Form 10-K

10-K 1 d10k.htm FORM 10-K Form 10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-K

(Mark one)

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

For the fiscal year ended December 31, 2010

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

Commission File Number: 1-8182

PIONEER DRILLING COMPANY

(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 N.E. Loop 410, Suite 1000 San Antonio, Texas		78209
(Address of principal executive offices)		(Zip Code)

Registrant’s telephone number, including area code: (210) 828-7689

Securities registered pursuant to Section 12(b) of the Act:


Title of each class		Name of each exchange on which registered
Common Stock, $0.10 par value		NYSE Amex

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ¨ No þ

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No þ

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 þ No ¨

Indicate by check mark whether the Registrant has submitted electronically and posted on its corporate Website, 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 ¨ No ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨

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. (Check one):


Large accelerated filer ¨		Accelerated filer þ
Non-accelerated filer ¨	(Do not check if a smaller reporting company)	Smaller 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 þ

The aggregate market value of the registrant’s common stock held by nonaffiliates of the registrant on the last business day of the registrant’s most recently completed second fiscal quarter (based on the closing sales price on the American Stock Exchange (NYSE Amex) on June 30, 2010) was approximately $303.8 million.

As of February 4, 2011, there were 54,243,452 shares of common stock, par value $0.10 per share, of the registrant issued and outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the proxy statement related to the registrant’s 2011 Annual Meeting of Shareholders are incorporated by reference into Part III of this report.

TABLE OF CONTENTS


		Page
	PART I
	Introductory Note		1
Item 1.	Business		2
Item 1A.	Risk Factors		19
Item 1B.	Unresolved Staff Comments		30
Item 2.	Properties		30
Item 3.	Legal Proceedings		30

	PART II
Item 5.	Market for Registrant’s Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities		31
Item 6.	Selected Financial Data		33
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		34
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		59
Item 8.	Financial Statements and Supplementary Data		61
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure		100
Item 9A.	Controls and Procedures		100
Item 9B.	Other Information		100

	PART III
Item 10.	Directors, Executive Officers and Corporate Governance		101
Item 11.	Executive Compensation		101
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters		101
Item 13.	Certain Relationships and Related Transactions, and Director Independence		101
Item 14.	Principal Accountant Fees and Services		101

	PART IV
Item 15.	Exhibits and Financial Statement Schedules		102

PART I

INTRODUCTORY NOTE

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

From time to time, our management or persons acting on our behalf make forward-looking statements to inform existing and potential security holders about our company. These statements may include projections and estimates concerning the timing and success of specific projects and our future backlog, revenues, income and capital spending. Forward-looking statements are generally accompanied by words such as “estimate,” “project,” “predict,” “believe,” “expect,” “anticipate,” “plan,” “intend,” “seek,” “will,” “should,” “goal” or other words that convey the uncertainty of future events or outcomes. These forward-looking statements speak only as of the date on which they are first made, which in the case of forward-looking statements made in this report is the date of this report. Sometimes we will specifically describe a statement as being a forward-looking statement and refer to this cautionary statement.

In addition, various statements contained in this Annual Report on Form 10-K, including those that express a belief, expectation or intention, as well as those that are not statements of historical fact, are forward-looking statements. Such forward-looking statements appear in Item 1—“Business” and Item 3—“Legal Proceedings” in Part I of this report; in Item 5—“Market for Registrant’s Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities,” Item 7—“Management’s Discussion and Analysis of Financial Condition and Results of Operations,” Item 7A—“Quantitative and Qualitative Disclosures About Market Risk” and in the Notes to Consolidated Financial Statements we have included in Item 8 of Part II of this report; and elsewhere in this report. These forward-looking statements speak only as of the date of this report. We disclaim any obligation to update these statements, and we caution you not to rely on them unduly. We have based these forward-looking statements on our current expectations and assumptions about future events. While our management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties, most of which are difficult to predict and many of which are beyond our control. These risks, contingencies and uncertainties relate to, among other matters, the following:

•

general economic and business conditions and industry trends;

•

levels and volatility of oil and gas prices;

•

decisions about onshore 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;

•

the supply of marketable drilling rigs, well service rigs and wireline units within the industry;

•

the continued availability of drilling rig, well service rig and wireline unit components;

•

the continued availability of qualified personnel;

•

the success or failure of our acquisition strategy, including our ability to finance acquisitions and manage growth; and

•

changes in, or our failure or inability to comply with, governmental regulations, including those relating to the environment.

We believe the items we have outlined above are important factors that could cause our actual results to differ materially from those expressed in a forward-looking statement contained in this report or elsewhere. We

have discussed many of these factors in more detail elsewhere in this report. Unpredictable or unknown factors we have not discussed in this report could also have material adverse effects on actual results of matters that are the subject of our forward-looking statements. We do not intend to update our description of important factors each time a potential important factor arises, except as required by applicable securities laws and regulations. We advise our security holders that they should (1) be aware that unpredictable or unknown 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. Also, please read the risk factors set forth in Item 1A—“Risk Factors.”

Item 1.

Business

General

Pioneer Drilling Company provides drilling services and production services to independent and major 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. 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. Our business has grown through acquisitions and through organic growth. Since September 1999, we have significantly expanded our drilling rig fleet by adding 35 rigs through acquisitions and by adding 31 rigs through the construction of rigs from new and used components. We significantly expanded our service offerings in March 2008, when we acquired the production services businesses of WEDGE Group Incorporated (“WEDGE”) for $314.7 million and Prairie Investors d/b/a Competition Wireline (“Competition”) for $30.0 million, which provide well services, wireline services and fishing and rental services. We funded the WEDGE acquisition primarily with $311.5 million of borrowings under our senior secured revolving credit facility. 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 customers.

We currently conduct our operations through two operating segments: our Drilling Services Division and our Production Services Division. The following is a description of these two operating segments. Financial information about our operating segments is included in Note 11, Segment Information, of the Notes to Consolidated Financial Statements, included in Part II Item 8, Financial Statements and Supplementary Data, of this Annual Report on Form 10-K.

•

Drilling Services Division—Our Drilling Services Division provides contract land drilling services with its fleet of 71 drilling rigs in the following locations:


Drilling Division Locations	Rig Count
South Texas		19
East Texas		13
West Texas		3
North Dakota		9
North Texas		3
Utah		3
Oklahoma		6
Appalachia		7
Colombia		8

established our West Texas drilling division location with three drilling rigs that were previously included in our East Texas drilling division location. One of these rigs has begun drilling in the Permian Basin and we expect the remaining two rigs to begin operations in late February 2011. 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 customers. 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.

•

Production Services Division—Our Production Services Division provides a range of services to oil and gas exploration and production companies, including well services, wireline services, and fishing and rental services. Our production services operations are managed through locations concentrated in the major United States onshore oil and gas producing regions in the Gulf Coast, Mid-Continent, Rocky Mountain and Appalachian states. 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 Services. Existing and newly-drilled wells require a range of services to establish and maintain production over their useful lives. We use our premium well service rig fleet to provide these required services, including maintenance of existing wells, workover of existing wells, completion of newly-drilled wells, and plugging and abandonment of wells at the end of their useful lives. We acquired one well service rig in early 2011, resulting in a total of 75 well service rigs in nine locations as of February 4, 2011. Our well service rig fleet consists of seventy 550 horsepower rigs, four 600 horsepower rigs, and one 400 horsepower rig, with an average age of 3.4 years. All our well service rigs are currently operating or are being actively marketed, with January 2011 utilization of approximately 88%. We plan to add another five well service rigs to our fleet by mid-2011.

•

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. When a producing well is completed, they also must perforate the production casing 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. We acquired 21 wireline units during 2010 and two additional wireline units in early 2011, resulting in a total of 86 wireline units in 22 locations as of February 4, 2011. We plan to add another 12 wireline units by mid-2011.

•

Fishing and Rental Services. During drilling operations, oil and gas exploration and production companies frequently rent unique equipment such as power swivels, foam circulating units, blow-out preventers, air drilling equipment, pumps, tanks, pipe, tubing, and fishing tools. We provide rental services out of four locations in Texas and Oklahoma. As of December 31, 2010 our fishing and rental tools have a gross book value of $13.5 million.

Pioneer Drilling Company’s corporate office is located at 1250 N.E. Loop 410, Suite 1000, San Antonio, Texas 78209. Our phone number is (210) 828-7689 and our website address is www.pioneerdrlg.com. We make available free of charge though 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 (the “SEC”). Information on our website is not incorporated into this report or otherwise made part of this report.

Industry Overview

Demand for oilfield services offered by our industry is a function of our customers’ willingness to make operating expenditures and capital expenditures to explore for, develop and produce hydrocarbons, which in turn is affected by current and expected levels of oil and natural gas prices.

From 2004 through 2008, domestic exploration and production spending increased as oil and natural gas prices increased. Since late 2008, there has been substantial volatility and a decline in oil and natural gas prices due to the downturn in the global economic environment. In response, our customers curtailed their drilling programs and reduced their production activities, particularly in natural gas producing regions, which resulted in a decrease in demand and revenue rates for certain of our drilling rigs and production services equipment. Additionally, there was uncertainty in the capital markets and access to financing was limited. These conditions adversely affected our business environment. For additional information concerning the effects of the volatility in oil and gas prices and uncertainty in capital markets, see Item 1A—“Risk Factors” in Part I of this Annual Report on Form 10-K.

With increasing oil and natural gas prices through 2010, exploration and production companies modestly increased their exploration and production spending for 2010 and industry rig utilization and revenue rates improved, particularly in oil-producing regions and in certain shale regions. We expect continued modest increases in exploration and production spending for 2011, which we expect will result in modest increases in industry rig utilization and revenue rates in 2011, as compared to 2010.

On February 4, 2011, the spot price for West Texas Intermediate crude oil was $89.03, the spot price for Henry Hub natural gas was $4.47 and the Baker Hughes land rig count was 1,696, a 33% increase from 1,280 on February 5, 2010. The average weekly spot prices of West Texas Intermediate crude oil and Henry Hub natural gas, the average weekly domestic land rig count per the Baker Hughes land rig count, and the average monthly domestic well service rig count for each of the last five years were:


	Years Ended December 31,
	2010		2009		2008		2007		2006
Oil (West Texas Intermediate)	$	79.39	$	61.81	$	99.86	$	72.71	$	66.28
Natural Gas (Henry Hub)	$	4.35	$	3.85	$	8.81	$	6.90	$	6.66
U.S. Land Rig Count		1,493		1,035		1,792		1,670		1,537
U.S. Well Service Rig Count		1,854		1,735		2,514		2,388		2,364

As represented in the table above, increases in oil and natural gas prices from 2004 to late 2008 resulted in corresponding increases in the U.S. land rig counts and U.S. well service rig counts, while declines in prices from late 2008 to late 2009 led to decreases in the U.S. land rig counts and U.S. well service rig counts. Since late 2009, increases in oil and natural gas prices have caused modest increases in exploration and production spending and the corresponding increases in drilling and well services activities is reflected by increases in the U.S. land rig counts and the U.S. well service rig counts in 2010.

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. 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, but these projects are less sensitive to commodity price volatility as compared to capital expenditures for exploration. Discretionary operating expenditure work is evaluated according to a simple short-term payout criterion which 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.

Competitive Strengths

Our competitive strengths include:

•

One of the Leading Providers in the Most Attractive Basins. Our 71 drilling rigs operate in many of the most attractive producing basins in the Americas, including the Bakken, Marcellus and Eagle Ford shales, as well as Colombia. Our rigs are located in nine divisions throughout the United States and Colombia, diversifying our geographic exposure and limiting the impact of any regional slowdown. We believe the varied capabilities of our rigs make them well suited to these areas where the optimal rig configuration is dictated by local geology and market conditions. Furthermore, certain of our division locations, such as Colombia, North Dakota, West Texas and parts of our South Texas division location, are in basins with oil-focused drilling, which reduces our relative exposure to changes in natural gas drilling activity.

•

High Quality Assets. We believe our drilling rig fleet is modern and well maintained, with 31 new-build rigs purchased since 2001, and the majority of these constructed from 2004 to 2006. The majority of our rig fleet has preferred equipment such as more efficient and lower emission engines, rounded bottom mud tanks, matched horsepower mud pumps and mobile or fast-paced substructures. In addition, 69% of our rig fleet has a horsepower rating of 1000 to 2000 horsepower and 49% has top drives, which allows us to pursue opportunities in shale plays, which typically require higher specification rigs than traditional areas. Our wireline and well servicing assets are among the newest in the industry, with 54% having been built in 2007 or later, and all but one of the well service rigs having at least 550 horsepower. We expect to add a total of 13 wireline units and six well service rigs during the first half of 2011. We believe that our modern and well maintained fleet allows us to realize higher contract and utilization rates by being able to offer our customers equipment that is more reliable and requires less downtime than older equipment.

•

Provide Services Throughout the Well Life Cycle. By offering our customers drilling, production and related services, we capture revenue throughout the life cycle of a well and diversify our business. Our Drilling Services Division performs work prior to initial production, and our Production Services Division provides services such as logging, completion, perforation, workover and maintenance throughout the productive life of a well. We also provide certain end-of-well-life activities such as plugging and abandonment. Drilling and production services activity have historically exhibited different degrees of demand fluctuation, and we believe the diversity of our services reduces our exposure to decreases in demand for any single service activity. The diversity of our services also enhances customer revenues by allowing us to cross-sell services in our various business divisions.

•

Excellent Safety Record. We believe that our excellent safety record and reputation are critical to winning new business and expanding our relationships with existing customers. Our commitment to

safety also reduces our business risk by keeping our employees safe and our equipment in good condition. We have consistently exceeded the International Association of Drilling Contractors (IADC) average for recordable incidents and have achieved a 70% improvement in recordable incidents since 2005. Much of our equipment contains additional safety features such as the iron roughnecks we have installed on 63% of our drilling rigs. We received scores of 100% on several health, safety and environment audits conducted during 2009 and 2010 by Ecopetrol S.A. (NYSE: EC), one of the leading oil companies in Latin America, for whom we currently operate eight drilling rigs in Colombia. We believe our strong performance on such measures has contributed significantly to our growing business with Ecopetrol.

•

Experienced Management Team. We believe that important competitive factors in establishing and maintaining long-term customer relationships include having an experienced and skilled management team and maintaining employee continuity. Our CEO, Wm. Stacy Locke, joined Pioneer in 1995 as President and has over 25 years of industry experience. Our two division presidents, F.C. “Red” West and Joe Eustace, have over 70 years of combined oilfield services experience. Our management team has operated through numerous oilfield services cycles and provides us with valuable long-term experience and a detailed understanding of customer requirements. We also seek to maximize employee continuity and minimize employee turnover by maintaining modern equipment, a strong safety record, ongoing growth and competitive compensation. We have devoted, and will continue to devote, substantial resources to our employee safety and training programs and maintaining low employee turnover.

•

Longstanding and Diversified Customers. We maintain long-standing, high quality customer relationships with a diverse group of major independent oil and gas exploration and production companies including Anadarko Petroleum Corporation, Cabot Oil and Gas Corporation, Whiting Petroleum Corporation and Chesapeake Energy Corporation. We also maintain a high quality relationship with Ecopetrol, which accounted for approximately 17.8% of our 2010 consolidated revenues. No other single customer accounted for more than 8.9% of consolidated revenues during the same period. We believe our relationships with our customers are excellent and offer numerous opportunities for future growth.

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 that operate in active drilling markets in the United States and 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 customers, expand our customer base in the areas in which we currently operate and further enhance our geographic diversification through selective international expansion. The key elements of this long-term strategy include:

•

Further Strengthen our Competitive Position in the Most Attractive Domestic Markets. Shale plays are expected to become increasingly important to domestic hydrocarbon production in the coming years and not all drilling rigs are capable of successfully drilling in these shale play opportunities. We currently have 39 drilling rigs capable of operating in unconventional plays. Of these 39 drilling rigs, 30 are currently operating in unconventional plays, eight are currently operating in Colombia under term contracts and one is operating domestically on a conventional well. We have 21 other drilling rigs that would require additional upgrades such as top drives to be capable of operating in unconventional plays. We may consider further upgrades in the future if they will result in profitable contract terms that justify the additional investment. We also intend to continue adding capacity to our wireline and well servicing product offerings, which are well positioned to capitalize on increased shale development.

•

Increase our Exposure to Oil-Driven Drilling Activity. We have intentionally increased our exposure to oil-related activities by redeploying certain of our assets into predominately oil-producing regions and actively seeking contracts with oil-focused producers. Currently, 60% of both our working drilling rigs and our well service rigs are operating on wells that are targeting or producing oil. In addition, we currently have one rig drilling in the Permian Basin, an oil producing region, and expect to have another two drilling rigs operating in this area by the end of February 2011. We believe that by targeting a balanced mix of oil and natural gas activities, we can lessen our exposure to fluctuations in capital spending associated with changes in any single commodity price. We believe that our flexible rig fleet and production services assets allow us to target opportunities focused on both natural gas and oil.

•

Selectively Expand our International Operations. In early 2007, we announced our intention to selectively expand internationally and began a relationship with Ecopetrol S.A. 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. We now have eight drilling rigs operating under term drilling contracts in Colombia. We are continuously evaluating additional international expansion opportunities and intend to target international markets that share the favorable characteristics of our Colombian operations and which would allow us to deploy sufficient assets in order to realize economies of scale.

•

Continue Growth with Select Capital Deployment. We intend to invest in the growth of our business by continuing to strategically upgrade our existing assets, selectively engaging in new-build opportunities, and potentially making selective acquisitions. Our capital investment decisions are determined by an analysis of the projected return on capital employed, which is based on the terms of secured contracts whenever possible, and the investment must be consistent with our strategic objectives. For example, we began our operations in Colombia in 2007 to diversify our operations into the international market, and we established our Appalachia drilling division location in 2009 to supply drilling rigs to the rapidly growing demand in the Marcellus Shale. We continued investing in these opportunities during 2010, exporting an additional two rigs to Colombia and placing an additional four rigs in the Appalachia drilling division location, all of which were equipped with upgrades such as top drives and walking/skidding systems. We now have a total of 15 drilling rigs in these locations as of February 4, 2011. We also significantly increased our production services wireline fleet with the addition of 21 wireline units during 2010, and we expect to add a total of 14 wireline units and six well service rigs during the first half of 2011.

Overview of Our Segments and Services

Drilling Services Division

A land drilling rig consists of engines, a hoisting system, a rotating system, pumps and related equipment to circulate drilling fluid, blowout preventers and related equipment.

Diesel or gas engines are typically the main power sources for a drilling rig. Power requirements for drilling jobs may vary considerably, but most land drilling rigs employ two or more engines to generate between 500 and 2,000 horsepower, depending on well depth and rig design. Most drilling rigs capable of drilling in deep formations, involving depths greater than 15,000 feet, use diesel-electric power units to generate and deliver electric current through cables to electrical switch gears, then to direct-current electric motors attached to the equipment in the hoisting, rotating and circulating systems.

Drilling rigs use long strings of drill pipe and drill collars to drill wells. Drilling rigs are also used to set heavy strings of large-diameter pipe, or casing, inside the borehole. Because the total weight of the drill string and the casing can exceed 500,000 pounds, drilling rigs require significant hoisting and braking capacities.

Generally, a drilling rig’s hoisting system is made up of a mast, or derrick, a traveling block and hook assembly that attaches to the rotating system, a mechanism known as the drawworks, a drilling line and ancillary equipment. The drawworks mechanism consists of a revolving drum, around which the drilling line is wound, and a series of shafts, clutches and chain and gear drives for generating speed changes and reverse motion. The drawworks also houses the main brake, which has the capacity to stop and sustain the weights used in the drilling process. When heavy loads are being lowered, a hydraulic or electric auxiliary brake assists the main brake to absorb the great amount of energy developed by the mass of the traveling block, hook assembly, drill pipe, drill collars and drill bit or casing being lowered into the well.

The rotating equipment from top to bottom consists of a top drive or a swivel, the kelly, and kelly bushing, the rotary table, drill pipe, drill collars and the drill bit. We refer to the equipment between the top drive or swivel and the drill bit as the drill stem. In a top drive system, the top drive hangs from a hook at the bottom of the traveling block. The top drive has a passageway for drilling mud to get into the drill pipe, and it has a heavy-duty electric motor connected to a threaded drive shaft which connects to and rotates the drill pipe. In a kelly drive system, the swivel assembly sustains the weight of the drill stem, permits its rotation and affords a rotating pressure seal and passageway for circulating drilling fluid into the top of the drill string. The swivel also has a large handle that fits inside the hook assembly at the bottom of the traveling block. Drilling fluid enters the drill stem through a hose, called the rotary hose, attached to the side of the swivel. The kelly is a triangular, square or hexagonal piece of pipe, usually 40 feet long, that transmits torque from the rotary table to the drill stem and permits its vertical movement as it is lowered into the hole. The bottom end of the kelly fits inside a corresponding triangular, square or hexagonal opening in a device called the kelly bushing. The kelly bushing, in turn, fits into a part of the rotary table called the master bushing. As the master bushing rotates, the kelly bushing also rotates, turning the kelly, which rotates the drill pipe and thus the drill bit. Drilling fluid is pumped through the kelly on its way to the bottom. The rotary table, equipped with its master bushing and kelly bushing, supplies the necessary torque to turn the drill stem. The drill pipe and drill collars are both steel tubes through which drilling fluid can be pumped. Drill pipe, sometimes called drill string, comes in 30-foot sections, or joints, with threaded sections on each end. Drill collars are heavier than drill pipe and are also threaded on the ends. Collars are used on the bottom of the drill stem to apply weight to the drilling bit. At the end of the drill stem is the bit, which chews up the formation rock and dislodges it so that drilling fluid can circulate the fragmented material back up to the surface where the circulating system filters it out of the fluid.

Drilling fluid, often called mud, is a mixture of clays, chemicals and water or oil, which is carefully formulated for the particular well being drilled. Drilling mud accounts for a major portion of the cost incurred and equipment used in drilling a well. Bulk storage of drilling fluid materials, the pumps and the mud-mixing equipment are placed at the start of the circulating system. Working mud pits and reserve storage are at the other end of the system. Between these two points, the circulating system includes auxiliary equipment for drilling fluid maintenance and equipment for well pressure control. Within the system, the drilling mud is typically routed from the mud pits to the mud pump and from the mud pump through a standpipe and the rotary hose to the drill stem. The drilling mud travels down the drill stem to the bit, up the annular space between the drill stem and the borehole and through the blowout preventer stack to the return flow line. It then travels to a shale shaker for removal of rock cuttings, and then back to the mud pits, which are usually steel tanks. The reserve pits, usually one or two fairly shallow excavations, are used for waste material and excess water around the location.

In a continuing effort to improve our drilling rig fleet, we have installed top drives in 35 rigs (with four additional spare top drives available for installation), iron roughnecks in 45 rigs, walking/skidding systems in 13 rigs (with three additional walking/skidding systems available for installation) and automatic catwalks in eight rigs. These upgrades provide our customers with drilling rigs that have more varied capabilities for drilling in unconventional plays, and they improve our efficiency and safety. Top drives provide maximum torque and rotational control, improved well control and better hole conditioning. In horizontal drilling, operators can utilize top drives to reach formations that may not be accessible with conventional rotary drilling. An iron roughneck is a remotely operated pipe handling feature on the rig floor, which is used to help reduce the occurrence of repetitive motion injuries and decrease drill pipe tripping time. Walking systems increase efficiency by allowing

multiple wells to be drilled on the same pad site and permitting the drilling rig to move between wells while drill pipe remains in the derrick, thus reducing move times and costs. Our walking system enables the drilling rig to move forward, backward, and side to side which affords the operator additional flexibility. An automated catwalk is a drill pipe handling feature used to raise drill pipe, drill collars, casing, and other necessary items to the drilling rig floor. Its function drastically reduces pick up and lay down time, thereby decreasing operator costs for handling casing.

There are numerous factors that differentiate land drilling rigs, including their power generation systems and their drilling depth capabilities. The actual drilling depth capability of a rig may be less than or more than its rated depth capability due to numerous factors, including the size, weight and amount of the drill pipe on the rig. The intended well depth and the drill site conditions determine the amount of drill pipe and other equipment needed to drill a well. Generally, land rigs operate with crews of five to six persons.

The following table sets forth historical information regarding utilization for our drilling rig fleet:


	Years ended December 31,
	2010			2009			2008			2007			2006
Average number of operating rigs for the period		71.0			70.7			67.4			66.1			58.5
Average utilization rate		59	%		41	%		89	%		89	%		96	%

We believe that our drilling rigs and other related equipment are in good operating condition. Our employees perform periodic maintenance and minor repair work on our drilling rigs. We rely on various oilfield service companies for major repair work and overhaul of our drilling equipment when needed. We also engage in periodic improvement of our drilling equipment. In the event of major breakdowns or mechanical problems, our rigs could be subject to significant idle time and a resulting loss of revenue if the necessary repair services are not immediately available.

As of February 4, 2011, we own a fleet of 55 trucks and related transportation equipment that we use to transport our drilling rigs to and from drilling sites. By owning our own trucks, we reduce the overall cost of rig moves and reduce downtime between rig moves.

We obtain our contracts for drilling oil and gas wells either through competitive bidding or through direct negotiations with customers. Our drilling contracts generally provide for compensation on either a daywork, turnkey or footage basis. The contract terms we offer 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. Generally, our contracts provide for the drilling of a single well and typically permit the customer to terminate on short notice. However, we have entered into more longer-term drilling contracts during periods of high rig demand. In addition, we generally construct new drilling rigs once we have entered into longer-term drilling contracts for such rigs. Currently, we have 32 contracts with terms of six months to three years in duration. Of these 32 contracts, if not renewed at the end of their terms, 14 will expire by August 15, 2011, 11 will expire by February 15, 2012, one will expire by August 15, 2012 and six have a remaining term in excess of 18 months. We have one additional drilling rig under contract that we expect will begin operating in late February 2011 with a six month term.

As a provider of contract land drilling services, our business and the profitability of our operations depend on the level of drilling activity by oil and gas exploration and production companies operating in the geographic markets where we operate. The oil and gas exploration and production industry is a historically cyclical industry characterized by significant changes in the levels of exploration and development activities. During periods of reduced drilling activity or excess rig capacity, price competition tends to increase and the profitability of daywork contracts tends to decrease. In this competitive price environment, we may be more inclined to enter into turnkey contracts that expose us to greater risk of loss but which offer potential contract profitability.

The following table presents, by type of contract, information about the total number of wells we completed for our customers during each of the last three fiscal years.


	Years ended December 31,
Type of Contract	2010		2009		2008
Daywork		453		323		828
Turnkey		11		14		10
Footage		—		1		71

Total number of wells		464		338		909

Daywork Contracts. Under daywork drilling contracts, we provide a drilling rig and required personnel to our customer who supervises the drilling of the well. We are paid based on a negotiated fixed rate per day while the rig is used. Daywork drilling contracts specify the equipment to be used, the size of the hole and the depth of the well. Under a daywork drilling contract, the customer bears a large portion of the out-of-pocket drilling costs and we generally bear no part of the usual risks associated with drilling, such as time delays and unanticipated costs.

Turnkey Contracts. Under a turnkey contract, we agree to drill a well for our customer to a specified depth and under specified conditions for a fixed price, regardless of the time required or the problems encountered in drilling the well. We provide technical expertise and engineering services, as well as most of the equipment and drilling supplies required to drill the well. We often subcontract for related services, such as the provision of casing crews, cementing and well logging. Under typical turnkey drilling arrangements, we do not receive progress payments and are paid by our customer only after we have performed the terms of the drilling contract in full.

The risks to us under a turnkey contract are substantially greater than on a well drilled on a daywork basis. This is primarily because under a turnkey contract we assume most of the risks associated with drilling operations generally assumed by the operator in a daywork contract, including the risk of blowout, loss of hole, stuck drill pipe, machinery breakdowns, abnormal drilling conditions and risks associated with subcontractors’ services, supplies, cost escalations and personnel. We employ or contract for engineering expertise to analyze seismic, geologic and drilling data to identify and reduce some of the drilling risks we assume. We use the results of this analysis to evaluate the risks of a proposed contract and seek to account for such risks in our bid preparation. We believe that our operating experience, qualified drilling personnel, risk management program, internal engineering expertise and access to proficient third-party engineering contractors have allowed us to reduce some of the risks inherent in turnkey drilling operations. We also maintain insurance coverage against some, but not all, drilling hazards. However, the occurrence of uninsured or under-insured losses or operating cost overruns on our turnkey jobs could have a material adverse effect on our financial position and results of operations.

Footage Contracts. Under footage contracts, we are paid a fixed amount for each foot drilled, regardless of the time required or the problems encountered in drilling the well. We typically pay more of the out-of-pocket costs associated with footage contracts as compared to daywork contracts. Similar to a turnkey contract, the risks to us on a footage contract are greater because we assume most of the risks associated with drilling operations generally assumed by the operator in a daywork contract, including loss of hole, stuck drill pipe, machinery breakdowns, abnormal drilling conditions and risks associated with subcontractors’ services, supplies, cost escalation and personnel. As with turnkey contracts, we manage this additional risk through the use of engineering expertise and bid the footage contracts accordingly. We also maintain insurance coverage against some, but not all, drilling hazards. However, the occurrence of uninsured or under-insured losses or operating cost overruns on our footage jobs could have a material adverse effect on our financial position and results of operations.

Production Services Division

Well Services. We provide rig-based well services, including maintenance of existing wells, workover of existing wells, completion of newly-drilled wells, and plugging and abandonment of wells at the end of their useful lives.

Regular maintenance is generally required throughout the life of a well to sustain optimal levels of oil and gas production. We believe regular maintenance comprises the largest portion of our work in this business segment. Common maintenance services include repairing inoperable pumping equipment in an oil well and replacing defective tubing in a gas well. Our maintenance services involve relatively low-cost, short-duration jobs which are part of normal well operating costs. The need for maintenance does not directly depend on the level of drilling activity, although it is somewhat impacted by short-term fluctuations in oil and gas prices. Accordingly, maintenance services generally experience relatively stable demand; however, when oil or gas prices are too low to justify additional expenditures, operating companies may choose to temporarily shut in producing wells rather than incur additional maintenance costs.

