Edgar Filing: PIONEER ENERGY SERVICES CORP

2014 Q2 10Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

______________________________________________

FORM 10-Q

______________________________________________

(Mark one)



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

For the quarterly period ended June 30, 2014



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

Commission File Number: 1-8182

PIONEER ENERGY SERVICES CORP.

(Exact name of registrant as specified in its charter)

_____________________________________________



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

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

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

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

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

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



Large accelerated filer	o	Accelerated filer	x

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

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

As of July 15, 2014, there were 63,200,570 shares of common stock, par value $0.10 per share, of the registrant outstanding.

PART 1. FINANCIAL INFORMATION


Item 1.	Financial Statements

PIONEER ENERGY SERVICES CORP. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS



	June 30, 2014			December 31, 2013
	(unaudited)			(audited)
	(in thousands, except share data)
ASSETS
Current assets:
Cash and cash equivalents	$	23,711		$	27,385
Receivables:
Trade, net of allowance for doubtful accounts	132,215			115,908
Unbilled receivables	52,156			49,535
Insurance recoveries	9,717			8,607
Income taxes and other	6,449			2,310
Deferred income taxes	32,365			13,092
Inventory	13,466			13,232
Prepaid expenses and other current assets	9,390			9,311
Total current assets	279,469			239,380
Property and equipment, at cost	1,778,653			1,724,124
Less accumulated depreciation	855,213			786,467
Net property and equipment	923,440			937,657
Intangible assets, net of accumulated amortization of $36.3 million and $32.8 million at June 30, 2014 and December 31, 2013, respectively	28,276			32,269
Noncurrent deferred income taxes	4,010			1,156
Other long-term assets	16,236			19,161
Total assets	$	1,251,431		$	1,229,623

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	54,735		$	43,718
Current portion of long-term debt	429			2,847
Deferred revenues	3,306			699
Accrued expenses:
Payroll and related employee costs	29,644			30,020
Insurance premiums and deductibles	11,575			10,940
Insurance claims and settlements	9,716			8,607
Interest	8,744			12,275
Other	12,104			11,727
Total current liabilities	130,253			120,833
Long-term debt, less current portion	493,630			499,666
Noncurrent deferred income taxes	102,988			84,636
Other long-term liabilities	4,771			6,055
Total liabilities	731,642			711,190
Commitments and contingencies (Note 7)
Shareholders’ equity:
Preferred stock, 10,000,000 shares authorized; none issued and outstanding	—			—
Common stock $.10 par value; 100,000,000 shares authorized; 63,101,570 and 62,534,636 shares outstanding at June 30, 2014 and December 31, 2013, respectively	6,342			6,275
Additional paid-in capital	462,131			456,812
Treasury stock, at cost; 316,682 and 219,304 shares at June 30, 2014 and December 31, 2013, respectively	(3,027		)	(1,895		)
Accumulated earnings	54,343			57,241
Total shareholders’ equity	519,789			518,433
Total liabilities and shareholders’ equity	$	1,251,431		$	1,229,623

See accompanying notes to condensed consolidated financial statements.

PIONEER ENERGY SERVICES CORP. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(unaudited)



	Three months ended June 30,						Six months ended June 30,
	2014			2013			2014			2013
	(in thousands, except per share data)
Revenues:
Drilling services	$	127,553		$	138,250		$	245,510		$	271,324
Production services	132,259			110,104			253,336			206,700
Total revenues	259,812			248,354			498,846			478,024
Costs and expenses:
Drilling services	83,762			89,294			160,100			178,280
Production services	82,505			70,450			160,257			131,069
Depreciation and amortization	45,791			47,348			91,317			93,633
General and administrative	25,276			23,605			49,759			46,659
Bad debt expense	561			137			437			418
Impairment charges	—			44,788			—			44,788
Total costs and expenses	237,895			275,622			461,870			494,847
Income (loss) from operations	21,917			(27,268		)	36,976			(16,823		)
Other (expense) income:
Interest expense	(10,728		)	(12,331		)	(23,116		)	(23,793		)
Loss on extinguishment of debt	(14,595		)	—			(22,482		)	—
Other	2,017			(1,249		)	4,691			(2,070		)
Total other expense	(23,306		)	(13,580		)	(40,907		)	(25,863		)
Loss before income taxes	(1,389		)	(40,848		)	(3,931		)	(42,686		)
Income tax benefit	1,070			14,953			1,033			15,499
Net loss	$	(319	)	$	(25,895	)	$	(2,898	)	$	(27,187	)

Loss per common share—Basic	$	(0.01	)	$	(0.42	)	$	(0.05	)	$	(0.44	)

Loss per common share—Diluted	$	(0.01	)	$	(0.42	)	$	(0.05	)	$	(0.44	)

Weighted average number of shares outstanding—Basic	62,877			62,177			62,710			62,073

Weighted average number of shares outstanding—Diluted	62,877			62,177			62,710			62,073

See accompanying notes to condensed consolidated financial statements.

PIONEER ENERGY SERVICES CORP. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited)



	Six months ended June 30,
	2014			2013
	(in thousands)
Cash flows from operating activities:
Net loss	$	(2,898	)	$	(27,187	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation and amortization	91,317			93,633
Allowance for doubtful accounts	396			408
Gain on dispositions of property and equipment	(1,731		)	(1,721		)
Stock-based compensation expense	3,827			3,064
Amortization of debt issuance costs, discount and premium	1,504			1,534
Loss on extinguishment of debt	22,482			—
Impairment charges	—			44,788
Deferred income taxes	(3,762		)	(16,717		)
Change in other long-term assets	4,448			(2,113		)
Change in other long-term liabilities	(1,284		)	(1,340		)
Changes in current assets and liabilities:
Receivables	(23,463		)	(22,179		)
Inventory	(234		)	(592		)
Prepaid expenses and other current assets	(77		)	4,147
Accounts payable	7,667			353
Deferred revenues	2,607			(1,513		)
Accrued expenses	(5,312		)	(3,888		)
Net cash provided by operating activities	95,487			70,677

Cash flows from investing activities:
Purchases of property and equipment	(74,567		)	(112,179		)
Proceeds from sale of property and equipment	6,538			6,059
Net cash used in investing activities	(68,029		)	(106,120		)

Cash flows from financing activities:
Debt repayments	(330,013		)	(10,862		)
Proceeds from issuance of debt	320,000			40,000
Debt issuance costs	(6,187		)	(13		)
Tender premium costs	(15,381		)	—
Proceeds from exercise of options	1,581			789
Purchase of treasury stock	(1,132		)	(628		)
Net cash provided by (used in) financing activities	(31,132		)	29,286

Net decrease in cash and cash equivalents	(3,674		)	(6,157		)
Beginning cash and cash equivalents	27,385			23,733
Ending cash and cash equivalents	$	23,711		$	17,576

Supplementary disclosure:
Interest paid	$	25,250		$	23,180
Income tax paid	$	2,131		$	1,627

See accompanying notes to condensed consolidated financial statements.

PIONEER ENERGY SERVICES CORP. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1. Organization and Summary of Significant Accounting Policies

Business

Our Drilling Services Segment provides contract land drilling services with its fleet of 62 drilling rigs which are currently assigned to the following divisions:



Drilling Division	Rig Count
South Texas	14
West Texas	20
North Dakota	9
Utah	7
Appalachia	4
Colombia	8
	62

As of June 30, 2014, 57 of our 62 drilling rigs are earning revenues under drilling contracts, 43 of which are under term contracts, and we are actively marketing all of our idle drilling rigs. All eight of our drilling rigs in Colombia are currently under term contracts that extend through the end of 2014, seven of which are currently earning revenues with the remaining rig waiting on the well site location to be prepared by our client. We are also currently constructing three new-build 1,500 HP AC drilling rigs which we expect to deliver and begin operating under long-term drilling contracts in the second and third quarters of 2015.

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, turnkey or footage 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.

Our Production Services Segment provides a range of services to exploration and production companies, including well servicing, wireline services, coiled tubing services, and fishing and rental 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 June 30, 2014, we have a fleet of 112 well servicing rigs consisting of one hundred two 550 horsepower rigs and ten 600 horsepower rigs, all of which are currently operating or are being actively marketed. We currently provide wireline services and coiled tubing services with a fleet of 121 wireline units and 14 coiled tubing units, and we provide rental services with a gross book value of $17.4 million in fishing and rental tools.

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 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, 2013.

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 fair value 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 June 30, 2014, through the filing of this Form 10-Q, for inclusion as necessary.

Drilling Contracts

Our drilling contracts generally provide for compensation on either a daywork, turnkey or footage 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. During periods of high rig demand, or for our newly constructed rigs, we enter into longer-term drilling contracts. Currently, we have contracts with original terms of six months to four years in duration. As of June 30, 2014, we have 44 drilling rigs under term contracts, which if not renewed at 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	36	21	8	2	3	2
Colombia	8	8	—	—	—	—
	44	29	8	2	3	2

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 and footage drilling contracts are invoiced upon completion of the contract.

Our unbilled receivables totaled $52.2 million at June 30, 2014, of which $0.4 million related to turnkey drilling contract revenues, $47.1 million represented revenue recognized but not yet billed on daywork drilling contracts in progress at June 30, 2014 and $4.7 million related to unbilled receivables for our Production Services Segment.

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.

Property and Equipment

During the six months ended June 30, 2014 and 2013, we spent $74.6 million and $112.2 million, respectively, on purchases of property and equipment. As of June 30, 2014 and December 31, 2013, capital expenditures for property and equipment that has not yet been placed in service was $43.8 million and $19.4 million, respectively. During the six months ended June 30, 2014 and 2013, we capitalized $0.1 million and $0.9 million, respectively, of interest costs incurred during the construction periods of new-build drilling rigs and other drilling equipment.

We recorded gains on disposition of our property and equipment of $1.7 million for both the six months ended June 30, 2014 and 2013 in our drilling and production services costs and expenses. In February 2014, we completed the sale of our trucking assets for a sales price of $4.5 million which included a fleet of 40 trucks and related transportation equipment that we used to transport our drilling rigs to and from drilling sites. By owning our own trucks, we have historically been able to reduce the overall cost and downtime between rig moves. However, with the industry trend toward pad drilling, we have upgraded a number of our drilling rigs in recent years to equip them with walking or skidding systems, which enable the drilling rigs to move between wells in pad drilling, and thus operating our own trucking fleet has become less beneficial. The net book value of the trucking assets sold was $3.4 million, for which we recognized a total gain of $1.1 million in our condensed consolidated statement of operations for the first quarter of 2014. During the second quarter of 2013, we sold two mechanical drilling rigs that were previously idle in our East Texas division, for which we recognized an associated gain of approximately $0.8 million.

