PIONEER ENERGY SERVICES CORP (Form: 10-Q, Received: 07/28/2016 15:33:25)

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 June 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 July 15, 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



	June 30, 2016			December 31, 2015
	(unaudited)			(audited)
	(in thousands, except share data)
ASSETS
Current assets:
Cash and cash equivalents	$	14,578		$	14,160
Receivables:
Trade, net of allowance for doubtful accounts	35,810			47,577
Unbilled receivables	2,121			13,624
Insurance recoveries	17,611			14,556
Other receivables	3,337			4,059
Inventory	8,640			9,262
Assets held for sale	4,513			4,619
Prepaid expenses and other current assets	5,889			7,411
Total current assets	92,499			115,268
Property and equipment, at cost	1,135,346			1,146,994
Less accumulated depreciation	480,552			444,409
Net property and equipment	654,794			702,585
Intangible assets, net of accumulated amortization of $12.7 million and $12.3 million at June 30, 2016 and December 31, 2015, respectively	1,166			1,944
Deferred income taxes	15			18
Other long-term assets	2,050			2,178
Total assets	$	750,524		$	821,993

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	13,077		$	16,951
Deferred revenues	2,848			6,222
Accrued expenses:
Payroll and related employee costs	13,391			13,859
Insurance premiums and deductibles	6,530			8,087
Insurance claims and settlements	14,058			14,556
Interest	5,489			5,508
Other	3,826			4,859
Total current liabilities	59,219			70,042
Long-term debt, less debt issuance costs	387,551			387,217
Deferred income taxes	15,100			17,520
Other long-term liabilities	3,508			4,571
Total liabilities	465,378			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 June 30, 2016 and December 31, 2015, respectively	6,559			6,496
Additional paid-in capital	476,077			475,823
Treasury stock, at cost; 515,546 and 458,170 shares at June 30, 2016 and December 31, 2015, respectively	(3,883		)	(3,759		)
Accumulated deficit	(193,607		)	(135,917		)
Total shareholders’ equity	285,146			342,643
Total liabilities and shareholders’ equity	$	750,524		$	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 June 30,						Six months ended June 30,
	2016			2015			2016			2015
	(in thousands, except per share data)
Revenues:
Drilling services	$	27,959		$	58,559		$	61,143		$	156,974
Production services	34,331			76,452			76,099			171,851
Total revenues	62,290			135,011			137,242			328,825

Costs and expenses:
Drilling services	14,773			32,815			32,213			95,111
Production services	28,742			53,106			63,591			121,874
Depreciation and amortization	28,922			38,489			58,746			80,271
General and administrative	15,258			18,363			31,766			40,223
Bad debt expense	112			394			57			713
Impairment charges	—			71,329			—			77,319
Loss (gain) on dispositions of property and equipment, net	508			(4,377		)	(92		)	(3,244		)
Total costs and expenses	88,315			210,119			186,281			412,267
Loss from operations	(26,025		)	(75,108		)	(49,039		)	(83,442		)

Other (expense) income:
Interest expense, net of interest capitalized	(6,375		)	(5,245		)	(12,629		)	(10,700		)
Loss on extinguishment of debt	(299		)	—			(299		)	—
Other	718			486			329			(2,194		)
Total other expense	(5,956		)	(4,759		)	(12,599		)	(12,894		)

Loss before income taxes	(31,981		)	(79,867		)	(61,638		)	(96,336		)
Income tax benefit	1,990			2,586			3,948			7,036
Net loss	$	(29,991	)	$	(77,281	)	$	(57,690	)	$	(89,300	)

Loss per common share—Basic	$	(0.46	)	$	(1.20	)	$	(0.89	)	$	(1.39	)

Loss per common share—Diluted	$	(0.46	)	$	(1.20	)	$	(0.89	)	$	(1.39	)

Weighted average number of shares outstanding—Basic	64,781			64,342			64,679			64,168

Weighted average number of shares outstanding—Diluted	64,781			64,342			64,679			64,168

See accompanying notes to condensed consolidated financial statements.

PIONEER ENERGY SERVICES CORP. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited)



	Six months ended June 30,
	2016			2015
	(in thousands)
Cash flows from operating activities:
Net loss	$	(57,690	)	$	(89,300	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation and amortization	58,746			80,271
Allowance for doubtful accounts, net of recoveries	57			713
Gain on dispositions of property and equipment, net	(92		)	(3,244		)
Stock-based compensation expense	2,065			1,240
Amortization of debt issuance costs	844			827
Loss on extinguishment of debt	299			—
Impairment charges	—			77,319
Deferred income taxes	(4,348		)	(8,267		)
Change in other long-term assets	102			1,018
Change in other long-term liabilities	(1,063		)	(1,606		)
Changes in current assets and liabilities:
Receivables	24,159			91,881
Inventory	454			1,001
Prepaid expenses and other current assets	1,525			1,384
Accounts payable	(5,100		)	(26,220		)
Deferred revenues	(2,786		)	22,798
Accrued expenses	(3,576		)	(28,044		)
Net cash provided by operating activities	13,596			121,771

Cash flows from investing activities:
Purchases of property and equipment	(13,240		)	(84,027		)
Proceeds from sale of property and equipment	812			34,538
Proceeds from insurance recoveries	—			227
Net cash used in investing activities	(12,428		)	(49,262		)

Cash flows from financing activities:
Debt repayments	—			(45,002		)
Debt issuance costs	(809		)	(5		)
Proceeds from exercise of options	183			753
Purchase of treasury stock	(124		)	(711		)
Net cash used in financing activities	(750		)	(44,965		)

Net increase in cash and cash equivalents	418			27,544
Beginning cash and cash equivalents	14,160			34,924
Ending cash and cash equivalents	$	14,578		$	62,468

Supplementary disclosure:
Interest paid	$	12,053		$	11,385
Income tax paid	$	519		$	2,331
Noncash investing and financing activity:
Change in capital expenditure accruals	$	722		$	11,133

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

We have a current fleet of 31 drilling 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	5
Appalachia	4
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 June 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	119	125
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. Currently, we have contracts with original terms of six months to four years in duration.

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.

Since late 2014, oil prices have declined significantly resulting in a downturn in our industry, affecting both drilling and production services. As a result, term contracts for 19 of our drilling rigs were terminated early, including three that were terminated in early 2016 .

As of June 30, 2016 , 11 of our 23 domestic drilling rigs are earning revenues, nine of which are under term contracts . Of the eight rigs in Colombia, three are under term contracts, but have been put on standby by our client and are not earning revenue. The term contracts in Colombia are cancelable without penalty, by our client 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 to diversify our client base, and evaluating other options, including the possibility of the sale of some or all of our assets in Colombia.

Including these three contracts in Colombia, 14 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	2	7	1	1	1	1	3
Earning but not working	—	2	2	—	—	—	—

Colombia Rigs (on standby)	—	3	1	—	—	—	2
	2	12	4	1	1	1	5

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, and our estimate of compensation related accruals.

In preparing the accompanying unaudited condensed consolidated financial statements, we have reviewed events that have occurred after June 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 $2.1 million at June 30, 2016 , of which $1.9 million represented revenue recognized but not yet billed on daywork drilling contracts in progress and $0.2 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 one turnkey contract in progress .

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, deferred lease liabilities and other deferred liabilities.

Related-Party Transactions

During the six months ended June 30, 2016 and 2015 , the Company paid approximately $84,000 and $88,000 , respectively, for trucking and equipment rental services, which represented arms-length transactions, to Gulf Coast Lease Service. Joe Freeman, our Senior Vice President of Well Servicing, serves as the President of Gulf Coast Lease Service, which is owned and operated by Mr. Freeman's two sons. Mr. Freeman does not receive compensation from Gulf Coast Lease Service, and he serves primarily in an advisory role to his sons.

Comprehensive Income

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

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 is 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 are currently evaluating the potential impact of this guidance, but at this time, 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.

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

During the six months ended June 30, 2016 and 2015 , we had capital expenditures of $14.0 million and $95.2 million , respectively, which includes $0.2 million and $1.5 million , respectively, of capitalized interest costs incurred during the construction periods of new drilling rigs and other drilling equipment. 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. As of June 30, 2016 and December 31, 2015 , capital expenditures incurred for property and equipment not yet placed in service was $9.9 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.

During the six months ended June 30, 2016 , we recorded net gains of $0.1 million on the disposition of property and equipment, primarily for the disposal of excess drill pipe for a gain, which was 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 are in the process of filing an insurance claim and expect the insurance proceeds will be approximately $3.4 million , resulting in an estimated net loss on disposal of $0.6 million recognized in the second quarter of 2016.

During the six months ended June 30, 2015 , we recorded net gains of $3.2 million on the disposition of property and equipment, primarily for the sale of 27 of our mechanical and lower horsepower electric drilling rigs and other drilling equipment which we sold for aggregate proceeds of $33.4 million.

As of June 30, 2016 , our condensed consolidated balance sheet reflects assets held for sale of $4.5 million , which primarily represents the fair value of four domestic mechanical and lower horsepower electric drilling rigs, as well as one real estate property and other equipment .