In addition to periodic maintenance, producing oil and gas wells occasionally require major repairs or modifications called workovers, which are typically more complex and more time consuming than maintenance operations. Workover services include extensions of existing wells to drain new formations either through perforating the well casing to expose additional productive zones not previously produced, deepening well bores to new zones or the drilling of lateral well bores to improve reservoir drainage patterns. Our well service rigs are also used to convert former producing wells to injection wells through which water or carbon dioxide is then pumped into the formation for enhanced oil recovery operations. Workovers also include major subsurface repairs such as repair or replacement of well casing, recovery or replacement of tubing and removal of foreign objects from the well bore. These extensive workover operations are normally performed by a well service rig with additional specialized auxiliary equipment, which may include rotary drilling equipment, mud pumps, mud tanks and fishing tools, depending upon the particular type of workover operation. All of our well service rigs are designed to perform complex workover operations. A workover may require a few days to several weeks and generally requires additional auxiliary equipment. The demand for workover services is sensitive to oil and gas producers’ intermediate and long-term expectations for oil and gas prices.

Completion services involve the preparation of newly drilled wells for production. The completion process may involve selectively perforating the well casing in the productive zones to allow oil or gas to flow into the well bore, stimulating and testing these zones and installing the production string and other downhole equipment. We provide well service rigs to assist in this completion process. Newly drilled wells are frequently completed by well service rigs to minimize the use of higher cost drilling rigs in the completion process. The completion process typically requires a few days to several weeks, depending on the nature and type of the completion, and generally requires additional auxiliary equipment. Accordingly, completion services require less well-to-well mobilization of equipment and generally provide higher operating margins than regular maintenance work. The demand for completion services is directly related to drilling activity levels, which are sensitive to changes in oil and gas prices.

Well service rigs are also used in the process of permanently closing oil and gas wells no longer capable of producing in economic quantities. Many well operators bid this work on a “turnkey” basis, requiring the service company to perform the entire job, including the sale or disposal of equipment salvaged from the well as part of the compensation received, and complying with state regulatory requirements. Plugging and abandonment work can provide favorable operating margins and is less sensitive to oil and gas pricing than drilling and workover activity since well operators must plug a well in accordance with state regulations when it is no longer productive. We perform plugging and abandonment work throughout our core areas of operation in conjunction with equipment provided by other service companies.

When we provide well services, we typically bill customers on an hourly basis during the period that the rig providing services is actively working. As of February 4, 2010, our fleet of well service rigs totaled 75 rigs.

These rigs are located mostly in Texas, serving the Gulf Coast and ArkLaTex regions, though we also have nine rigs in Louisiana and Mississippi and nine rigs in North Dakota. Our fleet is among the newest in the industry, consisting primarily of premium, 550 horsepower rigs capable of working at depths of 20,000 feet.

Wireline Services. We provide both open and cased-hole wireline services with our fleet of 86 wireline units, as of February 4, 2011. We provide these services in Texas, Kansas, Colorado, Utah, Montana, North Dakota, Louisiana, West Virginia, Wyoming and Mississippi. Wireline services typically utilize a single truck equipped with a spool of wireline that is used to lower and raise a variety of specialized tools in and out of the wellbore. These tools can be used to measure pressures and temperatures as well as the condition of the casing and the cement that holds the casing in place. Other applications for wireline tools include placing equipment in or retrieving equipment from the wellbore, or perforating the casing and cutting off pipe that is stuck in the well so that the free section can be recovered. Electric wireline contains a conduit that allows signals to be transmitted to or from tools located in the well. Wireline trucks are often used in place of a well service rig when there is no requirement to remove tubulars from the well in order to make repairs. Wireline trucks, like well service rigs, are utilized throughout the life of a well.

Fishing and Rental Services. Our rental and fishing tool business provides a range of specialized services and equipment that are utilized on a non-routine basis for both drilling and well servicing operations. Drilling and well service rigs are equipped with a complement of tools to complete routine operations under normal conditions for most projects in the geographic area where they are employed. When downhole problems develop with drilling or servicing operations, or conditions require non-routine equipment, our customers will usually rely on a provider of rental and fishing tools to augment equipment that is provided with a typical drilling or well service rig package. The important rental tools that we offer include air drilling equipment, foam units, power swivels, and blowout preventers.

The term “fishing” applies to a wide variety of downhole operations designed to correct a problem that has developed when drilling or servicing a well. Often, the problem involves equipment that has become lodged in the well and cannot be removed without special equipment. Our customers employ our technicians and our tools that are specifically suited to retrieve the trapped equipment, or “fish,” in order for operations to resume.

Our Production Services operations are impacted by seasonal factors. Our business can be negatively impacted during the winter months due to inclement weather, fewer daylight hours, and holidays. Because our well service rigs and wireline units are mobile, during periods of heavy snow, ice or rain, we may not be able to move our equipment between locations.

Customers

We provide drilling services and production services to numerous major and independent oil and gas exploration and production companies that are active in the geographic areas in which we operate. The following table shows our three largest customers as a percentage of our total revenue for each of our last three fiscal years.


Customer	Total Revenue Percentage
Fiscal Year Ended December 31, 2010:
Ecopetrol		17.7	%
Whiting Petroleum Corporation		8.9	%
Chesapeake Operating, Inc.		3.7	%

Fiscal Year Ended December 31, 2009:
Ecopetrol		16.2	%
Anadarko Petroleum Corporation		5.9	%
Cabot Oil and Gas Corporation		5.6	%

Fiscal Year Ended December 31, 2008:
EOG Resources, Inc.		10.0	%
Ecopetrol		7.4	%
Anadarko Petroleum Corporation		6.4	%

Competition

Drilling Services Division

We encounter substantial competition from other drilling contractors. Our primary market areas are highly fragmented and competitive. The fact that drilling rigs are mobile and can be moved from one market to another in response to market conditions heightens the competition in the industry.

The drilling contracts we compete for are usually awarded on the basis of competitive bids. Our principal competitors are Helmerich & Payne, Inc., Precision Drilling Trust, Patterson-UTI Energy, Inc. and Nabors Industries, Ltd. In addition to pricing and rig availability, we believe the following factors are also important to our customers in determining which drilling contractors to select:

•

the type and condition of each of the competing drilling rigs;

•

the mobility and efficiency of the rigs;

•

the quality of service and experience of the rig crews;

•

the safety records of the rigs;

•

the offering of ancillary services; and

•

the ability to provide drilling equipment adaptable to, and personnel familiar with, new technologies and drilling techniques.

While we must be competitive in our pricing, our competitive strategy generally emphasizes the quality of our equipment, the safety record of our rigs and the experience of our rig crews to differentiate us from our competitors.

Contract drilling companies compete primarily on a regional basis, and the intensity of competition may vary significantly from region to region at any particular time. If demand for drilling services improves in a region where we operate, our competitors might respond by moving in suitable rigs from other regions. An influx of rigs from other regions could rapidly intensify competition and make any improvement in demand for drilling rigs in a particular region short-lived.

Some of our competitors have greater financial, technical and other resources than we do. Their greater capabilities in these areas may enable them to:

•

better withstand industry downturns;

•

compete more effectively on the basis of price and technology;

•

better retain skilled rig personnel; and

•

build new rigs or acquire and refurbish existing rigs so as to be able to place rigs into service more quickly than us in periods of high drilling demand.

Production Services Division

The market for production services is highly competitive. Competition is influenced by such factors as price, capacity, availability of work crews, type and condition of equipment and reputation and experience of the service provider. We believe that an important competitive factor in establishing and maintaining long-term customer relationships is having an experienced, skilled and well-trained work force. In recent years, many of our larger customers have placed increased emphasis on the safety performance and quality of the crews, equipment and services provided by their contractors. We have devoted, and will continue to devote, substantial resources toward employee safety and training programs. Although we believe customers consider all of these factors, price is generally the primary factor in determining which service provider is awarded the work. However, we believe that most customers are willing to pay a slight premium for the quality and efficient service we provide.

The largest well service providers that we compete with are Key Energy Services, Basic Energy Services, Nabors Industries, Complete Production Services and CC Forbes. In addition, there are numerous smaller companies that compete in our well service markets.

The wireline market is dominated by Schlumberger Ltd. and Halliburton Company. These companies have a substantially larger asset base than we do and operate in all major U.S. oil and natural gas producing basins. Other competitors include Weatherford International, Baker Atlas, Superior Energy Services, Basic Energy Services, and Key Energy Services. The market for wireline services is very competitive, but historically we have competed effectively with our competitors based on performance and strong customer service.

The fishing and rental tools market is fragmented compared to our other product lines. Companies which provide fishing services generally compete based on the reputation of their fishing tool operators and their relationships with customers. Competition for rental tools is sometimes based on price; however, in most cases, when a customer chooses a specific fishing tool operator for a particular job, then the necessary rental equipment will be part of that job as well. Our primary competitors include: Baker Oil Tools, Weatherford International, Basic Energy Services, Key Energy Services, Quail Tools (owned by Parker Drilling) and Knight Oil Tools.

The need for well servicing, wireline, and fishing and rental services fluctuates, primarily, in relation to the price (or anticipated price) of oil and natural gas, which, in turn, is driven by the supply of and demand for oil and natural gas. Generally, as supply of those commodities decreases and demand increases, service and maintenance requirements increase as oil and natural gas producers attempt to maximize the productivity of their wells in a higher priced environment.

The level of our revenues, earnings and cash flows are substantially dependent upon, and affected by, the level of domestic and international oil and gas exploration and development activity, as well as the equipment capacity in any particular region. For a more detailed discussion, see Item 7—“Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Raw Materials

The materials and supplies we use in our drilling and production services operations include fuels to operate our drilling and well service equipment, drilling mud, drill pipe, drill collars, drill bits and cement. We do not rely on a single source of supply for any of these items. While we are not currently experiencing any shortages, from time to time there have been shortages of drilling equipment and supplies during periods of high demand. Shortages could result in increased prices for drilling equipment or supplies that we may be unable to pass on to customers. In addition, during periods of shortages, the delivery times for equipment and supplies can be substantially longer. Any significant delays in our obtaining drilling equipment or supplies could limit drilling operations and jeopardize our relations with customers. In addition, shortages of drilling equipment or supplies could delay and adversely affect our ability to obtain new contracts for our rigs, which could have a material adverse effect on our financial condition and results of operations.

Operating Risks and Insurance

Our operations are subject to the many hazards inherent in the contract land drilling business, including the risks of:

•

blowouts;

•

fires and explosions;

•

loss of well control;

•

collapse of the borehole;

•

lost or stuck drill strings; and

•

damage or loss from natural disasters.

Any of these hazards can result in substantial liabilities or losses to us from, among other things:

•

suspension of drilling operations;

•

damage to, or destruction of, our property and equipment and that of others;

•

personal injury and loss of life;

•

damage to producing or potentially productive oil and gas formations through which we drill; and

•

environmental damage.

We seek to protect ourselves from some but not all operating hazards through insurance coverage. However, some risks are either not insurable or insurance is available only at rates that we consider uneconomical. Those risks include pollution liability in excess of relatively low limits. Depending on competitive conditions and other factors, we attempt to obtain contractual protection against uninsured operating risks from our customers. However, customers who provide contractual indemnification protection may not in all cases maintain adequate insurance to support their indemnification obligations. Our insurance or indemnification arrangements may not adequately protect us against liability or loss from all the hazards of our operations. The occurrence of a significant event that we have not fully insured or indemnified against or the failure of a customer to meet its indemnification obligations to us could materially and adversely affect our results of operations and financial condition. Furthermore, we may not be able to maintain adequate insurance in the future at rates we consider reasonable.

Our current insurance coverage includes property insurance on our rigs, drilling equipment, production services equipment and real property. Our insurance coverage for property damage to our rigs, drilling equipment and production services equipment is based on our estimates of the cost of comparable used equipment to replace the insured property. The policy provides for a deductible on drilling rigs of $250,000 per occurrence ($500,000 deductible for rigs with an insured value greater than $10 million), and a deductible on production services equipment of $100,000 per occurrence. Our third-party liability insurance coverage is $51 million per occurrence and in the aggregate, with a deductible of $260,000 per occurrence. We believe that we are adequately insured for public liability and property damage to others with respect to our operations. However, such insurance may not be sufficient to protect us against liability for all consequences of well disasters, extensive fire damage or damage to the environment.

In addition, we generally carry insurance coverage to protect against certain hazards inherent in our turnkey contract drilling operations. This insurance covers “control-of-well,” including blowouts above and below the surface, redrilling, seepage and pollution. This policy provides coverage of $3 million, $5 million, $10 million, $15 million or $20 million depending on the area in which the well is drilled and its target depth, subject to a deductible of the greater of 15% of the well’s anticipated dry hole cost or $150,000. This policy also provides care, custody and control insurance, with a limit of $1 million, subject to a $100,000 deductible.

Employees

We currently have approximately 2550 employees. Approximately 300 of these employees are salaried administrative or supervisory employees. The rest of our employees are working in operations for our Drilling Services Division and Production Services Division and are primarily compensated on an hourly basis. The number of employees in operations fluctuates depending on the utilization of our drilling rigs, well service rigs and wireline units at any particular time. None of our employment arrangements are subject to collective bargaining arrangements.

Our operations require the services of employees having the technical training and experience necessary to obtain proper operational standards. As a result, our operations depend, to a considerable extent, on the

continuing availability of such personnel. Although we have not encountered material difficulty in hiring and retaining employees in our operations, shortages of qualified personnel have occurred in our industry. If we should suffer any material loss of personnel to competitors or be unable to employ additional or replacement personnel with the requisite level of training and experience to adequately operate our equipment, our operations could be materially and adversely affected. While we believe our wage rates are competitive and our relationships with our employees are satisfactory, a significant increase in the wages paid by other employers could result in a reduction in our workforce, increases in wage rates, or both. The occurrence of either of these events for a significant period of time could have a material and adverse effect on our financial condition and results of operations.

Facilities

Our corporate office facilities are located at 1250 N.E. Loop 410, Suite 1000 San Antonio, Texas 78209 and are leased with payments escalating from $27,911 per month in January 2011 to $29,316 per month with a non-cancelable lease term expiring in December 2013.

We conduct our business operations through 50 other real estate locations in the United States (Texas, Oklahoma, Colorado, Utah, Montana, North Dakota, Pennsylvania, West Virginia, Wyoming, Mississippi, Arkansas, Louisiana and Kansas) and internationally in Colombia. These real estate locations are primarily used for regional offices and storage and maintenance yards. We own 11 of these real estate locations and the remaining 39 real estate locations are leased with payments ranging from $250 per month to $27,169 per month with non-cancelable lease terms expiring through August 2015.

Governmental Regulation

Our operations are subject to stringent laws and regulations relating to containment, disposal and controlling the discharge of hazardous oilfield waste and other non-hazardous waste material into the environment, requiring removal and cleanup under certain circumstances, or otherwise relating to the protection of the environment. In addition, our operations are often conducted in or near ecologically sensitive areas, such as wetlands and coastal areas of the Gulf of Mexico, which are subject to special protective measures and which may expose us to additional operating costs and liabilities for accidental discharges of oil, natural gas, drilling fluids or contaminated water, or for noncompliance with other aspects of applicable laws. We are also subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable state statutes. The OSHA hazard communication standard, the Environmental Protection Agency (“EPA”) “community right-to-know” regulations under Title III of the Federal Superfund Amendment and Reauthorization Act and comparable state statutes require us to organize and report information about the hazardous materials we use in our operations to employees, state and local government authorities and local citizens.

Environmental laws and regulations are complex and subject to frequent change. In some cases, they can impose liability for the entire cost of cleanup on any responsible party, without regard to negligence or fault, and can impose liability on us for the conduct of others or conditions others have caused, or for our acts that complied with all applicable requirements when we performed them. We may also be exposed to environmental or other liabilities originating from businesses and assets that we purchased from others. Compliance with applicable environmental laws and regulations has not, to date, materially affected our capital expenditures, earnings or competitive position, although compliance measures have added to our costs of operating drilling equipment in some instances. We do not expect to incur material capital expenditures in our next fiscal year in order to comply with current environment control regulations. However, our compliance with amended, new or more stringent requirements, stricter interpretations of existing requirements or the future discovery of contamination may require us to make material expenditures or subject us to liabilities that we currently do not anticipate.

restricting the emission of carbon dioxide, methane and other greenhouse gases. Among these developments are the United Nations Framework Convention on Climate Change, also known as the “Kyoto Protocol” (an internationally applied protocol, which has been ratified in Colombia, one of our reporting segments), the Regional Greenhouse Gas Initiative or “RGGI” in the Northeastern United States, and the Western Regional Climate Action Initiative in the Western United States, including partners states New Mexico, Utah, and Montana and observer states Colorado and Wyoming.

The U.S. Congress has been actively considering legislation to reduce emissions of greenhouse gases, primarily through the development of greenhouse gas cap and trade programs. In June of 2009, the U.S. House of Representatives passed a cap and trade bill known as the American Clean Energy and Security Act of 2009, which is now being considered by the U.S. Senate, among other alternative bills. In addition, more than one-third of the states already have begun implementing legal measures to reduce emissions of greenhouse gases.

In 2007, the United States Supreme Court in Massachusetts, et al. v. EPA, held that carbon dioxide may be regulated as an “air pollutant” under the federal Clean Air Act. On December 7, 2009, the EPA responded to the Massachusetts, et al. v. EPA decision and issued a finding that the current and projected concentrations of greenhouse gases in the atmosphere threaten the public health and welfare of current and future generations, and that certain greenhouse gases from new motor vehicles and motor vehicle engines contribute to the atmospheric concentrations of greenhouse gases and hence to the threat of climate change.

On September 22, 2009, the EPA finalized a rule requiring nation-wide reporting of greenhouse gas emissions beginning January 1, 2010. The rule applies primarily to large facilities emitting 25,000 metric tons or more of carbon dioxide-equivalent greenhouse gas emissions per year, and to most upstream suppliers of fossil fuels and industrial greenhouse gas, as well as to manufacturers of vehicles and engines. In addition, the EPA recently proposed a rule that would, in general, require facilities that emit more than 25,000 tons per year of greenhouse gas equivalents to obtain permits to demonstrate that best practices and technology are being used to minimize greenhouse gas emissions.

Although it is not possible at this time to predict whether proposed legislation or regulations will be adopted as initially written, if at all, or how legislation or new regulations that may be adopted to address greenhouse gas emissions would impact our business, any such future laws and regulations could result in increased compliance costs or additional operating restrictions. Any additional costs or operating restrictions associated with legislation or regulations regarding greenhouse gas emissions could have a material adverse effect on our operating results and cash flows. In addition, these developments could curtail the demand for fossil fuels such as oil and gas in areas of the world where our customers operate and thus adversely affect demand for our services, which may in turn adversely affect our future results of operations. Finally, we cannot predict with any certainty whether changes to temperature, storm intensity or precipitation patterns as a result of climate change will have a material impact on our operations.

The EPA has recently focused on citizen concerns about the risk of water contamination and public health problems from drilling and hydraulic fracturing activities. The EPA is conducting a comprehensive research study on the potential adverse effects that hydraulic fracturing may have on water quality and public health. It is possible that resulting federal, state and local laws and regulations might be imposed on fracturing activities. The potential adoption of federal and state legislative and regulatory initiatives related to hydraulic fracturing could result in operating restrictions or delays in the completion of oil and gas wells. A decline in the drilling of new wells and related well servicing activities caused by these initiatives could adversely affect our financial position, results of operations and cash flows.

In addition, our business depends on the demand for land drilling and production services from the oil and gas industry and, therefore, is affected by tax, environmental and other laws relating to the oil and gas industry generally, by changes in those laws and by changes in related administrative regulations. It is possible that these laws and regulations may in the future add significantly to our operating costs or those of our customers, or otherwise directly or indirectly affect our operations.

Our wireline operations involve the use of radioactive isotopes along with other nuclear, electrical, acoustic, and mechanical devices. Our activities involving the use of isotopes are regulated by the U.S. Nuclear Regulatory Commission and specified agencies of certain states. Additionally, we use high explosive charges for perforating casing and formations, and we use various explosive cutters to assist in wellbore cleanout. Such operations are regulated by the U.S. Department of Justice, Bureau of Alcohol, Tobacco, Firearms, and Explosives and require us to obtain licenses or other approvals for the use of densitometers as well as explosive charges. We have obtained these licenses and approvals when necessary and believe that we are in substantial compliance with these federal requirements.

Among the services we provide, we operate as a motor carrier for the transportation of our own equipment and therefore are subject to regulation by the U.S. Department of Transportation and by various state agencies. These regulatory authorities exercise broad powers, governing activities such as the authorization to engage in motor carrier operations and regulatory safety. There are additional regulations specifically relating to the trucking industry, including testing and specification of equipment and product handling requirements. The trucking industry is subject to possible regulatory and legislative changes that may affect the economics of the industry by requiring changes in operating practices or by changing the demand for common or contract carrier services or the cost of providing truckload services. Some of these possible changes include increasingly stringent environmental regulations, changes in the hours of service regulations which govern the amount of time a driver may drive in any specific period, onboard black box recorder devices or limits on vehicle weight and size.

Interstate motor carrier operations are subject to safety requirements prescribed by the U.S. Department of Transportation. To a large degree, intrastate motor carrier operations are subject to state safety regulations that mirror federal regulations. Such matters as weight and dimension of equipment are also subject to federal and state regulations.

From time to time, various legislative proposals are introduced, including proposals to increase federal, state, or local taxes, including taxes on motor fuels, which may increase our costs or adversely impact the recruitment of drivers. We cannot predict whether, or in what form, any increase in such taxes applicable to us will be enacted.

Available Information

Our Website address is www.pioneerdrlg.com. Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports, are available free of charge through our Website as soon as reasonably practicable after we electronically file those materials with, or furnish those materials to, the Securities and Exchange Commission. The public may read and copy these materials at the Securities and Exchange Commission’s Public Reference Room at 100 F Street, N.E., Washington, DC 20549. For additional information on the Securities and Exchange Commission’s Public Reference Room, please call 1-800-SEC-0330. In addition, the Securities and Exchange Commission maintains an Internet site at www.sec.gov that contains reports, proxy and information statements and other information regarding issuers that file electronically. We have also posted on our Website our: Charters for the Audit, Compensation, and Nominating and Corporate Governance Committees of our Board; Code of Conduct and Ethics; Rules of Conduct; and Company Contact Information.

Item 1A.

Risk Factors

The information set forth in this Item 1A should be read in conjunction with the rest of the information included in this report, including “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 and the historical financial statements and related notes this report contains. While we attempt to identify, manage and mitigate risks and uncertainties associated with our business to the extent practical under the circumstances, some level of risk and uncertainty will always be present. Additional risks and uncertainties that are not presently known to us or that we currently believe are immaterial also may negatively impact our business, financial condition or operating results.

Set forth below are various risks and uncertainties that could adversely impact our business, financial condition, results of operations and cash flows.

Risks Relating to the Oil and Gas Industry

We derive all our revenues from companies in the oil and gas exploration and production industry, a historically cyclical industry with levels of activity that are significantly affected by the levels and volatility of oil and gas prices.

As a provider of contract land drilling services and oil and gas production services, our business depends on the level of exploration and production activity in the geographic markets where we operate. The oil and gas exploration and production industry is a historically cyclical industry characterized by significant changes in the levels of exploration and development activities. Oil and gas prices, and market expectations of potential changes in those prices, significantly affect the levels of those activities. Worldwide political, economic, and military events as well as natural disasters have contributed to oil and gas price volatility and are likely to continue to do so in the future. Any prolonged reduction in the overall level of exploration and development activities, whether resulting from changes in oil and gas prices or otherwise, could materially and adversely affect us in many ways by negatively impacting:

•

our revenues, cash flows and profitability;

•

the fair market value of our drilling rig fleet and production service assets;

•

our ability to maintain or increase our borrowing capacity;

•

our ability to obtain additional capital to finance our business and make acquisitions, and the cost of that capital; and

•

our ability to retain skilled rig personnel whom we would need in the event of an upturn in the demand for our services.

Depending on the market prices of oil and gas, oil and gas exploration and production companies may cancel or curtail their drilling programs and may lower production spending on existing wells, thereby reducing demand for our services. Many factors beyond our control affect oil and gas prices, including:

•

the cost of exploring for, producing and delivering oil and gas;

•

the discovery rate of new oil and gas reserves;

•

the rate of decline of existing and new oil and gas reserves;

•

available pipeline and other oil and gas transportation capacity;

•

the levels of oil and gas storage;

•

the ability of oil and gas exploration and production companies to raise capital;

•

economic conditions in the United States and elsewhere;

•

actions by OPEC, the Organization of Petroleum Exporting Countries;

•

political instability in the Middle East and other major oil and gas producing regions;

•

governmental regulations, both domestic and foreign;

•

domestic and foreign tax policy;

•

weather conditions in the United States and elsewhere;

•

the pace adopted by foreign governments for the exploration, development and production of their national reserves;

•

the price of foreign imports of oil and gas; and

•

the overall supply and demand for oil and gas.

Oil and gas prices have been volatile historically and, we believe, will continue to be so in the future. During 2009, oil and natural gas prices fell significantly below the levels seen in late 2008, and while oil prices have improved during 2010, natural gas prices have remained depressed. Future declines in and volatility in oil and gas prices could materially and adversely affect our business and financial results.

Risks Relating to Our Business

Reduced demand for or excess capacity of drilling services or production services could adversely affect our profitability.

Our profitability in the future will depend on many factors, but largely on pricing and utilization rates for our drilling and production services. A reduction in the demand for drilling rigs or an increase in the supply of drilling rigs, whether through new construction or refurbishment, could decrease the dayrates and utilization rates for our drilling services, which would adversely affect our revenues and profitability. An increase in supply of well service rigs, wireline units and fishing and rental tools equipment, without a corresponding increase in demand, could similarly decrease the pricing and utilization rates of our production services, which would adversely affect our revenues and profitability. We experienced a substantial decrease in revenue and utilization rates during the last quarter of 2008 and during 2009. During 2010, revenue and utilization rates modestly increased and we expect continued modest increases in 2011.

We operate in a highly competitive, fragmented industry in which price competition could reduce our profitability.

We encounter substantial competition from other drilling contractors and other oilfield service companies. Our primary market areas are highly fragmented and competitive. The fact that drilling and well service rigs are mobile and can be moved from one market to another in response to market conditions heightens the competition in the industry and may result in an oversupply of rigs in an area. Contract drilling companies and other oilfield service companies compete primarily on a regional basis, and the intensity of competition may vary significantly from region to region at any particular time. If demand for drilling or production services improves in a region where we operate, our competitors might respond by moving in suitable rigs from other regions. An influx of rigs from other regions could rapidly intensify competition, reduce profitability and make any improvement in demand for drilling or production services short-lived.

Most drilling services contracts and production services contracts are awarded on the basis of competitive bids, which also results in price competition. In addition to pricing and rig availability, we believe the following factors are also important to our customers in determining which drilling services or production services provider to select:

•

the type and condition of each of the competing drilling, and well service rigs;

•

the mobility and efficiency of the rigs;

•

the quality of service and experience of the rig crews;

•

the safety records of the rigs;

•

the offering of ancillary services; and

•

the ability to provide drilling and production equipment adaptable to, and personnel familiar with, new technologies and drilling and production techniques.

While we must be competitive in our pricing, our competitive strategy generally emphasizes the quality of our equipment, the safety record of our rigs, our ability to offer ancillary services and the quality of service and experience of our rig crews to differentiate us from our competitors. This strategy is less effective as lower demand for drilling and production services or an oversupply of drilling and well service rigs intensifies price competition and makes it more difficult for us to compete on the basis of factors other than price. In all of the markets in which we compete, an oversupply of rigs can cause greater price competition, which can reduce our profitability.

We face competition from many competitors with greater resources.

Some of our competitors have greater financial, technical and other resources than we do. Their greater capabilities in these areas may enable them to:

•

better withstand industry downturns;

•

compete more effectively on the basis of price and technology;

•

retain skilled rig personnel; and

•

build new rigs or acquire and refurbish existing rigs so as to be able to place rigs into service more quickly than us in periods of high drilling demand.

Additionally, although we take measures to ensure that we use advanced technologies for drilling and production services equipment, changes in technology or improvements in our competitors’ equipment could make our equipment less competitive or require significant capital investments to keep our equipment competitive.

Unexpected cost overruns on our turnkey drilling jobs and our footage contracts could adversely affect our financial position and our results of operations.

We have historically derived a portion of our revenues from turnkey drilling contracts, and we expect turnkey contracts will continue to represent a component of our future revenues. The occurrence of uninsured or under-insured losses or operating cost overruns on our turnkey jobs could have a material adverse effect on our financial position and results of operations. Under a typical turnkey drilling contract, we agree to drill a well for our customer to a specified depth and under specified conditions for a fixed price. We provide technical expertise and engineering services, as well as most of the equipment and drilling supplies required to drill the well. We often subcontract for related services, such as the provision of casing crews, cementing and well logging. Under typical turnkey drilling arrangements, we do not receive progress payments and are paid by our customer only after we have performed the terms of the drilling contract in full. For these reasons, the risk to us under a turnkey drilling contract is substantially greater than for a well drilled on a daywork basis because we must assume most of the risks associated with drilling operations that the operator generally assumes under a daywork contract, including the risks of blowout, loss of hole, stuck drill pipe, machinery breakdowns, abnormal drilling conditions and risks associated with subcontractors’ services, supplies, cost escalations and personnel. Similar to our turnkey contracts, under a footage contract we assume most of the risks associated with drilling operations that the operator generally assumes under a daywork contract. In addition, since we are only paid by our customers after we have performed the terms of the drilling contract in full, our liquidity can be affected by the number of turnkey and footage contracts that we enter into.

Although we attempt to obtain insurance coverage to reduce certain of the risks inherent in our turnkey drilling operations, adequate coverage may be unavailable in the future and we might have to bear the full cost of such risks, which could have an adverse effect on our financial condition and results of operations.

Our operations involve operating hazards, which, if not insured or indemnified against, could adversely affect our results of operations and financial condition.

Our operations are subject to the many hazards inherent in the drilling and well services industries, including the risks of:

•

blowouts;

•

cratering;

•

fires and explosions;

•

loss of well control;

•

collapse of the borehole;

•

damaged or lost drilling equipment; and

•

damage or loss from natural disasters.

