duration of the original contract to which it relates, and referred to herein as “deferred costs.”

Our current and noncurrent deferred revenues and costs as of September 30, 2019 and December 31, 2018 were as follows (amounts in thousands):



	September 30, 2019		December 31, 2018
Current deferred revenues	$	1,616	$	1,722
Current deferred costs	2,418		1,543

Noncurrent deferred revenues	$	77	$	437
Noncurrent deferred costs	130		679

The changes in deferred revenue and cost balances during the nine months ended September 30, 2019 are primarily related to increases in deferred revenue and costs for the deployment of rigs under five new domestic and four new international contracts in 2019, offset by decreases related to the amortization of deferred revenues and costs during the period. Amortization of deferred revenues and costs during the three and nine months ended September 30, 2019 and 2018 were as follows (amounts in thousands):



	Three months ended September 30,				Nine months ended September 30,
	2019		2018		2019		2018
Amortization of deferred revenues	$	1,219	$	720	$	3,453	$	1,762
Amortization of deferred costs	1,293		1,100		3,389		2,050

In 2019, two of our domestic clients elected to early terminate their contract with us and make upfront early termination payments based on a per day rate for the respective remaining contract term, resulting in $2.2 million and $2.6 million of revenue recognized for the three and nine months ended September 30, 2019, respectively. Currently, 21 of our 25 rigs are earning under daywork contracts, 12 of which are domestic term contracts. Unlike our domestic term contracts, our international drilling contracts are cancelable by our clients without penalty, although the contracts require 15 to 30 days notice and payment for demobilization services. The spot contracts for our domestic drilling rigs are also terminable by our client with 30 days notice and include a required payment for demobilization services.

3. Leases

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

As a lessee, we lease our corporate office headquarters in San Antonio, Texas, and we conduct our business operations through 25 other regional offices located throughout the United States and internationally in Colombia. These operating locations typically include regional offices, storage and maintenance yards and employee housing sufficient to support our operations in the area. We lease most of these properties under non-cancelable term and month-to-month operating leases, many of which contain renewal options that can extend the lease term from one to five years and some of which contain escalation clauses. We also lease supplemental equipment, typically under cancelable short-term and very short term (less than 30 days) leases. Due to the nature of our business, any option to renew these short-term leases, and the options to extend certain of our long-term real estate leases, are generally not considered reasonably certain to be exercised. Therefore, the periods covered by such optional periods are not included in the determination of the term of the lease, and the lease payments during these periods are similarly excluded from the calculation of operating lease asset and lease liability balances.

In accordance with ASC Topic 842, we recognize an operating lease asset and a corresponding operating lease liability for all our long-term leases, which include real estate and office equipment leases, for which we elected to combine, or not separate, the lease and non-lease components, and therefore, all fixed charges associated with non-lease components are included in the lease payments and the calculation of the operating lease asset and associated lease liability. The operating

lease asset and operating lease liability are discounted at the rate which represents our secured incremental borrowing rate, as most of our leases do not provide an implicit rate, and which we estimate based on the rate in effect under our asset-based lending facility.

We recognize rent expense on a straight-line basis, except for certain variable expenses which are recognized when the variability is resolved, typically during the period in which they are paid. Variable lease payments typically include charges for property taxes and insurance, and some leases contain variable payments related to non-lease components, including common area maintenance and usage of office equipment (for example, copiers), which totaled approximately $0.3 million and $0.9 million during the three and nine months ended September 30, 2019. The following table summarizes our lease expense recognized, excluding variable lease costs (amounts in thousands):



	Three months ended September 30,		Nine months ended September 30,
	2019		2019
Long-term operating lease expense	$	1,272	$	2,943
Short-term operating lease expense	$	3,754	$	11,490

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



	September 30, 2019			December 31, 2018
Within 1 year	$	2,499		$	3,318
In the second year	1,970			2,032
In the third year	1,624			1,721
In the fourth year	1,235			1,407
In the fifth year	909			1,110
Thereafter	1,041			1,738
Total undiscounted lease obligations	$	9,278		$	11,326
Impact of discounting	(909		)
Discounted value of operating lease obligations	$	8,369

Current operating lease liabilities	$	2,180
Noncurrent operating lease liabilities	6,189
	$	8,369

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



	September 30, 2019
Weighted-average remaining lease term (in years)	4.7
Weighted-average discount rate	4.5	%

4. Property and Equipment

Capital Expenditures—Our capital expenditures were ~~$54.2~~$36.3 million and ~~$24.0~~$52.3 million during the nine months ended September 30, ~~2017~~2019 and ~~2016, respectively, which includes $0.4 million and $0.2 million, respectively, of capitalized interest costs incurred.~~2018, respectively. Capital expenditures during ~~2017~~the nine months ended September 30, 2019 primarily related to ~~the acquisition~~various upgrades and refurbishments 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.~~fleets, vehicle and ancillary equipment purchases, and the completion of construction on our 17^th AC drilling rig, which we deployed in March. Capital expenditures during the nine months ended September 30, 2018 primarily related to various routine expenditures to maintain our fleets and purchase new support equipment, as well as the expansion of our wireline and coiled tubing fleets, capital projects to upgrade and refurbish certain components of our international and domestic drilling rigs and begin construction of one new-build drilling rig, and vehicle fleet upgrades in all domestic business segments.

At September 30, ~~2017,~~2019, capital expenditures incurred for property and equipment not yet placed in service was ~~$6.5~~$3.3 million, primarily related to ~~routine~~ capital ~~expenditures on domestic~~projects to upgrade and refurbish certain components of our drilling ~~equipment, installments on the purchase of two wireline units,~~ and ~~scheduled refurbishments on production services equipment.~~well servicing rig fleets. At December 31, ~~2016,~~2018, property and equipment not yet placed in service was ~~$9.0~~$19.6 million, primarily related to ~~new drilling equipment that was ordered in 2014 which required a long lead-time for delivery, as well as deposits~~approximately $8.0 million of costs for the ~~20 well servicing rigs~~construction of a new-build drilling rig, various refurbishments and ~~four~~upgrades of drilling and production services equipment, and the purchase of other new ~~wireline units that were on order for delivery in 2017.~~ancillary equipment.

Gain/Loss on Disposition of Property — During the nine months ended September 30, ~~2017,~~2019, we recognized a net gain of ~~$2.3~~$2.2 million on the disposition of drill pipe and various other property and equipment, including some assets which were previously held for sale, as well as insurance proceeds received for damaged equipment. During the nine months ended September 30, 2018, we recognized a net gain of $2.9 million on the disposition of various property and equipment, including ~~sales~~the sale of ~~certain~~five coiled tubing ~~equipment~~units, twelve wireline units, and ~~vehicles, as well as the loss of drill pipe in operation,~~one drilling rig, which was previously held 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.~~sale.

Assets Held for Sale—As of September 30, ~~2017,~~2019, our condensed consolidated balance sheet reflects assets held for sale of ~~$8.8~~$6.2 million, which includes the fair value of buildings and yards for one domestic drilling yard and two closed wireline locations, both of which were designated as held for sale in 2019, one domestic SCR drilling rig, two coiled tubing units, and spare support equipment. As of December 31, 2018, our condensed consolidated balance sheet reflects assets held for sale of $3.6 million, which primarily represents the fair value of ~~three~~one domestic SCR drilling ~~rigs~~rig and ~~one domestic mechanical drilling rig, as well as other drilling~~related spare equipment and ~~two~~three coiled tubing units.

During the nine months ended September 30, ~~2017,~~2019 and 2018, we recognized impairment charges of ~~$0.8~~$1.4 million and $2.6 million to ~~adjust~~reduce the carrying values of ~~certain of these~~ assets which were classified as held for sale, to their estimated fair values, based on expected sales prices which are classified as Level 3 inputs as defined by ~~Accounting Standards Codification (ASC)~~ASC Topic 820, Fair Value Measurements and Disclosures.

~~During the three~~Impairments — In accordance with ASC Topic 360, Property, Plant and ~~nine months ended September 30, 2016,~~Equipment, we ~~recognized $3.3 million~~monitor all indicators 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~~—potential 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~~We perform an impairment evaluation and estimate future undiscounted cash flows for ~~the individual reporting units (well~~each of our asset groups separately, which are our domestic drilling services, international drilling services, well servicing, wireline services 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. tubing services segments. If the sum of the estimated future undiscounted net cash flows is less than the carrying amount of the asset group, then we determine the fair value of the asset ~~group. The~~group, and the amount of an impairment charge iswould be measured as the difference between the carrying amount and the fair value of the assets.

Due to ~~continued performance at levels~~ lower than anticipated operating results and a decline in our projected cash flows for the coiled tubing reporting unit, we performed an impairment analysis of this reporting unit at September 30, 2019. As a result of this analysis, we concluded that this reporting unit was not at risk of impairment because the estimated fair value of the reporting unit’s assets was in excess of the carrying value.

The assumptions we use in the evaluation for impairment are inherently uncertain and require management judgment. Although we believe the assumptions and estimates used in our impairment analysis are reasonable, different assumptions and estimates could materially impact the analysis and resulting conclusions. The most significant inputs used in our impairment analysis include the projected utilization and pricing of our ~~coiled tubing business~~services, as well as the estimated proceeds upon any future sale or disposal of ~~June 30, 2017~~the assets, all of which are classified as Level 3 inputs as defined by ASC Topic 820, Fair Value Measurements and ~~concluded that no impairment was present.~~Disclosures

. If commodity prices decrease or remain at current levels for an extended period of time, or if the demand for any of our ~~assets become or remain idle for an extended amount of time, then~~services decreases below what we are currently projecting, our estimated cash flows may ~~further~~ decrease and ~~therefore~~our estimates of the ~~probability~~fair value of ~~a near term sale~~certain assets may ~~increase.~~decrease as well. If any of the foregoing were to occur, we ~~may~~could 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~~on the ~~three and nine months ended September 30, 2017 and 2016 (amounts in thousands):~~related assets.

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


3.5.	Valuation Allowances on Deferred Tax Assets

~~As of September 30, 2017, we had $157.1 million of~~Our deferred tax assets related to ~~domestic and foreign~~ net operating losses, ~~that~~which are available to reduce future taxable ~~income. In assessing~~income, consist of the ~~realizability~~following (amounts in thousands):



	September 30, 2019		December 31, 2018
Domestic net operating loss carryforward	$	101,332	$	96,777
Foreign net operating loss carryforward	6,931		9,582

The majority of our ~~deferred tax assets, we consider whether~~domestic net operating losses will begin to expire in 2030, while losses generated after 2017 are carried forward indefinitely but are limited in usage to 80% of taxable income. The majority of our foreign net operating losses are carried forward indefinitely, but losses generated after 2016 are carried forward for 12 years and will begin to expire in 2029.

We provide a valuation allowance when it is more likely than not that some portion ~~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.~~

~~In performing this analysis~~As result, as of September 30, 2019 and December 31, 2018, we had valuation allowances of $69.7 million and $62.6 million that offset a portion of our domestic and foreign net deferred tax assets.

Since 2017, ~~in accordance with ASC Topic 740,~~ ~~Income Taxes~~,market conditions and operating results for our Colombian operations have improved, and if they continue to improve, then we ~~assessed the available positive and negative~~may determine that there is sufficient evidence ~~to estimate whether sufficient~~that 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 offsetsutilize our foreign deferred tax assets ~~and mostly offsets~~which would result in the reversal of a portion of the valuation allowance relating to our ~~domestic~~foreign 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.assets.

4.6. Debt

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


	September 30, 2017			December 31, 2016			September 30, 2019			December 31, 2018
Senior secured revolving credit facility	$	97,733		$	46,000
Senior secured term loan							$	175,000		$	175,000
Senior notes	300,000			300,000			300,000			300,000
	397,733			346,000			475,000			475,000
Less unamortized discount (based on imputed interest rate of 10.46%)							(2,077		)	(2,668		)
Less unamortized debt issuance costs	(5,132		)	(6,527		)	(6,036		)	(7,780		)
	$	392,601		$	339,473		$	466,887		$	464,552

Senior Secured ~~Revolving Credit~~Term Loan

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

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

The Term Loan contains a financial covenant requiring the ratio of (i) the net orderly liquidation value of our fixed assets (based on appraisals obtained as required by our lenders), on a consolidated basis, in which the lenders under the Term Loan maintain a first priority security interest, plus proceeds of asset dispositions not required to be used to effect a prepayment of the Term Loan to (ii) the outstanding principal amount of the Term Loan, to be at least equal to 1.50 to 1.00 as of any June 30 ~~2016,~~or December 31 of any calendar year through maturity.