As of June 30, 2014, we have identified certain real estate properties and other production services equipment which are currently held for sale. The total value of these properties, which are recorded at the lower of cost or fair market value and which is included in property and equipment in our condensed consolidated balance sheet, is approximately $0.7 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, coiled tubing and fishing and rental services). For our Drilling Services Segment, we perform an impairment evaluation and estimate future undiscounted cash flows for individual drilling rig assets. 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.

Intangible Assets

Substantially all of 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, coiled tubing and fishing and rental services). 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.

Due to several significant adverse factors affecting our coiled tubing services reporting unit, including increased competition in certain coiled tubing markets, turnover of key personnel and lower than anticipated utilization, all of which contributed to a decline in our projected cash flows for the coiled tubing reporting unit, we performed an impairment analysis of our long-lived tangible and intangible assets as of June 30, 2013. We determined that the sum of the estimated future undiscounted net cash flows for our coiled tubing services reporting unit was less than the carrying amount at June 30, 2013. We then performed a valuation of the assets which resulted in a non-cash impairment charge of $3.1 million to reduce our intangible asset carrying value of client relationships. This impairment charge did not have an impact on our liquidity or debt covenants; however, it was a reflection of the increased competition in certain coiled tubing markets where we operate and a decline in our projected cash flows for the coiled tubing reporting unit.

The most significant inputs used in our impairment analysis 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. An increase of 1% in either the utilization or pricing assumptions would have resulted in a decrease to our impairment charge for our long-lived intangible assets of approximately $1 million. Similarly, a decrease of 1% in either of these assumptions would have led to an approximate $1 million increase to our impairment charge. 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. The assumptions used in estimating fair values and performing the impairment test are inherently uncertain and require management judgment.

Our impairment analysis did not result in any impairment charges to our coiled tubing tangible long-lived assets, substantially all of which was related to the 13 coiled tubing units owned at June 30, 2013. As discussed further below, we also recorded a non-cash impairment charge to reduce the carrying value of goodwill to zero.

Due to continued increases in competition in certain coiled tubing markets and lower than anticipated operating results, we performed another impairment analysis of our long-lived tangible and intangible assets as of December 31, 2013. We determined that the sum of the estimated future undiscounted net cash flows for our coiled tubing services reporting unit was in excess of the carrying amount and concluded that no impairment existed as of December 31, 2013. The future undiscounted cash flows used in our impairment analysis include projected increases in utilization and pricing from what we have historically experienced. 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. Our coiled tubing services' operating results for the six months ended June 30, 2014 are meeting our projections.

Goodwill

Goodwill results from business acquisitions and represents the excess of acquisition costs over the fair value of the net assets acquired. In connection with the acquisition of the production services business from Go-Coil, we recorded $41.7 million of goodwill at December 31, 2011, all of which was allocated to the coiled tubing services reporting unit within our Production Services Segment.

We perform a qualitative assessment of goodwill annually as of December 31 or more frequently if events or changes in circumstances indicate that the asset might be impaired. Circumstances that could indicate a potential impairment include a significant adverse change in the economic or business climate, a significant adverse change in legal factors, an adverse action or assessment by a regulator, unanticipated competition, loss of key personnel and the likelihood that a reporting unit or significant portion of a reporting unit will be sold or otherwise disposed of. In addition, these circumstances could lead to our net book value exceeding our market capitalization which is another indicator of a potential impairment of goodwill.

If our qualitative assessment of goodwill indicates a possible impairment, we test for goodwill impairment using a two-step process. First, the fair value of each reporting unit with goodwill is compared to its carrying value to determine whether an indication of impairment exists. Second, if impairment is indicated, then the fair value of the reporting unit's goodwill is determined by allocating the unit's fair value to its assets and liabilities (including any unrecognized intangible assets) as if the reporting unit had been acquired in a business combination on the impairment test date. The amount of impairment for goodwill is measured as the excess of the carrying value of the reporting unit over its fair value.

When estimating fair values of a reporting unit for our goodwill impairment test, we use an income approach which provides an estimated fair value based on the reporting unit’s anticipated cash flows that are discounted using a weighted average cost of capital rate. The primary assumptions used in the income approach are estimated cash flows and weighted average cost of capital. Estimated cash flows are primarily based on projected revenues, operating costs and capital expenditures and are discounted at a rate that is based on our weighted average cost of capital and estimated industry average rates for cost of capital. To ensure the reasonableness of the estimated fair value of our reporting units, we consider current industry market multiples and we perform a reconciliation of our total market capitalization to the total estimated fair value of all our reporting units.

Due to several significant adverse factors affecting our coiled tubing services reporting unit, including increased competition in certain coiled tubing markets, turnover of key personnel and lower than anticipated utilization, all of which contributed to a decline in our projected cash flows for the coiled tubing reporting unit, we performed an impairment analysis of our goodwill as of June 30, 2013. We determined that the fair value of our coiled tubing services reporting unit was less than its carrying value, including goodwill, and therefore, we performed the second step of the goodwill impairment test which led us to conclude that there would be no remaining implied fair value attributable to goodwill. Accordingly, we recorded a non-cash impairment charge of $41.7 million to reduce the carrying value of our goodwill to zero. This impairment charge did not have an impact on our liquidity or debt covenants; however, it was a reflection of the increased competition in certain coiled tubing markets where we operate and a decline in our projected cash flows for the coiled tubing reporting unit.

The most significant inputs used in our impairment analysis include the projected utilization and pricing of our coiled tubing services and the weighted average cost of capital (discount rate) used in order to calculate the discounted cash flows for the reporting unit. These inputs are classified as Level 3 inputs as defined by ASC Topic 820, Fair Value Measurements and Disclosures. We assumed a 13% discount rate to estimate the fair value of the coiled tubing services reporting unit. A decrease in this assumption of 5% would have resulted in a decrease to our goodwill impairment charge of approximately $3.5 million. An increase of 1% in either the utilization or pricing assumptions would have resulted in a decrease to our goodwill impairment charge of approximately $2 million or $3 million, respectively. 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. The assumptions used in estimating fair values of reporting units and performing the goodwill impairment test are inherently uncertain and require management judgment.

Other Long-Term Assets

Other long-term assets consist of noncurrent prepaid taxes in Colombia which are creditable against future income taxes, 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, professional and other fees. We routinely expense these items in the normal course of business over the periods these expenses benefit. Our other accrued expenses also consist of the current portion of the Colombian net equity tax.

Other Long-Term Liabilities

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

Recently Issued Accounting Standards

Discontinued Operations. In May 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2014-08, Discontinued Operations (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. This update, among other things, raises the threshold for a disposal to qualify for discontinued operations accounting and requires additional disclosures about disposals. We are required to apply this guidance prospectively beginning with our first quarterly filing in 2015.

Revenue Recognition. In May 2014, the FASB issued ASU No. 2014-09, a comprehensive new revenue recognition standard that will supersede nearly all existing revenue recognition guidance. The standard outlines a single comprehensive model for revenue recognition based on the core principle that a company will recognize revenue when promised goods or services are transferred to clients, in an amount that reflects the consideration to which an entity expects to be entitled in exchange for those goods or services. We are required to apply this new standard beginning with our first quarterly filing in 2017. We are currently evaluating the potential impact of this guidance, but at this time, do not expect that the adoption of this new standard will have a material effect 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. Debt

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



	June 30, 2014			December 31, 2013
Senior secured revolving credit facility	$	70,000		$	80,000
Senior notes	423,563			419,586
Other	496			2,927
	494,059			502,513
Less current portion	(429		)	(2,847		)
	$	493,630		$	499,666

Senior Secured Revolving Credit Facility

We have a credit agreement, as amended on June 30, 2011 and March 3, 2014, 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 $250 million, all of which matures on June 30, 2016 (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 $250 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 2.50% to 3.25% and 1.50% to 2.25%, respectively. The LIBOR margin and bank prime rate margin currently in effect are 3.00% and 2.00%, 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. Effective October 1, 2012, Pioneer Coiled Tubing Services, LLC was added as a subsidiary guarantor under the Revolving Credit Facility. Borrowings under the Revolving Credit Facility are available for acquisitions, working capital and other general corporate purposes.

As of June 30, 2014, we had $70.0 million outstanding under our Revolving Credit Facility and $14.0 million in committed letters of credit, which resulted in borrowing availability of $166.0 million under our Revolving Credit Facility. There are no limitations on our ability to access this borrowing capacity other than maintaining compliance with the covenants under the Revolving Credit Facility. At June 30, 2014, we were in compliance with our financial covenants under the Revolving Credit Facility. Our total consolidated leverage ratio was 2.0 to 1.0, our senior consolidated leverage ratio was 0.3 to 1.0, and our interest coverage ratio was 5.4 to 1.0. The financial covenants contained in our Revolving Credit Facility include the following:


•	A maximum total consolidated leverage ratio that cannot exceed 4.00 to 1.00;


•	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 capital expenditures as long as (a) no event of default exists under the Revolving Credit Facility or would result from such capital expenditures, (b) after giving effect to such capital expenditures there is availability under the Revolving Credit Facility equal to or greater than $25 million and (c) the senior consolidated leverage ratio as of the last day of the most recent reported fiscal quarter is less than 2.00 to 1.00. If the senior consolidated leverage ratio as of the last day 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 June 30, 2014, 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, redemptions of capital stock, 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.

On March 3, 2014, the Revolving Credit Facility was amended to increase the amount of unsecured debt that we could incur, in order to facilitate the offering of our 2014 Senior Notes and the use of proceeds therefrom to repurchase a portion of our 2010 and 2011 Senior Notes, as described in the following section.

Senior Notes

On March 11, 2010, we issued $250 million of unregistered senior notes with a coupon interest rate of 9.875% that are due in 2018 (the “2010 Senior Notes”). The 2010 Senior Notes were sold with an original issue discount of $10.6 million that was based on 95.75% of their face value, which will result in an effective yield to maturity of approximately 10.677%. On March 11, 2010, we received $234.8 million of net proceeds from the issuance of the 2010 Senior Notes after deductions were made for the $10.6 million of original issue discount and $4.6 million for underwriters’ fees and other debt offering costs. The net proceeds were used to repay a portion of the borrowings outstanding under our Revolving Credit Facility.

