PATTERSON UTI ENERGY INC - Annual Report: 2009 (Form 10-K)

UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

 

 

 

Form 10-K

 

 

Commission File Number 0-22664

 

 

 

 

Patterson-UTI Energy, Inc.

(Exact name of registrant as specified in its charter)

 

 

Registrant’s telephone number, including area code:

(281) 765-7100

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 þ     or No o

 

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

 

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

 

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

 

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.  þ

 

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 definition of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

 

 

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

 

The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant as of June 30, 2009, the last business day of the registrant’s most recently completed second fiscal quarter, was $1,944,259,033, calculated by reference to the closing price of $12.86 for the common stock on the Nasdaq Global Select Market on that date.

 

As of February 17, 2010, the registrant had outstanding 153,567,174 shares of common stock, $.01 par value, its only class of common stock.

 

Documents incorporated by reference:

 

Portions of the registrant’s definitive proxy statement for the 2010 Annual Meeting of Stockholders are incorporated by reference into Part III of this report.

 

 

DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS

 

This Annual Report on Form 10-K (this “Report”) and other public filings and press releases by us contain “forward-looking statements” within the meaning of the Securities Act of 1933, as amended (the “Securities Act”), the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and the Private Securities Litigation Reform Act of 1995, as amended. These “forward-looking statements” involve risk and uncertainty. These forward-looking statements include, without limitation, statements relating to: liquidity; financing of operations; continued volatility of oil and natural gas prices; source and sufficiency of funds required for immediate capital needs and additional rig acquisitions (if further opportunities arise); impact of inflation; demand for our services; and other matters. Our forward-looking statements can be identified by the fact that they do not relate strictly to historic or current facts and often use words such as “believes,” “budgeted,” “continue,” “expects,” “estimates,” “project,” “will,” “could,” “may,” “plans,” “intends,” “strategy,” or “anticipates,” or the negative thereof or other words and expressions of similar meaning. The forward-looking statements are based on certain assumptions and analyses we make in light of our experience and our perception of historical trends, current conditions, expected future developments and other factors we believe are appropriate in the circumstances. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we can give no assurance that such expectations will prove to have been correct. Forward-looking statements may be made orally or in writing, including, but not limited to, Management’s Discussion and Analysis of Financial Condition and Results of Operations included in this Report and other sections of our filings with the United States Securities and Exchange Commission (the “SEC”) under the Exchange Act and the Securities Act.

 

Forward-looking statements are not guarantees of future performance and a variety of factors could cause actual results to differ materially from the anticipated or expected results expressed in or suggested by these forward-looking statements. Factors that might cause or contribute to such differences include, but are not limited to, deterioration of global economic conditions, declines in oil and natural gas prices that could adversely affect demand for our services and their associated effect on day rates, rig utilization and planned capital expenditures, excess availability of land drilling rigs, including as a result of the reactivation or construction of new land drilling rigs, adverse industry conditions, adverse credit and equity market conditions, difficulty in integrating acquisitions, demand for oil and natural gas, shortages of rig equipment, governmental regulation and ability to retain management and field personnel. Refer to “Risk Factors” contained in Part 1 of this Report for a more complete discussion of these and other factors that might affect our performance and financial results. You are cautioned not to place undue reliance on any of our forward-looking statements. These forward-looking statements are intended to relay our expectations about the future, and speak only as of the date they are made. We undertake no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, changes in internal estimates or otherwise.

 

PART I

 

 

Available Information

 

This Report, along with our Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act, are available free of charge through our Internet website (www.patenergy.com) as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. The information contained on our website is not part of this Report or other filings that we make with the SEC. You may read and copy any materials we file with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington, DC 20549. You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC maintains an internet site (www.sec.gov) that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC.

Overview

 

We own and operate one of the largest fleets of land-based drilling rigs in the United States. The Company was formed in 1978 and reincorporated in 1993 as a Delaware corporation. Our contract drilling business operates primarily in Texas, New Mexico, Oklahoma, Arkansas, Louisiana, Mississippi, Colorado, Utah, Wyoming, Montana, North Dakota, Pennsylvania, West Virginia and western Canada.

 

As of December 31, 2009, we had a drilling fleet that consisted of 341 marketable land-based drilling rigs. A drilling rig includes the structure, power source and machinery necessary to cause a drill bit to penetrate the earth to a depth desired by the customer. A drilling rig is considered marketable at a point in time if it is operating or can be made ready to operate without significant capital expenditures. We also have a substantial inventory of drill pipe and drilling rig components.

 

We provide pressure pumping services to oil and natural gas operators primarily in the Appalachian Basin. These services consist primarily of well stimulation and cementing for completion of new wells and remedial work on existing wells. We also own and invest in oil and natural gas assets as a working interest owner. Our oil and natural gas interests are located primarily in Texas and New Mexico.

 

Prior to January 20, 2010, we provided drilling fluids, completion fluids and related services to oil and natural gas operators offshore in the Gulf of Mexico and on land in Texas, New Mexico, Oklahoma and Louisiana. We exited the drilling and completion fluids services business on January 20, 2010 and sold substantially all of the assets, other than billed accounts receivable, of that business.

 

Industry Segments

 

Our revenues, operating profits and identifiable assets have been primarily attributable to four industry segments:

 

 

On January 20, 2010, we exited the drilling and completion fluids services business and ceased operations in that segment. As a result of the sale of this business, the historical results of operations for this segment have been reclassified and are presented as discontinued operations in this Report.

 

All of our industry segments had operating profits in 2007. In 2008, except for our drilling and completion fluids services segment, all of our industry segments had operating profits. In 2009, our pressure pumping services and oil and natural gas exploration and production segments had operating profits and our contract drilling services segment had an operating loss.

 

See “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Note 15 of Notes to Consolidated Financial Statements included as a part of Items 7 and 8, respectively, of this Report for financial information pertaining to these industry segments.

 

Contract Drilling Operations

 

General — We market our contract drilling services to major and independent oil and natural gas operators. As of December 31, 2009, we had 341 marketable land-based drilling rigs based in the following regions:

 

 

 

Our marketable drilling rigs have rated maximum depth capabilities ranging from 5,000 feet to 30,000 feet. Of these drilling rigs, 107 are electric rigs and 234 are mechanical rigs. An electric rig differs from a mechanical rig in that the electric rig converts the diesel power (the sole energy source for a mechanical rig) into electricity to power the rig. We also have a substantial inventory of drill pipe and drilling rig components, which may be used in the activation of additional drilling rigs or as replacement parts for marketable rigs.