Any of these hazards can result in substantial liabilities or losses to us from, among other things:

•

suspension of operations;

•

damage to, or destruction of, our property and equipment and that of others;

•

personal injury and loss of life;

•

damage to producing or potentially productive oil and gas formations through which we drill; and

•

environmental damage.

We seek to protect ourselves from some but not all operating hazards through insurance coverage. However, some risks are either not insurable or insurance is available only at rates that we consider uneconomical. Those risks include, among other things, pollution liability in excess of relatively low limits. Depending on competitive conditions and other factors, we attempt to obtain contractual protection against uninsured operating risks from our customers. However, customers who provide contractual indemnification protection may not in all cases maintain adequate insurance or otherwise have the financial resources necessary to support their indemnification obligations. Our insurance or indemnification arrangements may not adequately protect us against liability or loss from all the hazards of our operations. The occurrence of a significant event that we have not fully insured or indemnified against or the failure of a customer to meet its indemnification obligations to us could materially and adversely affect our results of operations and financial condition. Furthermore, we may be unable to maintain adequate insurance in the future at rates we consider reasonable.

We could be adversely affected if shortages of equipment, supplies or personnel occur.

From time to time there have been shortages of drilling and production services equipment and supplies during periods of high demand which we believe could recur. Shortages could result in increased prices for drilling and production services equipment or supplies that we may be unable to pass on to customers. In addition, during periods of shortages, the delivery times for equipment and supplies can be substantially longer. Any significant delays in our obtaining drilling and production services equipment or supplies could limit drilling and production services operations and jeopardize our relations with customers. In addition, shortages of drilling and production services equipment or supplies could delay and adversely affect our ability to obtain new contracts for our rigs, which could have a material adverse effect on our financial condition and results of operations.

Our strategy of constructing drilling rigs during periods of peak demand requires that we maintain an adequate supply of drilling rig components to complete our rig building program. Our suppliers may be unable to continue providing us the needed drilling rig components if their manufacturing sources are unable to fulfill their commitments.

Our operations require the services of employees having the technical training and experience necessary to obtain the proper operational results. As a result, our operations depend, to a considerable extent, on the continuing availability of such personnel. Shortages of qualified personnel have occurred in our industry. If we should suffer any material loss of personnel to competitors or be unable to employ additional or replacement personnel with the requisite level of training and experience to adequately operate our equipment, our operations could be materially and adversely affected. A significant increase in the wages paid by other employers could result in a reduction in our workforce, increases in wage rates, or both. The occurrence of either of these events for a significant period of time could have a material and adverse effect on our financial condition and results of operations.

Our acquisition strategy exposes us to various risks, including those relating to difficulties in identifying suitable acquisition opportunities and integrating businesses, assets and personnel, as well as difficulties in obtaining financing for targeted acquisitions and the potential for increased leverage or debt service requirements.

As a key component of our business strategy, we have pursued and intend to continue to pursue acquisitions of complementary assets and businesses. For example, since September 1999, we have significantly expanded our drilling rig fleet by adding 35 rigs through acquisitions and by adding 31 rigs through the construction of rigs from new and used components. In addition, we completed the acquisition of the production services businesses of WEDGE and Competition during the first quarter of 2008. We have continued to invest in the expansion of our operations and plan to add a total of six well service rigs and 14 wireline units in the first half of 2011.

Our acquisition strategy in general, and our recent acquisitions in particular, involve numerous inherent risks, including:

•

unanticipated costs and assumption of liabilities and exposure to unforeseen liabilities of acquired businesses, including environmental liabilities;

•

difficulties in integrating the operations and assets of the acquired business and the acquired personnel;

•

limitations on our ability to properly assess and maintain an effective internal control environment over an acquired business in order to comply with applicable periodic reporting requirements;

•

potential losses of key employees and customers of the acquired businesses;

•

risks of entering markets in which we have limited prior experience; and

•

increases in our expenses and working capital requirements.

The process of integrating an acquired business may involve unforeseen costs and delays or other operational, technical and financial difficulties that may require a disproportionate amount of management attention and financial and other resources. Possible future acquisitions may be for purchase prices significantly higher than those we paid for previous acquisitions. Our failure to achieve consolidation savings, to incorporate the acquired businesses and assets into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on our financial condition and results of operations.

In addition, we may not have sufficient capital resources to complete additional acquisitions. Historically, we have funded the growth of our rig fleet through a combination of debt and equity financing. We may incur substantial additional indebtedness to finance future acquisitions and also may issue equity securities or convertible securities in connection with such acquisitions. Debt service requirements could represent a

significant burden on our results of operations and financial condition and the issuance of additional equity or convertible securities could be dilutive to our existing shareholders. Furthermore, we may not be able to obtain additional financing on satisfactory terms.

Even if we have access to the necessary capital, we may be unable to continue to identify additional suitable acquisition opportunities, negotiate acceptable terms or successfully acquire identified targets.

Our indebtedness could restrict our operations and make us more vulnerable to adverse economic conditions.

In connection with the acquisition of the production services businesses of WEDGE and Competition in March 2008, we entered into a senior secured revolving credit facility (the “Revolving Credit Facility”) which was later amended in October 2009 and February 2010. In March 2010, we issued $250 million of Senior Notes with a coupon interest rate of 9.875% that are due in 2018 (the “Senior Notes”). We received $234.8 million of net proceeds from the issuance of the 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. As of December 31, 2010, our total debt was $280.9 million.

Our current and future indebtedness could have important consequences, including:

•

impairing our ability to make investments and obtain additional financing for working capital, capital expenditures, acquisitions or other general corporate purposes;

•

limiting our ability to use operating cash flow in other areas of our business because we must dedicate a substantial portion of these funds to make principal and interest payments on our indebtedness;

•

making us more vulnerable to a downturn in our business, our industry or the economy in general as a substantial portion of our operating cash flow could be required to make principal and interest payments on our indebtedness, making it more difficult to react to changes in our business and in industry and market conditions;

•

limiting our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate;

•

limiting our ability to obtain additional financing that may be necessary to operate or expand our business;

•

putting us at a competitive disadvantage to competitors that have less debt; and

•

increasing our vulnerability to rising interest rates.

We anticipate that our cash generated by operations and our ability to borrow under the currently unused portion of our Revolving Credit Facility should allow us to meet our routine financial obligations for the foreseeable future. However, our ability to make payments on our indebtedness, and to fund planned capital expenditures, will depend on our ability to generate cash in the future. This, to a certain extent, is subject to conditions in the oil and gas industry, general economic and financial conditions, competition in the markets where we operate, the impact of legislative and regulatory actions on how we conduct our business and other factors, all of which are beyond our control. If our business does not generate sufficient cash flow from operations to service our outstanding indebtedness, we may have to undertake alternative financing plans, such as:

•

refinancing or restructuring our debt;

•

selling assets;

•

reducing or delaying acquisitions or capital investments, such as refurbishments of our rigs and related equipment; or

•

seeking to raise additional capital.

However, we may be unable to implement alternative financing plans, if necessary, on commercially reasonable terms or at all, and any such alternative financing plans might be insufficient to allow us to meet our debt obligations. If we are unable to generate sufficient cash flow or are otherwise unable to obtain the funds required to make principal and interest payments on our indebtedness, or if we otherwise fail to comply with the various covenants in our Revolving Credit Facility or other instruments governing any future indebtedness, we could be in default under the terms of our Revolving Credit Facility or such instruments. In the event of a default, the lenders under our Revolving Credit Facility could elect to declare all the loans made under such facility to be due and payable together with accrued and unpaid interest and terminate their commitments thereunder and we or one or more of our subsidiaries could be forced into bankruptcy or liquidation. Any of the foregoing consequences could materially and adversely affect our business, financial condition, results of operations and prospects.

Our Revolving Credit Facility and our Senior Notes impose restrictions on us that may affect our ability to successfully operate our business.

Our Revolving Credit Facility limits our ability to take various actions, such as:

•

limitations on the incurrence of additional indebtedness;

•

restrictions on investments, capital expenditures, mergers or consolidations, asset dispositions, acquisitions, transactions with affiliates and other transactions without the lenders’ consent; and

•

limitation on dividends and distributions.

In addition, our Revolving Credit Facility requires us to maintain certain financial ratios and to satisfy certain financial conditions, which may require us to reduce our debt or take some other action in order to comply with them.

The Indenture governing our Senior Notes contains certain restrictions on our and certain of our subsidiaries’ ability to:

•

pay dividends on stock;

•

repurchase stock or redeem subordinated debt or make other restricted payments;

•

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

•

create liens on the our assets;

•

enter into sale and leaseback transactions;

•

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 another person;

•

enter into transactions with affiliates; and

•

enter into new lines of business.

The failure to comply with any of these restrictions or conditions, some of which become more restrictive over time, such as financial ratios or covenants, would cause an event of default under our Revolving Credit Facility or our Senior Notes. An event of default, if not waived, could result in acceleration of the outstanding indebtedness, in which case the debt would become immediately due and payable. If this occurs, we may not be able to pay our debt or borrow sufficient funds to refinance it. Even if new financing is available, it may not be available on terms that are acceptable to us. These restrictions could also limit our ability to obtain future financing, make needed capital expenditures, withstand a downturn in our business or the economy in general, or otherwise conduct necessary corporate activities. We also may be prevented from taking advantage of business opportunities that arise because of the limitations imposed on us by the restrictive covenants under our Revolving Credit Facility and our Senior Notes.

Our international operations are subject to political, economic and other uncertainties not encountered in our domestic operations.

As we continue to implement our strategy of expanding into areas outside the United States, our international operations will be subject to political, economic and other uncertainties not generally encountered in our U.S. operations. These will include, among potential others:

•

risks of war, terrorism, civil unrest and kidnapping of employees;

•

expropriation, confiscation or nationalization of our assets;

•

renegotiation or nullification of contracts;

•

foreign taxation;

•

the inability to repatriate earnings or capital due to laws limiting the right and ability of foreign subsidiaries to pay dividends and remit earnings to affiliated companies;

•

changing political conditions and changing laws and policies affecting trade and investment;

•

concentration of customers;

•

regional economic downturns;

•

the overlap of different tax structures;

•

the burden of complying with multiple and potentially conflicting laws;

•

the risks associated with the assertion of foreign sovereignty over areas in which our operations are conducted;

•

difficulty in collecting international accounts receivable; and

•

potentially longer payment cycles.

Our international operations are concentrated in Colombia and our drilling contracts are currently with one customer, Ecopetrol. We believe our relationship with Ecopetrol is good; however, the loss of this large customer could have an adverse effect on our business, financial condition and result of operations.

Our international operations may also face the additional risks of fluctuating currency values, hard currency shortages and controls of foreign currency exchange. Additionally, in some jurisdictions, we may be subject to foreign governmental regulations favoring or requiring the awarding of contracts to local contractors or requiring foreign contractors to employ citizens of, or purchase supplies from, a particular jurisdiction. These regulations could adversely affect our ability to compete.

Our operations are subject to various laws and governmental regulations that could restrict our future operations and increase our operating costs.

Many aspects of our operations are subject to various federal, state and local laws and governmental regulations, including laws and regulations governing:

•

environmental quality;

•

pollution control;

•

remediation of contamination;

•

preservation of natural resources;

•

transportation, and

•

worker safety.

Our operations are subject to stringent federal, state and local laws, rules and regulations governing the protection of the environment and human health and safety. Some of those laws, rules and regulations relate to the disposal of hazardous substances, oilfield waste and other waste materials and restrict the types, quantities and concentrations of those substances that can be released into the environment. Several of those laws also require removal and remedial action and other cleanup under certain circumstances, commonly regardless of fault. Our operations routinely involve the handling of significant amounts of waste materials, some of which are classified as hazardous substances. Planning, implementation and maintenance of protective measures are required to prevent accidental discharges. Spills of oil, natural gas liquids, drilling fluids and other substances may subject us to penalties and cleanup requirements. Handling, storage and disposal of both hazardous and non-hazardous wastes are also subject to these regulatory requirements. In addition, our operations are often conducted in or near ecologically sensitive areas, such as wetlands, which are subject to special protective measures and which may expose us to additional operating costs and liabilities for accidental discharges of oil, gas, drilling fluids, contaminated water or other substances, or for noncompliance with other aspects of applicable laws and regulations.

The federal Clean Water Act, as amended by the Oil Pollution Act, the federal Clean Air Act, the federal Resource Conservation and Recovery Act, the federal Comprehensive Environmental Response, Compensation, and Liability Act, or CERCLA, the Safe Drinking Water Act, the federal Outer Continental Shelf Lands Act, the Occupational Safety and Health Act, or OSHA, and their state counterparts and similar statutes are the primary statutes that impose the requirements described above and provide for civil, criminal and administrative penalties and other sanctions for violation of their requirements. The OSHA hazard communication standard, the Environmental Protection Agency “community right-to-know” regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require us to organize and report information about the hazardous materials we use in our operations to employees, state and local government authorities and local citizens. In addition, CERCLA, also known as the “Superfund” law, and similar state statutes impose strict liability, without regard to fault or the legality of the original conduct, on certain classes of persons who are considered responsible for the release or threatened release of hazardous substances into the environment. These persons include the current owner or operator of a facility where a release has occurred, the owner or operator of a facility at the time a release occurred, and companies that disposed of or arranged for the disposal of hazardous substances found at a particular site. This liability may be joint and several. Such liability, which may be imposed for the conduct of others and for conditions others have caused, includes the cost of removal and remedial action as well as damages to natural resources. Few defenses exist to the liability imposed by environmental laws and regulations. It is also common for third parties to file claims for personal injury and property damage caused by substances released into the environment.

Environmental laws and regulations are complex and subject to frequent change. Failure to comply with governmental requirements or inadequate cooperation with governmental authorities could subject a responsible party to administrative, civil or criminal action. We may also be exposed to environmental or other liabilities originating from businesses and assets which we acquired from others. Our compliance with amended, new or more stringent requirements, stricter interpretations of existing requirements or the future discovery of contamination or regulatory noncompliance may require us to make material expenditures or subject us to liabilities that we currently do not anticipate.

There are a variety of regulatory developments, proposals or requirements and legislative initiatives that have been introduced in the United States and international regions in which we operate that are focused on restricting the emission of carbon dioxide, methane and other greenhouse gases. Among these developments are the United Nations Framework Convention on Climate Change, also known as the “Kyoto Protocol” (an internationally applied protocol, which has been ratified in Colombia, one of our reporting segments), the Regional Greenhouse Gas Initiative or “RGGI” in the Northeastern United States, and the Western Regional Climate Action Initiative in the Western United States, including partners states New Mexico, Utah, and Montana and observer states Colorado and Wyoming.

Among the services we provide, we operate as a motor carrier and therefore are subject to regulation by the U.S. Department of Transportation and by various state agencies. These regulatory authorities exercise broad powers, governing activities such as the authorization to engage in motor carrier operations and regulatory safety. There are additional regulations specifically relating to the trucking industry, including testing and specification of equipment and product handling requirements. The trucking industry is subject to possible regulatory and

legislative changes that may affect the economics of the industry by requiring changes in operating practices or by changing the demand for common or contract carrier services or the cost of providing truckload services. Some of these possible changes include increasingly stringent environmental regulations, changes in the hours of service regulations which govern the amount of time a driver may drive in any specific period, onboard black box recorder devices or limits on vehicle weight and size.

Risk Relating to Our Capitalization and Organizational Documents

We do not intend to pay dividends on our common stock in the foreseeable future, and therefore only appreciation of the price of our common stock will provide a return to our shareholders.

We have not paid or declared any dividends on our common stock and currently intend to retain any earnings to fund our working capital needs and growth opportunities. Any future dividends will be at the discretion of our board of directors after taking into account various factors it deems relevant, including our financial condition and performance, cash needs, income tax consequences and restrictions imposed by the Texas Business Organizations Code and other applicable laws and by our credit facilities. Our debt arrangements include provisions that generally prohibit us from paying dividends on our capital stock, including our common stock.

We may issue preferred stock whose terms could adversely affect the voting power or value of our common stock.

Our articles of incorporation authorize us to issue, without the approval of our shareholders, one or more classes or series of preferred stock having such designations, preferences, limitations and relative rights, including preferences over our common stock respecting dividends and distributions, as our board of directors may determine. The terms of one or more classes or series of preferred stock could adversely impact the voting power or value of our common stock. For example, we might grant holders of preferred stock the right to elect some number of our directors in all events or on the happening of specified events or the right to veto specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we might assign to holders of preferred stock could affect the residual value of the common stock.

Provisions in our organizational documents could delay or prevent a change in control of our company even if that change would be beneficial to our shareholders.

The existence of some provisions in our organizational documents could delay or prevent a change in control of our company even if that change would be beneficial to our shareholders. Our articles of incorporation and bylaws contain provisions that may make acquiring control of our company difficult, including:

•

provisions regulating the ability of our shareholders to nominate candidates for election as directors or to bring matters for action at annual meetings of our shareholders;

•

limitations on the ability of our shareholders to call a special meeting and act by written consent;

•

provisions dividing our board of directors into three classes elected for staggered terms; and

•

the authorization given to our board of directors to issue and set the terms of preferred stock.

Item 1B.

Unresolved Staff Comments

Not applicable.

Item 2.

Properties

For a description of our significant properties, see “Business—General” and “Business—Facilities” in Item 1 of this report. We consider each of our significant properties to be suitable for its intended use.

Item 3.

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.

PART II

Item 5.

Market for Registrant’s Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities

As of February 4, 2011, 54,243,452 shares of our common stock were outstanding, held by 515 shareholders of record. The number of record holders does not necessarily bear any relationship to the number of beneficial owners of our common stock.

Our common stock trades on the NYSE Amex under the symbol “PDC.” The following table sets forth, for each of the periods indicated, the high and low sales prices per share on the NYSE Amex:


	Low		High
Fiscal Year Ended December 31, 2010:
First Quarter	$	6.89	$	9.79
Second Quarter		5.24		7.92
Third Quarter		5.40		6.90
Fourth Quarter		6.04		9.03

Fiscal Year Ended December 31, 2009:
First Quarter	$	3.28	$	6.70
Second Quarter		3.46		6.88
Third Quarter		3.96		7.34
Fourth Quarter		6.00		8.16

Fiscal Year Ended December 31, 2008:
First Quarter	$	10.59	$	16.70
Second Quarter		15.29		20.64
Third Quarter		12.49		18.82
Fourth Quarter		4.85		13.09

The last reported sales price for our common stock on the NYSE Amex on February 4, 2011 was $9.56 per share.

We have not paid or declared any dividends on our common stock and currently intend to retain earnings to fund our working capital needs and growth opportunities. Any future dividends will be at the discretion of our board of directors after taking into account various factors it deems relevant, including our financial condition and performance, cash needs, income tax consequences and the restrictions Texas and other applicable laws and our credit facilities then impose. Our debt arrangements include provisions that generally prohibit us from paying dividends, other than dividends on our preferred stock. We currently have no preferred stock outstanding.

No shares of our common stock were purchased by or on behalf of our company or any affiliated purchaser during the quarter ended December 31, 2010.

Performance Graph

The following graph compares, for the periods from December 31, 2005 to December 31, 2010, the cumulative total shareholder return on our common stock with the cumulative total return on the companies that comprise the AMEX Composite Index and a peer group index that includes five companies that provide contract drilling services and / or production services. The companies that comprise the peer group index are Patterson-UTI Energy, Inc., Nabors Industries Ltd., Bronco Drilling Company, Precision Drilling Trust and Key Energy Services. The comparison assumes that $100 was invested on December 31, 2005 in our common stock, the companies that compose the AMEX Composite Index and the companies that compose the peer group index, and further assumes all dividends were reinvested.

LOGO

Item 6.

Selected Financial Data

The following information derives from our audited financial statements. You should review this information in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 of this report and the historical financial statements and related notes this report contains. The acquisitions of WEDGE and Competition, effective March 1, 2008, and the change in our fiscal year end, resulting in a nine month fiscal year ended December 31, 2007, affect the comparability from period to period of our historical results.


	Years Ended December 31,									Nine months Ended December 31, 2007			Year Ended March 31, 2007
	2010(1)			2009(1)			2008(1)(2)			Nine months Ended December 31, 2007			Year Ended March 31, 2007
	(In thousands, except per share amounts)
Statement of Operations Data:
Revenues	$	487,210		$	325,537		$	610,884		$	313,884		$	416,178
Income (loss) from operations		(18,572	)		(31,840	)		(43,954	)		55,260			126,976
Income (loss) before income taxes		(47,558	)		(40,172	)		(56,688	)		57,774			130,789
Net earnings (loss) applicable to common stockholders		(33,261	)		(23,215	)		(62,745	)		39,645			84,180
Earnings (loss) per common share-basic	$	(0.62	)	$	(0.46	)	$	(1.26	)	$	0.80		$	1.70
Earnings (loss) per common share-diluted	$	(0.62	)	$	(0.46	)	$	(1.26	)	$	0.79		$	1.68

Other Financial Data:
Net cash provided by operating activities	$	98,351		$	123,313		$	186,635		$	115,455		$	131,530
Net cash used in investing activities		(129,481	)		(113,909	)		(505,615	)		(123,858	)		(137,960	)
Net cash provided by financing activities		12,762			4,154			269,098			161			201
Capital expenditures		135,151			110,453			148,096			128,038			147,230


	As of December 31,								As of March 31, 2007
	2010(1)		2009(1)		2008(1)		2007		As of March 31, 2007
	(In thousands)
Balance Sheet Data:
Working capital	$	76,142	$	90,336	$	64,372	$	99,807	$	124,089
Property and equipment, net		655,508		637,022		627,562		417,022		342,901
Long-term debt and capital lease obligations, excluding current installments		279,530		258,073		262,115		—		—
Shareholders’ equity		396,333		421,448		414,118		471,072		428,109
Total assets		841,343		824,955		824,479		560,212		501,495

(1)

The statement of operations data and other financial data for the years ended December 31, 2010, 2009 and 2008 and the balance sheet data as of December 31, 2010, 2009 and 2008 include the impact of the acquisitions of WEDGE and Competition, both of which occurred on March 1, 2008. See Note 2 to Consolidated Financial Statements, included in Part II, Item 8, Financial Statements and Supplementary Data, of this Annual Report on Form 10-K.

(2)

The statement of operations data and other financial data for the year ended December 31, 2008 reflect the impact of a goodwill impairment charge of $118.6 million and an intangible asset impairment charge of $52.8 million. See Note 1 to Consolidated Financial Statements, included in Part II, Item 8, Financial Statements and Supplementary Data, of this Annual Report on Form 10-K.

Item 7.

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, the continued strength or weakness of the contract land drilling industry in the geographic areas in which we operate, decisions about onshore exploration and development projects to be made by oil and gas exploration and production companies, the highly competitive nature of our business, the availability, terms and deployment of capital, the availability of qualified personnel, and changes in, or our failure or inability to comply with, government regulations, including those relating to the environment. We have discussed many of these factors in more detail elsewhere in this report, 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 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 the date on which they are made and we undertake no duty to update or revise any forward-looking statements. 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 Drilling Company provides drilling services and production services to independent and major 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. 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. Our business has grown through acquisitions and through organic growth. Since September 1999, we have significantly expanded our drilling rig fleet by adding 35 rigs through acquisitions and by adding 31 rigs through the construction of rigs from new and used components. On March 1, 2008, we significantly expanded our service offerings when we acquired the production services businesses of WEDGE Group Incorporated (“WEDGE”) for $314.7 million and Prairie Investors d/b/a Competition Wireline (“Competition”) for $30.0 million, which provide well services, wireline services and fishing and rental services. We funded the WEDGE acquisition primarily with $311.5 million of borrowings under our senior secured revolving credit facility. 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 customers.

Business Segments

We currently conduct our operations through two operating segments: our Drilling Services Division and our Production Services Division. The following is a description of these two operating segments. Financial information about our operating segments is included in Note 11, Segment Information, of the Notes to Consolidated Financial Statements, included in Part II, Item 8, Financial Statements and Supplementary Data, of this Annual Report on Form 10-K.

•

Drilling Services Division—Our Drilling Services Division provides contract land drilling services with its fleet of 71 drilling rigs in the following locations:


Drilling Division Locations	Rig Count
South Texas		19
East Texas		13
West Texas		3
North Dakota		9
North Texas		3
Utah		3
Oklahoma		6
Appalachia		7
Colombia		8

As of February 4, 2011, 48 drilling rigs are operating under drilling contracts. We have 17 drilling rigs that are idle and six drilling rigs have been placed in storage or “cold stacked” in our Oklahoma drilling division due to low demand for drilling rigs in that region. We are actively marketing all our idle drilling rigs both domestically and internationally in Latin America. During the second quarter of 2009, we established our Appalachia drilling division location and now have seven drilling rigs operating in the Marcellus Shale. In early 2011, we established our West Texas drilling division location with three drilling rigs that were previously included in our East Texas drilling division location. One of these rigs has begun drilling in the Permian Basin and we expect the remaining two rigs to begin operations in late February 2011. 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 customers. 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.

•

Market Conditions in Our Industry

From 2004 through 2008, domestic exploration and production spending increased as oil and natural gas prices increased. Since late 2008, there has been substantial volatility and a decline in oil and natural gas prices due to the downturn in the global economic environment. In response, our customers curtailed their drilling programs and reduced their production activities, particularly in natural gas producing regions, which has resulted in a decrease in demand and revenue rates for certain of our drilling rigs and production services equipment. Additionally, there was uncertainty in the capital markets and access to financing was limited. These conditions adversely affected our business environment. For additional information concerning the effects of the volatility in oil and gas prices and uncertainty in capital markets, see Item 1A—“Risk Factors” in Part I of this Annual Report on Form 10-K.


	Years Ended December 31,
	2010		2009		2008		2007		2006
Oil (West Texas Intermediate)	$	79.39	$	61.81	$	99.86	$	72.71	$	66.28
Natural Gas (Henry Hub)	$	4.35	$	3.85	$	8.81	$	6.90	$	6.66
U.S. Land Rig Count		1,493		1,035		1,792		1,670		1,537
U.S. Well Service Rig Count		1,854		1,735		2,514		2,388		2,364

Liquidity and Capital Resources

Sources of Capital Resources

Our principal liquidity requirements have been for working capital needs, capital expenditures and acquisitions. Our principal sources of liquidity consist of: (i) cash and cash equivalents (which equaled $22.0 million as of December 31, 2010); (ii) cash generated from operations; and (iii) the unused portion of our senior secured revolving credit facility (the “Revolving Credit Facility”). Our Revolving Credit Facility provides for a senior secured revolving credit facility, with sub-limits for letters of credit and swing-line loans, of up to an aggregate principal amount of $225 million, all of which matures on August 31, 2012. We made a $12.8 million principal payment after December 31, 2010, which resulted in a $25.0 million outstanding balance under our Revolving Credit Facility and $9.2 million in committed letters of credit at February 4, 2011. Therefore, our borrowing availability under our Revolving Credit Facility was $190.8 million as of February 4, 2011. There are no limitations on our ability to access the full borrowing availability under the Revolving Credit Facility other than maintaining compliance with the covenants in the Revolving Credit Facility. Additional information regarding these covenants is provided in the Debt Requirements section below. Borrowings under the Revolving Credit Facility are available for acquisitions, working capital and other general corporate purposes. We presently 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.

On March 11, 2010, we issued $250 million of 9.875% unregistered senior notes due 2018 (the “Senior Notes”), and received $234.8 million net proceeds, after deducting the original issue discount, underwriters’ fees and other debt offering costs, which were used to reduce the outstanding debt balance under our Revolving Credit Facility. The Senior Notes will mature on March 15, 2018 with interest due semi-annually in arrears on March 15 and September 15 of each year, commencing on September 15, 2010. We have the option to redeem the 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 “Indenture”) together with any accrued and unpaid interest to the date of redemption. Prior to March 15, 2014, we may also redeem the Senior Notes, in whole or in part, at a “make-whole” redemption price specified in the Indenture, together with any accrued and unpaid interest to the date of redemption. In addition, prior to March 15, 2013, we may, on one or more occasions, redeem up to 35% of the aggregate principal amount of the Senior Notes at a redemption price of 109.875% of the principal amount, plus any accrued and unpaid interest to the redemption date, with the net proceeds of certain equity offerings, if at least 65% of the aggregate principal amount of the Senior Notes remains outstanding after such redemption and the redemption occurs within 120 days of the closing of the equity offering. In accordance with a registration rights agreement with the holders of our Senior Notes, we filed an exchange offer registration statement on Form S-4 with the Securities and Exchange Commission that became effective on September 2, 2010. This exchange offer registration statement enabled the holders of our Senior Notes to exchange their Senior Notes for publicly registered notes with substantially identical terms. References to the “Senior Notes” herein include the Senior Notes issued in the exchange offer.

In July 2009, we filed a shelf registration statement that permits us to sell equity or debt in one or more offerings up to a total dollar amount of $300 million. In November 2009, we obtained $24.0 million in net proceeds when we sold 3,820,000 shares of our common stock at $6.75 per share, less underwriters’ commissions, pursuant to a public offering under the $300 million shelf registration statement. The remaining availability under the $300 million shelf registration statement for equity or debt offerings is $274.2 million as of February 4, 2011. In the future, we may consider equity or debt offerings, as appropriate, to meet our liquidity needs.

At December 31, 2010, we held $15.9 million (par value) of ARPSs, which were variable-rate preferred securities and had a long-term maturity with the interest rate being reset through “Dutch auctions” that were held every seven days. The ARPSs had historically traded at par because of the frequent interest rate resets and because they were callable at par at the option of the issuer. Interest was paid at the end of each auction period. Our ARPSs were AAA/Aaa rated securities, collateralized by municipal bonds and backed by assets that were equal to or greater than 200% of the liquidation preference. Until February 2008, the auction rate securities market was highly liquid. Beginning mid-February 2008, we experienced several “failed” auctions, meaning that there was not enough demand to sell all of the securities that holders desired to sell at auction. The immediate effect of a failed auction was that such holders could not sell the securities at auction and the interest rate on the security reset to a maximum auction rate. We continued to receive interest payments on our ARPSs in accordance with their terms.