The Term Loan contains customary mandatory prepayments from the proceeds of certain transactions including certain asset dispositions and debt issuances, and has additional customary restrictions that, among other things, and subject to certain exceptions, limit our ability to:

incur additional debt;

incur or permit liens on assets;

make investments and acquisitions;

consolidate or merge with ~~Wells Fargo Bank, N.A.~~another company;

engage in asset sales; and ~~a syndicate~~

pay dividends or make distributions.

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

payment defaults;

covenant defaults;

material breaches of representations or warranties;

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

bankruptcy or insolvency;

material judgments against us;

failure of any security document supporting the Term Loan; and

change of control.

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

Asset-based Lending Facility

In addition to entering into the Term Loan, on November 8, 2017, we also entered into a senior secured revolving asset-based credit facility ~~with sub-limits~~(the “ABL Facility”) providing for borrowings in the aggregate principal amount of up to $75 million, subject to a borrowing base and including a $30 million sub-limit for letters of credit 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~~credit. The ABL Facility ~~bear~~bears interest, at our option, at the LIBOR rate or at the ~~bank prime~~base rate as defined in the ABL Facility, plus an applicable ~~per annum~~ margin ~~of 5.50% and 4.50%~~ranging from 1.75% to 3.25%, ~~respectively.~~based on average availability on the ABL Facility. The ~~Revolving Credit~~ABL Facility requires a commitment fee due ~~quarterly~~monthly based on the average ~~daily~~monthly unused amount of the commitments of the lenders, a fronting fee due for each letter of credit issued, and a ~~quarterly~~monthly letter of credit fee due based on the average undrawn amount of letters of credit outstanding during such period.

The ~~Revolving Credit~~ABL Facility ~~contains customary mandatory prepayments from~~is generally set to mature 90 days prior to 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 endmaturity of the ~~preceding day (as calculated pursuant~~Term Loan, subject to certain circumstances, including the ~~Revolving Credit Facility) exceeds $20 million, we pay down the outstanding principal balance by the amount~~future repayment, extinguishment or refinancing of ~~such excess.~~

~~Our obligations~~our Term Loan and/or Senior Notes prior to their respective maturity dates. Availability under the ~~Revolving Credit~~ABL Facility ~~are secured~~is determined by ~~substantially all~~reference to a borrowing base as defined in the agreement, generally comprised of a percentage of our ~~domestic assets (including equity interests in Pioneer Global Holdings, Inc.~~accounts receivable and ~~65% of~~inventory.

We have not drawn upon 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 CreditABL Facility ~~are available for selective acquisitions, working capital and other general corporate purposes.~~

to date. As of ~~October 31, 2017,~~September 30, 2019, we had ~~$101.7 million outstanding under our Revolving Credit Facility and $11.8~~$9.4 million in committed letters of credit, which, after borrowing base limitations, resulted in borrowing availability of ~~$36.6 million~~$50.6 million. Borrowings available under ~~our Revolving Credit Facility. There~~the ABL Facility are available for general corporate purposes, and there are no limitations on our ability to access the borrowing capacity provided there is no default ~~all representations and warranties are true and correct,~~ and compliance with ~~financial~~the covenants under the ~~Revolving Credit~~ABL Facility is maintained. ~~At September 30, 2017, we were in compliance with~~Additionally, if our ~~financial covenants~~availability under the ~~Revolving Credit Facility.~~

~~The financial covenants contained in our Revolving Credit~~ABL Facility ~~include~~is less than 15% of the ~~following:~~

A maximum ~~senior consolidated leverage~~amount (or $11.25 million), we are required to maintain a minimum fixed charge coverage 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~~ABL Facility, of at least 1.00 to 1.00, measured on a trailing ~~twelve~~12 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~~

basis.

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

declare dividends and make other distributions;

issue or sell certain equity interests;

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

make loans or investments (including acquisitions);

incur additional ~~debt~~indebtedness or ~~make prepayments~~modify the terms of ~~existing debt;~~permitted indebtedness;

~~create liens on~~

grant liens;

change our business or ~~dispose~~the business of our ~~assets;~~subsidiaries;

~~pay dividends on stock~~

merge, consolidate, reorganize, recapitalize, or ~~repurchase stock;~~reclassify our equity interests;

sell our assets, and

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

~~make other restricted investments;~~

~~conduct~~certain types of transactions with ~~affiliates;~~affiliates.

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

~~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, subject to certain exceptions, in our ability to:

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

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

create liens on our or their assets;

enter into sale and leaseback transactions;

sell or transfer assets;

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

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

enter into transactions with affiliates; and

enter into new lines of business.

The Senior Notes are not subject to any sinking fund requirements. The Senior Notes are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by certain of our existing domestic subsidiaries and by certain of our future domestic subsidiaries. (See Note ~~10,~~12, Guarantor/Non-Guarantor Condensed ~~Consolidated~~Consolidating Financial Statements.)

Debt Issuance Costs and Original Issue Discount

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


5.7.	Fair Value of Financial Instruments

The FASB’s Accounting Standards Codification (ASC) Topic 820, Fair Value Measurements and Disclosures, defines fair value and provides a hierarchal framework associated with the level of subjectivity used in measuring assets and liabilities at fair value. At ~~September 30, 2017~~ ~~and~~ ~~December 31, 2016, our~~Our financial instruments consist primarily of cash and cash equivalents, trade and other receivables, trade payables, phantom stock unit awards and long-term debt.

The carrying value of cash and cash equivalents, trade and other receivables, and trade payables are considered to be representative of their respective fair values due to the short-term nature of these instruments. At September 30, 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 7,9, Stock-Based Compensation Plans.At September 30, 2019, the estimated aggregate fair value of our phantom stock unit awards was $0.1 million.

The fair value of our ~~long-term debt~~Senior Notes is estimated ~~using a discounted cash flow analysis,~~ based on ~~rates that we believe we would currently pay~~recent observable market prices for ~~similar types of~~our debt ~~instruments. This discounted cash flow analysis is based on inputs~~instruments, which are defined by ASC Topic 820 as Level 2 inputs. The fair value of our Term Loan is based on estimated market pricing for our debt instrument, which is defined by ASC Topic 820 as using Level 3 inputs which are ~~observable inputs for similar types of debt instruments.~~unobservable and therefore more likely to be affected by changes in assumptions. The following table presents supplemental fair value information ~~about~~and carrying value for our ~~long-term~~ debt, at ~~September 30, 2017~~net of discount and ~~December 31, 2016~~debt issuance costs (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



		September 30, 2019				December 31, 2018
	Hierarchy Level	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Senior notes	2	$	297,628	$	114,000	$	296,988	$	186,750
Senior secured term loan	3	169,259		$	166,250	167,564		175,875
		$	466,887	$	280,250	$	464,552	$	362,625


6.8.	Earnings (Loss) Per Common Share

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


	Three months ended September 30,						Nine months ended September 30,						Three months ended September 30,						Nine months ended September 30,
	2017			2016			2017			2016			2019			2018			2019			2018
Numerator (both basic and diluted):
Net loss	$	(17,227	)	$	(34,620	)	$	(62,560	)	$	(92,310	)	$	(26,016	)	$	(5,233	)	$	(54,075	)	$	(34,524	)
Denominator:
Weighted-average shares (denominator for basic earnings (loss) per share)	77,552			64,905			77,335			64,755			78,473			78,136			78,405			77,897
Diluted effect of outstanding stock options, restricted stock and restricted stock unit awards	—			—			—			—
Dilutive 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			78,473			78,136			78,405			77,897
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	)
Loss per common share - Basic													$	(0.33	)	$	(0.07	)	$	(0.69	)	$	(0.44	)
Loss per common share - Diluted													$	(0.33	)	$	(0.07	)	$	(0.69	)	$	(0.44	)
Potentially dilutive securities excluded as anti-dilutive	4,612			4,550			5,167			4,985			5,577			3,964			4,962			4,895


7.9.	Stock-Based Compensation Plans

We ~~grant~~currently have outstanding stock option and restricted stock awards with vesting based on time of service ~~conditions. We grant~~conditions; 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~~conditions; and 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. At this time, however, we have temporarily discontinued the grants of any new equity-based incentive awards.

We recognize compensation cost for our stock-based compensation awards based on the fair value estimated in accordance with ASC Topic ~~718.~~718, Compensation—Stock Compensation, and we recognize forfeitures when they occur. For our awards with graded vesting, we recognize compensation expense on a straight-line basis over the service period for each separately vesting portion of the award as if the award was, in substance, multiple awards. ~~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 (benefit) recognized for phantom stock unit awards during the three and nine months ended September 30, ~~2017~~2019 and ~~2016~~2018 (amounts in thousands):


	Three months ended September 30,				Nine months ended September 30,				Three months ended September 30,						Nine months ended September 30,
	2017		2016		2017		2016		2019			2018			2019			2018
Stock option awards	$	249	$	192	$	726	$	573	$	31		$	101		$	105		$	342
Restricted stock awards	116		116		345		306		135			116			370			344
Restricted stock unit awards	525		625		2,154		2,119		653			822			1,538			2,709
	$	890	$	933	$	3,225	$	2,998	$	819		$	1,039		$	2,013		$	3,395
Phantom stock unit awards	$	878	$	307	$	397	$	1,033	$	(150	)	$	(3,722	)	$	(99	)	$	2,808

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~~We did not grant any stock option ~~pricing model based on a weighted-average calculation for the options granted~~awards 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 at2019 or ~~near the value we have estimated using the Black-Scholes options-pricing model.~~2018.

Restricted Stock and Restricted Stock Unit Awards

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

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

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~~2019 and ~~2016~~2018:

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
$ —



	Nine months ended September 30,
	2019		2018
Restricted Stock:
Restricted stock awards granted	729,112		78,632
Weighted-average grant-date fair value (per share)	$	0.73	$	5.85
Time-based RSUs:
Time-based RSUs granted	870,648		788,377
Weighted-average grant-date fair value (per unit)	$	1.38	$	3.85

Our time-based RSUs generally vest over a three-year period, with fair values based on the closing price of our common stock on the date of grant.

Our performance-based RSUs ~~generally~~ cliff vest ~~after~~at 39 months from the date of grant and are granted at a target number of issuable shares, for which the final number of shares of common stock is adjusted based on our actual achievement levels that are measured against predetermined performance conditions. The number of shares of common stock awarded will be based upon the Company’s achievement in certain performance conditions, as compared to a predefined peer group, over the performance period, generally three years.

~~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,~~2019, we estimate that

the ~~weighted average~~ achievement level for our outstanding performance-based RSUs granted in ~~2015 and~~ 2017 will be approximately ~~94%~~80% of the predetermined performance conditions.

Phantom Stock Unit Awards

~~In 2016, we granted 1,268,068~~We grant phantom stock unit awards with vesting based on time of service, performance and market conditions. Time-based phantom stock unit awards, which were granted in 2019, vest annually in thirds over a ~~weighted-average grant-date fair value of $1.35 per share. These~~three-year vesting period. Performance-based phantom stock unit awards, which were granted in 2016, 2018 and 2019, cliff-vest after 39 months from the date of grant, with vesting based on time of service, performance and market conditions. The number of performance-based units ultimately awarded will be based upon the Company’s achievement in certain performance conditions, as compared to a predefined peer group, over the respective three-year performance ~~period, and each~~periods. Each unit awarded will entitle the employee to a cash payment equal to the stock price of our common stock on the date of vesting, subject to an applicable maximum payout feature that is based on a ~~maximum~~multiple of ~~$8.08 (which is four times~~ the grant date stock ~~price on the date of grant).~~price.

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

The following table summarizes the number, weighted-average grant-date fair value, and applicable maximum cash value 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~~during 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 ofnine months ended 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, 2018.2019 and 2018:



	Nine months ended September 30,
	2019		2018
Performance-based:
Phantom stock unit awards granted	2,467,776		1,188,216
Weighted-average grant-date fair value (per unit)	$	1.10	$	3.06
Maximum cash value per unit (three times the grant date stock price)	$	4.62	$	9.66
Time-based:
Phantom stock unit awards granted	810,648		—
Weighted-average grant-date fair value (per unit)	$	1.17	$	—
Maximum cash value per unit (three times the grant date stock price)	$	4.62	$	—

These awards are classified as liability awards under ASC Topic 718, Compensation—Stock Compensation, because we expect to settle the awards in cash when they vest, and are remeasured at fair value at the end of each reporting period until they vest. The change in fair value is recognized as a current period compensation expense in our ~~statement~~condensed consolidated statements of operations. Therefore, changes in the inputs used to measure fair value can result in volatility in our compensation expense. This volatility increases as the phantom stock awards approach the vesting date. We estimate that a hypothetical increase of $1 in the market price of our common stock, which was $0.06 as of September 30, ~~2017,~~2019, if all other inputs were unchanged, would result in an increase in cumulative compensation expense of ~~$0.8~~$1.2 million, which represents the hypothetical increase in fair value of the liability ~~which~~for the 2018 and 2019 phantom stock unit awards. The maximum payout feature of these awards would limit this volatility if the stock price exceeds the maximum payout threshold. As of September 30, 2019, we estimate the weighted-average achievement level for our outstanding phantom stock unit awards granted in 2018 and 2019 to be ~~recognized as compensation expense in our statement of operations.~~67%.

