UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

______________________________________________ 

FORM 10-K

______________________________________________ 

(Mark one)

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

For the fiscal year ended December 31, 2011

or

¨ 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  þ No  ¨

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

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, 2011) was approximately $822.6 million.

As of February 10, 2012, there were 61,828,317 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 2012 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	17
Item 1B.	Unresolved Staff Comments	27
Item 2.	Properties	27
Item 3.	Legal Proceedings	27
	PART II
Item 5.	Market for Registrant’s Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities	28
Item 6.	Selected Financial Data	30
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	31
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	50
Item 8.	Financial Statements and Supplementary Data	51
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	85
Item 9A.	Controls and Procedures	85
Item 9B.	Other Information	85
	PART III
Item 10.	Directors, Executive Officers and Corporate Governance	86
Item 11.	Executive Compensation	86
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters	86
Item 13.	Certain Relationships and Related Transactions, and Director Independence	86
Item 14.	Principal Accountant Fees and Services	86
	PART IV
Item 15.	Exhibits and Financial Statement Schedules	87

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 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, wireline units and coiled tubing units within the industry;

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

• the continued availability of qualified personnel;

• the success or failure of our acquisition strategy, including our ability to finance acquisitions, effectively integrate acquired businesses 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.”

1

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 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. Since September 1999, we have significantly expanded our drilling rig fleet through acquisitions and through the construction of rigs from new and used components. In March 2008, we significantly expanded our service offerings with the acquisition of two production services businesses, which provide well services, wireline services and fishing and rental services. We have continued to invest in the growth of all our service offerings through acquisitions and organic growth. On December 31, 2011, we acquired Go-Coil, LLC ("Go-Coil"), a coiled tubing service company based in Maurice, Louisiana, to complement our existing production services offerings. 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 10, 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 64 drilling rigs in the following locations:

Drilling Division Locations	Rig Count
South Texas	15
East Texas	5
West Texas	18
North Dakota	9
Utah	4
Appalachia	5
Colombia	8

Drilling revenues and rig utilization steadily improved during 2010 and 2011, primarily due to increased demand for drilling services in domestic shale plays and oil or liquid rich regions. We capitalized on this trend by moving drilling rigs in our fleet to these higher demand regions from lower demand regions such as our Oklahoma, North Texas and East Texas drilling division locations which have conventional natural gas production. During 2010 and 2011, we moved drilling rigs into our North Dakota and Appalachia drilling division locations, both of which are shale regions, and in early 2011, we established our West Texas drilling division location where we currently have 18 drilling rigs operating.

In September 2011, we evaluated the drilling rigs in our fleet that had remained idle and decided to place six mechanical drilling rigs as held for sale as of September 30, 2011. Four of the held for sale drilling rigs were previously assigned to our Oklahoma drilling division location and the remaining two drilling rigs were previously assigned to our East Texas drilling division location. Sales of all six mechanical drilling rigs were completed by mid November 2011. In addition, we decided to retire another drilling rig from our fleet that was previously assigned to our Utah drilling division location, with most of its components to be used for spare equipment. We recognized an impairment charge of $0.5 million in September 2011 in association with our decision to dispose of these seven drilling rigs.

At December 31, 2011, we have 64 drilling rigs in our fleet. We currently have term contracts for ten new-build AC drilling rigs that are fit for purpose for domestic shale plays, five of which we estimate will begin working in the first half of 2012, with the remaining five to begin operating by the end of 2012. As of February 10, 2012, 55 drilling rigs are operating under drilling contracts, 44 of which are under term contracts. We have nine drilling rigs that are idle, three of which are under contract to begin working in the first quarter of 2012. We are actively marketing all our idle drilling rigs.

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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, coiled tubing 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 15 well service rigs during 2011 and two additional well service rigs in early 2012, resulting in a total of 91 well service rigs in 12 locations as of February 10, 2012. Our well service rig fleet consists of eighty-one 550 horsepower rigs, nine 600 horsepower rigs, and one 400 horsepower rig. All our well service rigs are currently operating or are being actively marketed, with January2012 utilization of approximately 86%. We plan to add another 13 well service rigs to our fleet during 2012.

• 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 2011 and four additional wireline units in early 2012, resulting in a total of 109 wireline units in 24 locations as of February 10, 2012. We plan to add another 18 wireline units to our fleet during 2012.

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

• 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, 2011 our fishing and rental tools have a gross book value of $15.1 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.

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From 2004 through 2008, domestic exploration and production spending increased as oil and natural gas prices increased. From late 2008 and into late 2009, there was 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.

With increasing oil and natural gas prices during 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. Increased natural gas production in the U.S. shale regions continues to depress natural gas prices, but oil prices continued to increase during 2011, resulting in continued increases in exploration and production spending during 2011, as compared to 2010. As a result, we experienced continued increases in industry rig utilization and revenue rates during 2011, as compared to 2010. We expect continued modest increases in exploration and production spending for 2012, which we expect will result in modest increases in industry equipment utilization and revenue rates in 2012, as compared to 2011. However, if oil prices remain steady but natural gas prices further decline to historically low levels for the remainder of 2012, then industry equipment utilization and revenue rates could decrease.

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.

On February 10, 2012, the spot price for West Texas Intermediate crude oil was $98.67, the spot price for Henry Hub natural gas was $2.51 and the Baker Hughes U.S. land rig count was 1,932, a 14%increase from 1,696 on February 4, 2011. 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:

	Year ended December 31,
	2011		2010		2009		2008		2007
Oil (West Texas Intermediate)	$	94.94	$	79.39	$	61.81	$	99.86	$	72.71
Natural Gas (Henry Hub)	$	3.95	$	4.35	$	3.85	$	8.81	$	6.90
U.S. Land Rig Count	1,829		1,493		1,035		1,792		1,670
U.S. Well Service Rig Count	2,075		1,854		1,735		2,514		2,388

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 primarily in oil prices have caused increases in exploration and production spending and the corresponding increases in drilling and well services activities are reflected by increases in the U.S. land rig counts and the U.S. well service rig counts in 2010 and 2011.

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.

4

Competitive Strengths

Our competitive strengths include:

• One of the Leading Providers in the Most Attractive Regions. Our 64 drilling rigs operate in many of the most attractive producing regions in the Americas, including the Bakken, Marcellus and Eagle Ford shales, and Permian and Uintah Basins, as well as Colombia. Our drilling rigs are located in seven 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 drilling 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 regions with oil-focused drilling, which reduces our relative exposure to changes in natural gas drilling activity.

• High Quality Assets. We have purchased 30 new-build drilling rigs since 2001, the majority of these constructed from 2004 to 2006, and currently have term contracts for ten new-build AC drilling rigs that are fit for purpose for domestic shale plays. The majority of our drilling rig fleet is fast moving and has preferred equipment such as more efficient and lower emission engines, rounded bottom mud tanks and matched horsepower mud pumps. Approximately 80% of our drilling rig fleet has a horsepower rating of over 1000 horsepower and the majority of our fleet is equipped with top drives, allowing us to pursue opportunities in shale plays, which typically require higher specification rigs than traditional areas. Approximately 64% of our production services assets have been built since 2007, and all but one of our well service rigs have at least 550 horsepower. 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. Our safety program called “Live Safe” focuses on creating an environment where everyone is committed to and recognizes the possibility of always working without incident or injury. We believe that by building strong relationships among our people we can achieve outstanding accomplishments. Our excellent safety record and reputation are critical to winning new business and expanding our relationships with existing customers. Our commitment to safety helps us to keep our employees safe and reduces our business risk.

• 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 EOG Resources, Inc., 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 14% of our 2011 consolidated revenues. No other single customer accounted for more than 11% of consolidated revenues during the same period. We believe our relationships with our customers are excellent and offer numerous opportunities for future growth.

5

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 and non-shale oil or liquid rich environments are increasingly important to domestic hydrocarbon production and not all drilling rigs are capable of successfully drilling in these unconventional opportunities. We are currently operating in unconventional areas in the Bakken, Marcellus and Eagle Ford shales and Permian and Uintah Basins, and we intend to add ten new-build drilling rigs that will be operating in the shale plays in 2012. We also intend to continue adding capacity to our wireline, coiled tubing, 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. As of February 10, 2012, approximately 87% of our working drilling rigs and 78% of our production services assets are operating on wells that are targeting or producing oil or liquids rich natural gas. 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 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. We currently have term contracts for ten new-build AC drilling rigs that are fit for purpose for domestic shale plays, five of which we estimate will begin working in the first half of 2012, with the remaining five to begin operating by the end of 2012. On December 31, 2011, we acquired the coiled tubing service company, Go-Coil, to complement our existing production services offerings. We have also significantly increased our other production services fleets with the addition of 21 wireline units and 15 well service rigs in 2011. We expect to add another 18 wireline units, 13 well service rigs and three coiled tubing units by the end of 2012.

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.

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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 both are 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 36 rigs (with three additional spare top drives available for installation), iron roughnecks in 49 rigs (with six additional spare iron roughnecks available for installation), walking/skidding systems in 16 rigs 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 significantly 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.

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

	Year ended December 31,
	2011		2010		2009		2008		2007
Average number of operating rigs for the period	69.3		71.0		70.7		67.4		66.1
Average utilization rate	73	%	59	%	41	%	89	%	89	%

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 10, 2012, we own a fleet of 54 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. 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. During periods of high rig demand, or for our newly constructed rigs, we enter into longer-term drilling contracts. Currently, we have contracts with terms of six months to four years in duration. As of February 10, 2012, we have 44 drilling rigs operating under term contracts. Of these 44 contracts, if not renewed at the end of their terms, 21 will expire by July 10, 2012, 22 will expire by February 10, 2013 and one will expire by February 10, 2014. We have term contracts for an additional three drilling rigs that we expect will begin operating in the first quarter of 2012 and we have ten term contracts for new-build AC drilling rigs, five of which we estimate will begin working in the first half of 2012, with the remaining five to begin operating by the end of 2012.

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 higher 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.

	Year ended December 31,
Types of Contracts	2011	2010	2009
Daywork	655	453	323
Turnkey	17	11	14
Footage	—	—	1
Total number of wells	672	464	338

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.

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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. Our well services rig fleet provides a range of 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.

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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 10, 2012, our fleet of well service rigs totaled 91 rigs. These rigs are located mostly in the Gulf Coast and ArkLaTex regions, though we also have 11 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 109 wireline units, as of February 10, 2012. We provide these services in Texas, Kansas, Colorado, Utah, Montana, North Dakota, Louisiana, Oklahoma, 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.

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

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, wireline units and coiled tubing units are mobile, during periods of heavy snow, ice or rain, we may not be able to move our equipment between locations.

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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, 2011
Ecopetrol	13.5	%
Whiting Petroleum Corporation	10.6	%
Talisman Energy USA, Inc.	3.6	%
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	%

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.

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.

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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, Superior Energy Services, Inc. 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 Hughes, 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 market for coiled tubing has increased due to the growth in deep well and horizontal drilling. Our primary competitors in the coiled tubing services market include Schlumberger Ltd., Baker Hughes, Halliburton Company and Superior Energy Services, Inc. In addition, numerous small companies compete in our coiled tubing services markets in the United States.

The fishing and rental tools market is fragmented compared to our other product lines. Companies that 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 in this area include Baker Hughes, Weatherford International, Basic Energy Services, Key Energy Services, Quail Tools (owned by Parker Drilling) and Knight Oil Tools.

The need for well servicing, wireline, coiled tubing, 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.”

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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 $76 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.

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Employees

We currently have approximately 3,330 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, wireline units and coiled tubing 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 through December 2020 with payments escalating from $29,839 per month in January 2012 to $42,635 per month in December 2020, for which the lease term is cancelable as early as December 2016 with applicable penalties.

We conduct our business operations through 82 other real estate locations in the United States (Texas, Oklahoma, Colorado, Utah, Montana, North Dakota, Pennsylvania, 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 10 of these real estate locations and the remaining 72 real estate locations are leased with payments ranging from $250 per month to $30,966 per month with non-cancelable lease terms expiring through August 2022.

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.

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.

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The U.S. Congress has from time to time considered legislation to reduce emissions of greenhouse gases, primarily through the development of greenhouse gas cap and trade programs. 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.

Based on these findings, in 2010 the EPA adopted two sets of regulations that restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act, including one that requires a reduction in emissions of greenhouse gases from motor vehicles and another that requires certain construction and operating permit reviews for greenhouse gas emissions from certain large stationary sources. The stationary source final rule addresses the permitting of greenhouse gas emissions from stationary sources under the Clean Air Act Prevention of Significant Deterioration construction and Title V operating permit programs, pursuant to which these permit programs have been "tailored" to apply to certain stationary sources of greenhouse gas emissions in a multi-step process, with the largest sources first subject to permitting. In addition, the EPA adopted rules requiring the monitoring and reporting of greenhouse gases from certain sources, including, among others, onshore oil and natural gas production facilities.

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.

Hydraulic fracturing is a commonly used process that involves injection of water, sand, and certain chemicals to fracture the hydrocarbon-bearing rock formation to allow flow of hydrocarbons into the wellbore. The federal Energy Policy Act of 2005 amended the Underground Injection Control provisions of the federal Safe Drinking Water Act (SDWA) to exclude certain hydraulic fracturing practices from the definition of "underground injection." The EPA has asserted regulatory authority over certain hydraulic fracturing activities involving diesel fuel and has begun the process of drafting guidance relating to such practices. In addition, repeal of the SDWA exclusion of hydraulic fracturing has been advocated by certain advocacy organizations and others in the public. Legislation has also been introduced before Congress to repeal the exemption for hydraulic fracturing from the SDWA, which would have the effect of allowing the EPA to promulgate new regulations and permitting requirements for hydraulic fracturing, and to require the disclosure of the chemical constituents of hydraulic fracturing fluids to a regulatory agency, which would make the information public via the Internet. Scrutiny of hydraulic fracturing activities continues in other ways, with the EPA having commenced a study of the potential environmental impacts of hydraulic fracturing, the initial results of which are expected to be available by late 2012 and the final results of which are expected in 2014. The U.S. Department of the Interior has also announced that it will propose regulations relating to the use of hydraulic fracturing techniques on public lands and disclosure of fracturing fluid constituents. In addition, some states and localities have adopted, and others are considering adopting, regulations or ordinances that could restrict hydraulic fracturing in certain circumstances, that would require, with some exceptions, disclosure of constituents of hydraulic fracturing fluids, or that would impose higher taxes, fees or royalties on natural gas production. Moreover, public debate over hydraulic fracturing and shale gas production has been increasing, and has resulted in delays of well permits in some areas.

Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition, including litigation, to oil and gas production activities using hydraulic fracturing techniques. Additional legislation or regulation could also lead to operational delays or increased operating costs in the production of oil and natural gas, including from the developing shale plays, incurred by our customers. The adoption of any federal, state or local laws or the implementation of regulations or ordinances restricting or increasing the costs of hydraulic fracturing cause a decrease in the completion of new oil and natural gas wells and an associated decrease in demand for our drilling and well servicing activities, any or all of which 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.

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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.

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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.

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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 and 2011, 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, coiled tubing units, and fishing and rental tools and 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. Currently, there are growing expectations of a possible downturn in the global economic environment in 2012, which could lead to a decline in oil and natural gas prices that would adversely affect our business. 

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.

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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.

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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 through acquisitions and through the construction of rigs from new and used components, and in March 2008, we significantly expanded our service offerings with the acquisition of two production services businesses, which provide well services, wireline services and fishing and rental services. On December 31, 2011, we acquired the coiled tubing services business of Go-Coil to complement our existing production services offerings.

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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.

Our indebtedness is primarily a result of the two production services businesses that we acquired in 2008, and more recently, the acquisition of Go-Coil in 2011. At December 31, 2011, our total debt balance of $419.6 million primarily consists of $417.7 million outstanding under our Senior Notes. As of December 31, 2011, our Revolving Credit Facility had a zero balance outstanding, with a current availability of $241.0 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, 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.

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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.

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The failure to comply with any of these restrictions or conditions 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 most of our drilling contracts are 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.

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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.

The U.S. Congress has from time to time considered legislation to reduce emissions of greenhouse gases, primarily through the development of greenhouse gas cap and trade programs. 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.

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Based on these findings, in 2010 the EPA adopted two sets of regulations that restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act, including one that requires a reduction in emissions of greenhouse gases from motor vehicles and another that requires certain construction and operating permit reviews for greenhouse gas emissions from certain large stationary sources. The stationary source final rule addresses the permitting of greenhouse gas emissions from stationary sources under the Clean Air Act Prevention of Significant Deterioration construction and Title V operating permit programs, pursuant to which these permit programs have been "tailored" to apply to certain stationary sources of greenhouse gas emissions in a multi-step process, with the largest sources first subject to permitting. In addition, the EPA adopted rules requiring the monitoring and reporting of greenhouse gases from certain sources, including, among others, onshore oil and natural gas production facilities.

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.

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.

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.

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.

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Federal and state legislative and regulatory initiatives related to hydraulic fracturing could result in operating restrictions or delays in the completion of oil and natural gas wells that may reduce demand for our drilling and well servicing activities and could adversely affect our financial position, results of operations and cash flows.

Hydraulic fracturing is a commonly used process that involves injection of water, sand, and certain chemicals to fracture the hydrocarbon-bearing rock formation to allow flow of hydrocarbons into the wellbore. The federal Energy Policy Act of 2005 amended the Underground Injection Control provisions of the federal Safe Drinking Water Act (SDWA) to exclude certain hydraulic fracturing practices from the definition of "underground injection." The EPA has asserted regulatory authority over certain hydraulic fracturing activities involving diesel fuel and has begun the process of drafting guidance relating to such practices. In addition, repeal of the SDWA exclusion of hydraulic fracturing has been advocated by certain advocacy organizations and others in the public. Legislation has also been introduced before Congress to repeal the exemption for hydraulic fracturing from the SDWA, which would have the effect of allowing the EPA to promulgate new regulations and permitting requirements for hydraulic fracturing, and to require the disclosure of the chemical constituents of hydraulic fracturing fluids to a regulatory agency, which would make the information public via the Internet. Scrutiny of hydraulic fracturing activities continues in other ways, with the EPA having commenced a study of the potential environmental impacts of hydraulic fracturing, the initial results of which are expected to be available by late 2012 and the final results of which are expected in 2014. The U.S. Department of the Interior has also announced that it will propose regulations relating to the use of hydraulic fracturing techniques on public lands and disclosure of fracturing fluid constituents. In addition, some states and localities have adopted, and others are considering adopting, regulations or ordinances that could restrict hydraulic fracturing in certain circumstances, that would require, with some exceptions, disclosure of constituents of hydraulic fracturing fluids, or that would impose higher taxes, fees or royalties on natural gas production. Moreover, public debate over hydraulic fracturing and shale gas production has been increasing, and has resulted in delays of well permits in some areas.

Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition, including litigation, to oil and gas production activities using hydraulic fracturing techniques. Additional legislation or regulation could also lead to operational delays or increased operating costs in the production of oil and natural gas, including from the developing shale plays, incurred by our customers. The adoption of any federal, state or local laws or the implementation of regulations or ordinances restricting or increasing the costs of hydraulic fracturing could cause a decrease in the completion of new oil and natural gas wells and an associated decrease in demand for our drilling and well servicing activities, any or all of which could adversely affect our financial position, results of operations and cash flows.

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.

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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.

Item 4. Mine Safety Disclosures

Not Applicable.

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PART II

Item 5. Market for Registrant’s Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities

As of February 10, 2012, 61,828,317 shares of our common stock were outstanding, held by 488 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, 2011
First Quarter	$	8.24	$	13.80
Second Quarter	11.89		16.17
Third Quarter	7.18		17.70
Fourth Quarter	6.41		11.78
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

The last reported sales price for our common stock on the NYSE Amex on February 10, 2012 was $9.29 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.

We did not make any unregistered sales of equity securities during the quarter ended December 31, 2011.

Period	Total Number of Shares Purchased  (1)	Average Price Paid per Share (2)	Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs
October 1 - October 31	—	—	—	—
November 1 - November 30	—	—	—	—
December 1 - December 31	32,460	$8.98	—	—
Total	32,460	$8.98	—	—

(1) The shares indicated consist of shares of our common stock tendered by employees to the Company during the three months ended December 31, 2011, to satisfy the employees’ tax withholding obligations in connection with the exercise of nonqualified stock options, which we repurchased based on the fair market value on the date the relevant transaction occurred.

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

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Performance Graph

The following graph compares, for the periods from December 31, 2006 to December 31, 2011, the cumulative total shareholder return on our common stock with the cumulative total return on the companies that comprise the AMEX Composite Index and both an old and new peer group index that include five and six companies, respectively, that provide contract drilling services and / or production services. The comparison assumes that $100 was invested on December 31, 2006 in our common stock, the companies that compose the AMEX Composite Index and the companies that compose the old and new peer group indexes, and further assumes all dividends were reinvested.

The companies that comprise the old peer group index are Patterson-UTI Energy, Inc., Nabors Industries Ltd., Bronco Drilling Company, Precision Drilling Trust and Key Energy Services. During 2011, Bronco Drilling Company was acquired by a competing energy company and Union Drilling, Inc. and Basic Energy Services, Inc. were added to the peer group. Therefore, the companies that comprise the new peer group index are Patterson-UTI Energy, Inc., Nabors Industries Ltd., Union Drilling, Inc., Basic Energy Services, Inc., Precision Drilling Trust and Key Energy Services. For comparative purposes, both the old and new peer group indexes are reflected in the following performance graph.

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Item 6. Selected Financial Data

The following information derives from our audited financial statements. This information should be reviewed 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 Group Incorporated ("WEDGE") and Prairie Investors d/b/a Competition Wireline ("Competition"), effective March 1, 2008, affect the comparability from period to period of our historical results.

	Year ended December 31,												Nine months ended December 31, 2007
	2011(1)			2010(1)			2009(1)			2008(1)(2)
	(In thousands, except per share amounts)
Statement of Operations Data:
Revenues	$	715,941		$	487,210		$	325,537		$	610,884		$	313,884
Income (loss) from operations	57,458			(18,572		)	(31,840		)	(43,954		)	55,260
Income (loss) before income taxes	20,833			(47,558		)	(40,172		)	(56,688		)	57,774
Net earnings (loss) applicable to common stockholders	11,177			(33,261		)	(23,215		)	(62,745		)	39,645
Earnings (loss) per common share-basic	$	0.19		$	(0.62	)	$	(0.46	)	$	(1.26	)	$	0.80
Earnings (loss) per common share-diluted	$	0.19		$	(0.62	)	$	(0.46	)	$	(1.26	)	$	0.79
Other Financial Data:
Net cash provided by operating activities	$	144,879		$	98,351		$	123,313		$	186,635		$	115,455
Net cash used in investing activities	(307,484		)	(129,481		)	(113,909		)	(505,615		)	(123,858		)
Net cash provided by financing activities	226,791			12,762			4,154			269,098			161
Capital expenditures	237,787			135,151			110,453			148,096			128,038

	As of December 31,
	2011(1)		2010(1)		2009(1)		2008(1)		2007
	(In thousands)
Balance Sheet Data:
Working capital	$	129,932	$	76,142	$	90,336	$	64,372	$	99,807
Property and equipment, net	793,956		655,508		637,022		627,562		417,022
Long-term debt and capital lease obligations, excluding current installments	418,728		279,530		258,073		262,115		—
Shareholders’ equity	510,445		396,333		421,448		414,118		471,072
Total assets	1,172,754		841,343		824,955		824,479		560,212

(1) The statement of operations data and other financial data for the years ended December 31, 2011, 2010, 2009 and 2008 and the balance sheet data as of December 31, 2011, 2010, 2009 and 2008 include the impact of the acquisitions of WEDGE and Competition, both of which occurred on March 1, 2008.

(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.

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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 companies, the highly competitive nature of our business, the availability, terms and deployment of capital, our ability to effectively integrate acquired businesses, future compliance with covenants under our senior secured revolving credit facility and our senior notes, 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. Since September 1999, we have significantly expanded our drilling rig fleet through acquisitions and through the construction of rigs from new and used components. In March 2008, we significantly expanded our service offerings with the acquisition of two production services businesses, which provide well services, wireline services and fishing and rental services. We have continued to invest in the growth of all our service offerings through acquisitions and organic growth. On December 31, 2011, we acquired Go-Coil, LLC ("Go-Coil"), a coiled tubing service company based in Maurice, Louisiana, to complement our existing production services offerings. 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 10, 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 64 drilling rigs in the following locations:

Drilling Division Locations	Rig Count
South Texas	15
East Texas	5
West Texas	18
North Dakota	9
Utah	4
Appalachia	5
Colombia	8

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Drilling revenues and rig utilization steadily improved during 2010 and 2011, primarily due to increased demand for drilling services in domestic shale plays and oil or liquid rich regions. We capitalized on this trend by moving drilling rigs in our fleet to these higher demand regions from lower demand regions such as our Oklahoma, North Texas and East Texas drilling division locations which have conventional natural gas production. During 2010 and 2011, we moved drilling rigs into our North Dakota and Appalachia drilling division locations, both of which are shale regions, and in early 2011, we established our West Texas drilling division location where we currently have 18 drilling rigs operating.

In September 2011, we evaluated the drilling rigs in our fleet that had remained idle and decided to place six mechanical drilling rigs as held for sale as of September 30, 2011. Four of the held for sale drilling rigs were previously assigned to our Oklahoma drilling division location and the remaining two drilling rigs were previously assigned to our East Texas drilling division location. Sales of all six mechanical drilling rigs were completed by mid November 2011. In addition, we decided to retire another drilling rig from our fleet that was previously assigned to our Utah drilling division location, with most of its components to be used for spare equipment. We recognized an impairment charge of $0.5 million in September 2011 in association with our decision to dispose of these seven drilling rigs.

At December 31, 2011, we have 64 drilling rigs in our fleet. We currently have term contracts for ten new-build AC drilling rigs that are fit for purpose for domestic shale plays, five of which we estimate will begin working in the first half of 2012, with the remaining five to begin operating by the end of 2012. As of February 10, 2012, 55 drilling rigs are operating under drilling contracts, 44 of which are under term contracts. We have nine drilling rigs that are idle, three of which are under contract to begin working in the first quarter of 2012. We are actively marketing all our idle drilling rigs.

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, coiled tubing, 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 15 well service rigs during 2011 and two additional well service rigs in early 2012, resulting in a total of 91 well service rigs in 12 locations as of February 10, 2012. Our well service rig fleet consists of eighty-one 550 horsepower rigs, nine 600 horsepower rigs, and one 400 horsepower rig. All our well service rigs are currently operating or are being actively marketed, with January 2012 utilization of approximately 86%. We plan to add another 13 well service rigs to our fleet during 2012.

• 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 2011 and four additional wireline units in early 2012, resulting in a total of 109 wireline units in 24 locations as of February 10, 2012. We plan to add another 18 wireline units to our fleet during 2012.

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

• 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, 2011 our fishing and rental tools have a gross book value of $15.1 million.

Market Conditions in Our Industry

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. From late 2008 and into late 2009, there was 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.

With increasing oil and natural gas prices during 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. Increased natural gas production in the U.S. shale regions continues to depress natural gas prices, but oil prices continued to increase during 2011, resulting in continued increases in exploration and production spending during 2011, as compared to 2010. As a result, we experienced continued increases in industry rig utilization and revenue rates during 2011, as compared to 2010. We expect continued modest increases in exploration and production spending for 2012, which we expect will result in modest increases in industry equipment utilization and revenue rates in 2012, as compared to 2011. However, if oil prices remain steady but natural gas prices further decline to historically low levels for the remainder of 2012, then industry equipment utilization and revenue rates could decrease.

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.

On February 10, 2012, the spot price for West Texas Intermediate crude oil was $98.67, the spot price for Henry Hub natural gas was $2.51 and the Baker Hughes U.S. land rig count was 1,932, a 14%increase from 1,696 on February 4, 2011. 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:

	Year ended December 31,
	2011		2010		2009		2008		2007
Oil (West Texas Intermediate)	$	94.94	$	79.39	$	61.81	$	99.86	$	72.71
Natural Gas (Henry Hub)	$	3.95	$	4.35	$	3.85	$	8.81	$	6.90
U.S. Land Rig Count	1,829		1,493		1,035		1,792		1,670
U.S. Well Service Rig Count	2,075		1,854		1,735		2,514		2,388

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 primarily in oil prices have caused increases in exploration and production spending and the corresponding increases in drilling and well services activities are reflected by increases in the U.S. land rig counts and the U.S. well service rig counts in 2010 and 2011.

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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.

Liquidity and Capital Resources

Sources of Capital Resources

Our principal liquidity requirements have been for working capital needs, capital expenditures and selective acquisitions. Our principal sources of liquidity consist of cash and cash equivalents (which equaled $86.2 million as of December 31, 2011), cash generated from operations, and the unused portion of our senior secured revolving credit facility (the “Revolving Credit Facility”).

In July 2009, we filed a registration statement that permits us to sell equity or debt in one or more offerings up to a total dollar amount of $300 million. 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’ discounts and commissions, pursuant to a public offering under the $300 million shelf registration statement. In July 2011, we obtained $94.3 million in net proceeds when we sold 6,900,000 shares of our common stock at $14.50 per share, less underwriters’ commissions and other offering costs, pursuant to a public offering under the $300 million shelf registration statement. On July 22, 2011, we used $57.0 million of these proceeds to pay down the debt balance outstanding under our Revolving Credit Facility. The current availability under the $300 million shelf registration statement for equity or debt is $174.2 million as of February 10, 2012. In the future, we may consider equity or debt offerings, as appropriate, to meet our liquidity needs.

