UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-K

(Mark one)

For the periodfiscal year ended December 31, 20082010

or

Commission File Number: 1-8182

PIONEER DRILLING COMPANY

(Exact name of registrant as specified in its charter)

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

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

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

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

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

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  xþ    No  ¨

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

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

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

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

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 Alternext US)Amex) on June 30, 2008)2010) was approximately $932.0$303.8 million.

As of February 6, 2009,4, 2011, there were 49,997,57854,243,452 shares of common stock, par value $0.10 per share, of the registrant issued and outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the proxy statement related to the registrant’s 20092011 Annual Meeting of Shareholders are incorporated by reference into Part III of this report.

TABLE OF CONTENTS

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 thatcontained in this Annual Report on Form 10-K, contains, including those that express a belief, expectation or intention, as well as those that are not statements of historical fact, are forward-looking statements. ThoseSuch 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:

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. 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. 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 importantunpredictable 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.”

In December 2007, our Board of Directors approved a change in our fiscal year end from March 31^st to December 31^st. The fiscal year end change was effective December 31, 2007 and resulted in a nine month reporting period from April 1, 2007 to December 31, 2007. Fiscal years beginning with the year ended December 31, 2008, will represent twelve month reporting periods. We implemented the fiscal year end change to align our United States reporting period with the required Colombian statutory reporting period as well as the reporting periods of peer companies in the industry.

General

Pioneer Drilling Company provides drilling services and production services to independent and major oil and gas exploration and production companies throughout much of the onshore oil and gas producing regions of the United States and internationally in Colombia. Our companyPioneer 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. Over the years, ourOur business has grown through acquisitions and through organic growth. Since September 1999, we have significantly expanded our drilling rig fleet by adding 4235 rigs through acquisitions and by adding 2731 rigs through the construction of rigs from new and used components. On March 1, 2008, weWe significantly expanded our service offerings in March 2008, when we acquired the production services businesses of WEDGE Group Incorporated (“WEDGE”) for $314.7 million and Prairie Investors d/b/a Competition Wireline (“Competition”) for $30.0 million, which provide well services, wireline services and fishing and rental services. We funded the WEDGE acquisition primarily with $311.5 million of borrowings under our $400 million senior secured revolving credit facility. As of February 23, 2009, the senior secured revolving credit facility has an outstanding balance of $257.5 million, all of which matures in February 2013. Drilling services and production services are fundamental to establishing and maintaining the flow of oil and natural gas throughout the productive life atof a well site and enable us to meet multiple needs of our customers.

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

As of February 23, 2009, 364, 2011, 48 drilling rigs are operating 29under drilling contracts. We have 17 drilling rigs that are idle and fivesix drilling rigs located in our Oklahoma drilling division have been placed in storage or “cold stacked” in our Oklahoma drilling division location due to low

demand for drilling rigs in thisthat region. We are actively marketing all our idle drilling rigs. During the second quarter of 2009, we established our Appalachia drilling division location and now have seven drilling rigs andoperating in the Marcellus Shale. In early 2011, we are earning revenue on two

established our West Texas drilling division location with three drilling rigs that were previously included in our East Texas drilling division location. One of these rigs through early termination fees on theirhas begun drilling contracts with terms expiring in March 2009the Permian Basin and May 2009. We are constructing a 1500 horsepower drilling rig that we expect the remaining two rigs to be completed and available for operationbegin operations in the in our North Dakota drilling division under a contract with a three year term beginning March 2009.late February 2011. In addition to our drilling rigs, we provide the drilling crews and most of the ancillary equipment needed to operate our drilling rigs. We obtain our contracts for drilling oil and natural gas wells either through competitive bidding or through direct negotiations with customers. Our drilling contracts generally provide for compensation on either a daywork, turnkey or footage basis. Contract terms generally depend on the complexity and risk of operations, the on-site drilling conditions, the type of equipment used, and the anticipated duration of the work to be performed.

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 iswww.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

In recent months, there has been substantial volatility and a decline in oil and natural gas prices due to the deteriorating global economic environment. In addition, there has been substantial uncertainty in the capital markets and access to financing is uncertain. These conditions have adversely affected our business environment.

Our customers have curtailed their drilling programs and reduced their production activities, which has resulted in a decrease in demand for drilling and production services and a reduction in day rates and utilization. In addition, certain of our customers could experience an inability to pay suppliers in the event they are unable to access the capital markets to fund their business operations.

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. For three years before the end of

From 2004 through 2008, domestic exploration and production spending increased as oil and natural gas prices increased. OilSince late 2008, there has been substantial volatility and a decline in oil and natural gas prices declined significantly atdue to the end of 2008downturn in the global economic environment. In response, our customers curtailed their drilling programs and reduced their production activities, particularly in recent monthsnatural gas producing regions, which resulted in a deteriorating global economic environment, and exploration and production companies have announced cutsdecrease in their exploration budgets for 2009. We expect these reductions in oil and gas exploration budgets to result in a reduction in our rig utilizationdemand and revenue rates for certain of our drilling rigs and production services equipment. Additionally, there was uncertainty in 2009. In addition, we may experience a shiftthe capital markets and access to more turnkey and footage drilling contracts from daywork drilling contracts.financing was limited. These conditions adversely affected our business environment. For additional information concerning the effects of the volatility in oil and gas prices and uncertainty in capital markets, see Item 1A—“Risk Factors” in Part I of this Annual Report on Form 10-K.

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

On February 6, 20094, 2011, the spot price for West Texas Intermediate crude oil was $40.17,$89.03, the spot price for Henry Hub natural gas was $4.67$4.47 and the Baker Hughes land rig count was 1,330,1,696, a 21% decrease33% increase from 1,6771,280 on February 8, 2008.5, 2010. The average weekly spot prices of West Texas Intermediate crude oil and Henry Hub natural gas, the average weekly domestic land rig count per the Baker Hughes land rig count, and the average monthly domestic workoverwell service rig count for the year ended December 31, 2008, the nine months ended December 31, 2007 and each of the previouslast five years ended March 31 were:

Increased expenditures for exploration and production activities generally lead to increased demand for our drilling services and production services. OverAs represented in the past several years, risingtable above, increases in oil and natural gas prices and thefrom 2004 to late 2008 resulted in corresponding increase in onshore oil and natural gas exploration and production spending led to expanded drilling and well service activity as reflected by the increases in the U.S. land rig counts and U.S. workoverwell service rig counts, overwhile declines in prices from late 2008 to late 2009 led to decreases in the previous five years.U.S. land rig counts and U.S. well service rig counts. Since late 2009, increases in oil and natural gas prices have caused modest increases in exploration and production spending and the corresponding increases in drilling and well services activities is reflected by increases in the U.S. land rig counts and the U.S. well service rig counts in 2010.

Our business is influenced substantially by both operating and capital expenditures by exploration and production companies. Exploration and production spending is generally categorized as either a capital expenditure or an operating expenditure. Activities designed to add hydrocarbon reserves are classified as capital expenditures, while those associated with maintaining or accelerating production are categorized as operating expenditures.

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 even a short periodlong 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.

Our business is influenced substantially by both operating and capital expenditures by exploration and production companies. Because existing oil and natural gas wells require ongoing spending to maintain production, expenditures by exploration and production companies for the maintenance of existing wells are relatively stable and predictable. In contrast, capital expenditures by exploration and production companies for exploration and drilling are more directly influenced by current and expected oil and natural gas prices and generally reflect the volatility of commodity prices.

Competitive Strengths

Our competitive strengths include:

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

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 operatesoperate in active drilling markets in the United States.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 evolve into a premier multi-service,further enhance our geographic diversification through selective international oilfield services provider.expansion. The key elements of this long-term strategy include:

•

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

With the recent decline in oil and natural gas prices due to the deteriorating global economic environment and the expected reductions in our rig utilization and revenue rates in 2009, our near-term strategy is to maintain a strong balance sheet and ample liquidity. Management has initiated certain cost reduction measures including workforce and wage rate reductions that will reduce operating expenses during the downturn in the industry cycle. Budgeted capital expenditures for 2009 represent routine capital expenditures necessary to keep our equipment in safe and efficient working order and limited discretionary capital expenditures of new equipment or upgrades of existing equipment. In addition, our marketing initiatives are focused on identifying regional opportunities and evaluating more turnkey drilling contract opportunities. We believe this near-term strategy will position us to take advantage of business opportunities and continue our long-term growth strategy.

Overview of Our Segments and Services

Drilling Services Division

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

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

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

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

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

Drilling fluid, often called mud, is a mixture of clays, chemicals and water or oil, which is carefully formulated for the particular well being drilled. Drilling mud accounts for a major portion of the cost incurred and equipment used in drilling a well. Bulk storage of drilling fluid materials, the pumps and the mud-mixing equipment are placed at the start of the circulating system. Working mud pits and reserve storage are at the other end of the system. Between these two points, the circulating system includes auxiliary equipment for drilling fluid maintenance and equipment for well pressure control. Within the system, the drilling mud is typically

routed from the mud pits to the mud pump and from the mud pump through a standpipe and the rotary hose to the drill stem. The drilling mud travels down the drill stem to the bit, up the annular space between the drill stem and the borehole and through the blowout preventer stack to the return flow line. It then travels to a shale shaker for removal of rock cuttings, and then back to the mud pits, which are usually steel tanks. The reserve pits, usually one or two fairly shallow excavations, are used for waste material and excess water around the location.