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


8.10.	Segment Information

We have ~~two~~five operating segments, ~~referred to as the Production Services Segment~~comprised of two drilling services business segments (domestic and ~~the Drilling Services Segment which is the basis management uses for making operating decisions~~international drilling) and ~~assessing performance.~~

~~Our Production Services Segment provides a range of~~three production services ~~including well~~business segments (well servicing, wireline services and coiled tubing services), which reflects the basis used by management in making decisions regarding our business for resource allocation and performance assessment, as required by ASC Topic 280, Segment Reporting.

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

Our well servicing, wireline services and coiled tubing services segments provide a range of production services to producers primarily in Texas and the Mid-Continent and Rocky Mountain regions, as well as in North Dakota, Louisiana and Mississippi.

The following ~~table sets~~tables set forth certain financial information for each of 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 )



	As of and for the three months ended September 30,				As of and for the nine months ended September 30,
	2019		2018		2019		2018
Revenues:
Domestic drilling	$	38,168	$	36,586	$	115,829	$	108,146
International drilling	21,617		23,131		68,682		62,515
Drilling services	59,785		59,717		184,511		170,661
Well servicing	30,293		24,369		86,053		68,645
Wireline services	43,874		52,654		137,134		171,392
Coiled tubing services	12,446		12,592		38,111		37,894
Production services	86,613		89,615		261,298		277,931
Consolidated revenues	$	146,398	$	149,332	$	445,809	$	448,592

Operating costs:
Domestic drilling	$	21,931	$	21,650	$	69,098	$	64,297
International drilling	15,844		19,013		50,884		49,038
Drilling services	37,775		40,663		119,982		113,335
Well servicing	21,414		17,193		61,348		49,443
Wireline services	38,349		40,840		119,500		130,042
Coiled tubing services	10,521		10,265		31,784		33,104
Production services	70,284		68,298		212,632		212,589
Consolidated operating costs	$	108,059	$	108,961	$	332,614	$	325,924

Gross margin:
Domestic drilling	$	16,237	$	14,936	$	46,731	$	43,849
International drilling	5,773		4,118		17,798		13,477
Drilling services	22,010		19,054		64,529		57,326
Well servicing	8,879		7,176		24,705		19,202
Wireline services	5,525		11,814		17,634		41,350
Coiled tubing services	1,925		2,327		6,327		4,790
Production services	16,329		21,317		48,666		65,342
Consolidated gross margin	$	38,339	$	40,371	$	113,195	$	122,668

Identifiable Assets:
Domestic drilling⁽¹⁾	$	354,534	$	375,982	$	354,534	$	375,982
International drilling ^{(1) (2)}	47,320		41,807		47,320		41,807
Drilling services	401,854		417,789		401,854		417,789
Well servicing	118,686		123,933		118,686		123,933
Wireline services	80,054		96,585		80,054		96,585
Coiled tubing services	34,339		34,866		34,339		34,866
Production services	233,079		255,384		233,079		255,384
Corporate	54,760		79,702		54,760		79,702
Consolidated identifiable assets	$	689,693	$	752,875	$	689,693	$	752,875

Depreciation:
Domestic drilling	$	10,864	$	10,358	$	32,297	$	30,946
International drilling	1,512		1,463		4,228		4,211
Drilling services	12,376		11,821		36,525		35,157
Well servicing	5,132		4,903		14,956		14,688
Wireline services	3,537		4,518		11,519		13,727
Coiled tubing services	1,660		1,991		4,719		6,137
Production services	10,329		11,412		31,194		34,552
Corporate	219		268		709		826
Consolidated depreciation	$	22,924	$	23,501	$	68,428	$	70,535

~~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



	As of and for the three months ended September 30,				As of and for the nine months ended September 30,
	2019		2018		2019		2018
Capital Expenditures:
Domestic drilling	$	2,777	$	6,274	$	14,344	$	13,768
International drilling	1,162		264		3,444		4,177
Drilling services	3,939		6,538		17,788		17,945
Well servicing	2,146		2,989		8,182		8,441
Wireline services	775		3,973		5,198		12,563
Coiled tubing services	1,756		4,498		4,567		12,479
Production services	4,677		11,460		17,947		33,483
Corporate	44		419		541		914
Consolidated capital expenditures	$	8,660	$	18,417	$	36,276	$	52,342


(1)	Identifiable assets for our drilling segments include the impact of a $37.5 million and $39.4 million intercompany balance, as of September 30, 2019 and 2018, respectively, between our domestic drilling segment (intercompany receivable) and our international ~~operations in Colombia~~drilling segment (intercompany payable).


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

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



	Three months ended September 30,						Nine months ended September 30,
	2019			2018			2019			2018
Consolidated gross margin	$	38,339		$	40,371		$	113,195		$	122,668
Depreciation	(22,924		)	(23,501		)	(68,428		)	(70,535		)
General and administrative	(30,485		)	(14,043		)	(68,271		)	(58,066		)
Bad debt (expense) recovery, net	(196		)	(111		)	90			311
Impairment	—			(239		)	(1,378		)	(2,607		)
Gain (loss) on dispositions of property and equipment, net	(17		)	1,861			2,184			2,922
Income (loss) from operations	$	(15,283	)	$	4,338		$	(22,608	)	$	(5,307	)


9.11.	Commitments and Contingencies

In connection with our operations in Colombia, our foreign subsidiaries ~~have obtained~~routinely obtain bonds for bidding on drilling contracts, performing under drilling contracts, and remitting customs and importation duties. We have guaranteed payments of ~~$43.4~~$70.2 million relating to our performance under these bonds as of September 30, ~~2017~~.2019. Based on historical experience and information currently available, we believe the likelihood of demand for payment under these bonds and guarantees is remote.

We are currently undergoing sales and use tax audits for multi-year ~~periods and we are working to resolve all relevant issues.~~periods. As of September 30, ~~2017~~2019 and December 31, ~~2016,~~2018, our accrued liability was ~~$1.1~~$1.9 million and $~~0.6~~1.7 million, respectively, based on our estimate of the sales and use tax obligations that are expected to result from these audits. Due to the inherent uncertainty of the audit process, we believe that it is reasonably possible that we may incur additional tax assessments with respect to one or more of the audits in excess of the amount accrued. We believe that such an outcome would not have a material adverse effect on our results of operations or financial position. Because certain of these audits are in a preliminary stage, an estimate of the possible loss or range of loss from an adverse result in all or substantially all of these cases cannot reasonably be made.

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


~~10.~~12.	Guarantor/Non-Guarantor Condensed Consolidating Financial Statements

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

In the event of a bankruptcy, liquidation or reorganization of any non-guarantor subsidiary, such non-guarantor subsidiary will pay the holders of its debt and other liabilities, including its trade creditors, before it will be able to distribute any of its assets to us. In the future, any non-U.S. subsidiaries, immaterial subsidiaries and subsidiaries that we designate as unrestricted subsidiaries under the Indenture will not guarantee the Senior Notes. As of September 30, ~~2017~~2019, there were no restrictions on the ability of subsidiary guarantors to transfer funds to the parent company.

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

CONDENSED CONSOLIDATING BALANCE SHEETS

(unaudited, in thousands)


	September 30, 2017														September 30, 2019
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated		Parent			Guarantor Subsidiaries		Non-Guarantor Subsidiaries			Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	10,780		$	(1,225	)	$	1,297		$	—		$	10,852	$	22,195		$	—	$	4,760		$	—		$	26,955
Restricted cash															998			—		—			—			998
Receivables, net of allowance	5			87,786			15,055			(42		)	102,804		258			96,704		34,979			611			132,552
Intercompany receivable (payable)	(24,836		)	47,186			(22,350		)	—			—		(28,105		)	65,374		(37,269		)	—			—
Inventory	—			6,216			5,542			—			11,758		—			10,103		11,983			—			22,086
Assets held for sale	—			8,704			52			—			8,756		—			6,233		—			—			6,233
Prepaid expenses and other current assets	1,589			2,043			1,699			—			5,331		2,497			2,994		1,500			—			6,991
Total current assets	(12,462		)	150,710			1,295			(42		)	139,501		(2,157		)	181,408		15,953			611			195,815
Net property and equipment	2,185			539,286			25,030			—			566,501		1,853			456,106		27,296			—			485,255
Investment in subsidiaries	573,721			20,198			—			(593,919		)	—		545,141			32,086		—			(577,227		)	—
Deferred income taxes	58,545			—			—			(58,545		)	—		44,277			—		—			(44,277		)	—
Other long-term assets	481			797			162			—			1,440
Operating lease assets															3,234			3,852		606			—			7,692
Other noncurrent assets															512			415		4			—			931
Total assets	$	622,470		$	710,991		$	26,487		$	(652,506	)	$	707,442	$	592,860		$	673,867	$	43,859		$	(620,893	)	$	689,693
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	467		$	28,858		$	2,683		$	—		$	32,008	$	1,441		$	26,000	$	4,686		$	—		$	32,127
Deferred revenues	—			302			481			—			783		—			424		1,192			—			1,616
Accrued expenses	5,526			38,548			2,690			(42		)	46,722		8,342			50,166		5,440			611			64,559
Total current liabilities	5,993			67,708			5,854			(42		)	79,513		9,783			76,590		11,318			611			98,302
Long-term debt, less debt issuance costs	392,601			—			—			—			392,601
Long-term debt, less unamortized discount and debt issuance costs															466,887			—		—			—			466,887
Noncurrent operating lease liabilities															2,859			2,875		455			—			6,189
Deferred income taxes	—			67,160			—			(58,545		)	8,615		—			48,985		—			(44,277		)	4,708
Other long-term liabilities	2,348			2,402			435			—			5,185
Other noncurrent liabilities															183			276		—			—			459
Total liabilities	400,942			137,270			6,289			(58,587		)	485,914		479,712			128,726		11,773			(43,666		)	576,545
Total shareholders’ equity	221,528			573,721			20,198			(593,919		)	221,528		113,148			545,141		32,086			(577,227		)	113,148
Total liabilities and shareholders’ equity	$	622,470		$	710,991		$	26,487		$	(652,506	)	$	707,442	$	592,860		$	673,867	$	43,859		$	(620,893	)	$	689,693

	December 31, 2016														December 31, 2018
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated		Parent			Guarantor Subsidiaries		Non-Guarantor Subsidiaries			Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	9,898		$	(764	)	$	1,060		$	—		$	10,194	$	50,350		$	—	$	3,216		$	—		$	53,566
Restricted cash															998			—		—			—			998
Receivables, net of allowance	480			64,946			7,210			(513		)	72,123		436			95,030		35,219			196			130,881
Intercompany receivable (payable)	(24,836		)	35,427			(10,591		)	—			—		(27,245		)	67,098		(39,853		)	—			—
Inventory	—			5,659			4,001			—			9,660		—			9,945		8,953			—			18,898
Assets held for sale	—			15,035			58			—			15,093		—			3,582		—			—			3,582
Prepaid expenses and other current assets	1,280			4,014			1,632			—			6,926		1,743			3,197		2,169			—			7,109
Total current assets	(13,178		)	124,317			3,370			(513		)	113,996		26,282			178,852		9,704			196			215,034
Net property and equipment	2,501			556,062			25,517			—			584,080		2,022			494,376		28,460			—			524,858
Investment in subsidiaries	577,965			24,270			—			(602,235		)	—		574,695			25,370		—			(600,065		)	—
Deferred income taxes	65,041			—			—			(65,041		)	—		42,585			—		—			(42,585		)	—
Other long-term assets	583			1,029			414			—			2,026
Other noncurrent assets															596			511		551			—			1,658
Total assets	$	632,912		$	705,678		$	29,301		$	(667,789	)	$	700,102	$	646,180		$	699,109	$	38,715		$	(642,454	)	$	741,550
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	546		$	16,317		$	2,345		$	—		$	19,208	$	1,093		$	26,795	$	6,246		$	—		$	34,134
Deferred revenues	—			680			769			—			1,449		—			95		1,627			—			1,722
Accrued expenses	9,316			34,765			1,777			(513		)	45,345		14,020			49,640		5,056			196			68,912
Total current liabilities	9,862			51,762			4,891			(513		)	66,002		15,113			76,530		12,929			196			104,768
Long-term debt, less debt issuance costs	339,473			—			—			—			339,473
Long-term debt, less unamortized discount and debt issuance costs															464,552			—		—			—			464,552
Deferred income taxes	—			73,249			(28		)	(65,041		)	8,180		—			46,273		—			(42,585		)	3,688
Other long-term liabilities	2,179			2,702			168			—			5,049
Other noncurrent liabilities															1,457			1,611		416			—			3,484
Total liabilities	351,514			127,713			5,031			(65,554		)	418,704		481,122			124,414		13,345			(42,389		)	576,492
Total shareholders’ equity	281,398			577,965			24,270			(602,235		)	281,398		165,058			574,695		25,370			(600,065		)	165,058
Total liabilities and shareholders’ equity	$	632,912		$	705,678		$	29,301		$	(667,789	)	$	700,102	$	646,180		$	699,109	$	38,715		$	(642,454	)	$	741,550