On January 19, 2011, we entered into an agreement with a financial institution to sell the ARPSs for $12.6 million, which represents 79% of the par value, plus accrued interest. Under the agreement, we retained the unilateral right for a period ending January 7, 2013 to: (a) repurchase all the ARPSs at the $12.6 million price at which they were initially sold to the financial institution; and (b) if not repurchased, receive additional proceeds from the financial institution upon redemption of the ARPSs by the original issuer.

Uses of Capital Resources

For the years ended December 31, 2010 and 2009, our primary uses of capital resources were property and equipment additions that consisted of the following (amounts in thousands):


	Years ended December 31,
	2010		2009
Drilling Services Division:
Routine	$	17,441	$	14,655
Discretionary		88,201		70,502
New-builds and acquisitions		—		12,046

Total Drilling Services Division		105,642		97,203
Production Services Division:
Routine		6,972		5,366
Discretionary		1,202		662
New-builds and acquisitions		17,187		11,481

Total Production Services Division		25,361		17,509

Net cash used for purchases of property and equipment		131,003		114,712
Net impact of accruals		4,148		(4,259	)

Total Capital Expenditures	$	135,151	$	110,453

We capitalized $0.5 million and $0.3 million of interest costs in property and equipment during the years ended December 31, 2010 and 2009, respectively.

Our Drilling Services Division performed significant upgrade projects on 24 drilling rigs during the year ended December 31, 2010, primarily in connection with obtaining new drilling contracts in unconventional plays and Colombia. These projects included the installation of 16 top drives, five iron roughnecks, two automatic catwalks and 11 walking/skidding systems. During the year ended December 31, 2009, we performed significant upgrade projects on seven drilling rigs, including the addition of 11 top drives to our drilling rigs. Also during the year ended December 31, 2009, we incurred $13.7 million of rig construction costs to complete construction of a 2000 horsepower drilling rig which was placed into service in June 2009.

Our Production Services Division acquired 20 and five wireline units, as well as auxiliary equipment for well service rigs, during the years ended December 31, 2010 and 2009, respectively, which is reflected in the new-builds and acquisitions section of the table above.

Currently, we expect to spend approximately $140 million to $150 million on capital expenditures during 2011. We expect the total capital expenditures for 2011 will be allocated approximately 75% for our Drilling Services Division and approximately 25% for our Production Services Division. Our planned capital expenditures for the year ending December 31, 2011 include 14 wireline units and six well service rigs that we expect will go into service during the first half of 2011 and two new-build drillings rigs. We will not begin construction of these new-build drilling rigs unless we have secured long-term contracts. Actual capital expenditures may vary depending on the level of new-build and other expansion opportunities that meet our strategic and return on capital criteria. We expect to fund these capital expenditures from operating cash flow in excess of our working capital and other normal cash flow requirements, and from borrowings under our Revolving Credit Facility, as necessary.

Working Capital

Our working capital was $76.1 million at December 31, 2010, compared to $90.3 million at December 31, 2009. Our current ratio, which we calculate by dividing our current assets by our current liabilities, was 2.0 at December 31, 2010 compared to 2.9 at December 31, 2009.

Our operations have historically generated cash flows sufficient to meet our requirements for debt service and normal capital expenditures. However, during periods when higher percentages of our drilling contracts are turnkey and footage contracts, our short-term working capital needs could increase.

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


	December 31, 2010		December 31, 2009		Change
Cash and cash equivalents	$	22,011	$	40,379	$	(18,368	)
Short-term investments		12,569		—		12,569
Receivables:
Trade, net of allowance for doubtful accounts		61,345		26,648		34,697
Unbilled receivables		21,423		8,586		12,837
Insurance recoveries		4,035		5,107		(1,072	)
Income taxes		2,712		41,126		(38,414	)
Deferred income taxes		9,867		5,560		4,307
Inventory		9,023		5,535		3,488
Prepaid expenses and other current assets		8,797		6,199		2,598

Current assets		151,782		139,140		12,642

Accounts payable		26,929		15,324		11,605
Current portion of long-term debt		1,408		4,041		(2,633	)
Prepaid drilling contracts		3,669		408		3,261
Accrued expenses:
Payroll and related employee costs		18,057		7,740		10,317
Insurance premiums and deductibles		8,774		8,615		159
Insurance claims and settlements		4,035		5,042		(1,007	)
Interest		7,307		271		7,036
Other		5,461		7,363		(1,902	)

Current liabilities		75,640		48,804		26,836

Working capital	$	76,142	$	90,336	$	(14,194	)

The decrease in cash and cash equivalents was primarily due to $131.0 million used for purchases of property and equipment, offset by cash provided by operations of $98.4 million and $12.7 million in proceeds from debt borrowings, net of debt repayments and issuance costs, during the year ended December 31, 2010.

Short-term investments as of December 31, 2010 represent our ARPS which were classified as available for sale as of December 31, 2010, and were liquidated in January 2011. At December 31, 2009, these investments were classified as long-term investments due to our inability to determine the recovery period for these investments at that time.

The increases in our trade receivables and unbilled receivables as of December 31, 2010 as compared to December 31, 2009 were due to the increase in revenues of $67.4 million, or 83%, for the quarter ended December 31, 2010 as compared to the quarter ended December 31, 2009, and due to the timing of the billing and collection cycles for long-term drilling contracts in Colombia.

Income taxes receivable as of December 31, 2009 primarily related to net operating losses recognized during 2009. We applied our net operating losses against taxable income that we recognized in prior years which resulted in a federal tax refund. Our income taxes receivable decreased at December 31, 2010, as we received a federal income tax refund of $40.6 million in April 2010 primarily related to the carry-back of our 2009 net operating losses.

The increase in deferred income taxes is due to the movement of our deferred tax assets related to net operating losses for our Colombian operations from long-term to current. We now expect to realize the deferred tax assets in the short-term due to the increase in our Colombian operations through 2010.

The increase in inventory at December 31, 2010 as compared to December 31, 2009 was primarily due to the expansion of our operations in Colombia, which accounted for $2.4 million of the increase, with the remaining increase primarily due to the expansion of our domestic wireline services operations during 2010. We maintain inventories of replacement parts and supplies for our drilling rigs operating in Colombia to ensure efficient operations in geographically remote areas. During 2010, we exported our seventh and eighth drilling rigs to Colombia and established an additional inventory level for these two additional rigs.

The increase in prepaid expenses and other current assets at December 31, 2010 as compared to December 31, 2009 is primarily due to an increase in deferred mobilization costs for four drilling rigs that began new long-term drilling contracts during the year ended December 31, 2010. These deferred mobilization costs are being amortized over the related contract terms.

The increase in accounts payable at December 31, 2010 as compared to December 31, 2009 is due to the overall increase in the demand for drilling, well services, wireline services and fishing and rental services during the quarter ended December 31, 2010 as compared to the quarter ended December 31, 2009. Our operating costs increased $37.1 million, or 65%, during the fourth quarter of 2010 as compared to the fourth quarter of 2009. In addition, our capital expenditures accruals increased for the quarter ended December 31, 2010 as compared to the quarter ended December 31, 2009, accounting for $4.1 million of the increase in accounts payable. Both the increase in the demand for our services and the increase in capital expenditures led to an increase in purchases from our vendors.

The current portion of long-term debt at December 31, 2010 relates to $1.4 million of debt payments under our subordinated notes payable and other debt that are due within the next year.

Prepaid drilling contracts represent amounts billed for mobilization revenues in excess of revenue recognized for certain drilling contracts. Mobilization billings, and costs incurred for the mobilization, are deferred and recognized over the term of the related drilling contracts. The increase in prepaid drilling contracts at December 31, 2010 as compared to December 31, 2009 is primarily due to an increase in deferred mobilization revenues for four of the drilling rigs in Colombia that began new long-term drilling contracts during the year ended December 31, 2010.

The increase in accrued payroll and related employee costs was primarily due to workforce additions and increased accruals for higher bonuses for 2010, both of which are a result of higher demand for our drilling and production services during the year ended December 31, 2010. Our employee count increased by approximately 850 people, or 50%, as of December 31, 2010, as compared to December 31, 2009.

Accrued interest at December 31, 2010 primarily relates to the outstanding debt balance for our Senior Notes, while accrued interest at December 31, 2009 primarily related to the outstanding debt balance under our Revolving Credit Facility. On March 11, 2010, we issued $250 million of Senior Notes with a coupon interest rate of 9.875%. The Senior Notes were sold with an original issue discount that will result in an effective yield to maturity of approximately 10.677%. The proceeds from the issuance of the Senior Notes were immediately used to make a payment of $234.8 million to reduce the outstanding debt balance under the Revolving Credit Facility.

The Revolving Credit Facility had an interest rate of 3.74% as of December 31, 2009 which was based on the LIBOR rate plus a per annum margin, with interest payments due monthly. The Senior Notes have a higher interest rate as compared to the Revolving Credit Facility, with interest payments due semi-annually, which resulted in an increase in accrued interest as of December 31, 2010.

Long-term Debt and Other Contractual Obligations

The following table includes all our contractual obligations at December 31, 2010 (amounts in thousands):


	Payments Due by Period
Contractual Obligations	Total		Less than 1 year		2-3 years		4-5 years		More than 5 years
Long-term debt	$	290,858	$	1,408	$	39,450	$	—	$	250,000
Interest on long-term debt		188,580		26,755		50,731		49,375		61,719
Purchase commitments		11,611		11,611		—		—		—
Operating leases		6,527		2,408		3,369		750		—
Restricted cash obligation		1,950		650		1,300		—		—

Total	$	499,526	$	42,832	$	94,850	$	50,125	$	311,719

Long-term debt consists of $37.8 million outstanding under our Revolving Credit Facility, $250 million face amount outstanding under our Senior Notes, $3.0 million outstanding under subordinated notes payable to certain employees that are former shareholders of previously acquired production services businesses, and other debt of $0.1 million. The $37.8 million outstanding under our Revolving Credit Facility is due at maturity on August 31, 2012. However, we may make principal payments to reduce the outstanding debt balance prior to maturity when cash and working capital is sufficient. The outstanding balance under our Senior Notes has a carrying value of $240.1 million, which represents the $250 million face value net of the $9.9 million of original issue discount, net of amortization. The discount is being amortized over the term of the Senior Notes based on the effective interest method. The Senior Notes will mature on March 15, 2018. Our subordinated notes payable have final maturity dates ranging from January 2011 to April 2013.

Interest payment obligations on our Revolving Credit Facility are estimated based on (1) the 4.77% interest rate that was in effect on February 4, 2011 and (2) the outstanding principal balance of $37.8 million at December 31, 2010 to be paid at maturity in August 2012. Interest payment obligations on our Senior Notes are calculated based on the coupon interest rate of 9.875% due semi-annually in arrears on March 15 and September 15 of each year, commencing on September 15, 2010, through maturity. Interest payment obligations on our subordinated notes payable are based on interest rates ranging from 5.4% to 14%, with either quarterly or annual payments of principal and interest through maturity.

Purchase obligations primarily relate to equipment upgrades and purchases of new equipment.

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

As of December 31, 2010, we had restricted cash in the amount of $2.0 million held in an escrow account to be used for future payments in connection with the acquisition of Competition. The former owner of Competition will receive annual installments of $0.7 million payable over the remaining three years from the escrow account.

Debt Requirements

The Revolving Credit Facility contains customary mandatory prepayments in respect of asset dispositions, debt incurrence and equity 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 $225 million borrowing capacity under the Revolving Credit Facility other than maintaining compliance with the covenants. At December 31, 2010, we were in compliance with our financial covenants. Our total consolidated leverage ratio was 2.7 to 1.0, our senior consolidated leverage ratio was 0.4 to 1.0 and our interest coverage ratio was 4.2 to 1.0.

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

•

A maximum total consolidated leverage ratio that cannot exceed:

•

5.00 to 1.00 as of the end of any fiscal quarter ending December 31, 2010 through June 30, 2011;

•

4.75 to 1.00 as of the end of the fiscal quarter ending September 30, 2011;

•

4.50 to 1.00 as of the end of the fiscal quarter ending December 31, 2011;

•

4.25 to 1.00 as of the end of the fiscal quarter ending March 31, 2012; and

•

4.00 to 1.00 as of the end of any fiscal quarter ending June 30, 2012 and thereafter.

•

A maximum senior consolidated leverage ratio, which excludes unsecured and subordinated debt, that cannot exceed:

•

4.50 to 1.00 as of the end of the fiscal quarter ending December 31, 2010;

•

4.25 to 1.00 as of the end of the fiscal quarter ending March 31, 2011;

•

4.00 to 1.00 as of the end of the fiscal quarter ending June 30, 2011;

•

3.75 to 1.00 as of the end of the fiscal quarter ending September 30, 2011;

•

3.50 to 1.00 as of the end of the fiscal quarter ending December 31, 2011;

•

3.25 to 1.00 as of the end of the fiscal quarter ending March 31, 2012; and

•

3.00 to 1.00 as of the end of any fiscal quarter ended June 30, 2012 and thereafter.

•

A minimum interest coverage ratio that cannot be less than:

•

2.00 to 1.00 as of the end of any fiscal quarter ending December 31, 2010 through December 31, 2011; and

•

3.00 to 1.00 as of the end of any fiscal quarter ending March 31, 2012 and thereafter.

•

If our senior consolidated leverage ratio is greater than 2.25 to 1.00 at the end of any fiscal quarter, a minimum asset coverage ratio that cannot be less than 1.00 to 1.00 for any fiscal quarter ending on or before December 31, 2011, and 1.10 to 1.00 for any fiscal quarter ending March 31, 2012 and thereafter (as provided in the Revolving Credit Facility). If our senior consolidated leverage ratio is greater than 2.25 to 1.00 and our asset coverage ratio is less than 1.00 to 1.00, then borrowings outstanding under the Revolving Credit Facility will be limited to the sum of 80% of eligible accounts receivable, 80% of the orderly liquidation value of eligible equipment and 40% of the net book value of certain other fixed assets.

The Revolving Credit Facility restricts capital expenditures unless (a) after giving effect to such capital expenditure, no event of default would exist under the Revolving Credit Facility and availability under the Revolving Credit Facility would be equal to or greater than $25 million and (b) if the senior consolidated leverage ratio as of the last day of the most recent reported fiscal quarter was equal to or greater than 2.50 to 1.00, such capital expenditure would not cause the sum of all capital expenditures to exceed:

•

$65 million for fiscal year 2010; and

•

$80 million for each fiscal year thereafter.

The capital expenditure thresholds for each period noted above may be increased by:

•

the first $25 million of any aggregate equity issuance proceeds received during such period and 25% of any equity issuance proceeds received in excess of $25 million during such period; and

•

25% of any debt incurrence proceeds received during such period.

In addition, any unused portion of the capital expenditure threshold up to $30 million can be carried over from the immediate preceding fiscal year.

At December 31, 2010, our senior consolidated leverage ratio was not greater than 2.50 to 1.00 and, therefore, we were not subject to the capital expenditure threshold restrictions listed above.

The Revolving Credit Facility has additional restrictive covenants that, among other things, limit the incurrence of additional debt, investments, liens, dividends, acquisitions, redemptions of capital stock, prepayments of indebtedness, asset dispositions, mergers and consolidations, transactions with affiliates, hedging contracts, sale leasebacks and other matters customarily restricted in such agreements. In addition, the Revolving Credit Facility contains customary events of default, including without limitation, payment defaults, breaches of representations and warranties, covenant defaults, cross-defaults to certain other material indebtedness in excess of specified amounts, certain events of bankruptcy and insolvency, judgment defaults in excess of specified amounts, failure of any guaranty or security document supporting the credit agreement and change of control.

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.

In addition to the financial covenants under our Revolving Credit Facility, the Indenture Agreement for our Senior Notes contains certain restrictions on our ability to:

•

pay dividends on stock;

•

repurchase stock or redeem subordinated debt or make other restricted payments;

•

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

•

create liens on our assets;

•

enter into sale and leaseback transactions;

•

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 another person;

•

enter into transactions with affiliates; and

•

enter into new lines of business.

These covenants are subject to important exceptions and qualifications.

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

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

Our Senior Notes are not subject to any sinking fund requirements. As of December 31, 2010, there were no restrictions on the ability of subsidiary guarantors to transfer funds to the parent company, and we were in compliance with all covenants pertaining to our Senior Notes.

Critical Accounting Policies and Estimates

Revenue and cost recognition—Our Drilling Services Division earns revenues by drilling oil and gas wells for our customers under daywork, turnkey or footage contracts, which usually provide for the drilling of a single well. 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. Individual contracts are usually completed in less than 60 days. 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.

Our management has determined that it is appropriate to use the percentage-of-completion method, as defined in the Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) Topic 605, Revenue Recognition, 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 customer and the possibility of litigation.

If a customer 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.

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 asset “unbilled receivables” represents revenues we have recognized in excess of amounts billed on drilling contracts and production services completed but not yet invoiced. 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 “prepaid drilling contracts” 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 December 31, 2010 we had $6.3 million of deferred mobilization revenues, of which the current portion was $3.7 million. The related deferred mobilization costs were $5.8 million, of which the current portion was $3.3 million. Our deferred mobilization costs and revenues primarily related to long-term contracts for our Colombian operations, which are being amortized through the year ending December 31, 2012. Amortization of deferred mobilization revenues was $3.0 million for the year ended December 31, 2010.

Our Production Services Division earns revenues for well services, wireline services and fishing and rental services pursuant to master services agreements based on purchase orders, contracts or other persuasive evidence of an arrangement with the customer that include fixed or determinable prices. Production service revenue is recognized when the service has been rendered and collectability is reasonably assured.

Long-lived Assets and Intangible Assets—We evaluate for potential impairment of long-lived assets and intangible assets subject to amortization when indicators of impairment are present, as defined in ASC Topic 360, Property, Plant, and Equipment and ASC Topic 350, Intangibles—Goodwill and Other. 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 for drilling rigs and well service rigs. In performing the impairment evaluation, we estimate the future undiscounted net cash flows relating to long-lived assets and intangible assets grouped at the lowest level that cash flows can be identified. For our Production Services Division, our long-lived assets and intangible assets are grouped at the reporting unit level which is one level below the operating segment level. For our Drilling Services Division, 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 long-lived assets and intangible assets for these asset grouping levels, then we would recognize an impairment charge. 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 and intangible assets are inherently uncertain and require management judgment.

intangible assets in each reporting unit at December 31, 2008. Our long-lived asset and intangible asset impairment analysis for the reporting units in our Production Services Division resulted in no impairment charge to property and equipment and a non-cash impairment charge of $52.8 million to the carrying value of our intangible assets for customers relationships for the year ended December 31, 2008. This impairment charge did not have an impact on our liquidity or debt covenants; however, it was a reflection of the overall downturn in our industry and decline in our projected cash flows. We did not record an impairment charge on any long-lived assets for our Production Services Division for the years ended December 31, 2010 or 2009. For our Drilling Services Division, we did not record an impairment charge on any long-lived assets for the years ended December 31, 2010, 2009 or 2008.

Goodwill—Goodwill results from business acquisitions and represents the excess of acquisition costs over the fair value of the net assets acquired. We account for goodwill and other intangible assets under the provisions of ASC Topic 350. Goodwill is tested for impairment 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. These circumstances could lead to our net book value exceeding our market capitalization which is another indicator of a potential impairment in goodwill. ASC Topic 350 requires a two-step process for testing impairment. First, the fair value of each reporting unit 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. Goodwill of $118.6 million was initially recorded in connection with the acquisitions of the production services businesses from WEDGE, Competition, Pettus and Paltec, all of which occurred between March 1, 2008 and October 1, 2008, and was allocated to the three reporting units for our Production Services Division which are well services, wireline services and fishing and rental services. We recorded a full impairment of this goodwill during the year ended December 31, 2008 as further described below.

When estimating fair values of a reporting unit for our goodwill impairment test, we use a combination of an income approach and a market approach which incorporates both management’s views and those of the market. The income approach provides an estimated fair value based on each reporting unit’s anticipated cash flows that were discounted using a weighted average cost of capital rate. The market approach provides an estimated fair value based on our market capitalization that was computed using the prior 30-day average market price of our common stock and the number of shares outstanding as of the impairment test date. The estimated fair values computed using the income approach and the market approach were then equally weighted and combined into a single fair value. The primary assumptions used in the income approach were estimated cash flows and weighted average cost of capital. Estimated cash flows were primarily based on projected revenues, operating costs and capital expenditures and are discounted based on comparable industry average rates for weighted average cost of capital. We utilized discount rates based on weighted average cost of capital ranging from 15.8% to 16.7% when we estimated fair values of our reporting units as of December 31, 2008. The primary assumptions used in the market approach were the allocation of total market capitalization to each reporting unit, which was based on projected EBITDA percentages for each reporting unit, and control premiums, which were based on comparable industry averages. We utilized a 30% control premium when we estimated fair values of our reporting units as of December 31, 2008. To ensure the reasonableness of the estimated fair values of our reporting units, we performed a reconciliation of our total market capitalization to the total estimated fair value of all our reporting units. The assumptions used in estimating fair values of reporting units and performing the goodwill impairment test are inherently uncertain and required management judgment.

time period. We concluded that the decline in the market price of our common stock resulted from a significant adverse change in the economic and business climate as financial markets reacted to the credit crisis facing major lending institutions and worsening conditions in the overall economy during the fourth quarter of the year ended December 31, 2008. During the same time, there were significant declines in oil and natural gas prices which led to declines in production service revenues, margins and cash flows. We considered the impact of these significant adverse changes in the economic and business climate as we performed our annual impairment assessment of goodwill as of December 31, 2008. The estimated fair values of our reporting units were negatively impacted by significant reductions in estimated cash flows for the income approach component and a significant reduction in our market capitalization for the market approach component of our fair value estimation process. Our goodwill was initially recorded in connection with the acquisitions of the production services businesses from WEDGE, Competition, Pettus and Paltec, all of which occurred between March 1, 2008 and October 1, 2008, when production service revenues, margins and cash flows and our market capitalization were at historically high levels.

Our goodwill impairment analysis led us to conclude that there would be no remaining implied fair value attributable to our goodwill and, accordingly, we recorded a non-cash charge of $118.6 million to our operating results for the year ended December 31, 2008, for the full impairment of our goodwill. Our goodwill impairment analysis would have led to the same full impairment conclusion if we increased or decreased our discount rates or control premiums by 10% when estimating the fair values of our reporting units. This impairment charge did not have an impact on our liquidity or debt covenants; however, it was a reflection of the overall downturn in our industry and decline in our projected cash flows.

We had no goodwill additions during the years ended December 31, 2010 or 2009, and consequently, have no goodwill reflected on our consolidated balance sheets at December 31, 2010 and 2009.

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 service rigs and wireline 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 service rigs and wireline units over 5 years. Therefore, in the first 5 years of our ownership of a drilling rig, well service rig or wireline 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—We consider the recognition of revenues and costs on turnkey and footage contracts to be critical accounting estimates. On these types of contracts, we are required to estimate the number of days needed for us to complete the contract and our total cost to complete the contract. 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 receive payment under turnkey and footage contracts when we deliver to our customer a well completed to the depth specified in the contract, unless the customer authorizes us to drill to a more shallow depth. Since 1995, we have completed all our turnkey or footage contracts. Although 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, 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. 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. During the year ended December 31, 2010, we experienced a loss of $0.2 million on one turnkey contract. During the year ended December 31, 2009, we did not experience a loss on any turnkey or footage contracts completed. 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. During periods of reduced demand for drilling rigs, our overall profitability on turnkey and footage contracts has historically exceeded our profitability on daywork contracts.

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. We had one turnkey and no footage contracts in progress at December 31, 2010. The turnkey contract was completed prior to the release of the financial statements included in this report. Our unbilled receivables totaled $21.4 million at December 31, 2010. Of that amount accrued, turnkey drilling contract revenues were $1.3 million. The remaining balance of unbilled receivables related to $18.7 million of the revenue recognized but not yet billed on daywork drilling contracts in progress at December 31, 2010 and $1.4 million related to unbilled receivables for our Production Services Division.

We estimate an allowance for doubtful accounts based on the creditworthiness of our customers as well as general economic conditions. We evaluate the creditworthiness of our customers based on commercial credit reports, trade references, bank references, financial information, production information and any past experience we have with the customer. Consequently, any change in those factors could affect our estimate of our allowance for doubtful accounts. In some instances, we require new customers to establish escrow accounts or make prepayments. We typically invoice our customers at 15-day intervals during the performance of daywork contracts and upon completion of the daywork contract. Turnkey and footage contracts are invoiced upon completion of the contract. Our typical contract provides for payment of invoices in 10 to 30 days. We generally do not extend payment terms beyond 30 days and have not extended payment terms beyond 90 days for any of our contracts in the last three fiscal years. We had an allowance for doubtful accounts of $0.7 million at December 31, 2010 and $0.3 million at December 31, 2009.

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 service rig or wireline 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 35 years of experience in the oilfield services industry with similar equipment.

As of December 31, 2010, we had a $1.2 million deferred tax asset related to the $3.3 million impairment of our ARPSs which will represent a capital loss for tax treatment purposes. We can recognize a tax benefit associated with this impairment to the extent of capital gains we expect to earn in future periods. We recorded a valuation allowance to fully offset our deferred tax asset relating to this capital loss since we believe capital gains are not likely in future periods.

As of December 31, 2010, we had $27.3 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 December 31, 2010 include accruals for costs incurred under the self-insurance portion of our health insurance of approximately $1.5 million and our workers’ compensation, general liability and auto liability insurance of approximately $6.6 million. As of January 1, 2011, we have a deductible of $150,000 per covered individual per year under the health insurance, up from $125,000 during 2010. We have a deductible of $500,000 per occurrence under our workers’ compensation insurance. We have deductibles of $250,000 and $100,000 per occurrence under our general liability insurance and auto liability insurance, respectively. We accrue for these costs as claims are incurred based on historical claim development data, and we accrue the costs of administrative services associated with claims processing. We also evaluate our workers’ compensation claim cost estimates based on estimates provided by a professional actuary.

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. As of December 31, 2010, we estimated that our actual achievement level will be 80% of the predetermined performance conditions. The final amount will be determinable in the first quarter of 2011.

Results of Operations

Effective March 1, 2008, we acquired the production services businesses of WEDGE and Competition which provide well services, wireline services and fishing and rental services. These acquisitions resulted in the formation of our new operating segment, the Production Services Division. We consolidated the results of these acquisitions from the day they were acquired. These acquisitions affect the comparability from period to period of our historical results, and our historical results may not be indicative of our future results.

Statements of Operations Analysis—Year Ended December 31, 2010 Compared with the Year Ended December 31, 2009

The following table provides information about our operations for the years ended December 31, 2010 and December 31, 2009 (amounts in thousands, except average number of drilling rigs, utilization rate and revenue day information).


	Years ended December 31,
	2010			2009
Drilling Services Division:
Revenues	$	312,196		$	219,751
Operating costs		227,136			147,343

Drilling Services Division margin	$	85,060		$	72,408

Average number of drilling rigs		71.0			70.7
Utilization rate		59	%		41	%
Revenue days		15,182			10,491

Average revenues per day	$	20,564		$	20,947
Average operating costs per day		14,961			14,045

Drilling Services Division margin per day	$	5,603		$	6,902

Production Services Division:
Revenues	$	175,014		$	105,786
Operating costs		105,295			68,012

Production Services Division margin	$	69,719		$	37,774

Combined:
Revenues	$	487,210		$	325,537
Operating costs		332,431			215,355

Combined margin	$	154,779		$	110,182

Adjusted EBITDA	$	103,151		$	74,942

We present Drilling Services Division margin, Production Services Division margin, combined margin and earnings before interest, taxes, depreciation, amortization and impairments (Adjusted EBITDA) information because we believe it provides investors and our management additional information to assist them in assessing our business and performance in comparison to other companies in our industry. Since Drilling Services Division margin, Production Services Division margin, combined margin and Adjusted EBITDA are “non-GAAP” financial measures under the rules and regulations of the SEC, we are providing the following reconciliation of combined margin and Adjusted EBITDA to net loss, which is the nearest comparable GAAP financial measure.


	Year ended December 31,
	2010			2009
	(amounts in thousands)
Reconciliation of combined margin and
Adjusted EBITDA to net loss:
Combined margin	$	154,779		$	110,182
General and administrative		(52,047	)		(37,478	)
Bad debt recovery (expense)		(493	)		1,642
Other income		912			596

Adjusted EBITDA		103,151			74,942
Depreciation and amortization		(120,811	)		(106,186	)
Interest income (expense), net		(26,567	)		(8,928	)
Impairment of investments		(3,331	)		—
Income tax benefit		14,297			16,957

Net loss	$	(33,261	)	$	(23,215	)

Our Drilling Services Division’s revenues increased by $92.4 million, or 42%, for the year ended December 31, 2010, as compared to the year ended December 31, 2009, due to a 45% increase in revenue days that resulted from an increase in our rig utilization rate to 59% from 41%. We have experienced an increase in the demand for drilling services in 2010 as our industry begins to recover from the downturn that bottomed in late 2009. Consequently, utilization rates and drilling revenue rates have improved in 2010 as compared to 2009. However, when compared to 2009, our Drilling Services Division’s average revenues decreased by $383 per day, or 2%. During 2009, a significant portion of our drilling rigs were still operating or were on standby under long-term drilling contracts that were entered into when drilling rig demand was high and drilling revenues per day were at historically high levels. The positive impact of the higher revenue rates for these long-term contracts had a diminishing affect on our average revenues per day as the contracts expired ratably during 2009. In addition, a larger percentage of our Drilling Services Division’s revenues were attributed to turnkey drilling contracts in 2009 when compared to 2010, and turnkey drilling contracts result in higher average revenues per day than daywork drilling contracts. The overall decreases in our average drilling revenues per day during 2010 as compared to 2009 was partially offset by an increase in our Colombian operations during 2010, as drilling contracts in Colombia have higher revenue rates per day when compared to domestic drilling contracts.

