PIONEER ENERGY SERVICES CORP - FORM 10-Q

Attached files

file	filename
EX-32.2 - EXHIBIT 32.2 - PIONEER ENERGY SERVICES CORP	exhibit3223q2015.htm
EX-32.1 - EXHIBIT 32.1 - PIONEER ENERGY SERVICES CORP	exhibit3213q2015.htm
EX-31.1 - EXHIBIT 31.1 - PIONEER ENERGY SERVICES CORP	exhibit3113q2015.htm
EX-31.2 - EXHIBIT 31.2 - PIONEER ENERGY SERVICES CORP	exhibit3123q2015.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

______________________________________________

FORM 10-Q

______________________________________________

(Mark one)



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

For the quarterly period ended September 30, 2015



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	x	Accelerated filer	o

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

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

As of October 15, 2015, there were 64,497,915 shares of common stock, par value $0.10 per share, of the registrant outstanding.

PART I. FINANCIAL INFORMATION


Item 1.	Financial Statements

PIONEER ENERGY SERVICES CORP. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS



	September 30, 2015			December 31, 2014
	(unaudited)			(audited)
	(in thousands, except share data)
ASSETS
Current assets:
Cash and cash equivalents	$	35,679		$	34,924
Receivables:
Trade, net of allowance for doubtful accounts	51,963			136,161
Unbilled receivables	7,653			38,002
Insurance recoveries	14,947			10,900
Other receivables	7,410			5,138
Deferred income taxes	6,299			10,998
Inventory	8,995			14,117
Assets held for sale	2,065			9,909
Prepaid expenses and other current assets	5,927			8,925
Total current assets	140,938			269,074
Property and equipment, at cost	1,509,931			1,702,273
Less accumulated depreciation	731,235			845,732
Net property and equipment	778,696			856,541
Intangible assets, net of accumulated amortization of $46.1 million and $40.3 million at September 30, 2015 and December 31, 2014, respectively	18,268			24,223
Noncurrent deferred income taxes	—			2,753
Other long-term assets	11,226			18,998
Total assets	$	949,128		$	1,171,589

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	35,072		$	64,305
Current portion of long-term debt	—			27
Deferred revenues	14,772			3,315
Accrued expenses:
Payroll and related employee costs	16,934			40,058
Insurance premiums and deductibles	8,302			12,829
Insurance claims and settlements	14,947			10,900
Interest	861			5,432
Other	6,419			10,326
Total current liabilities	97,307			147,192
Long-term debt, less current portion	410,000			455,053
Noncurrent deferred income taxes	48,745			69,578
Other long-term liabilities	4,193			4,702
Total liabilities	560,245			676,525
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; 64,497,915 and 63,820,126 shares outstanding at September 30, 2015 and December 31, 2014, respectively	6,496			6,414
Additional paid-in capital	473,763			472,457
Treasury stock, at cost; 458,170 and 317,103 shares at September 30, 2015 and December 31, 2014, respectively	(3,759		)	(3,030		)
Accumulated earnings (deficit)	(87,617		)	19,223
Total shareholders’ equity	388,883			495,064
Total liabilities and shareholders’ equity	$	949,128		$	1,171,589

See accompanying notes to condensed consolidated financial statements.

PIONEER ENERGY SERVICES CORP. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(unaudited)



	Three months ended September 30,						Nine months ended September 30,
	2015			2014			2015			2014
	(in thousands, except per share data)
Revenues:
Drilling services	$	41,238		$	128,117		$	198,212		$	373,627
Production services	66,242			145,150			238,093			398,486
Total revenues	107,480			273,267			436,305			772,113

Costs and expenses:
Drilling services	22,875			88,963			118,114			250,904
Production services	48,643			89,993			170,517			250,140
Depreciation and amortization	35,257			46,081			115,528			137,398
General and administrative	16,814			26,613			56,909			76,372
Bad debt expense (recovery)	(1,071		)	19			(358		)	456
Impairment charges	2,329			678			79,648			678
Loss (gain) on dispositions of property and equipment	605			142			(2,639		)	(1,589		)
Gain on sale of fishing and rental services operations	—			(10,702		)	—			(10,702		)
Gain on litigation	—			(1,324		)	—			(4,200		)
Total costs and expenses	125,452			240,463			537,719			699,457
Income (loss) from operations	(17,972		)	32,804			(101,414		)	72,656

Other (expense) income:
Interest expense, net of interest capitalized	(5,465		)	(8,969		)	(16,165		)	(32,085		)
Loss on extinguishment of debt	—			—			—			(22,482		)
Other	(785		)	(1,455		)	(2,979		)	360
Total other expense	(6,250		)	(10,424		)	(19,144		)	(54,207		)

Income (loss) before income taxes	(24,222		)	22,380			(120,558		)	18,449
Income tax (expense) benefit	6,682			(9,927		)	13,718			(8,894		)
Net income (loss)	$	(17,540	)	$	12,453		$	(106,840	)	$	9,555

Income (loss) per common share—Basic	$	(0.27	)	$	0.20		$	(1.66	)	$	0.15

Income (loss) per common share—Diluted	$	(0.27	)	$	0.19		$	(1.66	)	$	0.15

Weighted average number of shares outstanding—Basic	64,449			63,451			64,262			62,960

Weighted average number of shares outstanding—Diluted	64,449			65,876			64,262			65,167

See accompanying notes to condensed consolidated financial statements.

PIONEER ENERGY SERVICES CORP. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited)



	Nine months ended September 30,
	2015			2014
	(in thousands)
Cash flows from operating activities:
Net income (loss)	$	(106,840	)	$	9,555
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization	115,528			137,398
Allowance for doubtful accounts	(358		)	408
Gain on dispositions of property and equipment	(2,639		)	(1,589		)
Stock-based compensation expense	2,275			5,761
Amortization of debt issuance costs, discount and premium	1,737			2,193
Gain on sale of fishing and rental services operations	—			(10,702		)
Loss on extinguishment of debt	—			22,482
Impairment charges	79,648			678
Deferred income taxes	(15,048		)	5,395
Change in other long-term assets	438			8,247
Change in other long-term liabilities	(509		)	(1,385		)
Changes in current assets and liabilities:
Receivables	113,686			(29,428		)
Inventory	1,533			(1,094		)
Prepaid expenses and other current assets	3,233			3,030
Accounts payable	(29,547		)	11,802
Deferred revenues	11,457			2,545
Accrued expenses	(35,529		)	(10,366		)
Net cash provided by operating activities	139,065			154,930

Cash flows from investing activities:
Purchases of property and equipment	(130,390		)	(120,738		)
Proceeds from sale of fishing and rental services operations	—			15,090
Proceeds from sale of property and equipment	37,803			7,197
Proceeds from insurance recoveries	227			—
Net cash used in investing activities	(92,360		)	(98,451		)

Cash flows from financing activities:
Debt repayments	(45,003		)	(360,019		)
Proceeds from issuance of debt	—			320,000
Debt issuance costs	(999		)	(9,173		)
Tender premium costs	—			(15,381		)
Proceeds from exercise of options	781			8,280
Purchase of treasury stock	(729		)	(1,132		)
Net cash used in financing activities	(45,950		)	(57,425		)

Net increase (decrease) in cash and cash equivalents	755			(946		)
Beginning cash and cash equivalents	34,924			27,385
Ending cash and cash equivalents	$	35,679		$	26,439

Supplementary disclosure:
Interest paid	$	21,543		$	41,188
Income tax paid	$	2,659		$	3,475
Noncash investing and financing activity:
Change in capital expenditure accruals	$	308		$	9,840

See accompanying notes to condensed consolidated financial statements.

PIONEER ENERGY SERVICES CORP. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1. Organization and Summary of Significant Accounting Policies

Business

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



Drilling Division	Rig Count
South Texas	10
West Texas	8
North Dakota	8
Appalachia	4
Colombia	8
	38

We have deployed four new-build 1,500 horsepower AC drilling rigs under multi-year term contracts during 2015 and expect to complete construction of one more new-build drilling rig by the end of the year. We also sold 28 of our mechanical and lower horsepower electric drilling rigs during 2015 which were the most negatively impacted by the industry downturn.

We expect to end 2015 with a drilling fleet of 39 rigs, of which 95% will be capable of drilling horizontally, with all but one of our AC rigs built within the last five years. The removal of older, less capable rigs from our fleet and the recent and ongoing investments in the construction of new-builds is transforming our fleet into a highly capable, pad optimal fleet focused on the horizontal drilling market.

Currently, 21 of our 38 drilling rigs are earning revenues under drilling contracts, 16 of which are earning under domestic term contracts, and three of which are under term contracts in Colombia. We are actively marketing our five remaining 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 Production Services Segment provides a range of services to exploration and production companies, including well servicing, wireline services and coiled tubing services. Our production services operations are concentrated in the major United States onshore oil and gas producing regions in the Mid-Continent and Rocky Mountain states and in the Gulf Coast, both onshore and offshore. As of September 30, 2015, we have a fleet of 124 well servicing rigs, consisting of 113 rigs with 550 horsepower and 11 rigs with 600 horsepower, 125 wireline units and 17 coiled tubing units. Our well servicing and coiled tubing utilization rates for the quarter ended September 30, 2015 were 62% and 25%, respectively, based on total fleet count, and we are currently actively marketing approximately 50% of our wireline fleet.

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 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.

In response to the significant decline in oil prices over the last year, term contracts for 16 of our drilling rigs have been early terminated, including five of our 19 drilling rigs that are currently earning revenues under term contracts, resulting in approximately $53.0 million of early termination revenues. Revenues derived from these early terminations are deferred and recognized over the remainder of the original term of the drilling contracts. We recognized $11.7 million and $39.0 million of revenue for early termination payments during the three and nine months ended September 30, 2015, respectively, and $0.3 million in the fourth quarter of 2014.