On March 11, 2010, we issued $250 million of senior notes with a coupon interest rate of 9.875% that are due in 2018 (the "2010 Senior Notes"). We received $234.8 million of net proceeds from the issuance of the 2010 Senior Notes that were used to repay a portion of the borrowings outstanding under our Revolving Credit Facility. On November 21, 2011, we issued an additional $175 million of senior notes (the "2011 Senior Notes") with the same terms and conditions as the 2010 Senior Notes. We received $172.7 million of net proceeds from the issuance of the 2011 Senior Notes, a portion of which were used to fund the acquisition of Go-Coil in December 2011.

Our Revolving Credit Facility provides for a senior secured revolving credit facility, with sub-limits for letters of credit and swing-line loans, of up to an aggregate principal amount of $250 million, all of which matures on June 30, 2016. As of February 10, 2012, we had a zero balance outstanding and $9.0 million in committed letters of credit, which resulted in borrowing availability of $241.0 million under our Revolving Credit Facility. There are no limitations on our ability to access the full borrowing availability under the Revolving Credit Facility other than maintaining compliance with the covenants in the Revolving Credit Facility. Additional information regarding these covenants is provided in the Debt Requirements section below. Borrowings under the Revolving Credit Facility are available for selective acquisitions, working capital and other general corporate purposes.

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

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Uses of Capital Resources

For the years ended December 31, 2011 and 2010, our primary uses of capital resources were for acquisitions of production services businesses and for property and equipment additions that consisted of the following (amounts in thousands):

	Year ended December 31,
	2011		2010
Drilling Services Division:
Routine	$	35,252	$	17,441
Discretionary	67,352		88,201
New-builds and acquisitions	41,005		—
Total Drilling Services Division	143,609		105,642
Production Services Division:
Routine	8,168		6,972
Discretionary	31,523		1,202
New-builds and acquisitions	26,766		17,187
Total Production Services Division	66,457		25,361
Net cash used for purchases of property and equipment	210,066		131,003
Net impact of accruals	27,721		4,148
Total Capital Expenditures	$	237,787	$	135,151

We capitalized $2.3 million and $0.5 million of interest costs in property and equipment during the years ended December 31, 2011 and 2010, respectively.

During the year ended December 31, 2011, our Drilling Services Division incurred $66.5 million of costs on ten new-build drilling rigs that were under construction at December 31, 2011. Additionally, we performed significant upgrade projects on 17 drilling rigs during the year ended December 31, 2011, primarily in connection with obtaining new drilling contracts in unconventional plays and in our new West Texas drilling division location. Some of these projects included the installation of six iron roughnecks, one top drive, two automatic catwalks and three walking/skidding systems. During the year ended December 31, 2010, we performed significant upgrade projects on 24 drilling rigs, primarily in connection with obtaining new drilling contracts in unconventional plays and in Colombia. These projects included the installation of 16 top drives, five iron roughnecks, two automatic catwalks and 11 walking/skidding systems. We did not have any rigs under construction at December 31, 2010.

Our Production Services Division acquired 21 wireline units and 15 well service rigs during the year ended December 31, 2011, as well as ten coiled tubing units with the acquisition of Go-Coil on December 31, 2011. During the year ended December 31, 2010, we acquired 20 wireline units as well as auxiliary equipment for well service rigs.

Currently, we expect to spend approximately $300 million to $330 million on capital expenditures during 2012. We expect the total capital expenditures for 2012 will be allocated approximately 70% for our Drilling Services Division and approximately 30% for our Production Services Division. Our planned capital expenditures for the year ending December 31, 2012 include well services, coiled tubing and wireline fleet additions, partial construction of new-build AC drilling rigs and routine capital expenditures. 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 partially from the proceeds from the sale of our 2011 Senior Notes in November 2011, from operating cash flow in excess of our working capital requirements and, as necessary, from borrowings under our Revolving Credit Facility.

Working Capital

Our working capital was $129.9 million at December 31, 2011, compared to $76.1 million at December 31, 2010. Our current ratio, which we calculate by dividing our current assets by our current liabilities, was 1.9 at December 31, 2011 compared to 2.0 at December 31, 2010.

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.

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

	December 31, 2011		December 31, 2010		Change
Cash and cash equivalents	$	86,197	$	22,011	$	64,186
Short-term investments	—		12,569		(12,569		)
Receivables:
Trade, net of allowance for doubtful accounts	106,084		61,345		44,739
Unbilled receivables	31,512		21,423		10,089
Insurance recoveries	5,470		4,035		1,435
Income taxes	2,168		2,712		(544		)
Deferred income taxes	15,433		9,867		5,566
Inventory	11,184		9,023		2,161
Prepaid expenses and other current assets	11,564		8,797		2,767
Current assets	269,612		151,782		117,830
Accounts payable	66,440		26,929		39,511
Current portion of long-term debt	872		1,408		(536		)
Prepaid drilling contracts	3,966		3,669		297
Accrued expenses:
Payroll and related employee costs	29,057		18,057		11,000
Insurance premiums and deductibles	10,583		8,774		1,809
Insurance claims and settlements	5,470		4,035		1,435
Interest	12,283		7,307		4,976
Other	11,009		5,461		5,548
Current liabilities	139,680		75,640		64,040
Working capital	$	129,932	$	76,142	$	53,790

The change in cash and cash equivalents during the year ended December 31, 2011 is primarily due to cash provided by operations of $144.9 million, net proceeds from the sale of common stock of $94.3 million, $130.3 million in proceeds from net debt borrowings and $12.6 million net proceeds from the sale of our ARPSs in 2011, partially offset by $210.1 million used for purchases of property and equipment and $115.5 million used for the acquisition of Go-Coil and other production services businesses.

The short-term investments balance at December 31, 2010 represented the fair value of our investment in ARPSs, which were liquidated in January 2011.

The increases in our trade and unbilled receivables as of December 31, 2011 as compared to December 31, 2010 were primarily due to the increase in revenues of $55.0 million, or 37%, for the quarter ended December 31, 2011 as compared to the quarter ended December 31, 2010, and due to the timing of the billing and collection cycles for long-term drilling contracts in Colombia. In addition, the acquisition of Go-Coil on December 31, 2011 resulted in approximately $8.2 million of the increase in our trade and unbilled receivables.

The increase in current deferred income taxes is primarily due to an increase in certain accrued expenses during 2011 that will be deductible for income tax purposes in 2012 and therefore, we expect to realize the tax benefit of the deferred tax assets in the short-term.

The increase in both our insurance recoveries receivables and our insurance claims and settlements accrued expense as of December 31, 2011 as compared to December 31, 2010 is primarily due to an environmental liability insurance claim.

The increase in our inventory as of December 31, 2011 as compared to December 31, 2010 is primarily due to the expansion of our wireline operations during 2011 from 84 to 105 wireline units, and an increase in inventory for our Colombian operations.

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The increase in prepaid expenses and other assets is primarily due to an increase in deferred mobilization costs for domestic drilling rigs that moved between drilling division locations, as well as an increase in prepaid insurance costs due to the growth of our business during 2011.

The increase in accounts payable is primarily due to the increase in operating costs of $34.1 million, or 36%, for the quarter ended December 31, 2011 as compared to the quarter ended December 31, 2010, and due to a $27.7 million increase in our accruals for capital expenditures as of December 31, 2011, as compared to December 31, 2010.

The increase in accrued payroll and employee related costs is primarily due to workforce additions, accruals for our long-term compensation plans which accrue over two to three years, increased incentive compensation based on strong 2011 operating results, and fluctuations due to timing of payroll payments.

The increase in accrued insurance premiums and deductibles at December 31, 2011 as compared to December 31, 2010 is due to the increases in our drilling services and production services utilization and the resulting increased workforce during the quarter ended December 31, 2011 as compared to the quarter ended December 31, 2010. The increase in utilization and our workforce led to increased actuarial claims estimates for the deductibles under these insurance policies.

The increase in accrued interest expense is primarily due to the issuance of our 2011 Senior Notes in November 2011, for which interest is due semi-annually on March 15 and September 15.

The increase in other accrued expenses is primarily due to an increase in our sales tax accrual for sales tax payable on the construction of our new-build drilling rigs as well as the $1.7 million current portion of the net-worth tax accrual for our Colombian operations, which was assessed on January 1, 2011. In addition, we have recorded an estimated accrual of $1.0 million at December 31, 2011 for the net working capital adjustment which is payable to the former owners of Go-Coil.

Long-term Debt and Other Contractual Obligations

The following table includes all our contractual obligations at December 31, 2011 (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	$	426,854	$	872	$	899	$	83	$	425,000
Interest on long-term debt	272,997		42,115		83,985		83,944		62,953
Purchase commitments	134,859		113,859		21,000		—		—
Operating leases	17,407		4,607		5,974		3,020		3,806
Restricted cash obligation	1,300		650		650		—		—
Total	$	853,417	$	162,103	$	112,508	$	87,047	$	491,759

At December 31, 2011, long-term debt primarily consists of $425.0 million face amount outstanding under our Senior Notes and $1.7 million outstanding under subordinated notes payable to certain employees that are former shareholders of previously acquired production services businesses. On July 22, 2011, we repaid the entire outstanding debt balance under our Revolving Credit Facility. However, we expect to use the availability under the Revolving Credit Facility to fund our working capital needs, capital expenditures, or selective acquisitions, as necessary, through the final maturity date of June 30, 2016. The $425.0 million face amount outstanding under our Senior Notes will mature on March 15, 2018. Our Senior Notes have a carrying value of $417.7 million as of December 31, 2011, which represents the $425.0 million face value net of the $8.9 million of original issue discount and $1.7 million of original issue premium, net of amortization, based on the effective interest method. Our subordinated notes payable have final maturity dates in March and April2013.

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. Interest payment obligations on our subordinated notes payable are based on interest rates ranging from 6% to 14%, with annual payments of principal and interest through maturity.

Purchase commitments primarily relate to ten new-build drilling rigs, equipment upgrades and purchases of other new equipment. The total estimated cost for the ten new-build drilling rigs is approximately $220 million to $240 million, of which $66.5 million has already been incurred and $103.4 million is reflected in the purchase commitments included in the table above.

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

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As of December 31, 2011, we had restricted cash in the amount of $1.3 million held in an escrow account to be used for future payments in connection with the acquisition of Competition. The former owners of Competition will receive annual installments of $0.7 million payable over the remaining two years from the escrow account.

Debt Requirements

The Revolving Credit Facility contains customary mandatory prepayments from the proceeds of certain asset dispositions or debt issuances, which are applied to reduce outstanding revolving and swing-line loans and letter of credit exposure. There are no limitations on our ability to access the $250 million borrowing capacity other than maintaining compliance with the covenants under the Revolving Credit Facility. At December 31, 2011, we were in compliance with our financial covenants. Our total consolidated leverage ratio was 2.2 to 1.0, our senior consolidated leverage ratio was 0.1 to 1.0, and our interest coverage ratio was 6.7 to 1.0. The financial covenants contained in our Revolving Credit Facility include the following:

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

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

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

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

The Revolving Credit Facility does not restrict capital expenditures as long as (a) no event of default exists under the Revolving Credit Facility or would result from such capital expenditures, (b) after giving effect to such capital expenditures there is availability under the Revolving Credit Facility equal to or greater than $25 million and (c) the senior consolidated leverage ratio as of the last day of the most recent reported fiscal quarter is less than 2.00 to 1.00. If the senior consolidated leverage ratio as of the last day of the most recent reported fiscal quarter is equal to or greater than 2.00 to 1.00, then capital expenditures are limited to $100 million for the fiscal year. The capital expenditure threshold may be increased by any unused portion of the capital expenditure threshold from the immediate preceding fiscal year up to $30 million.

At December 31, 2011, our senior consolidated leverage ratio was not greater than 2.00 to 1.00 and therefore, we were not subject to the capital expenditure threshold restrictions listed above.

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

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 addition to the financial covenants under our Revolving Credit Facility, the Indenture Agreement for our Senior Notes contains certain restrictions generally 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.

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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 Go-Coil, 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, 2011, 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 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.

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

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With most drilling contracts, we receive payments contractually designated for the mobilization of rigs and other equipment. Payments received, and costs incurred for the mobilization services are deferred and recognized on a straight line basis over the related contract term. Costs incurred to relocate rigs and other drilling equipment to areas in which a contract has not been secured are expensed as incurred. Reimbursements that we receive for out-of-pocket expenses are recorded as revenue and the out-of-pocket expenses for which they relate are recorded as operating costs.

Our Production Services Division earns revenues for well services, wireline services, coiled tubing 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.

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, 2011, we had $4.0 million of current deferred mobilization revenues and $4.6 million of current deferred mobilization costs. 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 $5.1 million and $3.0 million for the years ended December 31, 2011 and 2010, respectively.

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. 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.

Goodwill—Goodwill results from business acquisitions and represents the excess of acquisition costs over the fair value of the net assets acquired. 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.

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

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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 are then equally weighted and combined into a single fair value. The primary assumptions used in the income approach are estimated cash flows and weighted average cost of capital. Estimated cash flows are primarily based on projected revenues, operating costs and capital expenditures and are discounted based on comparable industry average rates for weighted average cost of capital. The assumptions used in estimating fair values of reporting units and performing the goodwill impairment test are inherently uncertain and require management judgment.

Deferred taxes—We provide deferred taxes for the basis differences in our property and equipment between financial reporting and tax reporting purposes and other costs such as compensation, net operating loss carryforwards, employee benefit and other accrued liabilities which are deducted in different periods for financial reporting and tax reporting purposes. For property and equipment, basis differences arise from differences in depreciation periods and methods and the value of assets acquired in a business acquisition where we acquire an entity rather than just its assets. For financial reporting purposes, we depreciate the various components of our drilling rigs, well service rigs, wireline units and coiled tubing units over 2 to 25 years and refurbishments over 3 to 5 years, while federal income tax rules require that we depreciate drilling rigs, well service rigs, wireline units and coiled tubing units over 5 years. Therefore, in the first 5 years of our ownership of a drilling rig, well service rig, wireline unit or coiled tubing units, 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. 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. 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. We experienced a total loss of approximately $1.5 million on two of the turnkey contracts completed during 2011.

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 contract in progress at December 31, 2011, which was completed prior to the release of the financial statements included in this report. 

Our unbilled receivables totaled $31.5 million at December 31, 2011. Of that amount accrued, turnkey drilling contract revenues were $0.6 million. The remaining balance of unbilled receivables related to $27.9 million of the revenue recognized but not yet billed on daywork drilling contracts in progress at December 31, 2011 and $3.0 million related to unbilled receivables for our Production Services Division.