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(unaudited, in thousands)


	Three months ended September 30, 2017															Three months ended September 30, 2019
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated			Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Revenues	$	—		$	109,878		$	7,403		$	—		$	117,281		$	—		$	124,781		$	21,617		$	—		$	146,398
Costs and expenses:
Operating costs	—			80,075			6,615			—			86,690			—			92,216			15,843			—			108,059
Depreciation and amortization	313			22,882			1,428			—			24,623
Depreciation																219			21,193			1,512			—			22,924
General and administrative	5,737			11,424			505			(138		)	17,528			15,979			13,640			1,001			(135		)	30,485
Intercompany leasing	—			(1,215		)	1,215			—			—			—			(1,215		)	1,215			—			—
Bad debt recovery	—			491			—			—			491
Gain on dispositions of property and equipment, net	—			(1,159		)	—			—			(1,159		)
Bad debt expense, net of recovery																—			196			—			—			196
Loss (gain) on dispositions of property and equipment, net																—			28			(11		)	—			17
Total costs and expenses	6,050			112,498			9,763			(138		)	128,173			16,198			126,058			19,560			(135		)	161,681
Income (loss) from operations	(6,050		)	(2,620		)	(2,360		)	138			(10,892		)	(16,198		)	(1,277		)	2,057			135			(15,283		)
Other (expense) income:
Other income (expense):
Equity in earnings of subsidiaries	(4,650		)	(2,393		)	—			7,043			—			(640		)	1,164			—			(524		)	—
Interest expense	(6,614		)	1			—			—			(6,613		)	(10,020		)	3			4			—			(10,013		)
Other (expense) income	9			220			204			(138		)	295
Total other (expense) income	(11,255		)	(2,172		)	204			6,905			(6,318		)
Other income (expense)																86			236			(775		)	(135		)	(588		)
Total other income (expense), net																(10,574		)	1,403			(771		)	(659		)	(10,601		)
Income (loss) before income taxes	(17,305		)	(4,792		)	(2,156		)	7,043			(17,210		)	(26,772		)	126			1,286			(524		)	(25,884		)
Income tax (expense) benefit ¹	78			142			(237		)	—			(17		)	756			(766		)	(122		)	—			(132		)
Net income (loss)	$	(17,227	)	$	(4,650	)	$	(2,393	)	$	7,043		$	(17,227	)	$	(26,016	)	$	(640	)	$	1,164		$	(524	)	$	(26,016	)


	Three months ended September 30, 2016															Three months ended September 30, 2018
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated			Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Revenues	$	—		$	67,731		$	622		$	—		$	68,353		$	—		$	126,202		$	23,130		$	—		$	149,332
Costs and expenses:
Operating costs	—			50,061			1,627			—			51,688			—			89,950			19,011			—			108,961
Depreciation and amortization	303			26,659			1,701			—			28,663
Depreciation																269			21,769			1,463			—			23,501
General and administrative	5,046			9,017			387			(138		)	14,312			2,260			11,152			736			(105		)	14,043
Intercompany leasing	—			(1,215		)	1,215			—			—			—			(1,215		)	1,215			—			—
Bad debt expense	—			(359		)	—			—			(359		)
Impairment charges	—			4,262			—			—			4,262
Bad debt expense, net of recovery																—			111			—			—			111
Impairment																—			239			—			—			239
Gain on dispositions of property and equipment, net	—			(325		)	(3		)	—			(328		)	—			(1,856		)	(5		)	—			(1,861		)
Total costs and expenses	5,349			88,100			4,927			(138		)	98,238			2,529			120,150			22,420			(105		)	144,994
Income (loss) from operations	(5,349		)	(20,369		)	(4,305		)	138			(29,885		)	(2,529		)	6,052			710			105			4,338
Other (expense) income:
Other income (expense):
Equity in earnings of subsidiaries	(23,794		)	(4,587		)	—			28,381			—			5,011			618			—			(5,629		)	—
Interest expense	(6,661		)	(14		)	(3		)	—			(6,678		)	(9,802		)	(12		)	3			—			(9,811		)
Other (expense) income	14			217			152			(138		)	245
Total other (expense) income	(30,441		)	(4,384		)	149			28,243			(6,433		)
Other income																244			222			137			(105		)	498
Total other income (expense), net																(4,547		)	828			140			(5,734		)	(9,313		)
Income (loss) before income taxes	(35,790		)	(24,753		)	(4,156		)	28,381			(36,318		)	(7,076		)	6,880			850			(5,629		)	(4,975		)
Income tax (expense) benefit ¹	1,170			959			(431		)	—			1,698			1,843			(1,869		)	(232		)	—			(258		)
Net income (loss)	$	(34,620	)	$	(23,794	)	$	(4,587	)	$	28,381		$	(34,620	)	$	(5,233	)	$	5,011		$	618		$	(5,629	)	$	(5,233	)

¹ The income tax expense (benefit) reflected in each column does not include any tax effect of the equity in earnings (losses) of subsidiaries.
¹ The income tax (expense) benefit reflected in each column does not include any tax effect of the equity in earnings (losses) of subsidiaries.																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															Nine months ended September 30, 2019
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated			Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Revenues	$	—		$	293,788		$	26,380		$	—		$	320,168		$	—		$	377,127		$	68,682		$	—		$	445,809
Costs and expenses:
Operating costs	—			218,344			20,175			—			238,519			—			281,735			50,879			—			332,614
Depreciation and amortization	921			69,027			4,407			—			74,355
Depreciation																709			63,491			4,228			—			68,428
General and administrative	16,507			33,818			1,431			(414		)	51,342			30,882			35,665			2,129			(405		)	68,271
Intercompany leasing	—			(3,645		)	3,645			—			—			—			(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		)
Bad debt recovery, net of expense																—			(90		)	—			—			(90		)
Impairment																—			1,378			—			—			1,378
Gain on dispositions of property and equipment, net																—			(2,077		)	(107		)	—			(2,184		)
Total costs and expenses	17,430			316,115			29,531			(414		)	362,662			31,591			376,457			60,774			(405		)	468,417
Income (loss) from operations	(17,430		)	(22,327		)	(3,151		)	414			(42,494		)	(31,591		)	670			7,908			405			(22,608		)
Other (expense) income:
Other income (expense):
Equity in earnings of subsidiaries	(19,518		)	(3,924		)	—			23,442			—			5,433			7,059			—			(12,492		)	—
Interest expense	(19,110		)	20			—			—			(19,090		)	(29,953		)	(12		)	(38		)	—			(30,003		)
Other (expense) income	37			678			(77		)	(414		)	224
Total other (expense) income	(38,591		)	(3,226		)	(77		)	23,028			(18,866		)
Other income (expense)																383			903			(436		)	(405		)	445
Total other income (expense), net																(24,137		)	7,950			(474		)	(12,897		)	(29,558		)
Income (loss) before income taxes	(56,021		)	(25,553		)	(3,228		)	23,442			(61,360		)	(55,728		)	8,620			7,434			(12,492		)	(52,166		)
Income tax (expense) benefit ¹	(6,539		)	6,035			(696		)	—			(1,200		)	1,653			(3,187		)	(375		)	—			(1,909		)
Net income (loss)	$	(62,560	)	$	(19,518	)	$	(3,924	)	$	23,442		$	(62,560	)	$	(54,075	)	$	5,433		$	7,059		$	(12,492	)	$	(54,075	)


	Nine months ended September 30, 2016															Nine months ended September 30, 2018
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated			Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Revenues	$	—		$	203,616		$	1,979		$	—		$	205,595		$	—		$	386,077		$	62,515		$	—		$	448,592
Costs and expenses:
Operating costs	—			142,766			4,726			—			147,492			—			276,893			49,031			—			325,924
Depreciation and amortization	960			81,257			5,192			—			87,409
Depreciation																826			65,498			4,211			—			70,535
General and administrative	16,324			29,061			1,107			(414		)	46,078			18,628			37,781			1,972			(315		)	58,066
Intercompany leasing	—			(3,645		)	3,645			—			—			—			(3,645		)	3,645			—			—
Bad debt expense	—			(302		)	—			—			(302		)
Impairment charges	—			4,262			—			—			4,262
Bad debt recovery, net of expense																—			(311		)	—			—			(311		)
Impairment																—			2,607			—			—			2,607
Gain on dispositions of property and equipment, net	—			(366		)	(54		)	—			(420		)	—			(2,890		)	(32		)	—			(2,922		)
Total costs and expenses	17,284			253,033			14,616			(414		)	284,519			19,454			375,933			58,827			(315		)	453,899
Income (loss) from operations	(17,284		)	(49,417		)	(12,637		)	414			(78,924		)	(19,454		)	10,144			3,688			315			(5,307		)
Other (expense) income:
Other income (expense):
Equity in earnings of subsidiaries	(58,421		)	(13,777		)	—			72,198			—			10,081			3,305			—			(13,386		)	—
Interest expense	(19,220		)	(88		)	1			—			(19,307		)	(28,963		)	(14		)	11			—			(28,966		)
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		)
Other income																405			664			292			(315		)	1,046
Total other income (expense), net																(18,477		)	3,955			303			(13,701		)	(27,920		)
Income (loss) before income taxes	(95,212		)	(62,060		)	(12,882		)	72,198			(97,956		)	(37,931		)	14,099			3,991			(13,386		)	(33,227		)
Income tax (expense) benefit ¹	2,902			3,639			(895		)	—			5,646			3,407			(4,018		)	(686		)	—			(1,297		)
Net income (loss)	$	(92,310	)	$	(58,421	)	$	(13,777	)	$	72,198		$	(92,310	)	$	(34,524	)	$	10,081		$	3,305		$	(13,386	)	$	(34,524	)

¹ The income tax expense (benefit) reflected in each column does not include any tax effect of the equity in earnings (losses) of subsidiaries.
¹ The income tax (expense) benefit reflected in each column does not include any tax effect of the equity in earnings (losses) of subsidiaries.																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															Nine months ended September 30, 2019
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated			Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations		Consolidated
Cash flows from operating activities	$	(35,376	)	$	19,768		$	4,346		$	—		$	(11,262	)	$	(38,177	)	$	41,854		$	4,961		$	—	$	8,638

Cash flows from investing activities:
Purchases of property and equipment	(563		)	(48,490		)	(4,023		)	270			(52,806		)	(637		)	(36,644		)	(3,262		)	—		(40,543		)
Proceeds from sale of property and equipment	—			10,528			149			(270		)	10,407			—			4,688			90			—		4,778
Proceeds from insurance recoveries	—			3,119			—			—			3,119			—			641			—			—		641
	(563		)	(34,843		)	(3,874		)	—			(39,280		)	(637		)	(31,315		)	(3,172		)	—		(35,124		)

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		)	(125		)	—			—			—		(125		)
Intercompany contributions/distributions	(14,379		)	14,614			(235		)	—			—			10,784			(10,539		)	(245		)	—		—
	36,821			14,614			(235		)	—			51,200			10,659			(10,539		)	(245		)	—		(125		)

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
Net increase (decrease) in cash, cash equivalents and restricted cash																(28,155		)	—			1,544			—		(26,611		)
Beginning cash, cash equivalents and restricted cash																51,348			—			3,216			—		54,564
Ending cash, cash equivalents and restricted cash																$	23,193		$	—		$	4,760		$	—	$	27,953

	Nine months ended September 30, 2016															Nine months ended September 30, 2018
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated			Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations		Consolidated
Cash flows from operating activities	$	(37,104	)	$	44,422		$	326		$	—		$	7,644		$	(43,466	)	$	60,269		$	4,687		$	—	$	21,490

Cash flows from investing activities:
Purchases of property and equipment	(352		)	(24,997		)	(235		)	—			(25,584		)	(762		)	(43,374		)	(4,642		)	—		(48,778		)
Proceeds from sale of property and equipment	—			2,689			54			—			2,743			—			4,648			17			—		4,665
Proceeds from insurance recoveries																—			965			15			—		980
	(352		)	(22,308		)	(181		)	—			(22,841		)	(762		)	(37,761		)	(4,610		)	—		(43,133		)

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			12			—			—			—		12
Purchase of treasury stock	(124		)	—			—			—			(124		)	(549		)	—			—			—		(549		)
Intercompany contributions/distributions	17,594			(17,524		)	(70		)	—			—			22,784			(22,508		)	(276		)	—		—
	28,334			(17,524		)	(70		)	—			10,740			22,247			(22,508		)	(276		)	—		(537		)

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


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

Statements we make in the following discussion that express a belief, expectation or intention, as well as those that are not historical fact, are forward-looking statements made in good faith that are subject to risks, uncertainties and assumptions. These forward-looking statements are based on our current beliefs, intentions, and expectations and are not guarantees or indicators of future performance. 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 term loan, our senior secured revolving asset-based 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 units and wireline units within the industry, the continued availability of new components for drilling ~~rig,~~rigs, well servicing ~~rig,~~rigs, coiled tubing units and wireline ~~unit components,~~units, the continued availability of qualified personnel, the success or failure of our acquisition strategy, ~~including our ability to finance acquisitions, manage growth and effectively integrate acquisitions,~~the occurrence of cybersecurity incidents, the political, economic, regulatory and other uncertainties encountered by our operations, and changes in, or our failure or inability to comply with, governmental regulations, including those relating to the ~~environment and our ability to close our proposed new $175 million term loan and $75 million asset-based revolving lending facility.~~environment. We have discussed many of these factors in more detail elsewhere in this reportandin our Annual Report on Form 10-K for the year ended December 31, ~~2016~~, 2018, including under the headings “Risk Factors” in Item 1A and “Special Note Regarding Forward-Looking Statements” in the Introductory Note to Part ~~I and “Risk Factors” in Item 1A~~.I. 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.~~well.