In September 2015, we entered into long-term contracts for three of our drilling rigs in Colombia which are cancelable without penalty provided that our client gives 30 days notice. Including these three contracts in Colombia and the new-build drilling rig that we deployed in early October 2015, 19 of our drilling rigs are currently earning revenues under term contracts, which if not renewed prior to the end of their terms, will expire as follows:



		Term Contract Expiration by Period
	Total Term Contracts	Within 6 Months	6 Months to 1 Year	1 Year to 18 Months	18 Months to 2 Years	2 to 4 Years
United States	16	6	5	—	—	5
Colombia	3	—	1	—	—	2
	19	6	6	—	—	7

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, 2014.

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 deferred taxes, 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 September 30, 2015, 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 $7.7 million at September 30, 2015, of which $6.8 million represented revenue recognized but not yet billed on daywork drilling contracts in progress at September 30, 2015 and $0.9 million related to unbilled receivables for our Production Services Segment. At December 31, 2014, our unbilled receivables totaled $38.0 million, of which $32.8 million represented revenue recognized but not yet billed on daywork drilling contracts in progress at December 31, 2014, $0.8 million related to turnkey drilling contract revenues, and $4.4 million related to unbilled receivables for our Production Services Segment. As of September 30, 2015, we did not have any turnkey contracts 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.

Intangible Assets

Our intangible assets were recorded in connection with the acquisitions of production services businesses and are subject to amortization. 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). If the sum of the estimated future undiscounted net cash flows is less

than the carrying amount of the asset group, then we would determine the fair value of the asset group. The amount of an impairment charge would be measured as the difference between the carrying amount and the fair value of these assets. The assumptions used in the impairment evaluation for long-lived assets are inherently uncertain and require management judgment.

Other Long-Term Assets

Other long-term assets consist of debt issuance costs net of amortization, cash deposits related to the deductibles on our workers’ compensation insurance policies 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, Colombian net wealth tax, professional and other fees. We routinely expense these items in the normal course of business over the periods these expenses benefit.

Other Long-Term Liabilities

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

Related-Party Transactions

During the nine months ended September 30, 2015 and 2014, the Company paid approximately $0.1 million and $0.3 million, respectively, for trucking and equipment rental services, which represented arms-length transactions, to Gulf Coast Lease Service, a trucking and construction company. Joe Freeman, our Senior Vice President of Well Servicing, serves as the President of Gulf Coast Lease Services, 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.

Recently Issued Accounting Standards

Revenue Recognition. In May 2014, the 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. The recognition and measurement guidance for debt issuance costs are not affected by the amendments in this ASU. This ASU requires retrospective adoption and will be effective for us beginning with our first quarterly filing in 2016. Early adoption is permitted. We do not expect this adoption 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 nine months ended September 30, 2015 and 2014, we had capital expenditures of $130.7 million and $130.6 million, respectively, which includes $2.5 million and $0.3 million, respectively, of capitalized interest costs incurred during the construction periods of new-build drilling rigs and other drilling equipment. Capital expenditures during 2015 primarily relate to our five new-build drilling rigs which began construction during 2014, as well as unit additions to our production services fleets. As of September 30, 2015 and December 31, 2014, capital expenditures incurred for property and equipment not yet placed in service was $67.3 million and $82.7 million, respectively.

During the nine months ended September 30, 2015, we recorded total gains on disposition of our property and equipment of $2.6 million, primarily for the sales of 28 of our mechanical and lower horsepower electric drilling rigs and other drilling equipment which we sold for aggregate net proceeds of $36.3 million, of which $1.1 million was recognized as a receivable at September 30, 2015. During the nine months ended September 30, 2014, we recorded total gains on disposition of our property and equipment of $1.6 million, of which $1.1 million was related to the sale of our trucking assets in February 2014. Additionally, in September 2014, we sold our fishing and rental services operations for total consideration of $16.1 million, resulting in a pretax gain of $10.7 million.

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 would determine the fair value of the asset group. The amount of an impairment charge would be measured as the difference between the carrying amount and the fair value of these assets. The assumptions used in the impairment evaluation for long-lived assets are inherently uncertain and require management judgment.

Beginning in October 2014, domestic and international oil prices have declined significantly resulting in a downturn in our industry, affecting both drilling and production services. In drilling, all rig classes were severely impacted by the industry downturn. However, AC drilling rigs equipped with either a walking or skidding system are the best suited for horizontal pad drilling and we believe they are the most desirable rig design available. As the downturn worsened through 2015 resulting in significantly reduced revenue and utilization rates, and projections that reflect a more delayed recovery than previously anticipated, we performed impairment testing on all the non-AC electric drilling rigs in our fleet, including the eight drilling rigs in Colombia, and our coiled tubing operations as of June 30, 2015.

Our analysis at June 30, 2015 indicated that the carrying value of our coiled tubing reporting unit and the carrying value of our six pad-capable non-AC drilling rigs in our fleet (those that are equipped with either a walking or skidding system) were recoverable and thus there was no impairment present at June 30, 2015. However, our analysis indicated that the carrying values of the six 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. Therefore, an impairment charge was necessary to reduce the carrying values of these assets to their estimated fair values, which were based on market appraisals which are considered Level 3 inputs as defined by ASC Topic 820, Fair Value Measurements and Disclosures. As a result, we recognized impairment charges of $50.2 million during the second quarter of 2015 to reduce the carrying values of all eight drilling rigs in Colombia and related drilling equipment, $3.6 million to reduce the carrying value of inventory in Colombia, $6.4 million to reduce the carrying value of nonrecoverable prepaid taxes associated with our Colombian operations, and $9.7 million to reduce the carrying values of the six non-AC electric drilling rigs in our domestic fleet that are not pad-capable, to their estimated fair values.

During the three and nine months ended September 30, 2015, we also recognized impairment charges of $2.3 million and $9.7 million, respectively, to reduce the carrying values of assets which were classified as held for sale, to their estimated fair values, based on expected sales prices. As of September 30, 2015, our condensed consolidated balance sheet reflects assets held for sale of $2.1 million, which represents the fair value of certain drilling equipment, one real estate property and other production services equipment. During the nine months ended September 30, 2014, we recorded impairment charges of $0.7 million to reduce the carrying value of certain drilling equipment and real estate property which were held for sale to their estimated fair value less costs to sell.

These impairment charges are not expected to have an impact on our liquidity or debt covenants; however, they are a reflection of the overall downturn in our industry and decline in our projected future cash flows.

With the downturn persisting through 2015, our projected cash flows have declined further as compared to our projections made earlier in the year. At September 30, 2015, we performed impairment testing on our coiled tubing operations and seven drilling rigs, including our domestic pad-capable non-AC rigs, which have a net book value of $83.2 million and $55.7 million, respectively. We concluded that the carrying value of these assets is recoverable, but that these assets are at risk for future impairment if our projected cash flows decline further.

In order to estimate our future undiscounted cash flows from the use and eventual disposition of our drilling assets, we incorporated probabilities of selling these assets in the near term, versus working them at a significantly reduced expected rate of utilization through the end of their remaining useful lives. The most significant assumptions used in our analysis are the expected margin per day and utilization, as well as the estimated proceeds upon any future sale or disposal of the assets. 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.

The most significant inputs used in our impairment analysis of our coiled tubing operations include the projected utilization and pricing of our coiled tubing services, which are classified as Level 3 inputs as defined by ASC Topic 820, Fair Value Measurements and Disclosures. Although we believe the assumptions and estimates used in our analysis are reasonable and appropriate, different assumptions and estimates could materially impact the analysis and resulting conclusions. If we fail to meet the projected increases in utilization and pricing for our coiled tubing services, or in the event of significant unfavorable changes in the forecasted cash flows or key assumptions used in our analysis, the most significant of these being the projected utilization and pricing of our coiled tubing services, then we may incur a future impairment.


3.	Valuation Allowances on Deferred Tax Assets

As of September 30, 2015, we had $82.3 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 only recognize a tax benefit to the extent of taxable income that we expect to earn in the jurisdiction in future periods. We estimate that our domestic operations will result in taxable income in excess of our net operating losses and we expect to apply the net operating losses against the current year taxable income and taxable income that we have estimated in future periods. The 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 2029, with the latest expiration in 2033. 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, we recorded a valuation allowance of $18.7 million that fully offsets our foreign deferred tax assets relating to net operating losses and other tax benefits.

4. Debt

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



	September 30, 2015		December 31, 2014
Senior secured revolving credit facility	$	110,000	$	155,000
Senior notes	300,000		300,000
Other	—		80
	410,000		455,080
Less current portion	—		(27		)
	$	410,000	$	455,053

Senior Secured Revolving Credit Facility

We have a credit agreement, as amended on September 15, 2015, 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 principal amount of $300 million, all of which matures in September 2019 (the “Revolving Credit Facility”). The Revolving Credit Facility contains customary mandatory prepayments from the proceeds of certain asset dispositions or debt issuances, which are applied to reduce outstanding revolving and swing-line loans and letter of credit exposure, but in no event will reduce the borrowing availability under the Revolving Credit Facility to less than $300 million.

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 that ranges from 2.25% to 4.5% and 1.25% to 3.5%, respectively. The LIBOR margin and bank prime rate margin currently in effect are 2.25% and 1.25%, 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.

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 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 September 30, 2015, we had $110.0 million outstanding under our Revolving Credit Facility and $17.3 million in committed letters of credit, which resulted in borrowing availability of $172.7 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. At September 30, 2015, we were in compliance with our financial covenants under the Revolving Credit Facility. Our total consolidated leverage ratio was 2.7 to 1.0, our senior consolidated leverage ratio was 0.8 to 1.0, and our interest coverage ratio was 6.9 to 1.0. The financial covenants contained in our Revolving Credit Facility include the following:

•

A maximum total leverage ratio at the end of forthcoming fiscal quarters that cannot exceed: 4.00 to 1.00 on September 30, 2015, 4.50 to 1.00 on December 31, 2015, 5.00 to 1.00 on March 31, 2016, 5.50 to 1.00 during the period commencing June 30, 2016 through and including March 31, 2017, 5.25 to 1.00 on June 30, 2017, 5.00 to 1.00 on September 30, 2017, 4.50 to 1.00 on December 31, 2017, and 4.00 to 1.00 at any time thereafter;


•	A maximum senior consolidated leverage ratio, which excludes unsecured and subordinated debt, that cannot exceed 2.50 to 1.00;


•	A minimum interest coverage ratio that cannot be less than 2.50 to 1.00; and


•	If our senior consolidated leverage ratio is greater than 2.00 to 1.00 at the end of any fiscal quarter, our minimum asset coverage ratio cannot be less than 1.00 to 1.00.