In a continuing effort to improve our drilling rig fleet, we have installed top drives in 1035 rigs (with four additional spare top drives available for installation), iron roughnecks in 3745 rigs, walkingwalking/skidding systems in one rig13 rigs (with three otheradditional walking/skidding systems available for installation) and automatic catwalks in twoeight rigs. These upgrades provide our customers with drilling rigs that have more varied capabilities for drilling in unconventional plays, and they improve our efficiency and safety. Top drives provide maximum torque and rotational control, improved well control and better hole conditioning. In horizontal drilling, operators can utilize top drives to reach formations that may not be accessible with conventional rotary drilling. An iron roughneck is a remotely operated pipe handling feature on the rig floor, which is used to help reduce the occurrence of repetitive motion injuries and decrease drill pipe tripping time. Walking systems increase efficiency by allowing

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

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

Our drilling rig fleet consists of 70 rigs. Not included in our 70 drilling rig count is a 1500 horsepower rig that we expect to be completed and available for operation in our North Dakota drilling division under a contract with a three year term beginning March 2009. We own all the rigs in our fleet. With the recent decline in demand for drilling services, as of February 23, 2009, we have 36 drilling rigs operating, 29 drilling rigs are idle and five drilling rigs located in our Oklahoma division have been placed in storage or “cold stacked” due to low demand for drilling rigs in this region. We are actively marketing all our idle drilling rigs and we are earning revenues on two of these rigs through early termination fees on these drilling contracts with terms expiring in March 2009 and May 2009.

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

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 6, 2009,4, 2011, we ownedown a fleet of 8055 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.

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 and footage contracts that expose us to greater risk of loss without commensurate increases in potential contract profitability.

We obtain our contracts for drilling oil and gas wells either through competitive bidding or through direct negotiations with customers. Our drilling contracts generally provide for compensation on either a daywork, turnkey or footage basis. The contract terms we offer generally depend on the complexity and risk of operations, the on-site drilling conditions, the type of equipment used and the anticipated duration of the work to be performed. Generally, our contracts provide for the drilling of a single well and typically permit the customer to terminate on short notice. However, we have entered into more longer-term drilling contracts during periods of high rig demand. In addition, we generally construct new drilling rigs once we have entered into longer-term drilling contracts for such rigs. As of February 6, 2009,Currently, we had 27have 32 contracts with terms of six months to three years in duration,duration. Of these 32 contracts, if not renewed at the end of which 18their terms, 14 will expire by August 6, 2009,15, 2011, 11 will expire by February 15, 2012, one will expire by August 15, 2012 and six have a remaining term of six to 12 months, one has a remaining term of 12 to 18 months and two have a remaining term in excess of 18 months. We have one additional drilling rig under contract that we expect will begin operating in late February 2011 with a six month term.

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

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

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

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

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

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

Production Services Division

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

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

In addition to periodic maintenance, producing oil and gas wells occasionally require major repairs or modifications called workovers, which are typically more complex and more time consuming than maintenance operations. Workover services include extensions of existing wells to drain new formations either through perforating the well casing to expose additional productive zones not previously produced, deepening well bores to new zones or the drilling of lateral well bores to improve reservoir drainage patterns. Our workoverwell 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 workoverwell 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 servicingservice rigs are designed to perform complex workover operations. A workover may require a few days to several weeks and generally requires additional auxiliary equipment. The demand for workover services is sensitive to oil and gas producers’ intermediate and long-term expectations for oil and gas prices.

Completion services involve the preparation of newly drilled wells for production. The completion process may involve selectively perforating the well casing in the productive zones to allow oil or gas to flow into the well bore, stimulating and testing these zones and installing the production string and other downhole equipment. We provide well service rigs to assist in this completion process. Newly drilled wells are frequently completed by well servicingservice 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 servicingservice 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 December 31, 2008,February 4, 2010, our fleet of well service rigs totaled 7475 rigs.

These rigs are located mostly in Texas, serving the Gulf Coast and ArkLaTex regions, though we also have fivenine rigs in Louisiana and fourMississippi and nine rigs in North Dakota. We estimate that approximately 20% of our rigs are located in predominantly oil regions while 80% of our rigs are located in predominantly natural gas regions. Our fleet is one ofamong the youngestnewest in the industry, consisting primarily of premium, 550 HPhorsepower 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 5986 wireline trucks.units, as of February 4, 2011. We provide these services in Texas, Kansas, Colorado, Utah, Montana, North Dakota, Louisiana, West Virginia, Wyoming and North Dakota.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 servicingservice rig when there is no requirement to remove tubulars from the well in order to make repairs. Wireline trucks, like well servicingservice rigs, are utilized throughout the life of a well.

Fishing and Rental Services. Our rental and fishing tool business provides a range of specialized services and equipment that are utilized on a non-routine basis for both drilling and well servicing operations. Drilling and well servicingservice 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 servicingservice rig package. The important rental tools that we offer include air drilling equipment, foam units, power swivels, and blowout preventers.

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

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

Customers

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

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, Inc.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:

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

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

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

Production Services Division

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

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

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

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

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

The level of our revenues, earnings and cash flows are substantially dependent upon, and affected by, the level of domestic and international oil and gas exploration and development activity, as well as the equipment capacity in any particular region. For a more detailed discussion, see Item 7. “Management’s7—“Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Raw Materials

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

Operating Risks and Insurance

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

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

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. We can offer no assurance that ourOur insurance or indemnification arrangements willmay 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 to our drillingproduction services equipment is based on our estimates of the cost of comparable used equipment to replace the insured property. The policy provides for a deductible on drilling rigs of $250,000 per occurrence ($500,000 deductible for rigs with an insured value greater than $10 million)., and a deductible on production services equipment of $100,000 per occurrence. Our third-party liability insurance coverage is $51 million per occurrence and in the aggregate, with a deductible of $260,000 per occurrence. We believe that we are adequately insured for public liability and property damage to others with respect to our operations. However, such insurance may not be sufficient to protect us against liability for all consequences of well disasters, extensive fire damage or damage to the environment.

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

Employees

We currently have approximately 1,9522550 employees. Approximately 247300 of these employees are salaried administrative or supervisory employees. The rest of our employees are hourly employees working in operations for our Drilling Services Division and Production Services Division.Division and are primarily compensated on an hourly basis. The number of hourly employees in operations fluctuates depending on the utilization of our drilling rigs, workoverwell service rigs and wireline units at any particular time. None of our employment arrangements are subject to collective bargaining arrangements.

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

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

Facilities

Our corporate office facilities are located at 1250 N.E. Loop 410, Suite 1000 San Antonio, Texas 78209 and are leased with costspayments escalating from $26,809$27,911 per month in January 2011 to $29,316 per month with a non-cancelable lease term expiring in December 2013.

We conduct our business operations through 4050 other real estate locations in the United States (Texas, Oklahoma, Colorado, Utah, Montana, North Dakota, Pennsylvania, West Virginia, Wyoming, Mississippi, Arkansas, Louisiana and Kansas) and internationally in Colombia. These real estate locations are primarily used for divisionregional offices and storage and maintenance yards. We own 1011 of these real estate locations and the remaining 3039 real estate locations are leased with costspayments ranging from $175$250 per month to $8,917$27,169 per month with non-cancelable lease terms expiring through April 2013.August 2015.

Governmental Regulation

Our operations are subject to stringent laws and regulations relating to containment, disposal and controlling the discharge of hazardous oilfield waste and other non-hazardous waste material into the environment, requiring removal and cleanup under certain circumstances, or otherwise relating to the protection of the environment. In addition, our operations are often conducted in or near ecologically sensitive areas, such as wetlands and coastal areas of the Gulf of Mexico, which are

subject to special protective measures and which may expose us to additional operating costs and liabilities for accidental discharges of oil, natural gas, drilling fluids or contaminated water, or for noncompliance with other aspects of applicable laws. We are also subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable state statutes. The OSHA hazard communication standard, the Environmental Protection Agency (“EPA”) “community right-to-know” regulations under Title III of the Federal Superfund Amendment and Reauthorization Act and comparable state statutes require us to organize and report information about the hazardous materials we use in our operations to employees, state and local government authorities and local citizens.

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

There are a variety of regulatory developments, proposals or requirements and legislative initiatives that have been introduced in the United States and international regions in which we operate that are focused on

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

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

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

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

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

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

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

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

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

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

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

Available Information

Our Web siteWebsite address iswww.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 atwww.sec.gov that contains reports, proxy and information statements and other information regarding issuers that file electronically. We have also posted on our Web siteWebsite our: Charters for the Audit, Compensation, and Nominating and Corporate Governance Committees of our Board; Code of Conduct and Ethics; Rules of Conduct; and Company Contact Information.

Item 1A.

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 by oil and gas 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. 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:

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. Oil and gas prices have been volatile historically and, we believe, will continue to be so in the future. Many factors beyond our control affect oil and gas prices, including:

As a result of recent declinesOil 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 substantial uncertainty in the capital markets due to the deteriorating global economic environment, our customerswhile oil prices have reduced spending on exploration and production and this has resulted in a decrease in demand for our services. We are unable to determine whether customers and/or vendors and suppliers will be able to access financing necessary to sustain their current level of operations, fulfill their commitments and/or fund future operations and obligations. The deteriorating global economic environment may impact industry fundamentals, and the potential resulting decrease in demand for drilling and production services could adversely affect our business.

Oil and natural gas prices, and market expectations of potential changes in these prices, significantly impact the level of worldwide drilling and production services activities. Oil andimproved during 2010, natural gas prices have declined significantly during recent monthsremained depressed. Future declines in a deteriorating global economic environment. This declineand volatility in oil and natural gas prices as well as the current crisis in the global credit markets, have caused exploration and production companies to reduce their overall level of drilling and production services activity and spending. When drilling and production activity and spending declines, both day rates and utilization have historically declined. As a result, the recent declines in oil and natural gas prices and the global economic crisis could materially and adversely affect our business and financial results.