 

Drilling rigs are typically equipped with engines, drawworks, masts, pumps to circulate the drilling fluid, blowout preventers, drill pipe and other related equipment. Over time, components on a drilling rig are replaced or rebuilt. We spend significant funds each year as part of a program to modify, upgrade and maintain our drilling rigs to ensure that our drilling equipment is competitive. We have spent $1.3 billion during the last three years on capital expenditures to (1) build new land drilling rigs and (2) modify, upgrade and maintain our drilling fleet. During fiscal years 2009, 2008 and 2007, we spent approximately $395 million, $361 million and $540 million, respectively, on these capital expenditures.

 

Depth and complexity of the well and drill site conditions are the principal factors in determining the specifications of the rig selected for a particular job.

 

Our contract drilling operations depend on the availability of drill pipe, drill bits, replacement parts and other related rig equipment, fuel and qualified personnel. Some of these have been in short supply from time to time.

 

Drilling Contracts — Most of our drilling contracts are with established customers on a competitive bid or negotiated basis. Our drilling contracts are either on a well-to-well basis or a term basis. Well-to-well contracts are generally short-term in nature and cover the drilling of a single well or a series of wells. Term contracts are entered into for a specified period of time (frequently one to three years) and provide for the use of the drilling rig to drill multiple wells. During 2009, our average number of days to drill a well (which includes moving to the drill site, rigging up and rigging down) was approximately 20 days.

 

Our drilling contracts obligate us to provide and operate a drilling rig and to pay certain operating expenses, including wages of drilling personnel and necessary maintenance expenses. Most drilling contracts are subject to termination by the customer on short notice and may or may not contain provisions for the payment of an early termination fee to us in the event that the contract is terminated by the customer. Generally, we indemnify our customers against claims by our employees and claims that might arise from surface pollution caused by spills of fuel, lubricants and other solvents within our control. Generally, the customers indemnify us against claims that might arise from other surface and subsurface pollution. Each drilling contract contains the actual terms setting forth our rights and obligations and those of the customer, any of which rights and obligations may deviate from what is customary due to industry conditions or other factors.

 

Our drilling contracts provide for payment on a daywork, footage, or turnkey basis, or a combination thereof. In each case, we provide the rig and crews. Except for two wells drilled under footage contracts in 2009, all of the wells drilled during the years ended December 31, 2009, 2008 and 2007 were drilled under daywork contracts. Our bid for each job depends upon location, depth and anticipated complexity of the well, on-site drilling conditions, equipment to be used, estimated risks involved, estimated duration of the job, availability of drilling rigs and other factors particular to each proposed well.

 

Under daywork contracts, we provide the drilling rig and crew to the customer. The customer supervises the drilling of the well. Our compensation is based on a contracted rate per day during the period the drilling rig is utilized. We often receive a lower rate when the drilling rig is moving or when drilling operations are interrupted or restricted by adverse weather conditions or other conditions beyond our control. Daywork contracts typically provide separately for mobilization of the drilling rig. Except for two wells drilled under footage contracts in 2009, all of the wells we drilled in 2009, 2008 and 2007 were under daywork contracts.

Under footage contracts, we contract to drill a well to a certain depth under specified conditions for a fixed price per foot. The customer provides drilling fluids, casing, cementing and well design expertise. These contracts require us to bear the cost of services and supplies that we provide until the well has been drilled to the agreed depth. If we drill the well in less time than estimated, we have the opportunity to improve our profits over those that would be attainable under a daywork contract. Profits are reduced and losses may be incurred if the well requires more days to drill to the contracted depth than estimated. Footage contracts generally contain greater risks for a drilling contractor than daywork contracts. Under footage contracts, the drilling contractor typically assumes certain risks associated with loss of the well from fire, blowouts and other risks. We drilled two wells under footage contracts in 2009, and we did not drill any wells under footage contracts in 2008 or 2007.

 

Under turnkey contracts, we contract to drill a well to a certain depth under specified conditions for a fixed fee. In a turnkey arrangement, we are required to bear the costs of services, supplies and equipment beyond those typically provided under a footage contract. In addition to the drilling rig and crew, we are required to provide the drilling and completion fluids, casing, cementing, and the technical well design and engineering services during the drilling process. We also typically assume certain risks associated with drilling the well such as fires, blowouts, cratering of the well bore and other such risks. Compensation occurs only when the agreed scope of the work has been completed, which requires us to make larger up-front working capital commitments prior to receiving payments under a turnkey drilling contract. Under a turnkey contract, we have the opportunity to improve our profits if the drilling process goes as expected and there are no complications or time delays. Given the increased exposure we have under a turnkey contract, however, profits can be significantly reduced and losses can be incurred if complications or delays occur during the drilling process. Turnkey contracts generally involve the highest degree of risk among the three different types of drilling contracts. Although we have entered into turnkey contracts in the past, we did not enter into any turnkey contracts in the past three years.

 

Contract Drilling Activity — Information regarding our contract drilling activity for the last three years follows:

 

 

 

 

Drilling Rigs and Related Equipment — We estimate the depth capacity with respect to our marketable rigs as of December 31, 2009 to be as follows:

 

 

At December 31, 2009, we owned and operated 323 trucks and 417 trailers used to rig down, transport and rig up our drilling rigs. Our ownership of trucks and trailers reduces our dependency upon third parties for these services and generally enhances the efficiency of our contract drilling operations, particularly in periods of high drilling rig utilization.

 

Most repair and overhaul work to our drilling rig equipment is performed at our yard facilities located in Texas, Oklahoma, Wyoming, Utah, Pennsylvania and western Canada.

Pressure Pumping Operations

 

General — We provide pressure pumping services to oil and natural gas operators primarily in the Appalachian Basin. Pressure pumping services are primarily well stimulation and cementing for the completion of new wells and remedial work on existing wells. Most wells drilled in the Appalachian Basin require some form of fracturing or other stimulation to enhance the flow of oil and natural gas by pumping fluids under pressure into the well bore. Appalachian Basin wells typically require cementing services. The cementing process inserts material between the wall of the well bore and the casing to center and stabilize the casing.

