Quarterly Report (10-q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

______________________________________________

FORM 10-Q

______________________________________________

(Mark one)



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

For the quarterly period ended September 30, 2016



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

Commission File Number: 1-8182

PIONEER ENERGY SERVICES CORP.

(Exact name of registrant as specified in its charter)

_____________________________________________



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

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

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

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

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting 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.)

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 14, 2016 , there were 65,071,906 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, 2016			December 31, 2015
	(unaudited)			(audited)
	(in thousands, except share data)
ASSETS
Current assets:
Cash and cash equivalents	$	9,703		$	14,160
Receivables:
Trade, net of allowance for doubtful accounts	38,185			47,577
Unbilled receivables	3,968			13,624
Insurance recoveries	17,298			14,556
Other receivables	2,761			4,059
Inventory	8,254			9,262
Assets held for sale	6,243			4,619
Prepaid expenses and other current assets	4,730			7,411
Total current assets	91,142			115,268
Property and equipment, at cost	1,111,500			1,146,994
Less accumulated depreciation	482,336			444,409
Net property and equipment	629,164			702,585
Intangible assets, net of accumulated amortization of $13.1 million and $12.3 million at September 30, 2016 and December 31, 2015, respectively	781			1,944
Other long-term assets	1,710			2,196
Total assets	$	722,797		$	821,993

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	13,014		$	16,951
Deferred revenues	1,157			6,222
Accrued expenses:
Payroll and related employee costs	13,981			13,859
Insurance premiums and deductibles	6,437			8,087
Insurance claims and settlements	13,952			14,556
Interest	900			5,508
Other	5,568			4,859
Total current liabilities	55,009			70,042
Long-term debt, less debt issuance costs	399,508			387,217
Deferred income taxes	13,439			17,520
Other long-term liabilities	3,737			4,571
Total liabilities	471,693			479,350
Commitments and contingencies (Note 9)
Shareholders’ equity:
Preferred stock, 10,000,000 shares authorized; none issued and outstanding	—			—
Common stock $.10 par value; 100,000,000 shares authorized; 65,071,906 and 64,497,915 shares outstanding at September 30, 2016 and December 31, 2015, respectively	6,559			6,496
Additional paid-in capital	476,655			475,823
Treasury stock, at cost; 515,546 and 458,170 shares at September 30, 2016 and December 31, 2015, respectively	(3,883		)	(3,759		)
Accumulated deficit	(228,227		)	(135,917		)
Total shareholders’ equity	251,104			342,643
Total liabilities and shareholders’ equity	$	722,797		$	821,993

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,
	2016			2015			2016			2015
	(in thousands, except per share data)
Revenues:
Drilling services	$	27,454		$	41,238		$	88,597		$	198,212
Production services	40,899			66,242			116,998			238,093
Total revenues	68,353			107,480			205,595			436,305

Costs and expenses:
Drilling services	19,776			23,003			51,989			118,114
Production services	31,912			48,643			95,503			170,517
Depreciation and amortization	28,663			35,257			87,409			115,528
General and administrative	14,312			16,686			46,078			56,909
Bad debt expense (recoveries)	(359		)	(1,071		)	(302		)	(358		)
Impairment charges	4,262			2,329			4,262			79,648
Loss (gain) on dispositions of property and equipment, net	(328		)	605			(420		)	(2,639		)
Total costs and expenses	98,238			125,452			284,519			537,719
Loss from operations	(29,885		)	(17,972		)	(78,924		)	(101,414		)

Other (expense) income:
Interest expense, net of interest capitalized	(6,678		)	(4,975		)	(19,307		)	(15,675		)
Loss on extinguishment of debt	—			(490		)	(299		)	(490		)
Other	245			(785		)	574			(2,979		)
Total other expense	(6,433		)	(6,250		)	(19,032		)	(19,144		)

Loss before income taxes	(36,318		)	(24,222		)	(97,956		)	(120,558		)
Income tax benefit	1,698			6,682			5,646			13,718
Net loss	$	(34,620	)	$	(17,540	)	$	(92,310	)	$	(106,840	)

Loss per common share—Basic	$	(0.53	)	$	(0.27	)	$	(1.43	)	$	(1.66	)

Loss per common share—Diluted	$	(0.53	)	$	(0.27	)	$	(1.43	)	$	(1.66	)

Weighted average number of shares outstanding—Basic	64,905			64,449			64,755			64,262

Weighted average number of shares outstanding—Diluted	64,905			64,449			64,755			64,262

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,
	2016			2015
	(in thousands)
Cash flows from operating activities:
Net loss	$	(92,310	)	$	(106,840	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation and amortization	87,409			115,528
Allowance for doubtful accounts, net of recoveries	(302		)	(358		)
Write-off of obsolete inventory	21			—
Gain on dispositions of property and equipment, net	(420		)	(2,639		)
Stock-based compensation expense	2,998			2,275
Amortization of debt issuance costs	1,311			1,247
Loss on extinguishment of debt	299			490
Impairment charges	4,262			79,648
Deferred income taxes	(6,372		)	(15,048		)
Change in other long-term assets	426			438
Change in other long-term liabilities	(833		)	(509		)
Changes in current assets and liabilities:
Receivables	20,910			113,686
Inventory	855			1,533
Prepaid expenses and other current assets	2,726			3,233
Accounts payable	(2,425		)	(29,547		)
Deferred revenues	(4,353		)	11,457
Accrued expenses	(6,558		)	(35,529		)
Net cash provided by operating activities	7,644			139,065

Cash flows from investing activities:
Purchases of property and equipment	(25,584		)	(130,390		)
Proceeds from sale of property and equipment	2,743			37,803
Proceeds from insurance recoveries	—			227
Net cash used in investing activities	(22,841		)	(92,360		)

Cash flows from financing activities:
Debt repayments	(500		)	(45,003		)
Proceeds from issuance of debt	12,000			—
Debt issuance costs	(819		)	(999		)
Proceeds from exercise of options	183			781
Purchase of treasury stock	(124		)	(729		)
Net cash provided by (used in) financing activities	10,740			(45,950		)

Net increase (decrease) in cash and cash equivalents	(4,457		)	755
Beginning cash and cash equivalents	14,160			34,924
Ending cash and cash equivalents	$	9,703		$	35,679

Supplementary disclosure:
Interest paid	$	22,849		$	21,543
Income tax paid	$	653		$	2,659
Noncash investing and financing activity:
Change in capital expenditure accruals	$	(1,592	)	$	308

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

As of September 30, 2016, our drilling rig fleet consists of 31 rigs, 94% of which are pad-capable, and 15 of which are AC walking rigs built within the last five years and engineered to optimize pad drilling. In addition to our drilling rigs, we provide the drilling crews and most of the ancillary equipment needed to operate our drilling rigs. The drilling rigs in our fleet are currently assigned to the following divisions:



Drilling Division	Rig Count
South Texas	6
West Texas	8
North Dakota	3
Appalachia	6
Colombia	8
	31

Our Production Services Segment provides a range of services to a diverse group of exploration and production companies, with our operations concentrated in the major United States onshore oil and gas producing regions in the Mid-Continent and Rocky Mountain states and in the Gulf Coast, both onshore and offshore. As of September 30, 2016 , our production services fleets are as follows:



Production Services Fleets
	550 HP	600 HP	Total
Well servicing rigs, by horsepower (HP) rating	114	11	125

	Offshore	Onshore	Total
Wireline units	6	108	114
Coiled tubing units	5	12	17

Drilling Contracts

We obtain our contracts for drilling oil and natural gas wells either through competitive bidding or through direct negotiations with existing or potential clients. Our drilling contracts generally provide for compensation on either a daywork or turnkey basis. Contract terms generally depend on the complexity and risk of operations, the on-site drilling conditions, the type of equipment used, and the anticipated duration of the work to be performed. Spot market contracts generally provide for the drilling of a single well and typically permit the client to terminate on short notice. We enter into longer-term drilling contracts for our newly constructed rigs and/or during periods of high rig demand.

With most term drilling contracts, we are entitled to receive a full or reduced rate of revenue from our clients if they choose to place a rig on standby or to early terminate the contract before its original expiration term. Generally, these revenues are billed and collected over the remaining term of the contract, as the rig is often placed on standby rather than fully released from the contract, and thus may go back to work at the client’s decision any time before the end of the contract. Some of our drilling contracts contain “make-whole” provisions whereby if we are able to secure additional work for the rig with another client, then each party is entitled to a make-whole payment. If the dayrates under the new contract are less than the dayrates in the original contract, we would be entitled to a reduced revenue dayrate from the terminating client, and likewise, the terminating client may be entitled to a payment from us if the new contract dayrates exceed those of the original contract. A client may also choose to early terminate the contract and make an upfront early termination payment based on a per day rate for the remaining term of the contract.

Revenues derived from rigs placed on standby or from the early termination of term drilling contracts are deferred and recognized as the amounts become fixed or determinable, over the remainder of the original term or when the rig is sold. As a result of the downturn that began in late 2014, term contracts for 19 of our drilling rigs were terminated early, including three that were terminated in early 2016 . As of September 30, 2016 , all of these contracts’ terms have expired and all the associated revenue from the early terminations has been recognized .

As of September 30, 2016 , 13 of our 23 domestic drilling rigs are earning revenues, eight of which are under term contracts . Of the eight rigs in Colombia, three are under term contracts, two of which have been put on standby by our client and are not earning revenue. The term contracts in Colombia are cancelable by our client without penalty if 30 days’ notice is provided, and by us if rig operations are suspended without an associated dayrate. 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.

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 (“GAAP”) 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 fiscal year ended December 31, 2015 .

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 recognition of revenues and costs for turnkey contracts, our estimate of the allowance for doubtful accounts, our determination of depreciation and amortization expenses, our estimates of projected cash flows and fair values for impairment evaluations, our estimate of the valuation allowance for deferred tax assets, our estimate of the liability relating to the self-insurance portion of our health and workers’ compensation insurance, our estimate of compensation related accruals and our estimate of sales tax audit liability.

In preparing the accompanying unaudited condensed consolidated financial statements, we have reviewed events that have occurred after September 30, 2016 , through the filing of this Form 10-Q , for inclusion as necessary.

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 invoiced. We typically invoice our clients at 15-day intervals during the performance of daywork drilling contracts and upon completion of the daywork contract. Turnkey drilling contracts are invoiced upon completion of the contract.

Our unbilled receivables totaled $4.0 million at September 30, 2016 , of which $3.2 million represented revenue recognized but not yet billed on daywork drilling contracts in progress and $0.8 million related to unbilled receivables for our Production Services Segment . At December 31, 2015 , our unbilled receivables totaled $13.6 million , of which $11.9 million represented revenue recognized but not yet billed on daywork drilling contracts in progress , $1.1 million related to unbilled receivables for our Production Services Segment , and $0.6 million related to related to turnkey drilling contract revenues .

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 and the long-term portion of deferred mobilization costs.

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, the long-term portion of deferred revenues and deferred lease liabilities.

Related-Party Transactions

During the nine months ended September 30, 2016 and 2015 , the Company paid approximately $0.1 million , during each of the respective periods, 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

Revenue Recognition. In May 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (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 are required to apply this new standard beginning with our first quarterly filing in 2018. We are currently evaluating the potential impact of this guidance, but at this time, do not expect that the adoption of this new standard will have a material effect on our financial position or results of operations. We expect the adoption of this new standard to primarily affect our accounting for revenue derived from long-term drilling contracts.