The Revolving Credit Facility does not restrict repurchases of capital stock as long as the following conditions are met: (a) no event of default under the Revolving Credit Facility exists or would result from such repurchase, (b) if such repurchase occurs prior to the date on which financial statements for the fiscal quarter ending December 31, 2017 are delivered, after giving effect to such repurchase there is availability under the Revolving Credit Facility of at least $50 million, and the total leverage ratio as of the end of the most recent reported fiscal quarter is not more than 2.50 to 1.00, and (c) if such repurchase occurs on or after such date, after giving effect to such repurchase, there is availability under the Revolving Credit Facility of at least $25 million, and the senior consolidated leverage ratio as of the end of the most recently completed fiscal quarter prior to such repurchase is not greater than 2.00 to 1.00. In addition, the repurchase of capital stock requires, on a pro-forma basis, compliance with the maximum total leverage ratio, minimum interest coverage ratio, and, if applicable, the minimum asset coverage ratio as set forth in the Revolving Credit Facility, both before and after giving effect to such repurchase.

The Revolving Credit Facility also does not restrict capital expenditures as long as (a) no event of default under the Revolving Credit Facility exists or would result from such expenditures, and (b) after giving effect to such expenditures, there is availability under the Revolving Credit Facility of at least $50 million. If the senior consolidated leverage ratio as of the end of the most recent reported fiscal quarter is equal to or greater than 2.00 to 1.00, then capital expenditures are limited to $100 million for the fiscal year. The capital expenditure threshold may be increased by any unused portion of the capital expenditure threshold from the immediate preceding fiscal year up to $30 million.

At September 30, 2015, our senior consolidated leverage ratio was not greater than 2.00 to 1.00 and therefore, we were not subject to the capital expenditure threshold restrictions listed above.

The Revolving Credit Facility has additional restrictive covenants that, among other things, limit the incurrence of additional debt, investments, liens, dividends, acquisitions, prepayments of indebtedness, asset dispositions, mergers and consolidations, transactions with affiliates, hedging contracts, sale leasebacks and other matters customarily restricted in such agreements. 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 March 2010 and November 2011, we issued an aggregate $425 million of unregistered senior notes with a coupon interest rate of 9.875% that were set to mature in 2018 (the “2010 and 2011 Senior Notes”). The net proceeds from the 2010 issuance were used to repay a portion of the borrowings outstanding under our Revolving Credit Facility and a portion of the net proceeds from the 2011 issuance were used to fund the acquisition of the coiled tubing business in December 2011. In order to reduce our overall interest expense and lengthen the overall maturity of our senior indebtedness, during 2014, we redeemed all of our outstanding 2010 and 2011 Senior Notes, funded primarily by proceeds from the issuance of our 2014 Senior Notes and additional borrowings under our Revolving Credit Facility, as well as some cash on hand.

In March 2014, we issued $300 million of unregistered senior notes with a coupon interest rate of 6.125% that are due in 2022 (the “2014 Senior Notes”). The 2014 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 which were used to fund the repayment of $300 million of aggregate principal amount of 2010 and 2011 Senior Notes in March and May 2014. During the nine months ended September 30, 2014, we recognized a loss on debt extinguishment of $22.5 million for the redemption of $300 million of 2010 and 2011 Senior Notes, which included redemption premiums of $15.4 million, $3.6 million of net unamortized discount and $3.5 million of unamortized debt issuance costs.

The 2014 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 2014 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 2014 Senior Notes, in whole or in part, at a

“make-whole” redemption price specified in the 2014 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 2014 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 2014 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 2014 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 September 2019. Costs incurred in connection with the issuance of our 2014 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.

Capitalized debt costs related to the issuance of our long-term debt were $9.0 million and $9.8 million as of September 30, 2015 and December 31, 2014, respectively. We recognized $1.7 million of associated amortization during the nine months ended September 30, 2015, which includes the write-off of $0.5 million of debt issuance costs associated with the reduced borrowing capacity of the Revolving Credit Facility that was amended in September 2015, and we recognized $1.5 million of associated amortization during the nine months ended September 30, 2014.


5.	Fair Value of Financial Instruments

ASC Topic 820, Fair Value Measurements and Disclosures, defines fair value and provides a hierarchal framework associated with the level of subjectivity used in measuring assets and liabilities at fair value.

At September 30, 2015 and December 31, 2014, our financial instruments consist primarily of cash, trade and other receivables, trade payables and long-term debt. The carrying value of cash, trade and other receivables, and trade payables are considered to be representative of their respective fair values due to the short-term nature of these instruments.

The fair value of our long-term debt is estimated using a discounted cash flow analysis, based on rates that we believe we would currently pay for similar types of debt instruments. This discounted cash flow analysis is based on inputs defined by ASC Topic 820 as level 2 inputs, which are observable inputs for similar types of debt instruments. The following table presents the supplemental fair value information about long-term debt at September 30, 2015 and December 31, 2014 (amounts in thousands):



	September 30, 2015				December 31, 2014
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Total debt	$	410,000	$	281,555	$	455,080	$	415,785


6.	Earnings Per Common Share

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



	Three months ended September 30,					Nine months ended September 30,
	2015			2014		2015			2014
Basic
Net income (loss)	$	(17,540	)	$	12,453	$	(106,840	)	$	9,555

Weighted-average shares	64,449			63,451		64,262			62,960

Income (loss) per common share—Basic	$	(0.27	)	$	0.20	$	(1.66	)	$	0.15

Diluted
Net income (loss)	$	(17,540	)	$	12,453	$	(106,840	)	$	9,555

Weighted-average shares
Outstanding	64,449			63,451		64,262			62,960
Diluted effect of outstanding stock options, restricted stock and restricted stock unit awards	—			2,425		—			2,207
	64,449			65,876		64,262			65,167

Income (loss) per common share—Diluted	$	(0.27	)	$	0.19	$	(1.66	)	$	0.15

Potentially dilutive stock options, restricted stock and restricted stock unit awards representing a total of 5,272,734 and 4,862,081 shares of common stock for the three and nine months ended September 30, 2015, respectively, and 735,624 and 1,692,549 for the three and nine months ended September 30, 2014, respectively, were excluded from the computation of diluted weighted average shares outstanding due to their antidilutive effect.


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 September 30, 2015, the entire $300 million under the shelf registration statement is available for equity or debt offerings. 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 also grant restricted stock unit awards with vesting based on time of service conditions, and in certain cases, subject to performance and market conditions. We recognize compensation cost for stock option, restricted stock and restricted stock unit awards based on the fair value estimated in accordance with ASC Topic 718, Compensation—Stock Compensation. 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 compensation expense recognized for stock option, restricted stock and restricted stock unit awards during the three and nine months ended September 30, 2015 and 2014 (amounts in thousands):



	Three months ended September 30,				Nine months ended September 30,
	2015		2014		2015		2014
Stock option awards	$	240	$	311	$	717	$	964
Restricted stock awards	88		127		311		421
Restricted stock unit awards	707		1,496		1,247		4,376
	$	1,035	$	1,934	$	2,275	$	5,761

Stock Options

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

We estimate the fair value of each option grant on the date of grant using a Black-Scholes option pricing model. There were no stock options granted during the three months ended September 30, 2015 or 2014. The following table summarizes the assumptions used in the Black-Scholes option pricing model based on a weighted-average calculation for the nine months ended September 30, 2015 and 2014:



	Nine months ended September 30,
	2015		2014
Expected volatility	64	%	66	%
Risk-free interest rates	1.4	%	1.7	%
Expected life in years	5.52		5.49
Options granted	341,638		221,440
Grant-date fair value	$2.31		$4.87

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 three and nine months ended September 30, 2015, 7,200 and 203,300 stock options, respectively, were exercised at a weighted-average exercise price of $3.84 for both periods. During the three and nine months ended September 30, 2014, 690,877 and 906,277 stock options were exercised at a weighted-average exercise price of $9.70 and $9.14, respectively. 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

Historically, we have generally granted restricted stock awards that vest over a three-year period with a fair value based on the closing price of our common stock on the date of the grant. However, beginning in 2013, we began granting restricted stock awards with a vesting period of one year. When restricted stock awards are granted, or when restricted stock unit awards are converted to restricted stock, shares of our common stock are considered issued, but subject to certain restrictions. During the nine months ended September 30, 2015 and 2014, we granted 47,296 and 32,100 shares of restricted stock awards, with a weighted-average grant-date fair value of $7.40 and $14.33, 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.

There were no restricted stock units granted during the three months ended September 30, 2015. The following table summarizes the number and weighted-average grant-date fair value of the restricted stock unit awards granted during the three months ended September 30, 2014, and nine months ended September 30, 2015 and 2014:



	Three months ended September 30,		Nine months ended September 30,
	2014		2015		2014
Time-based RSUs:
Time-based RSUs granted	13,330		151,919		360,665
Weighted-average grant-date fair value	$	13.73	$	4.08	$	8.64

Performance-based RSUs:
Performance-based RSUs granted	—		531,522		321,606
Weighted-average grant-date fair value	$	—	$	6.18	$	9.90

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 one-third of the performance-based RSUs granted during 2012 and 2013, and 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 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 2015, we determined that 64% of the target number of shares granted during 2012 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, 2012 through December 31, 2014. The performance-based RSUs granted during 2012 vested and were converted to common stock at the end of April 2015. As of September 30, 2015, we estimated that our actual achievement level for the performance-based RSUs granted during 2013, 2014 and 2015 will be approximately 40%, 80% and 100% of the predetermined performance conditions, respectively.


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.