On November 21, 2011, we issued $175 million of unregistered Senior Notes (the “2011 Senior Notes”). The 2011 Senior Notes have the same terms and conditions as the 2010 Senior Notes. The 2011 Senior Notes were sold with an original issue premium of $1.8 million that was based on 101% of their face value, which will result in an effective yield to maturity of approximately 9.66%. On November 21, 2011, we received $172.7 million of net proceeds from the issuance of the 2011 Senior Notes, including the original issue premium, and after $4.1 million of deductions were made for underwriters' fees and other debt offering costs. A portion of the net proceeds were used to fund the acquisition of the coiled tubing business of Go-Coil, L.L.C. ("Go-Coil") in December 2011.

In accordance with a registration rights agreement with the holders of both our 2010 Senior Notes and 2011 Senior Notes, we filed exchange offer registration statements on Form S-4 with the Securities and Exchange Commission that became effective on September 2, 2010 and July 13, 2012, respectively. These exchange offer registration statements enabled the holders of both our 2010 Senior Notes and 2011 Senior Notes to exchange their senior notes for publicly registered notes with substantially identical terms. References to the “2010 Senior Notes” and “2011 Senior Notes” herein include the senior notes issued in the exchange offers.

The 2010 and 2011 Senior Notes will mature on March 15, 2018 with interest due semi-annually in arrears on March 15 and September 15 of each year. We have the option to redeem the 2010 and 2011 Senior Notes, in whole or in part, at any time (on or after March 15, 2014) in each case at the redemption price specified in the Indenture dated March 11, 2010 (the “2010 and 2011 Indenture”) plus any accrued and unpaid interest and any additional interest thereon to the date of redemption.

In order to reduce our overall interest expense and lengthen the overall maturity of our senior indebtedness, on March 4, 2014, we announced a tender offer for up to an aggregate principal amount of $300 million of our 2010 and 2011 Senior Notes, to be funded by proceeds from the issuance of our 2014 Senior Notes, which is further described below. The tender offer for our 2010 and 2011 Senior Notes expired on March 31, 2014, at which time we had received valid tenders with respect to approximately $99.5 million of the $425 million aggregate principal amount of 2010 and 2011 Senior Notes outstanding. The holders of the $99.5 million of 2010 and 2011 Senior Notes tendered received the total consideration of $1,055.08 for each $1,000 principal amount, the premium portion of which totaled approximately $5.5 million, which was recorded as loss on debt extinguishment during the three months ended March 31, 2014. Additionally, we wrote off $1.2 million related to the net unamortized discount and $1.2 million of unamortized debt costs associated with the $99.5 million of notes tendered, for a total loss on extinguishment of $7.9 million.

On April 1, 2014, we announced the redemption of $200.5 million in aggregate principal amount of the 2010 and 2011 Senior Notes (the "Redemption") which occurred on May 1, 2014 (the "Redemption Date") at a redemption price equal to 104.938% of the principal amount thereof, plus accrued and unpaid interest on the notes redeemed to, but not including, the Redemption Date. The redemption of these notes was primarily funded by the remaining net proceeds from the issuance of our 2014 Senior Notes described below, and through cash on hand. Upon redemption, we recognized a loss on debt extinguishment of approximately $14.6 million during the three months ended June 30, 2014, which included the redemption premium of $9.9 million, $2.4 million of net unamortized discount and $2.3 million of unamortized debt issuance costs associated with the Redemption.

The 2010 and 2011 Senior Notes are reflected on our condensed consolidated balance sheet at June 30, 2014 with a total carrying value of $123.6 million, which represents the $125.0 million total face value outstanding net of the $1.7 million unamortized portion of original issue discount and $0.3 million unamortized portion of original issue premium. The original issue discount and premium are being amortized over the term of the 2010 and 2011 Senior Notes based on the effective interest method.

On March 18, 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. On March 18, 2014, we received $293.9 million of net proceeds from the issuance of the 2014 Senior Notes after deductions were made for the $6.1 million for underwriters’ fees and other debt offering costs. The net proceeds were used to fund the tender and redemption of 2010 and 2011 Senior Notes in March and May 2014.

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 “2014 Indenture”) plus any accrued and unpaid interest and any additional interest (as defined in the 2014 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.

If we experience a change of control (as defined in the 2010 and 2011 Indenture and the 2014 Indenture (collectively, the "Indentures")), we will be required to make an offer to each holder of the 2010 Senior Notes, 2011 Senior Notes and 2014 Senior Notes (collectively, 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 Indentures, among other things, limit our ability and the ability of certain of our subsidiaries 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.

We were in compliance with these covenants as of June 30, 2014. 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 8, Guarantor/Non-Guarantor Condensed Consolidated Financial Statements.)

Other Debt

Our other debt consists of a short-term financing of insurance premiums with monthly payments due through August 2014 and a capital lease obligation for equipment with monthly payments due through November 2016.

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 June 2016. Costs incurred in connection with the issuance of our Senior Notes were capitalized and are being amortized using the straight-line method (which approximates the use of the interest method) over the term of the Senior Notes which mature in March 2018 and 2022.

Capitalized debt costs related to the issuance of our long-term debt were $9.1 million and $7.5 million as of June 30, 2014 and December 31, 2013, respectively. We recognized $1.1 million and $1.1 million of associated amortization during the six months ended June 30, 2014 and 2013, respectively, which excludes the $3.5 million of debt costs recognized as loss on extinguishment of debt.


3.	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 June 30, 2014 and December 31, 2013, our financial instruments consist primarily of cash, trade and other receivables, trade payables and long-term debt. The carrying value of cash, trade and other receivables, and trade payables are considered to be representative of their respective fair values due to the short-term nature of these instruments.

The fair value of our long-term debt is estimated using a discounted cash flow analysis, based on rates that we believe we would currently pay for similar types of debt instruments. This discounted cash flow analysis is based on inputs defined by ASC Topic 820 as level 2 inputs, which are observable inputs for similar types of debt instruments. The following table presents the supplemental fair value information about long-term debt at June 30, 2014 and December 31, 2013 (amounts in thousands):



	June 30, 2014				December 31, 2013
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Total debt	$	494,059	$	501,699	$	502,513	$	538,074


4.	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 June 30,						Six months ended June 30,
	2014			2013			2014			2013
Basic
Net loss	$	(319	)	$	(25,895	)	$	(2,898	)	$	(27,187	)

Weighted-average shares	62,877			62,177			62,710			62,073

Loss per common share—Basic	$	(0.01	)	$	(0.42	)	$	(0.05	)	$	(0.44	)

Diluted
Net loss	$	(319	)	$	(25,895	)	$	(2,898	)	$	(27,187	)

Weighted-average shares
Outstanding	62,877			62,177			62,710			62,073
Diluted effect of outstanding options, stock, restricted stock and restricted stock unit awards	—			—			—			—
	62,877			62,177			62,710			62,073

Loss per common share—Diluted	$	(0.01	)	$	(0.42	)	$	(0.05	)	$	(0.44	)

Potentially dilutive stock options, restricted stock and restricted stock unit awards representing a total of 3,213,088 and 4,170,854 shares of common stock for the three and six months ended June 30, 2014, respectively, and 5,584,899 and 5,461,022 for the three and six months ended June 30, 2013, respectively, were excluded from the computation of diluted weighted average shares outstanding due to their antidilutive effect.


5.	Equity Transactions and Stock-Based Compensation Plans

Equity Transactions

In May 2012, we filed a registration statement that permits us to sell equity or debt in one or more offerings up to a total dollar amount of $300 million. As of June 30, 2014, the entire $300 million under the shelf registration statement is available for equity or debt offerings. In the future, we may consider equity 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 six months ended June 30, 2014 and 2013 (amounts in thousands):



	Three months ended June 30,				Six months ended June 30,
	2014		2013		2014		2013
Stock option awards	$	310	$	421	$	653	$	947
Restricted stock awards	141		130		294		263
Restricted stock unit awards	1,520		1,001		2,880		1,854
	$	1,971	$	1,552	$	3,827	$	3,064

Stock Options

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

We estimate the fair value of each option grant on the date of grant using a Black-Scholes option pricing model. There were no stock options granted during the three months ended June 30, 2014 or 2013. The following table summarizes the assumptions used in the Black-Scholes option pricing model based on a weighted-average calculation for the six months ended June 30, 2014 and 2013:



	Six months ended June 30,
	2014		2013
Expected volatility	66	%	66	%
Risk-free interest rates	1.7	%	1.0	%
Expected life in years	5.49		5.53
Options granted	221,440		220,656
Grant-date fair value	$4.87		$4.36

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 six months ended June 30, 2014, 168,500 and 215,400 stock options were exercised at a weighted-average exercise price of $7.74 and $7.34, respectively. During the three and six months ended June 30, 2013, 104,500 and 162,867 stock options were exercised at a weighted-average exercise price of $4.73 and $4.84, 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, we reported all excess tax benefits resulting from the exercise of stock options as financing cash flows in our condensed consolidated statement of cash flows.

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 six months ended June 30, 2014 and 2013, we granted 32,100 and 61,248 shares of restricted stock awards, with a weighted-average grant-date fair value of $14.33 and $7.57, 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 June 30, 2014. The following table summarizes the number and weighted-average grant-date fair value of the restricted stock unit awards granted during the six months ended June 30, 2014 and the three and six months ended June 30, 2013:



	Three months ended June 30,		Six months ended June 30,
	2013		2014		2013
Time-based RSUs:
Time-based RSUs granted	252,749		347,335		406,027
Weighted-average grant-date fair value	$	7.54	$	8.44	$	7.59

Performance-based RSUs:
Performance-based RSUs granted	295,873		321,606		346,731
Weighted-average grant-date fair value	$	8.33	$	9.90	$	8.34

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 2011, 2012 and 2013, and half of the performance-based RSUs granted during 2014, are subject to a market condition based on total shareholder return, 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, if any. The remaining performance-based RSUs are subject to performance conditions, based on EBITDA and return on capital employed, 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 2014, we determined that 116.6% of the target number of shares granted during 2011 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, 2011 through December 31, 2013. The performance-based RSUs granted during 2011 have vested and were converted to common stock at the end of April 2014.

As of June 30, 2014, we estimated that our actual achievement level for the performance-based RSUs granted during 2012, 2013 and 2014 will be approximately 125%, 100% and 100% of the predetermined performance conditions, respectively.


6.	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.