Debt Issuance Costs. On April 7, 2015, the FASB issued ASU No. 2015-03, Simplifying the Presentation of Debt Issuance Costs, which requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts, and that amortization of debt issuance costs be reported as interest expense. In August 2015, these provisions were further amended with guidance from the Securities and Exchange Commission Staff that they would not object to an entity deferring and presenting debt issuance costs related to line-of-credit arrangements as an asset and subsequently amortizing the deferred debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. The recognition and measurement guidance for debt issuance costs are not affected by the amendments in this ASU. This ASU requires retrospective adoption and was effective for us beginning with our first quarterly filing in 2016. The adoption of this new standard resulted in reclassifying $7.8 million of debt issuance costs from other long-term assets to long-term debt in the accompanying December 31, 2015 condensed consolidated balance sheet.

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 with our first quarterly filing in 2019. We are currently evaluating the potential impact of this guidance and have not yet determined its impact on our financial position and results of operations.

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. This ASU is effective for us beginning with our first quarterly filing in 2017. We do not expect that the adoption of this update will have a material effect on our financial position or results of operations.

Credit Losses. In June 2016, the FASB issued ASU No. 2016-13, Measurement of Credit Losses on Financial Instruments , which sets forth an impairment model requiring the measurement of all expected credit losses for financial instruments (including trade receivables) held at the reporting date based on historical experience, current conditions, and reasonable supportable forecasts. This ASU is effective for us beginning with our first quarterly filing in 2020. We do not expect the adoption of this guidance to have a material impact on our financial position or results of operations.

Statement of Cash Flows . In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows , which clarifies how companies present and classify certain cash receipts and cash payments in the statement of cash flows. The update is intended to reduce the existing diversity in practice, and is effective for us beginning with our first quarterly filing in 2018. We do not expect the adoption of this guidance to have a material impact on our financial position and results of operations.

Reclassifications

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

2 . Property and Equipment

Our capital expenditures were $24.0 million and $130.7 million , during the nine months ended September 30, 2016 and 2015 , respectively, which includes $0.2 million and $2.5 million , respectively, of capitalized interest costs incurred during the construction periods of new drilling rigs and other drilling equipment. As of September 30, 2016 and December 31, 2015 , capital expenditures incurred for property and equipment not yet placed in service was $5.6 million and $18.6 million , respectively, primarily related to new drilling equipment that was ordered in 2014, but which requires a long lead-time for delivery . This equipment will either be used to construct new drilling rigs or as spare equipment for our AC rig fleet. Capital expenditures during 2015 primarily related to our five drilling rigs which began construction during 2014, as well as unit additions to our production services fleets.

We recorded net gains during the nine months ended September 30, 2016 of $0.4 million on the disposition of property and equipment, primarily for the disposal of excess drill pipe for a gain, which were mostly offset by a loss on the disposition of damaged property. During the second quarter of 2016, one of our AC drilling rigs sustained damages, primarily to the mast and top drive, that resulted in a disposal of the damaged components with an aggregate net carrying value of $4.0 million , for which we filed an insurance claim and expect the insurance proceeds will be approximately $3.1 million , resulting in an estimated net loss on disposal of $0.9 million . This net loss on disposal partially offset the net gains recognized during the nine months ended September 30, 2016 on other property dispositions. During the nine months ended September 30, 2015 , we recorded net gains of $2.6 million on the disposition of property and equipment, primarily for the sale of 28 of our mechanical and lower horsepower electric drilling rigs and other drilling equipment which we sold for aggregate proceeds of $36.3 million .

As of September 30, 2016 , our condensed consolidated balance sheet reflects assets held for sale of $6.2 million , which primarily represents the fair value of four domestic mechanical and lower horsepower electric drilling rigs, other drilling equipment, 13 wireline units and certain coiled tubing equipment .

The following table summarizes impairment charges recognized during the three and nine months ended September 30, 2016 and 2015 (amounts in thousands):



	Three months ended September 30,				Nine months ended September 30,
	2016		2015		2016		2015
Assets held for sale	$	3,344	$	2,329	$	3,344	$	9,858
Colombian assets	—		—		—		60,130
Domestic drilling rigs and equipment	918		—		918		9,660
	$	4,262	$	2,329	$	4,262	$	79,648

During the 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 is on hand for the construction of drilling rigs, which we no longer believe is likely to be used.

During the three and nine months ended September 30, 2015 , we recorded impairment charges of $2.3 million and $9.9 million , respectively, to reduce the carrying value of certain assets which were classified as held for sale, to their estimated fair values, based on expected sales prices . Additionally, based on our impairment analysis performed at June 30, 2015, we concluded that the carrying values of the non-AC drilling rigs in our domestic fleet which are not pad-capable, and our Colombian assets as a group, exceeded our estimated undiscounted cash flows for these assets and recognized $69.8 million of impairment charges to reduce the carrying values of these assets to their estimated fair values.

We evaluate for potential impairment of long-lived tangible and intangible assets subject to amortization when indicators of impairment are present. Circumstances that could indicate a potential impairment include significant adverse changes in industry trends, economic climate, legal factors, and an adverse action or assessment by a regulator. More specifically, significant adverse changes in industry trends include significant declines in revenue rates, utilization rates, oil and natural gas market prices and industry rig counts. Since late 2014, oil prices have declined significantly resulting in a downturn in our industry, affecting both drilling and production services. Despite the modest recovery in commodity prices in recent months, we continue to monitor all indicators of potential impairments in accordance with ASC Topic 360, Property, Plant and Equipment.

In performing an impairment evaluation, we estimate the future undiscounted net cash flows from the use and eventual disposition of long-lived tangible and intangible assets grouped at the lowest level that cash flows can be identified. For our Production Services Segment, we perform an impairment evaluation and estimate future undiscounted cash flows for the individual reporting units (well servicing, wireline and coiled tubing). For our Drilling Services Segment, we perform an impairment evaluation and estimate future undiscounted cash flows for individual domestic drilling rig assets and for our Colombian drilling rig assets as a group. If the sum of the estimated future undiscounted net cash flows is less than the carrying amount of the asset group, then we determine the fair value of the asset group. The amount of an impairment charge is measured as the difference between the carrying amount and the fair value of the assets. The assumptions used in the impairment evaluation for long-lived assets are inherently uncertain and require management judgment.

Due to lower than anticipated operating results in 2016 and a decline in our projected cash flows for the coiled tubing reporting unit, we performed an impairment analysis of our coiled tubing long-lived assets which indicated that our projected net undiscounted cash flows associated with the coiled tubing reporting unit were in excess of the net carrying value of the assets, and thus no impairment was present at September 30, 2016 . The most significant inputs used in our impairment analysis of our coiled tubing operations include the projected utilization and pricing of our coiled tubing services, which are classified as Level 3 inputs as defined by ASC Topic 820, Fair Value Measurements and Disclosures .

Although we believe the assumptions and estimates used in our analysis are reasonable and appropriate, different assumptions and estimates could materially impact the analysis and resulting conclusions. If the demand for our drilling services remains at current levels or declines further and any of our rigs become or remain idle for an extended amount of time, then our estimated cash flows may further decrease, and the probability of a near term sale may increase. If any of the foregoing were to occur, we may incur additional impairment charges.


3 .	Valuation Allowances on Deferred Tax Assets

In performing this analysis as of September 30, 2016 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 objective negative evidence evaluated is the projected cumulative loss incurred over the three-year period ending December 31, 2016. Such objective negative evidence limits the ability to consider other subjective positive evidence, such as projections for taxable income in future years. Due to the continued downturn in our industry, we expect to be in a net deferred tax asset position by the end of 2016, and as a result, we may recognize a benefit only to the extent that reversals of deferred income tax liabilities are expected to generate income tax expense in each relevant jurisdiction in future periods which would offset our deferred tax assets.

Our domestic net operating losses have a 20 year carryforward period and can be used to offset future domestic taxable income until their expiration, beginning in 2030 , with the latest expiration in 2033 . However, we determined that a valuation allowance should be recorded against some of the benefit expected to be generated in 2016. The valuation allowance has been factored into the estimated annual tax rate to be applied throughout 2016, and is the primary factor causing our effective tax rate to be significantly lower than the statutory rate of 35% . The amount of the deferred tax asset considered realizable, however, could be adjusted if estimates of future taxable income are reduced or increased or if objective negative evidence in the form of cumulative losses is no longer present and additional weight is given to subjective evidence such as projected future taxable income.

The majority of our foreign net operating losses have an indefinite carryforward period. However, as a result of the conditions leading to the impairment of our assets in Colombia during 2015 and the continued industry downturn, we have a valuation allowance that fully offsets our $21.3 million of foreign deferred tax assets at September 30, 2016 .

4 . Debt

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



	September 30, 2016			December 31, 2015
Senior secured revolving credit facility	$	106,500		$	95,000
Senior notes	300,000			300,000
	406,500			395,000
Less unamortized debt issuance costs	(6,992		)	(7,783		)
	$	399,508		$	387,217

Senior Secured Revolving Credit Facility

We have a credit agreement, as most recently amended on June 30, 2016 , with Wells Fargo Bank, N.A. and a syndicate of lenders which provides for a senior secured revolving credit facility, with sub-limits for letters of credit and swing-line loans, of up to an aggregate commitment amount of $175 million , with further reductions to $150 million not later than December 31, 2017 , 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”). The Revolving Credit Facility contains customary mandatory prepayments from the proceeds of certain asset dispositions or equity or debt issuances, which are applied to reduce outstanding revolving and swing-line loans and to cash-collateralize letter of credit exposure, and in certain cases, also reduce the commitment amount available .

Borrowings under the Revolving Credit Facility bear interest, at our option, at the LIBOR rate or at the bank prime rate, plus an applicable per annum margin of 5.50% and 4.50% , respectively. The Revolving Credit Facility requires a commitment fee due quarterly based on the average daily unused amount of the commitments of the lenders, a fronting fee due for each letter of credit issued, and a quarterly letter of credit fee due based on the average undrawn amount of letters of credit outstanding during such period. Additionally, the Revolving Credit Facility requires that if on the last business day of each week, our aggregate amount of cash (as calculated pursuant to the Revolving Credit Facility) exceeds $20 million , we pay down the outstanding principal balance by the amount of such excess.

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

As of October 15, 2016 , we had $111.5 million outstanding under our Revolving Credit Facility and $17.3 million in committed letters of credit, which resulted in borrowing availability of $46.2 million under our Revolving Credit Facility. There are no limitations on our ability to access the borrowing capacity provided there is no default, all representations and warranties are true and correct, and compliance with financial covenants under the Revolving Credit Facility is maintained. At September 30, 2016 , we were in compliance with our financial covenants under the Revolving Credit Facility.

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


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



w	4.50	to 1.00	on	September 30, 2016
w	5.00	to 1.00	on	September 30, 2017
w	4.00	to 1.00	on	December 31, 2017
w	3.50	to 1.00	on	March 31, 2018
w	3.25	to 1.00	on	June 30, 2018
w	2.50	to 1.00	at any time after June 30, 2018


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



w	1.15	to 1.00	for the quarterly period ending	September 30, 2016
w	1.00	to 1.00	for the quarterly period ending	September 30, 2017
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


•	A minimum EBITDA requirement, for the periods indicated, as defined in the Revolving Credit Facility. EBITDA required at the end of forthcoming fiscal quarters cannot be less than the minimum amounts as follows:



w	$4 million	for the two-fiscal quarter period ending December 31, 2016
w	$7 million	for the three-fiscal quarter period ending March 31, 2017
w	$12 million		for the four-fiscal quarter period ending June 30, 2017

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



w	$35 million	in fiscal year 2016
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 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.