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 , and concluded there are no triggers present that require impairment testing as of June 30, 2016 .

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.

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. As a result, we recognized $69.8 million of impairment charges during the second quarter of 2015 to reduce the carrying values of these assets to their estimated fair values. Additionally, during the three and six months ended June 30, 2015 , we recorded impairment charges of $1.5 million and $7.5 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.

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 June 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 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 $19.5 million of foreign deferred tax assets at June 30, 2016 .

4 . Debt

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



	June 30, 2016			December 31, 2015
Senior secured revolving credit facility	$	95,000		$	95,000
Senior notes	300,000			300,000
	395,000			395,000
Less unamortized debt issuance costs	(7,449		)	(7,783		)
	$	387,551		$	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 June 30, 2016 , we had $95 million outstanding under our Revolving Credit Facility and $17.3 million in committed letters of credit, which resulted in borrowing availability of $62.7 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.

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	3.50	to 1.00	on	June 30, 2016
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	1.50	to 1.00	for the quarterly period ending	June 30, 2016
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 $0.8 million of associated amortization during each of the six months ended June 30, 2016 and 2015 . Additionally, we recognized $0.3 million 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 which was amended in June 2016.


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 June 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 June 30, 2016 and December 31, 2015 (amounts in thousands):



	June 30, 2016				December 31, 2015
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Total debt	$	387,551	$	306,683	$	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 June 30,						Six months ended June 30,
	2016			2015			2016			2015
Numerator (both basic and diluted):
Net loss	$	(29,991	)	$	(77,281	)	$	(57,690	)	$	(89,300	)

Denominator:
Weighted-average shares (denominator for basic earnings per share)	64,781			64,342			64,679			64,168
Diluted effect of outstanding stock options, restricted stock and restricted stock unit awards	—			—			—			—

Denominator for diluted earnings per share	64,781			64,342			64,679			64,168

Loss per common share—Basic	$	(0.46	)	$	(1.20	)	$	(0.89	)	$	(1.39	)

Loss per common share—Diluted	$	(0.46	)	$	(1.20	)	$	(0.89	)	$	(1.39	)

Potentially dilutive securities excluded as anti-dilutive	5,095			4,718			5,152			4,894


7 .	Equity Transactions and Stock-Based Compensation Plans

Equity Transactions

In May 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 June 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. In the future, 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 six months ended June 30, 2016 and 2015 (amounts in thousands):



	Three months ended June 30,				Six months ended June 30,
	2016		2015		2016		2015
Stock option awards	$	188	$	213	$	381	$	477
Restricted stock awards	103		99		190		223
Restricted stock unit awards	597		523		1,494		540
	$	888	$	835	$	2,065	$	1,240

Phantom stock unit awards	$	608	$	—	$	726	$	—

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 June 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 six months ended June 30, 2016 and 2015 :



	Six months ended June 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.

During the six months ended June 30, 2016 , 46,804 stock options were exercised at a weighted-average exercise price of $3.92 . There were no stock options exercised during the three months ended March 31, 2016. During the three and six months ended June 30, 2015 , 39,600 and 196,100 stock options, respectively, were exercised at a weighted-average exercise price of $3.84 . 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 six months ended June 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 three and six months ended June 30, 2016 and 2015 :



	Three months ended June 30,				Six months ended June 30,
	2016		2015		2016		2015
Time-based RSUs:
Time-based RSUs granted	28,500		—		260,334		151,919
Weighted-average grant-date fair value	$	2.88	$	—	$	1.48	$	4.08

Performance-based RSUs:
Performance-based RSUs granted	—		145,107		—		439,773
Weighted-average grant-date fair value	$	—	$	8.34	$	—	$	5.76

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 performance period from January 1, 2013 through 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 June 30, 2016 , we estimated that our actual achievement level for the performance-based RSUs granted during 2014 and 2015 will be approximately 80% 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 tables set forth certain financial information for our two operating segments and corporate as of and for the three and six months ended June 30, 2016 and 2015 (amounts in thousands):



	As of and for the three months ended June 30, 2016
	Drilling Services Segment		Production Services Segment		Corporate		Total
Identifiable assets	$	478,799	$	256,284	$	15,441	$	750,524
Revenues	$	27,959	$	34,331	$	—	$	62,290
Operating costs	14,773		28,742		—		43,515
Segment and combined margin	$	13,186	$	5,589	$	—	$	18,775
Depreciation and amortization	$	15,408	$	13,188	$	326	$	28,922
Capital expenditures	$	5,437	$	2,953	$	79	$	8,469



	As of and for the three months ended June 30, 2015
	Drilling Services Segment		Production Services Segment		Corporate		Total
Identifiable assets	$	564,529	$	411,883	$	28,485	$	1,004,897
Revenues	$	58,559	$	76,452	$	—	$	135,011
Operating costs	32,815		53,106		—		85,921
Segment and combined margin	$	25,744	$	23,346	$	—	$	49,090
Depreciation and amortization	$	20,815	$	17,328	$	346	$	38,489
Capital expenditures	$	42,634	$	3,696	$	14	$	46,344



	As of and for the six months ended June 30, 2016
	Drilling Services Segment		Production Services Segment		Corporate		Total
Identifiable assets	$	478,799	$	256,284	$	15,441	$	750,524
Revenues	$	61,143	$	76,099	$	—	$	137,242
Operating costs	32,213		63,591		—		95,804
Segment and combined margin	$	28,930	$	12,508	$	—	$	41,438
Depreciation and amortization	$	31,086	$	27,002	$	658	$	58,746
Capital expenditures	$	7,545	$	6,242	$	175	$	13,962



	As of and for the six months ended June 30, 2015
	Drilling Services Segment		Production Services Segment		Corporate		Total
Identifiable assets	$	564,529	$	411,883	$	28,485	$	1,004,897
Revenues	$	156,974	$	171,851	$	—	$	328,825
Operating costs	95,111		121,874		—		216,985
Segment and combined margin	$	61,863	$	49,977	$	—	$	111,840
Depreciation and amortization	$	44,415	$	35,161	$	695	$	80,271
Capital expenditures	$	75,690	$	19,153	$	317	$	95,160

The following table reconciles the combined margin reported above to income from operations as reported on the consolidated statements of operations for the three and six months ended June 30, 2016 and 2015 (amounts in thousands):



	Three months ended June 30,						Six months ended June 30,
	2016			2015			2016			2015
Combined margin	$	18,775		$	49,090		$	41,438		$	111,840
Depreciation and amortization	(28,922		)	(38,489		)	(58,746		)	(80,271		)
General and administrative	(15,258		)	(18,363		)	(31,766		)	(40,223		)
Bad debt expense	(112		)	(394		)	(57		)	(713		)
Impairment charges	—			(71,329		)	—			(77,319		)
Gain (loss) on dispositions of property and equipment, net	(508		)	4,377			92			3,244
Loss from operations	$	(26,025	)	$	(75,108	)	$	(49,039	)	$	(83,442	)

The following table sets forth certain financial information for our international operations in Colombia as of and for the three and six months ended June 30, 2016 and 2015 (amounts in thousands):



	As of and for the three months ended June 30,				As of and for the six months ended June 30,
	2016		2015		2016		2015
Identifiable assets	$	42,347	$	65,902	$	42,347	$	65,902
Revenues	$	261	$	14,078	$	1,357	$	34,039

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. Due to the downturn in our industry and the resulting loss of drilling contracts, we recognized impairment charges of $60.2 million during the second quarter of 2015 to reduce the carrying values of all eight drilling

rigs in Colombia and related drilling equipment, as well as inventory and nonrecoverable prepaid taxes associated with our Colombian operations.


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 $36.8 million relating to our performance under these bonds as of June 30, 2016 .

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 June 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)



	June 30, 2016
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	10,528		$	(1,112	)	$	5,162		$	—		$	14,578
Receivables, net of allowance	363			55,960			2,556			—			58,879
Intercompany receivable (payable)	(24,837		)	31,628			(6,791		)	—			—
Inventory	—			5,128			3,512			—			8,640
Assets held for sale	—			4,513			—			—			4,513
Prepaid expenses and other current assets	1,645			3,038			1,206			—			5,889
Total current assets	(12,301		)	99,155			5,645			—			92,499
Net property and equipment	2,829			623,236			28,729			—			654,794
Investment in subsidiaries	606,157			32,981			—			(639,138		)	—
Intangible assets, net of accumulated amortization	—			1,166			—			—			1,166
Deferred income taxes	85,759			—			15			(85,759		)	15
Other long-term assets	437			850			763			—			2,050
Total assets	$	682,881		$	757,388		$	35,152		$	(724,897	)	$	750,524
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	927		$	11,870		$	280		$	—		$	13,077
Deferred revenues	—			2,446			402			—			2,848
Accrued expenses	8,266			33,949			1,079			—			43,294
Total current liabilities	9,193			48,265			1,761			—			59,219
Long-term debt, less debt issuance costs	387,551			—			—			—			387,551
Deferred income taxes	—			100,859			—			(85,759		)	15,100
Other long-term liabilities	991			2,107			410			—			3,508
Total liabilities	397,735			151,231			2,171			(85,759		)	465,378
Total shareholders’ equity	285,146			606,157			32,981			(639,138		)	285,146
Total liabilities and shareholders’ equity	$	682,881		$	757,388		$	35,152		$	(724,897	)	$	750,524

