PIONEER ENERGY SERVICES CORP - FORM 10-Q

Attached files

file	filename
EX-32.2 - EXHIBIT 32.2 - PIONEER ENERGY SERVICES CORP	a2014q310qexhibit322.htm
EX-31.2 - EXHIBIT 31.2 - PIONEER ENERGY SERVICES CORP	a2014q310qexhibit312.htm
EX-32.1 - EXHIBIT 32.1 - PIONEER ENERGY SERVICES CORP	a2014q310qexhibit321.htm
EX-31.1 - EXHIBIT 31.1 - PIONEER ENERGY SERVICES CORP	a2014q310qexhibit311.htm
EXCEL - IDEA: XBRL DOCUMENT - PIONEER ENERGY SERVICES CORP	Financial_Report.xls

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

______________________________________________

FORM 10-Q

______________________________________________

(Mark one)



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

For the quarterly period ended September 30, 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 October 15, 2014, there were 63,804,243 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



	September 30, 2014			December 31, 2013
	(unaudited)			(audited)
	(in thousands, except share data)
ASSETS
Current assets:
Cash and cash equivalents	$	26,439		$	27,385
Receivables:
Trade, net of allowance for doubtful accounts	142,096			115,908
Unbilled receivables	44,830			49,535
Insurance recoveries	10,539			8,607
Income taxes and other	10,847			2,310
Deferred income taxes	38,472			13,092
Inventory	14,327			13,232
Prepaid expenses and other current assets	6,283			9,311
Total current assets	293,833			239,380
Property and equipment, at cost	1,807,981			1,724,124
Less accumulated depreciation	881,590			786,467
Net property and equipment	926,391			937,657
Intangible assets, net of accumulated amortization of $38.3 million and $32.8 million at September 30, 2014 and December 31, 2013, respectively	26,291			32,269
Noncurrent deferred income taxes	3,450			1,156
Other long-term assets	14,792			19,161
Total assets	$	1,264,757		$	1,229,623

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	66,168		$	43,718
Current portion of long-term debt	3,672			2,847
Deferred revenues	3,244			699
Accrued expenses:
Payroll and related employee costs	33,519			30,020
Insurance premiums and deductibles	12,029			10,940
Insurance claims and settlements	10,539			8,607
Interest	1,293			12,275
Other	11,015			11,727
Total current liabilities	141,479			120,833
Long-term debt, less current portion	460,060			499,666
Noncurrent deferred income taxes	117,674			84,636
Other long-term liabilities	4,669			6,055
Total liabilities	723,882			711,190
Commitments and contingencies (Note 8)
Shareholders’ equity:
Preferred stock, 10,000,000 shares authorized; none issued and outstanding	—			—
Common stock $.10 par value; 100,000,000 shares authorized; 63,796,447 and 62,534,636 shares outstanding at September 30, 2014 and December 31, 2013, respectively	6,411			6,275
Additional paid-in capital	470,695			456,812
Treasury stock, at cost; 316,682 and 219,304 shares at September 30, 2014 and December 31, 2013, respectively	(3,027		)	(1,895		)
Accumulated earnings	66,796			57,241
Total shareholders’ equity	540,875			518,433
Total liabilities and shareholders’ equity	$	1,264,757		$	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 September 30,						Nine months ended September 30,
	2014			2013			2014			2013
	(in thousands, except per share data)
Revenues:
Drilling services	$	128,117		$	131,033		$	373,627		$	402,357
Production services	145,150			112,946			398,486			319,646
Total revenues	273,267			243,979			772,113			722,003
Costs and expenses:
Drilling services	88,848			89,350			248,948			267,630
Production services	90,250			72,115			250,507			203,184
Depreciation and amortization	46,081			47,414			137,398			141,047
General and administrative	26,613			23,691			76,372			70,350
Gain on sale of fishing and rental services operations	(10,702		)	—			(10,702		)	—
Bad debt expense	19			35			456			453
Impairment charges	678			9,504			678			54,292
Total costs and expenses	241,787			242,109			703,657			736,956
Income (loss) from operations	31,480			1,870			68,456			(14,953		)
Other (expense) income:
Interest expense	(8,969		)	(12,324		)	(32,085		)	(36,117		)
Loss on extinguishment of debt	—			—			(22,482		)	—
Other	(131		)	610			4,560			(1,460		)
Total other expense	(9,100		)	(11,714		)	(50,007		)	(37,577		)
Income (loss) before income taxes	22,380			(9,844		)	18,449			(52,530		)
Income tax (expense) benefit	(9,927		)	3,614			(8,894		)	19,113
Net income (loss)	$	12,453		$	(6,230	)	$	9,555		$	(33,417	)

Income (loss) per common share—Basic	$	0.20		$	(0.10	)	$	0.15		$	(0.54	)

Income (loss) per common share—Diluted	$	0.19		$	(0.10	)	$	0.15		$	(0.54	)

Weighted average number of shares outstanding—Basic	63,451			62,325			62,960			62,158

Weighted average number of shares outstanding—Diluted	65,876			62,325			65,167			62,158

See accompanying notes to condensed consolidated financial statements.

PIONEER ENERGY SERVICES CORP. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited)



	Nine months ended September 30,
	2014			2013
	(in thousands)
Cash flows from operating activities:
Net income (loss)	$	9,555		$	(33,417	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization	137,398			141,047
Allowance for doubtful accounts	408			534
Gain on dispositions of property and equipment	(1,589		)	(865		)
Stock-based compensation expense	5,761			4,692
Amortization of debt issuance costs, discount and premium	2,193			2,309
Gain on sale of fishing and rental services operations	(10,702		)	—
Loss on extinguishment of debt	22,482			—
Impairment charges	678			54,292
Deferred income taxes	5,395			(21,153		)
Change in other long-term assets	8,247			(5,554		)
Change in other long-term liabilities	(1,385		)	(1,306		)
Changes in current assets and liabilities:
Receivables	(29,428		)	(21,353		)
Inventory	(1,094		)	(620		)
Prepaid expenses and other current assets	3,030			7,330
Accounts payable	11,802			(379		)
Deferred revenues	2,545			(2,973		)
Accrued expenses	(10,366		)	(12,509		)
Net cash provided by operating activities	154,930			110,075

Cash flows from investing activities:
Purchases of property and equipment	(120,738		)	(137,945		)
Proceeds from sale of fishing and rental services operations	15,090			—
Proceeds from sale of property and equipment	7,197			6,898
Net cash used in investing activities	(98,451		)	(131,047		)

Cash flows from financing activities:
Debt repayments	(360,019		)	(25,868		)
Proceeds from issuance of debt	320,000			40,000
Debt issuance costs	(9,173		)	(13		)
Tender premium costs	(15,381		)	—
Proceeds from exercise of options	8,280			833
Purchase of treasury stock	(1,132		)	(628		)
Net cash provided by (used in) financing activities	(57,425		)	14,324

Net decrease in cash and cash equivalents	(946		)	(6,648		)
Beginning cash and cash equivalents	27,385			23,733
Ending cash and cash equivalents	$	26,439		$	17,085

Supplementary disclosure:
Interest paid	$	41,188		$	45,273
Income tax paid	$	3,475		$	2,508

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 September 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 working under term contracts that extend through the end of 2014, but we are in discussions with Ecopetrol to extend our term contracts in Colombia. We are currently constructing five new-build 1,500 horsepower AC drilling rigs which we expect to deliver and begin operating under long-term drilling contracts in 2015, with the first two rigs to be deployed during the second quarter, two rigs in the third quarter, and the final rig by the end of the year.

