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~~June 30, ~~2017~~2018



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

Commission File Number: 1-8182

PIONEER ENERGY SERVICES CORP.

(Exact name of registrant as specified in its charter)

_____________________________________________



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

1250 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

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

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

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



Large accelerated filer	o	Accelerated filer	x

Non-accelerated filer	o	Smaller reporting company	o
(Do not check if a small reporting company.)
(Do not check if a small reporting company.)		Emerging Growth Company	o

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

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

As of ~~October 16, 2017,~~July 13, 2018, there were ~~77,719,021~~78,214,550 shares of common stock, par value $0.10 per share, of the registrant outstanding.

PART I. FINANCIAL INFORMATION


ITEM 1.	FINANCIAL STATEMENTS

PIONEER ENERGY SERVICES CORP. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS


	September 30, 2017			December 31, 2016			June 30, 2018			December 31, 2017
	(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		$	61,517		$	73,640
Restricted cash							2,000			2,008
Receivables:
Trade, net of allowance for doubtful accounts	71,634			38,764			84,591			79,592
Unbilled receivables	14,268			7,417			22,951			16,029
Insurance recoveries	13,491			17,003			15,014			13,874
Other receivables	3,411			8,939			4,270			3,510
Inventory	11,758			9,660			17,719			14,057
Assets held for sale	8,756			15,093			6,433			6,620
Prepaid expenses and other current assets	5,331			6,926			6,710			6,229
Total current assets	139,501			113,996			221,205			215,559
Property and equipment, at cost	1,100,513			1,058,261			1,100,291			1,093,635
Less accumulated depreciation	534,012			474,181			567,014			544,012
Net property and equipment	566,501			584,080			533,277			549,623
Other long-term assets	1,440			2,026
Other noncurrent assets							2,562			1,687
Total assets	$	707,442		$	700,102		$	757,044		$	766,869

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	32,008		$	19,208		$	38,014		$	29,538
Deferred revenues	783			1,449			1,921			905
Accrued expenses:
Payroll and related employee costs	19,298			14,813			29,315			21,023
Insurance claims and settlements							14,702			13,289
Insurance premiums and deductibles	7,811			6,446			6,238			6,742
Insurance claims and settlements	13,084			13,667
Interest	912			5,395			6,361			6,624
Other	5,617			5,024			7,732			6,793
Total current liabilities	79,513			66,002			104,283			84,914
Long-term debt, less debt issuance costs	392,601			339,473
Long-term debt, less unamortized discount and debt issuance costs							463,072			461,665
Deferred income taxes	8,615			8,180			3,429			3,151
Other long-term liabilities	5,185			5,049
Other noncurrent liabilities							3,569			7,043
Total liabilities	485,914			418,704			574,353			556,773
Commitments and contingencies (Note 9)
Commitments and contingencies (Note 10)
Shareholders’ equity:
Preferred stock, 10,000,000 shares authorized; none issued and outstanding	—			—			—			—
Common stock $.10 par value; 200,000,000 shares authorized 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; 78,214,550 and 77,719,021 shares outstanding at June 30, 2018 and December 31, 2017, respectively							7,900			7,835
Additional paid-in capital	545,032			541,823			548,461			546,158
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; 789,532 and 630,688 shares at June 30, 2018 and December 31, 2017, respectively							(4,965		)	(4,416		)
Accumulated deficit	(326,923		)	(264,308		)	(368,705		)	(339,481		)
Total shareholders’ equity	221,528			281,398			182,691			210,096
Total liabilities and shareholders’ equity	$	707,442		$	700,102		$	757,044		$	766,869

See accompanying notes to condensed consolidated financial statements.

PIONEER ENERGY SERVICES CORP. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(unaudited)

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

Revenues	$	154,782		$	107,130		$	299,260		$	202,887

Costs and expenses:
Operating costs	114,197			79,059			216,963			151,787
Depreciation and amortization	23,287			24,740			47,034			49,732
General and administrative	24,829			16,112			44,023			33,856
Bad debt recovery, net of expense	(370		)	(226		)	(422		)	(589		)
Impairment	2,368			795			2,368			795
Gain on dispositions of property and equipment, net	(726		)	(621		)	(1,061		)	(1,092		)
Total costs and expenses	163,585			119,859			308,905			234,489
Loss from operations	(8,803		)	(12,729		)	(9,645		)	(31,602		)

Other income (expense):
Interest expense, net of interest capitalized	(9,642		)	(6,418		)	(19,155		)	(12,477		)
Other income (expense), net	44			73			548			(71		)
Total other expense, net	(9,598		)	(6,345		)	(18,607		)	(12,548		)

Loss before income taxes	(18,401		)	(19,074		)	(28,252		)	(44,150		)
Income tax (expense) benefit	249			(1,135		)	(1,039		)	(1,183		)
Net loss	$	(18,152	)	$	(20,209	)	$	(29,291	)	$	(45,333	)

Loss per common share - Basic	$	(0.23	)	$	(0.26	)	$	(0.38	)	$	(0.59	)

Loss per common share - Diluted	$	(0.23	)	$	(0.26	)	$	(0.38	)	$	(0.59	)

Weighted average number of shares outstanding—Basic	77,944			77,377			77,776			77,225

Weighted average number of shares outstanding—Diluted	77,944			77,377			77,776			77,225

See accompanying notes to condensed consolidated financial statements.

PIONEER ENERGY SERVICES CORP. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited)


	Nine months ended September 30,						Six months ended June 30,
	2017			2016			2018			2017
	(in thousands)						(in thousands)
Cash flows from operating activities:
Net loss	$	(62,560	)	$	(92,310	)	$	(29,291	)	$	(45,333	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depreciation and amortization	74,355			87,409			47,034			49,732
Allowance for doubtful accounts, net of recoveries	(98		)	(302		)	(422		)	(589		)
Write-off of obsolete inventory	—			21
Gain on dispositions of property and equipment, net	(2,251		)	(420		)	(1,061		)	(1,092		)
Stock-based compensation expense	3,225			2,998			2,356			2,335
Amortization of debt issuance costs	1,395			1,311
Loss on extinguishment of debt	—			299
Impairment charges	795			4,262
Amortization of debt issuance costs and discount							1,422			930
Impairment							2,368			795
Deferred income taxes	434			(6,372		)	273			768
Change in other long-term assets	335			426
Change in other long-term liabilities	136			(833		)
Change in other noncurrent assets							(199		)	299
Change in other noncurrent liabilities							(3,480		)	(1,563		)
Changes in current assets and liabilities:
Receivables	(38,848		)	20,910			(12,368		)	(27,687		)
Inventory	(2,098		)	855			(3,662		)	(2,151		)
Prepaid expenses and other current assets	1,594			2,726			(785		)	(403		)
Accounts payable	11,360			(2,425		)	5,858			7,441
Deferred revenues	(470		)	(4,353		)	619			(244		)
Accrued expenses	1,434			(6,558		)	8,463			465
Net cash provided by (used in) operating activities	(11,262		)	7,644			17,125			(16,297		)

Cash flows from investing activities:
Purchases of property and equipment	(52,806		)	(25,584		)	(31,485		)	(40,032		)
Proceeds from sale of property and equipment	10,407			2,743			2,225			7,748
Proceeds from insurance recoveries	3,119			—			541			3,119
Net cash used in investing activities	(39,280		)	(22,841		)	(28,719		)	(29,165		)

Cash flows from financing activities:
Debt repayments	(13,267		)	(500		)	—			(12,305		)
Proceeds from issuance of debt	65,000			12,000			—			55,000
Debt issuance costs	—			(819		)
Proceeds from exercise of options	—			183			12			—
Purchase of treasury stock	(533		)	(124		)	(549		)	(533		)
Net cash provided by financing activities	51,200			10,740
Net cash provided by (used in) financing activities							(537		)	42,162

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							(12,131		)	(3,300		)
Beginning cash, cash equivalents and restricted cash							75,648			10,194
Ending cash, cash equivalents and restricted cash							$	63,517		$	6,894

Supplementary disclosure:
Interest paid	$	22,928		$	22,849		$	18,073		$	11,971
Income tax paid	$	847		$	653		$	1,789		$	630
Noncash investing and financing activity:
Change in capital expenditure accruals	$	1,396		$	(1,592	)	$	2,440		$	1,952

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

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

Our ~~Production Services Segment provides~~production services business segments provide a range of well, wireline and coiled tubing services to a diverse group of exploration and production companies, with our operations concentrated in the major ~~United States~~domestic onshore oil and gas producing regions in the Gulf Coast, Mid-Continent and Rocky Mountain ~~states~~states. The following table summarizes our current fleet count and ~~in the Gulf Coast, both onshore and offshore. As~~composition for each of ~~September 30, 2017,~~ our production services ~~fleets are as follows:~~business segments, including one coiled tubing unit which was delivered in early July:

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	113	12	125

	Onshore	Offshore	Total
Wireline services units	104	—	104
Coiled tubing services units	9	2	11

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.~~2017.

Use of Estimates — In preparing the accompanying unaudited condensed consolidated financial statements, we make various estimates and assumptions that affect the amounts of assets and liabilities we report as of the dates of the balance sheets and income and expenses we report for the periods shown in the income statements and statements of cash flows. Our actual results could differ significantly from those estimates. Material estimates that are particularly susceptible to significant changes in the near term relate to our ~~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 and our estimate of compensation related ~~accruals and our estimate of sales tax audit liability.~~accruals.

Subsequent Events — In preparing the accompanying unaudited condensed consolidated financial statements, we have reviewed events that have occurred after ~~September~~June 30, ~~2017,~~2018, through the filing of this Form 10-Q, for inclusion as necessary.

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

We have five operating segments, comprised of two drilling services business segments (domestic and international drilling) and three production services business segments (well servicing, wireline services and coiled tubing services). We revised our segments as of December 31, 2017 to reflect changes in the basis used by management in making decisions regarding our business for resource allocation and performance assessment. These changes reflect our current operating focus as is required by ASC Topic 280, Segment Reporting. See Note 9, Segment Informationfor this revised presentation.

Change in Accounting Principle and Recently Issued Accounting Standards

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

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

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

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

Leases. In February 2016, the FASB issued ASU No. 2016-02, Leases, which among other things, requires lessees to recognize substantially all leases on the balance sheet, with expense recognition that is similar to the current lease standard, and aligns the principles of lessor accounting with the principles of the FASB’s new revenue guidance (referenced above). 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 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. The future lease obligations disclosed in Note 4, Leases, included in Part II, Item 8, of our Annual Report on Form 10-K for the year ended December 31, 2017, provides some insight to the estimated impact of adoption for us as a lessee.

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 these contracts. However, recent FASB tentative decisions indicate that additional practical expedients may be adopted by the FASB which, if adopted, we expect would allow us to continue to recognize and present our revenues from drilling contracts (both lease and service components) as one revenue stream in our consolidated statements of operations. We have not yet determined the impact this standard may have on our production services businesses. We continue to evaluate the impact of this guidance and have not yet determined its impact on our financial position and results of operations.

Additional Detail of Account Balances and Related-Party Transactions

Cash and Cash Equivalents — As of June 30, 2018, we had $50.1 million of cash equivalents, consisting of investments in highly-liquid money-market mutual funds. We had no cash equivalents at December 31, 2017.

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 deferred mobilization costs for short-term drilling contracts.

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

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

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

Related-Party Transactions — During the six months ended June 30, 2018 and 2017, the Company paid approximately $120,000 and $70,000, respectively, for trucking and equipment rental services, which represented arms-length transactions, to Gulf Coast Lease Service. Joe Freeman, our Senior Vice President of Well Servicing, serves as the President of Gulf Coast Lease Service, which is owned and operated by Mr. Freeman’s two sons. Mr. Freeman does not receive compensation from Gulf Coast Lease Service, and he serves primarily in an advisory role to his sons.

2. Revenue from Contracts with Customers

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

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

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

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

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

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

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

Contract Asset and Liability Balances and Contract Cost Assets

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

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

Our current and noncurrent deferred revenues and costs as of June 30, 2018 and January 1, 2018 were as follows (amounts in thousands):



	June 30, 2018		January 1, 2018
Current deferred revenues	$	1,921	$	1,287
Current deferred costs	633		1,072

Noncurrent deferred revenues	$	964	$	564
Noncurrent deferred costs	1,425		1,177

The changes in deferred revenue and cost balances during the three and six months ended June 30, 2018 are primarily related to the increase in deferred mobilization revenue and cost balances for the deployment of one international rig under a new term contract in the first quarter of 2018, an increase in deferred revenues associated with a prepayment made by one of our international clients, and decreases related to the amortization of deferred revenues and costs during the period. Amortization of deferred revenues and costs during the three and six months ended June 30, 2018 and 2017 were as follows (amounts in thousands):



	Three months ended June 30,				Six months ended June 30,
	2018		2017		2018		2017
Amortization of deferred revenues	$	542	$	521	$	1,041	$	1,297
Amortization of deferred costs	486		1,219		949		2,686

As of June 30, 2018, all 16 of our domestic drilling rigs are operating under daywork contracts, 14 of which are term contracts, and seven of our eight international drilling rigs are operating under term daywork contracts. The term contracts for our international drilling rigs are cancelable by our clients without penalty, although the contracts require 30 days notice and payment for demobilization services. The spot contracts for our domestic drilling rigs are also terminable by our client with 30 days notice, but typically do not include a required payment for demobilization services. Revenues associated with the initial mobilization and/or demobilization of drilling rigs under cancelable contracts are deferred and recognized ratably over the anticipated duration of the original contract, which is the period during which we expect our client to benefit from the mobilization of the rig, and represents a separate performance obligation because the payment for mobilization and/or demobilization creates a material right to our client during the cancelable period, for which the transaction price is allocated to the optional goods and services expected to be provided.