	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
Deferred income taxes	84,989			—			18			(84,989		)	18
Other long-term assets	512			962			704			—			2,178
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 June 30, 2016
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Revenues	$	—		$	62,029		$	261		$	—		$	62,290
Costs and expenses:
Operating costs	—			42,395			1,120			—			43,515
Depreciation and amortization	325			26,867			1,730			—			28,922
General and administrative	5,393			9,496			507			(138		)	15,258
Intercompany leasing	—			(1,215		)	1,215			—			—
Bad debt expense	—			112			—			—			112
Loss (gain) on dispositions of property and equipment, net	—			514			(6		)	—			508
Total costs and expenses	5,718			78,169			4,566			(138		)	88,315
Income (loss) from operations	(5,718		)	(16,140		)	(4,305		)	138			(26,025		)
Other income (expense):
Equity in earnings of subsidiaries	(18,210		)	(4,344		)	—			22,554			—
Interest expense	(6,325		)	(52		)	2			—			(6,375		)
Loss on extinguishment of debt	(299		)	—			—			—			(299		)
Other	5			685			166			(138		)	718
Total other income (expense)	(24,829		)	(3,711		)	168			22,416			(5,956		)
Income (loss) before income taxes	(30,547		)	(19,851		)	(4,137		)	22,554			(31,981		)
Income tax (expense) benefit ¹	556			1,641			(207		)	—			1,990
Net income (loss)	$	(29,991	)	$	(18,210	)	$	(4,344	)	$	22,554		$	(29,991	)



	Three months ended June 30, 2015
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Revenues	$	—		$	120,933		$	14,078		$	—		$	135,011
Costs and expenses:
Operating costs	—			74,904			11,017			—			85,921
Depreciation and amortization	346			34,367			3,776			—			38,489
General and administrative	5,685			12,118			698			(138		)	18,363
Intercompany leasing	—			(1,215		)	1,215			—			—
Bad debt expense	—			394			—			—			394
Impairment charges	—			15,447			56,632			(750		)	71,329
Gain on dispositions of property and equipment, net	—			(4,356		)	(21		)	—			(4,377		)
Total costs and expenses	6,031			131,659			73,317			(888		)	210,119
Income (loss) from operations	(6,031		)	(10,726		)	(59,239		)	888			(75,108		)
Other income (expense):
Equity in earnings of subsidiaries	(70,508		)	(62,574		)	—			133,082			—
Interest expense	(5,135		)	(118		)	8			—			(5,245		)
Other	(2		)	419			207			(138		)	486
Total other income (expense)	(75,645		)	(62,273		)	215			132,944			(4,759		)
Income (loss) before income taxes	(81,676		)	(72,999		)	(59,024		)	133,832			(79,867		)
Income tax (expense) benefit ¹	3,645			2,491			(3,550		)	—			2,586
Net income (loss)	$	(78,031	)	$	(70,508	)	$	(62,574	)	$	133,832		$	(77,281	)

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited, in thousands)



	Six months ended June 30, 2016
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Revenues	$	—		$	135,885		$	1,357		$	—		$	137,242
Costs and expenses:
Operating costs	—			92,705			3,099			—			95,804
Depreciation and amortization	657			54,598			3,491			—			58,746
General and administrative	11,278			20,044			720			(276		)	31,766
Intercompany leasing	—			(2,430		)	2,430			—			—
Bad debt expense	—			57			—			—			57
Gain on dispositions of property and equipment, net	—			(41		)	(51		)	—			(92		)
Total costs and expenses	11,935			164,933			9,689			(276		)	186,281
Income (loss) from operations	(11,935		)	(29,048		)	(8,332		)	276			(49,039		)
Other income (expense):
Equity in earnings of subsidiaries	(34,627		)	(9,190		)	—			43,817			—
Interest expense	(12,559		)	(74		)	4			—			(12,629		)
Loss on extinguishment of debt	(299		)	—			—			—			(299		)
Other	(2		)	1,005			(398		)	(276		)	329
Total other income (expense)	(47,487		)	(8,259		)	(394		)	43,541			(12,599		)
Income (loss) before income taxes	(59,422		)	(37,307		)	(8,726		)	43,817			(61,638		)
Income tax (expense) benefit ¹	1,732			2,680			(464		)	—			3,948
Net income (loss)	$	(57,690	)	$	(34,627	)	$	(9,190	)	$	43,817		$	(57,690	)


	Six months ended June 30, 2015
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Revenues	$	—		$	294,786		$	34,039		$	—		$	328,825
Costs and expenses:
Operating costs	—			190,443			26,542			—			216,985
Depreciation and amortization	695			72,044			7,532			—			80,271
General and administrative	10,760			28,373			1,366			(276		)	40,223
Intercompany leasing	—			(2,430		)	2,430			—			—
Bad debt expense	—			713			—			—			713
Impairment charges	—			21,437			56,632			(750		)	77,319
Gain on dispositions of property and equipment, net	—			(3,223		)	(21		)				(3,244		)
Total costs and expenses	11,455			307,357			94,481			(1,026		)	412,267
Income (loss) from operations	(11,455		)	(12,571		)	(60,442		)	1,026			(83,442		)
Other income (expense):
Equity in earnings of subsidiaries	(75,971		)	(67,163		)	—			143,134			—
Interest expense	(10,590		)	(122		)	12			—			(10,700		)
Other	7			871			(2,796		)	(276		)	(2,194		)
Total other income (expense)	(86,554		)	(66,414		)	(2,784		)	142,858			(12,894		)
Income (loss) before income taxes	(98,009		)	(78,985		)	(63,226		)	143,884			(96,336		)
Income tax (expense) benefit ¹	7,959			3,014			(3,937		)	—			7,036
Net income (loss)	$	(90,050	)	$	(75,971	)	$	(67,163	)	$	143,884		$	(89,300	)

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)



	Six months ended June 30, 2016
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidated
Cash flows from operating activities	$	(22,636	)	$	33,298		$	2,934		$	13,596
Cash flows from investing activities:
Purchases of property and equipment	(148		)	(12,819		)	(273		)	(13,240		)
Proceeds from sale of property and equipment	—			761			51			812
	(148		)	(12,058		)	(222		)	(12,428		)
Cash flows from financing activities:
Debt issuance costs	(809		)	—			—			(809		)
Proceeds from exercise of options	183			—			—			183
Purchase of treasury stock	(124		)	—			—			(124		)
Intercompany contributions/distributions	16,841			(16,740		)	(101		)	—
	16,091			(16,740		)	(101		)	(750		)
Net increase (decrease) in cash and cash equivalents	(6,693		)	4,500			2,611			418
Beginning cash and cash equivalents	17,221			(5,612		)	2,551			14,160
Ending cash and cash equivalents	$	10,528		$	(1,112	)	$	5,162		$	14,578

	Six months ended June 30, 2015
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidated
Cash flows from operating activities	$	(24,993	)	$	137,663		$	9,101		$	121,771
Cash flows from investing activities:
Purchases of property and equipment	(268		)	(82,554		)	(1,205		)	(84,027		)
Proceeds from sale of property and equipment	22			34,487			29			34,538
Proceeds from insurance recoveries	—			227			—			227
	(246		)	(47,840		)	(1,176		)	(49,262		)
Cash flows from financing activities:
Debt repayments	(45,000		)	(2		)	—			(45,002		)
Debt issuance costs	(5		)	—			—			(5		)
Proceeds from exercise of options	753			—			—			753
Purchase of treasury stock	(711		)	—			—			(711		)
Intercompany contributions/distributions	100,200			(86,338		)	(13,862		)	—
	55,237			(86,340		)	(13,862		)	(44,965		)
Net increase (decrease) in cash and cash equivalents	29,998			3,483			(5,937		)	27,544
Beginning cash and cash equivalents	27,688			(5,516		)	12,752			34,924
Ending cash and cash equivalents	$	57,686		$	(2,033	)	$	6,815		$	62,468


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

Statements we make in the following discussion that express a belief, expectation or intention, as well as those that are not historical fact, are forward-looking statements 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. We have a current fleet of 31 drilling 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		5
Appalachia		4
Colombia		8
		31

•

Production Services Segment— In March 2008, we acquired two production services companies which significantly expanded our service offerings to include well servicing and wireline services. Through these business acquisitions, we also obtained fishing and rental services operations, which were subsequently sold in September 2014. 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 June 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 June 30, 2016 , we have a fleet of 125 wireline units in 17 operating locations in the Gulf Coast, Mid-Continent and Rocky Mountain states.

•

Coiled Tubing Services. Coiled tubing is 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 stimula tion 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 June 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 oil and gas exploration and production companies tend to be relatively sensitive to volatility in oil or natural gas prices because project decisions are tied to a return on investment spanning a number of months or years. As such, capital expenditure economics often require the use of commodity price forecasts which may prove inaccurate over the amount of time necessary to plan and execute a capital expenditure project (such as a drilling program for a number of wells in a certain area). When commodity prices are depressed for longer periods of time, capital expenditure projects are routinely deferred until prices are forecasted to return to an acceptable level.