 

Equipment — Our pressure pumping equipment at December 31, 2009 includes equipment used in providing hydraulic and nitrogen fracturing services as well as cementing services as follows:

 

Hydraulic fracturing equipment:

 

 

 

 

Nitrogen fracturing equipment:

 

 

 

 

Cementing equipment:

 

 

 

In addition to the equipment listed above, we had 45 tractors at December 31, 2009 which are used in all of the lines of business within our pressure pumping segment.

 

Oil and Natural Gas Interests

 

We have been engaged in the development, exploration, acquisition and production of oil and natural gas. Through October 31, 2007, we served as operator with respect to several properties and were actively involved in

the development, exploration, acquisition and production of oil and natural gas. Effective November 1, 2007, we sold the related operations portion of our exploration and production business, which was the portion of our business that actively managed the development, exploration, acquisition and production of oil and natural gas. We continue to own and invest in oil and natural gas assets as a working interest owner. Our oil and natural gas interests are located primarily in producing regions of Texas and New Mexico.

 

Drilling and Completion Fluids Operations

 

Prior to exiting the business in January 2010, we provided drilling fluids, completion fluids and related services to oil and natural gas operators offshore in the Gulf of Mexico and on land in Texas, New Mexico, Oklahoma and Louisiana.

 

Customers

 

The customers of each of our oil and natural gas service business segments are oil and natural gas operators. Our customer base includes both major and independent oil and natural gas operators. During 2009, no single customer accounted for 10% or more of our consolidated operating revenues.

 

Competition

 

Our contract drilling and pressure pumping businesses are highly competitive. Historically, available equipment used in these businesses has frequently exceeded demand in our markets. The price for our services is a key competitive factor in our markets, in part because equipment used in our businesses can be moved from one area to another in response to market conditions. In addition to price, we believe availability and condition of equipment, quality of personnel, service quality and safety record are key factors in determining which contractor is awarded a job in the markets in which we operate. We expect that the market for land drilling and pressure pumping services will continue to be competitive.

 

Government and Environmental Regulation

 

All of our operations and facilities are subject to numerous Federal, state, foreign, and local laws, rules and regulations related to various aspects of our business, including:

 

 

To date, applicable environmental laws and regulations in the United States and Canada have not required the expenditure of significant resources outside the ordinary course of business. We do not anticipate any material capital expenditures for environmental control facilities or extraordinary expenditures to comply with environmental rules and regulations in the foreseeable future. However, compliance costs under existing laws or under any new requirements could become material, and we could incur liability in any instance of noncompliance.

 

Our business is generally affected by political developments and by Federal, state, foreign, and local laws and regulations that relate to the oil and natural gas industry. The adoption of laws and regulations affecting the oil and natural gas industry for economic, environmental and other policy reasons could increase costs relating to drilling and production. They could have an adverse effect on our operations. Federal, state, foreign and local environmental laws and regulations currently apply to our operations and may become more stringent in the future.

 

We believe we use operating and disposal practices that are standard in the industry. However, hydrocarbons and other materials may have been disposed of or released in or under properties currently or formerly owned or operated by us or our predecessors which may have resulted, or may result, in soil and groundwater contamination in certain locations. Any contamination found on, under or originating from the properties may be subject to remediation requirements under Federal, state, foreign and local laws and regulations. In addition, some of these properties have been operated by third parties over whom we have no control of their treatment of hydrocarbon and other materials or the manner in which they may have disposed of or released such materials. We could be required to remove or remediate wastes disposed of or released by prior owners or operators. In addition, it is possible we could be held responsible for oil and natural gas properties in which we own an interest but are not the operator.

Some of the environmental laws and regulations that are applicable to our business operations are discussed in the following paragraphs, but the discussion does not cover all environmental laws and regulations that govern our operations.

 

In the United States, the Federal Comprehensive Environmental Response Compensation and Liability Act of 1980, as amended, commonly known as CERCLA, and comparable state statutes impose strict liability on:

 

 

The Federal Resource Conservation and Recovery Act (“RCRA”), as amended, and comparable state statutes govern the disposal of “hazardous wastes.” Although CERCLA currently excludes petroleum from the definition of “hazardous substances,” and RCRA also excludes certain classes of exploration and production wastes from regulation, such exemptions by Congress under both CERCLA and RCRA may be deleted, limited, or modified in the future. If such changes are made to CERCLA and/or RCRA, we could be required to remove and remediate previously disposed of materials (including materials disposed of or released by prior owners or operators) from properties (including ground water contaminated with hydrocarbons) and to perform removal or remedial actions to prevent future contamination.

 

The Federal Water Pollution Control Act and the Oil Pollution Act of 1990, as amended, and implementing regulations govern:

 

 

The Oil Pollution Act imposes strict liability for a comprehensive and expansive list of damages from an oil spill into waters from facilities. Liability may be imposed for oil removal costs and a variety of public and private damages. Penalties may also be imposed for violation of Federal safety, construction and operating regulations, and for failure to report a spill or to cooperate fully in a clean-up.

 

The Oil Pollution Act also expands the authority and capability of the Federal government to direct and manage oil spill clean-up and operations, and requires operators to prepare oil spill response plans in cases where it can reasonably be expected that substantial harm will be done to the environment by discharges on or into navigable waters. We have spill prevention control and countermeasure plans in place for our working interest in oil and natural gas properties in each of the areas in which these interests are located. Failure to comply with ongoing requirements or inadequate cooperation during a spill event may subject a responsible party, such as us, to civil or criminal actions. Although the liability for owners and operators is the same under the Federal Water Pollution Act, the damages recoverable under the Oil Pollution Act are potentially much greater and can include natural resource damages.

 

In Canada, a variety of Canadian federal, provincial and municipal laws and regulations impose, among other things, restrictions, liabilities and obligations in connection with the generation, handling, use, storage, transportation, treatment and disposal of hazardous substances and wastes and in connection with spills, releases and emissions of various substances to the environment. These laws and regulations also require that facility sites and other properties associated with our operations be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. In addition, new projects or changes to existing projects may require the submission and approval of environmental assessments or permit applications. These laws and regulations are subject to frequent change, and the clear trend is to place increasingly stringent limitations on activities that may affect the environment.

 

Our operations are also subject to Federal, state, foreign and local laws, rules and regulations for the control of air emissions, including the Federal Clean Air Act and the Canadian Environmental Protection Act. We are aware of the increasing focus of local, state, national and international regulatory bodies on greenhouse gas (GHG) emissions and climate change issues. We are also aware of legislation proposed by United States lawmakers and the Canadian legislature to reduce GHG emissions, as well as GHG emissions regulations enacted by the U.S. Environmental Protection Agency and the Canadian provinces of Alberta and British Columbia. We will continue to monitor and assess any new policies, legislation or regulations in the areas where we operate to determine the impact of GHG emissions and climate change on our operations and take appropriate actions, where necessary. Any direct and

indirect costs of meeting these requirements may adversely affect our business, results of operations and financial condition.