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 and coiled tubing services. Our production services operations are concentrated in the major United States onshore oil and gas producing regions in the Mid-Continent and Rocky Mountain states and in the Gulf Coast, both onshore and offshore. As of September 30, 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 123 wireline units and 16 coiled tubing units. On September 17, 2014, we completed the disposition of our fishing and rental services operations.

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 September 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 September 30, 2014, we have 43 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
United States	35	23	4	4	4
Colombia	8	8	—	—	—
	43	31	4	4	4

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 $44.8 million at September 30, 2014, of which $0.2 million related to turnkey drilling contract revenues, $38.6 million represented revenue recognized but not yet billed on daywork drilling contracts in progress at September 30, 2014 and $6.0 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 prepaid taxes in Colombia which are creditable against future income taxes and 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 nine months ended September 30, 2014, we had capital expenditures of $130.6 million. As of September 30, 2014 and December 31, 2013, capital expenditures incurred for property and equipment not yet placed in service was $67.5 million and $19.4 million, respectively. Capital expenditures during 2014 primarily relate to our five new-build drilling rigs which began construction during 2014, as well as unit additions to our production services fleets. During the nine months ended September 30, 2014 and 2013, we capitalized $0.3 million and $0.9 million, respectively, of interest costs incurred during the construction periods of new-build drilling rigs and other equipment.

We recorded gains on disposition of our property and equipment of $1.6 million and gains of $0.9 million for the nine months ended September 30, 2014 and 2013, respectively, 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. 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 September 30, 2014, we have identified certain drilling equipment and real estate property which is currently held for sale. During the nine months ended September 30, 2014, we recorded impairment charges of $0.7 million to reduce the carrying value of these assets to their estimated fair value less costs to sell. The total value of this property, which is included in property and equipment in our condensed consolidated balance sheet, is approximately $0.5 million.

We recorded impairment charges on our property and equipment of $9.5 million for the nine months ended September 30, 2013. During the third quarter of 2013, we decided to place eight of our mechanical drilling rigs as held for sale, and we recognized an impairment loss of $9.2 million in order to reduce the carrying value of these assets to their estimated fair value, based on their sales price. The sales of all eight drilling rigs were completed in late October 2013 and we did not incur any additional gain or loss upon the sale of these rigs. We also recorded an impairment of $0.3 million during the third quarter of 2013 in association with our decision to sell certain production services equipment.

We evaluate for potential impairment of long-lived tangible and intangible assets subject to amortization when indicators of impairment are present. Circumstances that could indicate a potential impairment include significant adverse changes in industry trends, economic climate, legal factors, and an adverse action or assessment by a regulator. More specifically, significant adverse changes in industry trends include significant declines in revenue rates, utilization rates, oil and natural gas market prices and industry rig counts. In performing an impairment evaluation, we estimate the future undiscounted net cash flows from the use and eventual disposition of long-lived tangible and intangible assets grouped at the lowest level that cash flows can be identified. For our Production Services Segment, we perform an impairment evaluation and estimate future undiscounted cash flows for the individual reporting units (well servicing, wireline and coiled tubing). For our Drilling Services Segment, we perform an impairment evaluation and estimate future undiscounted cash flows for individual 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.

and lower horsepower 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 mechanical and lower horsepower drilling rigs in our fleet that are currently idle. 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 these drilling rigs. If the demand for vertical drilling continues to soften and these remaining mechanical and lower horsepower 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.

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 and coiled tubing). If the sum of the estimated future undiscounted net cash flows is less than the carrying amount of the asset group, then we would determine the fair value of the asset group. The amount of an impairment charge would be measured as the difference between the carrying amount and the fair value of these assets. The assumptions used in the impairment evaluation for long-lived assets are inherently uncertain and require management judgment.

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 nine months ended September 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 chose early adoption of this guidance beginning July 1, 2014.

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. Sale of Fishing and Rental Services Operations

On September 17, 2014, we entered into an asset sales agreement with Basic Energy Services L.P. ("Basic") for the sale of our fishing and rental services (“F&R”) operations for total consideration of $16.1 million, subject to certain adjustments. The sales price consisted of $15.1 million of cash received at closing and $1.0 million to be held in escrow for a period of 180 days for potential claims due to Basic. Under the terms of the sales agreement, Basic purchased two real estate locations and all F&R tools and equipment for which we had a total net book value of $4.3 million at the date of sale. Basic also purchased certain other assets and assumed certain liabilities related to our F&R operations. In addition, Basic offered employment to the F&R employees and we agreed to provide transition services to Basic after the close of the transaction. We recognized a $10.7 million gain on the sale of our F&R operations, net of costs directly attributable to the sale. Net of income taxes, the gain was $6.6 million. Cash proceeds from the sale were used to repay long-term debt obligations.

For the nine months ended September 30, 2014, F&R operations represented approximately 1% of our consolidated revenues and approximately 1% of our consolidated pretax income. Total assets for F&R at the date of sale represented less than 1% of our total assets as of September 30, 2014. The sale of the F&R operations does not represent a strategic shift for our company and will not have a significant effect on our operating results. Therefore, the F&R operations does not represent discontinued operations based on the criteria of ASU No. 2014-08, "Discontinued Operations."

Balance sheet information for the F&R operations is as follows (amounts in thousands):



	December 31, 2013
Current assets	$	1,877
Property and equipment, less accumulated depreciation	6,132
Total assets	$	8,009

Current liabilities	$	919
Long term liabilities	1,452
Total liabilities	$	2,371

Statement of operations information for the F&R operations is as follows (amounts in thousands):



	Three months ended September 30,					Nine months ended September 30,
	2014		2013			2014			2013
Revenues	$	2,603	$	3,072		$	7,828		$	9,627
Operating costs	1,686		2,082			5,097			6,217
F&R margin	$	917	$	990		$	2,731		$	3,410

Income (loss) before income taxes	$	52	$	(51	)	$	(162	)	$	238

3. Debt

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



	September 30, 2014			December 31, 2013
Senior secured revolving credit facility	$	40,000		$	80,000
Senior notes	423,645			419,586
Other	87			2,927
	463,732			502,513
Less current portion	(3,672		)	(2,847		)
	$	460,060		$	499,666

Senior Secured Revolving Credit Facility

We have a credit agreement, as amended on September 22, 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 $350 million, all of which matures on September 22, 2019 (the “Revolving Credit Facility”). In addition, at our request, and with the lenders' consent, the aggregate commitments of the lenders under the Revolving Credit Facility may be increased up to an additional $100 million provided that no default exists, all representations and warranties are true and correct, and compliance with financial covenants as set forth in the Revolving Credit Facility is met immediately prior to and after giving effect thereto. 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 $350 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 2.0% to 3.0% and 1.0% to 2.0%, respectively. The LIBOR margin and bank prime rate margin currently in effect are 2.25% and 1.25%, respectively. The Revolving Credit Facility requires a commitment fee due quarterly based on the average daily unused amount of the commitments of the lenders, a fronting fee due for each letter of credit issued, and a quarterly letter of credit fee due based on the average undrawn amount of letters of credit outstanding during such period.