Drilling ~~Services Segment—~~Services— 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~~Our current drilling rig fleet is 100% ~~pad-capable. We offer~~pad-capable and offers the latest advancements in pad ~~drilling with our fleet of 16~~drilling. We have 17 AC rigs in the US and ~~eight~~8 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~~We provide 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~~comprehensive service offering which includes the drilling rig, crews, supplies and most of the ancillary equipment needed to operate our drilling ~~rigs. The drilling~~ rigs ~~in our fleet~~which are ~~currently~~ deployed through our division offices in the following regions:



		Rig Count
Domestic drilling:
Marcellus/Utica		6
~~Eagle Ford~~		15
Permian Basin and Eagle Ford		710
Bakken		2
~~Colombia~~International drilling		8
		2425

Production ~~Services Segment—~~Services— Our ~~Production Services Segment provides a range of~~production services business segments provide well, wireline and coiled tubing services to ~~a diverse group of exploration~~producers primarily in Texas 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~~regions, as well as in North Dakota, Louisiana and ~~in the Gulf Coast, both onshore and offshore. The primary production services we offer are the following:~~Mississippi.

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,~~2019, we have a fleet of ~~113~~112 rigs with 550 horsepower and 12 rigs with 600 horsepower with operations in 109 locations ~~mostly~~concentrated in ~~the Gulf Coast states,~~Texas, as well as in ~~Arkansas,~~ North Dakota, Colorado and ~~Colorado.~~Mississippi.

•

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, 2019, we have a fleet of 93 wireline units, including 2 greaseless, EcoQuiet^TM units designed to reduce noise when operating in proximity to urban areas and an additional 6 units that offer greaseless electric wireline used to reach further depths in longer laterals. Our fleet is deployed through 10 operating locations concentrated in Texas and the Rocky Mountain and Mid-Continent regions, as well as in Louisiana and North Dakota.. 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~~Services.. Coiled tubing is another important element of the well servicing industry that allows operators to continue production during service operations on a well under pressure without shutting in the well, thereby reducing the risk of formation damage. Coiled tubing services involve the use of a continuous flexible metal pipe which is spooled on a large reel ~~for~~and inserted into the wellbore to perform a variety of oil and natural gas well applications, such as wellbore clean-outs, nitrogen jet lifts, through-tubing fishing, formation stimulation utilizing acid, chemical treatments and fracturing. Coiled tubing is also used for a number of horizontal well applications, such as milling temporary plugs between frac stages. As of September 30, ~~2017, our coiled tubing business consists~~2019, we have a current fleet of ~~10 onshore and four offshore~~9 coiled tubing units, ~~which are~~consisting of 4 small-diameter and 5 large-diameter units (larger than two inches), deployed through ~~four~~2 operating locations that provide services in Texas, ~~Louisiana~~Wyoming and ~~Wyoming.~~surrounding areas.

Pioneer Energy Services Corp. was incorporated under the laws of the State of Texas in 1979 as the successor to a business that had been operating since 1968. ~~Over the last 15 years,~~Since then, we have significantly expanded and transformed our business through acquisitions and organic growth. Our business is comprised of two business lines — Drilling Services and Production Services. We ~~conduct our operations through two operating segments:~~report our Drilling Services ~~Segment~~business as two reportable segments: (i) Domestic Drilling and (ii) International Drilling. We report our Production Services ~~Segment.~~business as three reportable segments: (i) Well Servicing, (ii) Wireline Services, and (iii) Coiled Tubing Services. Financial information about our operating segments is included in Note 8,10, Segment Information, of the Notes to Unaudited Condensed Consolidated Financial Statements, included in Part I, Item 1, Financial Statements, of this Quarterly Report on Form 10-Q.

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

Market Conditions in Our Industry

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

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

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

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

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

Technological advancements and trends in our industry also affect the demand for certain types of equipment, and can affect the overall demand for the services our industry provides. Enhanced directional and horizontal drilling techniques have allowed exploration and production operators to drill increasingly longer lateral wellbores which enable higher hydrocarbon production per well, and reduce the overall number of wells needed to achieve the desired production. The trend in our industry toward fewer, but longer lateral wellbores has led to an overall reduction in drilling and completion activity and demand for the equipment in our industry that is more heavily weighted toward the more specialized equipment available, such as high-spec drilling rigs, higher horsepower well servicing rigs equipped with taller masts, larger diameter coiled tubing units, and other higher power ancillary equipment, which is needed in order to drill, complete and provide services

to the full length of the wellbore. Our domestic drilling and production services fleets are highly capable and designed for operation in today’s long lateral, pad-oriented environment.

For additional information concerning the potential effects of ~~the~~ volatility in oil and gas prices and ~~the effects of technological advancements and~~other industry 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.~~2018.

Market Conditions — Our industry ~~has~~ experienced a severe down cycle ~~since~~from late 2014 ~~which persisted~~ through 2016, ~~with~~during which WTI oil prices ~~(WTI) dipping~~dipped below $30 per barrel in early 2016. A modest recovery in commodity prices began in the latter half of 2016 with ~~an average~~WTI oil ~~price during the first nine months of 2017~~prices steadily increasing from just ~~below~~under $50 per barrel ~~and~~at the end of June 2016 to approximately $60 per barrel at the end of 2017. In 2018, WTI oil prices continued to increase to a ~~current~~high of $75 per barrel in October, but then decreased to $45 per barrel at the end of 2018. Despite some improvement in 2019, oil ~~price at~~prices have averaged just over $55 per barrel through September ~~30, 2017 of almost $52 per barrel.~~2019.

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~~Currently, 21 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~~25 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
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



	Spot Market Contracts		Term Contract Expiration by Period
	Spot Market Contracts	Total Term Contracts	Within 6 Months	6 Months to 1 Year	1 Year to 18 Months	18 Months to 2 Years	2 to 4 Years
Domestic rigs	3	12	6	3	2	—	1
International rigs	—	6	4	2	—	—	—
	3	18	10	5	2	—	1

~~Despite~~Unlike our domestic term contracts, our international drilling contracts are cancelable by our clients without penalty, although the contracts require 15 to 30 days notice and payment for demobilization services. The spot contracts for our domestic drilling rigs are also terminable by our client with 30 days notice and include a required payment for demobilization services. We are actively marketing our idle drilling rigs, as well as those that have terms expiring in the near term or that we otherwise expect to complete their current contracts in the short term.

As compared to our drilling services businesses which generally perform one type of service under longer-term contracts, our production services businesses perform a range of services that are more short-term in nature, and for which demand can, at times, experience quicker adjustments to regional demand and capacity. As compared to the second quarter of 2019, overall demand for our well servicing business was consistent with some slight pricing improvement, our wireline business experienced slight pricing improvements despite a 9% decline in the total number of jobs performed, and our coiled tubing business experienced both improved utilization and pricing during the quarter.

The level of exploration and production activity within a region can fluctuate due to a variety of factors which may directly or indirectly impact our operations in the region. A recent ~~increases~~influx of coiled tubing equipment has led to excess capacity and increased competition in ~~activity,~~the South Texas and Rocky Mountain regions, while certain seasonal factors surrounding wildlife migration during the second quarter caused an interruption to the operations in affected areas of the Rocky Mountains. In Colorado, Senate Bill 19-181 was enacted in April 2019, which gives the state’s oil and gas conservation commission and the state’s local governments more authority over oil and gas operations, and which could lead to newly imposed regulations that may impede our clients’ ability to operate in the region, and similarly reduce demand for the services that we provide in this region. At the end of September 2019, we were operating ten wireline units and six well servicing rigs in Colorado, which we believe can be redeployed to other markets should future regulations negatively impact demand.

The continuing trend toward longer lateral wellbores and the enhanced efficiency of the equipment in our industry, in combination with current ~~uncertainty in~~ commodity prices ~~could cause~~and more disciplined spending by exploration and production companies, has contributed to some oversupply of equipment in our industry, declining rig counts and reduced completion activity. Although we expect a competitive market environment and some additional clients to ~~again reduce~~decrease their ~~spending which would negatively impact our~~ activity during the remainder of 2019 due to budget constraints, we remain focused on improving margins through realignment of certain businesses and ~~pricing. We expect a highly competitive environment to continue into 2018, but~~reducing costs, and we believe our high-quality equipment, services and excellent safety record ~~make~~position us well ~~positioned~~ to compete.

Liquidity and Capital Resources

Sources of Capital Resources

Our principal sources of liquidity currently consist of:

total cash and cash equivalents ($~~10.9~~28.0 million as of September 30, ~~2017)~~2019);

cash generated from ~~operations;~~operations ($8.6 million during the nine months ended September 30, 2019);

proceeds from sales of ~~certain non-strategic~~ assets; ($4.8 million during the nine months ended September 30, 2019); and

the ~~unused portion~~availability under our asset-based lending facility ($50.6 million as of ~~our senior secured revolving credit~~September 30, 2019).

Our asset-based lending facility (the ~~“Revolving Credit~~“ABL 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 asset-based credit facility, with sub-limits for letters of credit, ~~and swing-line loans,~~ of up to a current aggregate commitment amount of ~~$150~~$75 million, subject to availability under a borrowing base generally comprised of ~~certain eligible cash, certain eligible receivables, certain eligible inventory, and certain eligible equipment of ours and certain~~a percentage of our ~~subsidiaries, all~~accounts receivable and inventory. The ABL Facility is generally set to mature 90 days prior to the maturity of ~~which matures in March 2019.~~the Term Loan, subject to certain circumstances, including the future repayment, extinguishment or refinancing of our Term Loan and/or Senior Notes prior to their respective maturity dates.

We have not drawn upon our ABL Facility to date. As of September 30, 2019, we had $9.4 million in committed letters of credit, which, after borrowing base limitations, resulted in borrowing availability of $50.6 million. Borrowings available under the ~~Revolving Credit~~ABL Facility are available for ~~selective acquisitions, working capital and other~~ general corporate ~~purposes. There~~purposes, and 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~~the covenants under the ~~Revolving Credit~~ABL Facility is maintained. Additional information regarding these covenants is provided in the Debt Compliance Requirements section below.

~~At September 30, 2017,~~In the future, 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 declineto 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,~~22, 2018, we filed a registration statement that permits us to sell equity or debt in one or more offerings up to a total dollar amount of $300 million. As of September 30, ~~2017, $234.6~~2019, the entire $300 million under the shelf registration statement is available for equity or debt offerings, subject to the limitations imposed by our ~~Revolving Credit~~Term Loan, ABL Facility and Senior Notes. Our ability to access the capital markets by issuing debt or equity securities will be dependent on market conditions, our financial condition, and other factors beyond our control.

We currently expect that cash and cash equivalents, cash generated from operations, proceeds from sales of ~~certain non-strategic~~ assets, and available ~~borrowings~~funds under our ~~Revolving Credit~~ABL 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.~~activity. During periods of sustained low activity and pricing, we may also access additional capital through the use of available funds under our ~~Revolving Credit~~ABL Facility.

We believe that we will have sufficient liquidity to fund our business and operations for at least the next 12 months. While the Term Loan is not expected to mature until December 2021, we continue to proactively explore various strategic and other alternatives to address the uncertainties related to our ability to refinance our outstanding debts as their maturities approach.