Drilling Services Segment—Our Drilling Services Segment provides contract land drilling services to a diverse group of oil and gas exploration and production companies with its fleet of 62 drilling rigs which are currently assigned to the following divisions:



Drilling Division	Rig Count
South Texas	14
West Texas	20
North Dakota	9
Utah	7
Appalachia	4
Colombia	8
	62

Production Services Segment—Our Production Services Segment provides a range of services to exploration and production companies, including well servicing, wireline services, coiled tubing services, and fishing and rental 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 June 30, 2014, we have a fleet of 112 well servicing rigs consisting of one hundred two 550 horsepower rigs and ten 600 horsepower rigs. We provide wireline services and coiled tubing services with a fleet of 121 wireline units and 14 coiled tubing units, and we provide rental services with a gross book value of $17.4 million in fishing and rental tools.

The following tables set forth certain financial information for our two operating segments and corporate as of and for the three and six months ended June 30, 2014 and 2013 (amounts in thousands):



	As of and for the three months ended June 30, 2014
	Drilling Services Segment		Production Services Segment		Corporate		Total
Identifiable assets	$	778,148	$	413,308	$	59,975	$	1,251,431
Revenues	$	127,553	$	132,259	$	—	$	259,812
Operating costs	83,762		82,505		—		166,267
Segment margin	$	43,791	$	49,754	$	—	$	93,545
Depreciation and amortization	$	28,969	$	16,466	$	356	$	45,791
Capital expenditures	$	19,383	$	21,486	$	127	$	40,996



	As of and for the three months ended June 30, 2013
	Drilling Services Segment		Production Services Segment		Corporate		Total
Identifiable assets	$	849,649	$	414,729	$	27,155	$	1,291,533
Revenues	$	138,250	$	110,104	$	—	$	248,354
Operating costs	89,294		70,450		—		159,744
Segment margin	$	48,956	$	39,654	$	—	$	88,610
Depreciation and amortization	$	31,041	$	16,025	$	282	$	47,348
Capital expenditures	$	19,548	$	12,361	$	751	$	32,660



	As of and for the six months ended June 30, 2014
	Drilling Services Segment		Production Services Segment		Corporate		Total
Identifiable assets	$	778,148	$	413,308	$	59,975	$	1,251,431
Revenues	$	245,510	$	253,336	$	—	$	498,846
Operating costs	160,100		160,257		—		320,357
Segment margin	$	85,410	$	93,079	$	—	$	178,489
Depreciation and amortization	$	58,208	$	32,485	$	624	$	91,317
Capital expenditures	$	40,639	$	36,829	$	445	$	77,913



	As of and for the six months ended June 30, 2013
	Drilling Services Segment		Production Services Segment		Corporate		Total
Identifiable assets	$	849,649	$	414,729	$	27,155	$	1,291,533
Revenues	$	271,324	$	206,700	$	—	$	478,024
Operating costs	178,280		131,069		—		309,349
Segment margin	$	93,044	$	75,631	$	—	$	168,675
Depreciation and amortization	$	61,087	$	32,012	$	534	$	93,633
Capital expenditures	$	47,344	$	26,234	$	1,132	$	74,710

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 six months ended June 30, 2014 and 2013 (amounts in thousands):



	Three months ended June 30,						Six months ended June 30,
	2014			2013			2014			2013
Segment margin	$	93,545		$	88,610		$	178,489		$	168,675
Depreciation and amortization	(45,791		)	(47,348		)	(91,317		)	(93,633		)
General and administrative	(25,276		)	(23,605		)	(49,759		)	(46,659		)
Bad debt expense	(561		)	(137		)	(437		)	(418		)
Impairment charges	—			(44,788		)	—			(44,788		)
Income (loss) from operations	$	21,917		$	(27,268	)	$	36,976		$	(16,823	)

The following table sets forth certain financial information for our international operations in Colombia as of and for the three and six months ended June 30, 2014 and 2013 (amounts in thousands):



	As of and for the three months ended June 30,				As of and for the six months ended June 30,
	2014		2013		2014		2013
Identifiable assets	$	157,025	$	150,223	$	157,025	$	150,223
Revenues	$	25,527	$	30,627	$	47,691	$	61,402

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.


7.	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 $41.9 million relating to our performance under these bonds as of June 30, 2014.

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.


8.	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, and certain of our future domestic subsidiaries. Effective October 1, 2012, the 2010 and 2011 Indenture was supplemented to add Pioneer Coiled Tubing Services, LLC as a subsidiary guarantor. The subsidiaries that generally operate our non-U.S. business concentrated in Colombia do not guarantee our Senior Notes. The non-guarantor subsidiaries do not have any payment obligations under the Senior Notes, the guarantees or the Indenture.

In the event of a bankruptcy, liquidation or reorganization of any non-guarantor subsidiary, such non-guarantor subsidiary will pay the holders of its debt and other liabilities, including its trade creditors, before it will be able to distribute any of its assets to us. In the future, any non-U.S. subsidiaries, immaterial subsidiaries and subsidiaries that we designate as unrestricted subsidiaries under the Indenture will not guarantee the Senior Notes. As of June 30, 2014, there were no restrictions on the ability of subsidiary guarantors to transfer funds to the parent company.

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

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited, in thousands)



	June 30, 2014
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	22,010			(1,485		)	3,186			—			$	23,711
Receivables, net of allowance	1,203			146,019			54,424			(1,109		)	200,537
Intercompany receivable (payable)	(24,837		)	52,296			(27,459		)	—			—
Deferred income taxes	22,710			8,122			1,533			—			32,365
Inventory	—			7,423			6,043			—			13,466
Prepaid expenses and other current assets	1,592			5,364			2,434			—			9,390
Total current assets	22,678			217,739			40,161			(1,109		)	279,469
Net property and equipment	4,351			828,830			91,009			(750		)	923,440
Investment in subsidiaries	913,402			124,684			—			(1,038,086		)	—
Intangible assets, net of accumulated amortization	76			28,200			—			—			28,276
Noncurrent deferred income taxes	77,957			—			4,010			(77,957		)	4,010
Other long-term assets	9,230			1,722			5,284			—			16,236
Total assets	$	1,027,694		$	1,201,175		$	140,464		$	(1,117,902	)	$	1,251,431
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	1,447		$	47,929		$	5,359		—			$	54,735
Current portion of long-term debt	—			429			—			—			429
Deferred revenues	—			1,563			1,743			—			3,306
Accrued expenses	11,825			52,891			8,176			(1,109		)	71,783
Total current liabilities	13,272			102,812			15,278			(1,109		)	130,253
Long-term debt, less current portion	493,564			66			—			—			493,630
Noncurrent deferred income taxes	—			180,945			—			(77,957		)	102,988
Other long-term liabilities	319			3,950			502			—			4,771
Total liabilities	507,155			287,773			15,780			(79,066		)	731,642
Total shareholders’ equity	520,539			913,402			124,684			(1,038,836		)	519,789
Total liabilities and shareholders’ equity	$	1,027,694		$	1,201,175		$	140,464		$	(1,117,902	)	$	1,251,431

	December 31, 2013
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	28,368		$	(2,059	)	$	1,076		$	—		$	27,385
Receivables, net of allowance	905			125,979			49,476			—			176,360
Intercompany receivable (payable)	(24,837		)	52,671			(27,834		)	—			—
Deferred income taxes	1,143			8,005			3,944			—			13,092
Inventory	—			7,415			5,817			—			13,232
Prepaid expenses and other current assets	1,013			7,094			1,204			—			9,311
Total current assets	6,592			199,105			33,683			—			239,380
Net property and equipment	4,531			846,632			87,244			(750		)	937,657
Investment in subsidiaries	939,091			120,630			—			(1,059,721		)	—
Intangible assets, net of accumulated amortization	75			32,194			—			—			32,269
Noncurrent deferred income taxes	78,486			—			1,156			(78,486		)	1,156
Other long-term assets	7,513			2,009			9,639			—			19,161
Total assets	$	1,036,288		$	1,200,570		$	131,722		$	(1,138,957	)	$	1,229,623
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	757		$	37,797		$	5,164		$	—		$	43,718
Current portion of long-term debt	—			2,847			—			—			2,847
Deferred revenues	—			699			—			—			699
Accrued expenses	16,368			51,739			5,462			—			73,569
Total current liabilities	17,125			93,082			10,626			—			120,833
Long-term debt, less current portion	499,586			80			—			—			499,666
Noncurrent deferred income taxes	—			163,122			—			(78,486		)	84,636
Other long-term liabilities	394			5,195			466			—			6,055
Total liabilities	517,105			261,479			11,092			(78,486		)	711,190
Total shareholders’ equity	519,183			939,091			120,630			(1,060,471		)	518,433
Total liabilities and shareholders’ equity	$	1,036,288		$	1,200,570		$	131,722		$	(1,138,957	)	$	1,229,623

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited, in thousands)



	Three months ended June 30, 2014
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Revenues	$	—		$	234,285		$	25,527		$	—		$	259,812
Costs and expenses:
Operating costs	—			149,353			16,914			—			166,267
Depreciation and amortization	356			41,979			3,456			—			45,791
General and administrative	6,800			17,438			1,176			(138		)	25,276
Intercompany leasing	—			(1,215		)	1,215			—			—
Bad debt expense	—			561			—			—			561
Total costs and expenses	7,156			208,116			22,761			(138		)	237,895
Income (loss) from operations	(7,156		)	26,169			2,766			138			21,917
Other income (expense):
Equity in earnings of subsidiaries	19,707			3,512			—			(23,219		)	—
Interest expense	(10,707		)	(24		)	3			—			(10,728		)
Loss on extinguishment of debt	(14,595		)	—			—			—			(14,595		)
Other	7			617			1,531			(138		)	2,017
Total other income (expense)	(5,588		)	4,105			1,534			(23,357		)	(23,306		)
Income (loss) before income taxes	(12,744		)	30,274			4,300			(23,219		)	(1,389		)
Income tax expense (benefit)	12,425			(10,567		)	(788		)	—			1,070
Net income (loss)	$	(319	)	$	19,707		$	3,512		$	(23,219	)	$	(319	)



	Three months ended June 30, 2013
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Revenues	$	—		$	217,727		$	30,627		$	—		$	248,354
Costs and expenses:
Operating costs	—			138,946			20,798			—			159,744
Depreciation and amortization	282			43,745			3,321			—			47,348
General and administrative	6,085			16,867			791			(138		)	23,605
Intercompany leasing	—			(1,215		)	1,215			—			—
Bad debt expense	67			70			—			—			137
Impairment charges	—			44,788			—			—			44,788
Total costs and expenses	6,434			243,201			26,125			(138		)	275,622
Income (loss) from operations	(6,434		)	(25,474		)	4,502			138			(27,268		)
Other income (expense):
Equity in earnings of subsidiaries	(13,455		)	1,511			—			11,944			—
Interest expense	(12,341		)	—			10			—			(12,331		)
Other	1			574			(1,686		)	(138		)	(1,249		)
Total other income (expense)	(25,795		)	2,085			(1,676		)	11,806			(13,580		)
Income (loss) before income taxes	(32,229		)	(23,389		)	2,826			11,944			(40,848		)
Income tax expense (benefit)	6,334			9,934			(1,315		)	—			14,953
Net income (loss)	$	(25,895	)	$	(13,455	)	$	1,511		$	11,944		$	(25,895	)