In contrast, both mandatory and discretionary operating expenditures are more stable than capital expenditures for exploration as these expenditures are less sensitive to commodity price volatility. Mandatory operating expenditure projects involve activities that cannot be avoided in the short term, such as regulatory compliance, safety, contractual obligations and certain projects to maintain the well and related infrastructure in operating condition. Discretionary operating expenditure projects may not be critical to the short-term viability of a lease or field and are generally evaluated according to a simple short-term payout criterion that is less dependent on commodity price forecasts.

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, because existing oil and natural gas wells require ongoing spending to maintain production, expenditures by exploration and production companies for the maintenance of existing wells, which requires a range of production services, are relatively stable and more 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 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.

Market Conditions — 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.

As shown in the charts above, the trends in industry rig counts are influenced primarily by fluctuations in oil prices, which affect the levels of capital and operating expenditures made by our clients. Colombian oil prices have historically trended in line with West Texas Intermediate (WTI) oil prices. Demand for drilling and production services in Colombia is largely dependent upon its national oil company's long-term exploration and production programs, and to a lesser extent, additional activity from other producers in the region.

Technological advancements and trends in our industry also affect the demand for certain types of equipment, and can affect the overall demand for equipment in our industry. For the several years prior to late 2014, generally increasing oil prices drove industry equipment utilization and revenue rates up, particularly in oil-producing regions and certain shale regions. Even though advancements in technology improved the efficiency of drilling rigs, overall demand remained steady, particularly for drilling rigs that are able to drill horizontally. During this same period, the demand for certain drilling rigs decreased, particularly in vertical well markets. The decline was a result of higher demand for drilling rigs that are able to drill horizontally and the increased use of "pad drilling" which enables a series of horizontal wells to be drilled in succession by a walking or skidding drilling rig at a single pad-site location, thereby improving the productivity of exploration and production activities. This trend, then coupled with the current downturn, resulted in significantly reduced demand for drilling rigs that do not have the ability to walk or skid and to drill horizontal wells .

Since late 2014, oil prices have declined significantly resulting in a downturn in our industry, affecting both drilling and production services. 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% , as compared to the respective highest counts during 2014. 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.

In drilling, all rig classes have been 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 . As of June 30, 2016 ,

11 of our 23 domestic drilling rigs are earning revenues, nine of which are under term contracts , two of which have been terminated early . Of the eight rigs in Colombia, three are under term contracts, but 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 to diversify our client base, and evaluating other options, including the possibility of the sale of some or all of our assets in Colombia. Our well servicing and coiled tubing utilization rates for the quarter ended June 30, 2016 were 40% and 20% , respectively, based on total fleet count, and we are currently actively marketing approximately 50% of our wireline fleet.

If oil and natural gas prices again decline, then industry equipment utilization and revenue rates would likely decrease further. Our clients significantly reduced both their operating and capital expenditures during 2015, with further reductions to their spending budgets for 2016. 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.

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

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 65% , reduced wage rates for our operations personnel, reduced incentive compensation, eliminated certain employment benefits and closed a total of ten location offices to reduce overhead and reduce associated lease payments. We will 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 , and placed four additional rigs as held for sale. 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, and we 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. Additionally, we paid down $60 million of debt during 2015.

•

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. During this difficult time, 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 62 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.

We have a current fleet of 31 drilling 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 in recent years 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. With natural gas prices at low levels in recent years, we intentionally increased our exposure to oil-related activities by redeploying certain of our assets into predominately oil-producing regions. With the recent decline in oil prices, 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 $14.6 million as of June 30, 2016 ), cash generated from operations , including payments from the early terminations of drilling contracts, 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 June 30, 2016 , we had $95 million outstanding under our Revolving Credit Facility and $17.3 million in committed letters of credit, which resulted in borrowing availability of $62.7 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 June 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 , including payments from the early terminations of drilling contracts, 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 six months ended June 30, 2016 , we spent $13.2 million on purchases of property and equipment and placed into service property and equipment of $14.0 million . Currently, we expect to spend approximately $27 million to $29 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 , including payments from the early terminations of drilling contracts, proceeds from sales of certain non-strategic assets and from borrowings under our Revolving Credit Facility, if necessary.

Working Capital

Our working capital was $33.3 million at June 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 1.6 at June 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.

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



	June 30, 2016		December 31, 2015		Change
Cash and cash equivalents	$	14,578	$	14,160	$	418
Receivables:
Trade, net of allowance for doubtful accounts	35,810		47,577		(11,767		)
Unbilled receivables	2,121		13,624		(11,503		)
Insurance recoveries	17,611		14,556		3,055
Other receivables	3,337		4,059		(722		)
Inventory	8,640		9,262		(622		)
Assets held for sale	4,513		4,619		(106		)
Prepaid expenses and other current assets	5,889		7,411		(1,522		)
Current assets	92,499		115,268		(22,769		)
Accounts payable	13,077		16,951		(3,874		)
Deferred revenues	2,848		6,222		(3,374		)
Accrued expenses:
Payroll and related employee costs	13,391		13,859		(468		)
Insurance premiums and deductibles	6,530		8,087		(1,557		)
Insurance claims and settlements	14,058		14,556		(498		)
Interest	5,489		5,508		(19		)
Other	3,826		4,859		(1,033		)
Current liabilities	59,219		70,042		(10,823		)
Working capital	$	33,280	$	45,226	$	(11,946	)

The increase in cash and cash equivalents during the six months ended June 30, 2016 is primarily due to $13.6 million of cash provided by operating activities, which includes early termination payments received on certain drilling contracts, and $0.8 million of proceeds from the sale of assets, mostly offset by $13.2 million of cash used for purchases of property and equipment and $0.8 million for the payment of debt issuance costs .

The net decrease in our total trade and unbilled receivables as of June 30, 2016 as compared to December 31, 2015 is primarily the result of the decrease in consolidated revenues of $42.2 million , or 40% , for the quarter ended June 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 June 30, 2016 as compared to December 31, 2015 is primarily due to an insurance claim receivable of $3.4 million for a drilling rig that was damaged during the second quarter of 2016.

The decrease in other receivables as of June 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 June 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 assets as of June 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 eight months of these October premiums at June 30, 2016 , as compared to two months at December 31, 2015 .

The decrease in accounts payable as of June 30, 2016 as compared to December 31, 2015 is primarily due to the 37% decrease in our operating costs for the quarter ended June 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 June 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.

The decrease in accrued payroll and employee related costs as of June 30, 2016 as compared to December 31, 2015 is primarily due to reduced accruals for incentive compensation, partially due to the payment of 2015 annual bonuses in early 2016 which were fully accrued at December 31, 2015, as well as reductions to incentive compensation for reduced headcount. The decrease in accrued payroll and employee related costs was mostly offset by an increase in accrued payroll due to the timing of pay periods and associated withholding and unemployment tax payments.

The decrease in insurance premiums and deductibles as of June 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 June 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 other accrued expenses as of June 30, 2016 as compared to December 31, 2015 is primarily due to a decrease in our property tax and sales tax accruals due to timing of payments.

Long-term Debt and Other Contractual Obligations

The following table includes information about the amount and timing of our contractual obligations at June 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	$	395,000	$	—	$	95,000	$	—	$	300,000
Interest on debt	128,511		24,032		48,065		38,039		18,375
Purchase commitments	6,073		6,073		—		—		—
Operating leases	11,185		3,407		5,018		2,489		271
Incentive compensation	15,692		4,921		10,771		—		—
Total	$	556,461	$	38,433	$	158,854	$	40,528	$	318,646

Debt obligations at June 30, 2016 consist of $300 million of principal amount outstanding under our Senior Notes which mature on March 15, 2022 and $95 million outstanding under our Revolving Credit Facility which is due at maturity on March 31, 2019 . However, we may make principal payments to reduce the outstanding balance under our Revolving Credit Facility prior to maturity when cash and working capital is sufficient.

Interest payment obligations on our Revolving Credit Facility are estimated based on (1) the 6.0% interest rate that was in effect at June 30, 2016 , and (2) the outstanding balance of $95 million at June 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 purchases of new equipment and equipment upgrades, including $4.9 million for 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.

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 June 30, 2016 , we were in compliance with our financial covenants under the Revolving Credit Facility. Our senior consolidated leverage ratio was 2.0 to 1.0 and our interest coverage ratio was 2.4 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:


•	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	3.50	to 1.00	on	June 30, 2016
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	1.50	to 1.00	for the quarterly period ending	June 30, 2016
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 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.

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 June 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 six months ended June 30, 2016 and 2015 (amounts in thousands, except average number of drilling rigs, utilization rate and revenue day information).