 

Risks and Insurance

 

Our operations are subject to the many hazards inherent in the drilling business, including:

 

 

These hazards could cause:

 

 

Damage to the environment, including property contamination in the form of either soil or ground water contamination, could also result from our operations, particularly through:

 

 

In addition, we could become subject to liability for reservoir damages. The occurrence of a significant event, including pollution or environmental damages, could materially affect our operations, cash flows and financial condition.

 

As a protection against operating hazards, we maintain insurance coverage we believe to be adequate, including:

 

 

We believe that we are adequately insured for bodily injury and property damage to others with respect to our operations. Such insurance, however, may not be sufficient to protect us against liability for all consequences of:

 

 

We also carry insurance to cover physical damage to, or loss of, our drilling rigs. Such insurance does not, however, cover the full replacement cost of the rigs, and we do not carry insurance against loss of earnings resulting

from such damage. In view of the difficulties that may be encountered in renewing such insurance at reasonable rates, no assurance can be given that:

 

 

In addition to insurance coverage, we also attempt to obtain indemnification from our customers for certain risks. These indemnity agreements typically require our customers to hold us harmless in the event of loss of production or reservoir damage. These contractual indemnifications, if obtained, may not be supported by adequate insurance maintained by the customer.

 

Employees

 

We had approximately 4,200 full-time employees at December 31, 2009. The number of employees fluctuates depending on the current and expected demand for our services. We consider our employee relations to be satisfactory. None of our employees are represented by a union.

 

Seasonality

 

Seasonality does not significantly affect our overall operations. However, our drilling operations in Canada and, to a lesser extent, our pressure pumping operations in the Appalachian Basin, are subject to slow periods of activity during the Spring thaw.

 

Raw Materials and Subcontractors

 

We use many suppliers of raw materials and services. These materials and services have historically been available, although there is no assurance that such materials and services will continue to be available on favorable terms or at all. We also utilize numerous independent subcontractors from various trades.

 

 

You should consider each of the following factors as well as the other information in this Report in evaluating our business and our prospects. Additional risks and uncertainties not presently known to us or that we currently consider immaterial may also impair our business operations. If any of the following risks actually occur, our business and financial results could be harmed. You should also refer to the other information set forth in this Report, including our financial statements and the related notes.

 

Global Economic Conditions May Adversely Affect Our Operating Results.

 

Since reaching a peak in June 2008, there has been a significant decline in oil and natural gas prices. Since that time there has also been a significant deterioration in the global economic environment. As part of this deterioration, there has been significant uncertainty in the capital markets and access to financing has been reduced. Due to these conditions, our customers reduced or curtailed their drilling programs, which resulted in a decrease in demand for our services. Furthermore, these factors have resulted in, and could continue to result in, certain of our customers experiencing an inability to pay suppliers, including us, if they are not able to access capital to fund their operations. Although the significant deterioration in the global economic environment appears to have recently stabilized to some degree, our customers may not substantially increase their drilling programs unless there is more certainty about global economic prospects. These conditions could have a material adverse effect on our business, financial condition, cash flows and results of operations.

We are Dependent on the Oil and Natural Gas Industry and Market Prices for Oil and Natural Gas. Declines in Oil and Natural Gas Prices Have Adversely Affected Our Operating Results.

 

Our revenue, profitability, financial condition and rate of growth are substantially dependent upon prevailing prices for natural gas and, to a lesser extent, oil. For many years, oil and natural gas prices and markets have been extremely volatile. Prices are affected by:

 

 

All of these factors are beyond our control. During 2008, the monthly average market price of natural gas peaked in June at $13.06 per Mcf before rapidly declining to an average of $5.99 per Mcf in December 2008. In 2009, the monthly average market price of natural gas declined further to a low of $3.06 per Mcf in September. This decline in the market price of natural gas resulted in our customers significantly reducing their drilling activities beginning in the fourth quarter of 2008, and drilling activities remained low throughout 2009. This reduction in demand combined with the reactivation and construction of new land drilling rigs in the United States during the last several years has resulted in excess capacity compared to demand. As a result of these factors, our average number of rigs operating has declined significantly. We expect oil and natural gas prices to continue to be volatile and to affect our financial condition, operations and ability to access sources of capital. Low market prices for natural gas would likely result in demand for our drilling rigs remaining low and adversely affect our operating results, financial condition and cash flows.

 

A General Excess of Operable Land Drilling Rigs and Increasing Rig Specialization May Adversely Affect Our Utilization and Profit Margins.

 

The North American land drilling industry has experienced periods of downturn in demand over the last decade. During these periods, there have been substantially more drilling rigs available than necessary to meet demand. As a result, drilling contractors have had difficulty sustaining profit margins and, at times, have sustained losses during the downturn periods.

 

In addition, unconventional resource plays have substantially increased recently and some drilling rigs are not capable of drilling these wells efficiently. Accordingly, the utilization of some older technology drilling rigs may be hampered by their lack of capability to successfully compete for this work. Other ongoing factors which could continue to adversely affect utilization rates and pricing, even in an environment of high oil and natural gas prices and increased drilling activity, include:

 

 

Construction of new drilling rigs increased significantly during the last five years. The addition of new drilling rigs to the market and the recent decrease in demand has resulted in excess capacity. We cannot predict either the future level of demand for our contract drilling services or future conditions in the oil and natural gas contract drilling business.

 

Shortages of Drill Pipe, Replacement Parts and Other Related Rig Equipment Adversely Affects Our Operating Results.

 

During periods of increased demand for drilling services, the industry has experienced shortages of drill pipe, replacement parts and other related rig equipment. These shortages can cause the price of these items to increase significantly and require that orders for the items be placed well in advance of expected use. In addition, any interruption in supply due to vendor or other issues could result in significant delays in delivery of equipment. These

price increases and delays in delivery may require us to increase capital and repair expenditures in our contract drilling segment. Severe shortages or delays in delivery could limit our ability to operate our drilling rigs.

 

The Oil Service Business Segments in Which We Operate Are Highly Competitive with Excess Capacity, which Adversely Affects Our Operating Results.