Moreover, the deteriorating global economic environment may impact fundamentals that are critical to our industry, such as the global demand for, and consumption of, oil and natural gas. Reduced demand for oil and natural gas generally results in lower prices for these commodities and may impact the economics of planned drilling projects and ongoing production projects, resulting in the curtailment, reduction, delay or postponement of such projects for an indeterminate period of time. Companies that planned to finance exploration, development or production projects through the capital markets may be forced to curtail, reduce, postpone or delay drilling or production services activities, and also may experience inability to pay suppliers. The deteriorating global economic environment could also impact our vendors and suppliers’ ability to meet obligations to provide materials and services in general. If any of the foregoing were to occur, it could have a material adverse effect on our business and financial results.

Risks Relating to Our Business

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

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

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

We encounter substantial competition from other drilling contractors and other oilfield service companies. Our primary market areas are highly fragmented and competitive. The fact that drilling workover and well-servicingwell 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:

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 workover and well-servicingwell service rigs intensifies price competition and makes it more difficult for us to compete on the basis of factors other than price. In all of the markets in which we compete, an oversupply of rigs can cause greater price competition, which can reduce our profitability.

We face competition from many competitors with greater resources.

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

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 maywill 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 workover and well-servicingwell services industries, including the risks of:

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

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 face increased exposure to operating difficulties because we primarily focus on providing drilling and production services for natural gas.

Most of our drilling and production contracts are with exploration and production companies in search of natural gas. Drilling on land for natural gas generally occurs at deeper drilling depths than drilling for oil. Although deep-depth drilling and production services expose us to risks similar to risks encountered in shallow-depth drilling and production services, the magnitude of the risk for deep-depth drilling and production services is greater because of the higher costs and greater complexities involved in providing drilling and production services for deep wells. We generally do not insure risks related to operating difficulties other than blowouts. If we do not adequately insure the increased risk from blowouts or if our contractual indemnification rights are insufficient or unfulfilled, our profitability and other results of operations and our financial condition could be adversely affected in the event we encounter blowouts or other significant operating difficulties while providing drilling or production services at deeper depths.

Our current primary focus on drilling for customers in search of natural gas could place us at a competitive disadvantage if we were to change our primary focus to drilling for customers in search of oil.

Our drilling rig fleet consists of rigs capable of drilling on land at drilling depths of 6,000 to 18,000 feet because most of our contracts are with customers drilling in search of natural gas, which generally occurs at deeper drilling depths than drilling in search of oil, which often occurs at drilling depths less than 6,000 feet. Generally, larger drilling rigs capable of deep drilling generally incur higher mobilization costs than smaller drilling rigs drilling at shallower depths. If our primary focus shifts from drilling for customers in search of natural gas to drilling for customers in search of oil, the majority of our rig fleet would be disadvantaged in competing for new oil drilling projects as compared to competitors that primarily use shallower drilling depth rigs when drilling in search of oil.

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 are occurringhave 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 March 31, 2003,September 1999, we have significantly expanded our drilling rig fleet has increased from 24 to 70 drillingby adding 35 rigs as a result ofthrough acquisitions and rig construction.by adding 31 rigs through the construction of rigs from new and used components. In addition, during the first quarter of 2008, we completed the acquisition of the production services businesses of WEDGE and Competition.Competition during the first quarter of 2008. We have continued to invest in the expansion of our operations and plan to add a total of six well service rigs and 14 wireline units in the first half of 2011.

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

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.

For several years we have had little or no long-term debt. In connection with the acquisition of the production services businesses of WEDGE and Competition in March 2008, we entered into a new $400 million, five-year, senior secured revolving credit facility.facility (the “Revolving Credit Facility”) which was later amended in October 2009 and February 2010. In March 2010, we issued $250 million of Senior Notes with a coupon interest rate of 9.875% that are due in 2018 (the “Senior Notes”). We received $234.8 million of net proceeds from the issuance of the Senior Notes after deductions were made for the $10.6 million of original issue discount and $4.6 million for underwriters’ fees and other debt offering costs. The net proceeds were used to repay a portion of the borrowings outstanding under our Revolving Credit Facility. As of December 31, 2008,2010, our total debt was approximately $272.5$280.9 million.

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

We anticipate that our cash generated by operations and our ability to borrow under the currently unused portion of our senior secured revolving credit facilityRevolving 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:

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 senior secured revolving credit facilityRevolving Credit Facility or other instruments governing any future indebtedness, we could be in default under the terms of our senior secured revolving credit facilityRevolving Credit Facility or such instruments. In the event of a default, the Lenderslenders under our senior secured revolving credit facilityRevolving 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 senior secured revolving credit facility imposesRevolving Credit Facility and our Senior Notes impose restrictions on us that may affect our ability to successfully operate our business.

Our senior secured revolving credit facilityRevolving Credit Facility limits our ability to take various actions, such as:

In addition, our senior secured revolving credit facilityRevolving 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:

The failure to comply with any of these financialrestrictions or conditions, some of which become more restrictive over time, such as financial ratios or

covenants, would cause an event of default under our senior secured revolving credit facility.Revolving Credit Facility or our Senior Notes. An event of default, if not waived, could result in acceleration of the outstanding indebtedness, under our senior secured revolving credit facility, 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 financings,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 senior secured revolving credit facility.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:

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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.

Our combined operating history may not be sufficient for investors to evaluate our business and prospects.

The acquisition of the production services businesses of WEDGE and Competition significantly expanded our operations and assets. Our historical combined financial statements include financial information based on the separate production services businesses of WEDGE and Competition. As a result, the historical and pro forma information presented may not provide an accurate indication of what our actual results would have been if the acquisition of the production services businesses of WEDGE and Competition had been completed at the beginning of the periods presented or of what our future results of operations are likely to be. Our future results will depend on our ability to efficiently manage our combined operations and execute our business strategy.

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 Corporation ActOrganizations Code and other applicable laws and by our credit facilities. Our debt arrangements include provisions that generally prohibit us from paying dividends on our capital stock, including our common stock.

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

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

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

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

We may continue to experience market conditions that could adversely affect the liquidity of our auction rate preferred security investment.

At December 31, 2008, we held $15.9 million (par value) of investments comprised of tax exempt, auction rate preferred securities (“ARPSs”), which are variable-rate preferred securities and have a long-term maturity with the interest rate being reset through “Dutch auctions” that are held every 7 days. The ARPSs have historically traded at par because of the frequent interest rate resets and because they are callable at par at the option of the issuer. Interest is paid at the end of each auction period. Our ARPSs are AAA/Aaa rated securities, collateralized by municipal bonds and backed by assets that are equal to or greater than 200% of the liquidation preference. Until February 2008, the auction rate securities market was highly liquid. Beginning mid-February 2008, we experienced several “failed” auctions, meaning that there was not enough demand to sell all of the securities that holders desired to sell at auction. The immediate effect of a failed auction is that such holders cannot sell the securities at auction and the interest rate on the security resets to a maximum auction rate. We have continued to receive interest payments on our ARPSs in accordance with their terms. Unless a future auction is successful or the issuer calls the security pursuant to redemption prior to maturity, we may not be able to access the funds we invested in our ARPSs without a loss of principal. We have no reason to believe that any of the underlying municipal securities that collateralize our ARPSs are presently at risk of default. We believe we will ultimately be able to liquidate our investments without material loss primarily due to the collateral securing the ARPSs. We do not currently intend to attempt to sell our ARPSs at a discount since our liquidity needs are expected to be met with cash flows from operating activities and our senior secured revolving credit facility. Our ARPSs are designated as available-for-sale and are reported at fair market value with the related unrealized gains or losses, included in accumulated other comprehensive income (loss), net of tax, a component of shareholders’ equity. The estimated fair value of our ARPSs at December 31, 2008 was $13.9 million compared with a par value of $15.9 million. The $2.0 million difference represents a fair value discount due to the current lack of liquidity which is considered temporary and is recorded as an unrealized loss. We would recognize an impairment charge if the fair value of our investments falls below the cost basis and is judged to be other-than-temporary. Our ARPSs are classified with other long-term assets on our consolidated balance sheet as of December 31, 2008 because of our inability to the determine recovery period of our investments.

Not applicable.

For a description of our significant properties, see “Business—Overview of Our Segments and Services”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.

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.

We did not submit any matter to a vote of our shareholders during the quarter ended December 31, 2008.

PART II

As of February 6, 2009, 49,997,5784, 2011, 54,243,452 shares of our common stock were outstanding, held by 560515 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 American Stock Exchange (NYSE Alternext US)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 American Stock Exchange (NYSE Alternext US):NYSE Amex:

The last reported sales price for our common stock on the American Stock Exchange (NYSE Alternext US)NYSE Amex on February 6, 20094, 2011 was $5.08$9.56 per share.

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

No shares of our common stock were purchased by or on behalf of our company or any affiliated purchaser during the fiscal yearquarter ended December 31, 2008.2010.

Performance Graph

The following graph compares, for the periods from December 31, 20032005 to December 31, 2008,2010, the cumulative total shareholder return on our common stock with the (1) cumulative total return on the companies that comprise the AMEX Composite Index (2) an old peer group index that includes the five companies that primarily provide contract drilling services, and (3) a new peer group index that includes five companies that provide contract drilling services and / or production services. With the acquisition of WEDGE and Competition on March 1, 2008, we expanded our operations beyond providing only contract drilling services and began providing production services. We believe the companies included in the new peer group index better reflect our peers with similar service offerings. The comparison assumes that $100 was invested on December 31, 2003 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 Helmerich & Payne, Inc., Grey Wolf, Inc., Patterson-UTI Energy, Inc., Nabors Industries Ltd. and Unit Corp. The companies that comprise the new peer group index are Patterson-UTI Energy, Inc., Nabors Industries Ltd., Bronco Drilling Company, Precision Drilling Trust and Key Energy Services.