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited, in thousands)



	Six months ended June 30, 2014
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Revenues	$	—		$	451,155		$	47,691		$	—		$	498,846
Costs and expenses:
Operating costs	—			288,840			31,517			—			320,357
Depreciation and amortization	625			83,843			6,849			—			91,317
General and administrative	13,535			34,636			1,864			(276		)	49,759
Intercompany leasing	—			(2,430		)	2,430			—			—
Bad debt expense	—			437			—			—			437
Total costs and expenses	14,160			405,326			42,660			(276		)	461,870
Income (loss) from operations	(14,160		)	45,829			5,031			276			36,976
Other (expense) income:
Equity in earnings of subsidiaries	32,592			4,087			—			(36,679		)	—
Interest expense	(23,106		)	(17		)	7			—			(23,116		)
Loss on extinguishment of debt	(22,482		)	—			—			—			(22,482		)
Other	2,886			1,288			793			(276		)	4,691
Total other (expense) income	(10,110		)	5,358			800			(36,955		)	(40,907		)
Income (loss) before income taxes	(24,270		)	51,187			5,831			(36,679		)	(3,931		)
Income tax (expense) benefit	21,372			(18,595		)	(1,744		)	—			1,033
Net income (loss)	$	(2,898	)	$	32,592		$	4,087		$	(36,679	)	$	(2,898	)




	Six months ended June 30, 2013
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Revenues	$	—		$	416,622		$	61,402		$	—		$	478,024
Costs and expenses:
Operating costs	—			268,162			41,187			—			309,349
Depreciation and amortization	534			86,447			6,652			—			93,633
General and administrative	11,511			33,845			1,579			(276		)	46,659
Intercompany leasing	—			(2,430		)	2,430			—			—
Bad debt expense	67			351			—			—			418
Impairment charges	—			44,788			—			—			44,788
Total costs and expenses	12,112			431,163			51,848			(276		)	494,847
Income (loss) from operations	(12,112		)	(14,541		)	9,554			276			(16,823		)
Other (expense) income:
Equity in earnings of subsidiaries	(4,266		)	3,853			—			413			—
Interest expense	(23,790		)	(20		)	17			—			(23,793		)
Other	2			857			(2,653		)	(276		)	(2,070		)
Total other (expense) income	(28,054		)	4,690			(2,636		)	137			(25,863		)
Income (loss) before income taxes	(40,166		)	(9,851		)	6,918			413			(42,686		)
Income tax (expense) benefit	12,979			5,585			(3,065		)	—			15,499
Net income (loss)	$	(27,187	)	$	(4,266	)	$	3,853		$	413		$	(27,187	)

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited, in thousands)



	Six months ended June 30, 2014
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidated
Cash flows from operating activities	$	25,255		$	57,484		$	12,748		$	95,487
Cash flows from investing activities:
Purchases of property and equipment	(494		)	(63,159		)	(10,914		)	(74,567		)
Proceeds from sale of property and equipment	—			6,262			276			6,538
	(494		)	(56,897		)	(10,638		)	(68,029		)
Cash flows from financing activities:
Debt repayments	(330,000		)	(13		)	—			(330,013		)
Proceeds from issuance of debt	320,000			—			—			320,000
Debt issuance costs	(6,187		)	—			—			(6,187		)
Tender premium costs	(15,381		)	—			—			(15,381		)
Proceeds from exercise of options	1,581			—			—			1,581
Purchase of treasury stock	(1,132		)	—			—			(1,132		)
	(31,119		)	(13		)	—			(31,132		)
Net increase (decrease) in cash and cash equivalents	(6,358		)	574			2,110			(3,674		)
Beginning cash and cash equivalents	28,368			(2,059		)	1,076			27,385
Ending cash and cash equivalents	$	22,010		$	(1,485	)	$	3,186		$	23,711



	Six months ended June 30, 2013
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidated
Cash flows from operating activities	$	(34,534	)	$	102,709		$	2,502		$	70,677
Cash flows from investing activities:
Purchases of property and equipment	(1,602		)	(103,574		)	(7,003		)	(112,179		)
Proceeds from sale of property and equipment	—			5,357			702			6,059
	(1,602		)	(98,217		)	(6,301		)	(106,120		)
Cash flows from financing activities:
Debt repayments	(10,000		)	(862		)	—			(10,862		)
Proceeds from issuance of debt	40,000			—			—			40,000
Debt issuance costs	(13		)	—			—			(13		)
Proceeds from exercise of options	789			—			—			789
Purchase of treasury stock	(628		)	—			—			(628		)
	30,148			(862		)	—			29,286
Net increase (decrease) in cash and cash equivalents	(5,988		)	3,630			(3,799		)	(6,157		)
Beginning cash and cash equivalents	18,479			(5,401		)	10,655			23,733
Ending cash and cash equivalents	$	12,491		$	(1,771	)	$	6,856		$	17,576


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, decisions about exploration and development projects to be made by oil and gas exploration and production companies, economic cycles and their impact on capital markets and liquidity, the continued demand for drilling services or production services in the geographic areas where we operate, the highly competitive nature of our business, our future financial performance, including availability, terms and deployment of capital, future compliance with covenants under our senior secured revolving credit facility and our senior notes, the supply of marketable drilling rigs, well servicing rigs, coiled tubing and wireline units within the industry, changes in technology and improvements in our competitors' equipment, 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, 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, in our Annual Report on Form 10-K for the year ended December 31, 2013 and in our Quarterly Report on Form 10-Q for the quarterly period ended March 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 we have not discussed in this report, in our Annual Report on Form 10-K for the year ended December 31, 2013, or in our Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2014 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, wireline services and fishing and rental services. We have continued to invest in the growth of all our service offerings through acquisitions and organic growth. On December 31, 2011, we acquired a coiled tubing services business to expand our existing production services offerings.

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 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.

Business Segments

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 6, 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 with its fleet of 62 drilling rigs which are currently assigned to the following divisions:



Drilling Division		Rig Count
South Texas		14
West Texas		20
North Dakota		9
Utah		7
Appalachia		4
Colombia		8
		62

•

Production Services Segment—Our Production Services Segment provides a range of services to exploration and production companies, including well servicing, wireline services, coiled tubing services, and fishing and rental 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 June 30, 2014, we operate one hundred two 550 horsepower rigs and ten 600 horsepower rigs through 11 locations, mostly in the Gulf Coast and ArkLaTex regions, though we also have 14 rigs in 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 June 30, 2014, we operate a fleet of 121 wireline units through 25 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 June 30, 2014, our coiled tubing business consists of ten onshore and four offshore coiled tubing units which are currently deployed through three locations in Texas and Louisiana.

•

Fishing and Rental Services. During drilling operations, oil and gas exploration and production companies frequently rent unique equipment such as power swivels, foam circulating units, blow-out preventers, air drilling equipment, pumps, tanks, pipe, tubing and fishing tools. We provide rental services out of three locations in Texas and Oklahoma. As of June 30, 2014 our fishing and rental tools have a gross book value of $17.4 million.

Pioneer Energy Services' 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.

With generally increasing oil prices in 2010 and 2011, exploration and production companies increased their exploration and production spending and industry equipment utilization and revenue rates improved, particularly in oil-producing regions and in certain shale regions. During 2012, modest increases in exploration and production spending resulted in modest increases in industry equipment utilization and revenue rates during 2012, as compared to 2011. Even though advancements in technology have improved the efficiency of drilling rigs, demand has remained steady with generally increasing oil prices during 2013 and 2014. If oil and natural gas prices decline, then industry equipment utilization and revenue rates could decrease domestically and in Colombia.

Historically, Colombian oil prices have generally trended in line with West Texas Intermediate (WTI) oil prices. However, fluctuations in oil prices have a less significant impact on demand for drilling and production services in Colombia as compared to the impact on demand in North America. Demand for drilling and production services in Colombia is largely dependent upon the national oil company's long-term exploration and production programs.

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 five years are illustrated in the graphs below.

As shown in the charts above, the recent 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.

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 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 years. As such, capital expenditure economics often require the use of commodity price forecasts which may prove inaccurate in the amount of time required to plan and execute a capital expenditure project (such as the drilling of a deep well). When commodity prices are depressed for long periods of time, capital expenditure projects are routinely deferred until prices 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 far less dependent on commodity price forecasts.

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 are relatively stable and predictable. In contrast, capital expenditures by exploration and production companies for exploration and drilling are more directly influenced by current and expected oil and natural gas prices and generally reflect the volatility of commodity prices.

Technological advancements and trends in our industry also affect the demand for certain types of equipment. During 2013 and 2014, the demand for traditional drilling rigs in vertical markets softened due to increased demand for drilling rigs that are able to drill horizontally. In addition, oil and gas exploration and production companies have increased the use of "pad drilling" in recent years whereby a series of horizontal wells are drilled in succession by a walking or skidding drilling rig at a single pad-site location. Pad drilling has improved the productivity of exploration and production activities which could reduce the demand for drilling rigs, particularly those that do not have the ability to walk or skid and to drill horizontal wells.

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, 2013.

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. We are currently operating in unconventional areas in the Bakken, Marcellus and Eagle Ford shales and Permian and Uintah Basins. All of the ten drilling rigs we recently constructed are currently operating in domestic shale and unconventional plays and our three new-build drilling rigs will be deployed to these regions as well. Additionally, in recent years, we have added significant capacity to our production services fleets, which we believe are well positioned to capitalize on increased 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. In recent years, we have intentionally increased our exposure to oil-related activities by redeploying certain of our assets into predominately oil-producing regions and we continue to actively seek contracts with oil-focused producers. As of June 30, 2014, approximately 98% of our working drilling rigs and 82% of our production services assets are operating on wells that are targeting or producing oil or liquids rich natural gas.

•

International Presence. In 2007, we began operating in Colombia after a comprehensive review of international opportunities wherein we determined that Colombia offered an attractive mix of favorable business conditions, political stability, and a long-term commitment to expanding national oil and gas production. All eight of our drilling rigs in Colombia are currently under term contracts that extend through the end of 2014, seven of which are currently earning revenues with the remaining rig waiting on the well site location to be prepared by our client.