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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 $1.0 million at December 31, 2011.

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, wireline unit or coiled tubing unit is idle or working. Our estimates of the useful lives of our drilling, production, transportation and other equipment are based on our more than 40 years of experience in the oilfield services industry with similar equipment.

As of December 31, 2011, we had a $1.2 million deferred tax asset related to the $3.3 million impairment of our ARPSs which represents 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. During the year ended December 31, 2010, 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, 2011, we had $46.1 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, 2011 include accruals for costs incurred under the self-insurance portion of our health insurance of approximately $1.9 million and our workers’ compensation, general liability and auto liability insurance of approximately $6.5 million. We have stop loss coverage of $150,000 per occurrence under our health insurance and a deductible of $500,000 per occurrence under our workers’ compensation insurance. We have a deductible of $250,000 per occurrence under both our general liability insurance and auto liability insurance. We accrue for these costs as claims are incurred based on historical claim development data, and we accrue the costs of administrative services associated with claims processing.

Our stock-based compensation expense includes estimates for certain of our long-term incentive compensation plans which have performance-based award components dependent upon our performance over a set performance period, as compared to the performance of a pre-defined peer group. The accruals for these awards include estimates which affect our stock-based compensation expense, employee related accruals and equity. The accruals are adjusted based on actual achievement levels at the end of the pre-determined performance periods.

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Results of Operations

Statements of Operations Analysis—Year Ended December 31, 2011 Compared with the Year Ended December 31, 2010

The following table provides information about our operations for the years ended December 31, 2011 and December 31, 2010 (amounts in thousands, except average number of drilling rigs, utilization rate and revenue day information).

	Year ended December 31,
	2011			2010
Drilling Services Division:
Revenues	$	433,902		$	312,196
Operating costs	292,559			227,136
Drilling Services Division margin	$	141,343		$	85,060
Average number of drilling rigs	69.3			71.0
Utilization rate	73		%	59		%
Revenue days	18,383			15,182
Average revenues per day	$	23,603		$	20,564
Average operating costs per day	15,915			14,961
Drilling Services Division margin per day	$	7,688		$	5,603
Production Services Division:
Revenues	$	282,039		$	175,014
Operating costs	164,365			105,295
Production Services Division margin	$	117,674		$	69,719
Combined:
Revenues	$	715,941		$	487,210
Operating costs	456,924			332,431
Combined margin	$	259,017		$	154,779
Adjusted EBITDA	$	183,870		$	103,151

Drilling Services Division margin represents contract drilling revenues less contract drilling operating costs. Production Services Division margin represents production services revenue less production services operating costs. We believe that Drilling Services Division Margin and Production Services Division margin are useful measures for evaluating financial performance, although they are not measures of financial performance under U.S. Generally Accepted Accounting Principles (GAAP). However, Drilling Services Division margin and Production Services Division margin are common measures of operating performance used by investors, financial analysts, rating agencies and Pioneer’s management. A reconciliation of Drilling Services Division margin and Production Services Division margin to net income (loss), as reported is included in the table below. Drilling Services Division margin and Production Services Division margin as presented may not be comparable to other similarly titled measures reported by other companies.

Adjusted EBITDA is a financial measure that is not in accordance with GAAP, and should not be considered (i) in isolation of, or as a substitute for, net earnings (loss), (ii) as an indication of operating performance or cash flows from operating activities or (iii) as a measure of liquidity. In addition, Adjusted EBITDA does not represent funds available for discretionary use. We define Adjusted EBITDA as earnings (loss) before interest income (expense), taxes, depreciation, amortization and any impairments. We use this measure, together with our GAAP financial metrics, to assess our financial performance and evaluate our overall progress towards meeting our long-term financial objectives. We believe that this non-GAAP financial measure is useful to investors and analysts in allowing for greater transparency of our operating performance and makes it easier to compare our results with those of other companies within our industry. Adjusted EBITDA, as we calculate it, may not be comparable to Adjusted EBITDA measures reported by other companies. A reconciliation of Adjusted EBITDA to net income (loss) is set forth in the following table.

43

	Year ended December 31,
	2011			2010
	(amounts in thousands)
Reconciliation of combined margin and Adjusted EBITDA to net income (loss):
Combined margin	$	259,017		$	154,779
General and administrative	(67,318		)	(52,047		)
Bad debt expense	(925		)	(493		)
Other (expense) income	(6,904		)	912
Adjusted EBITDA	183,870			103,151
Depreciation and amortization	(132,832		)	(120,811		)
Impairment of equipment	(484		)	—
Interest expense	(29,721		)	(26,567		)
Impairment of investments	—			(3,331		)
Income tax (expense) benefit	(9,656		)	14,297
Net income (loss)	$	11,177		$	(33,261	)

Our Drilling Services Division experienced increases in its revenues and operating costs due to higher demand for our drilling services in 2011 as compared to 2010, as our industry continues to recover from the downturn that bottomed in late 2009. With increasing oil prices, rig utilization and revenue rates improved, particularly in oil-producing regions and in certain shale regions.

Our Drilling Services Division’s revenues increased by $121.7 million, or 39%, for the year ended December 31, 2011 as compared to the year ended December 31, 2010, due to an increase in utilization rates and drilling revenue rates. During the year ended December 31, 2011, our drilling rig utilization increased to 73% from 59%, and our average drilling revenues per day increased by 15%, or $3,039 per day, as compared to to the year ended December 31, 2010.

Our Drilling Services Division’s operating costs increased by $65.4 million, or 29%, for the year ended December 31, 2011, as compared to the year ended December 31, 2010, primarily due to the increase in utilization and the increase in our operating costs per day. Our operating costs per day increased by 6%, or $954 per day, for the year ended December 31, 2011 as compared to the year ended December 31, 2010. As utilization rates increased, average operating costs per day increased due to higher wage rates and repair and maintenance expenses as drilling rigs came out of storage and began operations.

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 17 turnkey drilling contracts during 2011, as compared to 11 turnkey drilling contracts completed during 2010. The following table provides percentages of our drilling revenues by drilling contract type for the years ended December 31, 2011 and 2010:

	Year ended December 31,
	2011		2010
Daywork Contracts	96	%	95	%
Turnkey Contracts	4	%	5	%
Footage Contracts	—		—

Our Production Services Division's revenues increased by $107.0 million, or 61%, while operating costs increased $59.1 million, or 56%. The increases in revenues and operating costs are primarily due to higher demand for our wireline services, well services and fishing and rental services, which resulted in higher utilization rates and higher revenue rates charged for these services during the year ended December 31, 2011, as compared to the year ended December 31, 2010. The expansion of our operations through the addition of 21 wireline units, or a 25% increase in units, and 15 well service rigs, or a 20% increase in our well service rig fleet, from December 31, 2010 to December 31, 2011 has also increased both our Production Services Division’s revenues and operating costs for the year ended December 31, 2011, as compared to 2010.

44

Our general and administrative expense increased by approximately $15.3 million, or 29%, for the year ended December 31, 2011 as compared to the year ended December 31, 2010. The increase is primarily due to increases in payroll and compensation related expenses. We have seen an increase in the demand for our services as our industry continues to recover from the industry downturn in 2009. As a result, payroll and compensation related expenses increased during the year ended December 31, 2011, as compared to the year ended December 31, 2010, as we have added employees in our corporate office and have accrued for increased incentive compensation based on strong 2011 operating results. In addition, professional fees increased in 2011 as compared to 2010, primarily due to the acquisition of Go-Coil on December 31, 2011.

Our other expense increased for the year ended December 31, 2011, as compared to the year ended December 31, 2010, primarily due to the $7.3 million net-worth tax expense for our Colombian operations which was assessed on January 1, 2011.

Our depreciation and amortization expenses increased by $12.0 million for the year ended December 31, 2011, as compared to the year ended December 31, 2010. 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 additions to our production services fleets.

During the year ended December 31, 2011, we recorded impairment charges of $0.5 million related to our decision to place six mechanical drilling rigs as held for sale, and to retire one drilling with most of its components to be used as spare parts.

Our interest expense increased for the year ended December 31, 2011, as compared to the year ended December 31, 2010, primarily due to the issuance of our Senior Notes in March 2010 and November 2011. The proceeds from the issuance in March 2010 were used to repay a portion of the outstanding debt balance under the Revolving Credit Facility, which has a lower interest rate when compared to the Senior Notes. In addition, the issuance of Senior Notes in November 2011 increased our overall debt balance in 2011. The overall increase in interest expense was partially offset by $2.3 million of capitalized interest during the year ended December 31, 2011 associated with the capital expenditures for upgrades to our drilling rig fleet and for our new-build drilling rigs.

Our effective income tax rate for the year ended December 31, 2011 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, the effect of foreign translation and other permanent differences, including the effect of the non-deductible, $7.3 million net-worth tax assessed on our Colombian operations as of January 1, 2011.

45

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).

	Year 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	)

46

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:

	Year 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 saw 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 came out of storage and began 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 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 saw an increase in the demand for our services as our industry began to recover from the industry downturn in 2009. Compensation related expenses increased during 2010 as we added employees in our corporate office and accrued for higher bonuses for 2010.

47

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.

During the year ended December 31, 2010, we recognized a $3.3 million other-than-temporary impairment of our ARPSs, which were liquidated in January 2011.

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.

48

Inflation

Wage rates for our operations personnel are impacted by inflationary pressures when the demand for drilling and production services increases and the availability of personnel is scarce. With the increase in rig counts beginning in late 2009, we saw decreased availability of personnel to operate our rigs and therefore we had wage rate increases for drilling rig personnel in certain of our locations of approximately 18% and 16% in February and July 2010, respectively. With continued increases in demand through 2011, and the resulting tightening of labor markets, we had another wage rate increase of approximately 10% across multiple divisions in January 2012 and may have additional increases towards the end of the year.

Costs for rig repairs and maintenance, rig upgrades and new rig construction are also impacted by inflationary pressures when the demand for drilling services increases. We experienced an increase in these costs of approximately 5% and 10% during 2010 and 2011, respectively, and we estimate that we will experience similar increases in 2012.

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 Financial Accounting Standards Board (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 are required to apply this guidance prospectively for revenue arrangements entered into or materially modified after January 1, 2011. The adoption of this new guidance has not had an impact on our financial position or results of operations.

Business Combinations. In December 2010, the FASB issued 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 are required to apply this guidance prospectively for business combinations for which the acquisition date is on or after January 1, 2011. The adoption of this new guidance has not had a material impact on our financial position or results of operations.

Fair Value Measurement. In May 2011, the FASB issued ASU No. 2011-04, Fair Value Measurement (Topic 820): Amendments to Achieve Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs. This update clarifies existing guidance about how fair value should be applied where it already is required or permitted and provides wording changes that align this standard with International Financial Reporting Standards (IFRS). We are required to apply this guidance prospectively beginning with our first quarterly filing in 2012. We do not expect the adoption of this new guidance to have a material impact on our financial position or results of operations.

Comprehensive Income. In June 2011, the FASB issued ASU No. 2011-05, Comprehensive Income (Topic 220): Presentation of Comprehensive Income. This update increases the prominence of other comprehensive income in financial statements, eliminating the option of presenting other comprehensive income in the statement of changes in equity, and instead, giving companies the option to present the components of net income and comprehensive income in either one or two consecutive financial statements. We are required to comply with this guidance prospectively beginning with our first quarterly filing in 2012. The adoption of this new guidance will not impact our financial position or statement of operations, other than changes in presentation.

In December 2011, the FASB issued ASU No. 2011-12, Comprehensive Income (Topic 220): Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05. This update delays the effective date of the requirement to present reclassification adjustments for each component of accumulated other comprehensive income in both net income and other comprehensive income on the face of the financial statements.

49

Intangibles–Goodwill and Other. In September 2011, the FASB issued ASU No. 2011-08, Intangibles–Goodwill and Other (Topic 350): Testing Goodwill for Impairment. This update allows entities testing goodwill for impairment the option of performing a qualitative assessment before calculating the fair value of the reporting unit (i.e., step one of the two-step goodwill impairment test). If entities determine, on the basis of qualitative factors, that the fair value of the reporting unit is more likely than not less than the carrying amount, the two-step impairment test would be required. The amendments are effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011. The adoption of this new guidance will not impact our financial position or statement 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, which was assessed on January 1, 2011 and is payable in eight semi-annual installments from 2011 through 2014.

Based on our Colombian operations’ net equity, measured on a Colombian tax basis as of January 1, 2011, our total net-worth tax obligation is approximately $7.3 million, which is not deductible for tax purposes. We recognized this tax obligation in full during the year ended December 31, 2011 in other expense in our consolidated statement of operations, and in other accrued expenses and other long-term liabilities on our consolidated balance sheet. As of December 31, 2011, the remaining obligation is $5.3 million.

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, 2011, we had a zero balance outstanding under our Revolving Credit Facility, which is our only variable rate debt. Future borrowings under the Revolving Credit Facility would be subject to interest rate market risk.

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 losses of $0.6 million for the year ended December 31, 2011.

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Item 8. Financial Statements and Supplementary Data

PIONEER DRILLING COMPANY

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

	Page
Reports of Independent Registered Public Accounting Firm	52
Consolidated Balance Sheets as of December 31, 2011 and December 31, 2010	54
Consolidated Statements of Operations for the years ended December 31, 2011, 2010 and 2009	55
Consolidated Statements of Shareholders’ Equity and Comprehensive Income for the years ended December 31, 2011, 2010 and 2009	56
Consolidated Statements of Cash Flows for the years ended December 31, 2011, 2010 and 2009	57
Notes to Consolidated Financial Statements	58

51

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, 2011 and 2010, 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, 2011. 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, 2011 and 2010, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2011, 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, 2011, 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 21, 2012 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

/s/ KPMG LLP

San Antonio, Texas

February 21, 2012

52

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, 2011, 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, 2011, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

The Company acquired Go-Coil, LLC ("Go-Coil") on December 31, 2011 and management excluded Go-Coil's internal control over financial reporting from its assessment of the effectiveness of the Company's internal control over financial reporting as of December 31, 2011. Go-Coil contributed approximately 10% of the Company's total assets as of December 31, 2011. Our audit of internal control over financial reporting of the Company also excluded an evaluation of the internal control over financial reporting of Go-Coil.

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, 2011 and 2010, 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, 2011, and our report dated February 21, 2012 expressed an unqualified opinion on those consolidated financial statements.