	Three months ended June 30,						Six months ended June 30,
	2016			2015			2016			2015
Drilling Services Segment:
Revenues	$	27,959		$	58,559		$	61,143		$	156,974
Operating costs	14,773			32,815			32,213			95,111
Drilling Services Segment margin	$	13,186		$	25,744		$	28,930		$	61,863

Average number of drilling rigs	31.0			37.0			31.0			41.6
Utilization rate	39		%	63		%	43		%	74		%
Revenue days	1,110			2,122			2,420			5,579

Average revenues per day	$	25,188		$	27,596		$	25,266		$	28,137
Average operating costs per day	13,309			15,464			13,311			17,048
Drilling Services Segment margin per day	$	11,879		$	12,132		$	11,955		$	11,089

Production Services Segment:
Revenues	$	34,331		$	76,452		$	76,099		$	171,851
Operating costs	28,742			53,106			63,591			121,874
Production Services Segment margin	$	5,589		$	23,346		$	12,508		$	49,977

Combined:
Revenues	$	62,290		$	135,011		$	137,242		$	328,825
Operating costs	43,515			85,921			95,804			216,985
Combined margin	$	18,775		$	49,090		$	41,438		$	111,840

Net loss	$	(29,991	)	$	(77,281	)	$	(57,690	)	$	(89,300	)
Adjusted EBITDA	$	3,615		$	35,196		$	10,036		$	71,954

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, any loss on extinguishment of debt and any 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 combined 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 June 30,						Six months ended June 30,
	2016			2015			2016			2015
	(amounts in thousands)
Reconciliation of combined margin and Adjusted EBITDA to net loss:
Combined margin	$	18,775		$	49,090		$	41,438		$	111,840
General and administrative	(15,258		)	(18,363		)	(31,766		)	(40,223		)
Bad debt (expense) recovery	(112		)	(394		)	(57		)	(713		)
Gain (loss) on dispositions of property and equipment, net	(508		)	4,377			92			3,244
Other expense	718			486			329			(2,194		)
Adjusted EBITDA	3,615			35,196			10,036			71,954
Depreciation and amortization	(28,922		)	(38,489		)	(58,746		)	(80,271		)
Impairment charges	—			(71,329		)	—			(77,319		)
Interest expense	(6,375		)	(5,245		)	(12,629		)	(10,700		)
Loss on extinguishment of debt	(299		)	—			(299		)	—
Income tax benefit	1,990			2,586			3,948			7,036
Net loss	$	(29,991	)	$	(77,281	)	$	(57,690	)	$	(89,300	)

Both our Drilling Services and Production Services Segments experienced a significant decline in activity during the three and six months ended June 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 six months ended June 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. The decrease in combined margin was partially offset by an increase in average margin per day in our Drilling Services Segment primarily from newly built rigs that were deployed during 2015 and the disposal of mechanical and lower horsepower electric drilling rigs from our fleet during 2015 which generally earned lower margins per day.

Our Drilling Services Segment’s revenues decreased by $30.6 million , or 52% , and $95.8 million , or 61% , for the three and six months ended June 30, 2016 , respectively, as compared to the corresponding periods in 2015 , while operating costs decreased by $18.0 million , or 55% , and $62.9 million , or 66% , respectively. The decreases in our Drilling Services Segment's revenues and operating costs primarily resulted from a decrease in revenue days and lower average operating costs per day. Revenue days decreased primarily due to the significant reduction in demand in our industry. Our average revenues per day decreased by $2,408 per day, or 9% , and $2,871 per day, or 10% , for the three and six months ended June 30, 2016 , respectively, as compared to the corresponding periods in 2015 , while our average

operating costs per day decreased by $2,155 per day, or 14% , and $3,737 per day, or 22% , respectively. Our average revenues and operating costs per day decreased primarily due to reduced activity for our Colombian operations, for which we typically earn higher dayrates and incur higher operating costs per day. Our average operating costs per day also decreased during 2016 due to various cost reduction measures and because we incurred higher costs during the deployment of new rigs in 2015. The overall decrease in average revenues per day was partially offset by the contribution from new drilling rigs deployed during 2015 which operate in higher demand regions and typically earn higher dayrates.

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. The amount of drilling revenues and the number of revenue days associated with drilling contracts that were terminated early for the three and six months ended June 30, 2016 and 2015 are as follows:



	Three months ended June 30,				Six months ended June 30,
	2016		2015		2016		2015
Revenues (in thousands)	$	4,423	$	15,953	$	11,520	$	27,265
Revenue days	182		729		478		1,178

Demand for drilling rigs also influences the types of drilling contracts we are able to obtain. Turnkey drilling contracts result in higher average revenues per day and higher average operating costs per day as compared to daywork drilling contracts. The following table provides the percentages of our drilling revenues by drilling contract type for the three and six months ended June 30, 2016 and 2015 :



	Three months ended June 30,				Six months ended June 30,
	2016		2015		2016		2015
Daywork contracts (not terminated early)	84	%	73	%	80	%	79	%
Daywork contracts terminated early	16	%	27	%	19	%	17	%
Turnkey contracts	—	%	—	%	1	%	4	%

Our Production Services Segment's revenues decreased by $42.1 million , or 55% , and $95.8 million , or 56% , for the three and six months ended June 30, 2016 , respectively as compared to the corresponding periods in 2015 , while operating costs decreased by $24.4 million , or 46% , and $58.3 million , or 48% , 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 22% and 31% for the three and six months ended June 30, 2016 , as compared to the corresponding periods in 2015 . The total rig hours for our well servicing fleet decreased by 42% and 41% , for the three and six months ended June 30, 2016 , as compared to the corresponding periods in 2015 . Our coiled tubing utilization decreased to 20% and 22% for the three and six months ended June 30, 2016 from 24% and 29% 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 have reduced our total headcount by approximately 65% 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 location 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 .

Our general and administrative expense decreased by $3.1 million , or 17% , and $8.5 million , or 21% , for the three and six months ended June 30, 2016 , respectively, as compared to the corresponding periods in 2015 , primarily due to a $5.9 million decrease in compensation and benefit costs during 2016 resulting from the reduction in our workforce, and other efforts taken to minimize various administrative costs such as employee benefits, office and rent expenses and travel.

Our gains of $0.1 million on the disposition of property and equipment during the six months ended June 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 $3.2 million on the disposition of property and equipment during the six months ended June 30, 2015 was primarily for the sale of 27 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 six months ended June 30, 2016 , as compared to net foreign currency losses during the corresponding period in 2015.

Our depreciation and amortization expense decreased by $9.6 million and $21.5 million for the three and six months ended June 30, 2016 , respectively, as compared to the corresponding periods in 2015 , primarily as a result of the sales of drilling rigs and equipment during 2015, as well as 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 partially offset by approximately $5.1 million of depreciation during the six months ended June 30, 2016 for the five new drilling rigs which we deployed in 2015.

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. As a result, we recognized $69.8 million of impairment charges during the second quarter of 2015 to reduce the carrying values of these assets to their estimated fair values. Additionally, during the three and six months ended June 30, 2015 , we recorded impairment charges of $1.5 million and $7.5 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.

Our interest expense increased by $1.1 million and $1.9 million for the three and six months ended June 30, 2016 , respectively, as compared to the corresponding periods in 2015 , 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 six months ended June 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.

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 rate 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 June 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, and our estimate of compensation related accruals.

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 six months ended June 30, 2016 . We incurred a total loss of $0.5 million on 3 of the 16 turnkey contracts completed during the six months ended June 30, 2015 . As of June 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 $1.8 million at June 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 in accordance with ASC Topic 360, Property, Plant and Equipment . 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 , and concluded there are no triggers present that require impairment testing as of June 30, 2016 . 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 June 30, 2016 , we had $111.0 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 June 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 $19.5 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 June 30, 2016 include accruals for costs incurred under the self-insurance portion of our health insurance of approximately $1.5 million and our workers’ compensation, general liability and auto liability insurance of approximately $5.0 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 June 30, 2016 , we had $95.0 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 $0.5 million , and a corresponding increase or decrease, respectively, in net income of approximately $0.3 million during the six months ended June 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 $0.3 million for the six months ended June 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 June 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 June 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 June 30, 2016 . The following table provides information relating to our repurchase of common shares during the quarter ended June 30, 2016 :



Period	Total Number of Shares Purchased (1)	Average Price Paid per Share (2)		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs
April 1 - April 30	24,625	$	3.11	—	—
May 1 - May 31	—	$	—	—	—
June 1 - June 30	1,167	$	3.61	—	—
Total	25,792	$	3.13	—	—


(1)	The shares indicated consist of shares of our common stock tendered by employees to the Company during the three months ended June 30, 2016 , to satisfy the employees’ tax withholding obligations in connection with the vesting of restricted stock unit awards, which we repurchased based on the fair market value on the date the relevant transaction occurred.


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


Item 3.	Defaults Upon Senior Securities

Not applicable.


Item 4.	Mine Safety Disclosures

Not applicable.


Item 5 .	Other Information

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)).

10.1*	-	Fifth Amendment dated as of June 30, 2016, by and among Pioneer Energy Services Corp., a Texas corporations, the lenders party thereto, and Wells Fargo Bank, N.A., as administrative agent for the lenders (Form 8-K dated July 1, 2016 (File No. 1-8182, Exhibit 4.1)).