The following tables set forth certain financial information for our two operating segments and corporate as of and for the three and nine months ended September 30, 2015 and 2014 (amounts in thousands):



	As of and for the three months ended September 30, 2015
	Drilling Services Segment		Production Services Segment		Corporate		Total
Identifiable assets	$	571,203	$	335,206	$	42,719	$	949,128
Revenues	$	41,238	$	66,242	$	—	$	107,480
Operating costs	22,875		48,643		—		71,518
Segment margin	$	18,363	$	17,599	$	—	$	35,962
Depreciation and amortization	$	17,648	$	17,284	$	325	$	35,257
Capital expenditures	$	30,757	$	4,633	$	148	$	35,538



	As of and for the three months ended September 30, 2014
	Drilling Services Segment		Production Services Segment		Corporate		Total
Identifiable assets	$	779,482	$	442,014	$	43,261	$	1,264,757
Revenues	$	128,117	$	145,150	$	—	$	273,267
Operating costs	88,963		89,993		—		178,956
Segment margin	$	39,154	$	55,157	$	—	$	94,311
Depreciation and amortization	$	28,728	$	16,993	$	360	$	46,081
Capital expenditures	$	36,249	$	16,265	$	151	$	52,665



	As of and for the nine months ended September 30, 2015
	Drilling Services Segment		Production Services Segment		Corporate		Total
Identifiable assets	$	571,203	$	335,206	$	42,719	$	949,128
Revenues	$	198,212	$	238,093	$	—	$	436,305
Operating costs	118,114		170,517		—		288,631
Segment margin	$	80,098	$	67,576	$	—	$	147,674
Depreciation and amortization	$	62,063	$	52,445	$	1,020	$	115,528
Capital expenditures	$	106,447	$	23,786	$	465	$	130,698



	As of and for the nine months ended September 30, 2014
	Drilling Services Segment		Production Services Segment		Corporate		Total
Identifiable assets	$	779,482	$	442,014	$	43,261	$	1,264,757
Revenues	$	373,627	$	398,486	$	—	$	772,113
Operating costs	250,904		250,140		—		501,044
Segment margin	$	122,723	$	148,346	$	—	$	271,069
Depreciation and amortization	$	86,936	$	49,478	$	984	$	137,398
Capital expenditures	$	76,888	$	53,094	$	596	$	130,578

The following table reconciles the segment profits reported above to income from operations as reported on the consolidated statements of operations for the three and nine months ended September 30, 2015 and 2014 (amounts in thousands):



	Three months ended September 30,						Nine months ended September 30,
	2015			2014			2015			2014
Segment margin	$	35,962		$	94,311		$	147,674		$	271,069
Depreciation and amortization	(35,257		)	(46,081		)	(115,528		)	(137,398		)
General and administrative	(16,814		)	(26,613		)	(56,909		)	(76,372		)
Bad debt recovery (expense)	1,071			(19		)	358			(456		)
Impairment charges	(2,329		)	(678		)	(79,648		)	(678		)
Gain (loss) on dispositions of property and equipment	(605		)	(142		)	2,639			1,589
Gain on sale of fishing and rental services operations	—			10,702			—			10,702
Gain on litigation	—			1,324			—			4,200
Income (loss) from operations	$	(17,972	)	$	32,804		$	(101,414	)	$	72,656

The following table sets forth certain financial information for our international operations in Colombia as of and for the three and nine months ended September 30, 2015 and 2014 (amounts in thousands):



	As of and for the three months ended September 30,				As of and for the nine months ended September 30,
	2015		2014		2015		2014
Identifiable assets	$	57,777	$	150,287	$	57,777	$	150,287
Revenues	$	2,670	$	22,904	$	36,709	$	70,595

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


9.	Commitments and Contingencies

In connection with our operations in Colombia, our foreign subsidiaries have obtained bonds for bidding on drilling contracts, performing under drilling contracts, and remitting customs and importation duties. We have guaranteed payments of $45.3 million relating to our performance under these bonds as of September 30, 2015.

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


10.	Guarantor/Non-Guarantor Condensed Consolidated Financial Statements

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

In the event of a bankruptcy, liquidation or reorganization of any non-guarantor subsidiary, such non-guarantor subsidiary will pay the holders of its debt and other liabilities, including its trade creditors, before it will be able to distribute any of its assets to us. In the future, any non-U.S. subsidiaries, immaterial subsidiaries and subsidiaries that we designate as unrestricted subsidiaries under the Indenture will not guarantee the Senior Notes. As of September 30, 2015, there were no restrictions on the ability of subsidiary guarantors to transfer funds to the parent company.

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

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited, in thousands)



	September 30, 2015
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	26,349		$	1,770		$	7,560		$	—		$	35,679
Receivables, net of allowance	2,310			68,008			11,655			—			81,973
Intercompany receivable (payable)	(24,836		)	34,169			(9,333		)	—			—
Deferred income taxes	751			5,472			76			—			6,299
Inventory	—			5,841			3,154			—			8,995
Assets held for sale	—			2,065			—			—			2,065
Prepaid expenses and other current assets	1,309			3,052			1,566			—			5,927
Total current assets	5,883			120,377			14,678			—			140,938
Net property and equipment	3,475			741,288			33,933			—			778,696
Investment in subsidiaries	706,106			43,254			—			(749,360		)	—
Intangible assets, net of accumulated amortization	—			18,268			—			—			18,268
Noncurrent deferred income taxes	78,664			—			—			(78,664		)	—
Other long-term assets	9,530			919			777			—			11,226
Total assets	$	803,658		$	924,106		$	49,388		$	(828,024	)	$	949,128
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	582		$	32,562		$	1,928		$	—		$	35,072
Deferred revenues	—			13,993			779			—			14,772
Accrued expenses	3,629			41,042			2,792			—			47,463
Total current liabilities	4,211			87,597			5,499			—			97,307
Long-term debt, less current portion	410,000			—			—			—			410,000
Noncurrent deferred income taxes	—			127,409			—			(78,664		)	48,745
Other long-term liabilities	564			2,994			635			—			4,193
Total liabilities	414,775			218,000			6,134			(78,664		)	560,245
Total shareholders’ equity	388,883			706,106			43,254			(749,360		)	388,883
Total liabilities and shareholders’ equity	$	803,658		$	924,106		$	49,388		$	(828,024	)	$	949,128

	December 31, 2014
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	27,688		$	(5,516	)	$	12,752		$	—		$	34,924
Receivables, net of allowance	1,641			151,048			37,512			—			190,201
Intercompany receivable (payable)	(24,836		)	55,567			(30,728		)	(3		)	—
Deferred income taxes	1,827			8,196			975			—			10,998
Inventory	—			7,208			6,909			—			14,117
Assets held for sale	—			9,909			—			—			9,909
Prepaid expenses and other current assets	1,217			6,554			1,154			—			8,925
Total current assets	7,537			232,966			28,574			(3		)	269,074
Net property and equipment	4,179			763,994			89,118			(750		)	856,541
Investment in subsidiaries	850,807			116,799			—			(967,606		)	—
Intangible assets, net of accumulated amortization	—			24,223			—			—			24,223
Noncurrent deferred income taxes	90,664			—			2,753			(90,664		)	2,753
Other long-term assets	10,122			1,955			6,921			—			18,998
Total assets	$	963,309		$	1,139,937		$	127,366		$	(1,059,023	)	$	1,171,589
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	735		$	57,910		$	5,660		$	—		$	64,305
Current portion of long-term debt	—			27			—			—			27
Deferred revenues	—			3,315			—			—			3,315
Accrued expenses	11,109			64,063			4,376			(3		)	79,545
Total current liabilities	11,844			125,315			10,036			(3		)	147,192
Long-term debt, less current portion	455,000			53			—			—			455,053
Noncurrent deferred income taxes	138			160,104			—			(90,664		)	69,578
Other long-term liabilities	513			3,658			531			—			4,702
Total liabilities	467,495			289,130			10,567			(90,667		)	676,525
Total shareholders’ equity	495,814			850,807			116,799			(968,356		)	495,064
Total liabilities and shareholders’ equity	$	963,309		$	1,139,937		$	127,366		$	(1,059,023	)	$	1,171,589

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited, in thousands)



	Three months ended September 30, 2015
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Revenues	$	—		$	104,810		$	2,670		$	—		$	107,480
Costs and expenses:
Operating costs	—			67,554			3,964			—			71,518
Depreciation and amortization	325			32,797			2,135			—			35,257
General and administrative	4,864			11,671			417			(138		)	16,814
Intercompany leasing	—			(1,215		)	1,215			—			—
Bad debt expense (recovery)	—			(1,071		)	—			—			(1,071		)
Impairment charges	—			2,329			—			—			2,329
Gain on dispositions of property and equipment	128			651			(174		)	—			605
Total costs and expenses	5,317			112,716			7,557			(138		)	125,452
Income (loss) from operations	(5,317		)	(7,906		)	(4,887		)	138			(17,972		)
Other income (expense):
Equity in earnings of subsidiaries	(11,208		)	(6,309		)	—			17,517			—
Interest expense	(5,473		)	2			6			—			(5,465		)
Other	(21		)	472			(1,098		)	(138		)	(785		)
Total other income (expense)	(16,702		)	(5,835		)	(1,092		)	17,379			(6,250		)
Income (loss) before income taxes	(22,019		)	(13,741		)	(5,979		)	17,517			(24,222		)
Income tax (expense) benefit ¹	4,479			2,533			(330		)	—			6,682
Net income (loss)	$	(17,540	)	$	(11,208	)	$	(6,309	)	$	17,517		$	(17,540	)