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


•	incur additional debt or make prepayments of existing debt;


•	create liens on or dispose of our assets;


•	pay dividends on stock or repurchase stock;


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


•	make other restricted investments; and


•	conduct transactions with affiliates.

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 with a coupon interest rate of 6.125% that are due in 2022 (the “Senior Notes”) . The Senior Notes were sold at 100% of their face value. After deductions were made for the $6.1 million for underwriters’ fees and other debt offering costs, we received $293.9 million of net proceeds. In order to reduce our overall interest expense and lengthen the overall maturity of our senior indebtedness, during 2014, we redeemed all of our then outstanding $425 million of unregistered senior notes with a coupon interest rate of 9.875% that were issued in 2010 and 2011 and were set to mature in 2018 , funded primarily by proceeds from the issuance of Senior Notes in 2014 and additional borrowings under our Revolving Credit Facility, as well as some cash on hand.

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. Prior to March 15, 2017 , we may also redeem the Senior Notes, in whole or in part, at a “make-whole” redemption price specified in the Indenture, plus any accrued and unpaid interest and any additional interest thereon to the date of redemption. In addition, prior to March 15, 2017 , we may, on one or more occasions, redeem up to 35% of the aggregate principal amount of the Senior Notes at a redemption price equal to 106.125% of the principal amount thereof, plus accrued and unpaid interest and additional interest, if any, to the redemption date, with the net cash proceeds of certain equity offerings, provided that at least 65% of the aggregate principal amount of the Senior Notes remains outstanding after the occurrence of such redemption and that the redemption occurs within 120 days of the date of the closing of such equity offering.

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

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

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


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


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


•	create liens on our or their assets ;


•	enter into sale and leaseback transactions;


•	sell or transfer assets;


•	pay dividends, engage in loans, or transfer other assets from certain of our subsidiaries;


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


•	enter into transactions with affiliates; and


•	enter into new lines of business .

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

Debt Issuance Costs

Costs incurred in connection with the Revolving Credit Facility were capitalized and are being amortized using the straight-line method over the term of the Revolving Credit Facility which matures in March 2019 . Costs incurred in connection with the issuance of our Senior Notes were capitalized and are being amortized using the straight-line method (which approximates amortization using the interest method) over the term of the Senior Notes which mature in March 2022 . We recognized $1.3 million and $1.2 million of associated amortization during the nine months ended September 30, 2016 and 2015 , respectively. Additionally, during the nine months ended September 30, 2016 and 2015 , we recognized $0.3 million and $0.5 million , respectively, of loss on extinguishment of debt for the write off of unamortized debt issuance costs associated with the reduction of borrowing capacity under our Revolving Credit Facility.


5 .	Fair Value of Financial Instruments

The FASB’s Accounting Standards Codification (ASC) Topic 820, Fair Value Measurements and Disclosures , defines fair value and provides a hierarchal framework associated with the level of subjectivity used in measuring assets and liabilities at fair value.

At September 30, 2016 and December 31, 2015 , our financial instruments consist primarily of cash, trade and other receivables, trade payables and long-term debt. The carrying value of cash, trade and other receivables, and trade payables are considered to be representative of their respective fair values due to the short-term nature of these instruments.

The fair value of our long-term debt is estimated using a discounted cash flow analysis, based on rates that we believe we would currently pay for similar types of debt instruments. This discounted cash flow analysis is based on inputs defined by ASC Topic 820 as level 2 inputs, which are observable inputs for similar types of debt instruments. The following table presents the supplemental fair value information about long-term debt at September 30, 2016 and December 31, 2015 (amounts in thousands):



	September 30, 2016				December 31, 2015
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Total debt	$	399,508	$	305,411	$	387,217	$	242,354


6 .	Earnings 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,
	2016			2015			2016			2015
Numerator (both basic and diluted):
Net loss	$	(34,620	)	$	(17,540	)	$	(92,310	)	$	(106,840	)

Denominator:
Weighted-average shares (denominator for basic earnings per share)	64,905			64,449			64,755			64,262
Diluted effect of outstanding stock options, restricted stock and restricted stock unit awards	—			—			—			—

Denominator for diluted earnings per share	64,905			64,449			64,755			64,262

Loss per common share—Basic	$	(0.53	)	$	(0.27	)	$	(1.43	)	$	(1.66	)

Loss per common share—Diluted	$	(0.53	)	$	(0.27	)	$	(1.43	)	$	(1.66	)

Potentially dilutive securities excluded as anti-dilutive	4,550			5,273			4,985			4,862


7 .	Equity Transactions and Stock-Based Compensation Plans

Equity Transactions

On May 15, 2015 , we filed a registration statement that permits us to sell equity or debt in one or more offerings up to a total dollar amount of $300 million . As of September 30, 2016 , 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 Facility and Senior Notes. We may consider equity and/or debt offerings, as appropriate, to meet our liquidity needs.

Stock-based Compensation Plans

We grant stock option and restricted stock awards with vesting based on time of service conditions. We grant restricted stock unit awards with vesting based on time of service conditions, and in certain cases, subject to performance and market conditions. In 2016, we granted phantom stock unit awards with vesting based on time of service, performance and market conditions, which were 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 stock option, restricted stock, restricted stock unit, and phantom stock unit awards based on the fair value estimated in accordance with ASC Topic 718. For our awards with graded vesting, we recognize compensation expense on a straight-line basis over the service period for each separately vesting portion of the award as if the award was, in substance, multiple awards.

The following table summarizes the stock-based compensation expense recognized for stock option, restricted stock and restricted stock unit awards, and the compensation expense recognized for phantom stock unit awards during the three and nine months ended September 30, 2016 and 2015 (amounts in thousands):



	Three months ended September 30,				Nine months ended September 30,
	2016		2015		2016		2015
Stock option awards	$	192	$	240	$	573	$	717
Restricted stock awards	116		88		306		311
Restricted stock unit awards	625		707		2,119		1,247
	$	933	$	1,035	$	2,998	$	2,275

Phantom stock unit awards	$	307	$	—	$	1,033	$	—

Stock Options

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

We estimate the fair value of each option grant on the date of grant using a Black-Scholes option pricing model. There were no stock options granted during the three months ended September 30, 2016 or 2015 . The following table summarizes the assumptions used in the Black-Scholes option pricing model based on a weighted-average calculation for the options granted during the nine months ended September 30, 2016 and 2015 :



	Nine months ended September 30,
	2016		2015
Expected volatility	70	%	64	%
Risk-free interest rates	1.5	%	1.4	%
Expected life in years	5.70		5.52
Options granted	905,966		341,638
Grant-date fair value	$0.80		$2.31

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.

There were no stock options exercised during the three months ended September 30, 2016 . During the nine months ended September 30, 2016 , 46,804 stock options were exercised at a weighted-average exercise price of $3.92 . During the three and nine months ended September 30, 2015 , 7,200 and 203,300 stock options, respectively, were exercised at a weighted-average exercise price of $3.84 for both periods. We receive a tax deduction for certain stock option exercises during the period the options are exercised, generally for the excess of the fair market value of our stock on

the date of exercise over the exercise price of the options. In accordance with ASC Topic 718, when we have excess tax benefits resulting from the exercise of stock options, we report them as financing cash flows in our condensed consolidated statement of cash flows, unless otherwise disallowed under ASC Topic 740, Income Taxes .

Restricted Stock

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. During the nine months ended September 30, 2016 and 2015 , we granted 166,664 and 47,296 shares of restricted stock awards with a weighted-average grant-date fair value of $2.76 and $7.40 , respectively.

Restricted Stock Units

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 unit awards granted during the nine months ended September 30, 2016 and 2015 :



	Nine months ended September 30,
	2016		2015
Time-based RSUs:
Time-based RSUs granted	260,334		151,919
Weighted-average grant-date fair value	$	1.48	$	4.08

Performance-based RSUs:
Performance-based RSUs granted	—		531,522
Weighted-average grant-date fair value	$	—	$	6.18

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 granted during 2014 and 2015 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 estimated 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 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 2016 , we determined that 72% of the target number of shares granted during 2013 were actually earned based on the Company’s achievement of certain performance measures, as compared to the predefined peer group, over the three-year performance period which ended December 31, 2015 . The performance-based RSUs granted during 2013 vested and were converted to common stock at the end of April 2016 . As of September 30, 2016 , we estimated that our actual achievement level for the performance-based RSUs granted during 2014 and 2015 will be approximately 90% and 100% of the predetermined performance conditions, respectively.

Phantom Stock Unit Awards

In 2016, we granted 1,268,068 phantom stock unit awards that cliff-vest after 39 months from the date of grant, with vesting based on time of service, performance and market conditions. The number of units ultimately awarded will be based upon the Company’s achievement in certain performance conditions, as compared to a predefined peer group, over the three -year performance period, and each unit awarded will entitle the employee to a cash payment equal to the stock price of our common stock on the date of vesting, subject to a maximum of four times the stock price on the date of grant.

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 each reporting period until they vest. Approximately half of the phantom stock unit awards granted are subject to a market condition based on relative total shareholder return, as compared to that of our predetermined peer group, and therefore the fair value of these awards is measured using a Monte Carlo simulation model. The remaining phantom stock unit awards are subject to performance conditions, based on our EBITDA and 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.


8 .	Segment Information

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

Our Drilling Services Segment provides contract land drilling services to a diverse group of exploration and production companies through our four drilling divisions in the US, and internationally in Colombia. In addition to our drilling rigs, we provide the drilling crews and most of the ancillary equipment needed to operate our drilling rigs.

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

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, 2016 and 2015 (amounts in thousands):



	As of and for the three months ended September 30,				As of and for the nine months ended September 30,
	2016		2015		2016		2015
Drilling Services Segment:
Revenues	$	27,454	$	41,238	$	88,597	$	198,212
Operating costs	19,776		23,003		51,989		118,114
Segment margin	$	7,678	$	18,235	$	36,608	$	80,098

Identifiable assets	$	463,621	$	571,203	$	463,621	$	571,203
Depreciation and amortization	15,511		17,648		46,597		62,063
Capital expenditures	7,785		30,757		15,330		106,447

Production Services Segment:
Revenues	$	40,899	$	66,242	$	116,998	$	238,093
Operating costs	31,912		48,643		95,503		170,517
Segment margin	$	8,987	$	17,599	$	21,495	$	67,576

Identifiable assets	$	246,610	$	335,206	$	246,610	$	335,206
Depreciation and amortization	12,849		17,284		39,851		52,445
Capital expenditures	2,070		4,633		8,312		23,786

Corporate:
Identifiable assets	$	12,566	$	42,719	$	12,566	$	42,719
Depreciation and amortization	303		325		961		1,020
Capital expenditures	175		148		350		465

The following table reconciles the consolidated margin of our two operating segments and corporate reported above to income from operations as reported on the consolidated statements of operations for the three and nine months ended September 30, 2016 and 2015 (amounts in thousands):



	Three months ended September 30,						Nine months ended September 30,
	2016			2015			2016			2015
Consolidated margin	$	16,665		$	35,834		$	58,103		$	147,674
Depreciation and amortization	(28,663		)	(35,257		)	(87,409		)	(115,528		)
General and administrative	(14,312		)	(16,686		)	(46,078		)	(56,909		)
Bad debt recoveries (expense)	359			1,071			302			358
Impairment charges	(4,262		)	(2,329		)	(4,262		)	(79,648		)
Gain (loss) on dispositions of property and equipment, net	328			(605		)	420			2,639
Loss from operations	$	(29,885	)	$	(17,972	)	$	(78,924	)	$	(101,414	)

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, 2016 and 2015 (amounts in thousands):



	As of and for the three months ended September 30,				As of and for the nine months ended September 30,
	2016		2015		2016		2015
Revenues	$	622	$	2,670	$	1,979	$	36,709
Identifiable assets	37,444		57,777		37,444		57,777

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


9 .	Commitments and Contingencies

In connection with our operations in Colombia, our foreign subsidiaries have obtained bonds for bidding on drilling contracts, performing under drilling contracts, and remitting customs and importation duties. We have guaranteed payments of $36.3 million relating to our performance under these bonds as of September 30, 2016 .