Remaining Performance Obligations

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

Disaggregation of Revenue

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

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

Our revenue recognition pattern under ASC Topic 606 is similar to revenue recognition under the previous accounting guidance, except for: (i) the timing of recognition of demobilization revenues which are estimated and recognized ratably over the term of the related contract under ASC Topic 606, and constrained when appropriate, but were previously not recognized until the activity was performed under previous guidance; (ii) the timing of recognition of mobilization revenues and costs which are recognized over the applicable amortization period beginning when the initial mobilization of the rig is completed, but which, under previous guidance, we recognized over the related contract term beginning when the initial mobilization activity commenced, (iii) the timing of recognition of mobilization costs which are deferred and recognized ratably over the expected period of benefit, but which, under previous guidance, we recognized ratably over the term of the initial contract; and (iv) presentation of mobilization costs which are presented as either current or noncurrent according to the duration of the original contract to which it relates under ASC Topic 606, but which we bifurcated and presented both current and noncurrent portions in separate line items under previous guidance.

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

3. Property and Equipment

Capital Expenditures—Our capital expenditures were ~~$54.2~~$33.9 million and ~~$24.0~~$42.0 million during the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2018 and ~~2016,~~2017, respectively, which includes ~~$0.4~~$0.1 million and ~~$0.2~~$0.3 million, respectively, of capitalized interest costs incurred. Capital expenditures during the six months ended June 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, vehicle fleet upgrades in all business segments, and capital projects to upgrade and refurbish certain of our international and domestic drilling rigs. Capital expenditures during the six months ended June 30, 2017 primarily related to the acquisition of 20 well servicing rigs, ~~and~~ expansion of our wireline fleet, upgrades to ~~certain domestic~~ drilling rigs ~~routine capital expenditures necessary to deploy rigs that were previously idle in Colombia,~~ and other new drilling equipment. ~~Capital expenditures during 2016 consisted primarily of routine capital expenditures to maintain our drilling and production services fleets.~~

At ~~September~~June 30, ~~2017,~~2018, capital expenditures incurred for property and equipment not yet placed in service was ~~$6.5~~$14.4 million, primarily related to ~~routine capital expenditures on domestic drilling equipment,~~ installments of $5.6 million on the purchase of two ~~wireline~~coiled tubing units, one of which was put into service in early July, as well as refurbishments and ~~scheduled refurbishments on~~upgrades of various drilling and production services equipment. At December 31, ~~2016,~~2017, property and equipment not yet placed in service was ~~$9.0~~$6.8 million, primarily related to ~~new~~routine refurbishments on one international drilling ~~equipment that was ordered~~rig in ~~2014 which required a long lead-time~~preparation for ~~delivery, as well as deposits for~~its deployment in 2018, installments on the ~~20 well servicing rigs and four new~~purchase of three wireline units ~~that were~~and one coiled tubing unit, and scheduled refurbishments on ~~order for delivery in 2017.~~drilling and production services equipment.

Gain/Loss on Disposition of Property — During the ~~nine~~six months ended ~~September~~June 30, ~~2017,~~2018, we recognized a net ~~gain~~gains of ~~$2.3~~$1.1 million on the disposition of various property and equipment, including ~~sales~~the sale of ~~certain coiled tubing~~six wireline units and one drilling rig, which was previously held for sale. During the six months ended June 30, 2017, we recognized a net gain of $1.1 million on the disposition of property and equipment ~~and vehicles, as well as~~which was primarily related to the loss of drill pipe in operation, for which we were reimbursed by the client, gains on sales of vehicles which were used in our production services segments’ operations, and a gain on the disposal of two cranes that were ~~damaged, for which we expect to receive insurance proceeds of $0.4 million.~~damaged.

Assets Held for Sale—As of ~~September~~June 30, 2018, our condensed consolidated balance sheet reflects assets held for sale of $6.4 million, which primarily represents the fair value of two domestic SCR drilling rigs and one domestic mechanical drilling rig, as well as other drilling equipment, six offshore wireline units and five coiled tubing units. All of the wireline units and three of the coiled tubing units were subsequently sold in July 2018. During the six months ended June 30, 2018 and 2017, we recognized impairment charges of $2.4 million and $0.8 million, respectively, to reduce the carrying values of assets which were classified as held for sale, to their estimated fair values, based on expected sales prices which are classified as Level 3 inputs as defined by ASC Topic 820, Fair Value Measurements and Disclosures.

As of December 31, 2017, our condensed consolidated balance sheet reflects assets held for sale of ~~$8.8~~$6.6 million, which primarily represents the fair value of three domestic SCR drilling rigs and one domestic mechanical drilling rig, as well as other drilling equipment, two offshore wireline units and ~~two~~one coiled tubing units. During the nine months ended September 30, 2017, we recognized impairment charges of $0.8 million to adjust the carrying values of certain of these assets to their estimated fair values, based on expected sales prices, which are classified as Level 3 inputs as defined by Accounting Standards Codification (ASC) Topic 820, ~~Fair Value Measurements~~unit and ~~Disclosures~~.

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

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 and continued through 2017, we ~~continue~~continued to monitor all indicators of potential impairments in accordance with ASC Topic 360, Property, Plant and Equipment.

~~In performing an~~, and concluded there are no triggers present that require impairment evaluation, we estimate the future undiscounted net cash flows from the use and eventual disposition of the assets grouped at the lowest level that independent cash flows can be identified. For our Production Services Segment, we perform an impairment evaluation and estimate future undiscounted cash flows for the individual reporting units (well servicing, wireline and coiled tubing). For our Drilling Services Segment, we perform an impairment evaluation and estimate future undiscounted cash flows for individual domestic drilling rig assets and for our Colombian drilling rig assets as a group. If the sum of the estimated future undiscounted net cash flows is less than the carrying amount of the asset group, then we determine the fair value of the asset group. The amount of an impairment charge is measured as the difference between the carrying amount and the fair value of the assets.

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

If any of our assets become or remain idle for an extended amount of time, then our estimated cash flows may further decrease, and therefore the probability of a near term sale may increase. If any of the foregoing were to occur, we may incur additional impairment charges.2018. The assumptions ~~used~~we use in the evaluation for impairment ~~evaluation~~ are inherently uncertain and require management judgment.

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

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


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

Valuation Allowances on Deferred Tax Assets

910

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 of ~~September~~June 30, ~~2017~~2018 in accordance with ASC Topic 740, Income Taxes, we assessed the available positive and negative evidence to estimate whether sufficient future taxable income will be generated to permit the use of deferred tax assets. A significant piece of negative evidence evaluated is the cumulative loss incurred during previous years. Such negative evidence limits the ability to consider other positive evidence that is subjective, such as projections for taxable income in future years. As a result, we ~~may~~would recognize a benefit only to the extent that reversals of deferred income tax liabilities are expected to generate taxable income in each relevant jurisdiction in future periods which would offset our deferred tax assets.

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

During the three and ~~nine~~six months ended ~~September~~June 30, ~~2017, the impact of~~2018, we provided valuation allowance adjustments on deferred tax assets ~~was $5.9~~of $1.5 million and ~~$19.1~~$5.7 million, respectively. During the three and ~~nine~~six months ended ~~September~~June 30, ~~2016, the impact of~~2017, we provided valuation allowance adjustments on deferred tax assets ~~was $11.8~~of $3.5 million and ~~$31.6~~$13.2 million, respectively. The valuation allowance is the primary factor causing our effective tax rate to be significantly lower than the statutory ~~rate of 35%.~~rate. The amount of the deferred tax asset considered realizable, however, would increase if cumulative losses are no longer present and additional weight is given to subjective evidence in the form of projected future taxable income.

Recently Enacted Tax Reform

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

Territorial Tax System — To minimize tax base erosion with a territorial tax system, beginning in 2018, the Tax Reform Act provides for a new global intangible low-taxed income (GILTI) provision. Under the GILTI provision, certain foreign subsidiary earnings in excess of an allowable return on the foreign subsidiary’s tangible assets are included in U.S. taxable income. We are now subject to GILTI, but have not yet triggered an income inclusion as of June 30, 2018. Any future inclusion is expected to be offset by net operating loss carry forwards in the U.S. We are still evaluating, pending further interpretive guidance, whether to make a policy election to treat the GILTI tax as a period expense or to provide U.S. deferred taxes on foreign temporary differences that are expected to generate GILTI income when they reverse in future years.

Limitation on Interest Expense Deduction — The new limitation on interest expense resulted in a $14.1 million disallowance for the period ended June 30, 2018; however, this adjustment is offset fully by our net operating loss carry forwards. The disallowed interest has an indefinite carry forward period and any limitations on the utilization of this interest expense carryforward have been factored into our valuation allowance analysis.

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

Measurement Period — Given the significance of the legislation, the SEC staff issued Staff Accounting Bulletin No. 118 (SAB 118), which allows registrants to record provisional amounts during a one year “measurement period” similar to that used when accounting for business combinations. However, the measurement period is deemed to have ended earlier when the registrant has obtained, prepared and analyzed the information necessary to finalize its accounting. During the measurement period, impacts of the law are expected to be recorded at the time a reasonable estimate for all or a portion of the effects can be made, and provisional amounts can be recognized and adjusted as information becomes available,

prepared or analyzed. SAB 118 summarizes a three-step process to be applied at each reporting period to account for and qualitatively disclose: (1) the effects of the change in tax law for which accounting is complete; (2) provisional amounts (or adjustments to provisional amounts) for the effects of the tax law where accounting is not complete, but that a reasonable estimate has been determined; and (3) a reasonable estimate cannot yet be made and therefore taxes are reflected in accordance with law prior to the enactment of the Tax Reform Act.

Our accounting is complete as of June 30, 2018 and December 31, 2017 as related to the re-measurement of deferred taxes to the new tax rate of 21%, repeal of the AMT, mandatory repatriation, limitation on the current deductibility of net interest expense in excess of 30% of adjusted taxable income, and limitation of net operating losses generated after 2017 to 80% of taxable income. With respect to the new GILTI provision, we are awaiting further interpretive guidance regarding the possible application of deferred taxes to GILTI.

4.5. Debt

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


	September 30, 2017			December 31, 2016			June 30, 2018			December 31, 2017
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%)							(3,036		)	(3,387		)
Less unamortized debt issuance costs	(5,132		)	(6,527		)	(8,892		)	(9,948		)
	$	392,601		$	339,473		$	463,072		$	461,665

Senior Secured Term Loan

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

~~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,~~June 30, 2018, we had ~~$101.7 million outstanding under our Revolving Credit Facility and $11.8~~$9.7 million in committed letters of credit, which, after borrowing base limitations, resulted in borrowing availability of ~~$36.6 million~~$62.0 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.

1113

~~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,~~11, Guarantor/Non-Guarantor Condensed Consolidated 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.


5.6.	Fair Value of Financial Instruments

The FASB’s Accounting Standards Codification (ASC) Topic 820, Fair Value Measurements and Disclosures, defines fair value and provides a hierarchal framework associated with the level of subjectivity used in measuring assets and liabilities at fair value. 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~~June 30, ~~2017~~2018 and December 31, ~~2016,~~2017, the aggregate estimated fair value of our phantom stock unit awards was ~~$4.6~~$18.3 million and ~~$7.0~~$6.1 million, respectively, for which the vested portion recognized as a liability in our condensed consolidated balance sheets was ~~$2.4~~$10.1 million and ~~$2.0~~$3.6 million, respectively. The phantom stock unit awards, and the measurement of fair value for these awards, are described in more detail in Note 7,8, Stock-Based Compensation Plans.