	Three months ended September 30, 2014
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Revenues	$	—		$	250,363		$	22,904		$	—		$	273,267
Costs and expenses:
Operating costs	—			159,958			18,998			—			178,956
Depreciation and amortization	358			42,250			3,473			—			46,081
General and administrative	7,110			18,665			976			(138		)	26,613
Intercompany leasing	—			(1,215		)	1,215			—			—
Bad debt expense (recovery)	—			19			—			—			19
Impairment charges	—			678			—			—			678
Gain on dispositions of property and equipment	—			147			(5		)	—			142
Gain on sale of fishing and rental services operations	—			(10,702		)	—			—			(10,702		)
Gain on litigation	(1,324		)	—			—			—			(1,324		)
Total costs and expenses	6,144			209,800			24,657			(138		)	240,463
Income (loss) from operations	(6,144		)	40,563			(1,753		)	138			32,804
Other income (expense):
Equity in earnings of subsidiaries	21,908			(3,742		)	—			(18,166		)	—
Interest expense	(8,943		)	(22		)	(4		)	—			(8,969		)
Loss on extinguishment of debt	—			—			—			—			—
Other	(2		)	707			(2,022		)	(138		)	(1,455		)
Total other income (expense)	12,963			(3,057		)	(2,026		)	(18,304		)	(10,424		)
Income (loss) before income taxes	6,819			37,506			(3,779		)	(18,166		)	22,380
Income tax (expense) benefit ¹	5,634			(15,598		)	37			—			(9,927		)
Net income (loss)	$	12,453		$	21,908		$	(3,742	)	$	(18,166	)	$	12,453

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited, in thousands)



	Nine months ended September 30, 2015
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Revenues	$	—		$	399,596		$	36,709		$	—		$	436,305
Costs and expenses:
Operating costs	—			258,125			30,506			—			288,631
Depreciation and amortization	1,020			104,841			9,667			—			115,528
General and administrative	15,624			39,916			1,783			(414		)	56,909
Intercompany leasing	—			(3,645		)	3,645			—			—
Bad debt expense (recovery)	—			(358		)	—			—			(358		)
Impairment charges	—			23,766			56,632			(750		)	79,648
Gain on dispositions of property and equipment	128			(2,572		)	(195		)	—			(2,639		)
Total costs and expenses	16,772			420,073			102,038			(1,164		)	537,719
Income (loss) from operations	(16,772		)	(20,477		)	(65,329		)	1,164			(101,414		)
Other income (expense):
Equity in earnings of subsidiaries	(87,179		)	(73,472		)	—			160,651			—
Interest expense	(16,063		)	(120		)	18			—			(16,165		)
Other	(14		)	1,343			(3,894		)	(414		)	(2,979		)
Total other income (expense)	(103,256		)	(72,249		)	(3,876		)	160,237			(19,144		)
Income (loss) before income taxes	(120,028		)	(92,726		)	(69,205		)	161,401			(120,558		)
Income tax (expense) benefit ¹	12,438			5,547			(4,267		)	—			13,718
Net income (loss)	$	(107,590	)	$	(87,179	)	$	(73,472	)	$	161,401		$	(106,840	)


	Nine months ended September 30, 2014
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Revenues	$	—		$	701,518		$	70,595		$	—		$	772,113
Costs and expenses:
Operating costs	—			450,262			50,782			—			501,044
Depreciation and amortization	983			126,093			10,322			—			137,398
General and administrative	20,645			53,301			2,840			(414		)	76,372
Intercompany leasing	—			(3,645		)	3,645			—			—
Bad debt expense (recovery)	—			456			—			—			456
Impairment charges	—			678			—			—			678
Gain on dispositions of property and equipment	—			(1,317		)	(272		)	—			(1,589		)
Gain on sale of fishing and rental services operations	—			(10,702		)	—			—			(10,702		)
Gain on litigation	(4,200		)	—			—			—			(4,200		)
Total costs and expenses	17,428			615,126			67,317			(414		)	699,457
Income (loss) from operations	(17,428		)	86,392			3,278			414			72,656
Other income (expense):
Equity in earnings of subsidiaries	54,500			345			—			(54,845		)	—
Interest expense	(32,049		)	(39		)	3			—			(32,085		)
Loss on extinguishment of debt	(22,482		)	—			—			—			(22,482		)
Other	8			1,995			(1,229		)	(414		)	360
Total other income (expense)	(23		)	2,301			(1,226		)	(55,259		)	(54,207		)
Income (loss) before income taxes	(17,451		)	88,693			2,052			(54,845		)	18,449
Income tax (expense) benefit ¹	27,006			(34,193		)	(1,707		)	—			(8,894		)
Net income (loss)	$	9,555		$	54,500		$	345		$	(54,845	)	$	9,555

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

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited, in thousands)



	Nine months ended September 30, 2015
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidated
Cash flows from operating activities	$	45,023		$	97,868		$	(3,826	)	$	139,065
Cash flows from investing activities:
Purchases of property and equipment	(437		)	(128,363		)	(1,590		)	(130,390		)
Proceeds from sale of property and equipment	22			37,557			224			37,803
Proceeds from insurance recoveries	—			227			—			227
	(415		)	(90,579		)	(1,366		)	(92,360		)
Cash flows from financing activities:
Debt repayments	(45,000		)	(3		)	—			(45,003		)
Debt issuance costs	(999		)	—			—			(999		)
Proceeds from exercise of options	781			—			—			781
Purchase of treasury stock	(729		)	—			—			(729		)
	(45,947		)	(3		)	—			(45,950		)
Net increase (decrease) in cash and cash equivalents	(1,339		)	7,286			(5,192		)	755
Beginning cash and cash equivalents	27,688			(5,516		)	12,752			34,924
Ending cash and cash equivalents	$	26,349		$	1,770		$	7,560		$	35,679

	Nine months ended September 30, 2014
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidated
Cash flows from operating activities	$	33,766		$	98,247		$	22,917		$	154,930
Cash flows from investing activities:
Purchases of property and equipment	(691		)	(106,208		)	(13,839		)	(120,738		)
Proceeds from sale of property and equipment	—			6,916			281			7,197
Proceeds from sale of fishing and rental services operations	15,090			—			—			15,090
	14,399			(99,292		)	(13,558		)	(98,451		)
Cash flows from financing activities:
Debt repayments	(360,000		)	(19		)	—			(360,019		)
Proceeds from issuance of debt	320,000			—			—			320,000
Debt issuance costs	(9,173		)	—			—			(9,173		)
Tender premium costs	(15,381		)	—			—			(15,381		)
Proceeds from exercise of options	8,280			—			—			8,280
Purchase of treasury stock	(1,132		)	—			—			(1,132		)
	(57,406		)	(19		)	—			(57,425		)
Net increase (decrease) in cash and cash equivalents	(9,241		)	(1,064		)	9,359			(946		)
Beginning cash and cash equivalents	28,368			(2,059		)	1,076			27,385
Ending cash and cash equivalents	$	19,127		$	(3,123	)	$	10,435		$	26,439


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, 2014, 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. 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) be aware that important factors not referred to above could affect the accuracy of our forward-looking statements and (2) use caution and common sense when considering our forward-looking statements.

Company Overview

Pioneer Energy Services Corp. (formerly called "Pioneer Drilling Company") was incorporated under the laws of the State of Texas in 1979 as the successor to a business that had been operating since 1968. Since September 1999, we have significantly expanded our drilling rig fleet through acquisitions and through the construction of rigs from new and used components. 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 on September 17, 2014. We also acquired a coiled tubing services business at the end of 2011 to expand our existing production services offerings. We have continued to invest in the growth of all our core service offerings through acquisitions and organic growth.

Pioneer Energy Services Corp. provides drilling services and production services to a diverse group of independent and large oil and gas exploration and production companies throughout much of the onshore oil and gas producing regions of 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 site and enable us to meet multiple needs of our clients.

We currently conduct our operations through two operating segments: our Drilling Services Segment and our Production Services Segment. The following is a description of these two operating segments. 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.

•

Drilling Services Segment—Our Drilling Services Segment provides contract land drilling services to a diverse group of oil and gas 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. 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		10
West Texas		8
North Dakota		8
Appalachia		4
Colombia		8
		38

•

Production Services Segment—Our Production Services Segment provides a range of services to exploration and production companies, including well servicing, wireline services and coiled tubing services. Our production services operations are 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. We provide our services to a diverse group of oil and gas exploration and production companies. The primary production services we offer are the following:

•

Well Servicing. A range of services are required in order to establish production in newly-drilled wells and to maintain production over the useful lives of active wells. We use our well servicing rig fleet to provide these necessary services, including the completion of newly-drilled wells, maintenance and workover of active wells, and plugging and abandonment of wells at the end of their useful lives. As of September 30, 2015, we have a fleet of 113 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. In order for oil and gas exploration and production companies to better understand the reservoirs they are drilling or producing, they require logging services to accurately characterize reservoir rocks and fluids. To complete a 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. We provide both open and cased-hole logging services, including the latest pulsed-neutron technology. In addition, we provide services which allow oil and gas exploration and production companies to evaluate the integrity of wellbore casing, recover pipe, or install bridge plugs. As of September 30, 2015, we have a fleet of 125 wireline units in 18 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 stimulation utilizing acid, chemical treatments and fracturing. Coiled tubing is also used for a number of horizontal well applications such as milling temporary plugs between frac stages. As of September 30, 2015, our coiled tubing business consists of 12 onshore and five offshore coiled tubing units which are deployed through three locations in Texas and Louisiana.

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

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 in turn is affected by current and expected oil and natural gas prices.

In recent years, 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, demand remained steady, particularly for drilling rigs that are able to drill horizontally. Beginning in October 2014, domestic and international oil prices have declined significantly resulting in a downturn in our industry, affecting both drilling and production services. If oil prices continue to decline, or if oil and natural gas prices remain at current levels for an extended period of time, then industry equipment utilization and revenue rates could decrease further. We expect continued pricing pressure, low activity levels and a highly competitive environment throughout the remainder of 2015 and into 2016, but we believe our high-quality equipment and services are well positioned to compete.

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.

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. However, in a severe downturn that is prolonged, both operating and capital expenditures are significantly reduced.

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.

Technological advancements and trends in our industry also affect the demand for certain types of equipment. In recent years, and especially during the recent downturn, demand has significantly decreased for certain drilling rigs, particularly in vertical well markets. The decline is primarily due to higher demand for drilling rigs that are able to drill horizontally and the increased use of "pad drilling." Pad drilling 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 has resulted in significantly reduced demand for drilling rigs that do not have the ability to walk or skid and to drill horizontal wells, and could further reduce the overall demand for all drilling rigs.