We have received an increased number of notices in recent years from state taxing authorities for audits of sales and use tax obligations. 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, 2016 and December 31, 2015 , our accrued liability was $1.5 million and $0.6 million , respectively, based on our estimate of the sales and use tax obligations that are expected to result from these audits . Due to the inherent uncertainty of the audit process, we believe that it is reasonably possible that we may incur additional tax assessments with respect to one or more of the audits in excess of the amount accrued. We believe that such an outcome would not have a material adverse effect on our results of operations or financial position. Because certain of these audits are in a preliminary stage, an estimate of the possible loss or range of loss from an adverse result in all or substantially all of these cases cannot reasonably be made.

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


10 .	Guarantor/Non-Guarantor Condensed Consolidated Financial Statements

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

In the event of a bankruptcy, liquidation or reorganization of any non-guarantor subsidiary, such non-guarantor subsidiary will pay the holders of its debt and other liabilities, including its trade creditors, before it will be able to distribute any of its assets to us. In the future, any non-U.S. subsidiaries, immaterial subsidiaries and subsidiaries that we designate as unrestricted subsidiaries under the Indenture will not guarantee the Senior Notes. As of September 30, 2016 , 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 consolidated balance sheets, statements of operations and statements of cash flows of the issuer, the guarantor subsidiaries and the non-guarantor subsidiaries.

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited, in thousands)



	September 30, 2016
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	8,099		$	(1,022	)	$	2,626		$	—		$	9,703
Receivables, net of allowance	360			59,404			2,448			—			62,212
Intercompany receivable (payable)	(24,836		)	31,627			(6,791		)	—			—
Inventory	—			4,749			3,505			—			8,254
Assets held for sale	—			6,243			—			—			6,243
Prepaid expenses and other current assets	1,245			2,177			1,308			—			4,730
Total current assets	(15,132		)	103,178			3,096			—			91,142
Net property and equipment	2,700			599,473			26,991			—			629,164
Investment in subsidiaries	581,866			28,362			—			(610,228		)	—
Intangible assets, net of accumulated amortization	—			781			—			—			781
Other long-term assets	87,347			704			489			(86,830		)	1,710
Total assets	$	656,781		$	732,498		$	30,576		$	(697,058	)	$	722,797
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	379		$	12,201		$	434		$	—		$	13,014
Deferred revenues	—			706			451			—			1,157
Accrued expenses	4,407			35,297			1,134			—			40,838
Total current liabilities	4,786			48,204			2,019			—			55,009
Long-term debt, less debt issuance costs	399,508			—			—			—			399,508
Deferred income taxes	—			100,269			—			(86,830		)	13,439
Other long-term liabilities	1,383			2,159			195			—			3,737
Total liabilities	405,677			150,632			2,214			(86,830		)	471,693
Total shareholders’ equity	251,104			581,866			28,362			(610,228		)	251,104
Total liabilities and shareholders’ equity	$	656,781		$	732,498		$	30,576		$	(697,058	)	$	722,797

	December 31, 2015
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	17,221		$	(5,612	)	$	2,551		$	—		$	14,160
Receivables, net of allowance	74			67,174			12,568			—			79,816
Intercompany receivable (payable)	(24,836		)	31,108			(6,272		)	—			—
Inventory	—			5,591			3,671			—			9,262
Assets held for sale	—			4,619			—			—			4,619
Prepaid expenses and other current assets	1,200			4,767			1,444			—			7,411
Total current assets	(6,341		)	107,647			13,962			—			115,268
Net property and equipment	3,311			667,321			31,953			—			702,585
Investment in subsidiaries	657,090			42,240			—			(699,330		)	—
Intangible assets, net of accumulated amortization	—			1,944			—			—			1,944
Other long-term assets	85,501			962			722			(84,989		)	2,196
Total assets	$	739,561		$	820,114		$	46,637		$	(784,319	)	$	821,993
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	616		$	14,628		$	1,707		$	—		$	16,951
Deferred revenues	—			5,570			652			—			6,222
Accrued expenses	8,373			37,023			1,473			—			46,869
Total current liabilities	8,989			57,221			3,832			—			70,042
Long-term debt, less debt issuance costs	387,217			—			—			—			387,217
Deferred income taxes	—			102,509			—			(84,989		)	17,520
Other long-term liabilities	712			3,294			565			—			4,571
Total liabilities	396,918			163,024			4,397			(84,989		)	479,350
Total shareholders’ equity	342,643			657,090			42,240			(699,330		)	342,643
Total liabilities and shareholders’ equity	$	739,561		$	820,114		$	46,637		$	(784,319	)	$	821,993

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited, in thousands)



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



	Three months ended September 30, 2015
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Revenues	$	—		$	104,810		$	2,670		$	—		$	107,480
Costs and expenses:
Operating costs	—			67,682			3,964			—			71,646
Depreciation and amortization	325			32,797			2,135			—			35,257
General and administrative	4,864			11,543			417			(138		)	16,686
Intercompany leasing	—			(1,215		)	1,215			—			—
Bad debt expense	—			(1,071		)	—			—			(1,071		)
Impairment charges	—			2,329			—			—			2,329
Loss (gain) on dispositions of property and equipment, net	128			651			(174		)	—			605
Total costs and expenses	5,317			112,716			7,557			(138		)	125,452
Income (loss) from operations	(5,317		)	(7,906		)	(4,887		)	138			(17,972		)
Other income (expense):
Equity in earnings of subsidiaries	(11,208		)	(6,309		)	—			17,517			—
Interest expense	(4,983		)	2			6			—			(4,975		)
Loss on extinguishment of debt	(490		)	—			—			—			(490		)
Other	(21		)	472			(1,098		)	(138		)	(785		)
Total other income (expense)	(16,702		)	(5,835		)	(1,092		)	17,379			(6,250		)
Income (loss) before income taxes	(22,019		)	(13,741		)	(5,979		)	17,517			(24,222		)
Income tax (expense) benefit ¹	4,479			2,533			(330		)	—			6,682
Net income (loss)	$	(17,540	)	$	(11,208	)	$	(6,309	)	$	17,517		$	(17,540	)

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited, in thousands)



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


	Nine months ended September 30, 2015
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Revenues	$	—		$	399,596		$	36,709		$	—		$	436,305
Costs and expenses:
Operating costs	—			258,125			30,506			—			288,631
Depreciation and amortization	1,020			104,841			9,667			—			115,528
General and administrative	15,624			39,916			1,783			(414		)	56,909
Intercompany leasing	—			(3,645		)	3,645			—			—
Bad debt expense	—			(358		)	—			—			(358		)
Impairment charges	—			23,766			56,632			(750		)	79,648
Gain on dispositions of property and equipment, net	128			(2,572		)	(195		)	—			(2,639		)
Total costs and expenses	16,772			420,073			102,038			(1,164		)	537,719
Income (loss) from operations	(16,772		)	(20,477		)	(65,329		)	1,164			(101,414		)
Other income (expense):
Equity in earnings of subsidiaries	(87,179		)	(73,472		)	—			160,651			—
Interest expense	(15,573		)	(120		)	18			—			(15,675		)
Loss on extinguishment of debt	(490		)	—			—			—			(490		)
Other	(14		)	1,343			(3,894		)	(414		)	(2,979		)
Total other income (expense)	(103,256		)	(72,249		)	(3,876		)	160,237			(19,144		)
Income (loss) before income taxes	(120,028		)	(92,726		)	(69,205		)	161,401			(120,558		)
Income tax (expense) benefit ¹	12,438			5,547			(4,267		)	—			13,718
Net income (loss)	$	(107,590	)	$	(87,179	)	$	(73,472	)	$	161,401		$	(106,840	)

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

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited, in thousands)



	Nine months ended September 30, 2016
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			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

	Nine months ended September 30, 2015
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidated
Cash flows from operating activities	$	7,109		$	114,977		$	16,979		$	139,065
Cash flows from investing activities:
Purchases of property and equipment	(437		)	(128,363		)	(1,590		)	(130,390		)
Proceeds from sale of property and equipment	22			37,557			224			37,803
Proceeds from insurance recoveries	—			227			—			227
	(415		)	(90,579		)	(1,366		)	(92,360		)
Cash flows from financing activities:
Debt repayments	(45,000		)	(3		)	—			(45,003		)
Debt issuance costs	(999		)	—			—			(999		)
Proceeds from exercise of options	781			—			—			781
Purchase of treasury stock	(729		)	—			—			(729		)
Intercompany contributions/distributions	37,914			(17,109		)	(20,805		)	—
	(8,033		)	(17,112		)	(20,805		)	(45,950		)
Net increase (decrease) in cash and cash equivalents	(1,339		)	7,286			(5,192		)	755
Beginning cash and cash equivalents	27,688			(5,516		)	12,752			34,924
Ending cash and cash equivalents	$	26,349		$	1,770		$	7,560		$	35,679


Item 2 .	Management’s Discussion and Analysis of Financial Condition and Results of Operations

Statements we make in the following discussion that express a belief, expectation or intention, as well as those that are not historical fact, are forward-looking statements that are subject to risks, uncertainties and assumptions. Our actual results, performance or achievements, or industry results, 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 our senior secured revolving credit facility and our senior notes, operating hazards inherent in our operations, the supply of marketable drilling rigs, well servicing rigs, coiled tubing and wireline units within the industry, the continued availability of drilling rig, well servicing rig, coiled tubing and wireline unit components, the continued availability of qualified personnel, the success or failure of our acquisition strategy, including our ability to finance acquisitions, manage growth and effectively integrate acquisitions, the political, economic, regulatory and other uncertainties encountered by our operations, and changes in, or our failure or inability to comply with, governmental regulations, including those relating to the environment. We have discussed many of these factors in more detail elsewhere in this report and in our Annual Report on Form 10-K for the year ended December 31, 2015 , including under the headings “Special Note Regarding Forward-Looking Statements” in the Introductory Note to Part I and “Risk Factors” in Item 1A . These factors are not necessarily all the important factors that could affect us. Other unpredictable or unknown factors could also have material adverse effects on actual results of matters that are the subject of our forward-looking statements. All forward-looking statements speak only as of the date on which they are made and we undertake no obligation to publicly update or revise any forward-looking statements whether as a result of new information, future events or otherwise. We advise our shareholders that they should (1) recognize that important factors not referred to above could affect the accuracy of our forward-looking statements and (2) use caution and common sense when considering our forward-looking statements.