Working Capital — Our working capital was ~~$60.0~~$97.5 million at September 30, ~~2017,~~2019, compared to ~~$48.0~~$110.3 million at December 31, ~~2016.~~2018. Our current ratio, which we calculate by dividing current assets by current liabilities, was ~~1.8~~2.0 at September 30, ~~2017,~~2019, as compared to ~~1.7~~2.1 at December 31, ~~2016.~~2018. 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			September 30, 2019		December 31, 2018		Change
Cash and cash equivalents	$	10,852	$	10,194	$	658		$	26,955	$	53,566	$	(26,611	)
Restricted cash								998		998		—
Receivables:
Trade, net of allowance for doubtful accounts	71,634		38,764		32,870			81,039		76,924		4,115
Unbilled receivables	14,268		7,417		6,851			20,906		24,822		(3,916		)
Insurance recoveries	13,491		17,003		(3,512		)	23,186		23,656		(470		)
Other receivables	3,411		8,939		(5,528		)	7,421		5,479		1,942
Inventory	11,758		9,660		2,098			22,086		18,898		3,188
Assets held for sale	8,756		15,093		(6,337		)	6,233		3,582		2,651
Prepaid expenses and other current assets	5,331		6,926		(1,595		)	6,991		7,109		(118		)
Current assets	139,501		113,996		25,505			195,815		215,034		(19,219		)
Accounts payable	32,008		19,208		12,800			32,127		34,134		(2,007		)
Deferred revenues	783		1,449		(666		)	1,616		1,722		(106		)
Accrued expenses:
Payroll and related employee costs	19,298		14,813		4,485
Employee compensation and related costs								22,489		24,598		(2,109		)
Insurance claims and settlements								22,991		23,593		(602		)
Insurance premiums and deductibles	7,811		6,446		1,365			6,036		5,482		554
Insurance claims and settlements	13,084		13,667		(583		)
Interest	912		5,395		(4,483		)	1,008		6,148		(5,140		)
Other	5,617		5,024		593			12,035		9,091		2,944
Current liabilities	79,513		66,002		13,511			98,302		104,768		(6,466		)
Working capital	$	59,988	$	47,994	$	11,994		$	97,513	$	110,266	$	(12,753	)

Cash and cash equivalents — ~~During 2017, we used $52.8~~The decrease in cash and cash equivalents during 2019 is primarily due to $40.5 million of cash used for the ~~purchases~~purchase of property and equipment, ~~and used $11.3~~offset in part by $8.6 million inof cash provided by operating activities ~~primarily funded by $51.7 million of net borrowings under our Revolving Credit Facility~~ and ~~$10.4~~$4.8 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~~property and ~~expected increase in activity.~~equipment.

Trade and unbilled receivables — The net increase in our total trade and unbilled receivables during ~~2017~~2019 is primarily due to the ~~64%~~3% increase in our revenues during the quarter ended September 30, ~~2017,~~2019, 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.~~2018. Our domestic trade receivables generally turn over within 9060 days, and our Colombian trade receivables generally turn over within 120 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~~increase in other receivables during ~~2017~~2019 is primarily due to an increase in recoverable income tax receivables attributable to the ~~sale of two drilling rigs~~increase in ~~December 2016,~~activity 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.our international operations.

Inventory — The increase in inventory during ~~2017~~2019 is primarily due to ~~the~~an increase in ~~activity~~inventory for our ~~Colombian operations, as well as purchases of~~international operations’ spare parts and supplies ~~and job materials for our coiled tubing operations.~~supporting rigs working in remote locations.

Assets held for sale— As of September 30, ~~2017,~~2019, our condensed consolidated balance sheet reflects assets held for sale of ~~$8.8~~$6.2 million, which includes the fair value of buildings and yards for one domestic drilling yard and two closed wireline locations, both of which were designated as held for sale in 2019, one domestic SCR drilling rig, two coiled tubing units, and spare support equipment. As of December 31, 2018, our condensed consolidated balance sheet reflects assets held for sale of $3.6 million, which primarily represents the fair value of ~~three~~one domestic SCR drilling ~~rigs~~rig and ~~one domestic mechanical drilling rig, as well as other drilling~~related spare equipment and ~~two~~three 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~~additional information, ~~about rig mobilization service revenues and costs,~~ see Note 1,4, ~~Organization~~Property and ~~Summary of Significant Accounting Policies~~Equipment, of the Notes to Condensed Consolidated Financial Statements, included in Part I, Item 1, Financial Statements, of this Quarterly Report on Form 10-Q.

Prepaid expenses and other current assets — The decrease in prepaid expenses and other current assets during 2019 is primarily due to the amortization of prepaid insurance premiums which are generally paid annually in October, which

was largely offset by an increase in deferred mobilization costs for one domestic drilling rig that moved between geographic regions.

Accounts payable — Our accounts payable generally turn over within 90 days. The decrease in accounts payable during 2019 is primarily due to a $4.3 million decrease in our accruals for capital expenditures, which was partially offset by an increase in accounts payable ~~during 2017 is~~ primarily ~~due~~attributable to the ~~54%~~4% increase in our operating costs for the quarter ended September 30, ~~2017~~2019 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.~~2018.

~~Accrued payroll~~Deferred revenues— The decrease in deferred revenues during 2019 is primarily due to deferred revenue amortization, offset by increases associated with the deployment of rigs under five new domestic and four new international contracts in 2019.

Employee compensation and related costs — The decrease in employee compensation and related costs during 2019 resulted from a decrease in accrued incentive cash compensation associated with the payment of 2018 annual bonuses in the first quarter of $6.6 million, the $3.5 million settlement of our phantom stock unit awards that vested in April 2019, and the termination of both our annual and long-term cash incentive awards in September 2019. The overall decrease was net of $9.8 million of incentive compensation that was granted in September 2019 and paid in October 2019.


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

Other accrued expenses— The increase in other accrued ~~payroll and related employee costs~~expenses 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~~2019 is primarily due to the ~~payment~~recognition of ~~interest~~$2.2 million of current operating lease liabilities upon our adoption of ASU No. 2016-02, Leases, and its related amendments, as of January 1, 2019. For additional information about adoption of this standard, see Note 1, Organization and Summary of Significant Accounting Policies and Note 3, Leases, of the Notes to Unaudited Condensed Consolidated Financial Statements, included in Part I, Item 1, Financial Statements, of this Quarterly Report on Form 10-Q. The increase in other accrued expenses during 2019 is also related to an increase in accrued taxes associated with the increase in revenues for our ~~Senior Notes which is due semi-annually on March 15 and September 15.~~international operations.

Debt and Other Contractual Obligations — The following table includes information about the amount and timing of our contractual obligations at September 30, ~~2017~~2019 (amounts are undiscounted and in thousands):

Payments Due by Period
Contractual Obligations Total Within 1 Year 2 to 3 Years 4 to 5 Years Beyond 5 Years
Debt $ 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



	Payments Due by Period
Contractual Obligations	Total		Within 1 Year		2 to 3 Years		4 to 5 Years		Beyond 5 Years
Debt	$	475,000	$	—	$	475,000	$	—	$	—
Interest on debt	93,713		35,525		58,188		—		—
Purchase commitments	4,238		4,238		—		—		—
Operating leases	9,278		2,499		3,594		2,144		1,041
Incentive compensation	10,820		10,163		657		—		—
	$	593,049	$	52,425	$	537,439	$	2,144	$	1,041

Debt — Debt obligations at September 30, ~~2017~~2019 consist of $300 million of principal amount outstanding under our Senior Notes which mature on March 15, 2022 and ~~$97.7~~$175 million of principal amount outstanding under our ~~Revolving Credit Facility~~Term Loan which is ~~due at maturity on March 31, 2019. However,~~expected to mature December 14, 2021. As of September 30, 2019, we ~~may make principal payments to reduce the~~had no debt outstanding ~~balance~~ under our ~~Revolving Credit Facility prior to maturity when cash and working capital is sufficient.~~ABL Facility.

Interest on debt — Interest payment obligations on our Senior Notes are calculated based on the coupon interest rate of 6.125% due semi-annually in arrears on March 15 and September 15 of each year until maturity on March 15, 2022. Interest payment obligations on our ~~Revolving Credit Facility~~Term Loan were estimated based on (1) the ~~6.7%~~9.8% interest rate that was in effect at September 30, ~~2017,~~2019, and (2) the ~~outstanding~~principal balance of ~~$97.7~~$175 million at September 30, ~~2017 to be paid~~2019, and assuming repayment of the outstanding balance occurs at ~~maturity on March 31, 2019.~~December 14, 2021.

Purchase commitments — Purchase commitments generally relate to capital projects for the repair, upgrade and maintenance of our equipment, the construction or purchase of new equipment, and purchase orders for various job and inventory supplies. At September 30, 2019, our purchase commitments primarily ~~consist~~pertain to $1.8 million of inventory and job supplies for our coiled tubing ~~inventory~~operations as well as various refurbishments and ~~equipment, remaining installments on the purchase of two new wireline units~~upgrades to ~~be delivered in the first half of 2018,~~our drilling and ~~routine equipment maintenance and upgrades.~~production services fleets.

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

Incentive compensation — Incentive compensation is payable to our employees, generally contingent upon their continued employment through the date of each respective award’s payout. A portion of our long-term incentive compensation is performance-based, and therefore, the final amount will be determined based on our actual performance relative to a pre-determined peer group over the performance period. At September 30, 2019, our incentive compensation payable primarily relates to $9.8 million of incentive compensation for awards which were granted in September, in conjunction with the termination of the 2019 annual bonus incentive awards and the cancellation of all prior long-term cash incentive awards, and which was subsequently paid in October 2019.

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 4,6, Debt, and Note ~~10,~~12, Guarantor/Non-Guarantor Condensed Consolidating Financial Statements, of the Notes to Unaudited Condensed Consolidated Financial Statements, included in Part I, Item 1, Financial Statements, of this Quarterly Report on Form 10-Q.

The ~~Revolving Credit Facility~~Term Loan contains a financial covenant requiring the ratio of (i) the net orderly liquidation value of our fixed assets (based on appraisals obtained as required by our lenders), on a consolidated basis, in which the lenders under the Term Loan maintain a first priority security interest, plus proceeds of asset dispositions not required to be used to effect a prepayment of the Term Loan to (ii) the outstanding principal amount of the Term Loan, to be at least equal to 1.50 to 1.00 as of any June 30 or December 31 of any calendar year through maturity. As of June 30, 2019, the asset coverage ratio, as calculated under the Term Loan, was 2.41 to 1.00.

The Term Loan contains customary mandatory prepayments from the proceeds of certain transactions including certain asset dispositions ~~or equity or~~and 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 containhas additional ~~restrictive covenants~~customary restrictions that limit our ability to enter into various transactions.

In addition, the Term Loan contains customary events of default, upon the occurrence and during the continuation of any of which the applicable margin would increase by 2% per year. Our obligations under the ~~Revolving Credit Facility~~Term Loan are guaranteed by our wholly-owned domestic subsidiaries, and are secured by substantially all of our domestic assets, in each case, subject to certain exceptions and permitted liens.

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

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

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

As of September 30, ~~2017,~~2019, we were in compliance with all covenants ~~pertaining to~~required by our Term Loan, ABL Facility and 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 declineto 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.

Notes.

Capital Expenditures — During the nine months ended September 30, ~~2017,~~2019, we spent ~~$52.8~~$40.5 million on purchases of property and equipment and placed into service property and equipment of ~~$54.2~~$36.3 million. Currently, we expect to spend approximately ~~$60~~$46 million to $49 million on capital expenditures during ~~2017, with~~ 2019, which includes approximately ~~half allocated to each of our segments. Our total planned capital expenditures for 2017 include approximately~~ ~~$22~~$8 million for ~~domestic and international~~final payments on the construction of the new-build drilling rig ~~upgrades, the exchange~~and previous commitments on high-pressure pump packages for coiled tubing completion operations, all of ~~20 well servicing rigs~~ which ~~was completed~~were made earlier in the ~~first quarter of 2017, and the purchase of six wireline units~~.year.