Equity Compensation Plan Information

The following table provides informationcomparison assumes that $100 was invested on our equity compensation plans as of December 31, 2008:2005 in our common stock, the companies that compose the AMEX Composite Index and the companies that compose the peer group index, and further assumes all dividends were reinvested.

Item 6.

Item 6.

Selected Financial Data

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

Item 7.

Item 7.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

Statements we make in the following discussion that express a belief, expectation or intention, as well as those that are not historical fact, are forward-looking statements that are subject to risks, uncertainties and assumptions. Our actual results, performance or achievements, or industry results, could differ materially from those we express in the following discussion as a result of a variety of factors, including general economic and business conditions and industry trends, the continued strength or weakness of the contract land drilling industry in the geographic areas in which we operate, decisions about onshore exploration and development projects to be made by oil and gas exploration and production companies, the highly competitive nature of our business, the availability, terms and deployment of capital, the availability of qualified personnel, and changes in, or our failure or inability to comply with, government regulations, including those relating to the environment. We have discussed many of these factors in more detail elsewhere in this report, including under the headings “Special Note Regarding Forward-Looking Statements” in the Introductory Note to Part I and “Risk Factors” in Item 1A. These factors are not necessarily all the important factors that could affect us. Unpredictable or unknown factors we have not discussed in this report or could also have material adverse effecteffects 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. Our companyPioneer 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. Over the years, ourOur business has grown through acquisitions and through organic growth. Since September 1999, we have significantly expanded our drilling rig fleet by adding 4235 rigs through acquisitions and by adding 2731 rigs through the construction of rigs from new and used components. On March 1, 2008, we significantly expanded our service offerings when we acquired the production services businesses of WEDGE Group Incorporated (“WEDGE”) for $314.7 million and Prairie Investors d/b/a Competition Wireline (“Competition”) for $30.0 million, which provide well services, wireline services and fishing and rental services. We funded the WEDGE acquisition primarily with $311.5 million of borrowings under our $400 million senior secured revolving credit facility. As of February 23, 2009, the senior secured revolving credit facility had an outstanding balance of $257.5 million, all of which matures in February 2013. Drilling services and production services are fundamental to establishing and maintaining the flow of oil and natural gas throughout the productive life atof a well site and enable us to meet multiple needs of our customers.

Business Segments

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

As of February 23, 2009, 364, 2011, 48 drilling rigs are operating 29under drilling contracts. We have 17 drilling rigs that are idle and fivesix drilling rigs located in our Oklahoma drilling division have been placed in storage or “cold stacked” in our Oklahoma drilling division due to low demand for drilling rigs in thisthat region. We are actively marketing all our idle drilling rigs both domestically and internationally in Latin America. During the second quarter of 2009, we are earning revenue on twoestablished our Appalachia drilling division location and now have seven drilling rigs operating in the Marcellus Shale. In early 2011, we established our West Texas drilling division location with three drilling rigs that were previously included in our East Texas drilling division location. One of these rigs through early termination fees on theirhas begun drilling contracts with a term expiring in March 2009the Permian Basin and May 2009. We are constructing a 1500 horsepower drilling rig that we expect the remaining two rigs to be completed and available for operationbegin operations in the in our North Dakota drilling division under a contract with a three year term beginning March 2009.late February 2011. In addition to our drilling rigs, we provide the drilling crews and most of the ancillary equipment needed to operate our drilling rigs. We obtain our contracts for drilling oil and natural gas wells either through competitive bidding or through direct negotiations with customers. Our drilling contracts generally provide for compensation on either a daywork, turnkey or footage basis. Contract terms generally depend on the complexity and risk of operations, the on-site drilling conditions, the type of equipment used and the anticipated duration of the work to be performed.

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 companies to evaluate the integrity of wellbore casing, recover pipe, or install bridge plugs. Our truck mounted wireline units have an average age of 3.7 years as of December 31, 2008.

Market Conditions in Our Industry

In recent months, there has been substantial volatility and a decline in oil and natural gas prices due to the deteriorating global economic environment. In addition, there has been substantial uncertainty in the capital markets and access to financing is uncertain. These conditions have adversely affected our business environment. Our customers have curtailed their drilling programs and reduced their production activities, which has resulted in a decrease in demand for drilling and production services and a reduction in day rates and utilization. In addition, certain of our customers could experience an inability to pay suppliers in the event they are unable to access the capital markets to fund their business operations.

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. For three years before the end of

From 2004 through 2008, domestic exploration and production spending increased as oil and natural gas prices increased. OilSince late 2008, there has been substantial volatility and a decline in oil and natural gas prices declined significantly atdue to the end of 2008downturn in the global economic environment. In response, our customers curtailed their drilling programs and reduced their production activities, particularly in recent monthsnatural gas producing regions, which has resulted in a deteriorating global economic environment, and exploration and production companies have announced cutsdecrease in their exploration budgets for 2009. We expect these reductions in oil and gas exploration budgets to result in a reduction in our rig utilizationdemand and revenue rates for certain of our drilling rigs and production services equipment. Additionally, there was uncertainty in 2009. In addition, we may experience a shiftthe capital markets and access to more turnkey and footage drilling contracts from daywork drilling contracts.financing was limited. These conditions adversely affected our business environment. For additional information concerning the effects of the volatility in oil and gas prices and uncertainty in capital markets, see Item 1A—“Risk Factors” in Part I of this Annual Report on Form 10-K.

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

On February 6, 20094, 2011, the spot price for West Texas Intermediate crude oil was $40.17,$89.03, the spot price for Henry Hub natural gas was $4.67$4.47 and the Baker Hughes land rig count was 1,330,1,696, a 21% decrease33% increase from 1,6771,280 on February 8, 2008.5, 2010. The average weekly spot prices of West Texas Intermediate crude oil and Henry Hub natural gas, the average weekly domestic land rig count per the Baker Hughes land rig count, and the average monthly domestic workoverwell service rig count for the year ended December 31, 2008, the nine months ended December 31, 2007 and each of the previouslast five years ended March 31 were:

Increased expenditures for exploration and production activities generally leads to increased demand for our drilling services and production services. Over

As represented in the past several years, risingtable above, increases in oil and natural gas prices and thefrom 2004 to late 2008 resulted in corresponding increase in onshore oil and natural gas exploration and production spending led to expanded drilling and well service activity as reflected by the increases in the U.S. land rig counts and U.S. workoverwell service rig counts, overwhile declines in prices from late 2008 to late 2009 led to decreases in the previous five years.

With the recent declineU.S. land rig counts and U.S. well service rig counts. Since late 2009, increases in oil and natural gas prices due to the deteriorating global economic environmenthave caused modest increases in exploration and production spending and the expected reductionscorresponding increases in our rig utilizationdrilling and revenue rates in 2009, our near-term strategywell services activities is to maintain a strong balance sheet and ample liquidity. Management has initiated certain cost reduction measures including workforce and wage rate reductions that will reduce operating expenses during the downturnreflected by increases in the industry cycle. BudgetedU.S. land rig counts and the U.S. well service rig counts in 2010.

Our business is influenced substantially by both operating and capital expenditures for 2009 represent routine capital expenditures necessary to keep our equipment in safeby exploration and efficient working order and limited discretionary capital expenditures of new equipment or upgrades of existing equipment. In addition, our marketing initiatives are focused on identifying regional opportunities and evaluating more turnkey drilling contract opportunities. We believe this near-term strategy will position us to take advantage of business opportunities and continue our long-term growth strategy.

production companies. Exploration and production spending is generally categorized as either a capital expenditure or an operating expenditure. Activities designed to add hydrocarbon reserves are classified as capital expenditures, while those associated with maintaining or accelerating production are categorized as operating expenditures.

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 even a short periodlong 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.

Our business is influenced substantially by both operating and capital expenditures by exploration and production companies. 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 acquisitions. Our principal sources of liquidity consist of: (i) cash and cash equivalents (which equaled $26.8$22.0 million as of December 31, 2008)2010); (ii) cash generated from operations; and (iii) the unused portion of our senior secured revolving credit facility (the “Revolving Credit Facility”). Our Revolving Credit Facility provides for a senior secured revolving credit facility, with sub-limits for letters of credit and swing-line loans, of up to an aggregate principal amount of $225 million, all of which hasmatures on August 31, 2012. We made a $12.8 million principal payment after December 31, 2010, which resulted in a $25.0 million outstanding balance under our Revolving Credit Facility and $9.2 million in committed letters of credit at February 4, 2011. Therefore, our borrowing availability of $133.2under our Revolving Credit Facility was $190.8 million as of February 23, 2009.4, 2011. There are no limitations on our ability to access the full borrowing availability under the senior secured revolving credit facilityRevolving Credit Facility other than maintaining compliance with the covenants in the credit agreement. Our principal liquidity requirements have been for working capital needs, capital expenditures and acquisitions.