 

Our land drilling and pressure pumping businesses are highly competitive. At times, available land drilling rigs and pressure pumping equipment exceed the demand for such equipment. This excess capacity has resulted in substantial competition for drilling and pressure pumping contracts. The fact that drilling rigs and pressure pumping equipment are mobile and can be moved from one market to another in response to market conditions heightens the competition in the industry.

 

We believe that price competition for drilling and pressure pumping contracts will continue due to the existence of available rigs and pressure pumping equipment.

 

In recent years, many drilling and pressure pumping companies have consolidated or merged with other companies. Although this consolidation has decreased the total number of competitors, we believe the competition for drilling and pressure pumping services will continue to be intense.

 

Labor Shortages and Rising Labor Costs Adversely Affect Our Operating Results.

 

During periods of increasing demand for contract drilling and pressure pumping services, the industry experiences shortages of qualified personnel. During these periods, our ability to attract and retain sufficient qualified personnel to market and operate our drilling rigs and pressure pumping equipment is adversely affected, which negatively impacts both our operations and profitability. Operationally, it is more difficult to hire qualified personnel, which adversely affects our ability to mobilize inactive rigs and pressure pumping equipment in response to the increased demand for such services. Additionally, wage rates for drilling and pressure pumping personnel are likely to increase during periods of increasing demand, resulting in higher operating costs.

 

Growth Through the Building of New Rigs and Rig Acquisitions are Not Assured.

 

We have increased our drilling rig fleet in the past through mergers, acquisitions and rig construction. The land drilling industry has experienced significant consolidation, and there can be no assurance that acquisition opportunities will be available in the future. We are also likely to continue to face intense competition from other companies for available acquisition opportunities. In addition, because improved technology has enhanced the ability to recover oil and natural gas, contract drillers may continue to build new, high technology rigs.

 

There can be no assurance that we will:

 

 

We may incur substantial indebtedness to finance future acquisitions or build new drilling rigs and also may issue equity, convertible or debt securities in connection with any such acquisitions or building program. Debt service requirements could represent a significant burden on our results of operations and financial condition, and the issuance of additional equity would be dilutive to existing stockholders. Also, continued growth could strain our management, operations, employees and other resources.

The Nature of our Business Operations Presents Inherent Risks of Loss that, if not Insured or Indemnified Against, Could Adversely Affect Our Operating Results.

 

Our operations are subject to many hazards inherent in the contract drilling and pressure pumping businesses, which in turn could cause personal injury or death, work stoppage, or serious damage to our equipment. Our operations could also cause environmental and reservoir damages. We maintain insurance coverage and have indemnification agreements with many of our customers. However, there is no assurance that such insurance or indemnification agreements would adequately protect us against liability or losses from all consequences of these hazards. Additionally, there can be no assurance that insurance would be available to cover any or all of these risks, or, even if available, that insurance premiums or other costs would not rise significantly in the future, so as to make the cost of such insurance prohibitive. Incurring a liability for which we are not fully insured or indemnified could materially affect our business, financial condition and results of operations.

 

We have also elected in some cases to accept a greater amount of risk through increased deductibles on certain insurance policies. For example, we maintain a $1.0 million per occurrence deductible on our workers’ compensation, general liability and equipment insurance coverages.

 

Violations of Environmental Laws and Regulations Could Materially Adversely Affect Our Operating Results.

 

All of our operations and facilities are subject to numerous Federal, state, foreign and local environmental laws, rules and regulations, including, without limitation, laws concerning the containment and disposal of hazardous substances, oil field waste and other waste materials, the use of underground storage tanks, and the use of underground injection wells. The cost of compliance with these laws and regulations could be substantial. A failure to comply with these requirements could expose us to substantial civil and criminal penalties. In addition, environmental laws and regulations in the United States and Canada impose a variety of requirements on “responsible parties” related to the prevention of oil spills and liability for damages from such spills. As an owner and operator of land-based drilling rigs, we may be deemed to be a responsible party under these laws and regulations.

 

We are aware of the increasing focus of local, state, national and international regulatory bodies on GHG emissions and climate change issues. We are also aware of legislation proposed by United States lawmakers and the Canadian legislature to reduce GHG emissions, as well as GHG emissions regulations enacted by the U.S. Environmental Protection Agency and the Canadian provinces of Alberta and British Columbia. We will continue to monitor and assess any new policies, legislation or regulations in the areas where we operate to determine the impact of GHG emissions and climate change on our operations and take appropriate actions, where necessary. Any direct and indirect costs of meeting these requirements may adversely affect our business, results of operations and financial condition.

 

Anti-takeover Measures in Our Charter Documents and Under State Law Could Discourage an Acquisition and Thereby Affect the Related Purchase Price.

 

We are a Delaware corporation subject to the Delaware General Corporation Law, including Section 203, an anti-takeover law. We have also enacted certain anti-takeover measures, including a stockholders’ rights plan. In addition, our Board of Directors has the authority to issue up to one million shares of preferred stock and to determine the price, rights (including voting rights), conversion ratios, preferences and privileges of that stock without further vote or action by the holders of the common stock. As a result of these measures and others, potential acquirers might find it more difficult or be discouraged from attempting to effect an acquisition transaction with us. This may deprive holders of our securities of certain opportunities to sell or otherwise dispose of the securities at above-market prices pursuant to any such transactions.

 

 

None.

 

Our corporate headquarters comprises approximately 12,000 square feet of leased office space, and is located at 450 Gears Road, Suite 500, Houston, Texas. Our telephone number at that address is (281) 765-7100. Our primary administrative office is located in Snyder, Texas and includes approximately 37,000 square feet of office and storage space.

 

Contract Drilling Operations — Our drilling services are supported by several offices and yard facilities located throughout our areas of operations, including Texas, New Mexico, Oklahoma, Colorado, Utah, Wyoming, Pennsylvania and western Canada.

 

Pressure Pumping — Our pressure pumping services are supported by several offices and yard facilities located throughout our areas of operations including Pennsylvania, Ohio, New York, West Virginia, Kentucky, Tennessee and Colorado.

 

Oil and Natural Gas Working Interests — Our interests in oil and natural gas properties are primarily located in Texas and New Mexico.

 

We own our administrative offices in Snyder, Texas, as well as several of our other facilities. We also lease a number of facilities, and we do not believe that any one of the leased facilities is individually material to our operations. We believe that our existing facilities are suitable and adequate to meet our needs.