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

As of September 30, 2014, we had $40.0 million outstanding under our Revolving Credit Facility and $14.0 million in committed letters of credit, which resulted in borrowing availability of $296.0 million under our Revolving Credit Facility. There are no limitations on our ability to access this borrowing capacity provided there is no default, all representations and warranties are true and correct, and compliance with financial covenants under the Revolving Credit Facility is maintained. At September 30, 2014, we were in compliance with our financial covenants under the Revolving Credit Facility. Our total consolidated leverage ratio was 1.9 to 1.0, our senior consolidated leverage ratio was 0.2 to 1.0, and our interest coverage ratio was 5.8 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 or repurchases of capital stock as long as (a) no event of default exists under the Revolving Credit Facility or would result from such capital expenditures or repurchases of capital stock, (b) after giving effect to such capital expenditures or repurchases of capital stock 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. In addition, the repurchase of capital stock requires, on a pro-forma basis, compliance with the maximum total leverage ratio and minimum interest coverage ratio as set forth in the Revolving Credit Facility, both before and after giving effect to such repurchase. 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 September 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, 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 September 22, 2014, the Revolving Credit Facility was amended to increase the amount of unsecured debt that we could incur, allowing us to use additional borrowings under the Revolving Credit Facility for the redemption of the remaining $125.0 million aggregate principal amount 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 in December 2011.

The 2010 and 2011 Senior Notes 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 2010 and 2011 Senior Notes. 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.

On September 23, 2014, we announced the redemption of the remaining $125.0 million in aggregate principal amount of the 2010 and 2011 Senior Notes (the "Final Redemption") which will occur on October 23, 2014 (the "Final Redemption Date") at a redemption price equal to 104.938% of the principal amount thereof, plus accrued and unpaid interest on the notes redeemed through, but not including, the Final Redemption Date. The redemption of these 2010 and 2011 Senior Notes will be primarily funded by proceeds from our Revolving Credit Facility and through cash on hand. We will recognize a loss on debt extinguishment of approximately $8.8 million during the three months ending December 31, 2014, which includes the redemption premium of $6.2 million, $1.3 million of net unamortized discount and $1.3 million of unamortized debt issuance costs associated with the Final Redemption.

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.

In accordance with a registration rights agreement with the holders of our 2010 Senior Notes, 2011 Senior Notes and 2014 Senior Notes (collectively, the "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, June 8, 2012 and October 2, 2014, respectively. These exchange offer registration statements enabled the holders of our Senior Notes to exchange their senior notes for publicly registered notes with substantially identical terms. References to the “Senior Notes” herein include the senior notes issued in the exchange offers.

The Senior Notes have a total carrying value of $423.6 million, which represents the $425.0 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.

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 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 September 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 9, Guarantor/Non-Guarantor Condensed Consolidated Financial Statements.)

Other Debt

Our other debt consists of 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 September 2019. Costs incurred in connection with the issuance of our Senior Notes were capitalized and are being amortized using the straight-line method (which approximates 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 $8.9 million and $7.5 million as of September 30, 2014 and December 31, 2013, respectively. We recognized $1.5 million and $1.6 million of associated amortization during the nine months ended September 30, 2014 and 2013, respectively, which excludes the $3.5 million of debt costs recognized as loss on extinguishment of debt. In September 2014, we recognized additional amortization expense related to the write-off of $0.1 million of debt issuance costs representing the portion of unamortized debt issuance costs associated with one syndicate lender that is no longer participating in the Revolving Credit Facility as amended on September 22, 2014.


4.	Fair Value of Financial Instruments

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

At September 30, 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 September 30, 2014 and December 31, 2013 (amounts in thousands):



	September 30, 2014				December 31, 2013
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Total debt	$	463,732	$	468,656	$	502,513	$	538,074


5.	Earnings Per Common Share

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



	Three months ended September 30,					Nine months ended September 30,
	2014		2013			2014		2013
Basic
Net income (loss)	$	12,453	$	(6,230	)	$	9,555	$	(33,417	)

Weighted-average shares	63,451		62,325			62,960		62,158

Income (loss) per common share—Basic	$	0.20	$	(0.10	)	$	0.15	$	(0.54	)

Diluted
Net income (loss)	$	12,453	$	(6,230	)	$	9,555	$	(33,417	)

Weighted-average shares
Outstanding	63,451		62,325			62,960		62,158
Diluted effect of outstanding stock options, restricted stock and restricted stock unit awards	2,425		—			2,207		—
	65,876		62,325			65,167		62,158

Income (loss) per common share—Diluted	$	0.19	$	(0.10	)	$	0.15	$	(0.54	)

Potentially dilutive stock options, restricted stock and restricted stock unit awards representing a total of 735,624 and 1,692,549 shares of common stock for the three and nine months ended September 30, 2014, respectively, and 5,510,520 and 5,467,291 for the three and nine months ended September 30, 2013, respectively, were excluded from the computation of diluted weighted average shares outstanding due to their antidilutive effect.


6.	Stock-Based Compensation Plans

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

The following table summarizes the compensation expense recognized for stock option, restricted stock and restricted stock unit awards during the three and nine months ended September 30, 2014 and 2013 (amounts in thousands):



	Three months ended September 30,				Nine months ended September 30,
	2014		2013		2014		2013
Stock option awards	$	311	$	412	$	964	$	1,359
Restricted stock awards	127		157		421		420
Restricted stock unit awards	1,496		1,059		4,376		2,913
	$	1,934	$	1,628	$	5,761	$	4,692

Stock Options

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

We estimate the fair value of each option grant on the date of grant using a Black-Scholes option pricing model. There were no stock options granted during the three months ended September 30, 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 nine months ended September 30, 2014 and 2013:



	Nine months ended September 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 nine months ended September 30, 2014, 690,877 and 906,277 stock options were exercised at a weighted-average exercise price of $9.70 and $9.14, respectively. During the three and nine months ended September 30, 2013, 11,600 and 174,467 stock options were exercised at a weighted-average exercise price of $3.84 and $4.77, 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. We did not grant any restricted stock awards during the three months ended September 30, 2014 or 2013. During the nine months ended September 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.

The following table summarizes the number and weighted-average grant-date fair value of the restricted stock unit awards granted during the three and nine months ended September 30, 2014 and 2013:



	Three months ended September 30,				Nine months ended September 30,
	2014		2013		2014		2013
Time-based RSUs:
Time-based RSUs granted	13,330		—		360,665		406,027
Weighted-average grant-date fair value	$	13.73	$	—	$	8.64	$	7.59

Performance-based RSUs:
Performance-based RSUs granted	—		—		321,606		346,731
Weighted-average grant-date fair value	$	—	$	—	$	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. 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 vested and were converted to common stock at the end of April 2014.

As of September 30, 2014, we estimated that our actual achievement level for the performance-based RSUs granted during 2012, 2013 and 2014 will be approximately 140%, 100% and 110% of the predetermined performance conditions, respectively.