On February 29, 2008, we entered into a credit agreement with Wells Fargo Bank, N.A. and a syndicate of lenders (collectivelyRevolving Credit Facility. Additional information regarding these covenants is provided in the “Lenders”). The credit agreement provides for a senior secured revolving credit facility, with sub-limits for letters of credit and a swing-line facility of up to an aggregate principal amount of $400 million, all of which mature on February 28, 2013. The senior secured revolving credit facility and the obligations thereunder are secured by substantially all our domestic assets and are guaranteed by certain of our domestic subsidiaries.Debt Requirements section below. Borrowings under the senior secured revolving credit facility bear interest,Revolving Credit Facility are available for acquisitions, working capital and other general corporate purposes. We presently expect that cash and cash equivalents, cash generated from operations and available borrowings under our Revolving Credit Facility are adequate to cover our liquidity requirements for at our option, atleast the next 12 months.

On March 11, 2010, we issued $250 million of 9.875% unregistered senior notes due 2018 (the “Senior Notes”), and received $234.8 million net proceeds, after deducting the bank prime rate or atoriginal issue discount, underwriters’ fees and other debt offering costs, which were used to reduce the LIBOR rate, plus an applicable per annum marginoutstanding debt balance under our Revolving Credit Facility. The Senior Notes will mature on March 15, 2018 with interest due semi-annually in arrears on March 15 and September 15 of each case. The applicable per annum margin is determined based upon our leverage ratio in accordance with a pricing grid inyear, commencing on September 15, 2010. We have the credit agreement. The per annum margin for LIBOR rate borrowings ranges from 1.50%option to 2.50% and for bank prime rate borrowings ranges from 0.50% to 1.50%. Based onredeem the terms in the credit agreement, the LIBOR margin and bank prime rate margin in effect until delivery of our financial statements and the compliance certificate for December 31, 2008 were 2.25% and 1.25%, respectively. A commitment fee is due quarterly based on the average daily unused amount of the commitments of the Lenders under the senior secured revolving credit facility. In addition, a fronting fee is due for each letter of credit issued and a quarterly letter of credit fee is due based on the average undrawn amount of letter of credit outstanding during such period. We may repay the senior secured revolving credit facility balance outstandingSenior Notes, in whole or in part, at any time without premiumon or penalty. The senior secured revolving credit facility replacedafter March 15, 2014 in each case at the $20.0redemption price specified in the Indenture dated March 11, 2010 (the “Indenture”) together with any accrued and unpaid interest to the date of redemption. Prior to March 15, 2014, we may also redeem the Senior Notes, in whole or in part, at a “make-whole” redemption price specified in the Indenture, together with any accrued and unpaid interest to the date of redemption. In addition, prior to March 15, 2013, we may, on one or more occasions, redeem up to 35% of the aggregate principal amount of the Senior Notes at a redemption price of 109.875% of the principal amount, plus any accrued and unpaid interest to the redemption date, with the net proceeds of certain equity offerings, if at least 65% of the aggregate principal amount of the Senior Notes remains outstanding after such redemption and the redemption occurs within 120 days of the closing of the equity offering. In accordance with a registration rights agreement with the holders of our Senior Notes, we filed an exchange offer registration statement on Form S-4 with the Securities and Exchange Commission that became effective on September 2, 2010. This exchange offer registration statement enabled the holders of our Senior Notes to exchange their Senior Notes for publicly registered notes with substantially identical terms. References to the “Senior Notes” herein include the Senior Notes issued in the exchange offer.

In July 2009, we filed a shelf registration statement that permits us to sell equity or debt in one or more offerings up to a total dollar amount of $300 million. In November 2009, we obtained $24.0 million credit facilityin net proceeds when we previously had with Frost National Bank. Borrowingssold 3,820,000 shares of our common stock at $6.75 per share, less underwriters’ commissions, pursuant to a public offering under the senior secured revolving credit facility were used to fund the WEDGE acquisition and are available for future acquisitions, working capital and other general corporate purposes.

At February 23, 2009, we had $257.5$300 million outstanding under the revolving portion of the senior secured revolving credit facility and $9.3 million in committed letters of credit. Under the terms of the credit agreement, committed letters of credit are applied against our borrowing capacity under the senior secured revolving credit facility.shelf registration statement. The borrowingremaining availability under the senior secured revolving credit facility was $133.2$300 million at February 23, 2009. Principal payments of $15.0shelf registration statement for equity or debt offerings is $274.2 million made after December 31, 2008 are classified in the current portion of long-term debt as of December 31, 2008. The outstanding balance under our senior secured credit facility is not due until maturity on February 28, 2013. However, when cash and working capital is sufficient,4, 2011. In the future, we may make principal paymentsconsider equity or debt offerings, as appropriate, to reduce the outstanding debt balance prior to maturity.meet our liquidity needs.

At December 31, 2008,2010, we held $15.9 million (par value) of investments comprised of tax exempt, auction rate preferred securities (“ARPSs”),ARPSs, which arewere variable-rate preferred securities and havehad a long-term maturity with the interest rate being reset through “Dutch auctions” that arewere held every 7seven days. The ARPSs havehad historically traded at par because of the frequent interest rate resets and because they arewere callable at par at the option of the issuer. Interest iswas paid at the end of each auction period. Our ARPSs arewere AAA/Aaa rated securities, collateralized by municipal bonds and backed by assets that arewere equal to or greater than 200% of the liquidation preference. Until February 2008, the auction rate securities market was highly liquid. Beginning mid-February 2008, we experienced several “failed” auctions, meaning that there was not enough demand to sell all of the securities that holders desired to sell at auction. The immediate effect of a failed auction iswas that such holders cannotcould not sell the securities at auction and the interest rate on the security resetsreset to a maximum auction rate. We have continued to receive interest payments on our ARPSs in accordance with their terms. Unless

On January 19, 2011, we entered into an agreement with a future auction is successful orfinancial institution to sell the issuer calls the security pursuant to redemption prior to maturity, we may not be able to access the funds we invested in our ARPSs without a loss of principal. We have no reason to believe that anyfor $12.6 million, which represents 79% of the underlying municipal securities that collateralize ourpar value, plus accrued interest. Under the agreement, we retained the unilateral right for a period ending January 7, 2013 to: (a) repurchase all the ARPSs are presently at risk of default. We believe we will ultimately be able to liquidate our investments without material loss primarily duethe $12.6 million price at which they were initially sold to the collateral securingfinancial institution; and (b) if not repurchased, receive additional proceeds from the ARPSs. We do not currently intend to attempt to sell ourfinancial institution upon redemption of the ARPSs at a discount since our liquidity needs are expected to be met with cash flows from operating activities and our senior secured revolving credit facility. Our ARPSs are designated as available-for-sale and are reported at fair market value withby the related unrealized gains or losses, included in accumulated other comprehensive income (loss), net of tax, a component of shareholders’ equity. The estimated fair value of our ARPSs at December 31, 2008 was $13.9 million compared with a par value of $15.9 million. The $2.0 million difference represents a fair value discount due to the current lack of liquidity which is considered temporary and is recorded as an unrealized loss. We would recognize an impairment charge if the fair value of our investments falls below the cost basis and is judged to be other-than-temporary. Our ARPSs are classified with other long-term assets on our consolidated balance sheet as of December 31, 2008 because of our inability to determine the recovery period of our investments.original issuer.

Uses of Capital Resources

On March 1, 2008, we acquired the production services business of WEDGE which provided well services, wireline services and fishing and rental services with a fleet of 62 workover rigs, 45 wireline units and approximately $13 million of fishing and rental tools equipment through facilities in Texas, Kansas, North Dakota, Colorado, Montana, Utah and Oklahoma. The aggregate purchase price for the acquisition was approximately $314.7 million, which consisted of assets acquired of $340.8 million and liabilities assumed of $26.1 million. The aggregate purchase price included $3.4 million of costs incurred to acquire the production services business from WEDGE. We financed the acquisition with approximately $3.2 million of cash on hand and $311.5 million of debt incurred under our new $400 million senior secured revolving credit facility.

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

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

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

For the yearyears ended December 31, 20082010 and the nine months ended December 31, 2007, the additions to2009, our primary uses of capital resources were property and equipment additions that consisted of the following (amounts in thousands):

We capitalized $0.5 million and $0.3 million of interest costs in property and equipment forduring the yearyears ended December 31, 20082010 and no capitalized interest cost for the nine months ended December 31, 2007.2009, respectively.

We constructed a 1500 horsepower drilling rig that was completed and placed into service in December 2008. As of December 31, 2008, we were constructing another 1500-horsepower drilling rig that we expect to complete and place in service in March 2009. Our Drilling Services Division incurred $28.4 million of rig

construction costs for these two 1500 horsepowerperformed significant upgrade projects on 24 drilling rigs during the year ended December 31, 2008. In2010, primarily in connection with obtaining new drilling contracts in unconventional plays and Colombia. These projects included the installation of 16 top drives, five iron roughnecks, two automatic catwalks and 11 walking/skidding systems. During the year ended December 31, 2009, we performed significant upgrade projects on seven drilling rigs, including the addition of 11 top drives to our Production Services Division incurred $20.2 million acquiring 14 workover rigs and $5.0 million acquiring 10 wireline unitsdrilling rigs. Also during the year ended December 31, 2008. During2009, we incurred $13.7 million of rig construction costs to complete construction of a 2000 horsepower drilling rig which was placed into service in June 2009.

Our Production Services Division acquired 20 and five wireline units, as well as auxiliary equipment for well service rigs, during the nine monthsyears ended December 31, 2007,2010 and 2009, respectively, which is reflected in the new-builds and acquisitions section of the table above.

Currently, we incurred $56.2expect to spend approximately $140 million to purchase and upgrade the 3 drilling rigs acquired for expansion into international markets.