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, 2014.

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 which we operate in the most attractive drilling markets throughout the United States and in Colombia. 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:

•

Competitive Position in the Most Attractive 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. By the end of 2015, we will have deployed a total of 15 new-build drilling rigs to the Bakken, Marcellus/Utica and Eagle Ford shales and the Permian Basin in the last three years. Additionally, we have added significant capacity in recent years to our production services fleets, which we believe are well positioned to further capitalize on 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 are most profitable.

•

Growth Through Select Capital Deployment. We have historically invested in the growth of our business by strategically upgrading our existing assets and disposing of assets which use older technology, selectively engaging in new-build opportunities, and through selective acquisitions. Since the beginning of 2010, we have added significant capacity to our production services offerings through the addition of 62 wireline units, 50 well servicing rigs and 17 coiled tubing units. We constructed ten AC drilling rigs from 2011 to 2013. We have deployed four new-build 1,500 horsepower AC drilling rigs under multi-year term contracts during 2015 and expect to complete construction of one more new-build drilling rig by the end of the year. We also sold 28 of our mechanical and lower horsepower electric drilling rigs during 2015 which were the most negatively impacted by the industry downturn.

With the recent decline in oil prices and the reductions in our utilization and revenue rates in 2015, our efforts are currently focused on:


•	Stringent cost control measures, including the reduction of overhead, personnel and incentive compensation costs;


•	The liquidation of nonstrategic or under-performing assets, including the disposal of 28 of our mechanical and lower horsepower drilling rigs during 2015, and the ongoing evaluation of our domestic and international fleets for additional drilling rigs or equipment for which a near term sale would be favorable;


•	Limited organic growth to complete fleet additions which were ordered prior to the recent decline in oil prices, the final of which is expected to be delivered by the end of 2015;


•	Maintaining a strong balance sheet and ample liquidity, including working with our lenders to maintain availability under our revolving credit facility which was amended in September 2015, and including availability for equity or debt offerings up to $300 million under our shelf registration statement; and


•	Continued emphasis on the execution and performance of our core businesses.

We believe these near-term goals will position us to take advantage of future business opportunities and continue our long-term growth strategy.

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 $35.7 million as of September 30, 2015), 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 March 2014, we issued $300 million of unregistered senior notes with a coupon interest rate of 6.125% that are due in 2022 (the “2014 Senior Notes”), the net proceeds from which, combined with cash on hand, were used to fund the repayment of $300 million of aggregate principal amount of 2010 and 2011 Senior Notes in March and May 2014. In October 2014, we redeemed the remaining $125.0 million in aggregate principal amount of the 2010 and 2011 Senior Notes, primarily funded by proceeds from our revolving credit facility and through cash on hand.

Our Revolving Credit Facility, as amended on September 15, 2015, provides for a senior secured revolving credit facility, with sub-limits for letters of credit and swing-line loans, of up to an aggregate principal amount of $300 million, all of which matures in September 2019. As of September 30, 2015, we had $110 million outstanding under our Revolving Credit Facility and $17.3 million in committed letters of credit, which resulted in borrowing availability of $172.7 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. Additional information regarding these covenants is provided in the Debt Requirements section below. Borrowings under the Revolving Credit Facility are available for selective acquisitions, working capital and other general corporate purposes.

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 nine months ended September 30, 2015, we spent $130.4 million on purchases of property and equipment and placed into service property and equipment of $130.7 million. Currently, we expect to spend approximately $150 million to $160 million on capital expenditures during 2015. We expect the total capital expenditures for 2015 will be allocated approximately 75% for our Drilling Services Segment and approximately 25% for our Production Services Segment. Our total planned capital expenditures for the year ending December 31, 2015 include the remaining payments for five new-build drilling rigs, nine well servicing rigs, eight wireline units, routine capital expenditures 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 timing of commitments and payments, as well as the level of new-build and other expansion opportunities that meet our strategic and return on capital employed criteria. We expect to fund capital expenditures in 2015 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 $43.6 million at September 30, 2015, compared to $121.9 million at December 31, 2014. Our current ratio, which we calculate by dividing current assets by current liabilities, was 1.4 at September 30, 2015, compared to 1.8 at December 31, 2014.

Our operations have historically generated cash flows sufficient to meet our requirements for debt service and normal capital expenditures. However, our working capital requirements could increase during periods when new-build rig construction projects are in progress or when higher percentages of our drilling contracts are turnkey contracts.

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



	September 30, 2015		December 31, 2014		Change
Cash and cash equivalents	$	35,679	$	34,924	$	755
Receivables:
Trade, net of allowance for doubtful accounts	51,963		136,161		(84,198		)
Unbilled receivables	7,653		38,002		(30,349		)
Insurance recoveries	14,947		10,900		4,047
Other receivables	7,410		5,138		2,272
Deferred income taxes	6,299		10,998		(4,699		)
Inventory	8,995		14,117		(5,122		)
Assets held for sale	2,065		9,909		(7,844		)
Prepaid expenses and other current assets	5,927		8,925		(2,998		)
Current assets	140,938		269,074		(128,136		)
Accounts payable	35,072		64,305		(29,233		)
Current portion of long-term debt	—		27		(27		)
Deferred revenues	14,772		3,315		11,457
Accrued expenses:
Payroll and related employee costs	16,934		40,058		(23,124		)
Insurance premiums and deductibles	8,302		12,829		(4,527		)
Insurance claims and settlements	14,947		10,900		4,047
Interest	861		5,432		(4,571		)
Other	6,419		10,326		(3,907		)
Current liabilities	97,307		147,192		(49,885		)
Working capital	$	43,631	$	121,882	$	(78,251	)

The increase in cash and cash equivalents during the nine months ended September 30, 2015 is primarily due to $139.1 million of cash provided by operating activities, which includes early termination payments made on certain drilling contracts, and $37.8 million of proceeds from the sale of assets, offset by $130.4 million used for purchases of property and equipment and $45.0 million used for debt repayment.

The net decrease in our total trade and unbilled receivables as of September 30, 2015 as compared to December 31, 2014 is primarily the result of the decrease in consolidated revenues of $175.6 million, or 62%, for the quarter ended September 30, 2015 as compared to the quarter ended December 31, 2014.

The increase in both our insurance recoveries receivables and our insurance claims and settlements accrued expenses as of September 30, 2015 as compared to December 31, 2014 is primarily due to an increase in our insurance company's reserve for workers' compensation claims in excess of our deductibles.

The increase in other receivables as of September 30, 2015 as compared to December 31, 2014 is primarily due to a decrease in income taxes payable due to a decrease in activity for our Colombian operations, and a $1.1 million short-term note receivable related to the sale of a drilling rig during the second quarter of 2015.

The decrease in current deferred income taxes as of September 30, 2015 as compared to December 31, 2014 is primarily due to a reduction in the current deferred tax assets for our annual bonus accruals which were paid in the first quarter of 2015, as well as the valuation allowance on our Colombian deferred tax assets recognized during 2015.

The decrease in inventory as of September 30, 2015 as compared to December 31, 2014 is primarily due to $3.6 million of impairment charges recognized in the second quarter of 2015 to reduce the carrying value of inventory associated with our Colombian operations, as well as a decrease in our inventory balance for our wireline operations due to decreased activity.

As of September 30, 2015, our condensed consolidated balance sheet reflects assets held for sale of $2.1 million, which represents the fair value of certain drilling equipment, one real estate property and other production services equipment.

The decrease in prepaid expenses and other assets as of September 30, 2015 as compared to December 31, 2014 is primarily due to a decrease in prepaid insurance costs because most of the insurance premiums are paid in late October of each year, and therefore we had amortization of eleven months of these October premiums at September 30, 2015, as compared to two months at December 31, 2014.

The decrease in accounts payable as of September 30, 2015 as compared to December 31, 2014 is primarily due to the 62% decrease in our operating costs for the quarter ended September 30, 2015 as compared to the quarter ended December 31, 2014.

The increase in deferred revenues as of September 30, 2015 as compared to December 31, 2014 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 September 30, 2015 as compared to December 31, 2014 is primarily due to a 48% reduction in headcount during 2015, as well as reduced accruals for annual bonuses which are expected to be significantly lower as compared to 2014.

The decrease in insurance premiums and deductibles as of September 30, 2015 as compared to December 31, 2014 is primarily due to a decrease in our workers compensation and health insurance costs resulting from a decrease in our estimated liability for the deductibles under these policies.

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

The decrease in other accrued expenses as of September 30, 2015 as compared to December 31, 2014 is primarily due to a decrease in our 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 September 30, 2015 (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	$	410,000	$	—	$	—	$	110,000	$	300,000
Interest on debt	130,202		21,081		42,162		39,396		27,563
Purchase commitments	21,576		21,255		321		—		—
Operating leases	13,782		4,095		5,605		3,389		693
Incentive compensation	10,144		5,424		4,720		—		—
Total	$	585,704	$	51,855	$	52,808	$	152,785	$	328,256

At September 30, 2015, debt obligations consist of $300 million of principal amount outstanding under our Senior Notes and $110.0 million outstanding under our Revolving Credit Facility. The $110.0 million outstanding under our Revolving Credit Facility is due at maturity on September 22, 2019. However, we may make principal payments to reduce the outstanding balance prior to maturity when cash and working capital is sufficient. The $300 million principal amount outstanding under our 2014 Senior Notes will mature on March 15, 2022.

Interest payment obligations on our Revolving Credit Facility are estimated based on (1) the 2.5% interest rate that was in effect at September 30, 2015, and (2) the outstanding balance of $110.0 million at September 30, 2015 to

be paid at maturity on September 22, 2019. Interest payment obligations on our 2014 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 components ordered for our new-build drilling rigs, purchases of other new equipment and equipment upgrades. The total estimated cost, excluding capitalized interest, for the five new-build drilling rigs is approximately $125 million, of which $121.0 million has already been incurred, and $3.4 million of which is reflected in the purchase commitments table above. In addition, $9.7 million of the purchase commitments in the table above represent obligations for well servicing rigs and other drilling equipment that were ordered during 2014, but which require a long lead-time for delivery.