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~~ 2019

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

Results of Operations

Statements of Operations Analysis

The following table provides certain information about our operations, including details of each of our business segments’ revenues, operating costs and gross margin for the three and nine months ended September 30, ~~2017~~2019 and ~~2016~~2018 (amounts in ~~thousands, except average number of drilling rigs, utilization rate and revenue day information).~~thousands):

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



	Three months ended September 30,						Nine months ended September 30,
	2019			2018			2019			2018
Revenues:
Domestic drilling	$	38,168		$	36,586		$	115,829		$	108,146
International drilling	21,617			23,131			68,682			62,515
Drilling services	59,785			59,717			184,511			170,661
Well servicing	30,293			24,369			86,053			68,645
Wireline services	43,874			52,654			137,134			171,392
Coiled tubing services	12,446			12,592			38,111			37,894
Production services	86,613			89,615			261,298			277,931
Consolidated revenues	$	146,398		$	149,332		$	445,809		$	448,592

Operating costs:
Domestic drilling	$	21,931		$	21,650		$	69,098		$	64,297
International drilling	15,844			19,013			50,884			49,038
Drilling services	37,775			40,663			119,982			113,335
Well servicing	21,414			17,193			61,348			49,443
Wireline services	38,349			40,840			119,500			130,042
Coiled tubing services	10,521			10,265			31,784			33,104
Production services	70,284			68,298			212,632			212,589
Consolidated operating costs	$	108,059		$	108,961		$	332,614		$	325,924

Gross margin:
Domestic drilling	$	16,237		$	14,936		$	46,731		$	43,849
International drilling	5,773			4,118			17,798			13,477
Drilling services	22,010			19,054			64,529			57,326
Well servicing	8,879			7,176			24,705			19,202
Wireline services	5,525			11,814			17,634			41,350
Coiled tubing services	1,925			2,327			6,327			4,790
Production services	16,329			21,317			48,666			65,342
Consolidated gross margin	$	38,339		$	40,371		$	113,195		$	122,668

Consolidated:
Net loss	$	(26,016	)	$	(5,233	)	$	(54,075	)	$	(34,524	)
Adjusted EBITDA ⁽¹⁾	$	7,053		$	28,576		$	47,643		$	68,881

(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, impairment, and any loss on extinguishment of ~~debt and impairments, if any.~~debt. Adjusted EBITDA is a non-GAAP measure that our management uses to facilitate period-to-period comparisons of our core operating performance and to evaluate our long-term financial performance against that of our peers. We believe that this measure is useful to investors and analysts in allowing for greater transparency of our core operating performance and makes it easier to compare our results with those of other companies within our industry. Adjusted EBITDA should not be considered (a) in isolation of, or as a substitute for, net income (loss), (b) as an indication of cash flows from operating activities or (c) as a measure of liquidity. In addition,

Adjusted EBITDA does not represent funds available for discretionary use. Adjusted EBITDA may not be comparable to other similarly titled measures reported by other companies.

A reconciliation of net loss, as reported, to Adjusted EBITDA, and ~~a reconciliation of net loss, as reported,~~ to consolidated ~~Production Services Segment margin and Drilling Services Segment~~gross margin, are set forth in the following ~~table.~~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



	Three months ended September 30,						Nine months ended September 30,
	2019			2018			2019			2018
	(amounts in thousands)
Net loss	$	(26,016	)	$	(5,233	)	$	(54,075	)	$	(34,524	)
Depreciation	22,924			23,501			68,428			70,535
Impairment	—			239			1,378			2,607
Interest expense	10,013			9,811			30,003			28,966
Income tax expense	132			258			1,909			1,297
Adjusted EBITDA	7,053			28,576			47,643			68,881
General and administrative	30,485			14,043			68,271			58,066
Bad debt expense (recovery), net	196			111			(90		)	(311		)
Loss (gain) on dispositions of property and equipment, net	17			(1,861		)	(2,184		)	(2,922		)
Other expense (income)	588			(498		)	(445		)	(1,046		)
Consolidated gross margin	$	38,339		$	40,371		$	113,195		$	122,668

Consolidated gross margin — ~~Both~~Our consolidated gross margin decreased by $2.0 million, or 5%, and $9.5 million, or 8%, for the three and nine months ended September 30, 2019, respectively, as compared to the corresponding periods in 2018, due to a decline in demand for our ~~Production Services and Drilling Services Segments experienced~~wireline services, despite an increase in gross margin for all our other business segments in 2019. The $2.0 million and $9.5 million overall decreases in consolidated gross margin were net of $4.7 million and $12.7 million combined increases in gross margin for our drilling services and well servicing segments.

DrillingServices— Our drilling services revenues increased slightly for the three months ended September 30, 2019 and by $13.9 million, or 8%, for the nine months ended September 30, 2019, as compared to the corresponding periods in 2018, while operating costs decreased by $2.9 million, or 7%, and increased by $6.6 million, or 6%, respectively. The increases in margin for the three and nine months ended September 30, 2019 are primarily due to the deployment of our newest AC drilling rig in March 2019, the benefit of early termination revenues during 2019 on two domestic drilling contracts and increased revenues associated with the demobilization of rigs in Colombia. The following table provides operating statistics for each of our drilling services segments:



	Three months ended September 30,						Nine months ended September 30,
	2019			2018			2019			2018
Domestic drilling:
Average number of drilling rigs	17			16			17			16
Utilization rate	88		%	99		%	94		%	100		%
Revenue days	1,383			1,459			4,279			4,353

Average revenues per day	$	27,598		$	25,076		$	27,069		$	24,844
Average operating costs per day	15,858			14,839			16,148			14,771
Average margin per day	$	11,740		$	10,237		$	10,921		$	10,073

International drilling:
Average number of drilling rigs	8			8			8			8
Utilization rate	71		%	76		%	79		%	79		%
Revenue days	521			562			1,724			1,733

Average revenues per day	$	41,491		$	41,158		$	39,839		$	36,073
Average operating costs per day	30,411			33,831			29,515			28,297
Average margin per day	$	11,080		$	7,327		$	10,324		$	7,776

Our domestic drilling average revenues and margin per day for the three and nine months ended September 30, 2019 increased as compared to the corresponding periods in 2018, primarily due to $2.2 million and $2.6 million of revenues, respectively, for the early termination of two of our drilling contracts and the deployment of our newest AC drilling rig in March 2019, as well as increasing dayrates during 2019, despite the impact of four rigs that re-priced downward in the second half of 2018 from historically high pre-downturn rates. These increases were partially offset by the impact of reduced utilization in 2019, as compared to 2018.

Our international average revenues and margin per day increased for the three and nine months ended September 30, 2019, as compared to the corresponding periods in 2018, primarily due to $1.4 million of revenues associated with the demobilization of three rigs in Colombia during the third quarter of 2019, as well as increasing dayrates during late 2018 and early 2019. Average margin per day during these periods also benefited from reduced costs associated with mobilization and demobilization activity during 2019 as compared to 2018.

Production Services— Our revenues from production services decreased by $3.0 million, or 3%, and $16.6 million, or 6%, for the three and nine months ended September 30, 2019, respectively, as compared to the corresponding periods in 2018, while operating costs increased $2.0 million, or 3%, for the three months ended September 30, 2019, and operating costs for the nine months ended September 30, 2019 were comparable with the corresponding period in 2018. The decrease in revenue is a result of the decreased demand for wireline completion services, partially offset by increased demand for our well servicing business which experienced a 25% increase in revenue and a 29% increase in gross margin during 2019. The following table provides operating statistics for each of our production services segments:



	Three months ended September 30,						Nine months ended September 30,
	2019			2018			2019			2018
Well servicing:
Average number of rigs	125			125			125			125
Utilization rate	59		%	51		%	58		%	49		%
Rig hours	52,210			44,155			151,169			127,800
Average revenue per hour	$	580		$	552		$	569		$	537

Wireline services:
Average number of units	94			104			98			107
Number of jobs	2,077			2,684			6,697			8,536
Average revenue per job	$	21,124		$	19,618		$	20,477		$	20,079

Coiled tubing services:
Average number of units	9			11			9			13
Revenue days	339			362			997			1,126
Average revenue per day	$	36,714		$	34,785		$	38,226		$	33,654

Our well servicing business experienced increases in demand during the three and nine months ended September 30, 2019, as compared to the corresponding periods in 2018, as the number of completed wells increased during the recovery of our industry, resulting in a larger inventory of producing wells that now require ongoing maintenance. Our well servicing rig hours increased by 18% in each period, while revenues per hour increased by 5% and 6% for the three and nine months ended September 30, 2019, respectively, as compared to the corresponding periods in 2018.

Our wireline services business segment experienced decreases of 23% and 22% in the number of jobs completed during the three and nine months ended September 30, 2019, as compared to the corresponding periods in 2018, respectively, while average revenues per job increased 8% and 2%, respectively. These decreases in activity were primarily a result of decreased demand for completion-related activity during the three and nine months ended September 30, ~~2017,~~2019, as compared to the corresponding periods in ~~2016, as our industry continues~~2018, when we experienced higher demand for services to ~~recover from an industry downturn.~~ complete both newly drilled wells and the remaining inventory of wells which had been drilled in prior periods but were not yet completed.

Our ~~consolidated margin increased 84%~~coiled tubing services business experienced decreases of 6% and ~~41%~~11% in revenue days for the three and nine months ended September 30, ~~2017,~~2019, respectively, as compared to the corresponding periods in ~~2016.~~

~~Our Production Services Segment’s revenues~~2018, while average revenue per day increased ~~by $33.8 million, or 83%,~~6% and ~~$82.8 million, or 71%, for~~14%. A recent influx of coiled tubing equipment has led to excess capacity and increased competition in the ~~three~~South Texas and ~~nine months ended September 30, 2017, respectively, as compared~~Rocky Mountain regions, while certain seasonal factors surrounding wildlife migration during the second quarter caused an interruption to the ~~corresponding periods~~operations 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~~affected areas 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

Rocky Mountains. 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 inaverage 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 larger proportion of the work performed with larger diameter coiled tubing units, including the addition of two new large-diameter coiled tubing units which were placed in service in July and December 2018. Large-diameter coiled tubing units typically earn 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,revenue rates 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

smaller diameter coiled tubing units.

Depreciation ~~and amortization~~ expense — Our depreciation ~~and amortization~~ expense decreased by ~~$4.0~~$0.6 million and ~~$13.1~~$2.1 million for the three and nine months ended September 30, ~~2017,~~2019, respectively, primarily in our wireline and coiled tubing segments, which currently operate with an overall smaller fleet 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 2016.2018.

Impairment ~~charges~~ — During the nine months ended September 30, ~~2017~~2019 and ~~2016,~~2018, we recognized impairment charges of ~~$0.8~~$1.4 million and ~~$4.3~~$2.6 million, respectively, ~~primarily~~ to reduce the carrying values of certain assets which were classified as held for sale, to their estimated fair ~~value~~values based on expected ~~sales~~sale prices. For more detail, see Note 4, Property and Equipment, of the

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

Interest expense — Our interest expense ~~decreased~~increased by ~~$0.2~~$1.0 million during the nine months ended September 30, ~~2017,~~2019, as compared to the corresponding period in ~~2016,~~2018, primarily due to ~~reduced debt outstanding under~~an increase in the ~~Revolving Credit Facility, for which the decrease was mostly offset by the increased~~LIBOR interest rate ~~under~~applicable to 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.Term Loan. For more detail see, Note 3,6, ~~Valuation Allowances on Deferred Tax Assets~~Debt, of the Notes to Condensed Consolidated Financial Statements, included in Part I, Item 1, Financial Statements, of this Quarterly Report on Form 10-Q.

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

General and administrative expense — Our general and administrative expense increased by ~~approximately $3.2~~$16.4 million ~~or 22%,~~ and ~~$5.3~~$10.2 million ~~or 11%,~~ for the three and nine months ended September 30, ~~2017,~~2019, respectively, as compared to the corresponding periods in ~~2016, due primarily to increased compensation costs. The increase in compensation cost was~~2018, primarily due to a ~~$4.1 million~~net increase in ~~salary~~incentive compensation of $9.7 million and ~~bonus~~$9.1 million, respectively, associated with retention and incentive compensation awards granted in the third quarter of 2019, concurrent with the termination of the previous annual and long-term cash incentive awards. The change in the fair value of our phantom stock unit awards also impacted our general and administrative expense, which resulted in an increase of $3.6 million during the three months ended September 30, 2019 and a decrease of $2.9 million during the nine months ended September 30, ~~2017, partially~~2019, as ~~a result~~compared to the corresponding periods in 2018, respectively. Various other expenses contributed to the overall increase in expenses during these periods, including an increase in professional fees of ~~increased headcount~~$1.5 million and $2.5 million for the three and nine months ended September 30, 2019, respectively, as compared to ~~accommodate higher activity levels,~~the corresponding period in 2018, 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~~an increase in ~~compensation cost were partially offset by a $0.6 million decrease in~~rent expense associated with ~~our phantom stock unit awards~~the termination of several leases for locations closed during the third quarter.

Loss (gain) on dispositions of property and equipment, net— During the nine months ended September 30, ~~2017.~~

~~Gain~~2019, we recognized a net gain of $2.2 million on ~~dispositions~~the disposition of drill pipe and various other property and equipment, ~~net —~~ ~~Our~~including some assets which were previously held for sale, as well as insurance proceeds received for damaged equipment. During the nine months ended September 30, 2018, we recognized a net gain of ~~$2.3~~$2.9 million on the disposition of various property and equipment, ~~during~~including the ~~nine months ended September 30, 2017 included sales~~sale of ~~certain~~five coiled tubing ~~equipment~~units, twelve wireline units, 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 pipeone drilling rig, which was ~~mostly offset by a loss on the disposition of damaged drilling equipment.~~previously held for sale.