7.	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 and coiled tubing services. Our production services operations are concentrated in the major United States onshore oil and gas producing regions in the Mid-Continent and Rocky Mountain states and in the Gulf Coast, both onshore and offshore. As of September 30, 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 123 wireline units and 16 coiled tubing units. On September 17, 2014, we completed the disposition of our fishing and rental services operations.

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



	As of and for the three months ended September 30, 2014
	Drilling Services Segment		Production Services Segment		Corporate		Total
Identifiable assets	$	789,103	$	411,777	$	63,877	$	1,264,757
Revenues	$	128,117	$	145,150	$	—	$	273,267
Operating costs	88,848		90,250		—		179,098
Segment margin	$	39,269	$	54,900	$	—	$	94,169
Depreciation and amortization	$	28,728	$	16,993	$	360	$	46,081
Capital expenditures	$	36,249	$	16,265	$	151	$	52,665



	As of and for the three months ended September 30, 2013
	Drilling Services Segment		Production Services Segment		Corporate		Total
Identifiable assets	$	818,161	$	401,609	$	31,831	$	1,251,601
Revenues	$	131,033	$	112,946	$	—	$	243,979
Operating costs	89,350		72,115		—		161,465
Segment margin	$	41,683	$	40,831	$	—	$	82,514
Depreciation and amortization	$	30,993	$	16,127	$	294	$	47,414
Capital expenditures	$	17,417	$	9,661	$	357	$	27,435



	As of and for the nine months ended September 30, 2014
	Drilling Services Segment		Production Services Segment		Corporate		Total
Identifiable assets	$	789,103	$	411,777	$	63,877	$	1,264,757
Revenues	$	373,627	$	398,486	$	—	$	772,113
Operating costs	248,948		250,507		—		499,455
Segment margin	$	124,679	$	147,979	$	—	$	272,658
Depreciation and amortization	$	86,936	$	49,478	$	984	$	137,398
Capital expenditures	$	76,888	$	53,094	$	596	$	130,578



	As of and for the nine months ended September 30, 2013
	Drilling Services Segment		Production Services Segment		Corporate		Total
Identifiable assets	$	818,161	$	401,609	$	31,831	$	1,251,601
Revenues	$	402,357	$	319,646	$	—	$	722,003
Operating costs	267,630		203,184		—		470,814
Segment margin	$	134,727	$	116,462	$	—	$	251,189
Depreciation and amortization	$	92,080	$	48,139	$	828	$	141,047
Capital expenditures	$	64,761	$	35,895	$	1,489	$	102,145

The following table reconciles the segment profits reported above to income (loss) from operations as reported on the consolidated statements of operations for the three and nine months ended September 30, 2014 and 2013 (amounts in thousands):



	Three months ended September 30,						Nine months ended September 30,
	2014			2013			2014			2013
Segment margin	$	94,169		$	82,514		$	272,658		$	251,189
Depreciation and amortization	(46,081		)	(47,414		)	(137,398		)	(141,047		)
General and administrative	(26,613		)	(23,691		)	(76,372		)	(70,350		)
Gain on sale of fishing and rental services operations	10,702			—			10,702			—
Bad debt expense	(19		)	(35		)	(456		)	(453		)
Impairment charges	(678		)	(9,504		)	(678		)	(54,292		)
Income (loss) from operations	$	31,480		$	1,870		$	68,456		$	(14,953	)

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



	As of and for the three months ended September 30,				As of and for the nine months ended September 30,
	2014		2013		2014		2013
Identifiable assets	$	150,287	$	153,287	$	150,287	$	153,287
Revenues	$	22,904	$	29,959	$	70,595	$	91,361

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.


8.	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 September 30, 2014.

The Colombian government is expected to enact a new net-worth tax for all Colombian entities by year end. The proposed tax is expected to be calculated based on an entity’s net equity as of January 1, 2015, and is expected to be assessed annually from 2015 through 2018. Based on our estimate of our Colombian operation's forecasted net equity, we believe our net-worth tax obligation will be approximately $2 million each year from 2015 through 2018. The proposed net worth tax is not expected to be deductible for income tax purposes, which is similar to the net equity tax enacted in 2011.

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.


9.	Guarantor/Non-Guarantor Condensed Consolidated Financial Statements

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

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



	September 30, 2014
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	19,127			(3,123		)	10,435			—			$	26,439
Receivables, net of allowance	482			161,329			47,443			(942		)	208,312
Intercompany receivable (payable)	(24,814		)	54,821			(30,007		)	—			—
Deferred income taxes	27,713			9,221			1,538			—			38,472
Inventory	—			7,846			6,481			—			14,327
Prepaid expenses and other current assets	1,177			2,607			2,499			—			6,283
Total current assets	23,685			232,701			38,389			(942		)	293,833
Net property and equipment	4,141			832,285			90,715			(750		)	926,391
Investment in subsidiaries	893,383			120,931			—			(1,014,314		)	—
Intangible assets, net of accumulated amortization	83			26,208			—			—			26,291
Noncurrent deferred income taxes	79,178			—			3,450			(79,178		)	3,450
Other long-term assets	11,628			1,595			1,569			—			14,792
Total assets	$	1,012,098		$	1,213,720		$	134,123		$	(1,095,184	)	$	1,264,757
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	826		$	60,489		$	4,853		—			$	66,168
Current portion of long-term debt	3,645			27			—			—			3,672
Deferred revenues	—			1,101			2,143			—			3,244
Accrued expenses	5,584			57,871			5,882			(942		)	68,395
Total current liabilities	10,055			119,488			12,878			(942		)	141,479
Long-term debt, less current portion	460,000			60			—			—			460,060
Noncurrent deferred income taxes	—			196,852			—			(79,178		)	117,674
Other long-term liabilities	418			3,937			314			—			4,669
Total liabilities	470,473			320,337			13,192			(80,120		)	723,882
Total shareholders’ equity	541,625			893,383			120,931			(1,015,064		)	540,875
Total liabilities and shareholders’ equity	$	1,012,098		$	1,213,720		$	134,123		$	(1,095,184	)	$	1,264,757

	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 September 30, 2014
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Revenues	$	—		$	250,363		$	22,904		$	—		$	273,267
Costs and expenses:
Operating costs	—			160,105			18,993			—			179,098
Depreciation and amortization	358			42,250			3,473			—			46,081
General and administrative	7,110			18,665			976			(138		)	26,613
Gain on sale of fishing and rental services operations	—			(10,702		)	—			—			(10,702		)
Intercompany leasing	—			(1,215		)	1,215			—			—
Bad debt expense	—			19			—			—			19
Impairment charges	—			678			—			—			678
Total costs and expenses	7,468			209,800			24,657			(138		)	241,787
Income (loss) from operations	(7,468		)	40,563			(1,753		)	138			31,480
Other income (expense):
Equity in earnings of subsidiaries	21,908			(3,742		)	—			(18,166		)	—
Interest expense	(8,943		)	(22		)	(4		)	—			(8,969		)
Other	1,322			707			(2,022		)	(138		)	(131		)
Total other income (expense)	14,287			(3,057		)	(2,026		)	(18,304		)	(9,100		)
Income (loss) before income taxes	6,819			37,506			(3,779		)	(18,166		)	22,380
Income tax (expense) benefit	5,634			(15,598		)	37			—			(9,927		)
Net income (loss)	$	12,453		$	21,908		$	(3,742	)	$	(18,166	)	$	12,453