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.

Debt Requirements

The Revolving Credit Facility contains customary mandatory prepayments from the proceeds of certain asset dispositions or debt issuances, which are applied to reduce outstanding revolving and swing-line loans and letter of credit exposure. There are no limitations on our ability to access the borrowing capacity provided there is no default, all representations and warranties are true and correct, and compliance with financial covenants under the Revolving Credit Facility is maintained. At September 30, 2015, we were in compliance with our financial covenants under the Revolving Credit Facility. Our total consolidated leverage ratio was 2.7 to 1.0, our senior consolidated leverage ratio was 0.8 to 1.0, and our interest coverage ratio was 6.9 to 1.0. The financial covenants contained in our Revolving Credit Facility include the following:

•


•	A maximum senior consolidated leverage ratio, which excludes unsecured and subordinated debt, that cannot exceed 2.50 to 1.00;


•	A minimum interest coverage ratio that cannot be less than 2.50 to 1.00; and


•	If our senior consolidated leverage ratio is greater than 2.00 to 1.00 at the end of any fiscal quarter, our minimum asset coverage ratio cannot be less than 1.00 to 1.00.

At September 30, 2015, our senior consolidated leverage ratio was not greater than 2.00 to 1.00 and therefore, we were not subject to the capital expenditure threshold restrictions listed above.

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


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


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


•	create liens on our assets;


•	enter into sale and leaseback transactions;


•	sell or transfer assets;


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


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


•	enter into transactions with affiliates; and


•	enter into new lines of business.

Our Senior Notes are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by our existing domestic subsidiaries, except for Pioneer Services Holdings, LLC. The subsidiaries that generally operate our non-U.S. business concentrated in Colombia do not guarantee our Senior Notes. The non-guarantor subsidiaries do not have any payment obligations under the Senior Notes, the guarantees or the Indenture. In the event of a bankruptcy, liquidation or reorganization of any non-guarantor subsidiary, such non-guarantor subsidiary will pay the holders of its debt and other liabilities, including its trade creditors, before it will be able to distribute any of its assets to us. In the future, any non-U.S. subsidiaries, immaterial subsidiaries and subsidiaries that we designate as unrestricted subsidiaries under the Indenture will not guarantee the Senior Notes.

Our Senior Notes are not subject to any sinking fund requirements. As of September 30, 2015, there were no restrictions on the ability of subsidiary guarantors to transfer funds to the parent company, and we were in compliance with all covenants pertaining to our Senior Notes.

Results of Operations

Statements of Operations Analysis

The following table provides information about our operations for the three and nine months ended September 30, 2015 and 2014 (amounts in thousands, except average number of drilling rigs, utilization rate and revenue day information).



	Three months ended September 30,						Nine months ended September 30,
	2015			2014			2015			2014
Drilling Services Segment:
Revenues	$	41,238		$	128,117		$	198,212		$	373,627
Operating costs	22,875			88,963			118,114			250,904
Drilling Services Segment margin	$	18,363		$	39,154		$	80,098		$	122,723

Average number of drilling rigs	35.9			62.0			39.7			62.0
Utilization rate	49		%	88		%	67		%	86		%
Revenue days	1,618			5,028			7,197			14,554

Average revenues per day	$	25,487		$	25,481		$	27,541		$	25,672
Average operating costs per day	14,138			17,694			16,412			17,240
Drilling Services Segment margin per day	$	11,349		$	7,787		$	11,129		$	8,432

Production Services Segment:
Revenues	$	66,242		$	145,150		$	238,093		$	398,486
Operating costs	48,643			89,993			170,517			250,140
Production Services Segment margin	$	17,599		$	55,157		$	67,576		$	148,346

Combined:
Revenues	$	107,480		$	273,267		$	436,305		$	772,113
Operating costs	71,518			178,956			288,631			501,044
Combined margin	$	35,962		$	94,311		$	147,674		$	271,069

Adjusted EBITDA	$	18,829		$	78,108		$	90,783		$	211,092

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. We believe that Drilling Services Segment margin and Production Services Segment margin are useful measures for evaluating financial performance, although they are not measures of financial performance under GAAP. However, Drilling Services Segment margin and Production Services Segment margin are common measures of operating performance used by investors, financial analysts, rating agencies and Pioneer Energy Services Corp.'s management. Drilling Services Segment margin and Production Services Segment margin as presented may not be comparable to other similarly titled measures reported by other companies.

Adjusted EBITDA represents income (loss) before interest expense, income tax (expense) benefit, depreciation and amortization, loss on extinguishment of debt and impairments. We use this non-GAAP measure, together with our GAAP financial metrics, to assess our financial performance and evaluate our overall progress towards meeting our long-term financial objectives. We believe that this measure is useful to investors and analysts in allowing for greater transparency of our 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 September 30,						Nine months ended September 30,
	2015			2014			2015			2014
	(amounts in thousands)
Reconciliation of combined margin and Adjusted EBITDA to net income (loss):
Combined margin	$	35,962		$	94,311		$	147,674		$	271,069
General and administrative	(16,814		)	(26,613		)	(56,909		)	(76,372		)
Bad debt expense	1,071			(19		)	358			(456		)
Gain on dispositions of property and equipment	(605		)	(142)			2,639			1,589
Gain on sale of fishing and rental services operations	—			10,702			—			10,702
Gain on settlement of litigation	—			1,324			—			4,200
Other income (expense)	(785		)	(1,455		)	(2,979		)	360
Adjusted EBITDA	18,829			78,108			90,783			211,092
Depreciation and amortization	(35,257		)	(46,081		)	(115,528		)	(137,398		)
Impairment charges	(2,329		)	(678		)	(79,648		)	(678		)
Interest expense	(5,465		)	(8,969		)	(16,165		)	(32,085		)
Loss on extinguishment of debt	—			—			—			(22,482		)
Income tax (expense) benefit	6,682			(9,927		)	13,718			(8,894		)
Net income (loss)	$	(17,540	)	$	12,453		$	(106,840	)	$	9,555

Both our Drilling Services and Production Services Segments experienced a significant decline in activity during the three and nine months ended September 30, 2015, as compared to the corresponding periods in 2014, due to the current downturn in our industry. Our combined margin decreased for the three and nine months ended September 30, 2015 as compared to the corresponding periods in 2014, 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 from rigs that were earning but not working during 2015 and due to the disposal of 28 mechanical and lower horsepower electric drilling rigs from our fleet which generally earned lower margins per day.

Our Drilling Services Segment’s revenues decreased by $86.9 million, or 68%, and $175.4 million, or 47%, and our Drilling Services Segment’s operating costs decreased by $66.1 million, or 74%, and $132.8 million, or 53%, for the three and nine months ended September 30, 2015, respectively, as compared to the corresponding periods in 2014, primarily resulting from a decrease in revenue days and lower average operating costs per day. Revenue days decreased primarily due to the significant decrease in demand in our industry. In addition, we sold 28 mechanical and lower horsepower electric drilling rigs during 2015.

Our average revenues per day increased by $1,869 per day, or 7%, for the nine months ended September 30, 2015, as compared to the corresponding period in 2014. Our average revenues per day increased primarily because the drilling rigs which we removed from our fleet, as described above, were generally earning lower dayrates as compared to the rest of our fleet. Our average operating costs per day decreased by $3,556 per day, or 20%, and $828 per day, or 5%, for the three and nine months ended September 30, 2015, respectively, as compared to the corresponding periods in 2014, primarily due to reduced costs from drilling rigs which were early terminated and were thus earning revenues while incurring minimal operating costs.

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. We completed one and 17 turnkey contracts during the three and nine months ended September 30, 2015, respectively, as compared to 32 and 68 turnkey drilling contracts completed during the corresponding periods in

2014, respectively. The following table provides the percentages of our drilling revenues by drilling contract type for the three and nine months ended September 30, 2015 and 2014:



	Three months ended September 30,				Nine months ended September 30,
	2015		2014		2015		2014
Daywork contracts	98	%	93	%	97	%	95	%
Turnkey contracts	2	%	7	%	3	%	5	%

Our Production Services Segment's revenues decreased by $78.9 million, or 54%, and $160.4 million, or 40%, for the three and nine months ended September 30, 2015, respectively, as compared to the corresponding periods in 2014, while operating costs decreased by 46% and 32%, 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 49% and 42% for the three and nine months ended September 30, 2015, as compared to the corresponding periods in 2014. The total rig hours for our well servicing fleet decreased by 34% and 23%, for the three and nine months ended September 30, 2015, as compared to the corresponding periods in 2014. Our coiled tubing utilization decreased to 25% and 28% for the three and nine months ended September 30, 2015 from 56% and 53% during the corresponding periods in 2014.

Our general and administrative expense decreased by approximately $9.8 million, or 37%, and $19.5 million, or 25%, for the three and nine months ended September 30, 2015, respectively, as compared to the corresponding periods in 2014, primarily due to a decrease in compensation costs. The decrease in compensation expense is primarily due to the reduction in our workforce during 2015, a reduction in stock-based compensation due to a decrease in certain long-term performance-based compensation plans' actual and projected achievement levels, and reduced incentive compensation for 2015.

Our gains on disposition of assets during the nine months ended September 30, 2015 are primarily related to the sale of 28 of our mechanical and lower horsepower drilling rigs. Our gains on disposition of assets during the nine months ended September 30, 2014 are primarily related to the sale of our trucking assets in February 2014.

In September 2014, we sold our fishing and rental services operations for total consideration of $16.1 million, resulting in a pretax gain of $10.7 million.

We recognized gains of $4.2 million related to settlements of litigation in our favor related to non-compete agreements during the nine months ended September 30, 2014.

Our other expense of $3.0 million for the nine months ended September 30, 2015 is primarily related to net foreign currency losses recognized for our Colombian operations due to the rise in the value of the U.S. dollar relative to the Colombian peso, and the net wealth tax obligation which was assessed in January 2015 by the Colombian government.