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 improve our Drilling Services Division’s margins. Turnkey drilling contracts also result in higher average revenues per day and higher average operating costs per day when compared to daywork drilling contracts. We completed 11 turnkey drilling contracts during 2010, as compared to 14 turnkey drilling contracts completed during 2009. The shift to fewer turnkey drilling contracts is due to the increase in the demand for drilling services in 2010. The following table provides percentages of our drilling revenues by drilling contract type for the years ended December 31, 2010 and 2009:


	Years ended December 31,
	2010			2009
Daywork Contracts		95	%		90	%
Turnkey Contracts		5	%		10	%
Footage Contracts		—			—

Our Drilling Services Division’s operating costs increased $79.8 million, or 54%, for the year ended December 31, 2010, as compared to the corresponding period in 2009, primarily due to the increase in utilization and the increase in our operating costs of $916 per day, or 7%. The increase in operating costs per day is due to higher average drilling costs per day for our domestic operations, as well as the increase in our Colombian operations during 2010 as compared to the corresponding period in 2009, where we have a higher operating cost per day as compared to our domestic operations. We have seen an increase in the demand for our services during 2010 as our industry begins to recover from the downturn that bottomed in late 2009. As utilization rates began to increase in 2010, average operating costs per day increased due to higher wage rates and repair and maintenance expenses as drilling rigs come out of storage and begin operations. In addition, average operating costs per day in 2009 were lower due to a significant portion of our drilling rigs earning standby revenue rates under longer-term drilling contracts and incurring reduced operating costs. The overall increase in operating costs per day in 2010 was partially offset by a decrease in operating costs per day due to a smaller proportion of our drilling services attributable to turnkey contracts during the year ended December 31, 2010 as compared to the corresponding period in 2009.

Our Production Services Division’s revenues increased by $69.2 million, or 65%, while operating costs increased by $37.3 million, or 55%, for the year ended December 31, 2010, as compared to the corresponding period in 2009. Our Production Services Division experienced increases in its revenue and operating cost due to higher demand for our wireline services, well services and fishing and rental services during 2010 as compared to 2009. The increase in our Production Services Division’s revenues is due primarily to higher utilization rates, especially in the wireline and well services operations, and to a lesser extent, higher revenue rates charged for these services during 2010, as compared to the corresponding period in 2009. We have also expanded our operations in 2010 by adding 21 wireline units resulting in an increase in both revenues and operating costs.

Our general and administrative expense increased by approximately $14.6 million, or 39%, for the year ended December 31, 2010 as compared to the corresponding period in 2009. The increase is primarily due to increases in compensation related expenses. With the industry downturn during 2009, we experienced a decrease in the demand for our services and we responded with workforce reductions, elimination of wage rate increases and reduced bonus compensation. During 2010, we have seen an increase in the demand for our services as our industry begins to recover from the industry downturn in 2009. Compensation related expenses increased during 2010 as we have added employees in our corporate office and have accrued for higher bonuses for 2010.

Bad debt recovery decreased for the year ended December 31, 2010 as compared to the corresponding period in 2009, primarily due to the collection of a customer’s past due account receivable balance in 2009 for which we had previously established a $1.3 million allowance for doubtful accounts in December 2008.

Our other income increased by $0.3 million for the year ended December 31, 2010 as compared to the corresponding period in 2009, primarily due to the increase in foreign currency translation gains in excess of losses recognized in relation to our operations in Colombia.

Our depreciation and amortization expenses increased by $14.6 million for the year ended December 31, 2010, as compared to the corresponding period in 2009. This increase resulted primarily from capital expenditures made to upgrade certain drilling rigs to meet the needs of our customers and obtain new contracts as well as capital expenditures for the acquisition of new wireline units.

Interest expense for the year ended December 31, 2010 primarily related to the outstanding debt balance for our Senior Notes, while interest expense for the year ended December 31, 2009 primarily related to the outstanding debt balance under our Revolving Credit Facility. On March 11, 2010, we issued $250 million of Senior Notes with a coupon interest rate of 9.875%. The Senior Notes were sold with an original issue discount that will result in an effective yield to maturity of approximately 10.677%. The proceeds from the issuance of the Senior Notes were immediately used to make a payment of $234.8 million to reduce the outstanding debt balance under the Revolving Credit Facility. The Revolving Credit Facility had a relatively low interest rate of 3.74% as of December 31, 2009, which was based on the LIBOR rate plus a per annum margin. The Senior Notes have a higher interest rate when compared to the Revolving Credit Facility, which resulted in the increase in interest expense during 2010. In addition, interest expense increased in 2010 as compared to 2009 due to an increase in total outstanding debt which was $280.9 million as of December 31, 2010 as compared to $262.1 million as of December 31, 2009.

Our effective income tax rate for the year ended December 31, 2010 differs from the federal statutory rate in the United States of 35% primarily due to a lower effective tax rate in foreign jurisdictions, state income taxes, valuation allowances and other permanent differences.

Statements of Operations Analysis—Year Ended December 31, 2009 Compared with the Year Ended December 31, 2008

The following table provides information about our operations for the years ended December 31, 2009 and 2008 (amounts in thousands, except average number of drilling rigs, utilization rate and revenue day information). Our Production Services Division was created on March 1, 2008, when we acquired the production services businesses from WEDGE and Competition.


	Years ended December 31,
	2009			2008
Drilling Services Division:
Revenues	$	219,751		$	456,890
Operating costs		147,343			269,846

Drilling Services Division margin	$	72,408		$	187,044

Average number of drilling rigs		70.7			67.4
Utilization rate		41	%		89	%
Revenue days		10,491			22,057
Average revenues per day	$	20,947		$	20,714
Average operating costs per day		14,045			12,234

Drilling Services Division margin per day	$	6,902		$	8,480

Production Services Division:
Revenues	$	105,786		$	153,994
Operating costs		68,012			80,097

Production Services Division margin	$	37,774		$	73,897

Combined:
Revenues	$	325,537		$	610,884
Operating costs		215,355			349,943

Combined margin	$	110,182		$	260,941

Adjusted EBITDA	$	74,942		$	214,766

We present drilling margin and earnings before interest, taxes, depreciation and amortization (Adjusted EBITDA) information because we believe it provides investors and our management additional information to assist them in assessing our business and performance in comparison to other companies in our industry. Since drilling margin and Adjusted EBITDA are “non-GAAP” financial measures under the rules and regulations of the SEC, we are providing the following reconciliation of drilling margin and Adjusted EBITDA to net earnings, which is the nearest comparable GAAP financial measure.


	Years ended December 31,
	2009			2008
	(amounts in thousands)
Reconciliation of combined margin and
Adjusted EBITDA to net loss:
Combined margin	$	110,182		$	260,941
General and administrative		(37,478	)		(44,834	)
Bad debt recovery (expense)		1,642			(423	)
Other income (expense)		596			(918	)

Adjusted EBITDA		74,942			214,766
Depreciation and amortization		(106,186	)		(88,145	)
Impairment of goodwill		—			(118,646	)
Impairment of intangible assets		—			(52,847	)
Interest expense, net		(8,928	)		(11,816	)
Income tax expense		16,957			(6,057	)

Net loss	$	(23,215	)	$	(62,745	)

Our Drilling Services Division’s revenues decreased by $237.1 million, or 52%, for the year ended December 31, 2009 as compared to the corresponding period in 2008, due to a 52% decrease in revenue days that resulted from a decline in our rig utilization rate from 89% to 41%. In contrast to the decrease in our Drilling Services Division’s revenues, our average contract drilling revenues per day increased by $233, or 1%. This increase in average drilling revenues per day is attributable to higher average drilling revenues per day for our Colombian operations which represented a larger portion of our drilling revenues for 2009 as compared to 2008. Our average drilling revenues per day for our domestic operations decreased by 8% for the year ended December 31, 2009, since the demand for drilling rigs decreased during 2009 as compared to 2008. The decrease in our average drilling revenues per day for our domestic operations is less than expected because a significant portion of our domestic drilling rigs were operating or were on standby under longer-term drilling contracts that were entered into when drilling rig demand was high and revenues per day were at historically high levels.

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 improve our Drilling Services Division’s margins. We completed 14 turnkey drilling contracts during the year ended December 31, 2009 as compared to ten turnkey drilling contracts completed during the year ended December 31, 2008. The following table provides percentages of our drilling revenues by drilling contract type for the years ended December 31, 2009 and 2008:


	Years ended December 31,
	2009			2008
Daywork Contracts		90	%		93	%
Turnkey Contracts		10	%		2	%
Footage Contracts		—			5	%

Our Drilling Services Division’s operating costs declined by $122.5 million, or 45%, for the year ended December 31, 2009 as compared to the corresponding period in 2008, primarily due to a 52% decrease in revenue days that resulted from a decline in our rig utilization rate from 89% to 41%. In contrast to the decrease in our Drilling Services Division’s operating costs, our average operating costs per day increased by $1,811, or 15%, primarily due to higher average drilling costs per day for our Colombian operations which represented a larger portion of our drilling costs for 2009 as compared to 2008. In addition, average operating costs per day increased due to a shift to more turnkey contracts and fixed overhead costs associated with division offices, supervisory level employees, insurance and property taxes. Since we had a significant decrease in revenue days, these fixed overhead costs result in an increase in average operating costs per revenue day.

For the year ended December 31, 2009, our Production Services Division’s revenue decreased by $48.2 million, or 31%, while operating costs decreased by $12.1 million, or 15%, as compared to the corresponding period in 2008. Our Production Services Division experienced decreases in its revenue and operating cost due to lower demand for well services, wireline services and fishing and rental services during the year ended December 31, 2009, as compared to the corresponding period in 2008. This decrease in revenues and operating costs that was due to lower demand was partially offset by the timing impact of the WEDGE and Competition acquisitions on March 1, 2008 which created our Production Services Division. A full year of Production Services Division operations are reflected in the operating results for the year ended December 31, 2009, as compared to ten months of operating results for the corresponding period in 2008.

Our general and administrative expense for the year ended December 31, 2009 decreased by approximately $7.4 million, or 16%, as compared to the corresponding period in 2008. Professional and consulting expenses decreased by $5.2 million and compensation related expenses decreased by $2.8 million for the year ended December 31, 2009, as compared to the corresponding period in 2008. We incurred professional and consulting expenses in 2008 related to an investigation conducted by the special committee of our Board of Directors and for the acquisitions of the production services businesses from WEDGE and Competition. The decrease in compensation related expenses is primarily due to decreases in bonus compensation and salary compensation related to workforce reductions in 2009 as compared to 2008. The overall decrease in general and administrative expense was partially offset by increases in insurance expenses and general and administrative expenses relating to our Production Services Division. As noted above, a full year of Production Services Division operations are reflected in the results of operations for the year ended December 31, 2009, as compared to ten months of operating results for the year ended December 31, 2008.

The bad debt recovery during the year ended December 31, 2009 was primarily due to the collection of a customer’s past due account receivable balance for which we had previously established a $1.3 million allowance for doubtful accounts in December 2008.

Our other income for the year ended December 31, 2009 increased by $1.5 million as compared to the corresponding period in 2008, primarily due to foreign currency translation gains and losses relating to our operations in Colombia. We recorded foreign currency translation losses of $0.1 million for the year ended December 31, 2009, and foreign currency translation losses of $1.4 million for the year ended December 31, 2008.

Our depreciation and amortization expenses for the year ended December 31, 2009 increased by $18.0 million, or 20%, as compared to the corresponding period in 2008. This increase resulted primarily from the increase in the fleet size of our drilling rigs, well service rigs and wireline units. The 2009 additions to each fleet consisted primarily of newly constructed equipment. The increase also related to additional depreciation and amortization expense for our new Production Services Division. As noted above, a full year of Production Services Division operations are reflected in the results of operations for the year ended December 31, 2009, as compared to ten months of operating results for the year ended December 31, 2008.

Our interest expense is primarily related to interest due on the amounts outstanding under our senior secured revolving credit facility. Our interest expense decreased $3.9 million for the year ended December 31, 2009, as compared to the corresponding period in 2008. This decrease is due to reductions in the amounts outstanding under our senior secured revolving credit facility and due to decreases in the LIBOR and bank prime base rates used to determine our effective borrowing rate per our senior secured revolving credit facility. Borrowings under the senior secured revolving credit facility were first used to fund the acquisitions of the production services businesses of WEDGE and Competition on March 1, 2008. Operating results for the year ended December 31, 2009 reflect a full year of interest expense as compared to ten months of interest expense for the year ended December 31, 2008.

Our effective income tax rate for the year ended December 31, 2009 differs from the federal statutory rate in the United States of 35% primarily due to pretax income recognized in foreign jurisdictions with a lower effective tax rate, the release of valuation allowance relating to foreign net operating loss carryforwards, state income taxes and other permanent differences.

Inflation

Wage rates for our operations personnel are impacted by inflationary pressures when the demand for drilling and production services increases and the availability of personnel is scarce. From early 2005 to late 2008, the increased rig count in each of our market areas resulted in increased wage rates for our drilling rig personnel. We were able to pass these wage rate increases on to our customers based on contract terms. Beginning in late 2008 and through late 2009, as the rig count in our market areas decreased, we reduced wage rates for drilling rig personnel. With the recent increase in rig counts, beginning in late 2009, we again saw a decreased availability of personnel to operate our rigs and therefore we had additional wage rate increases for drilling rig personnel of approximately 18% and 16% in February and July 2010, respectively.

During the fiscal years ended December 31, 2007 and 2008, we experienced increases in costs for rig repairs and maintenance and costs of rig upgrades and new rig construction, due to the increased industry-wide demand for equipment, supplies and service. We estimate these costs increased by 10% to 15% during the fiscal years ended December 31, 2007 and 2008. We did not experience similar cost increases during 2009; however, we have experienced an increase of approximately 5% during 2010.

Off-Balance Sheet Arrangements

We do not currently have any off-balance sheet arrangements.

Recently Issued Accounting Standards

Multiple Deliverable Revenue Arrangements. In October 2009, the FASB issued Accounting Standards Update (ASU) No. 2009-13, Revenue Recognition (Topic 605): Multiple Deliverable Revenue Arrangements – A Consensus of the FASB Emerging Issues Task Force. This update provides application guidance on whether multiple deliverables exist, how the deliverables should be separated and how the consideration should be allocated to one or more units of accounting. This update establishes a selling price hierarchy for determining the selling price of a deliverable. The selling price used for each deliverable will be based on vendor-specific objective evidence, if available, third-party evidence if vendor-specific objective evidence is not available, or estimated selling price if neither vendor-specific or third-party evidence is available. We will be required to apply this guidance prospectively for revenue arrangements entered into or materially modified after January 1, 2011; however, earlier application is permitted. We do not expect the adoption of this new guidance to have a material impact on our financial position or results of operations.

Business Combinations. In December 2010, the FASB issued Accounting Standards Update (ASU) No. 2010-29, Business Combinations (Topic 805): Disclosure of Supplementary Pro Forma Information for

Business Combinations—A consensus of the FASB Emerging Issues Task Force. This update provides clarification requiring public companies that have completed material acquisitions to disclose the revenue and earnings of the combined business as if the acquisition took place at the beginning of the comparable prior annual reporting period, and also expands the supplemental pro forma disclosures to include a description of the nature and amount of material, nonrecurring pro forma adjustments directly attributable to the business combination included in the reported pro forma revenue and earnings. We will be required to apply this guidance prospectively for business combinations for which the acquisition date is on or after January 1, 2011. We do not expect the adoption of this new guidance to have a material impact on our financial position or results of operations.

Recently Enacted Regulation

The Colombian government enacted a tax reform act which, among other things, adopted a one-time, net-worth tax for all Colombian entities. The tax is assessed on an entity’s net equity, measured on a Colombian tax basis as of January 1, 2011, and is payable in eight semi-annual installments from 2011 through 2014. Based on our Colombian operations’ net equity, as defined, we estimate that our total net-worth tax obligation is approximately $7.3 million, which is not deductible for tax purposes. In January 2011, the actual net-worth tax obligation will be recognized in full in other expense in our consolidated statement of operations and in other accrued expenses and other long-term liabilities on our consolidated balance sheet.

Item 7A. 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 December 31, 2010, we had $37.8 million outstanding under our Revolving Credit Facility subject to variable interest rate risk. The impact of a 1% increase in interest rates on this amount of debt would have resulted in increased interest expense of approximately $0.4 million and a decrease in net income of approximately $0.2 million during 2010.

At December 31, 2010, we held $15.9 million (par value) of investments comprised of tax exempt, auction rate preferred securities (ARPS), which were variable-rate preferred securities and had a long-term maturity with the interest rate being reset through “Dutch auctions” that were held every seven days. The ARPSs had historically traded at par because of the frequent interest rate resets and because they were callable at par at the option of the issuer. Interest was paid at the end of each auction period. Our ARPSs were AAA/Aaa rated securities, collateralized by municipal bonds and backed by assets that were equal to or greater than 200% of the liquidation preference. Until February 2008, the auction rate securities market was highly liquid. Beginning mid-February 2008, we experienced several “failed” auctions, meaning that there was not enough demand to sell all of the securities that holders desired to sell at auction. The immediate effect of a failed auction is that such holders could not sell the securities at auction and the interest rate on the security reset to a maximum auction rate. We continued to receive interest payments on our ARPSs in accordance with their terms.

On January 19, 2011, we entered into an agreement with a financial institution to sell the ARPSs for $12.6 million, which represents 79% of the par value, plus accrued interest. Under the agreement, we retained the unilateral right for a period ending January 7, 2013 to: (a) repurchase all the ARPSs that were sold at the $12.6 million price at which they were initially sold to the financial institution; and (b) if not repurchased, receive additional proceeds from the financial institution upon redemption of the ARPSs by the original issuer of these securities.

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 has and will continue to affect the reported amount of revenues, expenses, profit, and assets and liabilities in the Company’s consolidated financial statements.

The impact of currency rate changes on our Colombian Peso denominated transactions and balances resulted in foreign currency gains of $0.4 million for the year ended December 31, 2010.

Item 8.

Financial Statements and Supplementary Data

PIONEER DRILLING COMPANY

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS


	Page
Reports of Independent Registered Public Accounting Firm		62

Consolidated Balance Sheets as of December 31, 2010 and December 31, 2009		64

Consolidated Statements of Operations for the Years Ended December 31, 2010, 2009 and 2008		65

Consolidated Statements of Shareholders’ Equity and Comprehensive Income for the Years Ended December 31, 2010, 2009 and 2008		66

Consolidated Statements of Cash Flows for the Years Ended December 31, 2010, 2009 and 2008		67

Notes to Consolidated Financial Statements		68

Report of Independent Registered Public Accounting Firm

The Board of Directors and Shareholders

Pioneer Drilling Company:

We have audited the accompanying consolidated balance sheets of Pioneer Drilling Company and subsidiaries as of December 31, 2010 and 2009, and the related consolidated statements of operations, shareholders’ equity and comprehensive income, and cash flows for each of the years in the three-year period ended December 31, 2010. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Pioneer Drilling Company and subsidiaries as of December 31, 2010 and 2009, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2010, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Pioneer Drilling Company’s internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 17, 2011 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

/s/ KPMG LLP

San Antonio, Texas

February 17, 2011

Report of Independent Registered Public Accounting Firm

The Board of Directors and Shareholders

Pioneer Drilling Company:

We have audited Pioneer Drilling Company’s internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Pioneer Drilling Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, Pioneer Drilling Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Pioneer Drilling Company and subsidiaries as of December 31, 2010 and 2009, and the related consolidated statements of operations, shareholders’ equity and comprehensive income, and cash flows for each of the years in the three-year period ended December 31, 2010, and our report dated February 17, 2011 expressed an unqualified opinion on those consolidated financial statements.

/s/ KPMG LLP

San Antonio, Texas

February 17, 2011

PIONEER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEET


	December 31, 2010			December 31, 2009
	December 31, 2010			December 31, 2009
	(In thousands, except share data)
*ASSETS*
Current assets:
Cash and cash equivalents	$	22,011		$	40,379
Short-term investments		12,569			—
Receivables:
Trade, net of allowance for doubtful accounts		61,345			26,648
Unbilled receivables		21,423			8,586
Insurance recoveries		4,035			5,107
Income taxes		2,712			41,126
Deferred income taxes		9,867			5,560
Inventory		9,023			5,535
Prepaid expenses and other current assets		8,797			6,199

Total current assets		151,782			139,140

Property and equipment, at cost		1,097,179			967,893
Less accumulated depreciation		441,671			330,871

Net property and equipment		655,508			637,022
Intangible assets, net of amortization		21,966			25,393
Noncurrent deferred income taxes		—			2,339
Long-term investments		—			13,228
Other long-term assets		12,087			7,833

Total assets	$	841,343		$	824,955

*LIABILITIES AND SHAREHOLDERS’ EQUITY*
Current liabilities:
Accounts payable	$	26,929		$	15,324
Current portion of long-term debt		1,408			4,041
Prepaid drilling contracts		3,669			408
Accrued expenses:
Payroll and related employee costs		18,057			7,740
Insurance premiums and deductibles		8,774			8,615
Insurance claims and settlements		4,035			5,042
Interest		7,307			271
Other		5,461			7,363

Total current liabilities		75,640			48,804
Long-term debt, less current portion		279,530			258,073
Other long-term liabilities		9,680			6,457
Deferred income taxes		80,160			90,173

Total liabilities		445,010			403,507

Commitments and contingencies (Note 11)
Shareholders’ equity:
Preferred stock, 10,000,000 shares authorized; none issued and outstanding		—			—
Common stock $.10 par value; 100,000,000 shares authorized; 54,228,170 shares and 54,120,852 shares issued and outstanding at December 31, 2010 and December 31, 2009, respectively		5,425			5,413
Additional paid-in capital		339,105			332,534
Treasury stock, at cost; 25,380 and 5,174 shares at December 31, 2010 and
December 31, 2009, respectively		(161	)		(31	)
Accumulated earnings		51,964			85,225
Accumulated other comprehensive loss		—			(1,693	)

Total shareholders’ equity		396,333			421,448

Total liabilities and shareholders’ equity	$	841,343		$	824,955

See accompanying notes to consolidated financial statements.

PIONEER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS


	Years ended December 31,
	2010			2009			2008
	(In thousands, except per share data)
Revenues:
Drilling services	$	312,196		$	219,751		$	456,890
Production services		175,014			105,786			153,994

Total revenue		487,210			325,537			610,884

Costs and expenses:
Drilling services		227,136			147,343			269,846
Production services		105,295			68,012			80,097
Depreciation and amortization		120,811			106,186			88,145
General and administrative		52,047			37,478			44,834
Bad debt (recovery) expense		493			(1,642	)		423
Impairment of goodwill		—			—			118,646
Impairment of intangible assets		—			—			52,847

Total costs and expenses		505,782			357,377			654,838

Loss from operations		(18,572	)		(31,840	)		(43,954	)

Other income (expense):
Interest expense		(26,659	)		(9,145	)		(13,072	)
Interest income		92			217			1,256
Impairment of investments		(3,331	)		—			—
Other		912			596			(918	)

Total other expense		(28,986	)		(8,332	)		(12,734	)

Loss before income taxes		(47,558	)		(40,172	)		(56,688	)
Income tax benefit (expense)		14,297			16,957			(6,057	)

Net loss	$	(33,261	)	$	(23,215	)	$	(62,745	)

Loss per common share—Basic	$	(0.62	)	$	(0.46	)	$	(1.26	)

Loss per common share—Diluted	$	(0.62	)	$	(0.46	)	$	(1.26	)

Weighted average number of shares outstanding—Basic		53,797			50,313			49,789

Weighted average number of shares outstanding—Diluted		53,797			50,313			49,789

See accompanying notes to consolidated financial statements.

PIONEER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY AND COMPREHENSIVE INCOME


	Shares					Amount					Additional Paid In Capital			Accumulated Earnings			Accumulated Other Comprehensive Loss			Total Shareholders’ Equity
	Common		Treasury			Common		Treasury			Additional Paid In Capital			Accumulated Earnings			Accumulated Other Comprehensive Loss			Total Shareholders’ Equity
	(In thousands)
Balance as of December 31, 2007		49,651		—		$	4,965	$	—		$	294,922		$	171,185		$	—		$	471,072
Comprehensive loss:
Net loss		—		—			—		—			—			(62,745	)		—			(62,745	)
Unrealized loss on securities		—		—			—		—			—			—			(1,245	)		(1,245	)

Total comprehensive loss																					(63,990	)

Exercise of options and related income tax effect of $244		170		—			17		—			1,011			—			—			1,028
Issuance of restricted stock		177		—			18		—			(34	)		—			—			(16	)
Stock-based compensation expense		—		—			—		—			6,024			—			—			6,024

Balance as of December 31, 2008		49,998		—		$	5,000	$	—		$	301,923		$	108,440		$	(1,245	)	$	414,118
Comprehensive loss:
Net loss		—		—			—		—			—			(23,215	)		—			(23,215	)
Unrealized loss on securities		—		—			—		—			—			—			(448	)		(448	)

Total comprehensive loss																					(23,663	)

Sale of common stock, net of offering costs		3,820		—			382		—			23,661			—			—			24,043
Purchase of treasury stock		—		(5	)		—		(31	)		—			—			—			(31	)
Income tax effect of restricted stock vesting		—		—			—		—			(235	)		—			—			(235	)
Issuance of restricted stock		308		—			31		—			(31	)		—			—			—
Stock-based compensation expense		—		—			—		—			7,216			—			—			7,216

Balance as of December 31, 2009		54,126		(5	)	$	5,413	$	(31	)	$	332,534		$	85,225		$	(1,693	)	$	421,448
Comprehensive loss:
Net loss		—		—			—		—			—			(33,261	)		—			(33,261	)
Impact of impairment of investments charge		—		—			—		—			—			—			1,693			1,693

Total comprehensive loss																					(31,568	)

Exercise of options and related income tax effect of $16		63		—			6		—			248			—			—			254
Purchase of treasury stock		—		(20	)		—		(130	)		—			—			—			(130	)
Income tax effect of restricted stock vesting												(120	)								(120	)
Income tax effect of stock option forfeitures and expirations		—		—			—		—			(226	)		—			—			(226	)
Issuance of restricted stock		64		—			6		—			(6	)		—			—			—
Stock-based compensation expense		—		—			—		—			6,675			—			—			6,675

Balance as of December 31, 2010		54,253		(25	)	$	5,425	$	(161	)	$	339,105		$	51,964		$	—		$	396,333

See accompanying notes to consolidated financial statements.

PIONEER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS


	Years ended December 31,
	2010			2009			2008
	(In thousands)
Cash flows from operating activities:
Net loss	$	(33,261	)	$	(23,215	)	$	(62,745	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation and amortization		120,811			106,186			88,145
Allowance for doubtful accounts		521			(1,170	)		1,591
(Gain) loss on dispositions of property and equipment		(1,629	)		56			(805	)
Stock-based compensation expense		6,675			7,216			4,597
Amortization of debt issuance costs and discount		2,609			1,547			553
Impairment of investments		3,331			—			—
Impairment of goodwill and intangibles assets		—			—			171,493
Deferred income taxes		(13,224	)		28,400			(2,066	)
Change in other long-term assets		(1,373	)		69			(288	)
Change in non-current liabilities		3,223			(1,312	)		(621	)
Changes in current assets and liabilities:
Receivables		(9,576	)		18,180			(24,867	)
Inventory		(3,487	)		(1,661	)		(927	)
Prepaid expenses & other current assets		(2,598	)		2,703			(2,390	)
Accounts payable		7,458			(2,243	)		(2,610	)
Income tax payable		—			—			409
Prepaid drilling contracts		3,261			(763	)		(762	)
Accrued expenses		15,610			(10,680	)		17,928

Net cash provided by operating activities		98,351			123,313			186,635

Cash flows from investing activities:
Acquisition of production services business of WEDGE		—			—			(313,621	)
Acquisition of production services business of Competition		—			—			(26,772	)
Acquisition of other production services businesses		(1,340	)		—			(9,301	)
Purchases of property and equipment		(131,003	)		(114,712	)		(147,455	)
Purchase of auction rate securities, net		—			—			(15,900	)
Proceeds from sale of property and equipment		2,331			767			4,008
Proceeds from insurance recoveries		531			36			3,426

Net cash used in investing activities		(129,481	)		(113,909	)		(505,615	)

Cash flows from financing activities:
Debt repayments		(256,856	)		(17,298	)		(87,767	)
Proceeds from issuance of debt		274,375			—			359,400
Debt issuance costs		(4,865	)		(2,560	)		(3,319	)
Proceeds from exercise of options		238			—			784
Proceeds from common stock, net of offering costs of $454		—			24,043			—
Purchase of treasury stock		(130	)		(31	)		—

Net cash provided by financing activities		12,762			4,154			269,098

Net (decrease) increase in cash and cash equivalents		(18,368	)		13,558			(49,882	)
Beginning cash and cash equivalents		40,379			26,821			76,703

Ending cash and cash equivalents	$	22,011		$	40,379		$	26,821

Supplementary disclosure:
Interest paid	$	17,529		$	7,917		$	12,468
Income tax (refunded) paid	$	(39,778	)	$	(8,889	)	$	11,767

See accompanying notes to consolidated financial statements.

PIONEER DRILLING COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.	Organization and Summary of Significant Accounting Policies

Business and Principles of Consolidation

Pioneer Drilling Company and subsidiaries provide drilling and production services to our customers in select oil and natural gas exploration and production regions in the United States and Colombia. Our Drilling Services Division provides contract land drilling services with its fleet of 71 drilling rigs in the following locations:


Drilling Division Locations	Rig Count
South Texas		19
East Texas		13
West Texas		3
North Dakota		9
North Texas		3
Utah		3
Oklahoma		6
Appalachia		7
Colombia		8

As of February 4, 2011, 48 drilling rigs are operating under drilling contracts. We have 17 drilling rigs that are idle and six drilling rigs have been placed in storage or “cold stacked” in our Oklahoma drilling division location due to low demand for drilling rigs in that region. We are actively marketing all our idle drilling rigs. During the second quarter of 2009, we established our Appalachia drilling division location and now have seven drilling rigs operating in the Marcellus Shale. In early 2011, we established our West Texas drilling division location with three drilling rigs that were previously included in our East Texas drilling division location. One of these rigs has begun drilling in the Permian Basin and we expect the remaining two rigs to begin operations in late February 2011. 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 customers. 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 Division provides a range of services to exploration and production companies, including well services, wireline services, and fishing and rental services. Our production services operations are managed through locations concentrated in the major United States onshore oil and gas producing regions in the Gulf Coast, Mid-Continent, Rocky Mountain and Appalachian states. As of February 4, 2011, we have a premium fleet of 75 well service rigs consisting of seventy 550 horsepower rigs, four 600 horsepower rigs and one 400 horsepower rig. All our well service rigs are currently operating or are being actively marketed, with January 2011 utilization of approximately 88%. We currently provide wireline services with a fleet of 86 wireline units and rental services with approximately $13.5 million of fishing and rental tools. We plan to add another five well service rigs and 12 wireline units to our production services fleet by mid-2011.