	Three months ended September 30, 2013
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Revenues	$	—		$	214,020		$	29,959		$	—		$	243,979
Costs and expenses:
Operating costs	—			139,166			22,299			—			161,465
Depreciation and amortization	294			43,794			3,326			—			47,414
General and administrative	7,052			15,905			872			(138		)	23,691
Intercompany leasing	—			(1,215		)	1,215			—			—
Bad debt expense	—			35			—			—			35
Impairment charges	—			9,504			—			—			9,504
Total costs and expenses	7,346			207,189			27,712			(138		)	242,109
Income (loss) from operations	(7,346		)	6,831			2,247			138			1,870
Other income (expense):
Equity in earnings of subsidiaries	6,377			1,845			—			(8,222		)	—
Interest expense	(12,320		)	(13		)	9			—			(12,324		)
Other	3			568			177			(138		)	610
Total other income (expense)	(5,940		)	2,400			186			(8,360		)	(11,714		)
Income (loss) before income taxes	(13,286		)	9,231			2,433			(8,222		)	(9,844		)
Income tax (expense) benefit	7,056			(2,854		)	(588		)	—			3,614
Net income (loss)	$	(6,230	)	$	6,377		$	1,845		$	(8,222	)	$	(6,230	)

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited, in thousands)



	Nine months ended September 30, 2014
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Revenues	$	—		$	701,518		$	70,595		$	—		$	772,113
Costs and expenses:
Operating costs	—			448,945			50,510			—			499,455
Depreciation and amortization	983			126,093			10,322			—			137,398
General and administrative	20,645			53,301			2,840			(414		)	76,372
Gain on sale of fishing and rental services operations	—			(10,702		)	—			—			(10,702		)
Intercompany leasing	—			(3,645		)	3,645			—			—
Bad debt expense	—			456			—			—			456
Impairment charges	—			678			—			—			678
Total costs and expenses	21,628			615,126			67,317			(414		)	703,657
Income (loss) from operations	(21,628		)	86,392			3,278			414			68,456
Other (expense) income:
Equity in earnings of subsidiaries	54,500			345			—			(54,845		)	—
Interest expense	(32,049		)	(39		)	3			—			(32,085		)
Loss on extinguishment of debt	(22,482		)	—			—			—			(22,482		)
Other	4,208			1,995			(1,229		)	(414		)	4,560
Total other (expense) income	4,177			2,301			(1,226		)	(55,259		)	(50,007		)
Income (loss) before income taxes	(17,451		)	88,693			2,052			(54,845		)	18,449
Income tax (expense) benefit	27,006			(34,193		)	(1,707		)	—			(8,894		)
Net income (loss)	$	9,555		$	54,500		$	345		$	(54,845	)	$	9,555




	Nine months ended September 30, 2013
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Revenues	$	—		$	630,642		$	91,361		$	—		$	722,003
Costs and expenses:
Operating costs	—			407,328			63,486			—			470,814
Depreciation and amortization	828			130,241			9,978			—			141,047
General and administrative	18,563			49,750			2,451			(414		)	70,350
Intercompany leasing	—			(3,645		)	3,645			—			—
Bad debt expense	67			386			—			—			453
Impairment charges	—			54,292			—			—			54,292
Total costs and expenses	19,458			638,352			79,560			(414		)	736,956
Income (loss) from operations	(19,458		)	(7,710		)	11,801			414			(14,953		)
Other (expense) income:
Equity in earnings of subsidiaries	2,111			5,698			—			(7,809		)	—
Interest expense	(36,110		)	(33		)	26			—			(36,117		)
Other	5			1,425			(2,476		)	(414		)	(1,460		)
Total other (expense) income	(33,994		)	7,090			(2,450		)	(8,223		)	(37,577		)
Income (loss) before income taxes	(53,452		)	(620		)	9,351			(7,809		)	(52,530		)
Income tax (expense) benefit	20,035			2,731			(3,653		)	—			19,113
Net income (loss)	$	(33,417	)	$	2,111		$	5,698		$	(7,809	)	$	(33,417	)

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited, in thousands)



	Nine months ended September 30, 2014
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidated
Cash flows from operating activities	$	33,766		$	98,247		$	22,917		$	154,930

Cash flows from investing activities:
Purchases of property and equipment	(691		)	(106,208		)	(13,839		)	(120,738		)
Proceeds from sale of fishing and rental services operations	15,090			—			—			15,090
Proceeds from sale of property and equipment	—			6,916			281			7,197
	14,399			(99,292		)	(13,558		)	(98,451		)

Cash flows from financing activities:
Debt repayments	(360,000		)	(19		)	—			(360,019		)
Proceeds from issuance of debt	320,000			—			—			320,000
Debt issuance costs	(9,173		)	—			—			(9,173		)
Tender premium costs	(15,381		)	—			—			(15,381		)
Proceeds from exercise of options	8,280			—			—			8,280
Purchase of treasury stock	(1,132		)	—			—			(1,132		)
	(57,406		)	(19		)	—			(57,425		)
Net increase (decrease) in cash and cash equivalents	(9,241		)	(1,064		)	9,359			(946		)
Beginning cash and cash equivalents	28,368			(2,059		)	1,076			27,385
Ending cash and cash equivalents	$	19,127		$	(3,123	)	$	10,435		$	26,439



	Nine months ended September 30, 2013
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidated
Cash flows from operating activities	$	(14,040	)	$	123,670		$	445		$	110,075

Cash flows from investing activities:
Purchases of property and equipment	(2,043		)	(126,738		)	(9,164		)	(137,945		)
Proceeds from sale of property and equipment	—			6,192			706			6,898
	(2,043		)	(120,546		)	(8,458		)	(131,047		)

Cash flows from financing activities:
Debt repayments	(25,000		)	(868		)	—			(25,868		)
Proceeds from issuance of debt	40,000			—			—			40,000
Debt issuance costs	(13		)	—			—			(13		)
Proceeds from exercise of options	833			—			—			833
Purchase of treasury stock	(628		)	—			—			(628		)
	15,192			(868		)	—			14,324
Net increase (decrease) in cash and cash equivalents	(891		)	2,256			(8,013		)	(6,648		)
Beginning cash and cash equivalents	18,479			(5,401		)	10,655			23,733
Ending cash and cash equivalents	$	17,588		$	(3,145	)	$	2,642		$	17,085


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 any future acquisition, 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 Reports 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 and wireline services. Through these purchases, we also acquired fishing and rental services operations, which were subsequently sold on September 17, 2014. We also acquired a coiled tubing services business at the end of 2011, to expand our existing production services offerings. We have invested and continue to invest in the growth of all our core service offerings through acquisitions and organic growth.

Pioneer Energy Services Corp. provides drilling services and production services to a diverse group of independent and large oil and gas exploration and production companies throughout much of the onshore oil and gas producing regions of the United States and internationally in Colombia. We also provide 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 7, 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

As of September 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 working under term contracts that extend through the end of 2014. We are also currently constructing five new-build 1,500 horsepower AC drilling rigs which we expect to deliver and begin operating under long-term drilling contracts in 2015, with the first two rigs to be deployed during the second quarter, two rigs in the third quarter, and the final rig by the end of the year.