•

Growth Through Select Capital Deployment. We have historically invested in the growth of our business by strategically upgrading our existing assets, selectively engaging in new-build opportunities, and through selective acquisitions. We have continued to make significant investments in the growth of our business over the past several years. For example, on December 31, 2011, we acquired a coiled tubing services business to expand our existing production services offerings. We have also added significant capacity to our other production services fleets through the addition of 58 wireline units and 38 well servicing rigs since the beginning of 2010 with more unit additions planned for the remainder of 2014 and 2015. From 2011 to early 2013, we constructed ten new-build AC drilling rigs, all of which are currently operating in domestic shale or unconventional plays, and we are currently building three more rigs which we expect to deliver and begin operating under long-term drilling contracts in the second and third quarters of 2015.

We are currently planning for and executing organic growth through select fleet additions, but this growth will be balanced with our plans for modest debt reduction. We believe this near-term strategy will position us to take advantage of future business opportunities and continue our long-term growth strategy. Management efforts are also focused on stringent cost control measures, the evaluation of nonstrategic or under-performing assets for potential liquidation and continued emphasis on the execution and performance of our core businesses.

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 $23.7 million as of June 30, 2014), cash generated from operations and the unused portion of our senior secured revolving credit facility (the “Revolving Credit Facility”).

In May 2012, we filed a registration statement that permits us to sell equity or debt in one or more offerings up to a total dollar amount of $300 million. As of June 30, 2014, 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.

In March 2010, we issued $250 million of senior notes with a coupon interest rate of 9.875% that are due in 2018 (the "2010 Senior Notes"), the net proceeds from which were used to repay a portion of the borrowings outstanding under our Revolving Credit Facility. In November 2011, we issued an additional $175 million of senior notes (the "2011 Senior Notes") with the same terms and conditions as the 2010 Senior Notes. We received $172.7 million of net proceeds from the issuance of the 2011 Senior Notes, a portion of which were used to fund the acquisition of our coiled tubing business in December 2011. 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.

Our Revolving Credit Facility 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 $250 million, all of which matures on June 30, 2016. As of June 30, 2014, we had $70.0 million outstanding under our Revolving Credit Facility and $14.0 million in committed letters of credit, which resulted in borrowing availability of $166.0 million under our Revolving Credit Facility. There are no limitations on our ability to access the full borrowing availability under the Revolving Credit Facility other than maintaining compliance with the covenants in the Revolving Credit Facility. 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 and available borrowings under our Revolving Credit Facility are adequate to cover our liquidity requirements for at least the next 12 months.

Uses of Capital Resources

During the six months ended June 30, 2014, we spent $74.6 million on purchases of property and equipment. Currently, we expect to spend approximately $185 million to $200 million on capital expenditures during 2014. We expect the total capital expenditures for 2014 will be allocated approximately 60% for our Drilling Services Segment and approximately 40% for our Production Services Segment. Our planned capital expenditures for the year ending December 31, 2014 include partial payments for three new-build drilling rigs, nine well servicing rigs, four coiled tubing units, six wireline units, upgrades to certain drilling rigs and routine capital expenditures. In addition, the capital expenditure budget for 2014 includes down payments for certain equipment that will be delivered in 2015, but requires long lead-time orders. 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 the remaining capital expenditures in 2014 from operating cash flow in excess of our working capital requirements and from borrowings under our Revolving Credit Facility if necessary.

Working Capital

Our working capital was $149.2 million at June 30, 2014, compared to $118.5 million at December 31, 2013. Our current ratio, which we calculate by dividing current assets by current liabilities, was 2.1 at June 30, 2014 compared to 2.0 at December 31, 2013.

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 higher percentages of our drilling contracts are turnkey and footage contracts and when new-build rig construction projects are in progress.

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



	June 30, 2014		December 31, 2013		Change
Cash and cash equivalents	$	23,711	$	27,385	$	(3,674	)
Receivables:
Trade, net of allowance for doubtful accounts	132,215		115,908		16,307
Unbilled receivables	52,156		49,535		2,621
Insurance recoveries	9,717		8,607		1,110
Income taxes and other	6,449		2,310		4,139
Deferred income taxes	32,365		13,092		19,273
Inventory	13,466		13,232		234
Prepaid expenses and other current assets	9,390		9,311		79
Current assets	279,469		239,380		40,089
Accounts payable	54,735		43,718		11,017
Current portion of long-term debt	429		2,847		(2,418		)
Deferred revenues	3,306		699		2,607
Accrued expenses:
Payroll and related employee costs	29,644		30,020		(376		)
Insurance premiums and deductibles	11,575		10,940		635
Insurance claims and settlements	9,716		8,607		1,109
Interest	8,744		12,275		(3,531		)
Other	12,104		11,727		377
Current liabilities	130,253		120,833		9,420
Working capital	$	149,216	$	118,547	$	30,669

The decrease in cash and cash equivalents during the six months ended June 30, 2014 is primarily due to $74.6 million used for purchases of property and equipment and $31.1 million of cash used in our financing activities, which were mostly offset by $95.5 million of cash provided by operating activities and $6.5 million of proceeds from the sale of assets.

The net increase in our total trade and unbilled receivables as of June 30, 2014 as compared to December 31, 2013 is the result of a 18% increase in our Production Services Segment revenues for the quarter ended June 30, 2014 as compared to the quarter ended December 31, 2013 and due to timing of billing and collection cycles in Colombia.

The increase in both our insurance recoveries receivables and our insurance claims and settlements accrued expenses as of June 30, 2014 as compared to December 31, 2013 is primarily due to an increase in our insurance company's reserve for workers' compensation claims in excess of our deductibles.

The increase in income taxes and other receivables as of June 30, 2014 as compared to December 31, 2013 is primarily due to the movement of prepaid taxes associated with our Colombian operations from noncurrent to current receivables, as we expect to utilize them in the near term.

The increase in current deferred income taxes as of June 30, 2014 as compared to December 31, 2013 is primarily due to the movement of domestic net operating losses from noncurrent to current deferred tax assets, as we expect to realize them in the near term. The overall increase is partially offset by the movement of net operating losses for our Colombian operations to noncurrent deferred tax assets, as we currently expect to utilize prepaid taxes rather than net operating losses to offset income taxes payable within the next year, as well as a decrease in current deferred income tax assets for 2013 annual bonus accruals which were paid in the first quarter of 2014.

Prepaid expenses and other current assets are primarily related to prepaid insurance and deferred mobilization costs that are amortized over the term of a drilling contract.

The increase in accounts payable as of June 30, 2014 as compared to December 31, 2013 is due to an increase in our accruals for capital expenditures as of June 30, 2014 as compared to December 31, 2013, and due to the 5% increase in our operating costs for the quarter ended June 30, 2014 as compared to the quarter ended December 31, 2013.

The current portion of our long-term debt is primarily related to a short-term financing for insurance premiums with monthly payments due through August 2014.

The increase in deferred revenues as of June 30, 2014 as compared to December 31, 2013 is related to deferred mobilization revenues and revenues collected but not yet earned for two turnkey jobs which were in progress at June 30, 2014.

The decrease in accrued payroll and employee related costs as of June 30, 2014 as compared to December 31, 2013 is primarily due to the payment of our 2013 annual bonuses in February 2014, which were fully accrued for as of December 31, 2013.

The decrease in accrued interest expense as of June 30, 2014 as compared to December 31, 2013 is primarily due to the repayment of $300 million of our 2010 and 2011 Senior Notes in March and May 2014, which had a higher interest rate than our 2014 Senior Notes which were issued in March 2014.

The increase in other accrued expenses as of June 30, 2014 as compared to December 31, 2013 is primarily due to an increase in our sales tax accrual, partially offset by a decrease in property taxes due to the timing of payments and a decrease in the Colombian equity tax obligation.

Long-term Debt and Other Contractual Obligations

The following table includes information about the amount and timing of our contractual obligations at June 30, 2014 (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	$	495,496	$	429	$	70,067	$	125,000	$	300,000
Interest on debt	198,906		31,215		63,472		49,094		55,125
Purchase commitments	54,777		54,777		—		—		—
Operating leases	16,927		4,738		5,850		3,264		3,075
Other long-term liabilities	13,001		6,519		6,482		—		—
Total	$	779,107	$	97,678	$	145,871	$	177,358	$	358,200

At June 30, 2014, debt obligations consist of $425.0 million of principal amount outstanding under our Senior Notes, $70.0 million outstanding under our Revolving Credit Facility and $0.5 million of other debt outstanding. The $70.0 million outstanding under our Revolving Credit Facility is due at maturity on June 30, 2016. However, we may make principal payments to reduce the outstanding balance prior to maturity when cash and working capital is sufficient. The remaining $125.0 million principal amount outstanding under our 2010 and 2011 Senior Notes will mature on March 15, 2018 and the $300.0 million principal amount outstanding under our 2014 Senior Notes will mature on March 15, 2022. Our Senior Notes have a total carrying value of $423.6 million as of June 30, 2014, which represents the $425.0 million face value net of the $1.7 million of original issue discount and $0.3 million of original issue premium, net of amortization, based on the effective interest method.

Interest payment obligations on our Revolving Credit Facility are estimated based on (1) the 3.2% interest rate that was in effect at June 30, 2014, and (2) the outstanding balance of $70.0 million at June 30, 2014 to be paid at maturity on June 30, 2016. Interest payment obligations on our Senior Notes are calculated based on the coupon interest rate of 9.875% for the 2010 and 2011 Senior Notes and 6.125% for the 2014 Senior Notes, both 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, equipment upgrades and purchases of other new equipment. The total estimated cost for the three new-build drilling rigs is approximately $75 million, of which $3.7 million has already been incurred and capitalized and an additional $24.2 million has been committed for purchase and is reflected in the table above.

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

Other long-term liabilities include the net equity tax payable to the Colombian tax authority and long-term incentive compensation which 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 $250 million borrowing capacity other than maintaining compliance with the covenants under the Revolving Credit Facility. At June 30, 2014, we were in compliance in all material respects with our financial covenants under the Revolving Credit Facility. Our total consolidated leverage ratio was 2.0 to 1.0, our senior consolidated leverage ratio was 0.3 to 1.0, and our interest coverage ratio was 5.4 to 1.0. The financial covenants contained in our Revolving Credit Facility include the following:


•	A maximum total consolidated leverage ratio that cannot exceed 4.00 to 1.00;


•	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 June 30, 2014, 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.

guarantor under the Revolving Credit Facility. Borrowings under the Revolving Credit Facility are available for acquisitions, working capital and other general corporate purposes.