 

 

We are party to various legal proceedings arising in the normal course of our business. We do not believe that the outcome of these proceedings, either individually or in the aggregate, will have a material adverse effect on our results of operations, cash flows or financial condition.

 

 

None.

PART II

 

 

 

Our common stock, par value $0.01 per share, is publicly traded on the Nasdaq Global Select Market and is quoted under the symbol “PTEN.” Our common stock is included in the S&P MidCap 400 Index and several other market indices. The following table provides high and low sales prices of our common stock for the periods indicated:

 

 

 

As of February 17, 2010, there were approximately 1,700 holders of record of our common stock.

 

 

We paid cash dividends during the years ended December 31, 2008 and 2009 as follows:

 

 

On February 10, 2010, our Board of Directors approved a cash dividend on our common stock in the amount of $0.05 per share to be paid on March 30, 2010 to holders of record as of March 15, 2010. The amount and timing of all future dividend payments, if any, is subject to the discretion of the Board of Directors and will depend upon business conditions, results of operations, financial condition, terms of our credit facilities and other factors.

 

Equity compensation plan information as of December 31, 2009 follows:

 

 

 

 

 

The following graph compares the cumulative stockholder return of our common stock for the period from December 31, 2004 through December 31, 2009, with the cumulative total return of the Standard & Poors 500 Stock Index, the Standard & Poors MidCap Index, the Oilfield Service Index and a peer group determined by us. Our 2008 peer group consists of BJ Services Company, Bronco Drilling Company, Inc., Helmerich & Payne, Inc., Nabors Industries, Ltd., Pioneer Drilling Co., Superior Well Services, Inc. and Unit Corp. We evaluated our peer group for 2009 and determined that it was appropriate to remove Unit Corp. from the peer group as their drilling revenue as a percentage of total revenue had fallen to a level that was no longer comparable to ours. All of the companies in our peer group are providers of land-based drilling or pressure pumping services. The graph assumes investment of $100 on December 31, 2004 and reinvestment of all dividends.

 

 

 

The foregoing graph is based on historical data and is not necessarily indicative of future performance. This graph shall not be deemed to be “soliciting material” or to be “filed” with the SEC or subject to Regulations 14A or 14C under the Exchange Act or to the liabilities of Section 18 under such Act.

 

 

Our selected consolidated financial data as of December 31, 2009, 2008, 2007, 2006 and 2005, and for each of the five years in the period ended December 31, 2009 should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the Consolidated Financial Statements and related Notes thereto, included as Items 7 and 8, respectively, of this Report. Certain reclassifications have been made to the historical financial data to conform with the 2009 presentation. Due to the sale of

substantially all of the assets of our drilling and completion fluids business in January 2010, the results of operations for that business have been reclassified and are presented as discontinued operations in all periods presented below.

 

 

Management Overview — We are a leading provider of contract services to the North American oil and natural gas industry. Our services primarily involve the drilling, on a contract basis, of land-based oil and natural gas wells and, to a lesser extent, pressure pumping services. In addition to the aforementioned contract services, we also invest, on a working interest basis, in oil and natural gas properties. For the three years ended December 31, 2009, our operating revenues consisted of the following (dollars in thousands):

 

 

We provide our contract services to oil and natural gas operators in many of the oil and natural gas producing regions of North America. Our contract drilling operations are focused in various regions of Texas, New Mexico, Oklahoma, Arkansas, Louisiana, Mississippi, Colorado, Utah, Wyoming, Montana, North Dakota, South Dakota, Pennsylvania, and western Canada, while our pressure pumping services are focused primarily in the Appalachian Basin. The oil and natural gas properties in which we hold interests are primarily located in Texas and New Mexico.

 

Typically, the profitability of our business is most readily assessed by two primary indicators in our contract drilling segment: our average number of rigs operating and our average revenue per operating day. During 2009, our average number of rigs operating was 91 compared to 254 in 2008 and 244 in 2007. Our average revenue per operating day was $17,950 in 2009 compared to $19,380 in 2008 and $19,550 in 2007. We had a consolidated net loss of $38.3 million for 2009 compared to consolidated net income of $347 million for 2008. This decrease was primarily due to our contract drilling segment experiencing a significant decrease in the average number of rigs operating as compared to 2008.

 

Our revenues, profitability and cash flows are highly dependent upon prevailing prices for natural gas and, to a lesser extent, oil. During periods of improved commodity prices, the capital spending budgets of oil and natural gas operators tend to expand, which generally results in increased demand for our contract services. Conversely, in periods when these commodity prices deteriorate, the demand for our contract services generally weakens and we experience downward pressure on pricing for our services. Since reaching a peak in June 2008, there has been a significant decline in oil and natural gas prices. Since that time there has also been a substantial deterioration in the global economic environment. As part of this deterioration, there has been substantial uncertainty in the capital markets and access to financing has been reduced. Due to these conditions, our customers reduced or curtailed their drilling programs, which resulted in a decrease in demand for our services, as evidenced by the decline in our monthly average rigs operating from a high of 283 in October 2008 to a low of 60 in June 2009 before partially recovering to 118 in December 2009. Furthermore, these factors have resulted in, and could continue to result in, certain of our customers experiencing an inability to pay suppliers, including us, if they are not able to access capital to fund their operations. We are also highly impacted by competition, the availability of excess equipment, labor issues and various other factors that could materially adversely affect our business, financial condition, cash flows and results of operations and which are more fully described above as “Risk Factors” in Item 1A of this Report.

 

We believe that the liquidity shown on our balance sheet as of December 31, 2009, which includes approximately $264 million in working capital (including $49.9 million in cash) and approximately $194 million available under our $240 million revolving credit facility, together with cash expected to be generated from operations (including expected income tax refunds in 2010 of approximately $114 million resulting from the carry-back of net operating losses), should provide us with sufficient ability to fund our current plans to build new equipment, make improvements to our existing equipment, expand into new regions, pay cash dividends and survive the current downturn in our industry. If we pursue opportunities for growth that require capital, we believe we would be able to satisfy these needs through a combination of working capital, cash generated from operations, borrowing capacity under our revolving credit facility or additional debt or equity financing. However, there can be no assurance that such capital will be available on reasonable terms, if at all.