10.2+*	-	Pioneer Energy Services Corp. Amended and Restated 2007 Incentive Plan (Appendix A of definitive proxy statement on Schedule 14A dated April 18, 2016 (File No. 1-8182)).

10.3+**	-	Pioneer Energy Services Corp. 2007 Incentive Plan Form of Performance Phantom Stock Unit Award Agreement.

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

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

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

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

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

+ Management contract or compensatory plan or arrangement.

SIGNATURES

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

PIONEER ENERGY SERVICES CORP.

/s/ Lorne E. Phillips

Lorne E. Phillips

Executive Vice President and Chief Financial Officer

(Principal Financial Officer and Duly Authorized Officer)

Dated: July 28, 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)).

10.1*	-	Fifth Amendment dated as of June 30, 2016, by and among Pioneer Energy Services Corp., a Texas corporations, the lenders party thereto, and Wells Fargo Bank, N.A., as administrative agent for the lenders (Form 8-K dated July 1, 2016 (File No. 1-8182, Exhibit 4.1)).

10.2+*	-	Pioneer Energy Services Corp. Amended and Restated 2007 Incentive Plan (Appendix A of definitive proxy statement on Schedule 14A dated April 18, 2016 (File No. 1-8182)).

10.3+**	-	Pioneer Energy Services Corp. 2007 Incentive Plan Form of Performance Phantom Stock Unit Award Agreement.

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

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

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

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

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

+ Management contract or compensatory plan or arrangement.

Exhibit 10.3

PERFORMANCE PHANTOM STOCK UNIT AGREEMENT

PIONEER ENERGY SERVICES CORP.

AMENDED AND RESTATED 2007 INCENTIVE PLAN

THIS PERFORMANCE PHANTOM STOCK UNIT AGREEMENT (this “ Agreement ”) is made as of <<Date>> , by and between Pioneer Energy Services Corp. (the “ Company ”) and <<Name>> (the “ Employee ”) pursuant to the Pioneer Energy Services Corp. Amended and Restated 2007 Incentive Plan (Effective <<Date>>) (the “ Plan ”). Capitalized terms are defined in the Plan if not defined herein.

The Compensation Committee of the Board of Directors of the Company (the “ Committee ”) desires to benefit the Company by increasing motivation on the part of the Employee, who is materially important to the Company, by creating an incentive to remain as an employee of the Company and to work to the very best of the Employee’s abilities.

To further this purpose, the Company desires to make an award (the “ Award ”) of phantom stock units (the “ Phantom Stock Units ”) to the Employee under the terms of the Plan.

Pursuant to official action of the Committee on <<Date>> (the “ Date of Award ”), the Company undertook to grant the Award contemplated by this Agreement to the Employee.

1. Grant of Phantom Stock Units . Subject to the vesting and other terms and conditions set forth in this Agreement, the Employee is hereby awarded a target number of <<Number>> Phantom Stock Units; provided , that , the number of Phantom Stock Units that the Employee may earn pursuant to this Award shall range from 0% to 200% of the target number Phantom Stock Units depending on the Company’s performance during the performance period that begins <<Performance Period>> (the “ Performance Period ”), as determined by the Committee in accordance with the performance conditions set forth in Exhibit A . Any Phantom Stock Units that are not earned in accordance with the immediately preceding sentence or Section 4(b) will terminate and be cancelled effective as of the last day of the Performance Period.

2. Nature of Phantom Stock Units . Each earned Phantom Stock Unit represents an unfunded, unsecured right to receive upon vesting an amount (the “ Settlement Amount ”) determined as follows:

(a) If the Phantom Stock Unit vests pursuant to Section 4(a) , the Settlement Amount shall be the lesser of (i) the average for the last fourteen (<<Number>>) trading days in <<Date>> of the Fair Market Value of the Company’s common stock, par value $0.10 per share (“ Common Stock ”) or (b) <<Share Price>>; and

(b) If the Phantom Stock Unit vests pursuant to Section 4(b) , the Settlement Amount shall be the lesser of (i) the average for the fourteen (14) trading days immediately preceding the

date on which the Phantom Stock Unit vests of the Fair Market Value of the Common Stock, or (b) <<Share Price>>.

3. Settlement of Earned Phantom Stock Units . Payment of the Settlement Amount for earned Phantom Stock Units that vest pursuant to Section 4(a) shall be made to the Employee in < Settlement Date> (the “ Settlement Date ”). Payment of the Settlement Amount for Phantom Stock Units that vest pursuant to Section 4(b) shall be made to the Employee as soon as practicable following vesting. In the Committee’s discretion, payment of the Settlement Amount shall be made (a) in the form of a lump sum cash payment, (b) by issuing, in the Employee’s name, a number of shares of Common Stock having a Fair Market Value on the Vesting Date (defined below) equal to the Settlement Amount, or (c) a combination of cash and shares of Common Stock. Payment shall be subject to withholding for taxes in accordance with Section 11 .

4. Vesting .

(a) Performance-Based Vesting . Subject to Section 4(b) below, the earned Phantom Stock Units shall vest on the date immediately preceding the Settlement Date (the “ Vesting Date ”).

(b) Accelerated Vesting Upon Certain Events .

(i) Change in Control . If either (A) the Employee remains continuously employed by the Company or a subsidiary of the Company through the date on which such Change in Control occurs or (B) the Employee’s employment or other service with the Company and its subsidiaries is involuntarily terminated without Cause on or after the thirtieth (30 ^th ) day prior to the date on which such Change in Control occurs, the Employee shall, upon the occurrence of the Change in Control, automatically earn and vest in the maximum potential number of Phantom Stock Units set forth in Section 1 .

(ii) If the Employee’s employment or other service with the Company and its subsidiaries terminates as a result of the Employee’s death or Disability, the Employee shall, upon such event, automatically earn and vest in the target number of Phantom Stock Units set forth in Section 1 . Any Phantom Stock Units that are not earned and vested after giving effect to the foregoing shall immediately terminate and be cancelled.

5. Effect of Termination of Employment . The Phantom Stock Units (as well as the related Dividend Equivalent Rights) shall terminate to the extent such Phantom Stock Units have not become earned and vested in accordance with Section 4 prior to the first date the Employee is no longer employed by the Company or one of its subsidiaries, except where the Employee’s termination of employment is as a result of the Employee’s death or Disability.

6. Limitations on Rights Associated with Phantom Stock Units . The Employee shall have no rights as a shareholder of the Company, no dividend rights and no voting rights with respect to the any shares of Common Stock underlying the Phantom Stock Units unless and until such shares of Common Stock are actually issued to and held of record by the Employee.

7. Provisions of the Plan Control . The Award is made pursuant to the Plan and is subject to the terms and provisions of the Plan and this Agreement. The terms and provisions of the Plan are incorporated into this Agreement and will govern to the extent that the terms and provisions in this Agreement conflict with the terms and provisions of the Plan. The Employee acknowledges receipt of a copy of the Plan prior to executing this Agreement.

8. Limitations on the Employee’s Rights . Participation in the Plan confers no rights or interests other than as herein provided. This Agreement creates only a contractual obligation on the part of the Company as to amounts payable and shall not be construed as creating a trust. Neither the Plan nor any underlying program, in and of itself, has any assets. The Employee shall have only the rights of a general unsecured creditor of the Company with respect to amounts credited and payable, if any, with respect to the Phantom Stock Units and associated Dividend Equivalent Rights, as and when payable hereunder.

9. Adjustments Upon Specified Events . Upon the occurrence of certain events relating to the Company’s Common Stock contemplated by Section 12 of the Plan (including, without limitation, declaration of an extraordinary dividend or other extraordinary distribution (whether in the form of cash, Common Stock or other property), stock split or reverse stock split), the Committee shall make adjustments in accordance with such section in the number of Phantom Stock Units then outstanding. For avoidance of doubt, no such adjustment shall be made with respect to any ordinary cash dividend.

10. Compliance with Section 409A . It is intended that the terms of the Award will not result in the imposition of any accelerated taxation or tax penalties under Section 409A of the Code. This Agreement shall be construed and interpreted consistent with that intent.

11. Responsibility for Taxes; Withholding .

(a) The Employee acknowledges that the ultimate liability for any and all income tax (including U.S. federal, state and local tax or non-U.S. tax) arising in connection with the grant, vesting and/or settlement of this Award is and remains the Employee’s responsibility. The Employee further acknowledges that the Company (i) makes no representations or undertakings regarding the tax treatment of any aspect of the Award and (ii) does not commit to and is under no obligation to structure any aspect of the Award to reduce or eliminate the Employee’s tax liability or achieve any particular tax result.