Company Overview

Pioneer Energy Services Corp. provides land-based drilling services and production services to a diverse group of independent and large oil and gas exploration and production companies in the United States and internationally in Colombia. We also provide two of our services (coiled tubing and wireline services) offshore in the Gulf of Mexico. Drilling services and production services are fundamental to establishing and maintaining the flow of oil and natural gas throughout the productive life of a well and enable us to meet multiple needs of our clients.

•

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

As of September 30, 2016, our drilling rig fleet consists of 31 rigs, 94% of which are pad-capable, and 15 of which are AC walking rigs built within the last five years and engineered to optimize pad drilling. The removal of older, less capable rigs from our fleet and the recent investments in the construction of new drilling rigs has transformed our fleet into a highly capable, pad optimal fleet focused on the horizontal drilling market. We believe this positions us to compete well, grow our presence in the significant shale basins in the US, and improve profitability upon recovery of our industry.

In addition to our drilling rigs, we provide the drilling crews and most of the ancillary equipment needed to operate our drilling rigs. We obtain our contracts for drilling oil and natural gas wells either through competitive bidding or through direct negotiations with existing or potential clients. Our drilling contracts generally provide for compensation on either a daywork or turnkey basis. Contract terms generally depend on the complexity and risk of operations, the on-site drilling conditions, the type of equipment used, and the anticipated duration of the work to be performed. The drilling rigs in our fleet are currently assigned to the following divisions:



Drilling Division		Rig Count
South Texas		6
West Texas		8
North Dakota		3
Appalachia		6
Colombia		8
		31

•

Production Services Segment— In 2008, we acquired two production services companies which significantly expanded our service offerings to include well servicing and wireline services. We also acquired a coiled tubing services business at the end of 2011 to further expand our production services offerings. Since the acquisitions of these businesses, we continued to invest in their organic growth and significantly expanded all our production services fleets. However, we have suspended organic growth of our production services fleets during the current downturn.

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

•

Well Servicing. A range of services are required in order to establish production in newly-drilled wells and to maintain production over the useful lives of active wells. We use our well servicing rig fleet to provide these necessary services, including the completion of newly-drilled wells, maintenance and workover of active wells, and plugging and abandonment of wells at the end of their useful lives. As of September 30, 2016 , we have a fleet of 114 rigs with 550 horsepower and 11 rigs with 600 horsepower with operations in 10 locations, mostly in the Gulf Coast states, as well as in Arkansas and North Dakota.


•	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, 2016 , we have a fleet of 114 wireline units in 17 operating locations in the Gulf Coast, Mid-Continent and Rocky Mountain states.

•

Coiled Tubing Services. Coiled tubing is also an important element of the well servicing industry that allows operators to continue production during service operations without shutting in the well, thereby reducing the risk of formation damage. Coiled tubing services involve the use of a continuous metal pipe spooled on a large reel for oil and natural gas well applications, such as wellbore clean-outs, nitrogen jet lifts, through-tubing fishing, formation stimulation utilizing acid, chemical treatments and fracturing. Coiled tubing is also used for a number of horizontal well applications such as milling temporary plugs between frac stages. As of September 30, 2016 , our coiled tubing business consists of 12 onshore and five offshore coiled tubing units which are deployed through two locations in Texas and Louisiana.

Pioneer Energy Services Corp. (formerly called “Pioneer Drilling Company”) 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 our business through acquisitions and organic growth. We conduct our operations through two operating segments: our Drilling Services Segment and our Production Services Segment. Financial information about our operating segments is included in Note 8 , Segment Information , of the Notes to Condensed Consolidated Financial Statements, included in Part I, Item 1 , Financial Statements , of this Quarterly Report on Form 10-Q .

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

Market Conditions in Our Industry

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

Our business is influenced substantially by both operating and capital expenditures by exploration and production companies. Exploration and production spending is generally categorized as either a capital expenditure or an operating expenditure. Capital expenditures by exploration and production companies for the drilling of exploratory wells or new 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 by exploration and production companies 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 exploratory drilling first in response to a shift in commodity prices, the demand for drilling services is generally impacted first and to a greater extent than the demand for production services which is more dependent on ongoing expenditures that are necessary to maintain production. Additionally, within the range of production services businesses, those that derive more revenue from production related activity, as opposed to maintenance, 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.

For additional information concerning the effects of the volatility in oil and gas prices and the effects of technological advancements and trends in our industry, see Item 1A – “Risk Factors” in Part I of our Annual Report on Form 10-K for the year ended December 31, 2015 .

Market Conditions — Since late 2014, oil prices have declined significantly resulting in a downturn in our industry, affecting both drilling and production services. 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:

At the end of 2015, the spot prices of WTI crude oil and Henry Hub natural gas were down by 66% and 74% , respectively, as compared to the peak 2014 prices. During this same period, the horizontal and vertical drilling rig counts in the United States dropped by 61% and 78% , respectively, while the domestic well servicing rig count decreased by 38% . Despite the modest recovery in commodity prices during recent months, commodity prices have remained low as compared to the price levels in 2014 and continue to depress activity and pricing for all our service offerings.

Our well servicing and coiled tubing utilization rates for the quarter ended September 30, 2016 were 41% and 22% , respectively, based on total fleet count, and we are currently actively marketing approximately 55% of our wireline fleet. These utilization rates are roughly flat with those of the most recently completed fiscal quarter, due to recent stability in commodity prices, and the number of wireline jobs completed during the quarter ended September 30, 2016 increased by 14% , as compared to the most recently completed fiscal quarter.

In drilling, all rig classes were severely impacted by the industry downturn. As a result, term contracts for 19 of our drilling rigs were terminated early, including three that were terminated in early 2016 . However, with the moderate improvement in commodity prices in recent months, several of our AC rigs have been subsequently placed on new spot contracts and as of September 30, 2016 , 13 of our 23 domestic drilling rigs are earning revenues, eight of which are under term contracts . This represents a current utilization of 81% of our AC rig fleet. Of the eight rigs in Colombia, three are under term contracts, two of which have been put on standby by our client and are not earning revenue. 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.

Including the contracts in Colombia that are on standby, 16 of our drilling rigs are currently under contract, which if not canceled or renewed prior to the end of their terms, will expire as follows:



	Spot Market Contracts		Term Contract Expiration by Period
	Spot Market Contracts	Total Term Contracts	Within 6 Months	6 Months to 1 Year	1 Year to 18 Months	18 Months to 2 Years	2 to 4 Years
Domestic Rigs:
Earning under contract	5	8	1	2	2	2	1
Colombia Rigs:
Earning under contract	—	1	—	1	—	—	—
On Standby (not earning)	—	2	—	1	—	1	—
	5	11	1	4	2	3	1

Our clients significantly reduced both their operating and capital expenditures during 2015, with further reductions to their spending budgets for 2016. If oil and natural gas prices again decline, then industry equipment utilization and revenue rates would likely decrease further. Although we expect continued pricing pressure, low activity levels and a highly competitive environment for the remainder of 2016, we expect the recent modest recovery in commodity prices, if it continues, to modestly increase industry activity levels and we believe our high-quality equipment and services are well positioned to compete.

Strategy

In past years, our strategy was to become a premier land drilling and production services company through steady and disciplined growth. We executed this strategy by acquiring and building a high quality drilling rig fleet and production services business. We provide drilling and production services in many of the most attractive drilling markets throughout the United States, and provide drilling services in Colombia.

With the decline in oil prices and the reductions in our utilization and revenue rates over the last eighteen months, our near-term efforts are focused on:

•

Cost Reductions. Since the beginning of 2015 , we have reduced our total headcount by approximately 61% , reduced wage rates for our operations personnel, reduced incentive compensation, eliminated certain employment benefits and closed a total of ten field offices to reduce overhead and reduce associated lease payments. We continue to evaluate opportunities to lower our cost structure in response to reduced revenues.

•

Liquidating Nonstrategic Assets. We sold 32 drilling rigs and other drilling equipment during 2015 for aggregate net proceeds of $53.6 million . As of September 30, 2016 , we have four additional domestic mechanical and lower horsepower electric drilling rigs held for sale, along with other drilling equipment, 13 wireline units and certain coiled tubing equipment . We will continue to evaluate our domestic and international fleets for additional drilling rigs or equipment for which a near term sale would be favorable.

•

Maintaining Liquidity and Financial Flexibility. We most recently amended our revolving credit facility on June 30, 2016, to maintain access to capital but with more flexible financial covenants. Since the beginning of 2015, we have paid down $43.5 million of debt, as of October 15, 2016 . We also have availability for equity or debt offerings up to $300 million under our shelf registration statement, subject to the limitations imposed by our Revolving Credit Facility and Senior Notes.

•

Performance of our Core Businesses. We will continue to focus on maintaining our relationships with our clients and vendors through the downturn, and continue to focus on our service quality and safety. We remain committed to our safety and service quality goals, and our 2015 total recordable incident rate is the lowest we have achieved since our company’s inception . With the expectation of a modest recovery , we are allocating our resources to the markets with the best opportunities for increased activity.

We will continue to evaluate our business and look for opportunities to further achieve these goals, which we believe will position us to take advantage of future business opportunities and continue our long-term growth strategy.

Our long-term strategy is to maintain and leverage our position as a leading land drilling and production services company, continue to expand our relationships with existing clients, expand our client base in the areas where we currently operate and further enhance our geographic diversification through selective expansion. The key elements of this long-term strategy are focused on our:


•	Investments in the Growth of our Business. We have historically invested in the growth of our business by strategically upgrading our existing assets and disposing of assets which use older technology, and engaging in select rig building opportunities and acquisitions.

Since the beginning of 2010, we have added significant capacity to our production services offerings through the addition of 40 wireline units, 51 well servicing rigs and 17 coiled tubing units. We constructed ten AC drilling rigs from 2011 to 2013 and we completed construction of five new 1,500 horsepower AC drilling rigs during 2015 . We sold 32 of our mechanical and lower horsepower electric drilling rigs during 2015, which were the most negatively impacted by the industry downturn, and placed an additional 4 rigs as held for sale.

As of September 30, 2016, our drilling rig fleet consists of 31 rigs, 94% of which are pad-capable, and 15 of which are AC walking rigs built within the last five years and engineered to optimize pad drilling. The removal of older, less capable rigs from our fleet and the recent investments in the construction of new drilling rigs has transformed our fleet into a highly capable, pad optimal fleet focused on the horizontal drilling market. We believe this positions us to compete well, grow our presence in the significant shale basins in the US, and improve profitability upon recovery of our industry.

•

Competitive Position in the Prominent Domestic Markets. Shale plays and non-shale oil or liquid rich environments are increasingly important to domestic hydrocarbon production, and not all drilling rigs are capable of successfully drilling in these unconventional opportunities. The 15 drilling rigs which we constructed in the last five years are well suited for our operations in the Marcellus/Utica and Eagle Ford shales, the Permian Basin and the Bakken. Additionally, we have added significant capacity to our production services fleets, with a focus on increasing our presence in those regions where demand benefits from shale development.