In addition to the financial covenants under our Revolving Credit Facility, the Indentures governing our Senior Notes both contain certain restrictions generally on 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.

Upon the occurrence of a change of control, holders of the Senior Notes will have the right to require us to purchase all or a portion of the Senior Notes at a price equal to 101% of the principal amount of each Senior Note, together with any accrued and unpaid interest to the date of purchase. Under certain circumstances in connection with asset dispositions, we will be required to use the excess proceeds of asset dispositions to make an offer to purchase the Senior Notes at a price equal to 100% of the principal amount of each Senior Note, together with any accrued and unpaid interest to the date of purchase.

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, and by certain of our future domestic subsidiaries. The subsidiaries that generally operate our non-U.S. business concentrated in Colombia do not guarantee our Senior Notes. The non-guarantor subsidiaries do not have any payment obligations under the Senior Notes, the guarantees or the Indenture. In the event of a bankruptcy, liquidation or reorganization of any non-guarantor subsidiary, such non-guarantor subsidiary will pay the holders of its debt and other liabilities, including its trade creditors, before it will be able to distribute any of its assets to us. In the future, any non-U.S. subsidiaries, immaterial subsidiaries and subsidiaries that we designate as unrestricted subsidiaries under the Indenture will not guarantee the Senior Notes.

Our Senior Notes are not subject to any sinking fund requirements. As of June 30, 2014, there were no restrictions on the ability of subsidiary guarantors to transfer funds to the parent company, and we were in compliance in all material respects with all covenants pertaining to our Senior Notes.

Results of Operations

Statements of Operations Analysis

The following table provides information about our operations for the three and six months ended June 30, 2014 and 2013 (amounts in thousands, except average number of drilling rigs, utilization rate and revenue day information).



	Three months ended June 30,						Six months ended June 30,
	2014			2013			2014			2013
Drilling Services Segment:
Revenues	$	127,553		$	138,250		$	245,510		$	271,324
Operating costs	83,762			89,294			160,100			178,280
Drilling Services Segment margin	$	43,791		$	48,956		$	85,410		$	93,044

Average number of drilling rigs	62.0			70.3			62.0			70.4
Utilization rate	87		%	87		%	85		%	85		%
Revenue days	4,895			5,537			9,526			10,876

Average revenues per day	$	26,058		$	24,968		$	25,773		$	24,947
Average operating costs per day	17,112			16,127			16,807			16,392
Drilling Services Segment margin per day	$	8,946		$	8,841		$	8,966		$	8,555

Production Services Segment:
Revenues	$	132,259		$	110,104		$	253,336		$	206,700
Operating costs	82,505			70,450			160,257			131,069
Production Services Segment margin	$	49,754		$	39,654		$	93,079		$	75,631

Combined:
Revenues	$	259,812		$	248,354		$	498,846		$	478,024
Operating costs	166,267			159,744			320,357			309,349
Combined margin	$	93,545		$	88,610		$	178,489		$	168,675
Adjusted EBITDA	$	69,725		$	63,619		$	132,984		$	119,528

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 U.S. Generally Accepted Accounting Principles (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’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 is a financial measure that is not in accordance with GAAP and 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. We define Adjusted EBITDA as income (loss) before interest income (expense), taxes, depreciation, amortization, loss on extinguishment of debt and any impairments. We use this 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 non-GAAP financial 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, as we calculate it, may not be comparable to Adjusted EBITDA measures reported by other companies.

A reconciliation of combined Drilling Services Segment margin and Production Services Segment margin to net income (loss), as reported, and a reconciliation of Adjusted EBITDA to net income (loss), as reported, are set forth in the following table.



	Three months ended June 30,						Six months ended June 30,
	2014			2013			2014			2013
	(amounts in thousands)
Reconciliation of combined margin and Adjusted EBITDA to net loss:
Combined margin	$	93,545		$	88,610		$	178,489		$	168,675
General and administrative	(25,276		)	(23,605		)	(49,759		)	(46,659		)
Bad debt expense	(561		)	(137		)	(437		)	(418		)
Other (expense) income	2,017			(1,249		)	4,691			(2,070		)
Adjusted EBITDA	69,725			63,619			132,984			119,528
Depreciation and amortization	(45,791		)	(47,348		)	(91,317		)	(93,633		)
Impairment charges	—			(44,788		)	—			(44,788		)
Interest expense	(10,728		)	(12,331		)	(23,116		)	(23,793		)
Loss on extinguishment of debt	(14,595		)	—			(22,482		)	—
Income tax benefit	1,070			14,953			1,033			15,499
Net loss	$	(319	)	$	(25,895	)	$	(2,898	)	$	(27,187	)

Our Drilling Services Segment’s revenues decreased by $10.7 million, or 8%, and $25.8 million, or 10%, during the three and six months ended June 30, 2014, respectively, as compared to the corresponding periods in 2013. The decrease in Drilling Services Segment revenues was primarily due to a 12% decrease in revenue days during both the three and six months ended June 30, 2014, as compared to the corresponding periods in 2013. Revenue days decreased due to the sale of eight drilling rigs in October 2013, some of which had been earning a standby dayrate. In addition, the decrease in revenue days is due to lower utilization in Colombia where two rigs were idle because of customer delays in preparing well sites. The decreases in the Drilling Services Segment revenues were partly offset by increases in average revenues per day of 4% or $1,090 per day, and 3% or $826 per day, during the three and six months ended June 30, 2014, respectively. The increases in average revenues per day were primarily due to the full impact of our new-build drilling rigs working in 2014 and certain rigs that were earning a lower standby dayrate during 2013. Average revenues per day also increased due to a scope-of-work agreement that was finalized with our client in Colombia during the second quarter of 2014 that resulted in additional billings of approximately $2.4 million for work that was performed in prior quarters.

Our Drilling Services Segment’s operating costs decreased by $5.5 million, or 6%, and $18.2 million, or 10%, during the three and six months ended June 30, 2014, respectively, as compared to the corresponding periods in 2013, primarily due to a decrease in revenue days as noted in the paragraph above. The decreases in the Drilling Services Segment operating costs were partially offset by increases in average operating costs per day of 6% or $985 per day, and 3% or $415 per day, during the three and six months ended June 30, 2014, respectively, as compared to the corresponding periods in 2013. The increases in average operating costs per day were primarily due to higher labor costs, which are reimbursed by the client, and due to certain rigs earning a lower standby dayrate and incurring less operating costs during part of 2013.

Demand for drilling rigs influences the types of drilling contracts we are able to obtain. As demand for drilling rigs decreases, daywork rates move down and we may switch to performing more turnkey drilling contracts to maintain higher utilization rates and to improve our Drilling Services Segment’s margins. 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 25 and 36 turnkey contracts during the three and six months ended June 30, 2014, respectively, as compared to three and six turnkey drilling contracts completed during the corresponding periods in 2013, respectively. The increase in turnkey drilling contracts during 2014 relates to lower horsepower rigs that are drilling a series of surface holes on pad sites which is a new industry trend.

The following table provides the percentages of our drilling revenues by drilling contract type for the three and six months ended June 30, 2014 and 2013:



	Three months ended June 30,				Six months ended June 30,
	2014		2013		2014		2013
Daywork contracts	94	%	97	%	96	%	97	%
Turnkey contracts	6	%	3	%	4	%	3	%

Our Production Services Segment's revenues increased by $22.2 million, or 20%, and $46.6 million, or 23%, during the three and six months ended June 30, 2014 as compared to the corresponding periods in 2013, while operating costs increased by 17% and 22%, respectively. The increases in our Production Services Segment's revenues and operating costs are primarily a result of the increased demand for our services. The number of wireline jobs we completed increased by 6% during both the three and six months ended June 30, 2014 as compared to the corresponding periods in 2013. The total rig hours for our well servicing fleet increased by 11%, during both the three and six months ended June 30, 2014. Our coiled tubing utilization increased to 53% during the three months ended June 30, 2014 from 46% during the corresponding period in 2013. Increased pricing for these services also contributed to the increase in revenues, which was primarily due to a greater mix of higher priced jobs performed in our wireline and coiled tubing businesses. The greater mix of higher cost wireline and coiled tubing jobs performed also resulted in the increase in operating costs during the three and six months ended June 30, 2014 as compared to the corresponding periods in 2013.

Our general and administrative expense increased by approximately $1.7 million, or 7%, and $3.1 million, or 7%, during the three and six months ended June 30, 2014, respectively, as compared to the corresponding periods in 2013, primarily due to an increase in payroll and compensation related expenses.

Our other income of $2.0 million and $4.7 million for the three and six months ended June 30, 2014, respectively, is primarily related to a settlement of litigation and a net foreign currency gain recognized for our Colombian operations.

Our depreciation and amortization expenses decreased by $1.6 million and $2.3 million during the three and six months ended June 30, 2014, respectively, as compared to the corresponding periods in 2013, primarily as a result of the sales of equipment during 2013 and 2014, as well as the impairment charge to write down coiled tubing intangible assets to fair value as of June 30, 2013.

During the six months ended June 30, 2013, we recorded impairment charges of $44.8 million of impairment charges to reduce the goodwill and intangible asset carrying values of our coiled tubing reporting unit, which were originally recorded in connection with the acquisition of Go-Coil, L.L.C. on December 31, 2011. On June 30, 2013, we performed an impairment analysis that led us to conclude that there would be no remaining implied value attributable to our goodwill and accordingly, we recorded a non-cash charge of $41.7 million for the full impairment of our goodwill. In addition, we performed an intangible asset impairment analysis on June 30, 2013, which resulted in a non-cash impairment charge of $3.1 million to reduce our intangible asset carrying value of client relationships. These impairment charges did not have an impact on our liquidity or debt covenants; however, it was a reflection of the increased competition in certain coiled tubing markets where we operate and a decline in our projected cash flows for the coiled tubing reporting unit.

Our interest expense decreased by $1.6 million and $0.7 million for the three and six months ended June 30, 2014, as compared to the corresponding periods in 2013, primarily due to the partial repayment of 2010 and 2011 Senior Notes which incurred interest at a higher rate than the 2014 Senior Notes which were issued in March 2014, partially offset by less capitalized interest associated with the capital expenditures.

Our loss on debt extinguishment during the three and six months ended June 30, 2014 represents the tender and redemption premium, net unamortized debt discount and debt issuance costs that were associated with the 2010 and 2011 Senior Notes that were repaid $99.5 million in March 2014 and $200.5 million in May 2014.