For the fiscal year ending December 31, 2009, we project$150 million on capital expenditures of approximately $84.5 million, comprised of newly approvedduring 2011. We expect the total capital expenditures offor 2011 will be allocated approximately $50.2 million75% for our Drilling Services Division and approximately $15.0 million25% for our Production Services Division and previously approvedDivision. Our planned capital expenditures from 2008for the year ending December 31, 2011 include 14 wireline units and six well service rigs that we expect will go into service during the first half of approximately $19.3 million2011 and two new-build drillings rigs. We will not begin construction of these new-build drilling rigs unless we have secured long-term contracts. Actual capital expenditures may vary depending on the level of new-build and other expansion opportunities that will be carried overmeet our strategic and incurred in 2009.return on capital criteria. We expect to fund these capital expenditures primarily from operating cash flow in excess of our working capital and other normal cash flow requirements.requirements, and from borrowings under our Revolving Credit Facility, as necessary.

Working Capital

Our working capital was $64.4$76.1 million at December 31, 2008,2010, compared to $99.8$90.3 million at December 31, 2007.2009. Our current ratio, which we calculate by dividing our current assets by our current liabilities, was 1.82.0 at December 31, 20082010 compared to 3.42.9 at December 31, 2007.2009.

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

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

The decrease in cash and cash equivalents was primarily due to our use$131.0 million used for purchases of $147.5 million for certain property and equipment, expenditures, debt payments of $87.8 million and $39.2 million of cash to fund the WEDGE, Competition, Paltec, Inc. and Pettus Well Service acquisitions. These uses of cash and cash equivalents were partially offset by $186.4 million of cash provided by operating activitiesoperations of $98.4 million and $12.7 million in proceeds from debt borrowings, undernet of debt repayments and issuance costs, during the credit lineyear ended December 31, 2010.

Short-term investments as of $47.9 million.December 31, 2010 represent our ARPS which were classified as available for sale as of December 31, 2010, and were liquidated in January 2011. At December 31, 2009, these investments were classified as long-term investments due to our inability to determine the recovery period for these investments at that time.

The increaseincreases in our trade receivables atand unbilled receivables as of December 31, 20082010 as compared to December 31, 2007 was2009 were due to receivables of $20.7 million at December 31, 2008 that relate to our new Production Services Division that was formed when we acquired the production services businesses of WEDGE and Competition on March 1, 2008, an

increase in receivablesrevenues of $14.7$67.4 million, for our Drilling Services Division and an increase of $4.4 million for federal income tax refunds. The increase in receivables for our Drilling Services Division is primarily due to a $2,774 per day increase in average revenue rates and a 3.5% increase in the number of revenue daysor 83%, for the quarter ended December 31, 2008,2010 as compared to the quarter ended December 31, 2007.2009, and due to the timing of the billing and collection cycles for long-term drilling contracts in Colombia.

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

The increase in unbilled receivables at December 31, 2008 as compared to December 31, 2007 was primarilydeferred income taxes is due to anthe movement of our deferred tax assets related to net operating losses for our Colombian operations from long-term to current. We now expect to realize the deferred tax assets in the short-term due to the increase in unbilled receivables of $4.5 million that relate to our drilling contracts in Colombia.Colombian operations through 2010.

The increase in inventory at December 31, 20082010 as compared to December 31, 20072009 was primarily due to the additionexpansion of inventory of $1.6 millionour operations in Colombia, which accounted for our new Production Services Division and an increase of $1.1$2.4 million of inventorythe increase, with the remaining increase primarily relateddue to the expansion of our third, fourth and fifth drilling rigs that began operating in Colombia in February 2008, August 2008 and November 2008, respectively.domestic wireline services operations during 2010. We maintain inventories of replacement parts and supplies for our drilling rigs operating in Colombia to ensure efficient operations in geographically remote areas. During 2010, we exported our seventh and eighth drilling rigs to Colombia and established an additional inventory level for these two additional rigs.

The increase in prepaid expenses and other current assets at December 31, 20082010 as compared to December 31, 20072009 is primarily due to $2.2 millionan increase in prepaid expenses and other current assets of our new Production Services Division. The increase also relates to additional prepaid insurance and deferred mobilization costs for the third, fourth and fifthfour drilling rigs that began operating in Colombia in 2008. In addition, prepaid expenses and other current assets increased by $0.9 million relating to funds held in a trust account that will be distributed to our former Chief Financial Officer on March 2, 2009 in accordance withnew long-term drilling contracts during the terms ofyear ended December 31, 2010. These deferred mobilization costs are being amortized over the severance agreement and $0.7 million relating to funds held in escrow that will be paid to the former owner of Competition.related contract terms.

The increase in accounts payable was primarily due to $4.6 million for our new Production Services Division and an increase of $1.5 million in accounts payable for our expanded operations in Colombia during 2008. The overall increase in accounts payable was partially offset by a decrease in drilling equipment purchases that were accrued at December 31, 20082010 as compared to December 31, 2007.

The2009 is due to the overall increase in the demand for drilling, well services, wireline services and fishing and rental services during the quarter ended December 31, 2010 as compared to the quarter ended December 31, 2009. Our operating costs increased $37.1 million, or 65%, during the fourth quarter of 2010 as compared to the fourth quarter of 2009. In addition, our capital expenditures accruals increased for the quarter ended December 31, 2010 as compared to the quarter ended December 31, 2009, accounting for $4.1 million of the increase in accounts payable. Both the increase in the demand for our services and the increase in capital expenditures led to an increase in purchases from our vendors.

The current portion of long-term debt at December 31, 20082010 relates to $1.4 million of debt payments under our subordinated notes payable and other debt that are due within the next year.

Prepaid drilling contracts represent amounts billed for mobilization revenues in excess of revenue recognized for certain drilling contracts. Mobilization billings, and costs incurred for the mobilization, are deferred and recognized over the term of the related drilling contracts. The increase in prepaid drilling contracts at December 31, 2010 as compared to December 31, 2009 is primarily due to principal paymentsan increase in deferred mobilization revenues for four of the drilling rigs in Colombia that were made afterbegan new long-term drilling contracts during the year ended December 31, 2008 to reduce the outstanding balance of our senior secured revolving credit facility and the current portion of our subordinated notes payable. The outstanding balance under our senior secured credit facility is not due until maturity on February 28, 2013. However, when cash and working capital is sufficient, we may make principal payments to reduce the outstanding debt balance prior to maturity.2010.

The increase in accrued payroll and related employee costs was due to an increase in the number of employees primarily due to workforce additions and increased accruals for higher bonuses for 2010, both of which are a result of higher demand for our new Production Services Divisiondrilling and an increase in the number of days represented in the payroll accrual at December 31, 2008 as compared to December 31, 2007. In addition, accrued payroll and related employee costs increased due to the payment obligation of $0.9 million to our former Chief Financial Officer.

The increase in accrued insurance premiums and deductibles was primarily due to increases in costs incurred for the self-insurance portion of our health and workers compensation insurance and other insurance costsproduction services during the year ended December 31, 20082010. Our employee count increased by approximately 850 people, or 50%, as of December 31, 2010, as compared to December 31, 2007.2009.

The increase in other accrued expensesAccrued interest at December 31, 2008 as compared2010 primarily relates to the outstanding debt balance for our Senior Notes, while accrued interest at December 31, 2007 is2009 primarily duerelated to $1.8the 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 accrued expensesan effective yield to maturity of our new Production Services Division and an increaseapproximately 10.677%. The proceeds from the issuance of $1.5 million relatingthe Senior Notes were immediately used to our expanded operations in Colombia during 2008. In addition, accrued expenses increased due tomake a payment obligation of $0.7$234.8 million to reduce the former owner of Competition, as noted inoutstanding debt balance under the prepaid and other current asset description above.Revolving Credit Facility.

Long-term Debt

Long-term debtThe Revolving Credit Facility had an interest rate of 3.74% as of December 31, 2008 consists2009 which was based on the LIBOR rate plus a per annum margin, with interest payments due monthly. The Senior Notes have a higher interest rate as compared to the Revolving Credit Facility, with interest payments due semi-annually, which resulted in an increase in accrued interest as of the following (amounts in thousands):December 31, 2010.

Long-term Debt and Other Contractual Obligations

The following table includes all our contractual obligations of the types specified below at December 31, 20082010 (amounts in thousands):

Long-term debt consists of $272.5$37.8 million outstanding under our senior secured credit facility, $6.5Revolving Credit Facility, $250 million face amount outstanding under our Senior Notes, $3.0 million outstanding under subordinated notes payable to certain employees that are former shareholders of previously acquired production services businesses, and other debt of $0.4$0.1 million. The $37.8 million outstanding balance under our senior secured credit facilityRevolving Credit Facility is not due untilat maturity on February 28, 2013, but principal payments of $15.0 million made after DecemberAugust 31, 2008 are classified in the current portion of long-term debt as of December 31, 2008. We2012. However, we may make principal payments to reduce the outstanding debt balance prior to maturity when cash and working capital is sufficient. The outstanding balance under our Senior Notes has a carrying value of $240.1 million, which represents the $250 million face value net of the $9.9 million of original issue discount, net of amortization. The discount is being amortized over the term of the Senior Notes based on the effective interest method. The Senior Notes will mature on March 15, 2018. Our subordinated notes payable have final maturity dates ranging from January 2011 to April 2013.

Interest payment obligations on our senior secured credit facilityRevolving Credit Facility are estimated based on (1) the 4.77% interest ratesrate that arewas in effect on February 6, 2009,4, 2011 and (2) $15.0 million of principal payments that have been made after December 31, 2008 to reduce the outstanding principal balance and (3) the remaining principal balance of $257.5$37.8 million at December 31, 2010 to be paid at maturity in February 2013.August 2012. Interest payment obligations on our Senior Notes are calculated based on the coupon interest rate of 9.875% due semi-annually in arrears on March 15 and September 15 of each year, commencing on September 15, 2010, through maturity. Interest payment obligations on our subordinated notes payable are based on interest rates ranging from 5.44%5.4% to 14%, with either quarterly or annual payments of principal and interest and final maturity dates ranging from January 2009 to March 2013.through maturity.