•

Exposure to Oil and Liquids Rich Natural Gas Drilling Activity. We believe that our flexible drilling and production services fleets allow us to pursue varied opportunities, enabling us to focus on a favorable mix of natural gas, oil and liquids rich natural gas activity. When natural gas prices fell to low levels, we increased our exposure to oil-related activities by redeploying certain of our assets into predominately oil-producing regions. As our industry recovers from the downturn that began in late 2014, we believe our fleets are highly capable and well positioned for deployment to whichever markets offer the most opportunity.

Liquidity and Capital Resources

Sources of Capital Resources

Our principal liquidity requirements have been for working capital needs, debt service, capital expenditures and selective acquisitions. Our principal sources of liquidity consist of cash and cash equivalents (which equaled $9.7 million as of September 30, 2016 ), cash generated from operations , proceeds from sales of certain non-strategic assets and the unused portion of our senior secured revolving credit facility (the “Revolving Credit Facility”).

In 2014 , we issued $300 million of unregistered senior notes with a coupon interest rate of 6.125% that are due in 2022 (the “Senior Notes”) . In order to reduce our overall interest expense and lengthen the overall maturity of our senior indebtedness, during 2014, we redeemed all of our then outstanding $425 million of unregistered senior notes with a coupon interest rate of 9.875% that were issued in 2010 and 2011 and were set to mature in 2018 , funded primarily by proceeds from the issuance of Senior Notes in 2014 and additional borrowings under our Revolving Credit Facility, as well as some cash on hand.

Our Revolving Credit Facility, as most recently amended on June 30, 2016 , provides for a senior secured revolving credit facility, with sub-limits for letters of credit and swing-line loans, of up to an aggregate commitment amount of $175 million , with further reductions to $150 million not later than December 31, 2017 , 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 . As of October 15, 2016 , we had $111.5 million outstanding under our Revolving Credit Facility and $17.3 million in committed letters of credit, which resulted in borrowing availability of $46.2 million under our Revolving Credit Facility. Borrowings under the Revolving Credit Facility are available for selective acquisitions, working capital and other general corporate purposes. There are no limitations on our ability to access the borrowing capacity provided there is no default, all representations and warranties are true and correct, and compliance with financial covenants under the Revolving Credit Facility is maintained. Additional information regarding these covenants is provided in the Debt Requirements section below.

At September 30, 2016 , we were in compliance with our financial covenants under the Revolving Credit Facility. However, 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. If we expect our future operating results to decline to a level that indicates we may become unable to comply with the financial covenants in the Revolving Credit Facility, we may seek to amend such provisions to remain in compliance or we may pursue other capital sources, such as other debt or equity 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 currently expect that cash and cash equivalents, cash generated from operations , proceeds from sales of certain non-strategic assets and available borrowings under our Revolving Credit Facility are adequate to cover our liquidity requirements for at least the next 12 months.

Uses of Capital Resources

During the nine months ended September 30, 2016 , we spent $25.6 million on purchases of property and equipment and placed into service property and equipment of $24.0 million . Currently, we expect to spend approximately $30 million to $32 million on capital expenditures during 2016 . We expect the total capital expenditures for 2016 will be allocated approximately 60% for our Drilling Services Segment and approximately 40% for our Production Services Segment. Our total planned capital expenditures for 2016 are limited to primarily routine capital expenditures, the remaining payments for the new drilling rigs which we deployed in late 2015 and certain drilling equipment that was ordered in 2014 but requires a long lead time for delivery.

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 2016 from operating cash flow in excess of our working capital requirements , proceeds from sales of certain non-strategic assets and from borrowings under our Revolving Credit Facility, if necessary.

Working Capital

Our working capital was $36.1 million at September 30, 2016 , compared to $45.2 million at December 31, 2015 . Our current ratio, which we calculate by dividing current assets by current liabilities, was 1.7 at September 30, 2016 , compared to 1.6 at December 31, 2015 .

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, during periods of expansion in our production services business, or when higher percentages of our drilling contracts are turnkey contracts, at which times we are more likely to access capital through debt or equity financing. During periods of sustained low activity and pricing, we may access additional capital through the use of available funds under our Revolving Credit Facility.

The changes in the components of our working capital were as follows (amounts in thousands):



	September 30, 2016		December 31, 2015		Change
Cash and cash equivalents	$	9,703	$	14,160	$	(4,457	)
Receivables:
Trade, net of allowance for doubtful accounts	38,185		47,577		(9,392		)
Unbilled receivables	3,968		13,624		(9,656		)
Insurance recoveries	17,298		14,556		2,742
Other receivables	2,761		4,059		(1,298		)
Inventory	8,254		9,262		(1,008		)
Assets held for sale	6,243		4,619		1,624
Prepaid expenses and other current assets	4,730		7,411		(2,681		)
Current assets	91,142		115,268		(24,126		)
Accounts payable	13,014		16,951		(3,937		)
Deferred revenues	1,157		6,222		(5,065		)
Accrued expenses:
Payroll and related employee costs	13,981		13,859		122
Insurance premiums and deductibles	6,437		8,087		(1,650		)
Insurance claims and settlements	13,952		14,556		(604		)
Interest	900		5,508		(4,608		)
Other	5,568		4,859		709
Current liabilities	55,009		70,042		(15,033		)
Working capital	$	36,133	$	45,226	$	(9,093	)

The decrease in cash and cash equivalents during the nine months ended September 30, 2016 is primarily due to $25.6 million of cash used for purchases of property and equipment , partially offset by $12.0 million of proceeds from issuance of debt, $7.6 million of cash provided by operating activities, which includes early termination payments received on certain drilling contracts, and $2.7 million of proceeds from the sale of assets .

The net decrease in our total trade and unbilled receivables as of September 30, 2016 as compared to December 31, 2015 is primarily the result of the decrease in consolidated revenues of $36.1 million , or 35% , for the quarter ended September 30, 2016 as compared to the quarter ended December 31, 2015 . Our trade receivables generally turn over within 90 days.

The increase in our insurance recoveries receivables as of September 30, 2016 as compared to December 31, 2015 is primarily due to an insurance claim receivable of $3.1 million for a drilling rig that was damaged during the second quarter of 2016.

The decrease in other receivables as of September 30, 2016 as compared to December 31, 2015 is primarily due to a decrease in net income tax receivables for our Colombian operations and a decrease in receivables for vendor purchase rebates due to a decline in activity.

The decrease in inventory as of September 30, 2016 as compared to December 31, 2015 is primarily due to a decline in activity for our wireline operations.

The decrease in prepaid expenses and other current assets as of September 30, 2016 as compared to December 31, 2015 is primarily due to a decrease in prepaid insurance costs because most of the insurance premiums are paid in late

October of each year, and therefore we had amortization of eleven months of these October premiums at September 30, 2016 , as compared to two months at December 31, 2015 .

The decrease in accounts payable as of September 30, 2016 as compared to December 31, 2015 is primarily due to the 26% decrease in our operating costs for the quarter ended September 30, 2016 as compared to the quarter ended December 31, 2015 . Our accounts payable generally turn over within 90 days.

The decrease in deferred revenues as of September 30, 2016 as compared to December 31, 2015 is primarily related to deferred revenue for early termination payments. Revenues derived from rigs placed on standby or from the early termination of term drilling contracts are deferred and recognized as the amounts become fixed or determinable, over the remainder of the original term or when the rig is sold. See Critical Accounting Policies and Estimates section for more detail. All of the contracts that were early terminated have expired as of September 30, 2016 and all the associated revenue from the early terminations has been recognized . Deferred revenues as of September 30, 2016 relate to payments received for the mobilization of our drilling rigs which are deferred and recognized on a straight line basis over the related contract term.

The increase in accrued payroll and related employee costs as of September 30, 2016 as compared to December 31, 2015 is primarily due to the timing of pay periods and associated withholding and unemployment tax payments, as well as a $0.4 million increase in our accruals for annual bonuses, primarily due to better projected performance under this plan during 2016, as compared to 2015. The overall increase is partially offset by reduced benefit accruals and reductions in long-term incentive compensation due to reduced headcount.

The decrease in insurance premiums and deductibles as of September 30, 2016 as compared to December 31, 2015 is primarily due to a decrease in our health insurance costs resulting from a decrease in our estimated liability for the deductibles under these policies, partly as a result of reduced headcount.

The decrease in our insurance claims and settlements accrued expenses as of September 30, 2016 as compared to December 31, 2015 is primarily due to a decrease in our insurance company’s reserve for workers’ compensation claims in excess of our deductibles.

The decrease in accrued interest expense as of September 30, 2016 as compared to December 31, 2015 is primarily due to the payment of interest on our Senior Notes which is due semi-annually on March 15 and September 15.

The increase in other accrued expenses as of September 30, 2016 as compared to December 31, 2015 is primarily due to an increase in our accrued liability for sales and use tax obligations.

Long-term Debt and Other Contractual Obligations

The following table includes information about the amount and timing of our contractual obligations at September 30, 2016 (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	$	406,500	$	—	$	106,500	$	—	$	300,000
Interest on debt	120,202		24,802		49,462		36,750		9,188
Purchase commitments	1,557		1,557		—		—		—
Operating leases	10,913		3,456		4,991		2,245		221
Incentive compensation	14,691		4,593		10,098		—		—
	$	553,863	$	34,408	$	171,051	$	38,995	$	309,409

Debt obligations at September 30, 2016 consist of $300 million of principal amount outstanding under our Senior Notes which mature on March 15, 2022 and $106.5 million outstanding under our Revolving Credit Facility which is due at maturity on March 31, 2019 . As of October 15, 2016 , we had $111.5 million outstanding under our Revolving Credit Facility. However, we may make principal payments to reduce the outstanding balance under our Revolving Credit Facility prior to maturity when cash and working capital is sufficient.

Interest payment obligations on our Revolving Credit Facility are estimated based on (1) the 6.0% interest rate that was in effect at September 30, 2016 , and (2) the outstanding balance of $106.5 million at September 30, 2016 to be paid at maturity on March 31, 2019 . 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.

Purchase commitments primarily relate to routine equipment maintenance and upgrades.

Operating leases consist of lease agreements for office space, operating facilities, equipment and personal property.

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 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 Requirements

The Revolving Credit Facility contains customary mandatory prepayments from the proceeds of certain asset dispositions or equity or debt issuances, which are applied to reduce outstanding revolving and swing-line loans and to cash-collateralize letter of credit exposure, and in certain cases, also reduce the commitment amount available . There are no limitations on our ability to access the borrowing capacity provided there is no default, all representations and warranties are true and correct, and compliance with financial covenants under the Revolving Credit Facility is maintained.

At September 30, 2016 , we were in compliance with our financial covenants under the Revolving Credit Facility. Our senior consolidated leverage ratio was 3.1 to 1.0 and our interest coverage ratio was 1.6 to 1.0. However, 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. If we expect our future operating results to decline to a level that indicates we may become unable to comply with the financial covenants in the Revolving Credit Facility, we may seek to amend such provisions to remain in compliance or we may pursue other capital sources, such as other debt or equity 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.

The financial covenants contained in our Revolving Credit Facility include the following , all of which are described in more detail in Note 4 , Debt , of the Notes to Condensed Consolidated Financial Statements, included in Part I, Item 1 , Financial Statements , of this Quarterly Report on Form 10-Q :


•	A maximum senior consolidated leverage ratio, calculated as senior consolidated debt at the period end, which excludes unsecured and subordinated debt, divided by EBITDA for the trailing twelve month period at each quarter end, as defined in the Revolving Credit Facility.