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



		June 30, 2018				December 31, 2017
	Hierarchy Level	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Senior notes	2	$	296,578	$	286,875	$	296,181	$	243,948
Senior secured term loan	3	166,494		$	181,781	165,484		171,613
		$	463,072	$	468,656	$	461,665	$	415,561


6.7.	Earnings (Loss) Per Common Share

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


	Three months ended September 30,						Nine months ended September 30,						Three months ended June 30,						Six months ended June 30,
	2017			2016			2017			2016			2018			2017			2018			2017
Numerator (both basic and diluted):
Net loss	$	(17,227	)	$	(34,620	)	$	(62,560	)	$	(92,310	)	$	(18,152	)	$	(20,209	)	$	(29,291	)	$	(45,333	)
Denominator:
Weighted-average shares (denominator for basic earnings (loss) per share)	77,552			64,905			77,335			64,755			77,944			77,377			77,776			77,225
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			77,944			77,377			77,776			77,225
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													$	(0.23	)	$	(0.26	)	$	(0.38	)	$	(0.59	)
Loss per common share - Diluted													$	(0.23	)	$	(0.26	)	$	(0.38	)	$	(0.59	)
Potentially dilutive securities excluded as anti-dilutive	4,612			4,550			5,167			4,985			4,055			5,185			5,015			4,750


7.8.	Stock-Based Compensation Plans

We grant stock option and restricted stock awards with vesting based on time of service conditions. We grant restricted stock unit awards with vesting based on time of service conditions, and in certain cases, subject to performance and market conditions. ~~In 2016, we granted~~We grant phantom stock unit awards with vesting based on time of service, performance and market conditions, which are classified as liability awards under ASC Topic 718, Compensation—Stock Compensation since we expect to settle the awards in cash when they become vested.

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


	Three months ended September 30,				Nine months ended September 30,				Three months ended June 30,					Six months ended June 30,
	2017		2016		2017		2016		2018		2017			2018		2017
Stock option awards	$	249	$	192	$	726	$	573	$	99	$	246		$	241	$	477
Restricted stock awards	116		116		345		306		115		117			228		229
Restricted stock unit awards	525		625		2,154		2,119		883		645			1,887		1,629
	$	890	$	933	$	3,225	$	2,998	$	1,097	$	1,008		$	2,356	$	2,335
Phantom stock unit awards	$	878	$	307	$	397	$	1,033	$	6,099	$	(581	)	$	6,529	$	(481	)

Stock Option Awards

We grant stock option awards which generally become exercisable over a three-year period and expire ten years after the date of grant. Our stock-based compensation plans require that all stock option awards have an exercise price that is not less than the fair market value of our common stock on the date of grant. We issue shares of our common stock when vested stock option awards are exercised.

We estimate the fair value of each option grant on the date of grant using a Black-Scholes option pricing model. ~~The following table summarizes the assumptions used in the Black-Scholes option pricing model based on a weighted-average calculation for the~~There were no stock options granted during the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2018. ~~and~~ ~~2016~~:

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

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

Restricted Stock and Restricted Stock Unit Awards

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

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

The following table summarizes the number and weighted-average grant-date fair value of the restricted stock and restricted stock unit awards granted during the ~~nine~~three and six months ended ~~September~~June 30, ~~2017~~2018 and ~~2016~~2017:


	Nine months ended September 30,				Three months ended June 30,				Six months ended June 30,
	2017		2016		2018		2017		2018		2017
Restricted Stock:
Restricted stock awards granted	167,272		166,664		78,632		167,272		78,632		167,272
Weighted-average grant-date fair value	$	2.75	$	2.76	$	5.85	$	2.75	$	5.85	$	2.75
Time-based RSUs:
Time-based RSUs granted	96,728		260,334		—		30,000		788,377		96,728
Weighted-average grant-date fair value	$	5.61	$	1.48	$	—	$	4.00	$	3.85	$	5.61
Performance-based RSUs:
Performance-based RSUs granted	563,469		—		—		—		—		563,469
Weighted-average grant-date fair value	$	7.75	$	—	$	—	$	—	$	—	$	7.75

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

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

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

In April ~~2017,~~2018, we determined that ~~121%~~106% of the target number of shares granted during ~~2014~~2015 were actually earned based on the Company’s achievement of the performance measures as described above. As of ~~September~~June 30, ~~2017,~~2018, we estimate that

the ~~weighted average~~ achievement level for our outstanding performance-based RSUs granted in ~~2015 and~~ 2017 will be approximately ~~94%~~100% of the predetermined performance conditions.

Phantom Stock Unit Awards

In 2016 and 2018, we granted 1,268,068 and 1,188,216 phantom stock unit awards with a weighted-average grant-date fair ~~value~~values of $1.35 and $3.06 per ~~share.~~share, respectively. These awards cliff-vest after 39 months from the date of grant, with vesting based on time of service, performance and market conditions. The number of units ultimately awarded will be based upon the Company’s achievement in certain performance conditions, as compared to a predefined peer group, over the respective three-year performance ~~period,~~periods, and each unit awarded will entitle the employee to a cash payment equal to the stock price of our common stock on the date of vesting, subject to a maximum of $8.08 and $9.66 (which is four and three times the grant date stock ~~price on the date of grant).~~price), respectively.

The fair value of these awards is measured using inputs that are defined as Level 3 inputs under ASC Topic 820, Fair Value Measurements and Disclosures. ~~Approximately half~~Half of the 2016 phantom stock unit awards ~~granted~~ are subject to a market condition based on relative total shareholder return, ~~as compared to that~~and therefore the fair values of these awards are measured using a Monte Carlo simulation model, which incorporates the estimate of our ~~predetermined peer group,~~relative total shareholder return achievement level. The remaining 2016 phantom stock unit awards are subject to performance conditions, based on our relative EBITDA and EBITDA return on capital employed, and the fair values of these awards are measured using a Black-Scholes pricing model. We estimate our relative weighted average EBITDA and EBITDA return on capital achievement level for the 2016 phantom stock unit awards to be 185% at June 30, 2018. The 2018 phantom stock unit awards will vest based upon our relative total shareholder return and relative EBITDA return on capital, both of which are subject to market conditions, and therefore, the fair value of these awards is measured using a Monte Carlo simulation ~~model. The remaining~~model which generates a fair value that incorporates the relative estimated achievement levels. We estimate our relative EBITDA return on capital achievement level for the 2018 phantom stock unit awards are subject to performance conditions, based on our EBITDA and EBITDA return on capital employed, relative to our predetermined peer group, and the fair value of these awards is measured using a Black-Scholes pricing model. As of September 30, 2017, our achievement level for the awards granted during 2016 is estimated to be ~~approximately 130%. The final payout percentage will be based on our performance versus the performance of our peer group, over the three year period ending December 31,~~100% at June 30, 2018.

These awards are classified as liability awards under ASC Topic 718, Compensation—Stock Compensation, because we expect to settle the awards in cash when they vest, and are remeasured at fair value at the end of each reporting period until they vest. The change in fair value is recognized as a current period compensation expense in our ~~statement~~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 as of ~~September~~June 30, ~~2017,~~2018, if all other inputs were unchanged, would result in an increase in cumulative compensation expense of ~~$0.8~~$1.1 million, which represents the hypothetical increase in fair value of the liability for all outstanding phantom stock unit awards which would be recognized as compensation expense in our condensed consolidated statement of operations.


8.9.	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,~~services). We revised our segments as of December 31, 2017 to ~~a diverse group of exploration and production companies, with our operations concentrated~~reflect changes in the ~~major United States onshore oil~~basis used by management in making decisions regarding our business for resource allocation and ~~gas producing regions in~~performance assessment. These changes reflect our current operating focus as is required by ASC Topic 280, Segment Reporting. The following financial information presented as of and for the ~~Mid-Continent~~three and ~~Rocky Mountain states~~six months ended June 30, 2017 have been restated to reflect this change.

Our domestic and ~~in the Gulf Coast, both onshore and offshore.~~

~~Our Drilling Services Segment provides~~international drilling services 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 provide the drilling crews and most of the ancillary equipment needed to operate our drilling rigs.

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

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



	As of and for the three months ended June 30,					As of and for the six months ended June 30,
	2018		2017			2018		2017
Revenues:
Domestic drilling	$	35,634	$	30,473		$	71,560	$	58,818
International drilling	21,773		8,306			39,384		18,977
Drilling services	57,407		38,779			110,944		77,795
Well servicing	23,162		21,017			44,276		39,751
Wireline services	62,137		39,832			118,738		72,378
Coiled tubing services	12,076		7,502			25,302		12,963
Production services	97,375		68,351			188,316		125,092
Consolidated revenues	$	154,782	$	107,130		$	299,260	$	202,887

Operating costs:
Domestic drilling	$	21,749	$	20,380		$	42,647	$	39,889
International drilling	17,064		5,968			30,025		13,566
Drilling services	38,813		26,348			72,672		53,455
Well servicing	16,680		15,091			32,250		29,128
Wireline services	46,716		30,032			89,202		55,978
Coiled tubing services	11,988		7,588			22,839		13,226
Production services	75,384		52,711			144,291		98,332
Consolidated operating costs	$	114,197	$	79,059		$	216,963	$	151,787

Gross margin:
Domestic drilling	$	13,885	$	10,093		$	28,913	$	18,929
International drilling	4,709		2,338			9,359		5,411
Drilling services	18,594		12,431			38,272		24,340
Well servicing	6,482		5,926			12,026		10,623
Wireline services	15,421		9,800			29,536		16,400
Coiled tubing services	88		(86		)	2,463		(263		)
Production services	21,991		15,640			44,025		26,760
Consolidated gross margin	$	40,585	$	28,071		$	82,297	$	51,100

1618

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

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

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

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

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

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

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

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



	As of and for the three months ended June 30,				As of and for the six months ended June 30,
	2018		2017		2018		2017
Identifiable Assets:
Domestic drilling⁽¹⁾	$	380,355	$	412,319	$	380,355	$	412,319
International drilling ^{(1) (2)}	42,457		33,469		42,457		33,469
Drilling services	422,812		445,788		422,812		445,788
Well servicing	124,458		135,041		124,458		135,041
Wireline services	99,243		88,629		99,243		88,629
Coiled tubing services	31,889		26,121		31,889		26,121
Production services	255,590		249,791		255,590		249,791
Corporate	78,642		12,962		78,642		12,962
Consolidated identifiable assets	$	757,044	$	708,541	$	757,044	$	708,541

Depreciation and Amortization:
Domestic drilling	$	10,139	$	11,534	$	20,588	$	23,013
International drilling	1,301		1,357		2,748		2,979
Drilling services	11,440		12,891		23,336		25,992
Well servicing	4,865		5,000		9,785		10,012
Wireline services	4,601		4,452		9,209		8,905
Coiled tubing services	2,114		2,089		4,146		4,215
Production services	11,580		11,541		23,140		23,132
Corporate	267		308		558		608
Consolidated depreciation and amortization	$	23,287	$	24,740	$	47,034	$	49,732

Capital Expenditures:
Domestic drilling	$	4,736	$	6,314	$	7,494	$	15,780
International drilling	1,213		1,342		3,913		1,714
Drilling services	5,949		7,656		11,407		17,494
Well servicing	3,403		2,007		5,452		14,347
Wireline services	4,917		3,501		8,590		7,509
Coiled tubing services	4,817		982		7,981		2,262
Production services	13,137		6,490		22,023		24,118
Corporate	251		231		495		372
Consolidated capital expenditures	$	19,337	$	14,377	$	33,925	$	41,984


(1)	Identifiable assets for our drilling segments include the impact of a $35.1 million and $20.6 million intercompany balance, as of June 30, 2018 and 2017, 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 June 30,						Six months ended June 30,
	2018			2017			2018			2017
Consolidated gross margin	$	40,585		$	28,071		$	82,297		$	51,100
Depreciation and amortization	(23,287		)	(24,740		)	(47,034		)	(49,732		)
General and administrative	(24,829		)	(16,112		)	(44,023		)	(33,856		)
Bad debt recovery, net of expense	370			226			422			589
Impairment	(2,368		)	(795		)	(2,368		)	(795		)
Gain on dispositions of property and equipment, net	726			621			1,061			1,092
Loss from operations	$	(8,803	)	$	(12,729	)	$	(9,645	)	$	(31,602	)


9.10.	Commitments and Contingencies

In connection with our operations in Colombia, our foreign subsidiaries have obtained bonds for bidding on drilling contracts, performing under drilling contracts, and remitting customs and importation duties. We have guaranteed payments of $~~43.4~~73.4 million relating to our performance under these bonds as of ~~September~~June 30, ~~2017~~2018.

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~~June 30, ~~2017~~2018 and December 31, ~~2016,~~2017, our accrued liability was ~~$1.1~~$1.4 million and $~~0.6~~1.2 million, respectively, based on our estimate of the sales and use tax obligations that are expected to result from these audits. Due to the inherent uncertainty of the audit process, we believe that it is reasonably possible that we may incur additional tax assessments with respect to one or more of the audits in excess of the amount accrued. We believe that such an outcome would not have a material adverse effect on our results of operations or financial position. Because certain of these audits are in a preliminary stage, an estimate of the possible loss or range of loss from an adverse result in all or substantially all of these cases cannot reasonably be made.