•

Production Services Segment—Our Production Services Segment provides a range of services to exploration and production companies, including well servicing, wireline services and coiled tubing services. Our production services operations are concentrated in the major United States onshore oil and gas producing regions in the Mid-Continent and Rocky Mountain states and in the Gulf Coast, both onshore and offshore. On September 17, 2014, we completed the disposition of our fishing and rental services operations. We provide our services to a diverse group of oil and gas exploration and production companies. The primary production services we offer are the following:

•

Well Servicing. A range of services are required in order to establish production in newly-drilled wells and to maintain production over the useful lives of active wells. We use our well servicing rig fleet to provide these necessary services, including the completion of newly-drilled wells, maintenance and workover of active wells, and plugging and abandonment of wells at the end of their useful lives. As of September 30, 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 September 30, 2014, we operate a fleet of 123 wireline units through 23 locations in the Gulf Coast, Mid-Continent and Rocky Mountain states.

•

Coiled Tubing Services. Coiled tubing is an important element of the well servicing industry that allows operators to continue production during service operations without shutting in the well, thereby reducing the risk of formation damage. Coiled tubing services involve the use of a continuous metal pipe spooled on a large reel for oil and natural gas well applications, such as wellbore clean-outs, nitrogen jet lifts, through-tubing fishing, formation stimulation utilizing acid, chemical treatments and fracturing. Coiled tubing is also used for a number of horizontal well applications such as milling temporary plugs between frac stages. As of September 30, 2014, our coiled tubing business consists of eleven onshore and five offshore coiled tubing units which are currently deployed through three locations in Texas and Louisiana.

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, and to a lesser extent in 2012, 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. Even though advancements in technology have improved the efficiency of drilling rigs, demand has remained steady, particularly for drilling rigs that are able to drill horizontally. During 2013 and 2014, our industry has experienced generally increasing oil prices. However, during October 2014, domestic oil prices have dipped to approximately $80 per barrel, from a high this year of $107 on June 20, 2014. If oil and natural gas prices remain at current levels for an extended period of time or continue to 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 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.

As reflected in the above graphs, technological advancements and trends in our industry also affect the demand for certain types of equipment. The demand for traditional drilling rigs in vertical markets has 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 the Bakken, Marcellus and Eagle Ford shales and Permian and Uintah Basins. All of the ten drilling rigs we constructed in 2011 to 2013 are currently operating in domestic shale and unconventional plays and our five new-build drilling rigs currently under construction will be deployed to these regions as well. Additionally, we have added significant capacity in recent years to our production services fleets, which we believe are well positioned to further 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 September 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 working under term contracts that extend through the end of 2014. We are currently having discussions with Ecopetrol to extend our term contracts in Colombia.

•

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. We acquired a coiled tubing services business to expand our existing production services offerings at the end of 2011. Since the beginning of 2010, we have added significant capacity to our other production services fleets through the addition of 60 wireline units and 38 well servicing rigs, and we plan to continue adding units during the remainder of 2014 and in 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 five more rigs which we expect to deliver and begin operating under long-term drilling contracts in 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 $26.4 million as of September 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 September 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. On October 23, 2014, we will redeem the remaining $125.0 million in aggregate principal amount of the 2010 and 2011 Senior Notes, primarily funded by proceeds from our revolving credit facility and through cash on hand.

Our Revolving Credit Facility, as amended on September 22, 2014, 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 $350 million, all of which matures in September 2019. In addition, at our request, and with the lenders' consent, the aggregate commitments of the lenders under the Revolving Credit Facility may be increased up to an additional $100 million provided that no default exists, all representations and warranties are true and correct, and compliance with financial covenants as set forth in the Revolving Credit Facility is met immediately prior to and after giving effect thereto. As of September 30, 2014, we had $40.0 million outstanding under our Revolving Credit Facility and $14.0 million in committed letters of credit, which resulted in borrowing availability of $296.0 million under our Revolving Credit Facility. Subsequent to the redemption of our 2010 and 2011 Senior Notes on October 23, 2014, our borrowing availability under our Revolving Credit Facility will be $176.0 million. There are no limitations on our ability to access this borrowing capacity provided there is no default, all representations and warranties are true and correct, and compliance with financial covenants under the Revolving Credit Facility is maintained. Additional information regarding these covenants is provided in the Debt Requirements section below. Borrowings under the Revolving Credit Facility are available for selective acquisitions, working capital and other general corporate purposes.

We currently expect that cash and cash equivalents, cash generated from operations and available borrowings under our Revolving Credit Facility are adequate to cover our liquidity requirements for at least the next 12 months.

Uses of Capital Resources

During the nine months ended September 30, 2014, we spent $120.7 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 five new-build drilling rigs, eleven 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 $152.4 million at September 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 September 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 new-build rig construction projects are in progress or when higher percentages of our drilling contracts are turnkey and footage contracts.

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



	September 30, 2014		December 31, 2013		Change
Cash and cash equivalents	$	26,439	$	27,385	$	(946	)
Receivables:
Trade, net of allowance for doubtful accounts	142,096		115,908		26,188
Unbilled receivables	44,830		49,535		(4,705		)
Insurance recoveries	10,539		8,607		1,932
Income taxes and other	10,847		2,310		8,537
Deferred income taxes	38,472		13,092		25,380
Inventory	14,327		13,232		1,095
Prepaid expenses and other current assets	6,283		9,311		(3,028		)
Current assets	293,833		239,380		54,453
Accounts payable	66,168		43,718		22,450
Current portion of long-term debt	3,672		2,847		825
Deferred revenues	3,244		699		2,545
Accrued expenses:
Payroll and related employee costs	33,519		30,020		3,499
Insurance premiums and deductibles	12,029		10,940		1,089
Insurance claims and settlements	10,539		8,607		1,932
Interest	1,293		12,275		(10,982		)
Other	11,015		11,727		(712		)
Current liabilities	141,479		120,833		20,646
Working capital	$	152,354	$	118,547	$	33,807

The decrease in cash and cash equivalents during the nine months ended September 30, 2014 is primarily due to $120.7 million used for purchases of property and equipment and $57.4 million of cash used in our financing activities, which were mostly offset by $154.9 million of cash provided by operating activities, $15.1 million of proceeds from the sale of our fishing and rental services operations and $7.2 million of proceeds from the sale of assets.

The net increase in our total trade and unbilled receivables as of September 30, 2014 as compared to December 31, 2013 is primarily the result of the increase in consolidated revenues of $35.1 million, or 15%, for the quarter ended September 30, 2014 as compared to the quarter ended December 31, 2013, and due to the timing of billing and collection cycles for turnkey projects.

The increase in both our insurance recoveries receivables and our insurance claims and settlements accrued expenses as of September 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 September 30, 2014 as compared to December 31, 2013 is primarily due to the movement of $7.3 million in 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 September 30, 2014 as compared to December 31, 2013 is primarily due to the movement of $26.5 million 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 $2.6 million 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.

The increase in inventory as of September 30, 2014 as compared to December 31, 2013 is primarily due to the expansion of our coiled tubing operation with the addition of three coiled tubing units in 2014.