(b) The grant and settlement of this Award shall be subject to the satisfaction of all applicable federal, state and local income and employment tax withholding requirements (the “ Required Withholding ”). In this regard, the Employee authorizes the Company, at its discretion and pursuant to such procedures as it may specify from time to time, to satisfy the Required Withholding by one or a combination of the following: (i) withholding from any wages or other cash compensation payable to the Employee by the Company or a subsidiary; (ii) withholding from the Settlement Amount otherwise payable to the Employee (whether such Settlement Amount is payable in the form of cash or shares of Common Stock); (iii) withholding from any Dividend Equivalent Rights payable upon vesting or settlement of the Award; or (iv) arranging for the sale of shares of Common Stock otherwise deliverable to the Employee in settlement of the Award (on

the Employee’s behalf and at the Employee’s direction pursuant to this authorization) and withholding the Required Withholding from the proceeds of such sale of shares of Common Stock. By execution of this Agreement, the Employee shall be deemed to have authorized the satisfaction of the Required Withholding by the Company as provided herein, and agrees to pay to the Company any portion of the Required Withholding that cannot be satisfied by the foregoing means.

12. No Service Rights . This Agreement is not a services or employment agreement and nothing contained in the Plan or this Agreement shall be interpreted or construed to confer upon the Employee any right with respect to the continuation of the Employee’s employment or other service with the Company or any subsidiary of the Company or interfere in any way with the right of the Company or any subsidiary of the Company at any time to terminate such relationship.

13. Recoupment of Incentive Compensation Policy . Notwithstanding any other provision of this Agreement to the contrary, the Phantom Stock Units, any cash or shares of Common Stock issued in settlement of the Phantom Stock Units, and any amount received with respect to any sale of any such shares of Common Stock, shall be subject to potential cancellation, recoupment, rescission, payback or other action in accordance with the terms of the Company’s Recoupment of Incentive Compensation Policy, as it may be amended from time to time (the “ Policy ”). The Employee agrees and consents to the Company’s application, implementation and enforcement of (a) the Policy and (b) any provision of applicable law relating to cancellation, rescission, payback or recoupment of compensation, and expressly agrees that the Company may take such actions as are necessary to effectuate the Policy or applicable law without further consent or action being required by the Employee. To the extent that the terms of this Agreement and the Policy conflict, then the terms of the Policy shall prevail.

14. Non-transferability . The Employee’s rights under this Agreement may not be sold, assigned, pledged, exchanged, hypothecated or otherwise disposed of, encumbered or transferred, except (a) to the Company or (b) upon the Employee’s death to a beneficiary designated by the Employee (subject to the terms of this Agreement and the Plan) or if no beneficiary has been duly designated or no duly designated beneficiary survives the Employee, pursuant to the Employee’s will or the laws of descent and distribution. Any attempted sale, assignment, pledge, exchange, hypothecation, disposition, encumbrance or transfer in violation of this Agreement shall be void and the Company and its Affiliates will not be bound thereby.

15. Severability . If any portion of this Agreement is determined to be in violation of any statute or public policy, then only the portion(s) of this Agreement that have been found to violate such statute or public policy shall be deleted and all portions of this Agreement that have not been found to violate any statute or public policy will continue in full force and effect. Furthermore, it is the parties’ intent that any order that requires deletion of any portion of this Agreement should modify the deleted portion of the Agreement as narrowly as possible to give as much effect as possible to the intentions of the parties hereto.

16. Limitation of Liability . Under no circumstances will the Company or any Affiliate be liable for any indirect, incidental, consequential or special damages (including lost profits) of any form incurred by any Person, whether or not foreseeable and regardless of the form of the act in which such a claim may be brought, with respect to this Agreement, the Award or the Plan.

17. Governing Law . This Agreement shall be governed by and construed in accordance with the laws of the State of Texas, without regard to its conflicts of law provisions.

18. Amendment and Waiver . Except as otherwise provided in this Agreement or the Plan, this Agreement may be amended, modified or superseded only by written instrument executed by the Company and the Employee. Only a written instrument executed and delivered by the party waiving compliance hereof shall make any waiver of the terms or conditions effective. Any waiver granted by the Company shall be effective only if executed and delivered by a duly authorized executive officer of the Company. The failure of any party at any time or times to require performance of any provisions hereof shall in no manner affect the right to enforce the same. No waiver by any party of any term or condition, or of any breach of any term or condition, contained in this Agreement, in one or more instances, shall be construed as a continuing waiver of any such condition or breach, a waiver of any other term or condition, or a waiver of any breach of any other term or condition.

19. Miscellaneous . This Agreement shall be binding upon and shall inure to the benefit of the parties hereto and their respective successors and permitted assigns, including any successor to the Company as the result of a direct or indirect purchase, merger, consolidation or similar transaction involving all or substantially all of the Company’s business or assets. This Agreement constitutes the entire agreement between the parties with respect to the subject matter hereof.

20. Certain Definitions .

(a) The term “ Affiliate ” means, with respect to any Person, any other Person that, directly or indirectly through one or more intermediaries, controls, is controlled by or is under common control with the Person in question. As used herein, the term “control” means the possession, direct or indirect, of the power to direct or cause the direction of the management and policies of a Person, whether through ownership of voting securities, by contract or otherwise.

(b) The term “ Associate ” means, with reference to any Person, (i) any corporation, firm, partnership, association, unincorporated organization or other entity (other than the Company or any of its Affiliates) of which that Person is an officer or general partner (or officer or general partner of a general partner) or is, directly or indirectly, the beneficial owner of 10% or more of any class of its equity securities, (ii) any trust or other estate in which that Person has a substantial beneficial interest or for or of which that Person serves as trustee or in a similar fiduciary capacity and (iii) any relative or spouse of that Person, or any relative of that spouse, who has the same home as that Person.

(d) The term “ Cause ” means, with reference to the Employee, (i) the commission by the Employee of (A) any felony or (B) any other crime or offense involving moral turpitude or dishonesty or involving money or other property of the Company or any Affiliate of the Company; (ii) the Employee’s participation in a fraud or act of dishonesty against the Company or any Affiliate of the Company; (iii) the Employee’s willful breach of the policies of the Company or of any Affiliate of the Company; (iv) the Employee’s intentional damage to the property of the Company or of any

Affiliate of the Company; (v) any material breach by the Employee of any agreement between the Employee and the Company or any Affiliate of the Company; (vi) any unauthorized use or disclosure by the Employee of confidential information or trade secrets of the Company or its Affiliates; (vii) the Employee’s refusal or willful failure to substantially perform his or her employment duties; (viii) the Employee’s receipt of any bribe or kickback in connection with the Company’s or its Affiliates’ business; or (ix) the Employee’s willful engagement in material misconduct that results in damage to the Company or to its Affiliates or results in adverse publicity, public contempt or public ridicule of the Employee or the Company or its Affiliates. The determination by the Board or the Committee as to whether Cause exists shall be final, conclusive and binding on the Employee.

(e) The term “ Change in Control ” means the occurrence of any of the following after the Date of Award:

(i) any Person (other than an Exempt Person) is or becomes the beneficial owner of Voting Stock (not including any securities acquired directly from the Company after the date the Plan first became effective) representing 40% or more of the combined voting power of the Voting Stock then outstanding; provided , however , that a Change in Control will not be deemed to occur under this clause (i) if a Person becomes the beneficial owner of Voting Stock representing 40% or more of the combined voting power of the Voting Stock then outstanding solely as a result of a reduction in the number of shares of Voting Stock outstanding which results from the Company’s repurchase of Voting Stock, unless and until such time as that Person or any Affiliate or Associate of that Person purchases or otherwise becomes the beneficial owner of additional shares of Voting Stock constituting 1% or more of the combined voting power of the Voting Stock then outstanding, or any other Person (or Persons) who is (or collectively are) the beneficial owner of shares of Voting Stock constituting 1% or more of the combined voting power of the Voting Stock then outstanding becomes an Affiliate or Associate of that Person, unless, in either such case, that Person, together with all its Affiliates and Associates, is not then the beneficial owner of Voting Stock representing 40% or more of the Voting Stock then outstanding; or

(ii) the following individuals cease for any reason to constitute a majority of the number of Directors then serving on the Company’s Board: (1) individuals who on the date the Plan first became effective constitute the Board; and (2) any new Director (other than a Director whose initial assumption of office is in connection with an actual or threatened election contest relating to the election of Directors of the Company) whose appointment or election by the Board or nomination for election by the Company’s shareholders was approved or recommended by a majority vote of the Directors then still in office who either were Directors on the date the Plan first became effective or whose appointment, election or nomination for election was previously so approved or recommended; or

(iii) there is consummated a merger or consolidation of the Company or any parent or direct or indirect subsidiary of the Company with or into any other corporation, other than: (A) a merger or consolidation which results in the Voting Stock outstanding immediately prior to such merger or consolidation continuing to represent (either by remaining outstanding or by being converted into voting securities of the surviving entity

or any parent thereof) at least 50% of the combined voting power of the securities which entitle the holder thereof to vote generally in the election of members of the Board or similar governing body of the Company or such surviving entity or any parent thereof outstanding immediately after such merger or consolidation; or (B) a merger or consolidation effected to implement a recapitalization of the Company (or similar transaction) in which no Person (other than an Exempt Person) is or becomes the beneficial owner of Voting Stock (not including, for purposes of this determination, any Voting Stock acquired directly from the Company or its subsidiaries after the date the Plan first became effective other than in connection with the acquisition by the Company or one of its subsidiaries of a business) representing 40% or more of the combined voting power of the Voting Stock then outstanding; or

(iv) the shareholders of the Company approve a plan of complete liquidation or dissolution of the Company, or there is consummated an agreement for the sale or disposition of all or substantially all of the Company’s assets, unless (A) the sale is to an entity of which at least 50% of the combined voting power of the securities which entitle the holder thereof to vote generally in the election of members of the board of directors or similar governing body of such entity (“ New Entity Securities ”) are owned by shareholders of the Company in substantially the same proportions as their ownership of the Voting Stock immediately prior to such sale; (B) no Person other than the Company and any employee benefit plan or related trust of the Company or of such corporation then beneficially owns 40% or more of the New Entity Securities; and (C) at least a majority of the directors of such corporation were members of the incumbent Board at the time of the execution of the initial agreement or action providing for such disposition.