/s/ KPMG LLP

San Antonio, Texas

February 21, 2012

53

PIONEER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEET

	December 31, 2011			December 31, 2010
	(In thousands, except share data)
ASSETS
Current assets:
Cash and cash equivalents	$	86,197		$	22,011
Short-term investments	—			12,569
Receivables:
Trade, net of allowance for doubtful accounts	106,084			61,345
Unbilled receivables	31,512			21,423
Insurance recoveries	5,470			4,035
Income taxes	2,168			2,712
Deferred income taxes	15,433			9,867
Inventory	11,184			9,023
Prepaid expenses and other current assets	11,564			8,797
Total current assets	269,612			151,782
Property and equipment, at cost	1,336,926			1,097,179
Less accumulated depreciation	542,970			441,671
Net property and equipment	793,956			655,508
Intangible assets, net of amortization	52,680			21,966
Goodwill	41,683			—
Noncurrent deferred income taxes	735			—
Other long-term assets	14,088			12,087
Total assets	$	1,172,754		$	841,343
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	66,440		$	26,929
Current portion of long-term debt	872			1,408
Prepaid drilling contracts	3,966			3,669
Accrued expenses:
Payroll and related employee costs	29,057			18,057
Insurance premiums and deductibles	10,583			8,774
Insurance claims and settlements	5,470			4,035
Interest	12,283			7,307
Other	11,009			5,461
Total current liabilities	139,680			75,640
Long-term debt, less current portion	418,728			279,530
Noncurrent deferred income taxes	94,745			80,160
Other long-term liabilities	9,156			9,680
Total liabilities	662,309			445,010
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; 61,782,180 shares and 54,228,170 shares outstanding at December 31, 2011 and December 31, 2010, respectively	6,188			5,425
Additional paid-in capital	442,020			339,105
Treasury stock, at cost; 95,409 shares and 25,380 shares at December 31, 2011 and December 31, 2010, respectively	(904		)	(161		)
Accumulated earnings	63,141			51,964
Total shareholders’ equity	510,445			396,333
Total liabilities and shareholders’ equity	$	1,172,754		$	841,343

See accompanying notes to consolidated financial statements.

54

PIONEER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

	Year ended December 31,
	2011			2010			2009
	(In thousands, except per share data)
Revenues:
Drilling services	$	433,902		$	312,196		$	219,751
Production services	282,039			175,014			105,786
Total revenues	715,941			487,210			325,537
Costs and expenses:
Drilling services	292,559			227,136			147,343
Production services	164,365			105,295			68,012
Depreciation and amortization	132,832			120,811			106,186
General and administrative	67,318			52,047			37,478
Bad debt expense (recovery)	925			493			(1,642		)
Impairment of equipment	484			—			—
Total costs and expenses	658,483			505,782			357,377
Income (loss) from operations	57,458			(18,572		)	(31,840		)
Other (expense) income:
Interest expense	(29,721		)	(26,567		)	(8,928		)
Impairment of investments	—			(3,331		)	—
Other	(6,904		)	912			596
Total other expense	(36,625		)	(28,986		)	(8,332		)
Income (loss) before income taxes	20,833			(47,558		)	(40,172		)
Income tax (expense) benefit	(9,656		)	14,297			16,957
Net income (loss)	$	11,177		$	(33,261	)	$	(23,215	)
Income (loss) per common share—Basic	$	0.19		$	(0.62	)	$	(0.46	)
Income (loss) per common share—Diluted	$	0.19		$	(0.62	)	$	(0.46	)
Weighted average number of shares outstanding—Basic	57,390			53,797			50,313
Weighted average number of shares outstanding—Diluted	58,779			53,797			50,313

See accompanying notes to consolidated financial statements.

55

PIONEER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY AND COMPREHENSIVE INCOME

	Shares					Amount
	Common		Treasury			Common			Treasury			Additional Paid In Capital				Accumulated Earnings				Accumulated Other Comprehensive Loss			Total Shareholders’ Equity
	(In thousands)
Balance at 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 at 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	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 at December 31, 2010	54,253		(25	)		$	5,425		$	(161	)	$	339,105			$	51,964			$	—		$	396,333
Comprehensive income:
Net income	—		—			—			—			—				11,177				—			11,177
Total comprehensive income																							11,177
Sale of common stock, net of offering costs	6,900	—	—		—	690		—	—			93,653			—	—			—	—			94,343
Exercise of options and related income tax effect	517		—			52			—			2,832				—				—			2,884
Purchase of treasury stock	—		(70	)		—			(743		)	—				—				—			(743		)
Income tax effect of stock option forfeitures and expirations	—		—			—			—			(254		)		—				—			(254		)
Issuance of restricted stock	207		—			21			—			(21		)		—				—			—
Stock-based compensation expense	—		—			—			—			6,705				—				—			6,705
Balance at December 31, 2011	61,877		(95	)		$	6,188		$	(904	)	$	442,020			$	63,141			$	—		$	510,445

See accompanying notes to consolidated financial statements.

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PIONEER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year ended December 31,
	2011			2010			2009
	(In thousands)
Cash flows from operating activities:
Net income (loss)	$	11,177		$	(33,261	)	$	(23,215	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization	132,832			120,811			106,186
Allowance for doubtful accounts	787			521			(1,170		)
Loss (gain) on dispositions of property and equipment	151			(1,629		)	56
Stock-based compensation expense	6,705			6,675			7,216
Amortization of debt issuance costs and discount	3,302			2,609			1,547
Impairment of investments	—			3,331			—
Impairment of equipment	484			—			—
Deferred income taxes	8,098			(13,224		)	28,400
Change in other long-term assets	2,828			(1,373		)	69
Change in other long-term liabilities	(623		)	3,223			(1,312		)
Changes in current assets and liabilities:
Receivables	(46,802		)	(9,576		)	18,180
Inventory	(2,161		)	(3,487		)	(1,661		)
Prepaid expenses and other current assets	(1,965		)	(2,598		)	2,703
Accounts payable	9,331			7,458			(2,243		)
Prepaid drilling contracts	297			3,261			(763		)
Accrued expenses	20,438			15,610			(10,680		)
Net cash provided by operating activities	144,879			98,351			123,313
Cash flows from investing activities:
Acquisition of production services business of Go-Coil	(109,035		)	—			—
Acquisition of other production services businesses	(6,502		)	(1,340		)	—
Purchases of property and equipment	(210,066		)	(131,003		)	(114,712		)
Proceeds from sale of property and equipment	5,550			2,331			767
Proceeds from sale of auction rate securities	12,569			—			—
Proceeds from insurance recoveries	—			531			36
Net cash used in investing activities	(307,484		)	(129,481		)	(113,909		)
Cash flows from financing activities:
Debt repayments	(113,158		)	(256,856		)	(17,298		)
Proceeds from issuance of debt	250,750			274,375			—
Debt issuance costs	(7,285		)	(4,865		)	(2,560		)
Proceeds from exercise of options	2,884			238			—
Proceeds from common stock, net of offering costs of $5,707 and $454 in 2011 and 2009, respectively	94,343			—			24,043
Purchase of treasury stock	(743		)	(130		)	(31		)
Net cash provided by financing activities	226,791			12,762			4,154
Net increase (decrease) in cash and cash equivalents	64,186			(18,368		)	13,558
Beginning cash and cash equivalents	22,011			40,379			26,821
Ending cash and cash equivalents	$	86,197		$	22,011		$	40,379
Supplementary disclosure:
Interest paid	$	26,955		$	17,529		$	7,917
Income tax paid (refunded)	$	952		$	(39,778	)	$	(8,889	)

See accompanying notes to consolidated financial statements.

57

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 provides drilling services and production services to independent and major oil and gas exploration and production companies throughout much of the oil and gas producing regions of the United States and internationally in Colombia.

Our Drilling Services Division provides contract land drilling services with its fleet of 64 drilling rigs in the following locations:

Drilling Division Locations	Rig Count
South Texas	15
East Texas	5
West Texas	18
North Dakota	9
Utah	4
Appalachia	5
Colombia	8

Drilling revenues and rig utilization steadily improved during 2010 and 2011, primarily due to increased demand for drilling services in domestic shale plays and oil or liquid rich regions. We capitalized on this trend by moving drilling rigs in our fleet to these higher demand regions from lower demand regions such as our Oklahoma, North Texas and East Texas drilling division locations which have conventional natural gas production. During 2010 and 2011, we moved drilling rigs into our North Dakota and Appalachia drilling division locations, both of which are shale regions, and in early 2011, we established our West Texas drilling division location where we currently have 18 drilling rigs operating.

In September 2011, we evaluated the drilling rigs in our fleet that had remained idle and decided to place six mechanical drilling rigs as held for sale as of September 30, 2011. Four of the held for sale drilling rigs were previously assigned to our Oklahoma drilling division location and the remaining two drilling rigs were previously assigned to our East Texas drilling division location. Sales of all six mechanical drilling rigs were completed by mid November 2011. In addition, we decided to retire another drilling rig from our fleet that was previously assigned to our Utah drilling division location, with most of its components to be used for spare equipment. We recognized an impairment charge of $0.5 million in September 2011 in association with our decision to dispose of these seven drilling rigs.

At December 31, 2011, we have 64 drilling rigs in our fleet. We currently have term contracts for ten new-build AC drilling rigs that are fit for purpose for domestic shale plays, five of which we estimate will begin working in the first half of 2012, with the remaining five to begin operating by the end of 2012. As of February 10, 2012, 55 drilling rigs are operating under drilling contracts, 44 of which are under term contracts. We have nine drilling rigs that are idle, three of which are under contract to begin working in the first quarter of 2012. We are actively marketing all our idle drilling rigs.

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.

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Our Production Services Division provides a range of services to exploration and production companies, including well services, wireline, coil tubing, 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 10, 2012, we have a premium fleet of 91 well service rigs consisting of eighty-one 550 horsepower rigs, nine 600 horsepower rigs and one 400 horsepower rig. All our well service rigs are currently operating or are being actively marketed, with January utilization of approximately 86%. We currently provide wireline and coiled tubing services with a fleet of 109 and ten wireline and coiled tubing units, respectively, and we provide rental services with approximately $15.1 million of fishing and rental tools. We plan to add another 13 well service rigs, 18 wireline units and three coiled tubing units by the end of 2012.

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 liability relating to 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, 2011, through the filing of this Form 10-K, for inclusion as necessary.

Recently Issued Accounting Standards

Multiple Deliverable Revenue Arrangements. In October 2009, the Financial Accounting Standards Board (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 are required to apply this guidance prospectively for revenue arrangements entered into or materially modified after January 1, 2011. The adoption of this new guidance has not had an impact on our financial position or results of operations.

Business Combinations. In December 2010, the FASB issued 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 are required to apply this guidance prospectively for business combinations for which the acquisition date is on or after January 1, 2011. The adoption of this new guidance has not had a material impact on our financial position or results of operations.

Fair Value Measurement. In May 2011, the FASB issued ASU No. 2011-04, Fair Value Measurement (Topic 820): Amendments to Achieve Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs. This update clarifies existing guidance about how fair value should be applied where it already is required or permitted and provides wording changes that align this standard with International Financial Reporting Standards (IFRS). We are required to apply this guidance prospectively beginning with our first quarterly filing in 2012. We do not expect the adoption of this new guidance to have a material impact on our financial position or results of operations.

Comprehensive Income. In June 2011, the FASB issued ASU No. 2011-05, Comprehensive Income (Topic 220): Presentation of Comprehensive Income. This update increases the prominence of other comprehensive income in financial statements, eliminating the option of presenting other comprehensive income in the statement of changes in equity, and instead, giving companies the option to present the components of net income and comprehensive income in either one or two consecutive financial statements. We are required to comply with this guidance prospectively beginning with our first quarterly filing in 2012. The adoption of this new guidance will not impact our financial position or statement of operations, other than changes in presentation.

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In December 2011, the FASB issued ASU No. 2011-12, Comprehensive Income (Topic 220): Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05. This update delays the effective date of the requirement to present reclassification adjustments for each component of accumulated other comprehensive income in both net income and other comprehensive income on the face of the financial statements.

Intangibles–Goodwill and Other. In September 2011, the FASB issued ASU No. 2011-08, Intangibles–Goodwill and Other (Topic 350): Testing Goodwill for Impairment. This update allows entities testing goodwill for impairment the option of performing a qualitative assessment before calculating the fair value of the reporting unit (i.e., step one of the two-step goodwill impairment test). If entities determine, on the basis of qualitative factors, that the fair value of the reporting unit is more likely than not less than the carrying amount, the two-step impairment test would be required. The amendments are effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011. The adoption of this new guidance will not impact our financial position or statement 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. During periods of high rig demand, or for our newly constructed rigs, we enter into longer-term drilling contracts. Currently, we have contracts with terms of six months to four years in duration. As of February 10, 2012, we have 44 drilling rigs operating under term contracts. Of these 44 contracts, if not renewed at the end of their terms, 21 will expire by July 10, 2012, 22 will expire by February 10, 2013 and one will expire by February 10, 2014. We have term contracts for an additional three drilling rigs that we expect will begin operating in the first quarter of 2012 and we have ten term contracts for new-build AC drilling rigs, five of which we estimate will begin working in the first half of 2012, with the remaining five to begin operating by the end of 2012.

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—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 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.

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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.

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

With most drilling contracts, we receive payments contractually designated for the mobilization of rigs and other equipment. Payments received, and costs incurred for the mobilization services are deferred and recognized on a straight line basis over the related contract term. Costs incurred to relocate rigs and other drilling equipment to areas in which a contract has not been secured are expensed as incurred. Reimbursements that we receive for out-of-pocket expenses are recorded as revenue and the out-of-pocket expenses for which they relate are recorded as operating costs.

Production Services—Our Production Services Division earns revenues for well services, wireline, coiled tubing, 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.

The asset “unbilled receivables” represents revenues we have recognized in excess of amounts billed on drilling contracts and production services completed but not yet invoiced. Our unbilled receivables totaled $31.5 million at December 31, 2011. Of that amount accrued, turnkey drilling contract revenues were $0.6 million. The remaining balance of unbilled receivables related to $27.9 million of the revenue recognized but not yet billed on daywork drilling contracts in progress at December 31, 2011 and $3.0 million related to unbilled receivables for our Production Services Division.

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, 2011 we had $4.0 million of current deferred mobilization revenues and $4.6 million of current deferred mobilization costs. 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 $5.1 million and $3.0 million for the years ended December 31, 2011 and 2010, respectively.

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, 2011 and 2010 were $5.7 million and $5.7 million, respectively.

Restricted Cash

As of December 31, 2011, we had restricted cash in the amount of $1.3 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 owners of Competition will receive annual installments of $0.7 million payable over the remaining two years from the escrow account. Restricted cash of $0.7 million and $0.7 million is recorded in other current assets and other long-term assets, respectively. The associated obligation of $0.7 million and $0.7 million is recorded in accrued expenses and other long-term liabilities, respectively.