The decrease in prepaid expenses and other assets as of September 30, 2014 as compared to December 31, 2013 is primarily due to a decrease in prepaid insurance costs because most of the insurance premiums are paid in late October of each year, and therefore we had amortization of eleven months of these October premiums at September 30, 2014, as compared to two months at December 31, 2013.

The increase in accounts payable as of September 30, 2014 as compared to December 31, 2013 is due to an increase in our accruals for capital expenditures as of September 30, 2014 as compared to December 31, 2013, and due to the 13% increase in our operating costs for the quarter ended September 30, 2014 as compared to the quarter ended December 31, 2013.

The increase in deferred revenues as of September 30, 2014 as compared to December 31, 2013 is primarily related to deferred mobilization revenues for two rig moves between geographic locations in Colombia during the third quarter of 2014.

The increase in accrued payroll and employee related costs as of September 30, 2014 as compared to December 31, 2013 is primarily due to higher accruals for our 2014 annual bonuses, as compared to 2013 bonuses which were earned at an amount below target, as well as an increase due to timing of pay periods.

The increase in insurance premiums and deductibles as of September 30, 2014 as compared to December 31, 2013 is primarily due to an increase in our accrual for workers compensation claims and health insurance costs resulting from an increase in our estimated liability for the deductibles under these policies.

The decrease in accrued interest expense as of September 30, 2014 as compared to December 31, 2013 is primarily due to the payment of interest on our Senior Notes which is due semi-annually on March 15 and September 15.

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

Long-term Debt and Other Contractual Obligations

The following table includes information about the amount and timing of our contractual obligations at September 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	$	463,732	$	3,672	$	60	$	160,000	$	300,000
Interest on debt	143,907		20,643		38,675		38,651		45,938
Redemption premium	6,173		6,173		—		—		—
Purchase commitments	105,382		86,882		18,500		—		—
Operating leases	15,294		4,475		5,936		3,134		1,749
Incentive compensation	12,625		6,133		6,492		—		—
Total	$	747,113	$	127,978	$	69,663	$	201,785	$	347,687

At September 30, 2014, debt obligations consisted of $425.0 million of principal amount outstanding under our Senior Notes, $40.0 million outstanding under our Revolving Credit Facility and $0.1 million of other debt outstanding. Our Senior Notes have a total carrying value of $423.6 million as of September 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.

The $300.0 million principal amount outstanding under our 2014 Senior Notes will mature on March 15, 2022. The remaining $125.0 million principal amount outstanding under our 2010 and 2011 Senior Notes will be redeemed on October 23, 2014 primarily through additional borrowings under the Revolving Credit Facility. The outstanding balance under our Revolving Credit Facility is due at maturity on September 22, 2019. However, we may make principal payments to reduce the outstanding balance prior to maturity when cash and working capital is sufficient.

Interest payment obligations on our Revolving Credit Facility are estimated based on (1) the 2.4% interest rate that was in effect at September 30, 2014, and (2) the outstanding balance of $40.0 million at September 30, 2014 to be paid at maturity on September 22, 2019. Interest payment obligations on our 2014 Senior Notes are calculated based on the coupon interest rate of 6.125% due semi-annually in arrears on March 15 and September 15 of each year. Interest payment obligations also reflect the interest associated with the $125.0 million of 2010 and 2011 Senior Notes that will be redeemed on October 23, 2014 as due within one year.

The redemption premium represents the redemption costs for the $125.0 million of 2010 and 2011 Senior Notes that will be redeemed on October 23, 2014.

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, excluding capitalized interest, for the five new-build drilling rigs is approximately $125 million, of which $21.8 million has already been incurred, and $55.8 million of which is reflected in the purchase commitments table above. In addition, $34.4 million of the purchase commitments in the table above represent obligations for well servicing rigs and other drilling equipment that will be delivered in the fourth quarter of 2014 and in 2015, but which require long lead-time orders.

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

Incentive compensation is payable to our employees, generally contingent upon their continued employment through the date of each respective award's payout.

Debt Requirements

The Revolving Credit Facility contains customary mandatory prepayments from the proceeds of certain asset dispositions or debt issuances, which are applied to reduce outstanding revolving and swing-line loans and letter of credit exposure. There are no limitations on our ability to access the $350 million borrowing capacity provided there is no default, all representations and warranties are true and correct, and compliance with financial covenants under the Revolving Credit Facility is maintained. At September 30, 2014, we were in compliance in all material respects with our financial covenants under the Revolving Credit Facility. Our total consolidated leverage ratio was 1.9 to 1.0, our senior consolidated leverage ratio was 0.2 to 1.0, and our interest coverage ratio was 5.8 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 September 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.

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.

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

Our Senior Notes are not subject to any sinking fund requirements. As of September 30, 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 nine months ended September 30, 2014 and 2013 (amounts in thousands, except average number of drilling rigs, utilization rate and revenue day information).



	Three months ended September 30,						Nine months ended September 30,
	2014			2013			2014			2013
Drilling Services Segment:
Revenues	$	128,117		$	131,033		$	373,627		$	402,357
Operating costs	88,848			89,350			248,948			267,630
Drilling Services Segment margin	$	39,269		$	41,683		$	124,679		$	134,727

Average number of drilling rigs	62.0			70.0			62.0			70.3
Utilization rate	88		%	80		%	86		%	84		%
Revenue days	5,028			5,174			14,554			16,050

Average revenues per day	$	25,481		$	25,325		$	25,672		$	25,069
Average operating costs per day	17,671			17,269			17,105			16,675
Drilling Services Segment margin per day	$	7,810		$	8,056		$	8,567		$	8,394

Production Services Segment:
Revenues	$	145,150		$	112,946		$	398,486		$	319,646
Operating costs	90,250			72,115			250,507			203,184
Production Services Segment margin	$	54,900		$	40,831		$	147,979		$	116,462

Combined:
Revenues	$	273,267		$	243,979		$	772,113		$	722,003
Operating costs	179,098			161,465			499,455			470,814
Combined margin	$	94,169		$	82,514		$	272,658		$	251,189
Adjusted EBITDA	$	78,108		$	59,398		$	211,092		$	178,926

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 September 30,						Nine months ended September 30,
	2014			2013			2014			2013
	(amounts in thousands)
Reconciliation of combined margin and Adjusted EBITDA to net loss:
Combined margin	$	94,169		$	82,514		$	272,658		$	251,189
General and administrative	(26,613		)	(23,691		)	(76,372		)	(70,350		)
Gain on sale of fishing and rental services operations	10,702			—			10,702			—
Bad debt expense	(19		)	(35		)	(456		)	(453		)
Other (expense) income	(131		)	610			4,560			(1,460		)
Adjusted EBITDA	78,108			59,398			211,092			178,926
Depreciation and amortization	(46,081		)	(47,414		)	(137,398		)	(141,047		)
Impairment charges	(678		)	(9,504		)	(678		)	(54,292		)
Interest expense	(8,969		)	(12,324		)	(32,085		)	(36,117		)
Loss on extinguishment of debt	—			—			(22,482		)	—
Income tax (expense) benefit	(9,927		)	3,614			(8,894		)	19,113
Net income (loss)	$	12,453		$	(6,230	)	$	9,555		$	(33,417	)

Our Drilling Services Segment’s revenues decreased by $2.9 million, or 2%, and $28.7 million, or 7%, while our operating costs decreased by $0.5 million, or 1%, and $18.7 million, or 7%, during the three and nine months ended September 30, 2014, respectively, as compared to the corresponding periods in 2013. The decreases in both our revenues and operating costs were primarily due to a 3% and 9% decrease in revenue days during the three and nine months ended September 30, 2014, respectively, as compared to the corresponding periods in 2013. Revenue days decreased primarily due to the sale of eight drilling rigs in October 2013, some of which had been earning a standby dayrate during 2013, and due to lower utilization in Colombia where we experienced downtime primarily due to client delays in preparing well sites until late in the third quarter of 2014. Overall decreases in revenues and operating costs were partially offset by an increase in domestic revenues and operating costs during the three months ended September 30, 2014 from increased turnkey work.