•	A minimum interest coverage ratio, calculated as EBITDA for the trailing twelve month period at each quarter end, as defined in the Revolving Credit Facility, divided by interest expense for the same period.


•	A minimum EBITDA requirement, for the periods indicated, as defined in the Revolving Credit Facility.

The Revolving Credit Facility also restricts capital expenditures, as further described in Note 4 , Debt , of the Notes to Condensed Consolidated Financial Statements, included in Part I, Item 1 , Financial Statements , of this Quarterly Report on Form 10-Q .

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


•	incur additional debt or make prepayments of existing debt;


•	create liens on or dispose of our assets;


•	pay dividends on stock or repurchase stock;


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


•	make other restricted investments; and


•	conduct transactions with affiliates.

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.

In addition to the financial covenants under our Revolving Credit Facility, the Indenture governing our Senior Notes also contains certain restrictions which generally restrict 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 assets;


•	enter into sale and leaseback transactions;


•	sell or transfer assets;


•	pay dividends, engage in loans, 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 .

Our Senior Notes are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by our existing 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.

Our Senior Notes are not subject to any sinking fund requirements. As of September 30, 2016 , there were no restrictions on the ability of subsidiary guarantors to transfer funds to the parent company, and we were in compliance with all covenants pertaining to our Senior Notes.

Results of Operations

Statements of Operations Analysis

The following table provides information about our operations for the three and nine months ended September 30, 2016 and 2015 (amounts in thousands, except average number of drilling rigs, utilization rate and revenue day information).



	Three months ended September 30,						Nine months ended September 30,
	2016			2015			2016			2015
Drilling Services Segment:
Revenues	$	27,454		$	41,238		$	88,597		$	198,212
Operating costs	19,776			23,003			51,989			118,114
Drilling Services Segment margin	$	7,678		$	18,235		$	36,608		$	80,098

Average number of drilling rigs	31.0			35.9			31.0			39.7
Utilization rate	38		%	49		%	41		%	67		%
Revenue days	1,093			1,618			3,513			7,197

Average revenues per day	$	25,118		$	25,487		$	25,220		$	27,541
Average operating costs per day	18,093			14,217			14,799			16,412
Drilling Services Segment margin per day	$	7,025		$	11,270		$	10,421		$	11,129

Production Services Segment:
Revenues	$	40,899		$	66,242		$	116,998		$	238,093
Operating costs	31,912			48,643			95,503			170,517
Production Services Segment margin	$	8,987		$	17,599		$	21,495		$	67,576

Combined:
Revenues	$	68,353		$	107,480		$	205,595		$	436,305
Operating costs	51,688			71,646			147,492			288,631
Consolidated margin	$	16,665		$	35,834		$	58,103		$	147,674

Net loss	$	(34,620	)	$	(17,540	)	$	(92,310	)	$	(106,840	)
Adjusted EBITDA	$	3,285		$	18,829		$	13,321		$	90,783

Drilling Services Segment margin represents contract drilling revenues less contract drilling operating costs. Production Services Segment margin represents production services revenue less production services operating costs. Drilling Services Segment margin and Production 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 Drilling Services Segment margin and Production Services Segment margin are useful to investors and analysts because they provide a means to evaluate the operating performance of the segments on an ongoing basis using criteria that are used by our internal decision makers. Additionally, the use of these measures highlights operating trends and aids in analytical comparisons. Drilling Services Segment margin and Production Services Segment margin as presented may not be comparable to other similarly titled measures reported by other companies.

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



	Three months ended September 30,						Nine months ended September 30,
	2016			2015			2016			2015
	(amounts in thousands)
Reconciliation of consolidated margin and Adjusted EBITDA to net loss:
Consolidated margin	$	16,665		$	35,834		$	58,103		$	147,674
General and administrative	(14,312		)	(16,686		)	(46,078		)	(56,909		)
Bad debt recovery	359			1,071			302			358
Gain (loss) on dispositions of property and equipment, net	328			(605)			420			2,639
Other income (expense)	245			(785		)	574			(2,979		)
Adjusted EBITDA	3,285			18,829			13,321			90,783
Depreciation and amortization	(28,663		)	(35,257		)	(87,409		)	(115,528		)
Impairment charges	(4,262		)	(2,329		)	(4,262		)	(79,648		)
Interest expense	(6,678		)	(4,975		)	(19,307		)	(15,675		)
Loss on extinguishment of debt	—			(490		)	(299		)	(490		)
Income tax benefit	1,698			6,682			5,646			13,718
Net loss	$	(34,620	)	$	(17,540	)	$	(92,310	)	$	(106,840	)

Both our Drilling Services and Production Services Segments experienced a significant decline in activity during the three and nine months ended September 30, 2016 , as compared to the corresponding periods in 2015 , due to the current downturn in our industry. Our combined margin decreased for the three and nine months ended September 30, 2016 as compared to the corresponding periods in 2015 , primarily as a result of decreased activity and pricing pressure for all our service offerings.

Our Drilling Services Segment’s revenues decreased by $13.8 million , or 33% , and $109.6 million , or 55% , for the three and nine months ended September 30, 2016 , respectively, as compared to the corresponding periods in 2015 , while operating costs decreased by $3.2 million , or 14% , and $66.1 million , or 56% , respectively. The decreases in our Drilling Services Segment’s revenues and operating costs primarily resulted from a 51% decrease in revenue days due to the significant reduction in demand in our industry.

Demand for drilling rigs influences the types of drilling contracts we are able to obtain, and the type of revenues we earn under our drilling contracts. As a result of the downturn in our industry, several of our clients terminated a number of their drilling contracts with us. Drilling rigs under contracts which are terminated early earn lower standby revenue rates, as compared to daywork rates, and incur minimal operating costs. Alternatively, turnkey drilling contracts result in higher average revenues per day and higher average operating costs per day as compared to daywork drilling contracts, and are more frequently entered into during periods of higher demand. The following table provides the percentages of our drilling revenues by contract type for the three and nine months ended September 30, 2016 and 2015 :



	Three months ended September 30,				Nine months ended September 30,
	2016		2015		2016		2015
Daywork contracts (not terminated early)	94	%	70	%	84	%	77	%
Daywork contracts terminated early	6	%	28	%	15	%	20	%
Turnkey contracts	—	%	2	%	1	%	3	%

For drilling contracts that were terminated early, the amount of drilling revenues and the number of revenue days for the three and nine months ended September 30, 2016 and 2015 are as follows:



	Three months ended September 30,				Nine months ended September 30,
	2016		2015		2016		2015
Revenues (in thousands)	$	1,754	$	11,690	$	13,274	$	38,955
Revenue days	17		500		495		1,678

Our average revenues per day decreased by $369 per day, or 1% , while our average operating costs per day increased by $3,876 per day, or 27% , for the three months ended September 30, 2016 , as compared to the corresponding period in 2015 , primarily due to the expiration of term contracts that were entered into in 2014 prior to the downturn, many of which were terminated early, resulting in a higher percentage of daywork revenue during the three months ended September 30, 2016 , as compared to the corresponding period in 2015. Our average revenues per day decreased by $2,321 per day, or 8% , while our average operating costs per day decreased by $1,613 per day, or 10% , for the nine months ended September 30, 2016 , as compared to the corresponding period in 2015 , primarily due to reduced activity for our Colombian operations, for which we typically earn higher dayrates and incur higher operating costs per day.

Our Production Services Segment’s revenues decreased by $25.3 million , or 38% , and $121.1 million , or 51% , for the three and nine months ended September 30, 2016 , respectively as compared to the corresponding periods in 2015 , while operating costs decreased by $16.7 million , or 34% , and $75.0 million , or 44% , respectively. The decreases in our Production Services Segment’s revenues and operating costs are a result of the significantly reduced demand for our services in response to the downturn in our industry, which led to decreased activity and increased pricing pressure for all our service offerings, especially our wireline services and coiled tubing operations. The number of wireline jobs we completed decreased by 10% and 24% for the three and nine months ended September 30, 2016 , as compared to the corresponding periods in 2015 . The total rig hours for our well servicing fleet decreased by 32% and 7% , for the three and nine months ended September 30, 2016 , as compared to the corresponding periods in 2015 . Our coiled tubing utilization decreased to 22% for both the three and nine months ended September 30, 2016 from 25% and 28% during the corresponding periods in 2015 .

In response to the downturn in our industry, we took several actions to reduce costs and better scale our business to the reduced revenues. We reduced our total headcount by approximately 61% since the beginning of 2015 . We reduced wage rates for our operations personnel, reduced incentive compensation and eliminated certain employment benefits. We closed a total of ten field offices since the beginning of 2015 to reduce overhead and reduce associated lease payments, amended our revolving credit facility, with the latest amendment in June 2016, and sold 32 drilling rigs and other drilling equipment in 2015 for aggregate net proceeds of $53.6 million . As of September 30, 2016 , we have four additional domestic mechanical and lower horsepower electric drilling rigs held for sale, along with other drilling equipment, 13 wireline units and certain coiled tubing equipment .

Our general and administrative expense decreased by $2.4 million , or 14% , and $10.8 million , or 19% , for the three and nine months ended September 30, 2016 , respectively, as compared to the corresponding periods in 2015 . These decreases are primarily due to a decrease in compensation and benefit costs during 2016 of $6.0 million , resulting primarily from the reduction in our workforce and reduced employee benefits, and other efforts taken to minimize various administrative costs such as office and rent expenses and travel.

Our gains of $0.4 million on the disposition of property and equipment during the nine months ended September 30, 2016 was primarily related to a gain on the disposal of excess drill pipe which was mostly offset by a loss on the disposition of damaged drilling equipment. Our gains of $2.6 million on the disposition of property and equipment during the nine months ended September 30, 2015 was primarily for the sale of 28 of our mechanical and lower horsepower electric drilling rigs and other drilling equipment.

The increase in our other income is primarily related to net foreign currency gains recognized for our Colombian operations during the nine months ended September 30, 2016 , as compared to net foreign currency losses during 2015 .

Our depreciation and amortization expense decreased by $6.6 million and $28.1 million for the three and nine months ended September 30, 2016 , respectively, as compared to the corresponding periods in 2015 , primarily as a result of the impairment charges during 2015 to reduce the carrying values of certain drilling rigs, coiled tubing equipment

and intangible assets to their estimated fair values, and the sales of drilling rigs and equipment during 2015. During the nine months ended September 31, 2015 , we recognized $8.8 million of depreciation on drilling rigs which were subsequently sold or placed as held for sale, and $2.8 million for the amortization of coiled tubing intangible assets which were impaired to zero at the end of 2015. The overall decrease in our depreciation expense was partially offset by $6.0 million of additional depreciation recognized during the nine months ended September 30, 2016 for the five new drilling rigs which we deployed in 2015 .

During the nine months ended September 30, 2016 , we recognized impairment charges of $4.3 million , primarily to reduce the carrying values of certain assets which were classified as held for sale, to their estimated fair value based on expected sales prices. During the nine months ended September 30, 2015 , we recognized impairment charges of $79.6 million . For more detail, see Note 2 , 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 .