The accompanying consolidated financial statements include the accounts of Pioneer Drilling Company and our wholly owned subsidiaries. All intercompany balances and transactions have been eliminated in consolidation. The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America. In preparing the accompanying 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 estimate of the self-insurance portion of our health and workers’ compensation insurance, our estimate of asset impairments, our estimate of deferred taxes, our estimate of compensation related accruals and our determination of depreciation and amortization expense.

In preparing the accompanying consolidated financial statements, we have reviewed events that have occurred after December 31, 2010, through the filing of this Form 10-K, for inclusion as necessary.

Recently Issued Accounting Standards

Multiple Deliverable Revenue Arrangements. In October 2009, the FASB issued Accounting Standards Update (ASU) No. 2009-13, Revenue Recognition (Topic 605): Multiple Deliverable Revenue Arrangements—A Consensus of the FASB Emerging Issues Task Force. This update provides application guidance on whether multiple deliverables exist, how the deliverables should be separated and how the consideration should be allocated to one or more units of accounting. This update establishes a selling price hierarchy for determining the selling price of a deliverable. The selling price used for each deliverable will be based on vendor-specific objective evidence, if available, third-party evidence if vendor-specific objective evidence is not available, or estimated selling price if neither vendor-specific or third-party evidence is available. We will be required to apply this guidance prospectively for revenue arrangements entered into or materially modified after January 1, 2011; however, earlier application is permitted. We do not expect the adoption of this new guidance to have a material impact on our financial position or results of operations.

Business Combinations. In December 2010, the FASB issued Accounting Standards Update (ASU) No. 2010-29, Business Combinations (Topic 805): Disclosure of Supplementary Pro Forma Information for Business Combinations—A consensus of the FASB Emerging Issues Task Force. This update provides clarification requiring public companies that have completed material acquisitions to disclose the revenue and earnings of the combined business as if the acquisition took place at the beginning of the comparable prior annual reporting period, and also expands the supplemental pro forma disclosures to include a description of the nature and amount of material, nonrecurring pro forma adjustments directly attributable to the business combination included in the reported pro forma revenue and earnings. We will be required to apply this guidance prospectively for business combinations for which the acquisition date is on or after January 1, 2011. We do not expect the adoption of this new guidance to have a material impact on our financial position or results of operations.

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. Generally, our contracts provide for the drilling of a single well and typically permit the customer to terminate on short notice. However, we have entered into more longer-term drilling contracts during periods of high rig demand. In addition, we have entered into longer-term drilling contracts for our newly constructed rigs. Currently, we have 32 contracts with terms of six months to three years in duration. Of these 32 contracts, if not renewed at the end of their terms, 14 will expire by August 15, 2011, 11 will expire by February 15, 2012, one will expire by August 15, 2012 and six have a remaining term in excess of 18 months. We have one additional drilling rig under contract that we expect will begin operating in late February 2011 with a six month term.

Foreign Currencies

Our functional currency for our foreign subsidiary in Colombia is the U.S. dollar. 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. Gains and losses from remeasurement of foreign currency financial statements into U.S. dollars and from foreign currency transactions are included in other income or expense.

Revenue and Cost Recognition

Drilling Services—We earn revenues by drilling oil and natural gas wells for our customers under daywork, turnkey or footage contracts, which usually provide for the drilling of a single well. 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. With most drilling contracts, we receive payments contractually designated for the mobilization of rigs and other equipment. Payments received, and costs incurred for the mobilization services are deferred and recognized on a straight line basis over the related contract term. Costs incurred to relocate rigs and other drilling equipment to areas in which a contract has not been secured are expensed as incurred. Reimbursements that we receive for out-of-pocket expenses are recorded as revenue and the out-of-pocket expenses for which they relate are recorded as operating costs.

Our management has determined that it is appropriate to use the percentage-of-completion method, as defined in the Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) Topic 605, Revenue Recognition, 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 we 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 customer and the possibility of litigation.

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. We charge general and administrative expenses to expense as we incur them. Changes in job performance, job conditions and estimated profitability on uncompleted contracts may result in revisions to costs and income. When we encounter, during the course of our drilling operations, conditions unforeseen in the preparation of our original cost estimate, we immediately increase our cost estimate for the additional costs 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 immediately 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. We had one turnkey and no footage contracts in progress as of December 31, 2010.

Production Services—We earn revenues for well services, wireline services and fishing and rental services based on purchase orders, contracts or other persuasive evidence of an arrangement with the customer, such as master service agreements, that include fixed or determinable prices. These production services revenues are recognized when the services have 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 for production services completed but not yet invoiced. 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 “prepaid drilling contracts” 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 December 31, 2010 we had $6.3 million of deferred mobilization revenues, of which the current portion was $3.7 million. The related deferred mobilization costs were $5.8 million, of which the current portion was $3.3 million. Our deferred mobilization costs and revenues primarily related to long-term contracts for our Colombian operations, which are being amortized through the year ending December 31, 2012. Amortization of deferred mobilization revenues was $3.0 million for the year ended December 31, 2010.

Cash and Cash Equivalents

For purposes of the statements of cash flows, we consider all highly liquid debt instruments purchased with a maturity of three months or less to be cash equivalents. Cash equivalents consist of investments in corporate and government money market accounts. Cash equivalents at December 31, 2010 and 2009 were $5.7 million and $9.9 million, respectively.

Restricted Cash

As of December 31, 2010, we had restricted cash in the amount of $2.0 million held in an escrow account to be used for future payments in connection with the acquisition of Prairie Investors d/b/a Competition Wireline (“Competition”). The former owner of Competition will receive annual installments of $0.7 million payable over the remaining three years from the escrow account. Restricted cash of $0.7 million and $1.3 million is recorded in other current assets and other long-term assets, respectively. The associated obligation of $0.7 million and $1.3 million is recorded in accrued expenses and other long-term liabilities, respectively.

Trade Accounts Receivable

We record trade accounts receivable at the amount we invoice our customers. These accounts do not bear interest. The allowance for doubtful accounts is our best estimate of the amount of probable credit losses in our accounts receivable as of the balance sheet date. We determine the allowance based on the credit worthiness of our customers and general economic conditions. Consequently, an adverse change in those factors could affect our estimate of our allowance for doubtful accounts. We review our allowance for doubtful accounts on a monthly basis. Balances more than 90 days past due are reviewed individually for collectability. We charge off account balances against the allowance after we have exhausted all reasonable means of collection and determined that the potential for recovery is remote. We do not have any off-balance sheet credit exposure related to our customers.

The changes in our allowance for doubtful accounts consist of the following (amounts in thousands):


	Years ended December 31,
	2010			2009			2008
Balance at beginning of year	$	286		$	1,574		$	—
Increase (decrease) in allowance charged to expense		521			(1,170	)		1,591
Accounts charged against the allowance, net of recoveries		(95	)		(118	)		(17	)

Balance at end of year	$	712		$	286		$	1,574

Prepaid Expenses and Other Current Assets

Prepaid expenses and other current assets include items such as insurance, rent deposits and fees, and restricted cash. 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 deferred mobilization costs for certain drilling contracts that are recognized on a straight line basis over the contract term.

Investments

As of December 31, 2010, short-term investments represented tax exempt, auction rate preferred securities (“ARPS”) that were classified as available for sale. The ARPSs were liquidated subsequent to year end on January 19, 2011. As of December 31, 2009 and 2008, the ARPSs were classified as long-term investments because of our inability to determine the recovery period of these available for sale investments at those times.

On January 19, 2011, we entered into an agreement with a financial institution to sell the ARPSs for $12.6 million, which represents 79% of the par value, plus accrued interest. Under the agreement, we retained the unilateral right for a period ending January 7, 2013 to: (a) repurchase all the ARPSs that were sold at the $12.6 million price at which they were initially sold to the financial institution; and (b) if not repurchased, receive additional proceeds from the financial institution upon redemption of the ARPSs by the original issuer of these securities (collectively, the “ARPSs Call Option”). The ARPSs Call Option has an estimated fair value of $0.6 million which will be recognized in our consolidated financial statements in 2011.

Our ARPSs were reported at amounts that reflected our estimate of fair value. ASC Topic 820, Fair Value Measurements and Disclosures (“ASC Topic 820”), provides a hierarchal framework associated with the level of subjectivity used in measuring assets and liabilities at fair value:

•

To estimate the fair values of our ARPSs as of December 31, 2010, we used inputs defined by ASC Topic 820 as level 1 inputs which are quoted market prices in active markets for identical securities. We obtained a quoted market price and liquidated the ARPSs subsequent to year end on January 19, 2011 based on the terms of the settlement agreement noted above. Therefore, the sales price under the settlement agreement of $12.6 million represents the fair value of the ARPSs at December 31, 2010. The $3.3 million difference between the ARPSs’ par value of $15.9 million and the sales price of $12.6 million represents an other-than-temporary impairment of the ARPSs investment which is reflected as an impairment of investments in our consolidated statement of operations for the year ended December 31, 2010. During the years ended December 31, 2009 and 2008, $2.7 million of the difference between the par value and fair value of the ARPSs was considered temporary and was recorded as unrealized losses, net of tax, in accumulated other comprehensive income (loss) which is a component of shareholders’ equity.

•

To estimate the fair values of our ARPSs as of December 31, 2009 and 2008, we used inputs defined by ASC Topic 820 as level 3 inputs which are unobservable for the asset or liability and are developed

based on the best information available in the circumstances. We estimated the fair value of our ARPSs based on discounted cash flow models and secondary market comparisons of similar securities. Based on this methodology, the estimated fair value of our ARPSs was $13.2 million at December 31, 2009 and $13.9 million at December 31, 2008, as compared to the par value of $15.9 million at both December 31, 2009 and December 31, 2008. The differences between the ARPSs’ fair values and par values were due to the lack of liquidity which was considered to be temporary at that time. We believed we would ultimately recover the par value of the ARPSs without a loss, primarily due to the collateral securing the ARPSs and our estimate of the discounted cash flows that we expected to collect. Also, we did not intend to sell the ARPSs at a loss and we believed it was more-likely-than-not that we would not have to sell prior to recovery of the ARPSs’ par value based on our liquidity needs. Therefore, the fair value discounts of $2.7 million and $2.0 million at December 31, 2009 and 2008, respectively, were recorded as unrealized losses, net of tax, in accumulated other comprehensive income (loss) which was a component of shareholders’ equity. There were no portions of the fair value discounts attributable to credit losses.

Inventories

Inventories primarily consist of drilling rig replacement parts and supplies held for use by our Drilling Services Division’s operations in Colombia and supplies held for use by our Production Services Division’s operations. Inventories are valued at the lower of cost (first in, first out or actual) or market value.

Property and Equipment

Property and equipment are carried at cost less accumulated depreciation. Depreciation is provided for our assets over the estimated useful lives of the assets using the straight-line method. We record the same depreciation expense whether a rig is idle or working. We charge our expenses for maintenance and repairs to operating costs. We charge our expenses for renewals and betterments to the appropriate property and equipment accounts.

As of December 31, 2010, the estimated useful lives and costs of our asset classes are as follows:


	Lives	Cost
		(amounts in thousands)
Drilling rigs and equipment	3 - 25	$	846,443
Workover rigs and equipment	5 - 20		123,831
Wireline units and equipment	2 - 10		66,452
Fishing and rental tools equipment	7		13,515
Vehicles	3 - 10		34,177
Office equipment	3 - 5		5,162
Buildings and improvements	3 - 40		6,991
Land	—		608

		$	1,097,179

We recorded gains (losses) on disposition of our property and equipment in contract drilling costs of $1.6 million, ($0.1) million and $0.8 million for the years ended December 31, 2010, 2009 and 2008, respectively. During the years ended December 31, 2010, 2009 and 2008, we capitalized $0.5 million, $0.3 million and $0.3 million, respectively, of interest costs incurred during the construction periods of certain drilling equipment. We had no drilling rigs under construction at December 31, 2010.

We evaluate for potential impairment of long-lived assets and intangible assets subject to amortization when indicators of impairment are present, as defined in ASC Topic 360, Property, Plant, and Equipment (“ASC Topic

360”) and ASC Topic 350, Intangibles—Goodwill and Other (“ASC Topic 350”). 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 for drilling rigs and well service rigs. In performing an impairment evaluation, we estimate the future undiscounted net cash flows from the use and eventual disposition of long-lived assets and intangible assets grouped at the lowest level that cash flows can be identified. For our Production Services Division, our long-lived assets and intangible assets are grouped at the reporting unit level which is one level below the operating segment level. For our Drilling Services Division, 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 long-lived assets and intangible assets for these asset grouping levels, then we would recognize an impairment charge. The amount of an impairment charge would be measured as the difference between the carrying amount and the fair value of these assets. As described in the Intangible Asset section of Note 1, our long-lived asset and intangible asset impairment analysis for the reporting units in our Production Services Division resulted in no impairment charge to property and equipment and a non-cash impairment charge of $52.8 million to the carrying value of our intangible assets for customers relationships for the year ended December 31, 2008. This impairment charge did not have an impact on our liquidity or debt covenants; however, it was a reflection of the overall downturn in our industry and decline in our projected cash flows. We did not record an impairment charge on any long-lived assets for our Production Services Division for the years ended December 31, 2010 or 2009. For our Drilling Services Division, we did not record an impairment charge on any long-lived assets for the years ended December 31, 2010, 2009 or 2008. The assumptions used in the impairment evaluation for long-lived assets and intangible assets are inherently uncertain and require management judgment.

Goodwill

Goodwill results from business acquisitions and represents the excess of acquisition costs over the fair value of the net assets acquired. We account for goodwill and other intangible assets under the provisions of ASC Topic 350. Goodwill is tested for impairment 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. These circumstances could lead to our net book value exceeding our market capitalization which is another indicator of a potential impairment in goodwill. ASC Topic 350 requires a two-step process for testing impairment. First, the fair value of each reporting unit is compared to its carrying value to determine whether an indication of impairment exists. All our goodwill was related to our Production Services Division operating segment and was allocated to its three reporting units which are well services, wireline services and fishing and rental services. 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. Goodwill of $118.6 million was initially recorded in connection with the acquisitions of the production services businesses from WEDGE, Competition, Pettus and Paltec, all of which occurred between March 1, 2008 and October 1, 2008, and was allocated to the three reporting units for our Production Services Division which are well services, wireline services and fishing and rental services. We recorded a full impairment of this goodwill during the year ended December 31, 2008 as further described below.

estimated fair value based on our market capitalization that was computed using the prior 30-day average market price of our common stock and the number of shares outstanding as of the impairment test date. The estimated fair values computed using the income approach and the market approach were then equally weighted and combined into a single fair value. The primary assumptions used in the income approach were estimated cash flows and weighted average cost of capital. Estimated cash flows were primarily based on projected revenues, operating costs and capital expenditures and are discounted based on comparable industry average rates for weighted average cost of capital. We utilized discount rates based on weighted average cost of capital ranging from 15.8% to 16.7% when we estimated fair values of our reporting units as of December 31, 2008. The primary assumptions used in the market approach were the allocation of total market capitalization to each reporting unit, which was based on projected EBITDA percentages for each reporting unit, and control premiums, which were based on comparable industry averages. We utilized a 30% control premium when we estimated fair values of our reporting units as of December 31, 2008. To ensure the reasonableness of the estimated fair values of our reporting units, we performed a reconciliation of our total market capitalization to the total estimated fair value of all our reporting units. The assumptions used in estimating fair values of reporting units and performing the goodwill impairment test are inherently uncertain and required management judgment.

Our common stock price per share declined in market value from $13.30 at September 30, 2008, to $5.57 at December 31, 2008, which resulted in our net book value exceeding our market capitalization during most of that time period. We concluded that the decline in the market price of our common stock resulted from a significant adverse change in the economic and business climate as financial markets reacted to the credit crisis facing major lending institutions and worsening conditions in the overall economy during the fourth quarter of the year ended December 31, 2008. During the same time, there were significant declines in oil and natural gas prices which led to declines in production service revenues, margins and cash flows. We considered the impact of these significant adverse changes in the economic and business climate as we performed our annual impairment assessment of goodwill as of December 31, 2008. The estimated fair values of our reporting units were negatively impacted by significant reductions in estimated cash flows for the income approach component and a significant reduction in our market capitalization for the market approach component of our fair value estimation process. Our goodwill was initially recorded in connection with the acquisitions of the production services businesses from WEDGE, Competition, Pettus and Paltec, all of which occurred between March 1, 2008 and October 1, 2008, when production service revenues, margins and cash flows and our market capitalization were at historically high levels.

Changes in the carrying amount of goodwill by operating segment are as follows (amounts in thousands):


	Drilling Services Division		Production Services Division			Total
Goodwill balance at January 1, 2008	$	—	$	—		$	—
Goodwill relating to acquisitions		—		118,646			118,646
Impairment		—		(118,646	)		(118,646	)

Goodwill balance at December 31, 2008	$	—	$	—		$	—

We had no goodwill additions during the years ended December 31, 2010 or 2009, and consequently, have no goodwill reflected on our consolidated balance sheets at December 31, 2010 and 2009.

Intangible Assets

All our intangible assets are subject to amortization and consist of customers relationships, non-compete agreements and trade names. Essentially all of our intangible assets were recorded in connection with the acquisitions of the production services businesses from WEDGE, Competition, Pettus, Paltec and Tiger, all of which are described in Note 2. Intangible assets consist of the following components (amounts in thousands):


	December 31, 2010			December 31, 2009
Cost:
Customer Relationships	$	33,036		$	32,039
Non-compete		2,024			2,304
Trade marks		155			143
Accumulated amortization:
Customer Relationships		(11,462	)		(7,509	)
Non-compete		(1,787	)		(1,584	)

	$	21,966		$	25,393

We evaluate for potential impairment of long-lived assets and intangible assets subject to amortization when indicators of impairment are present, as defined in ASC Topic 360 and ASC Topic 350. 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 for drilling rigs and well service rigs. In performing the impairment evaluation, we estimate the future undiscounted net cash flows relating to long-lived assets and intangible assets grouped at the lowest level that cash flows can be identified. Our long-lived assets and intangible assets for our Production Services Division are grouped one level below the operating segment in the three reporting units which are well services, wireline services and fishing and rental services. If the sum of the estimated future undiscounted net cash flows is less than the carrying amount of the long-lived assets and intangible assets in each reporting unit, then we would recognize an impairment charge. 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 and intangible assets are inherently uncertain and require management judgment.

We performed an impairment analysis of our long-lived assets and intangible assets at December 31, 2008, due to significant adverse changes in the economic and business climate that resulted in decreases in estimated revenues, margins and cash flows. Essentially all our intangible assets were recorded in connection with the acquisitions of the production services businesses from WEDGE, Competition, Pettus and Paltec when revenues, margins and cash flows were at historically high levels in early 2008. We determined that the sum of the estimated future undiscounted net cash flows was less than the carrying amount of the long-lived assets and intangible assets in each reporting unit at December 31, 2008. Our impairment analysis resulted in a reduction to our intangible asset carrying value of customers relationships and a non-cash impairment charge of $52.8 million recorded to our operating results for the year ended December 31, 2008.

The cost of our customer relationships is amortized using the straight-line method over their respective estimated economic useful lives which range from seven to nine years. Amortization expense for our non-compete agreements are calculated using the straight-line method over the period of the agreements which range from one to seven years. Amortization expense was $4.6 million, $4.7 million and $8.4 million for the years ended December 31, 2010, 2009 and 2008, respectively. Amortization expense is estimated to be approximately $4.1 million for the year ending December 31, 2011, and $4.0 million for each of the years ending December 31, 2012, 2013, 2014 and 2015. These future amortization amounts are estimates and reflect the

impact of the $52.8 million impairment charge to intangible assets recorded in the year ended December 31, 2008. Actual amortization amounts may be different due to future acquisitions, impairments, changes in amortization periods, or other factors.

Other Long-Term Assets

Other long-term assets consist of our investment in ARPSs, restricted cash held in an escrow account, cash deposits related to the deductibles on our workers’ compensation insurance policies, the long-term portion of deferred mobilization costs and loan fees, net of amortization. Loan fees are described in more detail in Note 3, Long-term Debt.

Treasury Stock

Treasury stock purchases are accounted for under the cost method whereby the cost of the acquired common stock is recorded as treasury stock. Gains and losses on the subsequent reissuance of treasury stock shares are credited or charged to additional paid in capital using the average cost method.

Income Taxes

Pursuant to ASC Topic 740, Income Taxes (“ASC Topic 740”), we follow the asset and liability method of accounting for income taxes, under which we recognize deferred tax assets and liabilities for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. We measure our deferred tax assets and liabilities by using the enacted tax rates we expect to apply to taxable income in the years in which we expect to recover or settle those temporary differences. Under ASC Topic 740, we reflect in income the effect of a change in tax rates on deferred tax assets and liabilities in the period during which the change occurs.

Comprehensive Income (Loss)

Comprehensive income (loss) is comprised of net loss and other comprehensive loss. During the years ended December 31, 2009 and 2008, $2.7 million of the difference between the par value and fair value of the ARPSs was considered temporary and was recorded as unrealized losses, net of taxes of $1.0 million, in accumulated other comprehensive income (loss). For the year ended December 31, 2010, we recognized a $3.3 million other-than-temporary impairment of the ARPSs to earnings. The following table sets forth the components of comprehensive loss (amounts in thousands):


	Years ended December 31,
	2010			2009			2008

Net loss	$	(33,261	)	$	(23,215	)	$	(62,745	)
Other comprehensive loss: unrealized losses on securities		—			(448	)		(1,245	)
Impact of impairment of investments charge		1,693			—			—

Comprehensive loss	$	(31,568	)	$	(23,663	)	$	(63,990	)

Earnings Per Common Share

We compute and present earnings per common share in accordance with ASC Topic 260, Earnings per Share (“ASC Topic 260”). This standard requires dual presentation of basic and diluted earnings per share on the face of our statement of operations.

Stock-based Compensation

Prior to 2010, we granted stock-based compensation in the form of stock option awards and restricted stock awards with vesting based solely on time of service conditions. In 2010, we continued to grant stock option awards with vesting based on time of service conditions and we began granting restricted stock unit awards with vesting based on time of service conditions, and in certain cases, performance conditions. We recognize compensation cost for stock option, restricted stock and restricted stock unit awards based on the grant-date fair value estimated in accordance with ASC Topic 718, Compensation—Stock Compensation (“ASC Topic 718”) and utilizing the graded vesting method.

We receive a tax deduction for certain stock option exercises during the period the options are exercised, generally for the excess of the market price of our common stock on the exercise date over the exercise price of the stock 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 consolidated statement of cash flows.

Related-Party Transactions

Our Chief Executive Officer and President of Drilling Services Division occasionally acquire at fair value a 1% to 5% minority working interest in oil and natural gas wells that we drill for one of our customers. These individuals did not own a working interest in any wells that we drilled for this customer during the years ended December 31, 2010 or 2009. Our President of Drilling Services Division acquired a minority working interest in two wells that we drilled for this customer during the year ended December 31, 2008. We recognized drilling services revenues of $2.0 million on these wells during the year ended December 31, 2008.

Reclassifications

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

2.	Acquisitions

On March 1, 2008, we acquired the production services business from WEDGE which provided well services, wireline services and fishing and rental services with a fleet of 62 well service rigs, 45 wireline units and approximately $13 million of fishing and rental equipment through its facilities in Texas, Kansas, North Dakota, Colorado, Utah and Oklahoma. The aggregate purchase price for the acquisition was approximately $314.7 million, which consisted of assets acquired of $340.8 million and liabilities assumed of $26.1 million. The aggregate purchase price includes $3.4 million of costs incurred to acquire the production services business from WEDGE. We financed the acquisition with approximately $3.2 million of cash on hand and $311.5 million of debt incurred under our senior secured revolving credit facility described in Note 3, Long-term Debt.

The following table summarizes the allocation of the purchase price and related acquisition costs to the estimated fair value of the assets acquired and liabilities assumed as of the date of acquisition (amounts in thousands):


Cash acquired	$	1,168
Other current assets		22,102
Property and equipment		138,493
Intangibles and other assets		66,118
Goodwill		112,869

Total assets acquired	$	340,750


Current liabilities	$	10,655
Long-term debt		1,462
Other long term liabilities		13,949

Total liabilities assumed	$	26,066

Net assets acquired	$	314,684

The following unaudited pro forma consolidated summary financial information gives effect of the acquisition of the production services business from WEDGE as though it was effective as of the beginning of the year ended December 31, 2008. Pro forma adjustments primarily relate to additional depreciation, amortization and interest costs. The pro forma information reflects our company’s historical data and historical data from the acquired production services business from WEDGE for the periods indicated. The pro forma data may not be indicative of the results we would have achieved had we completed the acquisition on January 1, 2008, or what we may achieve in the future and should be read in conjunction with the accompanying historical financial statements.


	Pro Forma Year Ended December 31, 2008


	(in thousands)
Total revenues	$	634,535
Net (loss) earnings	$	(62,514	)
(Loss) earnings per common share
Basic	$	(1.26	)
Diluted	$	(1.26	)

On March 1, 2008, immediately following the acquisition of the production services business from WEDGE, we acquired the production services business from Competition which provided wireline services with a fleet of 6 wireline units through its facilities in Montana. The aggregate purchase price for the Competition acquisition was approximately $30.0 million, which consisted of assets acquired of $30.1 million and liabilities assumed of $0.1 million. The aggregate purchase price includes $0.4 million of costs incurred to acquire the production services business from Competition. We financed the acquisition with $26.7 million cash on hand and a note payable due to the prior owner for $3.3 million. Goodwill of $5.3 million and intangible assets and other assets of $18.0 million were recorded in connection with the acquisition.

On August 29, 2008, we acquired the wireline services business from Paltec, Inc. (“Paltec”). The aggregate purchase price was $7.8 million which we financed with $6.5 million in cash and a sellers note of $1.3 million. Intangible and other assets of $4.3 million and goodwill of $0.1 million were recorded in connection with the acquisition.

On October 1, 2008, we acquired the well services business from Pettus Well Service (“Pettus”). The aggregated purchase price was $3.0 million which we financed with $2.8 million in cash and a sellers note of $0.2 million. Intangible and other assets of $1.2 million and goodwill of $0.1 million were recorded in connection with the acquisition.

The acquisitions of the production services businesses from WEDGE, Competition, Paltec and Pettus were accounted for as acquisitions of businesses. The purchase price allocations for these production services businesses were finalized as of December 31, 2008. Goodwill was recognized as part of the WEDGE, Competition, Paltec and Pettus acquisitions since the purchase price exceeded the estimated fair value of the assets acquired and liabilities assumed. We believed that the goodwill was related to the acquired workforces, future synergies between our existing Drilling Services Division and our new Production Services Division and the ability to expand our service offerings. These acquisitions occurred between March 1, 2008 and October 1, 2008, when production service revenues, margins and cash flows and our market capitalization were at historically high levels. As described in Note 1, our goodwill impairment analysis performed at December 31, 2008 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 $118.6 million for a full impairment of goodwill relating to these acquisitions. We also performed an impairment analysis which resulted in an impairment charge of $52.8 million and reduction in the intangible asset carrying value of customer relationships relating to these acquisitions. These impairment charges were primarily related to significant adverse changes in the economic and business climate that occurred during the fourth quarter of the year ended December 31, 2008.

On April 1, 2010, we acquired Tiger Wireline Services, Inc. (“Tiger”), which provided wireline services with two wireline units through its facilities in Kansas. The aggregate purchase price was approximately $1.9 million, which we financed with $1.3 million in cash and a seller’s note of $0.6 million. The identifiable assets recorded in connection with this acquisition include fixed assets of $0.8 million and intangible assets of $1.1 million representing customer relationships and a non-competition agreement. We did not recognize any goodwill in conjunction with the acquisition and no contingent assets or liabilities were assumed. Our acquisition of Tiger has been accounted for as an acquisition of a business in accordance with ASC Topic 805, Business Combinations.

3.	Long-term Debt

Long-term debt consists of the following (amounts in thousands):


	December 31, 2010			December 31, 2009

Senior secured revolving credit facility	$	37,750		$	257,500
Senior notes		240,080			—
Subordinated notes payable		3,045			4,387
Other		63			227

		280,938			262,114
Less current portion		(1,408	)		(4,041	)

	$	279,530		$	258,073

Senior Secured Revolving Credit Facility

We have a credit agreement, as amended, 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 $225 million, all of which matures on August 31, 2012 (the “Revolving Credit Facility”). The Revolving Credit Facility contains customary mandatory prepayments in respect of asset dispositions, debt incurrence and equity 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 $225 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 3.50% to 6.00% and 2.50% to 5.00%, respectively. The LIBOR margin and bank prime rate margin in effect at February 4, 2011 are 4.50% and 3.50%, respectively. The Revolving Credit Facility requires a commitment fee due quarterly based on the average daily unused amount of the commitments of the lenders, a fronting fee due for each letter of credit issued, and a quarterly letter of credit fee due based on the average undrawn amount of letters of credit outstanding during such period. 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.

In March 2010, we made a payment of $234.8 million to reduce the outstanding debt balance under the Revolving Credit Facility, using the net proceeds from the issuance of our Senior Notes which is described below. We may choose to make additional principal payments to reduce the outstanding debt balance prior to maturity on August 31, 2012 when cash and working capital is sufficient. We made a $12.8 million principal payment after December 31, 2010, which resulted in a $25.0 million outstanding balance under our Revolving Credit Facility and $9.2 million in committed letters of credit at February 4, 2011. Therefore, our borrowing availability under our Revolving Credit Facility was $190.8 million as of February 4, 2011. There are no limitations on our ability to access this borrowing capacity other than maintaining compliance with the covenants under the Revolving Credit Facility. At December 31, 2010, we were in compliance with our financial covenants. Our total consolidated leverage ratio was 2.7 to 1.0, our senior consolidated leverage ratio was 0.4 to 1.0 and our interest coverage ratio was 4.2 to 1.0. The financial covenants contained in our Revolving Credit Facility include the following:

•

A maximum total consolidated leverage ratio that cannot exceed:

•

5.00 to 1.00 as of the end of any fiscal quarter ending December 31, 2010 through June 30, 2011;

•

4.75 to 1.00 as of the end of the fiscal quarter ending September 30, 2011;

•

4.50 to 1.00 as of the end of the fiscal quarter ending December 31, 2011;

•

4.25 to 1.00 as of the end of the fiscal quarter ending March 31, 2012; and

•

4.00 to 1.00 as of the end of any fiscal quarter ending June 30, 2012 and thereafter.