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


~~10.~~11.	Guarantor/Non-Guarantor Condensed Consolidating Financial Statements

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

In the event of a bankruptcy, liquidation or reorganization of any non-guarantor subsidiary, such non-guarantor subsidiary will pay the holders of its debt and other liabilities, including its trade creditors, before it will be able to distribute any of its assets to us. In the future, any non-U.S. subsidiaries, immaterial subsidiaries and subsidiaries that we designate as unrestricted subsidiaries under the Indenture will not guarantee the Senior Notes. As of ~~September~~June 30, ~~2017~~2018, there were no restrictions on the ability of subsidiary guarantors to transfer funds to the parent company.

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

1820

CONDENSED CONSOLIDATING BALANCE SHEETS

(unaudited, in thousands)


	September 30, 2017														June 30, 2018
	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	$	57,351		$	(1,688	)	$	5,854		$	—		$	61,517
Restricted cash															2,000			—			—			—			2,000
Receivables, net of allowance	5			87,786			15,055			(42		)	102,804		4			100,739			25,342			741			126,826
Intercompany receivable (payable)	(24,836		)	47,186			(22,350		)	—			—		(24,836		)	59,677			(34,841		)	—			—
Inventory	—			6,216			5,542			—			11,758		—			8,895			8,824			—			17,719
Assets held for sale	—			8,704			52			—			8,756		—			6,433			—			—			6,433
Prepaid expenses and other current assets	1,589			2,043			1,699			—			5,331		2,062			3,137			1,511			—			6,710
Total current assets	(12,462		)	150,710			1,295			(42		)	139,501		36,581			177,193			6,690			741			221,205
Net property and equipment	2,185			539,286			25,030			—			566,501		1,949			502,384			28,944			—			533,277
Investment in subsidiaries	573,721			20,198			—			(593,919		)	—		589,844			22,780			—			(612,624		)	—
Deferred income taxes	58,545			—			—			(58,545		)	—		40,272			—			—			(40,272		)	—
Other long-term assets	481			797			162			—			1,440
Other noncurrent assets															641			582			1,339			—			2,562
Total assets	$	622,470		$	710,991		$	26,487		$	(652,506	)	$	707,442	$	669,287		$	702,939		$	36,973		$	(652,155	)	$	757,044
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	467		$	28,858		$	2,683		$	—		$	32,008	$	1,245		$	29,882		$	6,887		$	—		$	38,014
Deferred revenues	—			302			481			—			783		—			45			1,876			—			1,921
Accrued expenses	5,526			38,548			2,690			(42		)	46,722		20,980			38,193			4,434			741			64,348
Total current liabilities	5,993			67,708			5,854			(42		)	79,513		22,225			68,120			13,197			741			104,283
Long-term debt, less debt issuance costs	392,601			—			—			—			392,601
Long-term debt, less unamortized discount and debt issuance costs															463,072			—			—			—			463,072
Deferred income taxes	—			67,160			—			(58,545		)	8,615		—			43,701			—			(40,272		)	3,429
Other long-term liabilities	2,348			2,402			435			—			5,185
Other noncurrent liabilities															1,299			1,274			996			—			3,569
Total liabilities	400,942			137,270			6,289			(58,587		)	485,914		486,596			113,095			14,193			(39,531		)	574,353
Total shareholders’ equity	221,528			573,721			20,198			(593,919		)	221,528		182,691			589,844			22,780			(612,624		)	182,691
Total liabilities and shareholders’ equity	$	622,470		$	710,991		$	26,487		$	(652,506	)	$	707,442	$	669,287		$	702,939		$	36,973		$	(652,155	)	$	757,044

	December 31, 2016														December 31, 2017
	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	$	72,258		$	(1,881	)	$	3,263		$	—		$	73,640
Restricted cash															2,008			—			—			—			2,008
Receivables, net of allowance	480			64,946			7,210			(513		)	72,123		7			93,866			19,174			(42		)	113,005
Intercompany receivable (payable)	(24,836		)	35,427			(10,591		)	—			—		(24,836		)	51,532			(26,696		)	—			—
Inventory	—			5,659			4,001			—			9,660		—			7,741			6,316			—			14,057
Assets held for sale	—			15,035			58			—			15,093		—			6,620			—			—			6,620
Prepaid expenses and other current assets	1,280			4,014			1,632			—			6,926		1,238			3,193			1,798			—			6,229
Total current assets	(13,178		)	124,317			3,370			(513		)	113,996		50,675			161,071			3,855			(42		)	215,559
Net property and equipment	2,501			556,062			25,517			—			584,080		2,011			521,080			26,532			—			549,623
Investment in subsidiaries	577,965			24,270			—			(602,235		)	—		596,927			20,095			—			(617,022		)	—
Deferred income taxes	65,041			—			—			(65,041		)	—		38,028			—			—			(38,028		)	—
Other long-term assets	583			1,029			414			—			2,026
Other noncurrent assets															496			788			403			—			1,687
Total assets	$	632,912		$	705,678		$	29,301		$	(667,789	)	$	700,102	$	688,137		$	703,034		$	30,790		$	(655,092	)	$	766,869
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	546		$	16,317		$	2,345		$	—		$	19,208	$	286		$	24,174		$	5,078		$	—		$	29,538
Deferred revenues	—			680			769			—			1,449		—			97			808			—			905
Accrued expenses	9,316			34,765			1,777			(513		)	45,345		12,504			37,814			4,195			(42		)	54,471
Total current liabilities	9,862			51,762			4,891			(513		)	66,002		12,790			62,085			10,081			(42		)	84,914
Long-term debt, less debt issuance costs	339,473			—			—			—			339,473
Long-term debt, less unamortized discount and debt issuance costs															461,665			—			—			—			461,665
Deferred income taxes	—			73,249			(28		)	(65,041		)	8,180		—			41,179			—			(38,028		)	3,151
Other long-term liabilities	2,179			2,702			168			—			5,049
Other noncurrent liabilities															3,586			2,843			614			—			7,043
Total liabilities	351,514			127,713			5,031			(65,554		)	418,704		478,041			106,107			10,695			(38,070		)	556,773
Total shareholders’ equity	281,398			577,965			24,270			(602,235		)	281,398		210,096			596,927			20,095			(617,022		)	210,096
Total liabilities and shareholders’ equity	$	632,912		$	705,678		$	29,301		$	(667,789	)	$	700,102	$	688,137		$	703,034		$	30,790		$	(655,092	)	$	766,869

1921

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(unaudited, in thousands)


	Three months ended September 30, 2017															Three months ended June 30, 2018
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated			Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Revenues	$	—		$	109,878		$	7,403		$	—		$	117,281		$	—		$	133,008		$	21,774		$	—		$	154,782
Costs and expenses:
Operating costs	—			80,075			6,615			—			86,690			—			97,134			17,063			—			114,197
Depreciation and amortization	313			22,882			1,428			—			24,623			266			21,720			1,301			—			23,287
General and administrative	5,737			11,424			505			(138		)	17,528			10,130			14,090			714			(105		)	24,829
Intercompany leasing	—			(1,215		)	1,215			—			—			—			(1,215		)	1,215			—			—
Bad debt recovery	—			491			—			—			491
Bad debt recovery, net of expense																—			(370		)	—			—			(370		)
Impairment																—			2,368			—			—			2,368
Gain on dispositions of property and equipment, net	—			(1,159		)	—			—			(1,159		)	—			(713		)	(13		)	—			(726		)
Total costs and expenses	6,050			112,498			9,763			(138		)	128,173			10,396			133,014			20,280			(105		)	163,585
Income (loss) from operations	(6,050		)	(2,620		)	(2,360		)	138			(10,892		)	(10,396		)	(6		)	1,494			105			(8,803		)
Other (expense) income:
Other income (expense):
Equity in earnings of subsidiaries	(4,650		)	(2,393		)	—			7,043			—			521			1,034			—			(1,555		)	—
Interest expense	(6,614		)	1			—			—			(6,613		)	(9,645		)	(2		)	5			—			(9,642		)
Other (expense) income	9			220			204			(138		)	295
Total other (expense) income	(11,255		)	(2,172		)	204			6,905			(6,318		)
Other income (expense)																159			223			(233		)	(105		)	44
Total other income (expense), net																(8,965		)	1,255			(228		)	(1,660		)	(9,598		)
Income (loss) before income taxes	(17,305		)	(4,792		)	(2,156		)	7,043			(17,210		)	(19,361		)	1,249			1,266			(1,555		)	(18,401		)
Income tax (expense) benefit ¹	78			142			(237		)	—			(17		)	1,209			(728		)	(232		)	—			249
Net income (loss)	$	(17,227	)	$	(4,650	)	$	(2,393	)	$	7,043		$	(17,227	)	$	(18,152	)	$	521		$	1,034		$	(1,555	)	$	(18,152	)


	Three months ended September 30, 2016															Three months ended June 30, 2017
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated			Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Revenues	$	—		$	67,731		$	622		$	—		$	68,353		$	—		$	98,824		$	8,306		$	—		$	107,130
Costs and expenses:
Operating costs	—			50,061			1,627			—			51,688			—			73,092			5,967			—			79,059
Depreciation and amortization	303			26,659			1,701			—			28,663			307			23,076			1,357			—			24,740
General and administrative	5,046			9,017			387			(138		)	14,312			4,941			10,833			476			(138		)	16,112
Intercompany leasing	—			(1,215		)	1,215			—			—			—			(1,215		)	1,215			—			—
Bad debt expense	—			(359		)	—			—			(359		)
Impairment charges	—			4,262			—			—			4,262
Gain on dispositions of property and equipment, net	—			(325		)	(3		)	—			(328		)
Bad debt recovery, net of expense																—			(226		)	—			—			(226		)
Impairment																—			795			—			—			795
Loss (gain) on dispositions of property and equipment, net																2			(511		)	(112		)	—			(621		)
Total costs and expenses	5,349			88,100			4,927			(138		)	98,238			5,250			105,844			8,903			(138		)	119,859
Income (loss) from operations	(5,349		)	(20,369		)	(4,305		)	138			(29,885		)
Other (expense) income:
Loss from operations																(5,250		)	(7,020		)	(597		)	138			(12,729		)
Other income (expense):
Equity in earnings of subsidiaries	(23,794		)	(4,587		)	—			28,381			—			(6,283		)	(883		)	—			7,166			—
Interest expense	(6,661		)	(14		)	(3		)	—			(6,678		)	(6,480		)	62			—			—			(6,418		)
Other (expense) income	14			217			152			(138		)	245
Total other (expense) income	(30,441		)	(4,384		)	149			28,243			(6,433		)
Income (loss) before income taxes	(35,790		)	(24,753		)	(4,156		)	28,381			(36,318		)
Other income (expense)																12			245			(46		)	(138		)	73
Total other expense, net																(12,751		)	(576		)	(46		)	7,028			(6,345		)
Loss before income taxes																(18,001		)	(7,596		)	(643		)	7,166			(19,074		)
Income tax (expense) benefit ¹	1,170			959			(431		)	—			1,698			(2,208		)	1,313			(240		)	—			(1,135		)
Net income (loss)	$	(34,620	)	$	(23,794	)	$	(4,587	)	$	28,381		$	(34,620	)
Net loss																$	(20,209	)	$	(6,283	)	$	(883	)	$	7,166		$	(20,209	)

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.

2022

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(unaudited, in thousands)


	Nine months ended September 30, 2017															Six months ended June 30, 2018
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated			Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Revenues	$	—		$	293,788		$	26,380		$	—		$	320,168		$	—		$	259,875		$	39,385		$	—		$	299,260
Costs and expenses:
Operating costs	—			218,344			20,175			—			238,519			—			186,943			30,020			—			216,963
Depreciation and amortization	921			69,027			4,407			—			74,355			557			43,729			2,748			—			47,034
General and administrative	16,507			33,818			1,431			(414		)	51,342			16,368			26,629			1,236			(210		)	44,023
Intercompany leasing	—			(3,645		)	3,645			—			—			—			(2,430		)	2,430			—			—
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																—			(422		)	—			—			(422		)
Impairment																—			2,368			—			—			2,368
Gain on dispositions of property and equipment, net																—			(1,034		)	(27		)	—			(1,061		)
Total costs and expenses	17,430			316,115			29,531			(414		)	362,662			16,925			255,783			36,407			(210		)	308,905
Income (loss) from operations	(17,430		)	(22,327		)	(3,151		)	414			(42,494		)	(16,925		)	4,092			2,978			210			(9,645		)
Other (expense) income:
Other income (expense):
Equity in earnings of subsidiaries	(19,518		)	(3,924		)	—			23,442			—			5,070			2,687			—			(7,757		)	—
Interest expense	(19,110		)	20			—			—			(19,090		)	(19,161		)	(2		)	8			—			(19,155		)
Other (expense) income	37			678			(77		)	(414		)	224
Total other (expense) income	(38,591		)	(3,226		)	(77		)	23,028			(18,866		)
Other income																161			442			155			(210		)	548
Total other income (expense), net																(13,930		)	3,127			163			(7,967		)	(18,607		)
Income (loss) before income taxes	(56,021		)	(25,553		)	(3,228		)	23,442			(61,360		)	(30,855		)	7,219			3,141			(7,757		)	(28,252		)
Income tax (expense) benefit ¹	(6,539		)	6,035			(696		)	—			(1,200		)	1,564			(2,149		)	(454		)	—			(1,039		)
Net income (loss)	$	(62,560	)	$	(19,518	)	$	(3,924	)	$	23,442		$	(62,560	)	$	(29,291	)	$	5,070		$	2,687		$	(7,757	)	$	(29,291	)