Commitments and Contingencies — As of December 31, 2009, we maintained letters of credit in the aggregate amount of $46.3 million for the benefit of various insurance companies as collateral for retrospective premiums and retained losses which could become payable under the terms of the underlying insurance contracts. These letters of credit expire at various times during each calendar year and are typically renewed annually. As of December 31, 2009, no amounts had been drawn under the letters of credit.

 

As of December 31, 2009, we had commitments to purchase approximately $186 million of major equipment.

 

Trading and investing — We have not engaged in trading activities that include high-risk securities, such as derivatives and non-exchange traded contracts. We invest cash primarily in highly liquid, short-term investments such as overnight deposits and money market accounts.

 

Description of business — We conduct our contract drilling operations in Texas, New Mexico, Oklahoma, Arkansas, Louisiana, Mississippi, Colorado, Utah, Wyoming, Montana, North Dakota, Pennsylvania, West Virginia and western Canada. For the years ended December 31, 2009, 2008 and 2007, revenue earned in Canada was $45.4 million, $88.5 million and $72.9 million, respectively. Additionally, we had long-lived assets located in Canada of $69.2 million and $67.2 million as of December 31, 2009 and 2008, respectively. As of December 31, 2009, we had 341 marketable land-based drilling rigs. We provide pressure pumping services to oil and natural gas operators primarily in the Appalachian Basin. These services consist primarily of well stimulation and cementing for completion of new wells and remedial work on existing wells. Prior to the sale of substantially all of the assets of our drilling fluids business on January 20, 2010, we provided drilling fluids, completion fluids and related services to oil and natural gas operators offshore in the Gulf of Mexico and on land in Texas, New Mexico, Oklahoma and Louisiana. Drilling and completion fluids are used by oil and natural gas operators during the drilling process to control pressure when drilling oil and natural gas wells. Due to our exit from the drilling and completion fluids business in January 2010, we have presented the results of that operating segment as discontinued operations in this Report. We also invest, on a working interest basis, in oil and natural gas properties.

 

Critical Accounting Policies

 

In addition to established accounting policies, our consolidated financial statements are impacted by certain estimates and assumptions made by management. The following is a discussion of our critical accounting policies pertaining to property and equipment, oil and natural gas properties, goodwill, revenue recognition and the use of estimates.

 

Property and equipment — Property and equipment, including betterments which extend the useful life of the asset, are stated at cost. Maintenance and repairs are charged to expense when incurred. We provide for the depreciation of our property and equipment using the straight-line method over the estimated useful lives. Our method of depreciation does not change when equipment becomes idle; we continue to depreciate idled equipment on a straight-line basis. No provision for salvage value is considered in determining depreciation of our property and equipment. We review our long-lived assets, including property and equipment, for impairment whenever events or changes in circumstances indicate that the carrying values of certain assets may not be recovered over their estimated remaining useful lives. In connection with this review, assets are grouped at the lowest level at which identifiable cash flows are largely independent of other asset groupings. The cyclical nature of our industry has resulted in fluctuations in rig utilization over periods of time. Management believes that the contract drilling industry will continue to be cyclical and rig utilization will fluctuate. Based on management’s expectations of future trends, we estimate future cash flows over the life of the respective assets in our assessment of impairment. These estimates of cash flows are based on historical cyclical trends in the industry as well as management’s expectations regarding the continuation of these trends in the future. Provisions for asset impairment are charged against income when estimated future cash flows, on an undiscounted basis, are less than the asset’s net book value. Any provision for impairment is measured based on discounted cash flows.

 

On a periodic basis, we evaluate our fleet of drilling rigs for marketability. During 2009 and 2008, in connection with our long term planning process, we evaluated our then-current fleet of marketable drilling rigs and identified 23 and 22 rigs, respectively, that we determined would no longer be marketed as rigs. Additionally, in 2009, we identified one rig which would be recommissioned in a different configuration. The components comprising these rigs were evaluated, and those components with continuing utility to our other marketed rigs

were transferred to other rigs or to our yards to be used as spare equipment. The remaining components of these rigs were impaired and the associated net book value of $10.5 million in 2009 and $10.4 million in 2008 was expensed in our consolidated statements of operations as an impairment charge.

 

In late 2008, we experienced a significant decrease in the number of our rigs operating and oil and natural gas prices decreased significantly. These events were deemed by us to be triggering events that required us to perform an assessment with respect to impairment of long-lived assets, including property and equipment, in our contract drilling segment. With respect to these long-lived assets, we estimated future cash flows over the expected life of the long-lived assets, which were comprised primarily of property and equipment, and determined that, on an undiscounted basis, expected cash flows exceeded the carrying value of the long-lived assets. Based on this assessment, no impairment was indicated. We again performed an assessment with respect to impairment of long-lived assets in our contract drilling segment in 2009 based on undiscounted cash flows and determined that no impairment was indicated. Impairment considerations in our oil and natural gas segment related to proved properties are discussed below. We concluded that no triggering event had occurred with respect to our pressure pumping segment, as the level of activity and revenue impact in that segment had not been affected to the same degree as in our other segments.

 

Oil and natural gas properties — Working interests in oil and natural gas properties are accounted for using the successful efforts method of accounting. Under the successful efforts method of accounting, exploration costs which result in the discovery of oil and natural gas reserves and all development costs are capitalized to the appropriate well. Exploration costs which do not result in discovering oil and natural gas reserves are charged to expense when such determination is made. Costs of exploratory wells are initially capitalized to wells in progress until the outcome of the drilling is known. We review wells in progress quarterly to determine whether sufficient progress is being made in assessing the reserves and the economic operating viability of the respective projects. If no progress has been made in assessing the reserves and the economic operating viability of a project after one year following the completion of drilling, we consider the costs of the well to be impaired and recognize the costs as expense. Geological and geophysical costs, including seismic costs and costs to carry and retain undeveloped properties, are charged to expense when incurred. The capitalized costs of both developmental and successful exploratory type wells, consisting of lease and well equipment, lease acquisition costs and intangible development costs, are depreciated, depleted and amortized on the units-of-production method, based on engineering estimates of proved oil and natural gas reserves of each respective field.