Purchase obligations primarily relate to drilling rigequipment upgrades and workover rig upgrades, acquisitions orpurchases of new construction.equipment.

Operating leases consist of lease agreements with terms in excess of one year for office space, operating facilities, equipment and personal property.

As of December 31, 2008,2010, we had restricted cash in the amount of $3.3$2.0 million held in an escrow account to be used for future payments in connection with the acquisition of Competition. The former owner of Competition will receive annual installments of $0.7 million payable over a five year termthe remaining three years from the escrow account. In addition, we had restricted cash in the amount of $0.9 million in a trust account that will be distributed to our former Chief Financial Officer on March 2, 2009 in accordance with the terms of the severance agreement.

Debt Requirements

Effective June 11, 2008, we entered into a Waiver AgreementThe Revolving Credit Facility contains customary mandatory prepayments in respect of asset dispositions, debt incurrence and equity issuances, which are applied to reduce outstanding revolving and swing-line loans and

letter of credit exposure. There are no limitations on our ability to access the $225 million borrowing capacity under the Revolving Credit Facility other than maintaining compliance with the Lenders to waive the requirement to provide certain financial statements in conjunction with our compliance certificate within the time period required by the credit agreement. The Waiver Agreement required us to provide the financial statements and our compliance certificate on or before August 13, 2008. Until we provided these financial statements and our compliance certificate, the aggregate principal amount outstanding under the credit agreement could not exceed $350 million at any time (provided, however, that the commitment fee would continue to be calculated based on the total commitment of $400 million), and the per annum margin applicable to all amounts outstanding under the credit agreement would increase from the current rate of 2.25% for LIBOR rate borrowings and 1.25% for bank prime rate borrowings to 2.50% for LIBOR rate borrowings and 1.50% for bank prime rate borrowings. The required financial statements and our compliance certificate were delivered concurrently with the filing of the Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2008 which occurred on August 5, 2008.

covenants. At December 31, 2008,2010, we were in compliance with the restrictiveour financial covenants. Our total consolidated leverage ratio was 2.7 to 1.0, our senior consolidated leverage ratio was 0.4 to 1.0 and our interest coverage ratio was 4.2 to 1.0.

The financial covenants contained in the credit agreement whichour Revolving Credit Facility include the following:

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

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

In addition, any unused portion of the capital expenditure threshold up to 1.00.$30 million can be carried over from the immediate preceding fiscal year.

At December 31, 2008,2010, our senior consolidated leverage ratio was 1.28not greater than 2.50 to 1.00 and, our interest coverage ratio was 17.15therefore, we were not subject to 1.00. the capital expenditure threshold restrictions listed above.

The credit agreementRevolving Credit Facility has additional restrictive covenants that, among other things, limit the incurrence of additional debt, to a maximum of $15 million (other than debt under the senior secured revolving credit facility), investments, liens, dividends, acquisitions, redemptions of capital stock, prepayments of indebtedness, asset dispositions, mergers and consolidations, transactions with affiliates, capital expenditures, hedging contracts, sale leasebacks and other matters customarily restricted in such agreements. In addition, the credit agreementRevolving 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. Non-compliance with restrictive covenants or other events of default

Our obligations under the credit agreement could triggerRevolving Credit Facility are secured by substantially all of our domestic assets (including equity interests in Pioneer Global Holdings, Inc. and 65% of the outstanding equity interests of any first-tier foreign subsidiaries owned by Pioneer Global Holdings, Inc., but excluding any equity interest in, and any assets of, Pioneer Services Holdings, LLC) and are guaranteed by certain of our domestic subsidiaries, including Pioneer Global Holdings, Inc.

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

These covenants are subject to important exceptions and qualifications.

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

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

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

Critical Accounting Policies and Estimates

Revenue and cost recognition

—Our Drilling Services Division earns revenues by drilling oil and gas wells for our customers under daywork, turnkey or footage contracts, which usually provide for the drilling of a single well. We recognize revenues on daywork contracts for the days completed based on the dayrate each contract specifies. We recognize revenues from our turnkey and footage contracts on the percentage-of-completion method based on our estimate of the number of days to complete each contract. Individual contracts are usually completed in less than 60 days. The risks to us under a turnkey contract and, to a lesser extent, under footage contracts, are substantially greater than on a contract drilled on a daywork basis. Under a turnkey contract, we assume most of the risks associated with drilling operations that are generally assumed by the operator in a daywork contract, including the risks of blowout, loss of hole, stuck drill pipe, machinery breakdowns and abnormal drilling conditions, as well as risks associated with subcontractors’ services, supplies, cost escalations and personnel operations.

Our management has determined that it is appropriate to use the percentage-of-completion method, as defined in the American Institute of Certified Public Accountants’ Statement of Position 81-1,Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) Topic 605,Revenue Recognition, to recognize revenue on our turnkey and footage contracts. Although our turnkey and footage contracts do not have express terms that provide us with rights to receive payment for the work that we perform prior to drilling wells to the agreed-on depth, we use this method because, as provided in applicable accounting literature, we believe we achieve a continuous sale for our work-in-progress and believe, under applicable state law, we ultimately could recover the fair value of our work-in-progress even in the event we were unable to drill to the agreed-on depth in breach of the applicable contract. However, in the event we were unable to drill to the agreed-on depth in breach of the contract, ultimate recovery of that value would be subject to negotiations with the customer and the possibility of litigation.

If a customer defaults on its payment obligation to us under a turnkey or footage contract, we would need to rely on applicable law to enforce our lien rights, because our turnkey and footage contracts do not expressly grant to us a security interest in the work we have completed under the contract and we have no ownership rights in the work-in-progress or completed drilling work, except any rights arising under the applicable lien statute on foreclosure. If we were unable to drill to the agreed-on depth in breach of the contract, we also would need to rely on equitable remedies outside of the contract including quantum meruit, 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 of certain drilling contracts.term. Costs incurred to relocate rigs and other drilling equipment to areas in which a contract has not been secured are expensed as incurred. Reimbursements that we receive for out-of-pocket expenses are recorded as revenue and the out-of-pocket expenses for which they relate are recorded as operating costs.

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

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

Long-lived Assets and Intangible AssetsAssets—

We evaluate for potential impairment of long-lived assets and intangible assets subject to amortization when indicators of impairment are present, as defined in SFAS No. 144,ASC Topic 360,Accounting for the Impairment or Disposal of Long-Lived AssetsProperty, Plant, and Equipment and ASC Topic 350,Intangibles—Goodwill and Other. Circumstances that could indicate a potential impairment include significant adverse changes in industry trends, economic climate, legal factors, and an adverse action or assessment by a regulator. More

specifically, significant adverse changes in industry trends include significant declines in revenue rates, utilization rates, oil and natural gas market prices and industry rig counts for drilling rigs and workoverwell 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.

We performed an impairment analysis of our long-lived assets and intangible assets at December 31, 2008, due to significant adverse changes in the economic and business climate that resulted in decreases in estimated revenues, margins and cash flows. Essentially all our intangible assets were recorded in connection with the acquisitions of the production services businesses from WEDGE, Competition, Pettus and Paltec when revenues, margins and cash flows were at historically high levels earlier in early 2008. We determined that the sum of the estimated future undiscounted net cash flows iswas less than the carrying amount of the long-lived assets and

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

GoodwillGoodwill—

Goodwill results from business acquisitions and represents the excess of acquisition costs over the fair value of the net assets acquired. We account for goodwill and other intangible assets under the provisions of SFAS No. 142,Goodwill and Other Intangible Assets.ASC Topic 350. Goodwill is tested for impairment annually as of December 31 or more frequently if events or changes in circumstances indicate that the asset might be impaired. Circumstances that could indicate a potential impairment include a significant adverse change in the economic or business climate, a significant adverse change in legal factors, an adverse action or assessment by a regulator, unanticipated competition, loss of key personnel and the likelihood that a reporting unit or significant portion of a reporting unit will be sold or otherwise disposed of. These circumstances could lead to our net book value exceeding our market capitalization which is another indicator of a potential impairment in goodwill. SFAS No. 142ASC Topic 350 requires a two-step process for testing impairment. First, the fair value of each reporting unit is compared to its carrying value to determine whether an indication of impairment exists. All our goodwill is related to our Production Services Division operating segment and is allocated to its three reporting units which are well services, wireline services and fishing and rental services. Second, if impairment is indicated, then the fair value of the reporting unit’sunit's goodwill is determined by allocating the unit’sunit's fair value to its assets and liabilities (including any unrecognized intangible assets) as if the reporting unit had been acquired in a business combination on the impairment test date. The amount of impairment for goodwill is measured as the excess of the carrying value of the reporting unit over its fair value. Goodwill of $118.6 million was initially recorded in connection with the acquisitions of the production services businesses from WEDGE, Competition, Pettus and Paltec, all of which occurred between March 1, 2008 and October 1, 2008, and was allocated to the three reporting units for our Production Services Division which are well services, wireline services and fishing and rental services. We recorded a full impairment of this goodwill during the year ended December 31, 2008 as further described below.