	Nine months ended September 30, 2016															Six months ended June 30, 2017
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated			Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Revenues	$	—		$	203,616		$	1,979		$	—		$	205,595		$	—		$	183,910		$	18,977		$	—		$	202,887
Costs and expenses:
Operating costs	—			142,766			4,726			—			147,492			—			138,227			13,560			—			151,787
Depreciation and amortization	960			81,257			5,192			—			87,409			608			46,145			2,979			—			49,732
General and administrative	16,324			29,061			1,107			(414		)	46,078			10,770			22,436			926			(276		)	33,856
Intercompany leasing	—			(3,645		)	3,645			—			—			—			(2,430		)	2,430			—			—
Bad debt expense	—			(302		)	—			—			(302		)
Impairment charges	—			4,262			—			—			4,262
Gain on dispositions of property and equipment, net	—			(366		)	(54		)	—			(420		)
Bad debt recovery, net of expense																—			(589		)	—			—			(589		)
Impairment																—			795			—			—			795
Loss (gain) on dispositions of property and equipment, net																2			(967		)	(127		)	—			(1,092		)
Total costs and expenses	17,284			253,033			14,616			(414		)	284,519			11,380			203,617			19,768			(276		)	234,489
Income (loss) from operations	(17,284		)	(49,417		)	(12,637		)	414			(78,924		)
Other (expense) income:
Loss from operations																(11,380		)	(19,707		)	(791		)	276			(31,602		)
Other income (expense):
Equity in earnings of subsidiaries	(58,421		)	(13,777		)	—			72,198			—			(14,868		)	(1,531		)	—			16,399			—
Interest expense	(19,220		)	(88		)	1			—			(19,307		)	(12,496		)	19			—			—			(12,477		)
Loss on extinguishment of debt	(299		)	—			—			—			(299		)
Other (expense) income	12			1,222			(246		)	(414		)	574
Total other (expense) income	(77,928		)	(12,643		)	(245		)	71,784			(19,032		)
Income (loss) before income taxes	(95,212		)	(62,060		)	(12,882		)	72,198			(97,956		)
Other income (expense)																28			458			(281		)	(276		)	(71		)
Total other expense, net																(27,336		)	(1,054		)	(281		)	16,123			(12,548		)
Loss before income taxes																(38,716		)	(20,761		)	(1,072		)	16,399			(44,150		)
Income tax (expense) benefit ¹	2,902			3,639			(895		)	—			5,646			(6,617		)	5,893			(459		)	—			(1,183		)
Net income (loss)	$	(92,310	)	$	(58,421	)	$	(13,777	)	$	72,198		$	(92,310	)
Net loss																$	(45,333	)	$	(14,868	)	$	(1,531	)	$	16,399		$	(45,333	)

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.

2123

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

(unaudited, in thousands)


																Six months ended June 30, 2018
																Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities																$	(26,819	)	$	37,264		$	6,680		$	—		$	17,125

Cash flows from investing activities:
Purchases of property and equipment																(435		)	(26,989		)	(4,061		)	—			(31,485		)
Proceeds from sale of property and equipment																—			2,212			13			—			2,225
Proceeds from insurance recoveries																—			527			14			—			541
																(435		)	(24,250		)	(4,034		)	—			(28,719		)

Cash flows from financing activities:
Proceeds from exercise of options																12			—			—			—			12
Purchase of treasury stock																(549		)	—			—			—			(549		)
Intercompany contributions/distributions																12,876			(12,821		)	(55		)	—			—
																12,339			(12,821		)	(55		)	—			(537		)

Net increase (decrease) in cash, cash equivalents and restricted cash																(14,915		)	193			2,591			—			(12,131		)
Beginning cash, cash equivalents and restricted cash																74,266			(1,881		)	3,263			—			75,648
Ending cash, cash equivalents and restricted cash																$	59,351		$	(1,688	)	$	5,854		$	—		$	63,517

	Nine months ended September 30, 2017															Six months ended June 30, 2017
	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	)	$	(21,031	)	$	2,799		$	1,935		$	—		$	(16,297	)

Cash flows from investing activities:
Purchases of property and equipment	(563		)	(48,490		)	(4,023		)	270			(52,806		)	(317		)	(37,904		)	(2,081		)	270			(40,032		)
Proceeds from sale of property and equipment	—			10,528			149			(270		)	10,407			—			7,869			149			(270		)	7,748
Proceeds from insurance recoveries	—			3,119			—			—			3,119			—			3,119			—			—			3,119
	(563		)	(34,843		)	(3,874		)	—			(39,280		)	(317		)	(26,916		)	(1,932		)	—			(29,165		)

Cash flows from financing activities:
Debt repayments	(13,267		)	—			—			—			(13,267		)	(12,305		)	—			—			—			(12,305		)
Proceeds from issuance of debt	65,000			—			—			—			65,000			55,000			—			—			—			55,000
Purchase of treasury stock	(533		)	—			—			—			(533		)	(533		)	—			—			—			(533		)
Intercompany contributions/distributions	(14,379		)	14,614			(235		)	—			—			(22,201		)	22,216			(15		)	—			—
	36,821			14,614			(235		)	—			51,200			19,961			22,216			(15		)	—			42,162

Net increase (decrease) in cash and cash equivalents	882			(461		)	237			—			658
Net decrease in cash and cash equivalents																(1,387		)	(1,901		)	(12		)	—			(3,300		)
Beginning cash and cash equivalents	9,898			(764		)	1,060			—			10,194			9,898			(764		)	1,060			—			10,194
Ending cash and cash equivalents	$	10,780		$	(1,225	)	$	1,297		$	—		$	10,852		$	8,511		$	(2,665	)	$	1,048		$	—		$	6,894

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

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

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

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

2224


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

Statements we make in the following discussion that express a belief, expectation or intention, as well as those that are not historical fact, are forward-looking statements made in good faith that are subject to risks, uncertainties and assumptions. Our actual results, performance or achievements, or industry results, ~~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 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~~, 2017, including under the headings “Special Note Regarding Forward-Looking Statements” in the Introductory Note to Part I and “Risk Factors” in Item 1A.1A. These factors are not necessarily all the important factors that could affect us.Other unpredictable or unknown factors could also have material adverse effects on actual results of matters that are the subject of our forward-looking statements. All forward-looking statements speak only as of the date on which they are made and we undertake no obligation to publicly update or revise any forward-looking statements whether as a result of new information, future events or otherwise. We advise our shareholders that they should (1) recognize that important factors not referred to above could affect the accuracy of our forward-looking statements and (2) use caution and common sense when considering our forward-looking statements.

Company Overview

Pioneer Energy Services Corp. ~~(formerly called “Pioneer Drilling Company”)~~ provides land-based drilling services and production services to a diverse group of ~~independent and large~~ oil and gas exploration and production companies in the United States and internationally in Colombia. ~~We also provide two of our services (coiled tubing and wireline services) offshore in the Gulf of Mexico.~~ Drilling services and production services are fundamental to establishing and maintaining the flow of oil and natural gas throughout the productive life of a ~~well and enable us to meet multiple needs of our clients.~~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~~drilling. We have 16 AC rigs in the US and eight SCR rigs in Colombia, all of which have 1,500 horsepower or greater drawworks. ~~The removal of older, less capable rigs from our fleet and the recent investments in~~In July 2018, we entered into a three-year term contract for the construction of a new ~~drilling rigs has transformed our fleet into a highly capable, pad optimal fleet focused on~~1,500 horsepower, AC pad-optimal rig which we expect to deploy in early 2019 to 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.

Permian Basin. In addition to our drilling rigs, we provide the drilling crews and most of the ancillary equipment needed to operate our drilling rigs. The drilling rigs in our current fleet are ~~currently~~ deployed through our division offices in the following regions:



		Rig Count
Domestic drilling
Marcellus/Utica		6
Permian Basin and Eagle Ford		1
~~Permian Basin~~		78
Bakken		2
~~Colombia~~International drilling		8
		24

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

Well Servicing. A range of services are required in order to establish production in newly-drilled wells and to maintain production over the useful lives of active wells. We use our well servicing rig fleet to provide these necessary services, including the completion of newly-drilled wells, maintenance and workover of active wells, and plugging and abandonment of wells at the end of their useful lives. ~~As of September 30, 2017, we~~We have a fleet of 113 rigs with 550 horsepower and 12 rigs with 600 horsepower with operations in 1011 locations, mostly in the Gulf Coast states, as well as in Arkansas, North Dakota, and Colorado.

Wireline Services. Oil and gas exploration and production companies require wireline services to better understand the reservoirs they are drilling or producing, and use logging services to accurately characterize reservoir rocks and fluids. To complete a cased-hole well, the production casing must be perforated to establish a flow path between the reservoir and the wellbore. We use our fleet of wireline units to provide these important logging and perforating services in addition to a range of other mechanical services that are needed in order to place equipment in or retrieve equipment or debris from the wellbore, install bridge plugs and control pressure. ~~As of September 30, 2017, we~~We have a current fleet of ~~117~~104 wireline units, with one additional unit on order for delivery in 17the third quarter of 2018. Our units are deployed through 14 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 metal pipe spooled on a large reel for oil and natural gas well applications, such as wellbore clean-outs, nitrogen jet lifts, through-tubing fishing, formation stimulation utilizing acid, chemical treatments and fracturing. Coiled tubing is also used for a number of horizontal well applications such as milling temporary plugs between frac stages. As We have a current fleet of ~~September 30, 2017, our coiled tubing business consists of 10 onshore and four offshore~~11 coiled tubing units, ~~which~~with one additional unit on order for delivery late in 2018. Our units are deployed through ~~four~~two 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, 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. We revised our reportable business segments as of the fourth quarter of 2017 to reflect changes in the basis used by management in making decisions regarding our business for resource allocation and performance assessment. Financial information about our operating segments is included in Note 8,9, Segment Information, of the Notes to Condensed Consolidated Financial Statements, included in Part I, Item 1, Financial Statements, of this Quarterly Report on Form 10-Q.

Pioneer Energy Services Corp.’s corporate office is located at 1250 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 activity, as opposed to completion of new wells, tend to be less affected by fluctuations in commodity prices and temporary reductions in industry activity.

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

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

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.~~2017.

Market Conditions — Our industry ~~has experienced~~is currently experiencing a recovery from a severe down cycle ~~since~~that began in late 2014 and which persisted through 2016, ~~with~~during which WTI oil prices ~~(WTI) dipping~~dipped below $30 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 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 almost $75 per barrel at the end of June, and ~~a current oil price at September 30, 2017 of almost $52~~have since averaged above $70 per ~~barrel.~~barrel through mid-July.

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,~~

We began 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~~with utilization of our ACdomestic fleet ~~was~~at 81% and ~~there was one rig~~four rigs 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~~domestic fleet ishas increased to 100%~~. Of the~~, and seven of our eight international rigs ~~in Colombia, five~~ are currently earning revenues ~~four of which are~~ under term ~~contracts, and an additional~~contracts. In July 2018, we entered into a three-year term contract for the construction of a new 1,500 horsepower, AC pad-optimal rig ~~is under contract, pending operations. The term contracts~~which we expect to deploy in ~~Colombia are cancelable by our clients without penalty, although~~early 2019 to 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.Permian Basin.

As of ~~September~~June 30, ~~2017, 22~~2018, 23 of our 24 drilling rigs are earning revenues, 1821 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	2	14	6	3	5	—	—
International rigs	—	7	—	2	1	3	1
	2	21	6	5	6	3	1

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

Our well servicing rig hours and number of wireline jobs completed during the quarter ended June 30, 2018 increased by 5% and 7%, respectively, while revenue days for our coiled tubing services decreased by 15%, as compared to the first quarter of 2018. Average revenue rates for our well servicing, wireline and coiled tubing services provided during this same period increased by 4%, 3% and 8% (on a per hour, per job and per day basis, respectively). The wireline and coiled tubing increases were primarily driven by an increase in the proportion of completion-related activity and work performed by larger diameter coiled tubing units.

Despite the ~~recent increases~~recovery of demand for our services in onshore regions, offshore activity ~~current uncertainty~~has remained depressed. As a result, we exited the offshore wireline and coiled tubing market in the second quarter of 2018 and designated as held for sale all but two of our more desirable offshore coiled tubing units that we may deploy if offshore demand improves.

Limited takeaway capacity in the Permian Basin has led to price discounts on crude oil that could impact activity and near term growth in the region; however, we have term contract coverage for our drilling rigs and limited production services units currently operating in this region which limits our exposure to any decreases in activity.