•

A maximum senior consolidated leverage ratio, which excludes unsecured and subordinated debt, that cannot exceed:

•

4.50 to 1.00 as of the end of the fiscal quarter ending December 31, 2010;

•

4.25 to 1.00 as of the end of the fiscal quarter ending March 31, 2011;

•

4.00 to 1.00 as of the end of the fiscal quarter ending June 30, 2011;

•

3.75 to 1.00 as of the end of the fiscal quarter ending September 30, 2011;

•

3.50 to 1.00 as of the end of the fiscal quarter ending December 31, 2011;

•

3.25 to 1.00 as of the end of the fiscal quarter ending March 31, 2012; and

•

3.00 to 1.00 as of the end of any fiscal quarter ended June 30, 2012 and thereafter.

•

A minimum interest coverage ratio that cannot be less than:

•

2.00 to 1.00 as of the end of any fiscal quarter ending December 31, 2010 through December 31, 2011; and

•

3.00 to 1.00 as of the end of any fiscal quarter ending March 31, 2012 and thereafter.

•

$65 million for fiscal year 2010; and

•

$80 million for each fiscal year thereafter.

The capital expenditure thresholds for each period noted above may be increased by:

•

the first $25 million of any aggregate equity issuance proceeds received during such period and 25% of any equity issuance proceeds received in excess of $25 million during such period; and

•

25% of any debt incurrence proceeds received during such period.

In addition, any unused portion of the capital expenditure threshold up to $30 million can be carried over from the immediate preceding fiscal year.

At December 31, 2010, our senior consolidated leverage ratio was not greater than 2.50 to 1.00 and therefore, we were not subject to the capital expenditure threshold restrictions listed above.

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 “Senior Notes”). The 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 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.

In accordance with a registration rights agreement with the holders of our Senior Notes, we filed an exchange offer registration statement on Form S-4 with the Securities and Exchange Commission that became effective on September 2, 2010. This exchange offer registration statement enabled the holders of our Senior Notes to exchange their Senior Notes for publicly registered notes with substantially identical terms. References to the “Senior Notes” herein include the Senior Notes issued in the exchange offer.

The Senior Notes are reflected on our condensed consolidated balance sheet at December 31, 2010 with a carrying value of $240.1 million, which represents the $250 million face value net of the $9.9 million unamortized portion of original issue discount. The original issue discount is being amortized over the term of the Senior Notes based on the effective interest method. The Senior Notes will mature on March 15, 2018 with interest due semi-annually in arrears on March 15 and September 15 of each year, commencing on September 15, 2010. We have the option to redeem the 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 “Indenture”) together with any accrued and unpaid interest to the date of redemption. Prior to March 15, 2014, we may also redeem the Senior Notes, in whole or in part, at a “make-whole” redemption price specified in the Indenture, together with any accrued and unpaid interest to the date of redemption. In addition, prior to March 15, 2013, we may, on one or more occasions, redeem up to 35% of the aggregate principal amount of the Senior Notes at a redemption price of 109.875% of the principal amount, plus any accrued and unpaid interest to the redemption date, with the net proceeds of certain equity offerings, if at least 65% of the aggregate principal amount of the Senior Notes remains outstanding after such redemption and the redemption occurs within 120 days of the closing of the equity offering.

The Indenture contains certain restrictions on our and certain of our subsidiaries’ ability to:

•

pay dividends on stock;

•

repurchase stock or redeem subordinated debt or make other restricted payments;

•

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

•

create liens on our assets;

•

enter into sale and leaseback transactions;

•

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 another person;

•

enter into transactions with affiliates; and

•

enter into new lines of business.

These covenants are subject to important exceptions and qualifications. We were in compliance with these covenants as of December 31, 2010. 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 13, Guarantor/Non-Guarantor Condensed Consolidated Financial Statements).

Subordinated Notes Payable and Other

In addition to amounts outstanding under our Revolving Credit Facility and Senior Notes, long-term debt includes subordinated notes payable to certain employees that are former shareholders of the production services businesses that were acquired by WEDGE prior to our acquisition of WEDGE on March 1, 2008, a subordinated note payable to an employee that is a former shareholder of Competition and three subordinated notes payable to

certain employees that are former shareholders of Paltec, Pettus and Tiger. These subordinated notes payable have interest rates ranging from 5.4% to 14%, require quarterly or annual payments of principal and interest and have final maturity dates ranging from January 2011 to April 2013. The aggregate outstanding balance of these subordinated notes payable was $3.0 million as of December 31, 2010.

Other debt represents a financing arrangement for computer software with an outstanding balance of $0.1 million at December 31, 2010.

Debt Issuance Costs

Costs incurred in connection with our 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 August 2012. Costs incurred in connection with the issuance of our Senior Notes were capitalized and are being amortized using the straight-line method over the term of the Senior Notes which mature in March 2018. Capitalized debt costs related to the issuance of our long-term debt were approximately $6.7 million and $3.8 million as of December 31, 2010 and December 31, 2009, respectively. We recognized approximately $1.9 million, $1.5 million and $0.6 million of associated amortization during the years ended December 31, 2010, 2009 and 2008, respectively.

4.	Leases

We lease our corporate office facilities in San Antonio, Texas at a payment escalating from $27,911 per month in January 2011 to $29,316 per month pursuant to a lease extending through December 2013. We recognize rent expense on a straight line basis for our corporate office lease. In addition, we lease real estate at 39 other locations under non-cancelable operating leases with payments ranging from $250 per month to $27,169 per month, pursuant to leases expiring through August 2015. These real estate locations are used primarily for division offices and storage and maintenance yards. We also lease office equipment under non-cancelable operating leases expiring through November 2013.

Future lease obligations required under non-cancelable operating leases as of December 31, 2010 were as follows (amounts in thousands):


Years Ended December 31,
2011	$	2,408
2012		1,885
2013		1,484
2014		586
2015		164
Thereafter		—

	$	6,527

Rent expense under operating leases for the years ended December 31, 2010, 2009 and 2008 was $2.9 million, $2.1 million and $1.4 million, respectively.

5.	Income Taxes

The jurisdictional components of loss before income taxes consist of the following (amounts in thousands):


	Years ended December 31,
	2010			2009			2008
Domestic	$	(48,650	)	$	(46,221	)	$	(62,388	)
Foreign		1,092			6,049			5,700

Loss before income tax	$	(47,558	)	$	(40,172	)	$	(56,688	)

The components of our income tax expense (benefit) consist of the following (amounts in thousands):


	Years ended December 31,
	2010			2009			2008
Current tax:
Federal	$	(2,547	)	$	(46,073	)	$	3,777
State		32			(2,969	)		1,181
Foreign		931			1,087			348

		(1,584	)		(47,955	)		5,306

Deferred taxes:
Federal		(13,046	)		31,740			476
State		1,366			3,390			(211	)
Foreign		(1,033	)		(4,132	)		486

		(12,713	)		30,998			751

Income tax expense (benefit)	$	(14,297	)	$	(16,957	)	$	6,057

The difference between the income tax (benefit) expense and the amount computed by applying the federal statutory income tax rate 35% to loss before income taxes consist of the following (amounts in thousands):


	Years ended December 31,
	2010			2009			2008
Expected tax benefit	$	(16,645	)	$	(14,060	)	$	(19,840	)
State income taxes		909			274			556
Incentive stock options		266			243			508
Goodwill impairment		—			—			26,752
Tax benefits in foreign jurisdictions		(207	)		(5,162	)		(1,377	)
Domestic production activities deduction		—			1,130			(457	)
Tax-exempt interest income		(23	)		(33	)		(219	)
Non deductible items for tax purposes		349			218			247
Valuation allowance		1,248			—			—
Other, net		(194	)		433			(113	)

Income tax expense (benefit)	$	(14,297	)	$	(16,957	)	$	6,057

Income tax expense (benefit) was allocated as follows (amounts in thousands):


	Years ended December 31,
	2010			2009			2008
Results of operations	$	(14,297	)	$	(16,957	)	$	6,057
Stockholders' equity		1,332			(26	)		(963	)

Income tax expense (benefit)	$	(12,965	)	$	(16,983	)	$	5,094

Deferred income taxes arise from temporary differences between the tax bases of assets and liabilities and their reported amounts in the consolidated financial statements. The components of our deferred income tax assets and liabilities were as follows (amounts in thousands):


	December 31, 2010			December 31, 2009
Deferred tax assets:
Auction rate preferred securities	$	1,248		$	983
Intangibles		21,594			22,365
Employee benefits and insurance claims accruals		3,634			3,338
Accounts receivable reserve		42			99
Employee stock based compensation		6,099			4,439
Accrued expenses not deductible for tax purposes		—			1,919
Accrued revenue not income for book purposes		3,393			1,649
Federal and state net operating loss and AMT credit carryforward		21,568			4,718
Foreign net operating loss carryforward		5,713			4,071

		63,291			43,581
Valuation allowance		(1,248	)		—

Total deferred tax assets		62,043			43,581

Deferred tax liabilities:
Accrued expenses not deductible for tax purposes		105			—
Property and equipment		132,231			125,855

Total deferred tax liabilities		132,336			125,855

Net deferred tax liabilities	$	70,293		$	82,274

In assessing the realizability of deferred tax assets, we consider whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. Based on the expectation of future taxable income and that the deductible temporary differences will offset existing taxable temporary differences, we believe it is more likely than not that we will realize the benefits of these deductible temporary differences, with the exception of the valuation allowance recorded to fully offset our deferred tax asset related to the unrealized loss on the impairment of our ARPS securities.

As of December 31, 2010, we had $21.6 million and $5.7 million of deferred tax assets related to domestic and foreign net operating losses, respectively, that are available to reduce future taxable income. In assessing the realizability of our deferred tax assets, we only recognize a tax benefit to the extent of taxable income that we

expect to earn in the jurisdiction in future periods. We estimate that our operations will result in taxable income in excess of our net operating losses and we expect to apply the net operating losses against taxable income that we have estimated in future periods. The domestic net operating losses can be used to offset future domestic taxable income through 2020, while the majority of the foreign net operating losses can be carried forward indefinitely.

Deferred income taxes have not been provided on the future tax consequences attributable to difference between the financial statements carrying amounts of existing assets and liabilities and the respective tax bases of our foreign subsidiary based on the determination that such differences are essentially permanent in duration in that the earnings of the subsidiary is expected to be indefinitely reinvested in foreign operations. As of December 31, 2010, the cumulative undistributed earnings/loss of the subsidiary was approximately a $2.3 million loss. If those earnings were not considered indefinitely reinvested, deferred income taxes would have been recorded after consideration of foreign tax credits. It is not practicable to estimate the amount of additional tax that might be payable on those earnings, if distributed.

We have no unrecognized tax benefits relating to ASC Topic 740 and no unrecognized tax benefit activity during the year ended December 31, 2010.

We adopted a policy to record interest and penalty expense related to income taxes as interest and other expense, respectively. At December 31, 2010, no interest or penalties have been or are required to be accrued. Our open tax years for our federal income tax returns in the United States are for the years ended March 31, 2007, December 31, 2007, December 31, 2008 and December 31, 2009. Our open tax years for our income tax returns in Colombia are for the years ended December 31, 2008 and December 31, 2009.

6.	Fair Value of Financial Instruments

Our financial instruments consist primarily of cash, trade receivables, trade payables, long-term debt, and our investments in ARPS. The carrying value of cash, trade receivables and trade payables are considered to be representative of their respective fair values due to the short-term nature of these instruments.

Our ARPSs are reported at amounts that reflect our estimate of fair value. To estimate the fair values of our ARPSs as of December 31, 2010, we used inputs defined by ASC Topic 820 as level 1 inputs which are quoted market prices in active markets for identical securities. Subsequent to year end, we entered into a settlement agreement with a financial institution to sell the ARPSs for $12.6 million, plus accrued interest, and liquidated the ARPS on January 25, 2011. Therefore, the $12.6 million sales price under the settlement agreement represents the fair value of the ARPSs at December 31, 2010. The $3.3 million difference between the ARPSs’ par value of $15.9 million and the fair value of $12.6 million represents an other-than-temporary impairment which is reflected as an impairment of investments in our consolidated statement of operations for the year ended December 31, 2010.

To estimate the fair values of our ARPSs as of December 31, 2009, we used inputs defined by ASC Topic 820 as level 3 inputs which are unobservable for the asset or liability and are developed based on the best information available in the circumstances. We estimated the fair value of our ARPSs based on discounted cash flow models and secondary market comparisons of similar securities. Based on this methodology, the estimated fair value of our ARPSs was $13.2 million at December 31, 2009, as compared to the par value of $15.9 million at both December 31, 2009. The difference between the ARPSs’ fair value and par value was due to the lack of liquidity which was considered to be temporary at that time. We believed we would ultimately recover the par value of the ARPSs without a loss, primarily due to the collateral securing the ARPSs and our estimate of the discounted cash flows that we expected to collect. Also, we did not intend to sell the ARPSs at a loss and we believed it was more-likely-than-not that we would not have to sell prior to recovery of the ARPSs’ par value based on our liquidity needs. Therefore, the fair value discount of $2.7 million at December 31, 2009 was recorded as unrealized losses, net of tax, in accumulated other comprehensive income (loss) which was a component of shareholders’ equity. There were no portions of the fair value discounts attributable to credit losses.

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 based on observable inputs for similar types of debt instruments represents level 2 inputs as defined by ASC Topic 820. The following table presents the supplemental fair value information about long-term debt at December 31, 2010 and 2009 (amounts in thousands):


	December 31, 2010				December 31, 2009
	Carrying		Fair		Carrying		Fair
	Amount		Value		Amount		Value
Total debt	$	280,938	$	308,630	$	262,114	$	262,429

7.	Earnings (loss) Per Common Share

The following table presents a reconciliation of the numerators and denominators of the basic loss per share and diluted loss per share comparisons as required by ASC Topic 260 (amounts in thousands, except per share data):


	Years ended December 31,
	2010			2009			2008
Basic
Net loss	$	(33,261	)	$	(23,215	)	$	(62,745	)

Weighted average shares		53,797			50,313			49,789

Loss per share	$	(0.62	)	$	(0.46	)	$	(1.26	)

Diluted
Net loss	$	(33,261	)	$	(23,215	)	$	(62,745	)
Effect of dilutive securities		—			—			—

Net loss available to common shareholders after assumed conversion	$	(33,261	)	$	(23,215	)	$	(62,745	)

Weighted average shares:
Outstanding		53,797			50,313			49,789
Options		—			—			—

		53,797			50,313			49,789

Loss per share	$	(0.62	)	$	(0.46	)	$	(1.26	)

Outstanding stock options, restricted stock and restricted stock unit awards representing 852,370, 279,949 and 546,429 shares of common stock were excluded from the diluted loss per share calculations for the years ended December 31, 2010, 2009 and 2008, respectively, because the effect of their inclusion would be anti-dilutive, or would decrease the reported loss per share.

8.	Equity Transactions and Stock Based Compensation Plans

On November 10, 2009, we sold 3,820,000 shares of our common stock at $6.75 per share, less underwriters’ commissions, pursuant to a public offering under a shelf registration statement.

We have stock based award plans that are administered by the Compensation Committee of our Board of Directors, which selects persons eligible to receive awards and determines the number of stock options, restricted stock, or restricted stock units subject to each award and the terms, conditions and other provisions of the awards. Total shares available for future stock option grants, restricted stock grants, and restricted stock unit grants to employees and directors under existing plans were 960,521 at December 31, 2010. Of the total shares available, no more than 730,421 shares may be granted in the form of restricted stock.

Stock Options

We grant stock option awards which generally become exercisable over three- to five-year periods, and expire ten years after the date of grant. Our stock-based compensation plans provide that all stock option awards must have an exercise price 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 options-pricing model. The following table summarizes the assumptions used in the Black-Scholes option-pricing model based on a weighted-average calculation for the years ended December 31, 2010, 2009 and 2008:


	Years ended December 31,
	2010			2009			2008
Expected volatility		62	%		58	%		44	%
Risk-free interest rates		2.6	%		2.1	%		2.7	%
Expected life in years		5.61			5.48			3.72
Grant-date fair value	$	4.91		$	2.09		$	5.66

The assumptions above 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.

The following table represents stock option activity from December 31, 2008 through December 31, 2010:


	Number of Shares			Weighted-Average Exercise Price Per Share		Weighted-Average Remaining Contract Life in Years
Outstanding stock options as of December 31, 2008		3,769,695		$	12.85
Granted		1,526,550			3.96
Forfeited		(240,632	)		12.88

Outstanding stock options as of December 31, 2009		5,055,613		$	10.17
Granted		787,200			8.64
Forfeited		(90,634	)		12.84
Exercised		(63,900	)		3.73

Outstanding stock options as of December 31, 2010		5,688,279		$	9.98		6.81

Stock options exercisable as of December 31, 2010		3,503,596		$	11.25		5.82

The following table summarizes the compensation expense recognized for stock option awards during the years ended December 31, 2010, 2009 and 2008 (amounts in thousands):


	Years ended December 31,
	2010		2009		2008
General and administrative expense	$	4,047	$	4,290	$	3,085
Operating costs		500		971		871

	$	4,547	$	5,261	$	3,956

At December 31, 2010, the aggregate intrinsic value of stock options outstanding was $9.9 million and the aggregate intrinsic value of stock options exercisable was $5.0 million. Intrinsic value is the difference between the exercise price of a stock option and the closing market price of our common stock, which was $8.81 on December 31, 2010.

The following table summarizes our nonvested stock option activity from December 31, 2008 through December 31, 2010:


	Number of Shares			Weighted-Average Grant-Date Fair Value Per Share
Nonvested stock options as of December 31, 2008		2,027,763		$	5.74
Granted		1,526,550			2.09
Vested		(831,539	)		5.62
Forfeited		(185,300	)		4.73

Nonvested stock options as of December 31, 2009		2,537,474		$	3.65
Granted		787,200			4.91
Vested		(1,115,991	)		4.19
Forfeited		(24,000	)		3.34

Nonvested stock options as of December 31, 2010		2,184,683		$	3.83

At December 31, 2010, there was $2.4 million of unrecognized compensation cost relating to stock options which are expected to be recognized over a weighted-average period of 1.4 years.

During the year ended December 31, 2010, employees exercised stock options for the purchase of 63,900 shares of common stock at prices ranging from $3.67 to $4.77 per share. Employees did not exercise any stock options during the year ending December 31, 2009. Employees exercised stock options for the purchase of 170,054 shares of common stock at prices ranging from $3.67 to $10.31 per share during the year December 31, 2008. 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 consolidated statement of cash flows.

On February 2, 2011, our Board of Directors approved the grant of stock options representing 597,298 shares of common stock to officers and employees that will vest over a three-year period.

Restricted Stock

We grant 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. When restricted stock awards are granted, shares of our common stock are considered issued, but subject to certain restrictions.

The following table summarizes our restricted stock activity from December 31, 2008 through December 31, 2010:


	Number of Shares			Weighted-Average Grant-Date Fair Value per Share
Nonvested restricted stock as of December 31, 2008		173,866		$	17.07
Granted		326,748			4.23
Vested		(54,956	)		17.07
Forfeited		(18,300	)		11.86

Nonvested restricted stock as of December 31, 2009		427,358		$	7.48
Granted		66,224			6.04
Vested		(160,223	)		8.52
Forfeited		(3,700	)		9.20

Nonvested restricted stock as of December 31, 2010		329,659		$	6.66

The following table summarizes the compensation expense recognized for restricted stock awards during the years ended December 31, 2010, 2009 and 2008 (amounts in thousands):


	Years ended December 31,
	2010		2009		2008
General and administrative expense	$	1,119	$	1,641	$	532
Operating costs		145		314		109

	$	1,264	$	1,955	$	641

At December 31, 2010, there was $0.7 million of unrecognized compensation cost relating to restricted stock awards which are expected to be recognized over a weighted-average period of 1.4 years.

Restricted Stock Units

We grant restricted stock unit awards with vesting based on time of service conditions only, and we grant restricted stock unit awards with vesting based on time of service and performance conditions. Shares of our common stock are issued to recipients of restricted stock units only when they have satisfied the applicable vesting conditions.

During the year ended December 31, 2010, we granted restricted stock unit awards with vesting based on time of service conditions. These restricted stock unit awards vest over a three-year period and represent 72,120 shares of common stock. The fair value of these restricted stock unit awards is based on the closing price of our common stock on the date of grant.

During the year ended December 31, 2010, we also granted restricted stock unit awards with vesting based on time of service and performance conditions. These restricted stock unit awards vest over a three-year period. The fair value of these restricted stock unit awards is computed based on the closing price of our common stock on the date of grant and the estimated number of shares of common stock. The estimated number of shares of

common stock will be adjusted based on our actual achievement levels that are measured against predetermined performance conditions. Compensation cost ultimately recognized is equal to the fair value of the restricted stock unit award based on the actual outcome of the service and performance conditions.

We did not grant any restricted stock unit awards prior to 2010. The following table summarizes our restricted stock unit activity from December 31, 2009 through December 31, 2010:


	Time-Based Award					Performance-Based Award
	Number of Time-Based Award Units			Weighted-Average Grant-Date Fair Value per Unit		Number of Performance-Based Award Units			Weighted-Average Grant-Date Fair Value per Unit
Nonvested restricted stock units as of December 31, 2009		—		$	—		—		$	—
Granted		72,120			8.86		194,680			8.86
Vested		—			—		—			—
Forfeited		(5,040	)		8.86		(2,160	)		8.86

Nonvested restricted stock units as of December 31, 2010		67,080		$	8.86		192,520		$	8.86

As of December 31, 2010, we estimated that our actual achievement level will be 80% of the predetermined performance conditions. Therefore, the outstanding 192,520 restricted stock units would be adjusted to represent 154,016 shares of our common stock.

The following table summarizes the compensation expense recognized for restricted stock unit awards during the year ended December 31, 2010 (amounts in thousands):


	Year ended December 31, 2010
General and administrative expense	$	748
Operating costs		116

	$	864

At December 31, 2010, there was $0.9 million of unrecognized compensation cost relating to restricted stock unit awards which are expected to be recognized over a weighted-average period of 2.1 years.

On February 2, 2011, our Board of Directors approved the grant of restricted stock units representing 249,382 shares of common stock to officers and employees that will vest over a three-year period.

9.	Employee Benefit Plans and Insurance

We maintain a 401(k) retirement plan for our eligible employees. Under this plan, we may make a matching contribution, on a discretionary basis, equal to a percentage of each eligible employee’s annual contribution, which we determine annually. Our matching contributions for the years ended December 31, 2010, 2009 and 2008 were $0.9 million, $0.7 million and $1.8 million, respectively.

We maintain a self-insurance program, for major medical, hospitalization and dental coverage for employees and their dependents, which is partially funded by employee payroll deductions. We have provided for both reported and incurred but not reported medical costs in the accompanying consolidated balance sheets. As of January 1, 2011, we have a maximum liability of $150,000 per employee/dependent per year, up from

$125,000 during 2010. Amounts in excess of the stated maximum are covered under a separate policy provided by an insurance company. Payroll and employee related cost accruals at December 31, 2010 and 2009 include $1.5 million and $1.0 million, respectively, for our estimate of incurred but unpaid costs related to the self-insurance portion of our health insurance.

We are self-insured for up to $500,000 per incident for all workers’ compensation claims submitted by employees for on-the-job injuries. We have deductibles of $250,000 and $100,000 per occurrence under our general liability insurance and auto liability insurance, respectively. We accrue our workers’ compensation claim cost estimates based on historical claims development data and we accrue the cost of administrative services associated with claims processing. Insurance premiums and deductibles accruals at December 31, 2010 and 2009 include $6.6 million and $7.0 million, respectively, for our estimate of costs relative to the self-insured portion of our workers’ compensation, general liability and auto liability insurance. Based upon our past experience, management believes that we have adequately provided for potential losses. However, future multiple occurrences of serious injuries to employees could have a material adverse effect on our financial position and results of operations.

10.

Segment Information

At December 31, 2010, we had two operating segments referred to as the Drilling Services Division and the Production Services Division which is the basis management uses for making operating decisions and assessing performance. Prior to our acquisitions of the production services businesses from WEDGE and Competition on March 1, 2008, all our operations related to the Drilling Services Division and we reported these operations in a single operating segment. The acquisitions of the production services businesses from WEDGE and Competition resulted in the formation of our Production Services Division (see Note 2, Acquisitions).

Drilling Services Division—Our Drilling Services Division provides contract land drilling services with its fleet of 71 drilling rigs in the following locations:


Drilling Division Locations	Rig Count
South Texas		19
East Texas		13
West Texas		3
North Dakota		9
North Texas		3
Utah		3
Oklahoma		6
Appalachia		7
Colombia		8

Production Services Division—Our Production Services Division provides a range of services to oil and gas exploration and production companies, including well services, wireline services, and fishing and rental services. Our production services operations are managed through locations concentrated in the major United States onshore oil and gas producing regions in the Gulf Coast, Mid-Continent, Rocky Mountain and Appalachian states. We have a premium fleet of 75 well service rigs consisting of seventy 550 horsepower rigs, four 600 horsepower rigs and one 400 horsepower rig. We provide wireline services with a fleet of 86 wireline units and rental services with approximately $13.5 million of fishing and rental tools.

The following tables set forth certain financial information for our two operating segments and corporate as of and for the year ended December 31, 2010 (amounts in thousands):


	As of and for the Year Ended December 31, 2010
	Drilling Services Division		Production Services Division		Corporate		Total
Identifiable assets	$	542,242	$	261,777	$	37,324	$	841,343

Revenues	$	312,196	$	175,014	$	—	$	487,210
Operating costs		227,136		105,295		—		332,431

Segment margin	$	85,060	$	69,719	$	—	$	154,779

Depreciation and amortization	$	92,800	$	26,740	$	1,271	$	120,811
Capital expenditures	$	109,261	$	25,411	$	479	$	135,151

The following tables set forth certain financial information for our two operating segments and corporate as of and for the year ended December 31, 2009 (amounts in thousands):


	As of and for the Year Ended December 31, 2009
	Drilling Services Division		Production Services Division		Corporate		Total
Identifiable assets	$	536,858	$	234,920	$	53,177	$	824,955

Revenues	$	219,751	$	105,786	$	—	$	325,537
Operating costs		147,343		68,012		—		215,355

Segment margin	$	72,408	$	37,774	$	—	$	110,182

Depreciation and amortization	$	81,078	$	23,893	$	1,215	$	106,186
Capital expenditures	$	94,887	$	15,162	$	404	$	110,453

The following table reconciles the segment profits reported above to income from operations as reported on the condensed consolidated statements of operations for the years ended December 31, 2010 and 2009 (amounts in thousands):


	Year Ended December 31, 2010			Year Ended December 31, 2009
Segment margin	$	154,779		$	110,182
Depreciation and amortization		(120,811	)		(106,186	)
General and administrative		(52,047	)		(37,478	)
Bad debt (expense) recovery		(493	)		1,642

Loss from operations	$	(18,572	)	$	(31,840	)

The following table sets forth certain financial information for our international operations in Colombia as of and for the years ended December 31, 2010 and 2009 which is included in our Drilling Services Division (amounts in thousands):


	As of and for the Year Ended December 31, 2010		As of and for the Year Ended December 31, 2009
Identifiable assets	$	157,509	$	120,319

Revenues	$	86,432	$	56,617

Identifiable assets as of December 31, 2010 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. Identifiable assets as of December 31, 2009 include five drilling rigs that are owned by our Colombia subsidiary and one drilling rigs that is owned by one of our domestic subsidiaries and leased to our Colombia subsidiary.

11.

Commitments and Contingencies

In connection with our expansion into international markets, 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 $62.8 million relating to our performance under these bonds.

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.

12.

Quarterly Results of Operations (unaudited)

The following table summarizes quarterly financial data for the years ended December 31, 2010 and December 31, 2009 (in thousands, except per share data):


Year Ended December 31, 2010	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Total
Revenues	$	86,021		$	117,027		$	135,544		$	148,618		$	487,210
Income (loss) from operations		(20,116	)		(7,856	)		2,536			6,864			(18,572	)
Income tax (expense) benefit		9,159			4,498			1,612			(972	)		14,297
Net loss		(14,547	)		(10,142	)		(2,580	)		(5,992	)		(33,261	)
Loss per share:
Basic	$	(0.27	)	$	(0.19	)	$	(0.05	)	$	(0.11	)	$	(0.62	)
Diluted	$	(0.27	)	$	(0.19	)	$	(0.05	)	$	(0.11	)	$	(0.62	)

Year Ended December 31, 2009
Revenues	$	100,840		$	69,120		$	74,366		$	81,211		$	325,537
Income (loss) from operations		2,857			(9,273	)		(12,022	)		(13,402	)		(31,840	)
Income tax expense		180			3,547			4,406			8,824			16,957
Net earnings (loss)		618			(6,259	)		(9,190	)		(8,384	)		(23,215	)
Earnings (loss) per share:
Basic	$	0.01		$	(0.13	)	$	(0.18	)	$	(0.16	)	$	(0.46	)
Diluted	$	0.01		$	(0.13	)	$	(0.18	)	$	(0.16	)	$	(0.46	)

13.