Other ~~(expense) income~~expense (income) — ~~Our~~The decrease in our other ~~income~~expense (income) is primarily related to net foreign currency ~~gains~~losses 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~~2019, as ~~our industry recovers from~~compared to net foreign currency gains during the ~~downturn.~~corresponding periods in 2018.

Critical Accounting Policies and Estimates

The preparation of financial statements in conformity with USU.S. GAAP requires us to make estimates and assumptions that affect the amounts reported in our financial statements and accompanying notes. Actual results could differ from those estimates. AsExcept for those related to the adoption of ASC Topic 842 discussed below, as of September 30, ~~2017,~~2019, there were no significant changes to our critical accounting policies since the date of our annual report on Form 10-K for the year ended December 31, ~~2016.~~2018.

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

~~With most drilling contracts,~~our unaudited condensed consolidated statements of operations. As a lessee, this standard primarily impacts our accounting for long-term real estate and office equipment leases, for which we ~~receive payments contractually designated for the mobilization of rigs~~recognized an operating lease asset and ~~other equipment. Payments received, and costs incurred for the mobilization services are deferred and recognized on~~ a ~~straight line basis over~~corresponding operating

lease liability on our unaudited condensed consolidated balance sheet of $9.8 million at the adoption date of January 1, 2019. For leases that commenced prior to adoption of ASC Topic 842, we elected to apply the package of practical expedients which allows us to carry forward the historical lease classification. The adoption of ASC Topic 842 also resulted in a cumulative effect adjustment of $0.3 million after applicable income taxes, related ~~contract term. Costs incurred~~ to ~~relocate rigs~~the write off of previously unamortized deferred lease liabilities at the date of adoption. For more information about the accounting under ASC Topic 842, and ~~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~~disclosures under the ~~out-of-pocket expenses for which they relate are recorded as operating costs.~~new standard, see Note 3,

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 Leases, 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~~Notes to ~~master services agreements based~~Unaudited Condensed Consolidated Financial Statements, included in Part I, Item 1 Financial Statements, of this Quarterly Report 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.~~Form 10-Q.

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

WeIn accordance with ASC Topic 606, Revenue from Contracts with Customers, 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 havecertain variable revenues associated 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 depreciationdemobilization 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.~~rigs under daywork drilling contracts. We ~~record the same depreciation expense whether a drilling rig, well servicing rig, wireline unit or coiled tubing unit is idle or working. Our~~also make estimates of the ~~useful lives~~applicable amortization periods for deferred mobilization costs, and for mobilization revenues related to cancelable term contracts which represent a material right to our clients. These estimates and assumptions are described in more detail in Note 2, Revenue from Contracts with Customers. In order to make these estimates, management considers all the facts and circumstances pertaining to each particular contract, our past experience and knowledge of ~~our drilling, production, transportation and other equipment are based~~current market conditions. For more information, see Note 2, Revenue from Contracts with Customers, of the Notes to Condensed Consolidated Financial Statements, included in Part I, Item 1, Financial Statements, of this Quarterly Report on ~~our almost~~ Form 10-Q.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~~In accordance with ASC Topic 360, Property, Plant and Equipment, we monitor all indicators of potential impairments. Due to ~~continued performance at levels~~ lower than anticipated operating results and a decline in our projected cash flows for the coiled tubing reporting unit, we performed an impairment ~~evaluation~~analysis of ~~our coiled tubing business as~~this reporting unit at September 30, 2019. As a result of ~~June 30, 2017 and~~this analysis, we concluded that nothis reporting unit was not at risk of impairment because the estimated fair value of the reporting unit’s assets was ~~present.~~

in excess of the carrying value. The assumptions ~~used~~we use in the evaluation for impairment ~~evaluation~~ are inherently uncertain and require management judgment. Although we believe the assumptions and estimates used in our impairment ~~analyses~~analysis are reasonable, ~~and appropriate,~~ different assumptions and estimates could materially impact the ~~analyses~~analysis and resulting conclusions. The most significant inputs used in our impairment analysis include the projected utilization and pricing of our services, as well as the estimated proceeds upon any future sale or disposal of the assets, all of which are classified as Level 3 inputs as defined by ASC Topic 820, Fair Value Measurements and Disclosures. If commodity prices decrease or remain at current levels for an extended period of time, or if the demand for any of our ~~assets become or remain idle for an extended amount of time, then~~services decreases below what we are currently projecting, our estimated cash flows may ~~further~~ decrease and ~~therefore~~our estimates of the ~~probability~~fair value of ~~a near term sale~~certain assets may ~~increase.~~decrease as well. If any of the foregoing were to occur, we ~~may~~could incur ~~additional~~ impairment ~~charges.~~charges on the related assets. For more information, see Note 4, Property and Equipment, of the Notes to Condensed Consolidated Financial Statements, included in Part I, Item 1, Financial Statements, of this Quarterly Report on Form 10-Q.

As of September 30, ~~2017,~~2019, we had ~~$157.1~~$101.3 million and $6.9 million of deferred tax assets related to domestic and foreign net operating losses, respectively, that are available to reduce future taxable income. In assessing the realizability of our deferred tax assets, we consider whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. As a result, as of September 30, 2019, we ~~have~~had a valuation allowance of $69.7 million that ~~fully~~ offsets a portion of our domestic and foreign net deferred tax assets. Since 2017, market conditions and operating results for our Colombian operations have improved, and if they continue to improve, then we may determine that there is sufficient evidence that future taxable income will be generated to utilize our foreign deferred tax assets ~~and mostly offsets~~which would result in the reversal of a portion of the valuation allowance relating to our ~~domestic~~foreign 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%.~~assets. For more information, see Note 3,5, Valuation Allowances on Deferred Tax Assets, of the Notes to Condensed Consolidated Financial Statements, included in Part I, Item 1, Financial Statements, of this Quarterly Report on Form 10-Q.

~~Our accrued~~We use a combination of self-insurance and third-party insurance ~~premiums and deductibles as~~for various types 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.coverage. We have stop-loss coverage of $200,000 per covered individual per year under our health insurance and a deductible of $500,000 per occurrence under our workers’ compensation insurance. We have a deductible of $250,000 per occurrence under both our general liability insurance and auto liability insurance, as well as an additional annual aggregate deductible of

$250,000 under our general liability insurance. At September 30, 2019, our accrued insurance premiums and deductibles include approximately $1.1 million of accruals for costs incurred under the self-insurance portion of our health insurance and approximately $3.6 million of accruals for costs associated with our workers’ compensation insurance. We accrue for these costs as claims are incurred using an actuarial calculation that is based on industry and our company’s historical claim development data, and we accrue the ~~costs~~cost of administrative services associated with claims processing.

Our compensation expense includes estimates for certain of our long-term incentive compensation plans which have performance-based award components dependent upon our performance over a set performance period, as compared to the performance of a pre-defined peer group. The accruals for these awards include estimates which affect our compensation expense, employee related accruals and equity. The accruals are adjusted based on actual achievement levels at the end of the pre-determined performance periods. Additionally, our phantom stock unit awards are classified as liability awards under ASC Topic 718, Compensation—Stock Compensation, because we expect to settle the awards in cash when they vest, and are remeasured at fair value at the end of each reporting period until they vest. The change in fair value is recognized as a current period compensation expense in our ~~statement~~condensed consolidated statements of operations. Therefore, changes in the inputs used to measure fair value can result in volatility in our compensation expense. This volatility increases as the phantom stock awards approach the vesting date. For more information, see Note 7,9, Stock-Based Compensation Plans, of the Notes to Condensed Consolidated Financial Statements, included in Part I, Item 1, Financial Statements, of this Quarterly Report on Form 10-Q.

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.

Recent Developments

On October 19, 2019, the Colombian Constitutional Court declared Colombia’s 2018 Tax Reform unconstitutional due to procedural flaws in the approval process, however, the decision is not effective until January 1, 2020. The Colombian government is currently working to reenact the tax reform through the correct procedure, to take effect on January 1, 2020. If a new tax reform package is not agreed to by that time, the tax regime prior to 2018 will be in effect as of January 1, 2020, in which case we would account for any potential changes in the fourth quarter of 2019.

Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements.


ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

Interest Rate Risk — We are ~~subject~~exposed to interest rate market risk on our variable rate debt. We do not use financial instruments for trading or other speculative purposes. As of September 30, ~~2017~~2019, ~~we had $97.7 million outstanding~~the principal amount under our ~~Revolving Credit Facility,~~Term Loan was $175 million, which is our only variable rate ~~debt.~~debt with an outstanding balance. The impact of a hypothetical 1% increase or decrease in interest rates on this amount of debt would have resulted in a corresponding increase or decrease, respectively, in interest expense of approximately $~~0.7~~1.3 million during the nine months ended September 30, ~~2017~~2019. This potential increase or decrease is based on the simplified assumption that the level of variable rate debt remains constant with an immediate across-the-board interest rate increase or decrease as of January 1, ~~2017~~2019.

Foreign Currency Risk — While the U.S. dollar is the functional currency for reporting purposes for our Colombian operations, we enter into transactions denominated in Colombian ~~pesos.~~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~~losses of ~~$0.2~~$0.5 million for the nine months ended September 30, ~~2017~~2019.


ITEM 4.	CONTROLS AND PROCEDURES

In accordance with Exchange Act Rules 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of September 30, ~~2017~~2019, to ensure that information required to be disclosed in our reports filed or submitted under the Exchange Act is (1) recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms and (2) accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

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

There has been no change in our internal control over financial reporting that occurred during the three months ended September 30, ~~2017~~2019 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II - OTHER INFORMATION


ITEM 1.	LEGAL PROCEEDINGS

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


ITEM 1A.	RISK FACTORS

~~Not applicable.~~There has been no material change in our risk factors as previously disclosed in Item 1A – “Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2018 (the “2018 Form 10-K”). In addition to the other factors set forth in this Form 10-Q, you should carefully consider the factors discussed in Item 1A – “Risk Factors” in our 2018 Form 10-K, which could materially affect our business, financial condition or future results.


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.~~2019. We did not repurchase any common shares during the quarter ended September 30, ~~2017.~~2019.


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.Not applicable.

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~~exhibits are ~~exhibits to~~filed as part of this ~~Form 10-Q~~:report:



Exhibit Number		Description

3.1*	-	Restated Articles of Incorporation of Pioneer Energy Services Corp. (Form 8-K dated May ~~17,~~22, 2017 (File No. 1-8182, Exhibit 3.1)).

3.2*	-	Amended and Restated Bylaws of Pioneer Energy Services Corp. (Form 8-K dated July ~~30, 2012~~2, 2019 (File No. 1-8182, Exhibit ~~3.2)~~3.1)).

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)).

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

10.1+*	-	Form of Retention Bonus Agreement (Form 8-K dated September 13, 2019 (File No. 1-8182, Exhibit 10.1)).

10.2+*	-	Pioneer Energy Services Corp. 2019 Employee Incentive Plan (Form 8-K dated September 13, 2019 (File No. 1-8182, Exhibit 10.2)).

10.3+*	-	Form of Bonus Award Letter (2019 Employee Incentive Plan) (Form 8-K dated September 13, 2019, (File No. 1-8182, Exhibit 10.3)).

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**101.INS	-	~~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.Instance Document

101.SCH	-	XBRL Taxonomy Schema Document

101.CAL	-	XBRL Calculation Linkbase Document

101.LAB	-	XBRL Label Linkbase Document

101.PRE	-	XBRL Presentation Linkbase Document

101.DEF	-	XBRL Definition Linkbase Document

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

SIGNATURES

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

PIONEER ENERGY SERVICES CORP.

/s/ Lorne E. Phillips

Lorne E. Phillips

Executive Vice President and Chief Financial Officer

(Principal Financial Officer and Duly Authorized Officer)

Dated: October 31, 2019



		Page
	PART I
Item 1.	Financial Statements and Supplementary Data	3
	Condensed Consolidated Balance Sheets	3
	Condensed Consolidated Statements of Operations	4
	Condensed Consolidated Statements of Shareholders’ Equity	5
	Condensed Consolidated Statements of Cash Flow	7
	Notes to Unaudited Condensed Consolidated Financial Statements	8
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	28
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	44
Item 4.	Controls and Procedures	45

	PART II
Item 1.	Legal Proceedings	46
Item 1A.	Risk Factors	46
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	46
Item 3.	Defaults Upon Senior Securities	46
Item 4.	Mine Safety Disclosures	46
Item 5.	Other Information	46
Item 6.	Exhibits	47



	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



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