Absent a significant decline in commodity prices, ~~could cause our clients~~we expect demand to ~~again reduce their spending which would negatively impact our activity and pricing. We~~remain strong for the remainder of 2018. Although we expect a highly competitive environment to continue, ~~into 2018, but~~ we believe our high-quality equipment and services and our excellent safety record make us well positioned to compete.

Liquidity and Capital Resources

Sources of Capital Resources

Our principal sources of liquidity currently consist of:

total cash and cash equivalents ($~~10.9~~63.5 million as of ~~September~~June 30, ~~2017)~~2018);

cash generated from ~~operations;~~operations ($17.1 million during the six months ended June 30, 2018);

proceeds from sales of certain non-strategic assets; and

the unused portion of our ~~senior secured revolving credit~~asset-based lending facility ($62.0 million as of June 30, 2018).

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 June 30, 2018, we had $9.7 million in committed letters of credit, which, after borrowing base limitations, resulted in borrowing availability of $62.0 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~~June 30, ~~2017, $234.6~~2018, 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.

We currently expect that cash and cash equivalents, cash generated from operations, proceeds from sales of certain non-strategic assets, and available borrowings under our ~~Revolving Credit~~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.

2729

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.

Working Capital — Our working capital was ~~$60.0~~$116.9 million at ~~September~~June 30, ~~2017,~~2018, compared to ~~$48.0~~$130.6 million at December 31, ~~2016.~~2017. Our current ratio, which we calculate by dividing current assets by current liabilities, was ~~1.8~~2.1 at ~~September~~June 30, ~~2017,~~2018, as compared to ~~1.7~~2.5 at December 31, ~~2016.~~2017. 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			June 30, 2018		December 31, 2017		Change
Cash and cash equivalents	$	10,852	$	10,194	$	658		$	61,517	$	73,640	$	(12,123	)
Restricted cash								2,000		2,008		(8		)
Receivables:
Trade, net of allowance for doubtful accounts	71,634		38,764		32,870			84,591		79,592		4,999
Unbilled receivables	14,268		7,417		6,851			22,951		16,029		6,922
Insurance recoveries	13,491		17,003		(3,512		)	15,014		13,874		1,140
Other receivables	3,411		8,939		(5,528		)	4,270		3,510		760
Inventory	11,758		9,660		2,098			17,719		14,057		3,662
Assets held for sale	8,756		15,093		(6,337		)	6,433		6,620		(187		)
Prepaid expenses and other current assets	5,331		6,926		(1,595		)	6,710		6,229		481
Current assets	139,501		113,996		25,505			221,205		215,559		5,646
Accounts payable	32,008		19,208		12,800			38,014		29,538		8,476
Deferred revenues	783		1,449		(666		)	1,921		905		1,016
Accrued expenses:
Payroll and related employee costs	19,298		14,813		4,485			29,315		21,023		8,292
Insurance claims and settlements								14,702		13,289		1,413
Insurance premiums and deductibles	7,811		6,446		1,365			6,238		6,742		(504		)
Insurance claims and settlements	13,084		13,667		(583		)
Interest	912		5,395		(4,483		)	6,361		6,624		(263		)
Other	5,617		5,024		593			7,732		6,793		939
Current liabilities	79,513		66,002		13,511			104,283		84,914		19,369
Working capital	$	59,988	$	47,994	$	11,994		$	116,922	$	130,645	$	(13,723	)

Cash and cash equivalents — ~~During 2017, we used $52.8~~The change in cash and cash equivalents during 2018 is primarily due to $31.5 million of cash used for the ~~purchases~~purchase of property and equipment, ~~and used $11.3~~partially offset by $17.1 million inof cash from operating activities ~~primarily funded by $51.7 million of net borrowings under our Revolving Credit Facility~~ and ~~$10.4~~$2.2 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~~2018 is primarily due to the ~~64%~~23% increase in our revenues during the quarter ended ~~September~~June 30, ~~2017,~~2018, 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.~~2017. Our domestic trade receivables generally turn over within 9060 days, and our Colombian trade receivables generally turn over within 100 days.

Insurance recoveries and Insurance claims and settlements — The increase in our insurance recoveries receivables and our insurance claims and settlements accrued expenses during 2018 is primarily due to an increase in our insurance company’s reserve for workers’ compensation claims in excess of our deductibles.

2830

~~Insurance recoveries~~ Other receivables— The ~~decrease~~increase in ~~our insurance recoveries~~other receivables during ~~2017~~2018 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~~increase in ~~early 2017.~~

~~Other~~recoverable income tax receivables — ~~The decrease in other receivables during 2017 is primarily due~~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.~~our international operations. This ~~decrease~~increase is partially offset by ~~$0.8 million remaining of~~ a decrease in short-term ~~note~~notes receivable from the ~~sales~~sale of ~~two mechanical~~ drilling rigs ~~that~~and equipment, for which payments were ~~sold~~received during ~~the third quarter of 2017.~~2018.

Inventory — The increase in inventory during ~~2017~~2018 is primarily due to the increase in activity for our ~~Colombian~~international operations, as well as purchases of supplies and job materials for our wireline and coiled tubing operations.

~~Assets held for sale~~Accounts payable — ~~As of September~~Our accounts payable generally turn over within 90 days. The increase in accounts payable during 2018 is primarily due to the 24% increase in our operating costs for the quarter ended June 30, ~~2017, our condensed consolidated balance sheet reflects assets held for sale of $8.8 million, which primarily represents~~2018 as compared to the ~~fair value of three domestic SCR drilling rigs and one domestic mechanical drilling rig, as well as other drilling equipment and two coiled tubing units. At~~quarter ended 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~~an increase of ~~which were sold~~$2.4 million in ~~2017; however, it did not include the fair value~~our accruals for capital expenditures as of ~~the coiled tubing units which were placed~~June 30, 2018 as ~~held for sale during~~compared to December 31, 2017.

~~Prepaid expenses~~Accrued payroll and ~~other current assets~~related employee costs — The ~~decrease~~increase in ~~prepaid expenses~~accrued payroll and ~~other current assets~~related employee costs during ~~2017~~2018 is primarily due to ~~a decrease in prepaid insurance costs because most~~the movement of the ~~insurance premiums~~accrued liability for our 2016 phantom stock unit awards from noncurrent to current, as these awards are ~~paid~~scheduled to vest 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.~~April 2019. Additionally, the ~~decrease is partially~~accrued liability for these awards increased due to the ~~amortization~~recent increase in our stock price which is the most impactful input for the fair value measurement of ~~mobilization costs for several domestic and Colombian drilling rigs which were mobilized under new contracts in late 2016 and early 2017.~~these awards. For ~~more~~additional information about ~~rig mobilization service revenues and costs,~~these awards, see Note 1,8, ~~Organization and Summary of Significant Accounting Policies~~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.

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

~~Accrued payroll and related employee costs —~~ The increase in accrued payroll and related employee costs during ~~2017~~2018 is ~~primarily due to timing~~partially offset by a decrease in annual incentive compensation associated with the payment 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.~~bonuses which were fully accrued at December 31, 2017 and were paid in the first quarter of 2018.

~~Insurance premiums and deductibles~~ Other accrued expenses— The increase in ~~insurance premiums and deductibles~~other accrued expenses during ~~2017~~2018 is ~~due~~primarily related to ~~increases in our drilling services and production services utilization and the resulting increased workforce. The~~an increase in ~~utilization and~~accrued taxes associated with the increase in revenues for our ~~workforce led to increased actuarial claims estimates for the deductibles under these insurance policies.~~

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

Debt and Other Contractual Obligations — The following table includes information about the amount and timing of our contractual obligations at ~~September~~June 30, ~~2017~~2018 (amounts in thousands):

Payments Due by Period
Contractual Obligations Total Within 1 Year 2 to 3 Years 4 to 5 Years Beyond 5 Years
Debt $ 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	131,672		35,228		70,455		25,989		—
Purchase commitments	11,959		11,959		—		—		—
Operating leases	10,803		3,432		3,568		2,258		1,545
Incentive compensation	27,947		17,544		10,403		—		—
	$	657,381	$	68,163	$	84,426	$	503,247	$	1,545

Debt — Debt obligations at ~~September~~June 30, ~~2017~~2018 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 June 30, 2018, 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~~June 30, ~~2017,~~2018, and (2) the principal balance of $175 million at June 30, 2018, and assuming repayment of the outstanding balance ~~of $97.7 million~~occurs at ~~September 30, 2017 to be paid 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 June 30, 2018, our purchase commitments primarily ~~consist~~pertain to $5.5 million of ~~coiled tubing inventory and equipment,~~ remaining ~~installments on~~obligations for the purchase of two new coiled tubing units (one of which was put into service in early July) and one new wireline ~~units to be delivered~~unit, which are on order for delivery in the ~~first~~second half of ~~2018,~~2018. Other purchase commitments include job supply purchases for our wireline and ~~routine equipment maintenance~~coiled tubing operations and ~~upgrades.~~committed capital expenditures for various refurbishments and upgrades to our drilling rig equipment.

Operating leases — Our operating leases consist of 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.

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 4,5, Debt, and Note ~~10,~~11, Guarantor/Non-Guarantor Condensed Consolidating Financial Statements, of the Notes to Condensed Consolidated Financial Statements, included in Part I, Item 1, Financial Statements, of this Quarterly Report on Form 10-Q.

The ~~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, 2018, the asset coverage ratio, as calculated under the Term Loan, was 2.17 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~~June 30, ~~2017,~~2018, 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~~six months ended ~~September~~June 30, ~~2017,~~2018, we spent ~~$52.8~~$31.5 million on purchases of property and equipment and placed into service property and equipment of ~~$54.2~~$33.9 million. Currently, we expect to spend approximately ~~$60~~$65 million to $70 million on capital expenditures during ~~2017, with approximately half allocated to each of our segments. Our total planned capital expenditures for 2017 include~~2018, which includes approximately $2223 million for ~~domestic~~two large-diameter coiled tubing units, one of which was delivered in early July, three wireline units, two of which were delivered in January, high-pressure pump packages for completion operations, and ~~international~~the construction of the new-build drilling rig ~~upgrades, the exchange of 20 well servicing rigs which was~~expected to be completed in ~~the first quarter of 2017, and the purchase of six wireline units~~2019.

Actual capital expenditures may vary depending on the climate of our industry and any resulting increase or decrease in activity levels, the timing of commitments and payments, and the level of rig build and other expansion opportunities that meet our strategic and return on capital employed criteria. We expect to fund the remaining capital expenditures in ~~2017~~2018 from operating cash flow in excess of our working capital requirements, proceeds from sales of certain non-strategic assets, remaining proceeds from our Term Loan issuance, and from available borrowings under our ~~Revolving Credit~~ABL Facility, if necessary.

Results of Operations

Statements of Operations Analysis

The following table provides certain information about our operations, including a detail of each of our business segments’ revenues, operating costs and gross margin for the three and ~~nine~~six months ended ~~September~~June 30, ~~2017~~2018 and ~~2016~~2017 (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

(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



	Three months ended June 30,						Six months ended June 30,
	2018			2017			2018			2017
Revenues:
Domestic drilling	$	35,634		$	30,473		$	71,560		$	58,818
International drilling	21,773			8,306			39,384			18,977
Drilling services	57,407			38,779			110,944			77,795
Well servicing	23,162			21,017			44,276			39,751
Wireline services	62,137			39,832			118,738			72,378
Coiled tubing services	12,076			7,502			25,302			12,963
Production services	97,375			68,351			188,316			125,092
Consolidated revenues	$	154,782		$	107,130		$	299,260		$	202,887

Operating costs:
Domestic drilling	$	21,749		$	20,380		$	42,647		$	39,889
International drilling	17,064			5,968			30,025			13,566
Drilling services	38,813			26,348			72,672			53,455
Well servicing	16,680			15,091			32,250			29,128
Wireline services	46,716			30,032			89,202			55,978
Coiled tubing services	11,988			7,588			22,839			13,226
Production services	75,384			52,711			144,291			98,332
Consolidated operating costs	$	114,197		$	79,059		$	216,963		$	151,787

Gross margin:
Domestic drilling	$	13,885		$	10,093		$	28,913		$	18,929
International drilling	4,709			2,338			9,359			5,411
Drilling services	18,594			12,431			38,272			24,340
Well servicing	6,482			5,926			12,026			10,623
Wireline services	15,421			9,800			29,536			16,400
Coiled tubing services	88			(86		)	2,463			(263		)
Production services	21,991			15,640			44,025			26,760
Consolidated gross margin	$	40,585		$	28,071		$	82,297		$	51,100

Consolidated:
Net loss	$	(18,152	)	$	(20,209	)	$	(29,291	)	$	(45,333	)
Adjusted EBITDA ⁽¹⁾	$	16,896		$	12,879		$	40,305		$	18,854

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)~~(1) 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.