When estimating fair values of a reporting unit for our goodwill impairment test, we use a combination of an income approach and a market approach which incorporates both management’s views and those of the market. The income approach provides an estimated fair value based on each reporting unit’s anticipated cash

flows that arewere discounted using a weighted average cost of capital rate. The market approach provides an estimated fair value based on our market capitalization that iswas 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 arewere then equally weighted and combined into a single fair value. The primary assumptions used in the income approach arewere estimated cash flows and weighted average cost of capital. Estimated cash flows arewere primarily based on projected revenues, operating costs and capital expenditures and are discounted based on comparable industry average rates for weighted average cost of capital. We utilized discount rates based on weighted average cost of capital ranging from 15.8% to 16.7% when we estimated fair values of our reporting units as of December 31, 2008. The primary assumptions used in the market approach iswere the allocation of total market capitalization to each reporting unit, which iswas based on projected EBITDA percentages for each reporting unit, and control premiums, which arewere based on comparable industry averages. We utilized a 30% control premium when we estimated fair values of our reporting units as of December 31, 2008. To ensure the reasonableness of the estimated fair values of our reporting units, we performperformed 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 requirerequired management judgment.

Our common stock price per share declined in market value from $13.30 at September 30, 2008, to $5.57 at December 31, 2008, which resulted in our net book value exceeding our market capitalization during most of this that

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

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

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

Deferred taxestaxes—

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, foreign 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, workoverwell service rigs and wireline units over 2 to 25 years and refurbishments over 3 to 5 years, while federal income tax rules require that we depreciate drilling rigs, workoverwell service rigs and wireline units and refurbishments over 5 years. Therefore, in the first 5 years of our ownership of a drilling rig, workoverwell service rig or wireline unit, our

tax depreciation exceeds our financial reporting depreciation, resulting in our providing deferred taxes on this depreciation difference. After 5 years, financial reporting depreciation exceeds tax depreciation, and the deferred tax liability begins to reverse.

Accounting estimatesestimates—

We consider the recognition of revenues and costs on turnkey and footage contracts to be critical accounting estimates. On these types of contracts, we are required to estimate the number of days needed for us to complete the contract and our total cost to complete the contract. Our actual costs could substantially exceed our estimated costs if we encounter problems such as lost circulation, stuck drill pipe or an underground blowout on contracts still in progress subsequent to the release of the financial statements. We receive payment under turnkey and footage contracts when we deliver to our customer a well completed to the depth specified in the contract, unless the customer authorizes us to drill to a more shallow depth. Since 1995, we have completed all our turnkey or footage contracts. Although our initial cost estimates for turnkey and footage contracts do not include cost estimates for risks such as stuck drill pipe or loss of circulation, we believe that our experienced management team, our knowledge of geologic formations in our areas of operations, the condition of our drilling equipment and our experienced crews have previously enabled us to make reasonable cost estimates and complete contracts according to our drilling plan. While we do bear the risk of loss for cost overruns and other events that are not specifically provided for in our initial cost estimates, our pricing of turnkey and footage contracts takes such risks into consideration. When we encounter, during the course of our drilling operations,

conditions unforeseen in the preparation of our original cost estimate, we increase our cost estimate to complete the contract. If we anticipate a loss on a contract in progress at the end of a reporting period due to a change in our cost estimate, we accrue the entire amount of the estimated loss, including all costs that are included in our revised estimated cost to complete that contract, in our consolidated statement of operations for that reporting period. During the year ended December 31, 2008,2010, we experienced losses on six of the 81 turnkey and footage contracts completed, with a loss of less than $25,000 each$0.2 million on three of these contracts andone turnkey contract. During the year ended December 31, 2009, we did not experience a loss of less than $130,000 each on the remaining three contracts.any turnkey or footage contracts completed. We are more likely to encounter losses on turnkey and footage contracts in periods in which revenue rates are lower for all types of contracts. During periods of reduced demand for drilling rigs, our overall profitability on turnkey and footage contracts has historically exceeded our profitability on daywork contracts.

Revenues and costs during a reporting period could be affected for contracts in progress at the end of a reporting period which have not been completed before our financial statements for that period are released. We did not have anyhad one turnkey orand no footage contracts in progress at December 31, 2008.2010. The turnkey contract was completed prior to the release of the financial statements included in this report. Our unbilled receivables of $12.3totaled $21.4 million at December 31, 2008 did not include any amounts2010. Of that amount accrued, turnkey drilling contract revenues were $1.3 million. The remaining balance of unbilled receivables related to turnkey or footage contracts.$18.7 million of the revenue recognized but not yet billed on daywork drilling contracts in progress at December 31, 2010 and $1.4 million related to unbilled receivables for our Production Services Division.

We estimate an allowance for doubtful accounts based on the creditworthiness of our customers as well as general economic conditions. We evaluate the creditworthiness of our customers based on commercial credit reports, trade references, bank references, financial information, production information and any past experience we have with the customer. Consequently, any change in those factors could affect our estimate of our allowance for doubtful accounts. In some instances, we require new customers to establish escrow accounts or make prepayments. We typically invoice our customers at 15-day intervals during the performance of daywork contracts and upon completion of the daywork contract. Turnkey and footage contracts are invoiced upon completion of the contract. Our typical contract provides for payment of invoices in 10 to 30 days. We generally do not extend payment terms beyond 30 days and have not extended payment terms beyond 90 days for any of our contracts in the last three fiscal years. We had an allowance for doubtful accounts of $1.6$0.7 million at December 31, 20082010 and no allowance for doubtful accounts$0.3 million at December 31, 2007.2009.

Our determination of the useful lives of our depreciable assets, which directly affects our determination of depreciation expense and deferred taxes is also a critical accounting estimate. A decrease in the useful life of our property and equipment would increase depreciation expense and reduce deferred taxes. We provide for depreciation of our drilling, production, transportation and other equipment on a straight-line method over useful lives that we have estimated and that range from 2 to 25 years. We record the same depreciation expense whether

a drilling rig, workoverwell service rig or wireline unit is idle or working. Our estimates of the useful lives of our drilling, production, transportation and other equipment are based on our more than 35 years of experience in the oilfield services industry with similar equipment. Effective January 1, 2008, we reassessed the estimated useful lives assigned to a group of 19 drilling rigs that were recently constructed. These drilling rigs were constructed with new components that have longer estimated useful lives when compared to other drilling rigs that are equipped with older components. As a result, we increased the estimated useful lives for this group of recently constructed drilling rigs from an average useful life of 9 years to 12 years. This change in the estimated useful lives of this group of 19 drilling rigs resulted in a $3.8 million decrease in depreciation and amortization expense for the year ended December 31, 2008.

As of December 31, 2008,2010, we had foreigna $1.2 million deferred tax asset related to the $3.3 million impairment of our ARPSs which will represent a capital loss for tax treatment purposes. We can recognize a tax benefit associated with this impairment to the extent of capital gains we expect to earn in future periods. We recorded a valuation allowance to fully offset our deferred tax asset relating to this capital loss since we believe capital gains are not likely in future periods.

As of December 31, 2010, we had $27.3 million of deferred tax assets consisting ofrelated to foreign and domestic net operating lossesloss and other tax benefitsAMT credit carryforwards available to reduce future taxable income in a foreign jurisdiction.income. In assessing the realizability of our foreign deferred tax assets, we only recognize a tax benefit to the extent of taxable income that we expect to earn in the foreign jurisdiction in future periods. DueWe estimate that our operations will result in taxable income in excess of our net operating losses and we expect to recent declines in oilapply the net operating losses against the current year taxable income and natural gas prices and the downturn in our industry, we anticipate reductions in drilling rig utilization and revenue rates in 2009. Consequently,taxable income that we have a valuation allowance of $5.4 million that fully offsets our foreign deferred tax assets. The foreign net operating loss has an indefinite carryforward period. The foreign net operating loss is primarily due to the special income tax benefits permitted by the Colombian government that allows us to recover 140% of the cost of certain imported assets. We exported a 1500 horsepower drilling rig to Colombiaestimated in October 2008. To obtain this special income tax benefit, our U.S operating company sold this drilling rig in October 2008 to Stayton Asset Group, a variable interest entity established for this transaction for which we are the primary beneficiary. Stayton Asset Group immediately sold this drilling rig to our operating entity in Colombia.future periods.

Our accrued insurance premiums and deductibles as of December 31, 20082010 include accruals for costs incurred under the self-insurance portion of our health insurance of approximately $1.1$1.5 million and our workers’ compensation, general liability and auto liability insurance of approximately $9.6$6.6 million. WeAs of January 1, 2011, we have a deductible of $125,000$150,000 per covered individual per year under the health insurance.insurance, up from $125,000 during 2010. We have a deductible of $500,000 per occurrence under our workers’ compensation insurance, except in North Dakota, where we do not have a deductible.insurance. We have deductibles of $250,000 and $100,000 per occurrence under our general liability insurance and auto liability insurance, respectively. We accrue for these costs as claims are incurred based on historical claim development data, and we accrue the costs of administrative services associated with claims processing. We also evaluate our workers’ compensation claim cost estimates based on estimates provided by a professional actuary.

Our stock-based compensation expense includes estimates for certain of our long-term incentive compensation plans which have performance-based award components dependent upon our performance over a set performance period, as compared to the performance of a pre-defined peer group. The accruals for these awards include estimates which affect our stock-based compensation expense, employee related accruals and equity. As of December 31, 2010, we estimated that our actual achievement level will be 80% of the predetermined performance conditions. The final amount will be determinable in the first quarter of 2011.

Results of Operations

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

Statements of Operations Analysis—Year Ended December 31, 20082010 Compared with the Year Ended December 31, 20072009

The following table provides information about our operations for the years ended December 31, 20082010 and December 31, 2007.2009 (amounts in thousands, except average number of drilling rigs, utilization rate and revenue day information).