Guarantor/Non-Guarantor Condensed Consolidated Financial Statements

Our Senior Notes are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by our existing domestic subsidiaries, except for Pioneer Services Holdings, LLC, and certain of our future domestic subsidiaries. The subsidiaries that generally operate our non-U.S. business concentrated in Colombia do not guarantee our Senior Notes. The non-guarantor subsidiaries do not have any payment obligations under the Senior Notes, the guarantees or the Indenture. In the event of a bankruptcy, liquidation or reorganization of any non-guarantor subsidiary, such non-guarantor subsidiary will pay the holders of its debt and other liabilities, including its trade creditors, before it will be able to distribute any of its assets to us. In the future, any non-U.S. subsidiaries, immaterial subsidiaries and subsidiaries that we designate as unrestricted subsidiaries under the Indenture will not guarantee the Senior Notes. As of December 31, 2010, 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)


	December 31, 2010
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
*ASSETS*
Current assets:
Cash and cash equivalents	$	15,737		$	(1,840	)	$	8,114		$	—		$	22,011
Short-term investments		12,569			—			—			—			12,569
Receivables		—			78,575			10,940			—			89,515
Intercompany receivable (payable)		(80,900	)		80,942			(42	)		—			—
Deferred income taxes		178			4,167			5,522			—			9,867
Inventory		—			2,874			6,149			—			9,023
Prepaid expenses and other current assets		263			4,604			3,930			—			8,797

Total current assets		(52,153	)		169,322			34,613			—			151,782

Net property and equipment		1,601			562,390			92,267			(750	)		655,508
Investment in subsidiaries		714,292			114,483			—			(828,775	)		—
Intangible assets, net of amortization		235			21,731			—			—			21,966
Noncurrent deferred income taxes		14,632			—			—			(14,632	)		—
Other long-term assets		6,739			2,844			2,504			—			12,087

Total assets	$	685,346		$	870,770		$	129,384		$	(844,157	)	$	841,343

*LIABILITIES AND SHAREHOLDERS’ EQUITY*
Current liabilities:
Accounts payable	$	242		$	20,134		$	6,553			—		$	26,929
Current portion of long-term debt		63			1,345			—			—			1,408
Prepaid drilling contracts		—			1,000			2,669			—			3,669
Accrued expenses		9,861			30,786			2,987			—			43,634

Total current liabilities		10,166			53,265			12,209			—			75,640
Long-term debt, less current portion		277,830			1,700			—			—			279,530
Other long-term liabilities		267			6,744			2,669			—			9,680
Deferred income taxes		—			94,769			23			(14,632	)		80,160

Total liabilities		288,263			156,478			14,901			(14,632	)		445,010
Total shareholders’ equity		397,083			714,292			114,483			(829,525	)		396,333

Total liabilities and shareholders’ equity	$	685,346		$	870,770		$	129,384		$	(844,157	)	$	841,343


	December 31, 2009
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
*ASSETS*
Current assets:
Cash and cash equivalents	$	33,352		$	(2,716	)	$	9,743		$	—		$	40,379
Receivables		—			76,490			4,977			—			81,467
Intercompany receivable (payable)		(86,442	)		86,663			(221	)		—			—
Deferred income taxes		—			3,909			1,651			—			5,560
Inventory		—			1,791			3,744			—			5,535
Prepaid expenses and other current assets		224			4,008			1,967			—			6,199

Total current assets		(52,866	)		170,145			21,861			—			139,140

Net property and equipment		1,898			550,730			85,143			(749	)		637,022
Investment in subsidiaries		712,720			104,256			—			(816,976	)		—
Intangible assets, net of amortization		698			24,695			—			—			25,393
Noncurrent deferred income taxes		980			11			2,339			(991	)		2,339
Long-term investments		13,228			—			—			—			13,228
Other long-term assets		3,779			3,561			493			—			7,833

Total assets	$	680,437		$	853,398		$	109,836		$	(818,716	)	$	824,955

*LIABILITIES AND SHAREHOLDERS’ EQUITY*
Current liabilities:
Accounts payable	$	286		$	12,277		$	2,761		$	—		$	15,324
Current portion of long-term debt		2,100			1,941			—			—			4,041
Prepaid drilling contracts		—			324			84			—			408
Accrued expenses		226			26,070			2,735			—			29,031

Total current liabilities		2,612			40,612			5,580			—			48,804
Long-term debt, less current portion		255,628			2,445			—			—			258,073
Other long-term liabilities		—			6,457			—			—			6,457
Deferred income taxes		—			91,164			—			(991	)		90,173

Total liabilities		258,240			140,678			5,580			(991	)		403,507
Total shareholders’ equity		422,197			712,720			104,256			(817,725	)		421,448

Total liabilities and shareholders’ equity	$	680,437		$	853,398		$	109,836		$	(818,716	)	$	824,955

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited, in thousands)


	Year Ended December 31, 2010
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Revenues:	$	—		$	400,778		$	86,432		$	—		$	487,210

Costs and expenses:
Operating costs		—			263,649			68,782			—			332,431
Depreciation and amortization		1,271			109,971			9,569			—			120,811
General and administrative		15,337			34,177			2,959			(426	)		52,047
Intercompany leasing		—			(4,323	)		4,323			—			—
Bad debt recovery		—			493			—			—			493

Total costs and expenses		16,608			403,967			85,633			(426	)		505,782

Income (loss) from operations		(16,608	)		(3,189	)		799			426			(18,572	)

Other income (expense):
Equity in earnings of subsidiaries		(1,982	)		1,335			—			647			—
Interest expense		(26,240	)		(399	)		(20	)		—			(26,659	)
Interest income		—			66			26			—			92
Impairment of investments		(3,331	)		—			—			—			(3,331	)
Other		—			953			385			(426	)		912

Total other income (expense)		(31,553	)		1,955			391			221			(28,986	)

Income (loss) before income taxes		(48,161	)		(1,234	)		1,190			647			(47,558	)
Income tax benefit (expense)		14,900			(748	)		145			—			14,297

Net earnings (loss)	$	(33,261	)	$	(1,982	)	$	1,335		$	647		$	(33,261	)


	Year Ended December 31, 2009
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Revenues:	$	—		$	268,920		$	56,617		$	—		$	325,537

Costs and expenses:
Operating costs		—			174,579			41,091			(315	)		215,355
Depreciation and amortization		1,215			97,015			7,956			—			106,186
General and administrative		12,222			25,293			1,379			(1,416	)		37,478
Bad debt recovery		—			(1,642	)		—			—			(1,642	)

Total costs and expenses		13,437			295,245			50,426			(1,731	)		357,377

Income (loss) from operations		(13,437	)		(26,325	)		6,191			1,731			(31,840	)

Other income (expense):
Equity in earnings of subsidiaries		(2,250	)		9,245			—			(6,995	)		—
Interest expense		(8,585	)		(555	)		(5	)		—			(9,145	)
Interest income		1			111			105			—			217
Other		1,056			1,362			(91	)		(1,731	)		596

Total other income (expense)		(9,778	)		10,163			9			(8,726	)		(8,332	)

Income (loss) before income taxes		(23,215	)		(16,162	)		6,200			(6,995	)		(40,172	)
Income tax benefit (expense)		—			13,912			3,045			—			16,957

Net earnings (loss)	$	(23,215	)	$	(2,250	)	$	9,245		$	(6,995	)	$	(23,215	)


	Year Ended December 31, 2008
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Revenues:	$	—		$	559,470		$	51,414		$	—		$	610,884

Costs and expenses:
Operating costs		—			313,319			37,254			(630	)		349,943
Depreciation and amortization		830			82,252			5,063			—			88,145
General and administrative		17,483			27,011			1,435			(1,095	)		44,834
Bad debt recovery		—			423			—			—			423
Impairment of goodwill		—			118,646			—			—			118,646
Impairment of intangible assets		—			52,847			—			—			52,847

Total costs and expenses		18,313			594,498			43,752			(1,725	)		654,838

Income (loss) from operations		(18,313	)		(35,028	)		7,662			1,725			(43,954	)

Other income (expense):
Equity in earnings of subsidiaries		(32,531	)		5,483			—			27,048			—
Interest expense		(12,523	)		(547	)		(2	)		—			(13,072	)
Interest income		5			1,143			108			—			1,256
Other		675			1,647			(1,451	)		(1,789	)		(918	)

Total other income (expense)		(44,374	)		7,726			(1,345	)		25,259			(12,734	)

Income (loss) before income taxes		(62,687	)		(27,302	)		6,317			26,984			(56,688	)
Income tax benefit (expense)		6			(5,229	)		(834	)		—			(6,057	)

Net earnings (loss)	$	(62,681	)	$	(32,531	)	$	5,483		$	26,984		$	(62,745	)

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited, in thousands)


	Year Ended December 31, 2010
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations		Consolidated
Cash flows from operating activities:	$	31,841		$	115,650		$	14,542		$	—	$	98,351

Cash flows from investing activities:
Acquisition of other production services businesses		—			(1,340	)		—			—		(1,340	)
Purchases of property and equipment		(478	)		(114,313	)		(16,212	)		—		(131,003	)
Proceeds from sale of property and equipment		—			2,290			41			—		2,331
Proceeds from insurance recoveries		—			531			—			—		531

		(478	)		(112,832	)		(16,171	)		—		(129,481	)

Cash flows from financing activities:
Debt repayments		(254,914	)		(1,942	)		—			—		(256,856	)
Proceeds from issuance of debt		274,375			—			—			—		274,375
Debt issuance costs		(4,865	)		—			—			—		(4,865	)
Proceeds from exercise of options		238			—			—			—		238
Purchase of treasury stock		(130	)		—			—			—		(130	)

		14,704			(1,942	)		—			—		12,762

Net increase (decrease) in cash and cash equivalents		17,615			876			(1,629	)		—		(18,368	)
Beginning cash and cash equivalents		33,352			(2,716	)		9,743			—		40,379

Ending cash and cash equivalents	$	15,737		$	(1,840	)	$	8,114		$	—	$	22,011


	Year Ended December 31, 2009
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations		Consolidated
Cash flows from operating activities:	$	26,598		$	91,432		$	5,283		$	—	$	123,313

Cash flows from investing activities:
Purchases of property and equipment		(404	)		(106,628	)		(7,680	)		—		(114,712	)
Proceeds from sale of property and equipment		—			694			73			—		767
Proceeds from insurance recoveries		—			36			—			—		36

		(404	)		(105,898	)		(7,607	)		—		(113,909	)

Cash flows from financing activities:
Debt repayments		(15,152	)		(2,146	)		—			—		(17,298	)
Debt issuance costs		(2,560	)		—			—			—		(2,560	)
Proceeds from common stock, net of offering costs of $454		24,043			—			—			—		24,043
Purchase of treasury stock		(31	)		—			—			—		(31	)

		6,300			(2,146	)		—			—		4,154

Net increase (decrease) in cash and cash equivalents		32,494			(16,612	)		(2,324	)		—		13,558
Beginning cash and cash equivalents		858			13,896			12,067			—		26,821

Ending cash and cash equivalents	$	33,352		$	(2,716	)	$	9,743		$	—	$	40,379


	Year Ended December 31, 2008
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations		Consolidated
Cash flows from operating activities:	$	98,637		$	71,444		$	16,554		$	—	$	186,635

Cash flows from investing activities:
Acquisition of production services business of WEDGE		(313,621	)		—			—			—		(313,621	)
Acquisition of production services business of Competition		(26,772	)		—			—			—		(26,772	)
Acquisition of other production services businesses		(9,301	)		—			—			—		(9,301	)
Purchases of property and equipment		(1,831	)		(133,598	)		(12,026	)		—		(147,455	)
Purchase of auction rate securities, net		(15,900	)		—			—			—		(15,900	)
Proceeds from sale of property and equipment		—			4,008			—			—		4,008
Proceeds from insurance recoveries		—			3,426			—			—		3,426

		(367,425	)		(126,164	)		(12,026	)		—		(505,615	)

Cash flows from financing activities:
Debt repayments		(87,305	)		(462	)		—			—		(87,767	)
Proceeds from issuance of debt		359,400			—			—			—		359,400
Debt issuance costs		(3,319	)		—			—			—		(3,319	)
Proceeds from exercise of options		784			—			—			—		784

		269,560			(462	)		—			—		269,098

Net increase (decrease) in cash and cash equivalents		772			(55,182	)		4,528			—		(49,882	)
Beginning cash and cash equivalents		86			69,078			7,539			—		76,703

Ending cash and cash equivalents	$	858		$	13,896		$	12,067		$	—	$	26,821

Item 9.

Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

Not applicable.

Item 9A.

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 December 31, 2010, 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 December 31, 2010 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Management’s Report on Internal Control Over Financial Reporting

The management of Pioneer Drilling Company is responsible for establishing and maintaining adequate internal control over financial reporting. Pioneer Drilling Company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that: (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of Pioneer Drilling Company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Pioneer Drilling Company’s management assessed the effectiveness of Pioneer Drilling Company’s internal control over financial reporting as of December 31, 2010. In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework. Based on our assessment we have concluded that, as of December 31, 2010, Pioneer Drilling Company’s internal control over financial reporting was effective based on those criteria.

KPMG LLP, the independent registered public accounting firm that audited the consolidated financial statements of Pioneer Drilling Company included in this Annual Report on Form 10-K, has issued an attestation report on the effectiveness of Pioneer Drilling Company’s internal control over financial reporting as of December 31, 2010. This report appears on page 62.

Item 9B.

Other Information

Not applicable.

100

PART III

In Items 10, 11, 12, 13 and 14 below, we are incorporating by reference the information we refer to in those Items from the definitive proxy statement for our 2011 Annual Meeting of Shareholders. We intend to file that definitive proxy statement with the SEC on or about April 8, 2011.

Item 10.

Directors, Executive Officers and Corporate Governance

Please see the information appearing under the headings “Proposal 1—Election of Directors,” “Executive Officers,” “Information Concerning Meetings and Committees of the Board of Directors,” “Code of Conduct and Ethics” and “Section 16(a) Beneficial Ownership Reporting Compliance” in the definitive proxy statement for our 2011 Annual Meeting of Shareholders for the information this Item 10 requires.

Item 11.

Executive Compensation

Please see the information appearing under the headings “Compensation Discussion and Analysis,” “Compensation of Directors,” “Compensation of Executive Officers,” “Compensation Committee Interlocks and Insider Participation” and “Compensation Committee Report” in the definitive proxy statement for our 2011 Annual Meeting of Shareholders for the information this Item 11 requires.

Item 12.

Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters

Please see the information appearing under the headings “Equity Compensation Plan Information” and “Security Ownership of Certain Beneficial Owners and Management” in the definitive proxy statement for our 2011 Annual Meeting of Shareholders for the information this Item 12 requires.

Item 13.

Certain Relationships and Related Transactions, and Director Independence

Please see the information appearing under the headings “Proposal 1—Election of Directors” and “Certain Relationships and Related Transactions” in the definitive proxy statement for our 2011 Annual Meeting of Shareholders for the information this Item 13 requires.

Item 14.

Principal Accountant Fees and Services

Please see the information appearing under the heading “Proposal 2—Ratification of Appointment of Independent Auditors” in the definitive proxy statement for our 2011 Annual Meeting of Shareholders for the information this Item 14 requires.

101

PART IV

Item 15.

Exhibits and Financial Statement Schedules

(1) Financial Statements.

See Index to Consolidated Financial Statements on page 61.

Financial Statement Schedules

No financial statement schedules are submitted because either they are inapplicable or because the required information is included in the consolidated financial statements or notes thereto.

(3) Exhibits. The following exhibits are filed as part of this report:


Exhibit Number		Description
2.1*	-	Securities Purchase Agreement, dated January 31, 2008, by and among Pioneer Drilling Company, WEDGE Group Incorporated, WEDGE Energy Holdings, L.L.C., WEDGE Oil & Gas Services, L.L.C., Timothy Daley, John Patterson and Patrick Grissom (Form 8-K dated February 1, 2008 (File No. 1-8182, Exhibit 2.1)).

2.2*	-	Letter Agreement, dated February 29, 2008, amending the Securities Purchase Agreement, dated January 31, 2008, by and among Pioneer Drilling Company, WEDGE Group Incorporated, WEDGE Energy Holdings, L.L.C., WEDGE Oil & Gas Services, L.L.C., Timothy Daley, John Patterson and Patrick Grissom (Form 8-K dated March 3, 2008 (File No. 1-8182, Exhibit 2.1)).

3.1*	-	Restated Articles of Incorporation of Pioneer Drilling Company (Form 10-K for the year ended December 31, 2008 (File No. 1-8182, Exhibit 3.1)).

3.2*	-	Amended and Restated Bylaws of Pioneer Drilling Company (Form 8-K dated December 15, 2008 (File No. 1-8182, Exhibit 3.1)).

4.1*	-	Form of Certificate representing Common Stock of Pioneer Drilling Company (Form S-8 filed November 18, 2003 (Reg. No. 333-110569, Exhibit 4.3)).

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)).

10.1*	-	Purchase Agreement, dated March 4, 2010, by and among Pioneer Drilling Company, the subsidiary guarantors party thereto and the initial purchasers party thereto (Form 8-K dated March 5, 2010 (File No. 1-8182, Exhibit 10.1)).

10.2*	-	Pioneer Drilling Company 2007 Incentive Plan Form of Long-Term Incentive Cash Award Agreement (Form 10-Q dated August 5, 2010 (File No. 1-8182, Exhibit 10.1)).

10.3+*	-	Pioneer Drilling Company 2007 Incentive Plan Form of Long-Term Incentive Cash Award Agreement (Form 10-Q dated August 5, 2010 (File No. 1-8182, Exhibit 10.2)).

10.4+*	-	Pioneer Drilling Company 2007 Incentive Plan Form of Long-Term Incentive Restricted Stock Award Agreement (Form 10-Q dated August 5, 2010 (File No. 1-8182, Exhibit 10.3)).

10.5+*	-	Pioneer Drilling Company 2007 Incentive Plan Form of Restricted Stock Unit Agreement (Form 10-Q dated August 5, 2010 (File No. 1-8182, Exhibit 10.4)).

102


Exhibit Number		Description
10.6+*	-	Pioneer Drilling Services, Ltd. Annual Incentive Compensation Plan dated August 5, 2005 (Form 8-K dated August 5, 2005 (File No. 1-8182, Exhibit 10.1)).

10.7+*		Pioneer Drilling Company Amended and Restated Key Executive Severance Plan dated December 10, 2007 (Form 10-Q for the quarter ended March 31, 2008 (File No. 1-8182, Exhibit 10.4)).

10.8+*	-	Pioneer Drilling Company’s 1995 Stock Plan and form of Stock Option Agreement (Form 10-K for the year ended March 31, 2001 (File No. 1-8182, Exhibit 10.5)).

10.9+*	-	Pioneer Drilling Company’s 1999 Stock Plan and form of Stock Option Agreement (Form 10-K for the year ended March 31, 2001 (File No. 1-8182, Exhibit 10.7)).

10.10+*	-	Pioneer Drilling Company 2003 Stock Plan (Form S-8 filed November 18, 2003 (File No. 333-110569, Exhibit 4.4)).

10.11+*	-	Amended and Restated Pioneer Drilling Company 2007 Incentive Plan adopted May 15, 2009 (Definitive Proxy Statement on Schedule 14A, filed April 10, 2009 (File No. 1-8182, Appendix A)).

10.12+*	-	Pioneer Drilling Company 2007 Incentive Plan Form of Stock Option Agreement (Form 8-K dated September 4, 2008 (File No. 1-8182, Exhibit 10.1)).

10.13+*	-	Pioneer Drilling Company 2007 Incentive Plan Form of Employee Restricted Stock Award Agreement (Form 8-K dated September 4, 2008 (File No. 1-8182, Exhibit 10.2)).

10.14+*	-	Pioneer Drilling Company 2007 Incentive Plan Form of Non-Employee Director Restricted Stock Award Agreement (Form 8-K dated September 4, 2008 (File No. 1-8182, Exhibit 10.3)).

10.15+*	-	Pioneer Drilling Company Form of Indemnification Agreement (Form 8-K dated August 8, 2007 (File No. 1-8182, Exhibit 10.1)).

10.16+*	-	Pioneer Drilling Company Employee Relocation Policy Executive Officers – Package A (Form 8-K dated August 8, 2007 (File No. 1-8182, Exhibit 10.3)).

10.17*	-	Credit Agreement, dated February 29, 2008, among Pioneer Drilling Company, as Borrower, and Wells Fargo Bank, N.A., as administrative agent, issuing lender, swing line lender and co-lead arranger, Fortis Bank SA/NV, New York Branch, as co-lead arranger, and each of the other parties listed therein (Form 8-K dated March 3, 2008 (File No. 1-8182, Exhibit 10.1)).

10.18*	-	First Amendment to Credit Agreement, dated as of October 5, 2009, among Pioneer Drilling Company, the lenders party thereto, and Wells Fargo Bank, N.A., as administrative agent, issuing lender and swing line lender (Form 8-K dated October 6, 2009 (File No. 1-8182, Exhibit 10.1))

10.19*	-	Waiver Agreement, dated as of June 9, 2008, among Pioneer Drilling Company, the guarantors party thereto, Wells Fargo Bank, N.A., as administrative agent, issuing lender and swing line lender, and each of the other financial institutions party thereto (Form 8-K dated June 11, 2008 (File No. 1-8182, Exhibit 10.1)).

10.20*	-	Second Amendment to Credit Agreement, dated as of February 23, 2010, among Pioneer Drilling Company, the lenders party thereto, and Wells Fargo Bank, N.A., as administrative agent, issuing lender and swing line lender (Form 8-K dated February 23, 2010 (File No. 1-8182, Exhibit 10.1)).

10.21+*	-	Employment Letter, effective March 1, 2008, from Pioneer Drilling Company to Joseph B. Eustace (Form 8-K dated March 5, 2008 (File No. 1-8182, Exhibit 10.1)).

10.22+*	-	Confidentiality and Non-Competition Agreement, dated February 29, 2008, by and between Pioneer Drilling Company, Pioneer Production Services, Inc. and Joe Eustace (Form 8-K dated March 5, 2008 (File No. 1-8182, Exhibit 10.2)).

103


Exhibit Number		Description
10.24+*	-	Employment Letter Agreement, effective January 7, 2009, from Pioneer Drilling Company to Lorne E. Phillips (Form 8-K dated January 14, 2009 (File No. 1-8182, Exhibit 10.1)).

21.1	-	Subsidiaries of Pioneer Drilling Company.

23.1	-	Consent of Independent Registered Public Accounting Firm.

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 (Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code).

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 (Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code).

*	Incorporated by reference to the filing indicated.

+	Management contract or compensatory plan or arrangement.

104

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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 DRILLING COMPANY

February 17, 2011		BY: /S/ WM. STACY LOCKE
		Wm. Stacy Locke Chief Executive Officer and President

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.


Signature	Title	Date
/S/ DEAN A. BURKHARDT Dean A. Burkhardt	Chairman	February 17, 2011

/S/ WM. STACY LOCKE Wm. Stacy Locke	President, Chief Executive Officer and Director (Principal Executive Officer)	February 17, 2011

/S/ LORNE E. PHILLIPS Lorne E. Phillips	Executive Vice President and Chief Financial Officer	February 17, 2011

/S/ C. JOHN THOMPSON C. John Thompson	Director	February 17, 2011

/S/ JOHN MICHAEL RAUH John Michael Rauh	Director	February 17, 2011

/S/ SCOTT D. URBAN Scott D. Urban	Director	February 17, 2011

105


Exhibit Number		Description
2.1*	-	Securities Purchase Agreement, dated January 31, 2008, by and among Pioneer Drilling Company, WEDGE Group Incorporated, WEDGE Energy Holdings, L.L.C., WEDGE Oil & Gas Services, L.L.C., Timothy Daley, John Patterson and Patrick Grissom (Form 8-K dated February 1, 2008 (File No. 1-8182, Exhibit 2.1)).

2.2*	-	Letter Agreement, dated February 29, 2008, amending the Securities Purchase Agreement, dated January 31, 2008, by and among Pioneer Drilling Company, WEDGE Group Incorporated, WEDGE Energy Holdings, L.L.C., WEDGE Oil & Gas Services, L.L.C., Timothy Daley, John Patterson and Patrick Grissom (Form 8-K dated March 3, 2008 (File No. 1-8182, Exhibit 2.1)).

3.1*	-	Restated Articles of Incorporation of Pioneer Drilling Company (Form 10-K for the year ended December 31, 2008 (File No. 1-8182, Exhibit 3.1)).

3.2*	-	Amended and Restated Bylaws of Pioneer Drilling Company (Form 8-K dated December 15, 2008 (File No. 1-8182, Exhibit 3.1)).

4.1*	-	Form of Certificate representing Common Stock of Pioneer Drilling Company (Form S-8 filed November 18, 2003 (Reg. No. 333-110569, Exhibit 4.3)).

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)).

10.1*	-	Purchase Agreement, dated March 4, 2010, by and among Pioneer Drilling Company, the subsidiary guarantors party thereto and the initial purchasers party thereto (Form 8-K dated March 5, 2010 (File No. 1-8182, Exhibit 10.1)).

10.2*	-	Pioneer Drilling Company 2007 Incentive Plan Form of Long-Term Incentive Cash Award Agreement (Form 10-Q dated August 5, 2010 (File No. 1-8182, Exhibit 10.1)).

10.3+*	-	Pioneer Drilling Company 2007 Incentive Plan Form of Long-Term Incentive Cash Award Agreement (Form 10-Q dated August 5, 2010 (File No. 1-8182, Exhibit 10.2)).

10.4+*	-	Pioneer Drilling Company 2007 Incentive Plan Form of Long-Term Incentive Restricted Stock Award Agreement (Form 10-Q dated August 5, 2010 (File No. 1-8182, Exhibit 10.3)).

10.5+*	-	Pioneer Drilling Company 2007 Incentive Plan Form of Restricted Stock Unit Agreement (Form 10-Q dated August 5, 2010 (File No. 1-8182, Exhibit 10.4)).

10.6+*	-	Pioneer Drilling Services, Ltd. Annual Incentive Compensation Plan dated August 5, 2005 (Form 8-K dated August 5, 2005 (File No. 1-8182, Exhibit 10.1)).

10.7+*		Pioneer Drilling Company Amended and Restated Key Executive Severance Plan dated December 10, 2007 (Form 10-Q for the quarter ended March 31, 2008 (File No. 1-8182, Exhibit 10.4)).

10.8+*	-	Pioneer Drilling Company’s 1995 Stock Plan and form of Stock Option Agreement (Form 10-K for the year ended March 31, 2001 (File No. 1-8182, Exhibit 10.5)).

10.9+*	-	Pioneer Drilling Company’s 1999 Stock Plan and form of Stock Option Agreement (Form 10-K for the year ended March 31, 2001 (File No. 1-8182, Exhibit 10.7)).

106


Exhibit Number		Description
10.10+*	-	Pioneer Drilling Company 2003 Stock Plan (Form S-8 filed November 18, 2003 (File No. 333-110569, Exhibit 4.4)).

10.11+*	-	Amended and Restated Pioneer Drilling Company 2007 Incentive Plan adopted May 15, 2009 (Definitive Proxy Statement on Schedule 14A, filed April 10, 2009 (File No. 1-8182, Appendix A)).

10.12+*	-	Pioneer Drilling Company 2007 Incentive Plan Form of Stock Option Agreement (Form 8-K dated September 4, 2008 (File No. 1-8182, Exhibit 10.1)).

10.13+*	-	Pioneer Drilling Company 2007 Incentive Plan Form of Employee Restricted Stock Award Agreement (Form 8-K dated September 4, 2008 (File No. 1-8182, Exhibit 10.2)).

10.14+*	-	Pioneer Drilling Company 2007 Incentive Plan Form of Non-Employee Director Restricted Stock Award Agreement (Form 8-K dated September 4, 2008 (File No. 1-8182, Exhibit 10.3)).

10.15+*	-	Pioneer Drilling Company Form of Indemnification Agreement (Form 8-K dated August 8, 2007 (File No. 1-8182, Exhibit 10.1)).

10.16+*	-	Pioneer Drilling Company Employee Relocation Policy Executive Officers – Package A (Form 8-K dated August 8, 2007 (File No. 1-8182, Exhibit 10.3)).

10.17*	-	Credit Agreement, dated February 29, 2008, among Pioneer Drilling Company, as Borrower, and Wells Fargo Bank, N.A., as administrative agent, issuing lender, swing line lender and co-lead arranger, Fortis Bank SA/NV, New York Branch, as co-lead arranger, and each of the other parties listed therein (Form 8-K dated March 3, 2008 (File No. 1-8182, Exhibit 10.1)).

10.18*	-	First Amendment to Credit Agreement, dated as of October 5, 2009, among Pioneer Drilling Company, the lenders party thereto, and Wells Fargo Bank, N.A., as administrative agent, issuing lender and swing line lender (Form 8-K dated October 6, 2009 (File No. 1-8182, Exhibit 10.1))

10.19*	-	Waiver Agreement, dated as of June 9, 2008, among Pioneer Drilling Company, the guarantors party thereto, Wells Fargo Bank, N.A., as administrative agent, issuing lender and swing line lender, and each of the other financial institutions party thereto (Form 8-K dated June 11, 2008 (File No. 1-8182, Exhibit 10.1)).

10.20*	-	Second Amendment to Credit Agreement, dated as of February 23, 2010, among Pioneer Drilling Company, the lenders party thereto, and Wells Fargo Bank, N.A., as administrative agent, issuing lender and swing line lender (Form 8-K dated February 23, 2010 (File No. 1-8182, Exhibit 10.1)).

10.21+*	-	Employment Letter, effective March 1, 2008, from Pioneer Drilling Company to Joseph B. Eustace (Form 8-K dated March 5, 2008 (File No. 1-8182, Exhibit 10.1)).

10.22+*	-	Confidentiality and Non-Competition Agreement, dated February 29, 2008, by and between Pioneer Drilling Company, Pioneer Production Services, Inc. and Joe Eustace (Form 8-K dated March 5, 2008 (File No. 1-8182, Exhibit 10.2)).

10.24+*	-	Employment Letter Agreement, effective January 7, 2009, from Pioneer Drilling Company to Lorne E. Phillips (Form 8-K dated January 14, 2009 (File No. 1-8182, Exhibit 10.1)).

21.1	-	Subsidiaries of Pioneer Drilling Company.

23.1	-	Consent of Independent Registered Public Accounting Firm.

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.

107


Exhibit Number		Description
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 (Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code).

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 (Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code).

*	Incorporated by reference to the filing indicated.

+	Management contract or compensatory plan or arrangement.

108