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 June 30,						Six months ended June 30,
	2018			2017			2018			2017
	(amounts in thousands)
Net loss	$	(18,152	)	$	(20,209	)	$	(29,291	)	$	(45,333	)
Depreciation and amortization	23,287			24,740			47,034			49,732
Impairment	2,368			795			2,368			795
Interest expense	9,642			6,418			19,155			12,477
Income tax expense (benefit)	(249		)	1,135			1,039			1,183
Adjusted EBITDA	16,896			12,879			40,305			18,854
General and administrative	24,829			16,112			44,023			33,856
Bad debt recovery, net of expense	(370		)	(226		)	(422		)	(589		)
Gain on dispositions of property and equipment, net	(726		)	(621		)	(1,061		)	(1,092		)
Other expense (income)	(44		)	(73		)	(548		)	71
Consolidated gross margin	$	40,585		$	28,071		$	82,297		$	51,100

Consolidated gross margin — Both our Production Services and Drilling Services Segments experienced an increase in activity during the three and nine months ended September 30, 2017, as compared to the corresponding periods in 2016, as our industry continues to recover from an industry downturn. Our consolidated gross margin increased ~~84%~~by 45% and ~~41%~~61% for the three and ~~nine~~six months ended ~~September~~June 30, ~~2017,~~2018, respectively, as compared to the corresponding periods in ~~2016.~~2017, as a result of higher demand for all of our drilling and production services segments. Of the $12.5 million and $31.2 million increases in consolidated gross margin for the three and six months ended June 30, 2018, respectively, 51% and 55%, respectively, are attributable to our production services segments, primarily due to improved demand for our wireline services, while the remaining increases are attributable to our drilling services segments, primarily driven by higher domestic dayrates and activity.

DrillingServices— Our ~~Production Services Segment’s~~drilling services revenues increased by ~~$33.8~~$18.6 million, or ~~83%~~48%, and ~~$82.8~~$33.1 million, or ~~71%~~43%, for the three and ~~nine~~six months ended ~~September~~June 30, ~~2017,~~2018, respectively, as compared to the corresponding periods in ~~2016,~~2017, while operating costs increased by ~~$26.4~~$12.5 million, or ~~83%~~47%, and ~~$61.2~~$19.2 million, or ~~64%, respectively.~~36%. The increases in our drilling services revenues and operating costs primarily resulted from a 29% increase in revenue days during both the three and six months ended June 30, 2018, as compared to the corresponding periods in 2017, due to the increasing demand in our industry. The following table provides ~~a detail of revenues~~operating statistics for each ~~production~~of our drilling services ~~business for the~~ segments:~~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



	Three months ended June 30,						Six months ended June 30,
	2018			2017			2018			2017
Domestic drilling:
Average number of drilling rigs	16			16			16			16
Utilization rate	100		%	92		%	100		%	89		%
Revenue days	1,454			1,345			2,894			2,580

Average revenues per day	$	24,508		$	22,657		$	24,727		$	22,798
Average operating costs per day	14,958			15,152			14,736			15,461
Average margin per day	$	9,550		$	7,505		$	9,991		$	7,337

International drilling:
Average number of drilling rigs	8			8			8			8
Utilization rate	85		%	36		%	81		%	40		%
Revenue days	621			262			1,171			582

Average revenues per day	$	35,061		$	31,702		$	33,633		$	32,607
Average operating costs per day	27,478			22,779			25,640			23,309
Average margin per day	$	7,583		$	8,923		$	7,993		$	9,298

Our domestic drilling fleet utilization has been fully utilized since mid-2017, allowing us to achieve the higher margins of a fully utilized fleet. Our domestic drilling average revenues per day for the three and six months ended June 30, 2018 increased as compared to the corresponding periods in 2017, primarily due to increasing drilling dayrates, while

our average operating costs per day decreased, primarily because additional costs were incurred during the first half of 2017 to deploy previously idle rigs under new contracts.

Our international drilling fleet utilization has steadily improved since the beginning of 2017, with seven of eight rigs utilized at June 30, 2018, versus four rigs utilized at the beginning of 2017. Despite the improved utilization in 2018, our average margin per day decreased for the three and six months ended June 30, 2018 as compared to the corresponding periods in 2017, due primarily to additional costs incurred to deploy a previously idle rig during the first quarter of 2018, and the impact of both an increase in the revenue days associated with mobilization activity and rigs on standby during the second quarter of 2018.

Production Services— Our revenues from production services increased by $29.0 million, or 42%, and $63.2 million, or 51%, for the three and six months ended June 30, 2018, respectively, as compared to the corresponding periods in 2017, while operating costs increased by $22.7 million, or 43%, and $46.0 million, or 47%, respectively. The increases in ~~our Production Services Segment’s~~ revenues and operating costs in our production services segments are a result of the increased demand for our services, ~~primarily~~particularly those that perform completion-related activities. The following table provides operating statistics for each of our production services segments:



	Three months ended June 30,						Six months ended June 30,
	2018			2017			2018			2017
Well servicing:
Average number of rigs	125			125			125			125
Utilization rate	49		%	47		%	48		%	45		%
Rig hours	42,871			40,880			83,645			78,589
Average revenue per hour	$	540		$	514		$	529		$	506

Wireline services:
Average number of units	108			114			108			114
Number of jobs	3,022			2,908			5,852			5,762
Average revenue per job	$	20,562		$	13,697		$	20,290		$	12,561

Coiled tubing services:
Average number of units	14			17			14			17
Revenue days	350			400			764			738
Average revenue per day	$	34,503		$	18,755		$	33,118		$	17,565

Increases in production services revenues and operating costs were led by our wireline ~~services. The~~services business segment, which experienced a significant increase in completion-related activity as wells that were drilled but not completed during the downturn created higher demand for completion services as our industry continues to recover. Although the number of wireline jobs we completed increased by ~~31%~~just 4% and ~~46%~~2% for

the three and ~~nine~~six months ended ~~September~~June 30, 2018, as compared to the corresponding periods in 2017, respectively, average revenue per job increased by 50% and 62%, respectively, which is largely due to a higher percentage of the work performed being attributable to completion-related jobs which earn higher revenue rates, but also incur higher costs for the job materials consumed on these types of jobs.

Our coiled tubing services business segment also experienced an increase in demand during 2018, especially for services provided using our larger diameter coiled tubing units. Although revenue days decreased 13% and increased 4% for the three and six months ended June 30, 2018, respectively, as compared to the corresponding periods in ~~2016. The total rig hours for our well servicing fleet~~2017, average revenue per day increased by 1%84% and 5%89%, ~~for~~respectively. The increases in average revenue per day were primarily due to a larger proportion of the ~~three and nine months ended September 30,~~work performed with larger diameter coiled tubing units which typically earn higher revenue rates as compared to smaller diameter coiled tubing units. Additionally, the expansion of our coiled tubing operations into a new market in late 2017 ~~respectively,~~contributed to the improvement in 2018, as compared to the corresponding periods in ~~2016, while pricing for these services increased by 7% and 2%.~~ 2017.

Our ~~coiled tubing~~well servicing business segment experienced a moderate increase in demand. Well servicing utilization increased to ~~29%~~49% and ~~25%~~48% for the three and ~~nine~~six months ended ~~September~~June 30, ~~2017,~~2018, 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%~~47% and 45%, ~~and $31.7 million, or 36%, for the three and nine months ended September 30, 2017,~~ respectively, as compared to the corresponding periods in 2016, while operating costs increased by $8.6 million, or 44%, and $29.9 million, or 57%, respectively. The increases in our Drilling Services Segment’s revenues and operating costs primarily resulted from a 40% increase in revenue days due to the increasing demand in our industry. The increase in our Drilling Services Segment’s operating costs is also primarily a result of the increase in activity, including the increase in revenue days associated with daywork activity during 2017, versus the revenue days associated with rigs that were earning but not working during the corresponding periods in ~~2016, during which time the rigs incur minimal operating costs. The following table provides the percentages of our drilling revenues by contract type for the~~ ~~three~~2017. These utilization improvements represent 5% 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~~6% increases in well servicing rig hours, respectively, while average ~~revenues~~revenue 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~~hour also increased by 12% for the three and nine months ended September 30, 2017, respectively, as compared to the corresponding periods in 2016. Our average revenues per day decreased due to the expiration of term contracts during 2016 that were entered into prior to the downturn at higher revenue rates, many of which were terminated early. The decrease in revenues per day was mostly offset by an increased percentage of our revenues attributable to our Colombian operations, where we typically earn a higher dayrate. Our operating costs per day increased during the nine months ended September 30, 2017, as compared to the corresponding period in 2016, primarily due to a higher percentage of daywork revenues versus revenues earned under contracts that were terminated early, as well as the increased contribution5% from our Colombian operations where our operating costs per day are higher. The increase in operating costs from increased activity was partially offset by the benefits realized from our reduced cost structure, especially in Colombia, which is the primary reason for the decrease in operating costs per day during the three months ended September 30, 2017, as compared to the corresponding period in 2016.both comparative periods.

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

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

Depreciation and amortization expense — Our depreciation and amortization expense decreased by ~~$4.0~~$1.5 million and ~~$13.1~~$2.7 million for the three and ~~nine~~six months ended ~~September~~June 30, ~~2017,~~2018, respectively, as compared to the corresponding periods in ~~2016,~~2017, primarily as a result of reduced capital expenditures during 2016 and 2017, when discretionary upgrades, refurbishments and purchases of new equipment were limited or deferred to preserve capital through 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.downturn.

Impairment ~~charges~~ — During the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2018 and ~~2016,~~2017, we recognized impairment charges of $2.4 million and $0.8 million, ~~and $4.3 million,~~ respectively, ~~primarily~~ to reduce the carrying values of certain assets which were classified as held for sale, to their estimated fair ~~value~~values based on expected ~~sales~~sale prices. For more detail, see Note 3,

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

Interest expense — Our interest expense ~~decreased~~increased by ~~$0.2~~$6.7 million during the ~~nine~~six months ended ~~September~~June 30, ~~2017,~~2018, as compared to the corresponding period in ~~2016,~~2017, primarily due to ~~reduced debt outstanding under~~ the ~~Revolving Credit Facility, for~~issuance of our Term Loan in November 2017, from which a portion of the ~~decrease was mostly offset by the increased interest rate under~~proceeds were used to repay and retire our Revolving Credit ~~Facility which~~Facility. As a result, our total debt outstanding increased, as did the interest rate applicable to outstanding borrowings. Debt outstanding under our Term Loan was ~~amended in~~$175 million during the six months ended June ~~2016. Average~~30, 2018, while the weighted average debt outstanding under our Revolving Credit Facility was approximately ~~$77.4 million and $96.6~~$74 million during the ~~nine~~six months ended ~~September~~June 30, 2017, ~~and 2016, respectively, while the~~with annualized weighted average interest ~~rate on~~rates applicable to these borrowings during these periods ~~was~~of approximately ~~6.5%~~9.6% and ~~5.4%~~5.5%, respectively.

Income tax expense (benefit) — Our effective income tax rate for the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2018 was lower than the federal statutory rate in the United States, primarily due to valuation allowances, ~~as well as the effect of~~ foreign currency translation, state taxes, and other permanent differences. For more detail, see Note 3,4, Valuation Allowances on Deferred Tax Assets and Recently Enacted Tax Reform, of the Notes to Condensed Consolidated Financial Statements, included in Part I, Item 1, Financial Statements, of this Quarterly Report on Form 10-Q.

General and administrative expense — Our general and administrative expense increased by approximately ~~$3.2~~$8.7 million, or ~~22%~~54%, and ~~$5.3~~$10.2 million, or ~~11%~~30%, for the three and ~~nine~~six months ended ~~September~~June 30, ~~2017,~~2018, respectively, as compared to the corresponding periods in ~~2016, due primarily to increased compensation costs.~~2017. The increase ~~in compensation cost~~during both of these periods was primarily due to an increase of $6.6 million during the three months ended June 30, 2018 associated with the increase in fair value of our phantom stock unit awards. In addition, our general and administrative expense increased due to higher compensation costs, including a ~~$4.1~~$1.7 million increase in salary and ~~bonus expense~~related employee benefits during the ~~nine~~six months ended ~~September~~June 30, 2017, partially as a result of increased headcount to accommodate higher activity levels, as well as increased incentive compensation based on improved company performance. In addition, employee benefit costs increased by $0.9 million and stock compensation increased by $0.3 million. These increases in compensation cost were partially offset by a $0.6 million decrease in expense associated with our phantom stock unit awards during the nine months ended September 30, 2017.

~~Gain on dispositions of property and equipment, net —~~ Our net gain of $2.3 million on the disposition of various property and equipment during the nine months ended September 30, 2017 included sales of certain coiled tubing equipment and vehicles, as well as the loss of drill pipe in operation, for which we were reimbursed by the client, and the disposal of two cranes that were damaged, for which we expect to receive insurance proceeds of $0.4 million. Our net gain of $0.4 million on the disposition of property and equipment during the corresponding period in 2016 was primarily for the disposal of excess drill pipe which was mostly offset by a loss on the disposition of damaged drilling equipment.