Our average revenues per day increased by 1% or $156 per day, and 2% or $603 per day, while our average operating costs per day increased by 2% or $402 per day, and 3% or $430 per day, during the three and nine months ended September 30, 2014, respectively, as compared to the corresponding periods in 2013. Our average revenues and operating costs per day increased primarily due to increased turnkey work performed during 2014 and due to certain rigs that were on standby during 2013 and thus were earning a lower standby dayrate and incurring less operating costs during part of 2013. Additionally, higher labor costs during 2014 which are reimbursed by the client contributed to our increases in average revenues and costs per day.

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 32 and 68 turnkey contracts during the three and nine months ended September 30, 2014, respectively, as compared to nine and 15 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 nine months ended September 30, 2014 and 2013:



	Three months ended September 30,				Nine months ended September 30,
	2014		2013		2014		2013
Daywork contracts	93	%	98	%	95	%	98	%
Turnkey contracts	7	%	2	%	5	%	2	%

Our Production Services Segment's revenues increased by $32.2 million, or 29%, and $78.8 million, or 25%, during the three and nine months ended September 30, 2014 as compared to the corresponding periods in 2013, while operating costs increased by 25% and 23%, 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 nine months ended September 30, 2014, as compared to the corresponding periods in 2013. The total rig hours for our well servicing fleet increased by 15% and 12%, during the three and nine months ended September 30, 2014, respectively. Our coiled tubing utilization increased to 56% during the three months ended September 30, 2014 from 53% 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 nine months ended September 30, 2014, as compared to the corresponding periods in 2013.

Our general and administrative expense increased by approximately $2.9 million, or 12%, and $6.0 million, or 9%, during the three and nine months ended September 30, 2014, respectively, as compared to the corresponding periods in 2013, primarily due to an increase in payroll and compensation related expenses as we are projecting higher incentive compensation based on our company's performance.

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

Our other income of $4.6 million for the nine months ended September 30, 2014 is primarily related to a settlement of litigation in our favor during the first quarter of 2014.

Our depreciation and amortization expenses decreased by $1.3 million and $3.6 million during the three and nine months ended September 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 nine months ended September 30, 2014, we recorded impairment charges of $0.7 million to reduce the carrying values of certain drilling equipment and real estate property which were held for sale to their estimated fair value less costs to sell. At September 30, 2014, we had approximately $0.5 million of property held for sale, which is included in property and equipment in our condensed consolidated balance sheet.

During the nine months ended September 30, 2013, we recorded impairment charges of $9.5 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 $3.4 million and $4.0 million for the three and nine months ended September 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 for ongoing construction projects during 2014.

Our loss on debt extinguishment during the nine months ended September 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 nine months ended September 30, 2014 was 48%, which is higher than the federal statutory rate in the United States, primarily due to the impact of state income taxes and the effect of foreign translation, and partially offset by 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. With the increase in demand from 2010 through 2011 and the resulting tightening of labor markets, we had a wage rate increase of approximately 10% across multiple drilling divisions in January 2012. We experienced modest wage rate increases in our Production Services Segment during 2013 and we estimate slightly higher increases for the year ending December 31, 2014.

Costs for equipment repairs and maintenance, upgrades and new equipment 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 2012 and 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 September 30, 2014 we had $3.2 million and $3.5 million of current deferred revenues and costs, respectively, and $0.1 million and $0.2 million of long-term deferred mobilization revenues and costs, respectively. Our deferred mobilization costs and revenues primarily relate to long-term drilling contracts in Colombia. Amortization of deferred mobilization revenues was $2.0 million and $5.1 million for the nine months ended September 30, 2014 and 2013, respectively.

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

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 $44.8 million at September 30, 2014, of which $0.2 million related to turnkey drilling contract revenues, $38.6 million represented revenue recognized but not yet billed on daywork drilling contracts in progress at September 30, 2014 and $6.0 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 and coiled tubing). 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.

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 nine months ended September 30, 2014 are meeting our projections.

Technological advancements and trends in our industry also affect the demand for certain types of equipment. Demand has decreased for certain mechanical and /or lower horsepower drilling rigs, particularly in vertical markets, 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 which enables a series of horizontal wells to be drilled in succession by a walking or skidding drilling rig at a single pad-site location. 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. Our drilling rig fleet includes mechanical and lower horsepower 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 mechanical and lower horsepower drilling rigs in our fleet that are currently idle. 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 these drilling rigs. If the demand for vertical drilling continues to soften and these remaining mechanical and lower horsepower 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 eight of the 68 turnkey contracts which were initiated and completed during the nine months ended September 30, 2014. As of September 30, 2014, we had $0.2 million of unbilled receivables related to two turnkey contracts that were in progress at September 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 September 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 September 30, 2014, we had $82.3 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 September 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 $8.4 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

Recently Proposed Regulation


Item 3.	Quantitative and Qualitative Disclosures About Market Risk

Interest Rate Risk

We are subject to interest rate market risk on our variable rate debt. As of September 30, 2014, we had $40.0 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 $0.3 million, and a corresponding increase or decrease, respectively, in net income of approximately $0.2 million during the nine months ended September 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 losses of $1.3 million for the nine months ended September 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 September 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 September 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 Quarterly Reports on 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 September 30, 2014. We did not repurchase any common shares during the quarter ended September 30, 2014.


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*		Second Amendment dated as of September 22, 2014, by and among Pioneer Energy Services Corp., a Texas corporation, the lenders party thereto, and Wells Fargo Bank, N.A., as administrative agent for the lenders (Form 8-K dated September 23, 2014 (File No. 1-8182, Exhibit 4.1)).

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

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

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

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

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

SIGNATURES

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

PIONEER ENERGY SERVICES CORP.

/s/ Lorne E. Phillips

Lorne E. Phillips

Executive Vice President and Chief Financial Officer

(Principal Financial Officer and Duly Authorized Officer)

Dated: October 28, 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*		Second Amendment dated as of September 22, 2014, by and among Pioneer Energy Services Corp., a Texas corporation, the lenders party thereto, and Wells Fargo Bank, N.A., as administrative agent for the lenders (Form 8-K dated September 23, 2014 (File No. 1-8182, Exhibit 4.1)).

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

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

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

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

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

PIONEER ENERGY SERVICES CORP - FORM 10-Q - October 28, 2014

Attached files

PIONEER ENERGY SERVICES CORP Reports