Notwithstanding the foregoing, if required to avoid accelerated taxation or tax penalties under Section 409A of the Code, a Change in Control shall be deemed to have occurred for purposes of the settlement of the Award only if a “change in the ownership of the corporation,” a “change in effective control of the corporation” or a “change in the ownership of a substantial portion of the assets of the corporation,” within the meaning of Section 409A(a)(2)(A)(v) of the Code shall also be deemed to have occurred.

(f) The term “ Committee ” means the Compensation Committee of the Board.

(g) The term “ Disability ” means the absence of the Employee from the Employee’s duties with the Company or any of its Affiliates on a full-time basis for at least 180 consecutive days as a result of incapacity due to mental or physical illness or injury which is determined by the Committee in its sole discretion to be permanent. Notwithstanding the foregoing, if required to avoid accelerated taxation or tax penalties under Section 409A of the Code, a “Disability” shall be deemed to have occurred for purposes of this Agreement only if the Employee is also “disabled” within the meaning of Section 409A(a)(2)(C) of the Code.

(h) The term “ Exempt Person ” means: (i) the Company; (ii) any Affiliate of the Company; (iii) any employee benefit plan of the Company or of any Affiliate and any Person organized, appointed or established by the Company for or pursuant to the terms of any such plan or for the purpose of funding any such plan or funding other employee benefits for employees of

the Company or any Affiliate of the Company; or (iv) any corporation or other entity owned, directly or indirectly, by the shareholders of the Company in substantially the same proportions as their ownership of capital stock of the Company.

(i) The “ Fair Market Value ” of a share of Common Stock means, as of a particular date, (i) if shares of Common Stock are listed on a national securities exchange, the closing sales price per share of Common Stock on the consolidated transaction reporting system for the principal national securities exchange on which shares of Common Stock are listed on that date, or, if there shall have been no such sales reported on that date, on the last preceding date on which such a sale was so reported, (ii) if the Common Stock is not so listed, the mean between the closing bid and asked price on that date, or, if there are no such prices available for such date, on the last preceding date on which such prices shall be available, as reported by the National Quotation Bureau Incorporated, or (iii) if shares of Common Stock are not publicly traded, the most recent value determined by an independent appraiser appointed by the Company for such purpose.

(j) The term “ Person ” has the meaning given in Section 3(a)(9) of the Exchange Act, as modified and used in Sections 13(d) and 14(d) thereof.

(k) The term “ Voting Stock ” means the Common Stock and any other securities issued by the Company that entitle the holder thereof to vote generally in the election of members of the Board.

[Signature Page Follows]

IN WITNESS WHEREOF , the Company has caused this Phantom Stock Unit Agreement to be duly executed by an officer thereunto duly authorized, and the Employee has executed this Agreement, all effective as of the date first above written.

PIONEER ENERGY SERVICES CORP.:

By:

Name: <<Company Officer>>

Title: <<Title>>

EMPLOYEE:

Name: <<Name>>

Address: <<Address>>

[SIGNATURE PAGE TO PHANTOM STOCK UNIT AGREEMENT]

Performance Phantom Stock Unit Agreement

Exhibit A

Performance Vesting Requirements

EXHIBIT A - EMPLOYEE NAME

Performance Period : <<Performance Period>>

Grant Date Phantom Share Value : <<Share Value>>

Grant Dates Phantom Share Units: «PBPhantom_Shares»

The Awarded Phantom Share Units (APSU) will equal the Grant Date Phantom Share Units (GDPSU) set forth above multiplied by the Award Percentage (AP) corresponding to the achievement of the Performance Goals set forth below. In other words: APSU = GDPSU x AP .

Performance Goals : The performance of the Company during the Performance Period will be compared against a peer group of companies in the following three metrics:


1.	EBITDA growth: Measure the change of the ending EBITDA at <<Date>> vs. the ending EBITDA on <<End Date>>.


2.	EBITDA return on capital employed: ROCE computation is Quarterly Annualized EBITDA / (Average Equity + Average Debt); Note: Average Equity plus Avg. Debt For the Quarter. Computation of Cum. Average ROCE: Final computation will consist of a simple average of << Number>> quarters (Q<<Number>> <<Year>> through Q<<Number>> <<Year>>).

Total Shareholder Return (TSR): Measure the TSR (including dividends) using the change of the stock price at the beginning of the Performance Period as determined by the average of the first <<Number>> consecutive trading days in <<Month>>, <<Year>> vs. the stock price at the end of the Performance Period as determined by the average of the last <<Number>> consecutive trading days in <<Month>>,<<Year>> for each member of the peer group.

The peer group: <<Peer Group>>

The results for TSR shall be weighted at <<Metric Weighting>> and the other two metrics at <<Metric Weighting>> each. Each member of the peer group will be ranked based on the results of those metrics. The award will be determined on the ranking of those measurements paid as follows on a sliding scale:



Company Ranking	Metric Percentage
<25 ^th Percentile:	0%
25th Percentile:	25%
50th Percentile:	100%
90th Percentile:	200%

The Metric Percentage for any ranking achieved between 25 ^th and 50 ^th percentiles and between 50 ^th and 90 ^th percentiles will be proportional to the percentile achieved. For example, achievement of the 37.5 ^th percentile would result in a 62.5% Metric Percentage, achievement of the 43.75 ^th percentile would result in a 83.3% Metric Percentage and achievement of the 70 ^th percentile would result in a 150% Metric Percentage.

The Award Percentage (AP) will be calculated as the weighted average of the three Metric Percentages.

Phantom share units award quantity and value is determined at the end of the performance period <<Ending Date>> and vests 100% <<Vesting Date>>, subject to Employee’s continuous employment through such vesting date. Performance-based phantom share unit quantities will be calculated after receipt of public filings of peer group on or about <<Qtr>> <<Year>>. Ending phantom share unit value (EPSUV) shall be the average closing price of PES for the last <<Number>> trading days in <<Month>>,<<Year>> and be capped at a maximum of <<Number>>X Grant Date Phantom Share Value (i.e., <<Share Price>>).

Subject to the EPSUV cap mentioned above the award value shall be determined as: APSU = GDPSU x AP

Awarded value = EPSUV x APSU

Exhibit 31.1

I, Wm. Stacy Locke, certify that:


1.	I have reviewed this quarterly report on Form 10-Q of Pioneer Energy Services Corp.;


2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;


3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;


4.	The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:


(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;


(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;


(c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and


(d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and


5.	The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):


(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and


(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

July 28, 2016

/s/ Wm. Stacy Locke

Wm. Stacy Locke

President and Chief Executive Officer

Exhibit 31.2

I, Lorne E. Phillips, certify that:


1.	I have reviewed this quarterly report on Form 10-Q of Pioneer Energy Services Corp.;


2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;


3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;


4.	The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:


(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;


(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;


(c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and


(d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and


5.	The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):


(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and


(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

July 28, 2016

/s/ Lorne E. Phillips

Lorne E. Phillips

Executive Vice President and Chief Financial Officer

Exhibit 32.1

Officer’s Certification Pursuant to

Section 906 of the Sarbanes-Oxley Act of 2002

(18 U.S.C 1350)

In connection with the Quarterly Report on Form 10-Q of Pioneer Energy Services Corp., a Texas corporation, (the “Company”) for the quarter ended June 30, 2016 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), the undersigned, Wm. Stacy Locke, President and Chief Executive Officer, hereby certifies, pursuant to 18 U.S.C. Section 1350, that, to the best of his knowledge:

(1) The Report is in full compliance with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.



Dated:	July 28, 2016	/s/ Wm. Stacy Locke
		Wm. Stacy Locke
		President and Chief Executive Officer

Exhibit 32.2

Officer’s Certification Pursuant to

Section 906 of the Sarbanes-Oxley Act of 2002

(18 U.S.C 1350)

In connection with the Quarterly Report on Form 10-Q of Pioneer Energy Services Corp., a Texas corporation, (the “Company”) for the quarter ended June 30, 2016 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), the undersigned, Lorne E. Phillips, Executive Vice President and Chief Financial Officer, hereby certifies, pursuant to 18 U.S.C. Section 1350, that, to the best of his knowledge:

(1) The Report is in full compliance with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.



Dated:	July 28, 2016	/s/ Lorne E. Phillips
		Lorne E. Phillips
		Executive Vice President and Chief Financial Officer