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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):

	Year ended December 31,
	2011			2010			2009
Balance at beginning of year	$	712		$	286		$	1,574
Increase (decrease) in allowance charged to expense	787			521			(1,170		)
Accounts charged against the allowance, net of recoveries	(505		)	(95		)	(118		)
Balance at end of year	$	994		$	712		$	286

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 (“ARPSs”) that were classified as available for sale. 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. On January 19, 2011, we entered into an agreement with a financial institution to sell the ARPSs for $12.6 million, which represented 79% of the par value, plus accrued interest. The $3.3 million difference between the ARPSs’ par value of $15.9 million and the sales price of $12.6 million represented an other-than-temporary impairment of the ARPSs investment which was reflected as an impairment of investments in our consolidated statement of operations for the year ended December 31, 2010.

Under the ARPSs sales 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”). Upon origination, the fair value of the ARPSs Call Option was estimated to be $0.6 million and was recognized as other income in our consolidated statement of operations for 2011. We are required to assess the value of the ARPSs Call Option at the end of each reporting period, with any changes in fair value recorded within our consolidated statement of operations. As of December 31, 2011, the ARPSs Call Option had an estimated fair value of $0.3 million, and was included in our other long-term assets in our consolidated balance sheet.

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.

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As of December 31, 2011, the estimated useful lives and costs of our asset classes are as follows:

	Lives	Cost
		(amounts in  thousands)
Drilling rigs and equipment	3 - 25	$	978,249
Well service rigs and equipment	5 - 20	153,503
Wireline units and equipment	2 - 10	101,955
Coiled tubing units and equipment	2 - 7	25,357
Fishing and rental tools and equipment	5 - 10	15,063
Vehicles	3 - 10	46,890
Office equipment	3 - 5	5,905
Buildings and improvements	3 - 40	9,196
Land	—	808
		$	1,336,926

We recorded gains (losses) on disposition of our property and equipment in contract drilling costs of $(0.2) million, $1.6 million and $(0.1) million for the years ended December 31, 2011, 2010 and 2009, respectively. During the years ended December 31, 2011, 2010 and 2009, we capitalized $2.3 million, $0.5 million and $0.3 million, respectively, of interest costs incurred during the construction periods of certain drilling equipment and new-build drilling rigs. During 2011, we incurred $66.5 million of costs on ten new-build drilling rigs that were under construction at December 31, 2011. We did not have any 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. 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. 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. 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.

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

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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 are 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. The primary assumptions used in the market approach is 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. 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.

We have goodwill of $41.7 million as of December 31, 2011. All of this goodwill was recorded in connection with the acquisition of the production services business from Go-Coil on December 31, 2011, as described in Note 2, Acquisitions. As a result, the goodwill has been allocated to the coiled tubing services reporting unit within our Production Services Division operating segment. No impairment loss on goodwill was recognized during the year ended December 31, 2011.

Intangible Assets

All our intangible assets are subject to amortization and consist of customer relationships, non-compete agreements, trade marks and trade names. Essentially all of our intangible assets were recorded in connection with the acquisitions of the production services businesses. Intangible assets consist of the following components (amounts in thousands):

	December 31, 2011			December 31, 2010
Cost:
Customer relationships	$	66,273		$	33,036
Non-compete agreements	3,133			2,024
Trademarks / trade names	671			155
Accumulated amortization:
Customer relationships	(15,512		)	(11,462		)
Non-compete agreements	(1,885		)	(1,787		)
	$	52,680		$	21,966

We evaluate for potential impairment of long-lived assets and intangible assets subject to amortization when indicators of impairment are present. Circumstances that could indicate a potential impairment include significant adverse changes in industry trends, economic climate, legal factors, and an adverse action or assessment by a regulator. More specifically, significant adverse changes in industry trends include significant declines in revenue rates, utilization rates, oil and natural gas market prices and industry rig counts 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 four reporting units which are well services, wireline services, coiled tubing 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.

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The cost of our customer relationships, trademarks and trade names are amortized using the straight-line method over their respective estimated economic useful lives which range from two to nine years. Amortization expense for our non-compete agreements is calculated using the straight-line method over the period of the agreements which range from two to seven years. Amortization expense was $4.3 million, $4.6 million and $4.7 million for the years ended December 31, 2011, 2010 and 2009, respectively. Amortization expense is estimated to be approximately $8.7 million, $8.7 million, $8.4 million, $8.4 million and $5.6 million for the years ending December 31, 2012, 2013, 2014, 2015 and 2016, respectively. 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 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, the ARPSs Call Option, and debt issuance costs, net of amortization. Debt issuance costs 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

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. The effect of a change in tax rates on deferred tax assets and liabilities is reflected in income in the period during which the change occurs.

Comprehensive Income (Loss)

Comprehensive income (loss) is comprised of net income (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):

	Year ended December 31,
	2011		2010			2009
Net income (loss)	$	11,177	$	(33,261	)	$	(23,215	)
Other comprehensive loss: unrealized losses on securities	—		—			(448		)
Impact of impairment of investments charge	—		1,693			—
Comprehensive income (loss)	$	11,177	$	(31,568	)	$	(23,663	)

Stock-based Compensation

We recognize compensation cost for stock option, restricted stock and restricted stock unit awards based on the fair value of the awards. For our awards with graded vesting, we recognize compensation expense on a straight-line basis over the service period for each separately vesting portion of the award as if the award was, in substance, multiple awards.

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. We report all excess tax benefits resulting from the exercise of stock options as financing cash flows in our consolidated statement of cash flows.

Reclassifications

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

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2. Acquisitions

On December 31, 2011, we acquired the production services business of Go-Coil, LLC, a Louisiana limited liability company ("Go-Coil") which provides coiled tubing services with a fleet of seven onshore units and three offshore units through its facilities in Louisiana, Texas, Oklahoma and Pennsylvania. The aggregate purchase price for the acquisition was approximately $110.4 million, which consisted of assets acquired of $114.9 million and liabilities assumed of $4.5 million. We funded the acquisition with cash on hand that was primarily generated from the proceeds of the Senior Notes issued in November 2011, as described in Note 3, Long-term Debt.

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

Cash acquired	$	313
Other current assets	9,068
Property and equipment	30,103
Intangibles and other assets	33,695
Goodwill	41,683
Total assets acquired	$	114,862
Current liabilities	$	4,337
Long-term debt	131
Total liabilities assumed	$	4,468
Net assets acquired	$	110,394

The following unaudited pro forma consolidated summary financial information gives effect of the acquisition of the production services business from Go-Coil as though it was effective as of the beginning of the year ended December 31, 2011. Pro forma adjustments primarily relate to additional depreciation, amortization, interest and tax expenses, as well as the removal of approximately $14.1 million of nonrecurring costs, primarily related to discontinued compensation arrangements and acquisition related costs. The pro forma information reflects our company’s historical data and Go-Coil's historical data 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, 2011, 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, 2011
	(in thousands)
Total revenues	$	762,978
Net earnings	$	8,412
Earnings per common share:
Basic	$	0.15
Diluted	$	0.14

The acquisition of the production services business from Go-Coil was accounted for as an acquisition of a business in accordance with ASC Topic 805, Business Combinations. The purchase price allocation for the Go-Coil acquisition is preliminary at this time and may change once we receive finalized information regarding the fair value estimates of the assets acquired and liabilities assumed in the acquisition. In addition, we have not finalized the working capital adjustment which will be payable to the former owners of Go-Coil and is estimated to be approximately $1.0 million. Goodwill was recognized as part of the Go-Coil acquisition, since the purchase price exceeded the estimated fair value of the assets acquired and liabilities assumed. We believe that the goodwill relates to the acquired workforce, future synergies between our existing service offerings and the ability to expand our service offerings.

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Prior to the Go-Coil acquisition, we completed four separate acquisitions in 2011 of other production services businesses for a total of $6.5 million in cash. The identifiable assets recorded in connection with these acquisitions included fixed assets of $5.2 million, representing six wireline units and two well service rigs, and intangible assets of $1.3 million representing customer relationships and non-competition agreements. We did not recognize any goodwill in conjunction with these acquisitions and no contingent assets or liabilities were assumed. These four acquisitions have been accounted for as acquisitions of businesses in accordance with ASC Topic 805, Business Combinations.

3. Long-term Debt

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

	December 31, 2011			December 31, 2010
Senior secured revolving credit facility	$	—		$	37,750
Senior Notes	417,747			240,080
Subordinated notes payable and other	1,853			3,108
	419,600			280,938
Less current portion	(872		)	(1,408		)
	$	418,728		$	279,530

Senior Secured Revolving Credit Facility

We have a credit agreement, as amended on June 30, 2011, with Wells Fargo Bank, N.A. and a syndicate of lenders which provides for a senior secured revolving credit facility, with sub-limits for letters of credit and swing-line loans, of up to an aggregate principal amount of $250 million, all of which matures on June 30, 2016 (the “Revolving Credit Facility”). The Revolving Credit Facility contains customary mandatory prepayments from the proceeds of certain asset dispositions or debt issuances, which are applied to reduce outstanding revolving and swing-line loans and letter of credit exposure, but in no event will reduce the borrowing availability under the Revolving Credit Facility to less than $250 million.

Borrowings under the Revolving Credit Facility bear interest, at our option, at the LIBOR rate or at the bank prime rate, plus an applicable per annum margin that ranges from 2.50% to 3.25% and 1.50% to 2.25%, respectively. The LIBOR margin and bank prime rate margin in effect at February 10, 2012 are 2.50% and 1.50%, 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.

As of February 10, 2012, we had a zero balance outstanding and $9.0 million in committed letters of credit, which resulted in borrowing availability of $241.0 million under our Revolving Credit Facility. There are no limitations on our ability to access this borrowing capacity other than maintaining compliance with the covenants under the Revolving Credit Facility. At December 31, 2011, we were in compliance with our financial covenants. Our total consolidated leverage ratio was 2.2 to 1.0, our senior consolidated leverage ratio was 0.1 to 1.0, and our interest coverage ratio was 6.7 to 1.0. The financial covenants contained in our Revolving Credit Facility include the following:

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

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

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

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

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The Revolving Credit Facility does not restrict capital expenditures as long as (a) no event of default exists under the Revolving Credit Facility or would result from such capital expenditures, (b) after giving effect to such capital expenditures there is availability under the Revolving Credit Facility equal to or greater than $25 million and (c) the senior consolidated leverage ratio as of the last day of the most recent reported fiscal quarter is less than 2.00 to 1.00. If the senior consolidated leverage ratio as of the last day of the most recent reported fiscal quarter is equal to or greater than 2.00 to 1.00, then capital expenditures are limited to $100 million for the fiscal year. The capital expenditure threshold may be increased by any unused portion of the capital expenditure threshold from the immediate preceding fiscal year up to $30 million.

At December 31, 2011, our senior consolidated leverage ratio was not greater than 2.00 to 1.00 and therefore, we were not subject to the capital expenditure threshold restrictions listed above.

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

Senior Notes

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

In accordance with a registration rights agreement with the holders of our 2010 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 2010 Senior Notes to exchange their senior notes for publicly registered notes with substantially identical terms. References to the “2010 Senior Notes” herein include the senior notes issued in the exchange offer.

On November 21, 2011, we issued $175 million of unregistered Senior Notes (the "2011 Senior Notes"). The 2011 Senior Notes have the same terms and conditions as the 2010 Senior Notes. The 2011 Senior Notes were sold with an original issue premium of $1.8 million that was based on 101% of their face value, which will result in an effective yield to maturity of approximately 9.66%. On November 21, 2011, we received $172.7 million of net proceeds from the issuance of the 2011 Senior Notes, including the original issue premium, and after $4.1 million of deductions were made for underwriters' fees and other debt offering costs. A portion of the net proceeds were used to fund the acquisition of Go-Coil in December 2011, as described in Note 2, Acquisitions.

The 2010 and 2011 Senior Notes (the "Senior Notes") are reflected on our condensed consolidated balance sheet at December 31, 2011 with a total carrying value of $417.7 million, which represents the $425.0 million total face value net of the $8.9 million unamortized portion of original issue discount and $1.7 million unamortized portion of original issue premium. The original issue discount and premium are 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. 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.

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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.

The Indenture contains certain restrictions generally 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.

We were in compliance with these covenants as of December 31, 2011. 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

We have two subordinated notes payable to certain employees that are former shareholders of production services businesses which we have acquired. These subordinated notes payable have interest rates of 6% and 14%, require annual payments of principal and interest and have final maturity dates in March and April2013. We have other debt of $0.2 million as of December 31, 2011 which represents a capital lease obligation for equipment, with monthly payments due through November 2016.

Debt Issuance Costs

Costs incurred in connection with the Revolving Credit Facility were capitalized and are being amortized using the straight-line method over the term of the Revolving Credit Facility which matures in June 2016. Costs incurred in connection with the issuance of our Senior Notes were capitalized and are being amortized using the straight-line method 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 $11.6 million and $6.7 million as of December 31, 2011 and 2010, respectively. We recognized approximately $1.8 million, $1.9 million and $1.5 million of associated amortization during 2011, 2010 and 2009, respectively. In June 2011, we recognized additional amortization expense related to the write-off of $0.6 million of debt issuance costs representing the portion of unamortized debt issuance costs associated with certain syndicate lenders who are no longer participating in the Revolving Credit Facility as amended on June 30, 2011.

4. Leases

We lease our corporate office facilities in San Antonio, Texas at a payment escalating from $29,839 per month in January 2012 to $42,635 per month in December 2020 pursuant to a lease which extends through December 2020, but which is cancelable as early as December 2016 with applicable penalties. We recognize rent expense on a straight line basis for our corporate office lease. In addition, we lease real estate at 72 other locations under non-cancelable operating leases with payments ranging from $250 per month to $30,966 per month, pursuant to leases expiring through August 2022. These real estate locations are used primarily for division offices and storage and maintenance yards. We also lease vehicles, office and other equipment under non-cancelable operating leases expiring through January 2017.

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Future lease obligations required under non-cancelable operating leases as of December 31, 2011 were as follows (amounts in thousands):

Year ended December 31,
2012	$	4,607
2013	3,475
2014	2,499
2015	1,839
2016	1,181
Thereafter	3,806
	$	17,407

Rent expense under operating leases for the years ended December 31, 2011, 2010 and 2009 was $3.6 million, $2.9 million and $2.1 million, respectively.