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

~~Inflation~~

~~When the demand for drilling and production services increases, we may be affected by inflation,~~2018 which primarily ~~impacts:~~

~~wage rates for our operations~~resulted from additional personnel ~~which~~to support the increase ~~when the availability of personnel is scarce;~~

~~equipment repair and maintenance costs;~~

~~costs to upgrade existing equipment; and~~

~~costs to construct new equipment.~~

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

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 ~~September~~ASC Topic 606 discussed below, as of June 30, ~~2017,~~2018, there were no significant changes to our critical accounting policies since the date of our annual report on Form 10-K for the year ended December 31, ~~2016.~~2017.

~~Revenues~~Revenue Recognition— In May 2014, the FASB issued ASU No. 2014-09, a comprehensive new revenue recognition standard that supersedes nearly all pre-existing revenue recognition guidance. The standard, and ~~Cost Recognition~~ ~~— Our Drilling Services Segment earns revenues by drilling oil and gas wells~~its related amendments, collectively referred to as ASC Topic 606, outlines a single comprehensive model for ~~our clients under daywork contracts. We recognize revenues on daywork contracts for the days completed~~revenue recognition 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~~core principle that a company will recognize revenue when promised goods or services are ~~deferred~~transferred to clients, in an amount that reflects the consideration to which an entity expects to be entitled in exchange for those goods or services.

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

The adoption of these standards resulted in a ~~straight line basis over~~cumulative effect adjustment of $0.1 million after applicable income taxes, which consists of the impact of the timing difference related to recognition of mobilization revenues and costs. Mobilization

3336

~~the related contract term. Costs~~costs incurred to relocate rigs and other drilling equipment to areas in which a contract has not been secured are expensed as incurred. Reimbursements that we receive for out-of-pocket expenses are recorded as revenues and the out-of-pocket expenses for which they relate are recorded as operating costs.

With most term drilling contracts, we are entitled to receive a full or reduced rate of revenues from our clients if they choose to place a rig on standby or to early terminate the contract before its original expiration term. Revenues derived from rigs placed on standby or from the early termination of term drilling contracts are deferred and ~~recognized as the amounts become fixed or determinable,~~amortized over the ~~remainder~~expected period of benefit under ASC Subtopic 340-40, but were amortized over the initial contract term under the previous accounting guidance. The recognition of both mobilization revenues and costs begins when mobilization activity is completed under ASC Topic 606, but were recognized during the period of initial mobilization under the previous accounting guidance. Additionally, the opening balances of deferred mobilization costs were reclassified in accordance with ASC Subtopic 340-40, which requires classification of the entire deferred balance according to the duration of the original ~~term or when~~contract to which it relates, rather than bifurcating the ~~rig is sold.~~

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

~~All of our revenues are recognized net of applicable sales taxes.~~noncurrent portions.

~~Long-lived assets —~~For more information about the accounting under ASC Topic 606, and disclosures under the new standard, see Note 2, 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 flowsRevenue from ~~the use and eventual disposition~~Contracts with Customers, 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).Notes to Condensed Consolidated Financial Statements, included in Part I, Item 1, 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.Financial Statements~~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 taxesthis Quarterly Report 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 and our estimate of compensation related ~~accruals and our estimate of sales tax audit liability.~~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 on our almost~~ current market conditions.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 and continued through 2017, we ~~continue~~continued to monitor all indicators of potential impairments in accordance with ASC Topic 360, Property, Plant and Equipment~~. Due to continued performance at levels lower than anticipated~~, and ~~a decline in our projected cash flows for the coiled tubing reporting unit, we performed an~~concluded there are no triggers present that require impairment ~~evaluation of our coiled tubing business~~testing as of June 30, ~~2017 and concluded that no impairment was present.~~

2018. 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 are reasonable and appropriate, different assumptions and estimates could materially impact the analyses and resulting conclusions. If any of our assets become or remain idle for an extended amount of time, then our estimated cash flows may further decrease, and therefore the probability of a near term sale may increase. If any of the foregoing were to occur, we may incur additional impairment charges.

As of ~~September~~June 30, ~~2017,~~2018, we had ~~$157.1~~$95.2 million and $11.8 million of deferred tax assets related to domestic and foreign net operating losses, respectively, that are available to reduce future taxable income. In assessing the realizability of our deferred tax assets, we consider whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. As a result, we have a valuation allowance that fully offsets our foreign ~~deferred tax assets~~ and ~~mostly offsets our~~ domestic federal deferred tax assets as of ~~September~~June 30, ~~2017.~~2018. The valuation allowance is the primary factor causing our effective tax rate to be significantly lower than the statutory ~~rate of 35%.~~rate. For more information, see Note 3,4, Valuation Allowances on Deferred Tax Assets and Recently Enacted Tax Reform, of the Notes to Condensed Consolidated Financial Statements, included in Part I, Item 1, Financial Statements, of this Quarterly Report on Form 10-Q.

Our accrued insurance premiums and deductibles as of ~~September~~June 30, ~~2017~~2018 include accruals for costs incurred under the self-insurance portion of our health insurance of approximately ~~$2.9~~$1.3 million and our workers’ compensation, general liability and auto liability insurance of approximately ~~$4.7~~$4.8 million. We have stop-loss coverage of $200,000 per covered individual per year under our health insurance and a deductible of $500,000 per occurrence under our workers’ compensation insurance. We have a deductible of $250,000 per occurrence under both our general liability insurance and auto liability insurance. We accrue for these costs as claims are incurred using an actuarial calculation that is based on industry and our company’s historical claim development data, and we accrue the costs of administrative services associated with claims processing.

Our compensation expense includes estimates for certain of our long-term incentive compensation plans which have performance-based award components dependent upon our performance over a set performance period, as compared to the performance of a pre-defined peer group. The accruals for these awards include estimates which affect our compensation expense, employee related accruals and equity. The accruals are adjusted based on actual achievement levels at the end of the pre-determined performance periods. Additionally, our phantom stock unit awards are classified as liability awards under ASC Topic 718, Compensation—Stock Compensation, because we expect to settle the awards in cash when they vest, and are remeasured at fair value at the end of each reporting period until they vest. The change in fair value is recognized as a current period compensation expense in our ~~statement~~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 7,8, Stock-Based Compensation Plans, of the Notes to Condensed Consolidated Financial Statements, included in Part I, Item 1, Financial Statements, of this Quarterly Report on Form 10-Q.

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

~~For more information, see Note 9,~~ ~~Commitments and Contingencies, of the Notes to Condensed Consolidated Financial Statements, included in Part I, Item 1,~~ ~~Financial Statements, of this Quarterly Report on Form 10-Q.~~

Recently Issued Accounting Standards

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

Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements.


ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Interest Rate Risk — We are subject to interest rate market risk on our variable rate debt. As of ~~September~~June 30, ~~2017~~2018, ~~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~~0.9 million during the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2018. This potential increase or decrease is based on the simplified assumption that the level of variable rate debt remains constant with an immediate across-the-board interest rate increase or decrease as of January 1, ~~2017~~2018.

Foreign Currency Risk — While the U.S. dollar is the functional currency for reporting purposes for our Colombian operations, we enter into transactions denominated in Colombian ~~pesos.~~Pesos. Nonmonetary assets and liabilities are translated at historical rates and monetary assets and liabilities are translated at exchange rates in effect at the end of the period. Income statement accounts are translated at average rates for the period. As a result, Colombian Peso denominated transactions are affected by changes in exchange rates. We generally accept the exposure to exchange rate movements without using derivative financial instruments to manage this risk. Therefore, both positive and negative movements in the Colombian Peso currency exchange rate against the U.S. dollar have and will continue to affect the reported amount of revenues, expenses, profit, and assets and liabilities in our consolidated financial statements. The impact of currency rate changes on our Colombian Peso denominated transactions and balances resulted in net foreign currency gains of ~~$0.2~~$0.1 million for the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2018.


ITEM 4.	CONTROLS AND PROCEDURES

In accordance with Exchange Act Rules 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of ~~September~~June 30, ~~2017~~2018, to ensure that information required to be disclosed in our reports filed or submitted under the Exchange Act is (1) recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms and (2) accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

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

internal control environment. There has been no change in our internal control over financial reporting that occurred during the three months ended ~~September~~June 30, ~~2017~~2018 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II - OTHER INFORMATION


ITEM 1.	LEGAL PROCEEDINGS

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


ITEM 1A.	RISK FACTORS

Not applicable.


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

We did not make any unregistered sales of equity securities during the quarter ended ~~September~~June 30, ~~2017. We did not~~2018. The following table provides information relating to our repurchase ~~any~~of common shares during the quarter ended ~~September~~June 30, ~~2017.~~2018:



Period	Total Number of Shares Purchased (1)	Average Price Paid per Share (2)		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs
April 1 - April 30	130,241	$	3.45	—	—
May 1 - May 31	730	$	6.00	—	—
June 1 - June 30	—	$	—	—	—
Total	130,971	$	3.46	—	—


(1)	The shares indicated consist of shares of our common stock tendered by employees to the Company during the three months ended June 30, 2018, to satisfy the employees’ tax withholding obligations in connection with the vesting of share-based compensation awards, which we repurchased based on the fair market value on the date the relevant transaction occurred.


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


ITEM 3.	DEFAULTS UPON SENIOR SECURITIES

Not applicable.


ITEM 4.	MINE SAFETY DISCLOSURES

Not applicable.


ITEM 5.	OTHER INFORMATION

~~(a)~~ We are providing the following disclosure in lieu of providing this information in a Current Report on Form 8-K.

Item 1.01 - Entry into a Material Definitive Agreement.

On ~~November 2, 2017,~~July 26, 2018, in connection with a periodic review of its existing indemnification agreements, the Board of Directors (the “Board”) of Pioneer Energy Services Corp. (the “Company”) approved a new form of indemnification agreement (“Indemnification Agreement”) to be entered into by and between the Company ~~issued a press release announcing (i) advanced discussions regarding a new $175 million senior secured term loan (the “Term Loan”)~~ and ~~(ii)~~each of its ~~receipt of a commitment letter for a $75 million senior secured revolving asset-based lending facility.~~

~~The closing~~directors 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”executive officers (each, an “Indemnitee”), 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~~enter into an Indemnification Agreement with each current member of the ~~definitive Term Loan Credit~~Board and each current executive officer of the Company.

The Indemnification Agreement ~~and ABL Credit Facility promptly after they become effective.~~

~~ABL Credit Facility~~

~~The ABL Credit Facility is expected to provide for borrowings~~supplements indemnification provisions already in the ~~aggregate principal amount~~Company’s Restated Articles 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.~~Incorporation and Amended and Restated Bylaws and supersedes any prior indemnification agreements entered into between the Company and its current directors or executive officers.

3740

~~Availability under~~In general, the ~~ABL Credit Facility is expected~~Indemnification Agreement provides that, subject to the procedures, limitations and exceptions set forth therein, the Company will indemnify the Indemnitee to the fullest extent permitted by the Texas Business Organizations Code against all damages, judgments, fines, penalties, settlements and other costs and expenses (including, without limitation, reasonable attorneys’ fees) actually paid or reasonably incurred by the Indemnitee in any threatened or pending proceeding by reason of or arising in part out of (i) the Indemnitee serving as a director, officer, partner, venturer, proprietor, trustee, fiduciary, managing member, employee, agent or similar functionary of the Company or (ii) the Indemnitee serving as a director, officer, partner, venturer, proprietor, trustee, fiduciary, managing member, employee, agent or similar functionary of any other corporation, limited liability company, limited or general partnership, joint venture, sole proprietorship, trust or other enterprise at the request of the Company.

Under the terms of the Indemnification Agreement, the Indemnitee also generally has the right to have the Company advance all expenses actually paid or reasonably incurred by the Indemnitee in any proceeding to the fullest extent permitted by the Texas Business Organizations Code prior to the final disposition of such proceeding.

The above description of the Indemnification Agreement does not purport to be ~~determined~~complete and is qualified in its entirety 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~~full text of the ~~closing date, (ii) 90 days prior to the scheduled maturity date under the Term Loan~~Indemnification Agreement filed herewith as Exhibit 10.1 and ~~(iii) 90 days prior to the maturity of the Senior Unsecured Notes issued~~incorporated herein 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.reference.


ITEM 6.	EXHIBITS

See the Index to Exhibits immediately following the signatures page.

3841

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~~July 31, 2018

3942

Index to Exhibits

The following documents are exhibits to this Form 10-Q:



Exhibit Number		Description

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

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

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

4.2*	-	Indenture, dated March 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+**		Pioneer Energy Services Corp. Form of Indemnification Agreement.

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

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

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

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

101**	-	The following financial statements from Pioneer Energy Services Corp.’s Form 10-Q for the quarter ended ~~September~~June 30, ~~2017,~~2018, formatted in XBRL (eXtensible Business Reporting Language): (i) Condensed Consolidated Balance Sheets, (ii) Condensed Consolidated Statements of Operations, (iii) Condensed Consolidated Statements of Cash Flows, and (iv) Notes to Condensed Consolidated Financial Statements.

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

4043



	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



	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