Our depreciation and amortization expenses decreased by $10.8 million and $21.9 million for the three and nine months ended September 30, 2015, respectively, as compared to the corresponding periods in 2014, primarily as a result of the sales of drilling rigs and equipment during 2014 and 2015, as well as impairment charges to reduce the carrying values of certain drilling rigs to fair value.

We recognized $79.6 million of impairment charges during the nine months ended September 30, 2015, primarily to reduce the carrying values of all eight drilling rigs in Colombia and certain other assets associated with our Colombian operations, as well as the six non-AC electric drilling rigs in our domestic fleet that are not pad-capable, to their estimated fair values. During the nine months ended September 30, 2014, we recorded impairment charges of $0.7 million to reduce the carrying value of certain drilling equipment and real estate property which were held for sale to their estimated fair value less costs to sell.

Our interest expense decreased by $3.5 million and $15.9 million for the three and nine months ended September 30, 2015, respectively, as compared to the corresponding periods in 2014 due to the redemption of our 2010 and 2011

Senior Notes in 2014, which incurred interest at a higher rate than the 2014 Senior Notes which we issued in March 2014, as well as the repayments we made in 2014 and 2015 to reduce the level of debt outstanding under our Revolving Credit Facility.

Our loss on debt extinguishment during the nine months ended September 30, 2014 represents the tender and redemption premiums and the write-off of net unamortized debt discount and debt issuance costs associated with the 2010 and 2011 Senior Notes that were redeemed in March and May 2014.

Our effective income tax rate for the nine months ended September 30, 2015 was lower than the federal statutory rate in the United States primarily due to valuation allowances on Colombian deferred tax assets, the effect of foreign currency translation and the nondeductible Colombian net wealth tax.

Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements.

Critical Accounting Policies and Estimates

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 60 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 percentage-of-completion method based on our estimate of the number of days to complete each contract. All of our revenues are recognized net of applicable sales taxes.

Our management has determined that it is appropriate to use the percentage-of-completion method to recognize revenue on our turnkey contracts. Although our turnkey contracts do not have express terms that provide us with rights to receive payment for the work that we perform prior to drilling wells to the agreed-on depth, we use this method because, as provided in applicable accounting literature, we believe we achieve a continuous sale for our work-in-progress and believe, under applicable state law, we ultimately could recover the fair value of our work-in-progress even in the event we were unable to drill to the agreed-on depth in breach of the applicable contract. However, in the event we were unable to drill to the agreed-on depth in breach of the contract, ultimate recovery of that value would be subject to negotiations with the client and the possibility of litigation.

If a client defaults on its payment obligation to us under a turnkey contract, we would need to rely on applicable law to enforce our lien rights, because our turnkey contracts do not expressly grant to us a security interest in the work we have completed under the contract and we have no ownership rights in the work-in-progress or completed drilling work, except any rights arising under the applicable lien statute on foreclosure. If we were unable to drill to the agreed-on depth in breach of the contract, we also would need to rely on equitable remedies outside of the contract available in applicable courts to recover the fair value of our work-in-progress under a turnkey contract.

The risks to us under a turnkey contract are substantially greater than on a contract drilled on a daywork basis. Under a turnkey contract, we assume most of the risks associated with drilling operations that are generally assumed by the operator in a daywork contract, including the risks of blowout, loss of hole, stuck drill pipe, machinery breakdowns and abnormal drilling conditions, as well as risks associated with subcontractors’ services, supplies, cost escalations and personnel operations.

We accrue estimated contract costs on turnkey contracts for each day of work completed based on our estimate of the total costs to complete the contract divided by our estimate of the number of days to complete the contract. Contract costs include labor, materials, supplies, repairs and maintenance, operating overhead allocations and allocations of depreciation and amortization expense. In addition, the occurrence of uninsured or under-insured losses or operating cost overruns on our turnkey contracts could have a material adverse effect on our financial position and results of operations. Therefore, our actual results for a contract could differ significantly if our cost estimates for that contract are later revised from our original cost estimates for a contract in progress at the end of a reporting period which was not completed prior to the release of our financial statements.

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 would determine the fair value of the asset group. The amount of an impairment charge would be measured as the difference between the carrying amount and the fair value of these 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 deferred taxes, 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.

Our initial cost estimates for turnkey contracts do not include cost estimates for risks such as stuck drill pipe or loss of circulation. When we encounter, during the course of our drilling operations, conditions unforeseen in the preparation of our original cost estimate, we increase our cost estimate to complete the contract. If we anticipate a loss on a contract in progress at the end of a reporting period 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 such as lost circulation, stuck drill pipe or an underground blowout on contracts still in progress subsequent to the release of the financial statements.

We believe that our experienced management team, our knowledge of geologic formations in our areas of operations, the condition of our drilling equipment and our experienced crews have previously enabled us to make reasonable cost estimates and complete contracts according to our drilling plan. While we do bear the risk of loss for cost overruns and other events that are not specifically provided for in our initial cost estimates, our pricing of turnkey contracts takes such risks into consideration. We are more likely to encounter losses on turnkey contracts in periods in which revenue rates are lower for all types of contracts. However, during periods of reduced demand for drilling rigs, our overall profitability on turnkey contracts has historically exceeded our profitability on daywork contracts.

We incurred a total loss of $0.5 million on three of the 17 turnkey contracts which were completed during the nine months ended September 30, 2015, and we incurred a total loss of $0.8 million on eight of the 68 turnkey contracts completed during the nine months ended September 30, 2014. As of September 30, 2015, we did not have any 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 $1.6 million at September 30, 2015.

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. Beginning in October 2014, domestic and international oil prices have declined significantly resulting in a downturn in our industry, affecting both drilling and production services.

As the downturn worsened through 2015 resulting in significantly reduced revenue and utilization rates, and projections that reflect a more delayed recovery than previously anticipated, we performed impairment testing on all

the non-AC electric drilling rigs in our fleet, including the eight drilling rigs in Colombia, and our coiled tubing operations as of June 30, 2015. Our analysis at June 30, 2015 indicated that the carrying value of our coiled tubing reporting unit and the carrying value of our six pad-capable non-AC drilling rigs in our fleet (those that are equipped with either a walking or skidding system) were recoverable and thus there was no impairment present at June 30, 2015. However, our analysis indicated 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 recorded $69.8 million of impairment charges during 2015 to reduce the carrying values of these assets to their estimated fair values, based on market appraisals which are considered Level 3 inputs as defined by ASC Topic 820, Fair Value Measurements and Disclosures.

As of September 30, 2015, we had $82.3 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 only recognize a tax benefit to the extent of taxable income that we expect to earn in the jurisdiction in future periods. We estimate that our domestic operations will result in taxable income in excess of our net operating losses and we expect to apply the net operating losses against the current year taxable income and taxable income that we have estimated in future periods. However, as a result of the conditions leading to the impairment of our assets in Colombia, we recorded a valuation allowance of $18.7 million that fully offsets our foreign deferred tax assets relating to net operating losses and other tax benefits.

Our accrued insurance premiums and deductibles as of September 30, 2015 include accruals for costs incurred under the self-insurance portion of our health insurance of approximately $1.6 million and our workers’ compensation, general liability and auto liability insurance of approximately $6.5 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 stock-based 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 stock-based 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


Item 3.	Quantitative and Qualitative Disclosures About Market Risk

Interest Rate Risk

We are subject to interest rate market risk on our variable rate debt. As of September 30, 2015, we had $110.0 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 $0.8 million, and a corresponding increase or decrease, respectively, in net income of approximately $0.5 million during the nine months ended September 30, 2015. 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, 2015.

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 losses of $2.8 million for the nine months ended September 30, 2015.


Item 4.	Controls and Procedures

In accordance with Exchange Act Rules 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of September 30, 2015, 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.

There has been no change in our internal control over financial reporting that occurred during the three months ended September 30, 2015 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II - OTHER INFORMATION


Item 1.	Legal Proceedings

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


Item 1A.	Risk Factors

Not applicable.


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

We did not make any unregistered sales of equity securities during the quarter ended September 30, 2015. The following table provides information relating to our repurchase of common shares during the quarter ended September 30, 2015:



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
July 1—July 31	3,153	$	5.46	—	—
August 1—August 31	—	$	—	—	—
September 1—September 30	440	$	2.56	—	—
Total	3,593	$	5.10	—	—


(1)	The shares indicated consist of shares of our common stock tendered by employees to the Company during the three months ended September 30, 2015, 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+*	-	Amended and Restated Pioneer Energy Services Corp. 2007 Incentive Plan (Appendix A of definitive proxy statement on Schedule 14A dated April 20, 2015 (File No. 1-8182)).

10.2*	-	Third Amendment dated as of September 15, 2015, by and among Pioneer Energy Services Corp., a Texas corporation, the lenders party thereto, and Wells Fargo Bank, N.A., as administrative agent for the lenders (Form 8-K dated September 15, 2015 (File No. 1-8182, Exhibit 4.1)).

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

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

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

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

101**	-	The following financial statements from Pioneer Energy Services Corp.’s Form 10-Q for the quarter ended September 30, 2015, 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: October 29, 2015

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+*	-	Amended and Restated Pioneer Energy Services Corp. 2007 Incentive Plan (Appendix A of definitive proxy statement on Schedule 14A dated April 20, 2015 (File No. 1-8182)).

10.2*	-	Third Amendment dated as of September 15, 2015, by and among Pioneer Energy Services Corp., a Texas corporation, the lenders party thereto, and Wells Fargo Bank, N.A., as administrative agent for the lenders (Form 8-K dated September 15, 2015 (File No. 1-8182, Exhibit 4.1)).

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

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

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

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

101**	-	The following financial statements from Pioneer Energy Services Corp.’s Form 10-Q for the quarter ended September 30, 2015, 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.

PIONEER ENERGY SERVICES CORP - FORM 10-Q - October 29, 2015

Attached files

PIONEER ENERGY SERVICES CORP Reports