5. Income Taxes

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

	Year ended December 31,
	2011			2010			2009
Domestic	$	23,396		$	(48,650	)	$	(46,221	)
Foreign	(2,563		)	1,092			6,049
Income (loss) before income tax	$	20,833		$	(47,558	)	$	(40,172	)

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

	Year ended December 31,
	2011			2010			2009
Current tax:
Federal	$	716		$	(2,547	)	$	(46,073	)
State	1,090			32			(2,969		)
Foreign	1,301			931			1,087
	3,107			(1,584		)	(47,955		)
Deferred taxes:
Federal	7,199			(13,046		)	31,740
State	102			1,366			3,390
Foreign	(752		)	(1,033		)	(4,132		)
	6,549			(12,713		)	30,998
Income tax expense (benefit)	$	9,656		$	(14,297	)	$	(16,957	)

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

	Year ended December 31,
	2011			2010			2009
Expected tax expense (benefit)	$	7,291		$	(16,645	)	$	(14,060	)
State income taxes	775			909			274
Incentive stock options	41			266			243
Net tax benefits and nondeductible expenses in foreign jurisdictions	1,391			(207		)	(5,162		)
Domestic production activities deduction	—			—			1,130
Nontaxable interest income	(1		)	(23		)	(33		)
Nondeductible expenses for tax purposes	567			349			218
Valuation allowance	—			1,248			—
Other, net	(408		)	(194		)	433
Income tax expense (benefit)	$	9,656		$	(14,297	)	$	(16,957	)

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

	Year ended December 31,
	2011		2010			2009
Results of operations	$	9,656	$	(14,297	)	$	(16,957	)
Stockholders' equity	255		1,332			(26		)
Income tax expense (benefit)	$	9,911	$	(12,965	)	$	(16,983	)

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, 2011			December 31, 2010
Deferred tax assets:
Auction rate preferred securities	$	1,239		$	1,248
Intangibles	20,829			21,594
Employee benefits and insurance claims accruals	9,126			3,634
Accounts receivable reserve	369			42
Employee stock based compensation	6,914			6,099
Accrued expenses not deductible for tax purposes	1,149			—
Accrued revenue not income for book purposes	2,212			3,393
Federal and state net operating loss and AMT credit carryforward	39,310			21,568
Foreign net operating loss carryforward	6,782			5,713
	87,930			63,291
Valuation allowance	(1,239		)	(1,248		)
Total deferred tax assets	86,691			62,043
Deferred tax liabilities:
Accrued expenses not deductible for tax purposes	—			105
Property and equipment	165,268			132,231
Total deferred tax liabilities	165,268			132,336
Net deferred tax liabilities	$	78,577		$	70,293

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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, 2011, 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, 2011, we had $39.3 million and $6.8 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 2031, 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, 2011, the cumulative undistributed earnings/loss of the subsidiary was approximately a $16.7 million loss. If 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 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, 2011.

We adopted a policy to record interest and penalty expense related to income taxes as interest and other expense, respectively. At December 31, 2011, 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 December 31, 2006 to 2010. Our open tax years for our income tax returns in Colombia are for the years ended December 31, 2008 to 2010.

6. Fair Value of Financial Instruments

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

At December 31, 2011, our financial instruments consist primarily of cash, trade receivables, trade payables, long-term debt, and our ARPSs Call Option. At December 31, 2010, our financial instruments also included our investments in ARPSs, which were liquidated in January 2011. 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.

At December 31, 2010, our ARPSs were reported at amounts that reflected 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. We obtained a quoted market price and liquidated the ARPSs 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 represented 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 represented an other-than-temporary impairment of the ARPSs investment which was reflected as an impairment of investments in our consolidated statement of operations for the year ended December 31, 2010.

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At December 31, 2011, our ARPSs Call Option is reported at an amount that reflects our current estimate of fair value. To estimate the value of our ARPSs Call Option as of December 31, 2011, we used inputs defined by ASC Topic 820 as level 3 inputs, which are significant unobservable inputs. The fair value of the ARPSs Call Option was estimated using a modified Black-Scholes model, based on an analysis of recent historical transactions for securities with similar characteristics to the underlying ARPSs, and an analysis of the probability that the options would be exercisable as a result of the underlying ARPSs being redeemed or traded in a secondary market at an amount greater than the option price before the expiration date. As of December 31, 2011, the ARPSs Call Option had an estimated fair value of $0.3 million, and was included in our other long-term assets in our consolidated balance sheet. Future changes in the fair values of the ARPSs Call Option will be reflected in other income (expense) in our consolidated statements of operations.

The fair value of our long-term debt at December 31, 2011 and 2010 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, 2011 and 2010 (amounts in thousands):

	December 31, 2011				December 31, 2010
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Total debt	$	419,600	$	443,309	$	280,938	$	308,630

7. Earnings (loss) Per Common Share

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

	Year ended December 31,
	2011		2010			2009
Basic
Net income (loss)	$	11,177	$	(33,261	)	$	(23,215	)
Weighted-average shares	57,390		53,797			50,313
Income (loss) per share	$	0.19	$	(0.62	)	$	(0.46	)
Diluted
Net income (loss)	$	11,177	$	(33,261	)	$	(23,215	)
Effect of dilutive securities	—		—			—
Net income (loss) available to common shareholders after assumed conversion	$	11,177	$	(33,261	)	$	(23,215	)
Weighted average shares:
Outstanding	57,390		53,797			50,313
Diluted effect of stock options, restricted stock, and restricted stock unit awards	1,389		—			—
	58,779		53,797			50,313
Income (loss) per share	$	0.19	$	(0.62	)	$	(0.46	)

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

8. Equity Transactions and Stock Based Compensation Plans

Equity Transactions

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 our $300 million shelf registration statement filed in July 2009.

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On July 20, 2011, we obtained $94.3 million in net proceeds when we sold 6,900,000 shares of our common stock at $14.50 per share, less underwriters’ commissions and other offering costs, pursuant to a public offering under our $300 million shelf registration statement. The remaining availability under the $300 million shelf registration statement for equity or debt offerings is $174.2 million.

Stock-based Compensation Plans

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 2,020,889 at December 31, 2011. Of the total shares available, no more than 882,903 shares may be granted in the form of restricted stock.

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

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, and utilizing the graded vesting method.

Stock Options

We grant stock option awards which generally become exercisable over a three-year period and expire ten years after the date of grant. Our stock-based compensation plans 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, 2011, 2010 and 2009:

	Year ended December 31,
	2011		2010		2009
Expected volatility	65	%	62	%	58	%
Risk-free interest rates	1.5	%	2.6	%	2.1	%
Expected life in years	4.33		5.61		5.48
Grant-date fair value	$4.69		$4.91		$2.09

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.

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The following table represents stock option activity from December 31, 2009 through December 31, 2011:

	Number of Shares	Weighted-Average Exercise Price Per Share	Weighted-Average Remaining Contract Life in Years
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
Granted	602,298	9.05
Forfeited	(210,184)	12.41
Exercised	(517,045)	5.58
Outstanding stock options as of December 31, 2011	5,563,348	$10.20	6.3
Stock options exercisable as of December 31, 2011	4,032,111	$11.27	5.6

The following table summarizes the compensation expense recognized for stock option awards during the years ended December 31, 2011, 2010 and 2009 (amounts in thousands):

	Year ended December 31,
	2011		2010		2009
General and administrative expense	$	3,483	$	4,047	$	4,290
Operating costs	237		500		971
	$	3,720	$	4,547	$	5,261

AtDecember 31, 2011, the aggregate intrinsic value of stock options outstanding was $10.1 million and the aggregate intrinsic value of stock options exercisable was $6.5 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 $9.68 on December 31, 2011.

The following table summarizes our nonvested stock option activity from December 31, 2009 through December 31, 2011:

	Number of Shares	Weighted-Average Grant-Date Fair Value Per Share
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
Granted	602,298	4.69
Vested	(1,154,360)	4.03
Forfeited	(101,384)	4.34
Nonvested stock options as of December 31, 2011	1,531,237	$3.98

At December 31, 2011, there was $1.6 million of unrecognized compensation cost relating to stock options which are expected to be recognized over a weighted-average period of 1.2 years.

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.

In January 2012, our Board of Directors approved the grant of stock options representing 470,656 shares of common stock to officers and employees that will vest over a three-year period.

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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, or when RSU awards are converted to restricted stock, shares of our common stock are considered issued, but subject to certain restrictions.

The following table summarizes our restricted stock activity from December 31, 2009 through December 31, 2011:

	Number of Shares	Weighted-Average Grant-Date Fair Value per Share
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
Granted	32,360	12.36
Converted from restricted stock units	166,918	8.86
Vested	(233,061)	8.25
Forfeited	(14,040)	9.16
Nonvested restricted stock as of December 31, 2011	281,836	$7.18

The following table summarizes the compensation expense recognized for restricted stock awards during the years ended December 31, 2011, 2010 and 2009 (amounts in thousands):

	Year ended December 31,
	2011		2010		2009
General and administrative expense	$	941	$	1,119	$	1,641
Operating costs	89		145		314
	$	1,030	$	1,264	$	1,955

At December 31, 2011, there was $0.6 million of unrecognized compensation cost relating to restricted stock awards which are expected to be recognized over a weighted-average period of 0.9 years.

Restricted Stock Units

We grant restricted stock unit awards with vesting based on time of service conditions only (“time-based RSUs”), and we grant restricted stock unit awards with vesting based on time of service, which are also subject to performance and market conditions (“performance-based RSUs”). Shares of our common stock are issued to recipients of restricted stock units only when they have satisfied the applicable vesting conditions.

Our time-based RSUs generally vest over a three-year period, with fair values based on the closing price of our common stock on the date of grant. Our performance-based RSUs are granted at a target number of issuable shares, for which the final number of shares of common stock is adjusted based on our actual achievement levels that are measured against predetermined performance conditions.

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Performance-based RSUs granted during 2011 will cliff vest after 39 months from the date of grant. The number of shares of common stock awarded will be based upon the Company’s achievement in certain performance conditions, as compared to a predefined peer group, over the performance period from January 1, 2011 through December 31, 2013. Approximately one-third of the performance-based RSUs are subject to a market condition, and therefore the fair value of these awards is measured using a Monte Carlo simulation model. Compensation expense for awards with a market condition is reduced only for estimated forfeitures; no adjustment to expense is otherwise made, regardless of the number of shares issued, if any. The remaining two-thirds of the performance-based RSUs are subject to performance conditions, and therefore the fair value is based on the closing price of our common stock on the date of grant, applied to the estimated number of shares that will be awarded. Compensation expense ultimately recognized for awards with performance conditions will be equal to the fair value of the restricted stock unit award based on the actual outcome of the service and performance conditions. As of December 31, 2011, we estimated that our actual achievement level will be approximately 150% of the predetermined performance conditions. Therefore, the outstanding 139,089 restricted stock units would be adjusted to represent 185,452 shares of our common stock.

Performance-based RSUs granted during 2010 have a fair value that is based on the closing price of our common stock on the date of grant. Compensation cost ultimately recognized will be equal to the fair value of the restricted stock unit award based on the actual outcome of the service and performance conditions. In April 2011, we determined that 166,918 shares, or 86.7% of the target number of shares net of forfeitures, were earned based on the Company’s achievement of certain performance measures, as compared to the predefined peer group, over the performance period from January 1, 2008 through December 31, 2010. After the earned number of shares was determined, the performance-based RSUs were converted to 166,918 shares of restricted stock, subject to graded vesting over a three-year period. The first tranche of 55,618 shares vested in April 2011.

The following table summarizes our restricted stock unit activity during 2011 and 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
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
Granted	251,023	11.19	146,479	10.23
Vested	(22,656)	8.92	—	—
Converted to restricted stock	—	—	(192,520)	8.86
Forfeited	(22,496)	11.74	(7,390)	10.23
Nonvested restricted stock units as of December 31, 2011	272,951	$10.76	139,089	$10.23

The following table summarizes the compensation expense recognized for restricted stock unit awards during the years ended December 31, 2011 and 2010 (amounts in thousands):

	Year ended December 31,
	2011		2010
General and administrative expense	$	1,637	$	748
Operating costs	318		116
	$	1,955	$	864

At December 31, 2011, there was $2.6 million of unrecognized compensation cost relating to restricted stock unit awards which are expected to be recognized over a weighted-average period of 1.7 years.

In January 2012, our Board of Directors approved the grant of restricted stock units representing 407,448 shares of common stock to officers and employees that will vest over a three-year period.

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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, 2011, 2010 and 2009 were $2.6 million, $0.9 million and $0.7 million, respectively.

We maintain a self-insurance program, for major medical and hospitalization 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. We have a maximum liability of $150,000 per employee/dependent per year. Amounts in excess of the stated maximum are covered under a separate policy provided by an insurance company. Insurance premiums and deductibles accruals at December 31, 2011 and 2010 include $1.9 million and $1.5 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 a deductible of $250,000 per occurrence under both our general liability insurance and auto liability insurance. 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, 2011 and 2010 include $6.5 million and $6.6 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

We have 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.

Drilling Services Division—Our Drilling Services Division provides contract land drilling services with its fleet of 64 drilling rigs that are assigned to the following locations:

Drilling Division Locations	Rig Count
South Texas	15
East Texas	5
West Texas	18
North Dakota	9
Utah	4
Appalachia	5
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, coiled tubing, 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 currently have a premium fleet of 91 well service rigs consisting of eighty-one 550 horsepower rigs, nine 600 horsepower rigs and one 400 horsepower rig. We currently provide wireline and coiled tubing services with a fleet of 109 and ten wireline and coiled tubing units, respectively, and we provide rental services with approximately $15.1 million of fishing and rental tools.

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The following tables set forth certain financial information for our two operating segments and corporate as of and for the years ended December 31, 2011, 2010 and 2009 (amounts in thousands):

	As of and for the year ended December 31, 2011
	Drilling Services Division		Production Services Division		Corporate		Total
Identifiable assets	$	667,588	$	398,128	$	107,038	$	1,172,754
Revenues	$	433,902	$	282,039	$	—	$	715,941
Operating costs	292,559		164,365		—		456,924
Segment margin	$	141,343	$	117,674	$	—	$	259,017
Depreciation and amortization	$	99,302	$	32,683	$	847	$	132,832
Capital expenditures	$	168,120	$	68,908	$	759	$	237,787

	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

	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 consolidated statements of operations for the years ended December 31, 2011, 2010 and 2009 (amounts in thousands):

	Year ended December 31,
	2011			2010			2009
Segment margin	$	259,017		$	154,779		$	110,182
Depreciation and amortization	(132,832		)	(120,811		)	(106,186		)
General and administrative	(67,318		)	(52,047		)	(37,478		)
Bad debt (expense) recovery	(925		)	(493		)	1,642
Impairment of equipment	(484		)	—			—
Income (loss) from operations	$	57,458		$	(18,572	)	$	(31,840	)

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The following table sets forth certain financial information for our international operations in Colombia as of and for the years ended December 31, 2011, 2010 and 2009 which is included in our Drilling Services Division (amounts in thousands):

	As of and for the years ended December 31,
	2011		2010		2009
Identifiable assets	$	151,448	$	157,509	$	120,319
Revenues	$	109,539	$	86,432	$	56,617

Identifiable assets as of December 31, 2011 and 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. As of December 31, 2009, identifiable assets include five drilling rigs that are owned by our Colombia subsidiary and one drilling rig 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 $54.9 million relating to our performance under these bonds.