Our effective income tax rate for the six months ended June 30, 2014 differs from the federal statutory rate in the United States primarily due to the impact of state income taxes, and partially offset by the effect of foreign translation, the impact of lower effective tax rates in foreign jurisdictions and other permanent differences.

Inflation

Wage rates for our operations personnel are impacted by inflationary pressures when the demand for drilling and production services increases and the availability of personnel is scarce. During 2013, we experienced modest wage rate increases in our Production Services Segment and we expect similar pressure in 2014.

Costs for rig repairs and maintenance, rig upgrades and new rig construction are also impacted by inflationary pressures when the demand for drilling services increases. We estimate that we experienced an increase in these costs of approximately 5% to 10% during 2013, and we estimate that we will experience a more moderate increase in 2014.

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, turnkey or footage 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 and footage 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 and footage contracts. Although our turnkey and footage 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 or footage contract, we would need to rely on applicable law to enforce our lien rights, because our turnkey and footage 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 or footage contract.

The risks to us under a turnkey contract and, to a lesser extent, under footage contracts, 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 and footage 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 and footage 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.

The assets “prepaid expenses and other current assets” and “other long-term assets” include the current and long-term portions of deferred mobilization costs for certain drilling contracts. The liabilities “deferred revenues” and “other long-term liabilities” include the current and long-term portions of deferred mobilization revenues for certain drilling contracts and amounts collected on contracts in excess of revenues recognized. As of June 30, 2014 we had $3.3 million and $3.4 million of current deferred revenues and costs, respectively, and $0.2 million and $0.3 million of long-term deferred mobilization revenues and costs, respectively. Our deferred mobilization costs and revenues primarily relate to long-term contracts for our new-build drilling rigs. Amortization of deferred mobilization revenues was $0.4 million and $4.3 million for the six months ended June 30, 2014 and 2013, respectively.

Our Production Services Segment earns revenues for well servicing, wireline services, coiled tubing services and fishing and rental 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.

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. Our unbilled receivables totaled $52.2 million at June 30, 2014, of which $0.4 million related to turnkey drilling contract revenues, $47.1 million represented revenue recognized but not yet billed on daywork drilling contracts in progress at June 30, 2014 and $4.7 million related to unbilled receivables for our Production Services Segment.

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, coiled tubing and fishing and rental services). For our Drilling Services Segment, we perform an impairment evaluation and estimate future undiscounted cash flows for individual drilling rig assets. 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.

In September 2013, we evaluated the drilling rigs in our fleet and decided to place eight of our mechanical drilling rigs as held for sale and recognized an impairment charge to reduce the carrying value of these assets to their estimated fair value, which was based on their sales price. The decision to sell these drilling rigs was primarily due to a decrease in demand for non-top drive mechanical rigs that drill vertical oil and gas wells. Our remaining drilling rig fleet includes mechanical rigs that are currently working, but which may have reduced utilization if demand for vertical drilling continues to soften. We performed an impairment evaluation on the remaining drilling rigs in our fleet which are similar to those that we decided to sell. In order to estimate our future undiscounted cash flows from the use and eventual disposition of these assets, we incorporated probabilities of selling these rigs in the near term, versus working them through the end of their remaining useful lives. Our analysis led us to conclude that no impairment presently exists for the remaining similar drilling rigs. If the demand for vertical drilling continues to soften and these remaining mechanical rigs become idle for an extended amount of time, then the probability of a near term sale may increase, which would likely result in an impairment charge, based on the current market value of these drilling rigs. 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.

Goodwill—Goodwill results from business acquisitions and represents the excess of acquisition costs over the fair value of the net assets acquired. In connection with the acquisition of the production services business from Go-Coil, we recorded $41.7 million of goodwill at December 31, 2011, all of which was allocated to the coiled tubing services reporting unit within our Production Services Segment.

Due to several significant adverse factors affecting our coiled tubing services reporting unit, including increased competition in certain coiled tubing markets, turnover of key personnel and lower than anticipated utilization, all of which contributed to a decline in our projected cash flows for the coiled tubing reporting unit, we performed an impairment analysis of our goodwill as of June 30, 2013. We determined that the fair value of our coiled tubing services reporting unit was less than its carrying value, including goodwill, and therefore, we performed the second step of the goodwill impairment test which led us to conclude that there would be no remaining implied fair value attributable to goodwill. Accordingly, we recorded a non-cash impairment charge of $41.7 million to reduce the carrying value of our goodwill to zero. This impairment charge did not have an impact on our liquidity or debt covenants; however, it was a reflection of the increased competition in certain coiled tubing markets where we operate and a decline in our projected cash flows for the coiled tubing reporting unit.

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 2 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 fair value 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 and footage 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 and footage 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 and footage contracts takes such risks into consideration. We are more likely to encounter losses on turnkey and footage 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 and footage contracts has historically exceeded our profitability on daywork contracts.

We incurred a total loss of $0.8 million on five of the 36 turnkey contracts which were initiated and completed during the six months ended June 30, 2014. As of June 30, 2014, we had $0.4 million of unbilled receivables related to two turnkey contracts that were in progress at June 30, 2014, which were completed prior to the issuance of these financial statements.

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 $1.7 million at June 30, 2014.

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 2 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 40 years of experience in the oilfield services industry with similar equipment.

As of June 30, 2014, we had $95.9 million of deferred tax assets related to foreign and domestic net operating loss and AMT credit carryforwards 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 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.

Our accrued insurance premiums and deductibles as of June 30, 2014 include accruals for costs incurred under the self-insurance portion of our health insurance of approximately $3.3 million and our workers’ compensation, general liability and auto liability insurance of approximately $7.7 million. We have stop-loss coverage of $200,000 per covered individual per year under our health insurance and a deductible of $500,000 per occurrence under our workers’ compensation insurance. We have a deductible of $250,000 per occurrence under both our general liability insurance and auto liability insurance. We accrue for these costs as claims are incurred using an actuarial calculation that is based on industry and our company's historical claim development data, and we accrue the costs of administrative services associated with claims processing.

Our 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 June 30, 2014, we had $70.0 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 $0.4 million, and a corresponding increase or decrease, respectively, in net income of approximately $0.2 million during the six months ended June 30, 2014. 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, 2014.

Foreign Currency Risk

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

The impact of currency rate changes on our Colombian Peso denominated transactions and balances resulted in foreign currency gains of $0.7 million for the six months ended June 30, 2014.


Item 4.	Controls and Procedures

In accordance with Exchange Act Rules 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of June 30, 2014, 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 June 30, 2014 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

Except for the risk factor described in our Form 10-Q for the quarter ended March 31, 2014, there have been no material changes in our risk factors as previously disclosed in Item 1A – "Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2013 (the “2013 Form 10-K”). In addition to the other information set forth in this Form 10-Q, you should carefully consider the factors discussed in Item 1A – "Risk Factors” in our 2013 Form 10-K and Form 10-Q for the quarter ended March 31, 2014, which could materially affect our business, financial condition or future results.


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

We did not make any unregistered sales of equity securities during the quarter ended June 30, 2014. The following table provides information relating to our repurchase of common shares during the quarter ended June 30, 2014:



Period	Total Number of Shares Purchased (1)	Average Price Paid per Share (2)		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs
April 1—April 30	31,310	$	14.92	—	—
May 1—May 31	264	$	15.11	—	—
June 1—June 30	14,331	$	15.92	—	—
Total	45,905	$	15.23	—	—


(1)	The shares indicated consist of shares of our common stock tendered by employees to the Company during the three months ended June 30, 2014, 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 9, 2014 (File No. 1-8182)).

10.2+**	-	Pioneer Energy Services Corp. 2007 Incentive Plan Form of Stock Option Agreement

10.3+**	-	Pioneer Energy Services Corp. 2007 Incentive Plan Form of Stock Option Agreement

10.4+**	-	Pioneer Energy Services Corp. 2007 Incentive Plan Form of Restricted Stock Unit Award Agreement

10.5+**	-	Pioneer Energy Services Corp. 2007 Incentive Plan Form of Long-Term Incentive Restricted Stock Unit Award Agreement

10.6+**	-	Pioneer Energy Services Corp. 2007 Incentive Plan Form of Non-Employee Director Restricted Stock Award Agreement

10.7+**	-	Pioneer Energy Services Corp. 2007 Incentive Plan Form of Long-Term Incentive Cash Award Agreement

10.8+**	-	Pioneer Energy Services Corp. 2007 Incentive Plan Form of Long-Term Incentive Cash Award Agreement

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

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

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

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

101**	-	The following financial statements from Pioneer Energy Services Corp.’s Form 10-Q for the quarter ended June 30, 2014, formatted in XBRL (eXtensible Business Reporting Language): (i) Condensed Consolidated Balance Sheets, (ii) Condensed Consolidated Statements of Operations, (iii) Condensed Consolidated Statements of Cash Flows, and (iv) Notes to Condensed Consolidated Financial Statements.

* Incorporated by reference to the filing indicated.

** Filed herewith.

# Furnished herewith.

+ Management contract or compensatory plan or arrangement.

SIGNATURES

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

PIONEER ENERGY SERVICES CORP.

/s/ Lorne E. Phillips

Lorne E. Phillips

Executive Vice President and Chief Financial Officer

(Principal Financial Officer and Duly Authorized Officer)

Dated: July 31, 2014

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 9, 2014 (File No. 1-8182)).

10.2+**	-	Pioneer Energy Services Corp. 2007 Incentive Plan Form of Stock Option Agreement

10.3+**	-	Pioneer Energy Services Corp. 2007 Incentive Plan Form of Stock Option Agreement

10.4+**	-	Pioneer Energy Services Corp. 2007 Incentive Plan Form of Restricted Stock Unit Award Agreement

10.5+**	-	Pioneer Energy Services Corp. 2007 Incentive Plan Form of Long-Term Incentive Restricted Stock Unit Award Agreement

10.6+**	-	Pioneer Energy Services Corp. 2007 Incentive Plan Form of Non-Employee Director Restricted Stock Award Agreement

10.7+**	-	Pioneer Energy Services Corp. 2007 Incentive Plan Form of Long-Term Incentive Cash Award Agreement

10.8+**	-	Pioneer Energy Services Corp. 2007 Incentive Plan Form of Long-Term Incentive Cash Award Agreement

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

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

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



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

101**	-	The following financial statements from Pioneer Energy Services Corp.’s Form 10-Q for the quarter ended June 30, 2014, 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.