Our interest expense increased by $1.7 million and $3.6 million for the three and nine months ended September 30, 2016 , respectively, as compared to the corresponding periods in 2015 , primarily due to the increased interest rate under our Revolving Credit Facility which was amended in late 2015 and again in June 2016.

Our effective income tax rate for the nine months ended September 30, 2016 was 6% , which is lower than the federal statutory rate in the United States primarily due to valuation allowances, the effect of foreign currency translation, state taxes, and other permanent differences. For more detail about the valuation allowances, see Note 3 , Valuation Allowances on Deferred Tax Assets , of the Notes to Condensed Consolidated Financial Statements, included in Part I, Item 1 , Financial Statements , of this Quarterly Report on Form 10-Q .

Inflation

Wage rates for our operations personnel are impacted by inflationary pressures when the demand for drilling and production services increases and the availability of personnel is scarce. Costs for equipment repairs and maintenance, upgrades and new equipment construction are also impacted by inflationary pressures when the demand for drilling services increases. As a result of the significantly reduced activity levels in our industry during 2015, we estimate that we experienced a moderate decrease in both wage rates and equipment costs during 2015 for both our Drilling and Production Services Segments, with similar decreases in 2016 as well.

Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements.

Critical Accounting Policies and Estimates

The preparation of financial statements in conformity with U.S. GAAP requires us to make estimates and assumptions that affect the amounts reported in our financial statements and accompanying notes. Actual results could differ from those estimates. As of September 30, 2016 , 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, 2015 .

Revenue and Cost Recognition — Our Drilling Services Segment earns revenues by drilling oil and gas wells for our clients under daywork or turnkey contracts, which usually provide for the drilling of a single well. Drilling contracts for individual wells are usually completed in less than 30 days. We recognize revenues on daywork contracts for the days completed based on the dayrate each contract specifies. We recognize revenues from our turnkey contracts on the proportional performance basis, based on our estimate of the number of days to complete each contract. All of our revenues are recognized net of applicable sales taxes.

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 revenue and the out-of-pocket expenses for which they relate are recorded as operating costs.

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

Long-lived tangible and intangible assets— We evaluate for potential impairment of long-lived tangible and intangible assets subject to amortization when indicators of impairment are present. Circumstances that could indicate a potential impairment include significant adverse changes in industry trends, economic climate, legal factors, and an adverse action or assessment by a regulator. More specifically, significant adverse changes in industry trends include significant declines in revenue rates, utilization rates, oil and natural gas market prices and industry rig counts. In performing an impairment evaluation, we estimate the future undiscounted net cash flows from the use and eventual disposition of long-lived tangible and intangible assets grouped at the lowest level that cash flows can be identified. For our Production Services Segment, we perform an impairment evaluation and estimate future undiscounted cash flows for the individual reporting units (well servicing, wireline and coiled tubing). For our Drilling Services Segment, we perform an impairment evaluation and estimate future undiscounted cash flows for individual domestic drilling rig assets and for our Colombian drilling rig assets as a group. If the sum of the estimated future undiscounted net cash flows is less than the carrying amount of the asset group, then we determine the fair value of the asset group. The amount of an impairment charge is measured as the difference between the carrying amount and the fair value of the assets. The assumptions used in the impairment evaluation for long-lived assets 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, basis differences arise from differences in depreciation periods and methods and the value of assets acquired in a business acquisition where we acquire an entity rather than just its assets. For financial reporting purposes, we depreciate the various components of our drilling rigs, well servicing rigs, wireline units and coiled tubing units over 1 to 25 years and refurbishments over 3 to 5 years, while federal income tax rules require that we depreciate drilling rigs, well servicing rigs, wireline units and coiled tubing units over 5 years. Therefore, in the first 5 years of our ownership of a drilling rig, well servicing rig, wireline unit or coiled tubing unit, our tax depreciation exceeds our financial reporting depreciation, resulting in our providing deferred taxes on this depreciation difference. After 5 years, financial reporting depreciation exceeds tax depreciation, and the deferred tax liability begins to reverse.

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

We consider the recognition of revenues and costs on turnkey contracts to be critical accounting estimates. For these types of contracts, we recognize revenues and accrue estimated costs based on our estimate of the number of days to complete each contract and our estimate of the total costs to complete the contract. Revenues and costs during a reporting period could be affected for contracts in progress at the end of a reporting period which have not been completed before our financial statements for that period are released. If we anticipate a loss on a contract in progress due to a change in our cost estimate, we accrue the entire amount of the estimated loss, including all costs that are included in our revised estimated cost to complete that contract, in our consolidated statement of operations for that reporting period. However, our actual costs could substantially exceed our estimated costs if we encounter problems while completing services on contracts still in progress at the end of a reporting period. We did not experience a loss on any of the turnkey contracts completed during the nine months ended September 30, 2016 . We incurred a total loss of $0.5 million on 3 of the 17 turnkey contracts completed during the nine months ended September 30, 2015 . As of September 30, 2016 , we had no turnkey contracts in progress.

We estimate an allowance for doubtful accounts based on the creditworthiness of our clients as well as general economic conditions. We evaluate the creditworthiness of our clients based on commercial credit reports, trade references, bank references, financial information, production information and any past experience we have with the client. Consequently, any change in those factors could affect our estimate of our allowance for doubtful accounts. In some instances, we require new clients to establish escrow accounts or make prepayments. We had an allowance for doubtful accounts of $1.0 million at September 30, 2016 .

Our determination of the useful lives of our depreciable assets, which directly affects our determination of depreciation expense and deferred taxes is also a critical accounting estimate. A decrease in the useful life of our property and equipment would increase depreciation expense and reduce deferred taxes. We provide for depreciation of our drilling, production, transportation and other equipment on a straight-line method over useful lives that we have estimated and that range from 1 to 25 years. We record the same depreciation expense whether a drilling rig, well servicing rig, wireline unit or coiled tubing unit is idle or working. Our estimates of the useful lives of our drilling, production, transportation and other equipment are based on our more than 45 years of experience in the oilfield services industry with similar equipment.

We evaluate for potential impairment of long-lived tangible and intangible assets subject to amortization when indicators of impairment are present. Despite the modest recovery in commodity prices in recent months, we continue to monitor all indicators of potential impairments in accordance with ASC Topic 360, Property, Plant and Equipment.

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

As of September 30, 2016 , we had $97.5 million of deferred tax assets related to domestic and foreign net operating losses that are available to reduce future taxable income. In assessing the realizability of our deferred tax assets, we consider whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. As of September 30, 2016 , we determined that a valuation allowance should be recorded for a portion of our domestic deferred tax assets, which has been factored into the estimated annual tax rate to be applied throughout 2016, and is the primary factor causing our effective tax rate to be significantly lower than the statutory rate of 35%. We also have a valuation allowance that fully offsets our $21.3 million of foreign deferred tax assets . For more information, see Note 3 , Valuation Allowances on Deferred Tax Assets , of the Notes to Condensed Consolidated Financial Statements, included in Part I, Item 1 , Financial Statements , of this Quarterly Report on Form 10-Q .

Our accrued insurance premiums and deductibles as of September 30, 2016 include accruals for costs incurred under the self-insurance portion of our health insurance of approximately $1.7 million and our workers’ compensation, general liability and auto liability insurance of approximately $4.7 million . We have stop-loss coverage of $200,000 per covered individual per year under our health insurance and a deductible of $500,000 per occurrence under our workers’ compensation insurance. We have a deductible of $250,000 per occurrence under both our general liability insurance and auto liability insurance. We accrue for these costs as claims are incurred using an actuarial calculation that is based on industry and our company’s historical claim development data, and we accrue the costs of administrative services associated with claims processing.

Our compensation expense includes estimates for certain of our long-term incentive compensation plans which have performance-based award components dependent upon our performance over a set performance period, as compared to the performance of a pre-defined peer group. The accruals for these awards include estimates which affect our compensation expense, employee related accruals and equity. The accruals are adjusted based on actual achievement levels at the end of the pre-determined performance periods.

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 .


Item 3 .	Quantitative and Qualitative Disclosures About Market Risk

Interest Rate Risk

We are subject to interest rate market risk on our variable rate debt. As of September 30, 2016 , we had $106.5 million outstanding under our Revolving Credit Facility, which is our only variable rate debt. The impact of a hypothetical 1% increase or decrease in interest rates on this amount of debt would have resulted in a corresponding increase or decrease, respectively, in interest expense of approximately $0.8 million , and a corresponding increase or decrease, respectively, in net income of approximately $0.5 million during the nine months ended September 30, 2016 . 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, 2016 .

Foreign Currency Risk

While the U.S. dollar is the functional currency for reporting purposes for our Colombian operations, we enter into transactions denominated in Colombian pesos. Nonmonetary assets and liabilities are translated at historical rates and monetary assets and liabilities are translated at exchange rates in effect at the end of the period. Income statement accounts are translated at average rates for the period. As a result, Colombian Peso denominated transactions are affected by changes in exchange rates. We generally accept the exposure to exchange rate movements without using derivative financial instruments to manage this risk. Therefore, both positive and negative movements in the Colombian Peso currency exchange rate against the U.S. dollar have and will continue to affect the reported amount of revenues, expenses, profit, and assets and liabilities in our consolidated financial statements.

The impact of currency rate changes on our Colombian Peso denominated transactions and balances resulted in foreign currency gains of $0.5 million for the nine months ended September 30, 2016 .


Item 4 .	Controls and Procedures

In accordance with Exchange Act Rules 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of September 30, 2016 , 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 have been no changes in our internal control over financial reporting during the three months ended September 30, 2016 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II - OTHER INFORMATION


Item 1 .	Legal Proceedings

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


Item 1A.	Risk Factors

Not applicable.


Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds

We did not make any unregistered sales of equity securities during the quarter ended September 30, 2016 . We did not repurchase any common shares during the quarter ended September 30, 2016 .


Item 3.	Defaults Upon Senior Securities

Not applicable.


Item 4.	Mine Safety Disclosures

Not applicable.


Item 5 .	Other Information

Not applicable.


Item 6 .	Exhibits

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




Exhibit Number		Description

3.1*	-	Restated Articles of Incorporation of Pioneer Energy Services Corp. (Form 8-K dated July 30, 2012 (File No. 1-8182, Exhibit 3.1)).

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

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

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

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

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

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

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

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

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

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

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

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

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

101**	-	The following financial statements from Pioneer Energy Services Corp.’s Form 10-Q for the quarter ended September 30, 2016, formatted in XBRL (eXtensible Business Reporting Language): (i) Condensed Consolidated Balance Sheets, (ii) Condensed Consolidated Statements of Operations, (iii) Condensed Consolidated Statements of Cash Flows, and (iv) Notes to Condensed Consolidated Financial Statements.

* Incorporated by reference to the filing indicated.

** Filed herewith.

# Furnished herewith.

SIGNATURES

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

PIONEER ENERGY SERVICES CORP.

/s/ Lorne E. Phillips

Lorne E. Phillips

Executive Vice President and Chief Financial Officer

(Principal Financial Officer and Duly Authorized Officer)

Dated: November 1, 2016

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 July 30, 2012 (File No. 1-8182, Exhibit 3.1)).

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

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

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

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

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

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

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

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

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

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

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

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

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

101**	-	The following financial statements from Pioneer Energy Services Corp.’s Form 10-Q for the quarter ended September 30, 2016, 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.