The Colombian government enacted a tax reform act which, among other things, adopted a one-time, net-worth tax for all Colombian entities, which was assessed on January 1, 2011 and is payable in eight semi-annual installments from 2011 through 2014. Based on our Colombian operations’ net equity, measured on a Colombian tax basis as of January 1, 2011, our total net-worth tax obligation is approximately $7.3 million, which is not deductible for tax purposes. We recognized this tax obligation in full during the first quarter of 2011 in other expense in our condensed consolidated statement of operations, and in other accrued expenses and other long-term liabilities on our consolidated balance sheet as of December 31, 2011. As of December 31, 2011, the remaining obligation is $5.3 million.

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.

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12. Quarterly Results of Operations (unaudited)

The following table summarizes quarterly financial data for the years ended December 31, 2011 and 2010 (in thousands, except per share data):

Year ended December 31, 2011	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Total
Revenues	$	153,349		$	171,285		$	187,651		$	203,656		$	715,941
Income from operations	5,919			11,918			19,324			20,297			57,458
Income tax (expense) benefit	2,102			(1,039		)	(5,250		)	(5,469		)	(9,656		)
Net income (loss)	(6,035		)	3,650			6,744			6,818			11,177
Earnings (loss) per share:
Basic	$	(0.11	)	$	0.07		$	0.11		$	0.11		$	0.19
Diluted	$	(0.11	)	$	0.07		$	0.11		$	0.11		$	0.19
Year ended December 31, 2010
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	)

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, Go-Coil, 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, 2011, 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.

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CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited, in thousands)

	December 31, 2011
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	91,932		$	(13,879	)	$	8,144		$	—		$	86,197
Receivables, net of allowance for doubtful accounts	(2		)	112,531			32,724			(19		)	145,234
Intercompany receivable (payable)	(122,552		)	131,585			(9,033		)	—			—
Deferred income taxes	1,408			8,644			5,381			—			15,433
Inventory	—			4,533			6,651			—			11,184
Prepaid expenses and other current assets	285			6,304			4,975			—			11,564
Total current assets	(28,929		)	249,718			48,842			(19		)	269,612
Net property and equipment	1,605			675,679			117,422			(750		)	793,956
Investment in subsidiaries	932,237			221,201			—			(1,153,438		)	—
Intangible assets, net of amortization	171			18,829			33,680			—			52,680
Goodwill	—			—			41,683			—			41,683
Noncurrent deferred income taxes	30,835			—			735			(30,835		)	735
Other long-term assets	11,949			2,124			15			—			14,088
Total assets	$	947,868		$	1,167,551		$	242,377		$	(1,185,042	)	$	1,172,754
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	1,090		$	57,150		$	8,200		—			$	66,440
Current portion of long-term debt	—			850			22			—			872
Prepaid drilling contracts	—			1,297			2,669			—			3,966
Accrued expenses	16,779			45,012			6,631			(20		)	68,402
Total current liabilities	17,869			104,309			17,522			(20		)	139,680
Long-term debt, less current portion	417,747			850			131			—			418,728
Noncurrent deferred income taxes	921			124,659			—			(30,835		)	94,745
Other long-term liabilities	137			5,496			3,523			—			9,156
Total liabilities	436,674			235,314			21,176			(30,855		)	662,309
Total shareholders’ equity	511,194			932,237			221,201			(1,154,187		)	510,445
Total liabilities and shareholders’ equity	$	947,868		$	1,167,551		$	242,377		$	(1,185,042	)	$	1,172,754
	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, net of allowance for doubtful accounts	—			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
Noncurrent deferred income taxes	—			94,769			23			(14,632		)	80,160
Other long-term liabilities	267			6,744			2,669			—			9,680
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

82

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited, in thousands)

	Year ended December 31, 2011
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Revenues:	$	—		$	606,402		$	109,539		$	—		$	715,941
Costs and expenses:
Operating costs	—			372,945			83,979			—			456,924
Depreciation and amortization	847			119,520			12,465			—			132,832
General and administrative	19,797			45,152			2,921			(552		)	67,318
Intercompany leasing	—			(4,860		)	4,857			3			—
Bad debt expense	—			925			—			—			925
Impairment of equipment	—			484			—			—			484
Total costs and expenses	20,644			534,166			104,222			(549		)	658,483
Income (loss) from operations	(20,644		)	72,236			5,317			549			57,458
Other (expense) income:
Equity in earnings of subsidiaries	43,182			(2,982		)	—			(40,200		)	—
Interest expense	(29,497		)	(248		)	24			—			(29,721		)
Other	311			1,163			(7,829		)	(549		)	(6,904		)
Total other expense	13,996			(2,067		)	(7,805		)	(40,749		)	(36,625		)
Income (loss) before income taxes	(6,648		)	70,169			(2,488		)	(40,200		)	20,833
Income tax (expense) benefit	17,825			(26,987		)	(494		)	—			(9,656		)
Net income (loss)	$	11,177		$	43,182		$	(2,982	)	$	(40,200	)	$	11,177
	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 expense	—			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		)	(333		)	6			—			(26,567		)
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 (expense) benefit	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	(8,584		)	(444		)	100			—			(8,928		)
Other	1,056			1,362			(91		)	(1,731		)	596
Total other 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 (expense) benefit	—			13,912			3,045			—			16,957
Net earnings (loss)	$	(23,215	)	$	(2,250	)	$	9,245		$	(6,995	)	$	(23,215	)

83

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited, in thousands)

	Year ended December 31, 2011
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations		Consolidated
Cash flows from operating activities:	$	(164,032	)	$	300,198		$	8,713		$	—	$	144,879
Cash flows from investing activities:
Acquisition of production services business of Go-Coil	—			(109,035		)	—			—		(109,035		)
Acquisition of other production services businesses	—			(6,502		)	—			—		(6,502		)
Purchases of property and equipment	(485		)	(200,887		)	(8,694		)	—		(210,066		)
Proceeds from sale of property and equipment	7			5,532			11			—		5,550
Proceeds from sale of auction rate securities	12,569			—			—			—		12,569
	12,091			(310,892		)	(8,683		)	—		(307,484		)
Cash flows from financing activities:
Debt repayments	(111,813		)	(1,345		)	—			—		(113,158		)
Proceeds from issuance of debt	250,750			—			—			—		250,750
Debt issuance costs	(7,285		)	—			—			—		(7,285		)
Proceeds from exercise of options	2,884			—			—			—		2,884
Proceeds from common stock, net of offering costs	94,343			—			—			—		94,343
Purchase of treasury stock	(743		)	—			—			—		(743		)
	228,136			(1,345		)	—			—		226,791
Net increase (decrease) in cash and cash equivalents	76,195			(12,039		)	30			—		64,186
Beginning cash and cash equivalents	15,737			(1,840		)	8,114			—		22,011
Ending cash and cash equivalents	$	91,932		$	(13,879	)	$	8,144		$	—	$	86,197
	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	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

84

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, 2011, 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, 2011 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, 2011. 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, 2011, Pioneer Drilling Company’s internal control over financial reporting was effective based on those criteria.

Management's evaluation of and conclusion regarding the effectiveness of its internal control over financial reporting excludes the internal control over financial reporting of Go-Coil, LLC ("Go-Coil"), which was acquired on December 31, 2011 (as described in Note 2 of Notes to Consolidated Financial Statements). Go-Coil contributed approximately 10% of the Company's total assets as of December 31, 2011.

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, 2011. This report appears on page 53.

Item 9B. Other Information

Not applicable.

85

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 2012 Annual Meeting of Shareholders. We intend to file that definitive proxy statement with the SEC on or about April 10, 2012.

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 2012 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 2012 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 2012 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 2012 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 2012 Annual Meeting of Shareholders for the information this Item 14 requires.

86

PART IV

Item 15. Exhibits and Financial Statement Schedules

(1) Financial Statements.

See Index to Consolidated Financial Statements on page 51.

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:

87

Exhibit Number		Description
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)).
4.4*	-	First Supplemental Indenture, dated November 21, 2011, by and among Pioneer Drilling Company, the subsidiary guarantors party thereto and Wells Fargo Bank, National Association, as trustee (Form 8-K dated November 21, 2011, (File No. 1-8182, Exhibit 4.2)).
4.5*	-	Registration Rights Agreement, dated November 21, 2011, by and among Pioneer Drilling Company, the subsidiary guarantors party thereto and the initial purchasers party thereto (Form 8-K dated November 21, 2011, (File No. 1-8182, Exhibit 4.3)).
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*	-	Purchase Agreement, dated November 15, 2011, by and among Pioneer Drilling Company, the subsidiary guarantors party thereto and the initial purchasers party thereto (Form 8-K dated November 16, 2011 (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 10.1)).
10.4+*	-	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)).
10.5+*	-	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)).
10.6+*	-	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)).

88

Exhibit Number		Description
10.7+*	-	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)).
10.8+*	-	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)).
10.9+*	-	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)).
10.10+*	-	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)).
10.11+*	-	Pioneer Drilling Company 2003 Stock Plan (Form S-8 filed November 18, 2003 (File No. 333-110569, Exhibit 4.4)).
10.12+*	-	Pioneer Drilling Company Amended and Restated 2007 Incentive Plan (Form 10-Q for the quarter ended September 30, 2011 (File No. 1-8182, Exhibit 10.1)).
10.13+*	-	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)).
10.14+*	-	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)).
10.15+*	-	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)).
10.16+*	-	Pioneer Drilling Company Form of Indemnification Agreement (Form 8-K dated August 8, 2007 (File No. 1-8182, Exhibit 10.1)).
10.17+*	-	Pioneer Drilling Company Employee Relocation Policy Executive Officers – Package A (Form 8-K dated August 8, 2007 (File No. 1-8182, Exhibit 10.3)).

89

Exhibit Number		Description
10.18*	-	Amended and Restated Credit Agreement, dated as of June 30, 2011 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 July 5, 2011 (File No. 1-8182, Exhibit 10.1)).
10.19+*	-	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)).
10.20+*	-	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)).
10.21+*	-	Employment Letter, 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)).
12.1**	-	Computation of ratio of earnings to fixed charges.
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).
101#	-	The following financial statements from Pioneer Drilling Company’s Form 10-K for the year ended December 31, 2011, formatted in XBRL (eXtensible Business Reporting Language): (i) Consolidated Balance Sheets, (ii) Consolidated Statements of Operations, (iii) Consolidated Statements of Shareholders' Equity and Comprehensive Income, (iv) Consolidated Statements of Cash Flows, and (v) Notes to Condensed Consolidated Financial Statements, tagged in detail. Information is furnished and not filed and is not incorporated by reference in any registration statement or prospectus for purposes of sections 11 or 12 of the Securities Act of 1933, as amended, is deemed not filed for purposes of section 18 of the Securities Exchange Act of 1934, as amended, and otherwise is not subject to liability under those sections.

 * Incorporated by reference to the filing indicated.

** Filed herewith.

# Furnished herewith.

+ Management contract or compensatory plan or arrangement.

90

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 21, 2012	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	Chairman	February 21, 2012
Dean A. Burkhardt
/S/    WM. STACY LOCKE	President, Chief Executive Officer and Director (Principal Executive Officer)	February 21, 2012
Wm. Stacy Locke
/S/    LORNEE. PHILLIPS	Executive Vice President and Chief Financial Officer	February 21, 2012
Lorne E. Phillips
/S/    C. JOHN THOMPSON	Director	February 21, 2012
C. John Thompson
/S/    JOHN MICHAEL RAUH	Director	February 21, 2012
John Michael Rauh
/S/    SCOTT D. URBAN	Director	February 21, 2012
Scott D. Urban

91

Exhibit Number		Description
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)).
4.4*	-	First Supplemental Indenture, dated November 21, 2011, by and among Pioneer Drilling Company, the subsidiary guarantors party thereto and Wells Fargo Bank, National Association, as trustee (Form 8-K dated November 21, 2011, (File No. 1-8182, Exhibit 4.2)).
4.5*	-	Registration Rights Agreement, dated November 21, 2011, by and among Pioneer Drilling Company, the subsidiary guarantors party thereto and the initial purchasers party thereto (Form 8-K dated November 21, 2011, (File No. 1-8182, Exhibit 4.3)).
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*	-	Purchase Agreement, dated November 15, 2011, by and among Pioneer Drilling Company, the subsidiary guarantors party thereto and the initial purchasers party thereto (Form 8-K dated November 16, 2011 (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 10.1)).
10.4+*	-	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)).
10.5+*	-	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)).

92

Exhibit Number		Description
10.6+*	-	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)).
10.7+*	-	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)).
10.8+*	-	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)).
10.9+*	-	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)).
10.10+*	-	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)).
10.11+*	-	Pioneer Drilling Company 2003 Stock Plan (Form S-8 filed November 18, 2003 (File No. 333-110569, Exhibit 4.4)).
10.12+*	-	Pioneer Drilling Company Amended and Restated 2007 Incentive Plan (Form 10-Q for the quarter ended September 30, 2011 (File No. 1-8182, Exhibit 10.1)).
10.13+*	-	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)).
10.14+*	-	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)).
10.15+*	-	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)).
10.16+*	-	Pioneer Drilling Company Form of Indemnification Agreement (Form 8-K dated August 8, 2007 (File No. 1-8182, Exhibit 10.1)).
10.17+*	-	Pioneer Drilling Company Employee Relocation Policy Executive Officers – Package A (Form 8-K dated August 8, 2007 (File No. 1-8182, Exhibit 10.3)).

93

Exhibit Number		Description
10.18*	-	Amended and Restated Credit Agreement, dated as of June 30, 2011 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 July 5, 2011 (File No. 1-8182, Exhibit 10.1)).
10.19+*	-	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)).
10.20+*	-	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)).
10.21+*	-	Employment Letter, 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)).
12.1**	-	Computation of ratio of earnings to fixed charges.
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).
101#	-	The following financial statements from Pioneer Drilling Company’s Form 10-K for the year ended December 31, 2011, formatted in XBRL (eXtensible Business Reporting Language): (i) Consolidated Balance Sheets, (ii) Consolidated Statements of Operations, (iii) Consolidated Statements of Shareholders' Equity and Comprehensive Income, (iv) Consolidated Statements of Cash Flows, and (v) Notes to Condensed Consolidated Financial Statements, tagged in detail. Information is furnished and not filed and is not incorporated by reference in any registration statement or prospectus for purposes of sections 11 or 12 of the Securities Act of 1933, as amended, is deemed not filed for purposes of section 18 of the Securities Exchange Act of 1934, as amended, and otherwise is not subject to liability under those sections.

 _______________

* Incorporated by reference to the filing indicated.

** Filed herewith.

# Furnished herewith.

+ Management contract or compensatory plan or arrangement.

94