 

We review our proved oil and natural gas properties for impairment when a triggering event occurs such as downward revisions in reserve estimates or decreases in oil and natural gas prices. Proved properties are grouped by field and undiscounted cash flow estimates are prepared based on our expectation of future commodity prices over the lives of the respective fields. These estimates are then reviewed by an independent petroleum engineer. If the net book value of a field exceeds its undiscounted cash flow estimate, impairment expense is measured and recognized as the difference between its net book value and discounted cash flow. The discounted cash flow estimates used in measuring impairment are based on our expectations of future commodity prices over the life of the respective field. Unproved oil and natural gas properties are reviewed quarterly to assess potential impairment. The intent to drill, lease expiration and abandonment of area are considered. Assessment of impairment is made on a lease-by-lease basis. If an unproved property is determined to be impaired, then costs related to that property are expensed. Impairment expense results from downward revisions in reserve estimates of proved properties and amounted to approximately $3.7 million, $4.4 million and $3.9 million for the years ended December 31, 2009, 2008 and 2007, respectively, is included in depreciation, depletion and impairment in the accompanying consolidated statements of operations.

 

Goodwill — Goodwill is considered to have an indefinite useful economic life and is not amortized. As such, we assess impairment of our goodwill annually as of December 31 or on an interim basis if events or circumstances indicate that the fair value of the asset has decreased below its carrying value. Goodwill impairment testing is performed at the level of our reporting units. Our reporting units have been determined to be the same as our operating segments.

 

In connection with our annual assessment of potential impairment of goodwill, we compare the fair value of the reporting unit with its carrying value. If the fair value exceeds the carrying value, no impairment is indicated. If the carrying value exceeds the fair value, we measure any impairment of goodwill in that reporting unit by allocating the fair value to the identifiable assets and liabilities of the reporting unit based on their respective fair

values. Any excess unallocated fair value would equal the implied fair value of goodwill, and if that amount is below the carrying value of goodwill, an impairment charge is recognized.

 

In connection with our annual goodwill impairment assessment performed as of December 31, 2008, we performed an impairment test of goodwill recorded in our contract drilling and drilling and completion fluids reporting units. In light of the adverse market conditions affecting our common stock price beginning in the fourth quarter of 2008 and continuing into 2009, including a significant decrease in the number of our rigs operating and a significant decline in oil and natural gas commodity prices, we utilized a discounted cash flow methodology to estimate the fair values of our reporting units. In completing the first step of our analysis, we used a three-year projection of discounted cash flows, plus a terminal value determined using the constant growth method to estimate the fair value of our reporting units. In developing these fair value estimates, we applied key assumptions, including an assumed discount rate of 13.99% for all reporting units, an assumed long-term growth rate of 3.50% for the contract drilling reporting unit and an assumed long-term growth rate of 2.00% for the drilling and completion fluids reporting unit.

 

Based on the results of the first step of the impairment test in 2008, we concluded that no impairment was indicated in the contract drilling reporting unit as the estimated fair value of that reporting unit exceeded its carrying value. An impairment was indicated in our drilling and completion fluids reporting unit as the estimated fair value of that reporting unit was less than its carrying value. In validating this conclusion, we considered the results of our long-lived asset impairment tests and performed sensitivity analyses of the key assumptions used in deriving the respective fair values of our reporting units. We then performed the second step of the analysis of our drilling and completion fluids reporting unit, which included allocating the estimated fair value to the identifiable tangible and intangible assets and liabilities of this reporting unit based on their respective values. This allocation indicated no residual value for goodwill, and accordingly we recorded an impairment charge of $9.964 million in our December 31, 2008 statement of operations. We exited the drilling and completion fluids business on January 20, 2010, and the 2008 impairment charge is included in our loss from discontinued operations in our statement of operations for the year ended December 31, 2008.

 

We again performed our annual goodwill impairment assessment as of December 31, 2009 related to the remaining $86.2 million in goodwill recorded in our contract drilling reporting unit. In completing the first step of our analysis, we used a three-year projection of discounted cash flows, plus a terminal value determined using the constant growth method to estimate the fair value of our reporting unit. In developing this fair value estimate, we applied key assumptions, including an assumed discount rate of 15.42% and an assumed long-term growth rate of 3.50%. Based on the results of the first step of the impairment test in 2009, we concluded that no impairment was indicated in our contract drilling reporting unit as the estimated fair value of that reporting unit exceeded its carrying value.

 

In the event that market conditions weaken, we may be required to record an impairment of goodwill in our contract drilling reporting unit in the future, and such impairment could be material.

 

Revenue recognition — Revenues are recognized when services are performed, except for revenues earned under turnkey contract drilling arrangements which are recognized using the completed contract method of accounting. We follow the percentage-of-completion method of accounting for footage contract drilling arrangements. Under the percentage-of-completion method, management estimates are relied upon in the determination of the total estimated expenses to be incurred drilling the well. Due to the nature of turnkey contract drilling arrangements and risks therein, we follow the completed contract method of accounting for such arrangements. Under this method, revenues and expenses related to a well in progress are deferred and recognized in the period the well is completed. Provisions for losses on incomplete or in-process wells are made when estimated total expenses are expected to exceed total revenues. We recognize reimbursements received from third parties for out-of-pocket expenses incurred as revenues and account for these out-of-pocket expenses as direct costs. Except for two wells drilled under footage contacts in 2009, all of the wells we drilled in 2009, 2008 and 2007 were drilled under daywork contracts.

 

Use of estimates — The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make certain estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of

the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from such estimates.

 

Key estimates used by management include:

 

 

For additional information on our accounting policies, see Note 1 of Notes to Consolidated Financial Statements included as a part of Item 8 of this Report.

 

Liquidity and Capital Resources

 

As of December 31, 2009, we had working capital of $264 million, including cash and cash equivalents of $49.9 million. During 2009, our sources of cash flow included:

 

 

During 2009, we used $30.7 million to pay dividends on our common stock, $6.2 million to pay issuance costs related to our revolving credit facility, $1.6 million to repurchase shares of our common stock and $453 million:

 

 

We paid cash dividends during the year ended December 31, 2009 as follows:

 

 

On February 10, 2010, our Board of Directors approved a cash dividend on our common stock in the amount of $0.05 per share to be paid on March 30, 2010 to holders of record as of March 15, 2010. The amount and timing of all future dividend payments, if any, is subject to the discretion of the Board of Directors and will depend upon business conditions, results of operations, financial condition, terms of our credit facilities and other factors.

 

On August 1, 2007, our Board of Directors approved a stock buyback program (“Program”), authorizing purchases of up to $250 million of our common stock in open market or privately negotiated transactions. During the year ended December 31, 2009, we purchased 5,715 shares of our common stock under the Program at a cost of approximately $79,000. As of December 31, 2009, we are authorized to purchase approximately $113 million of our outstanding common stock under the Program.

 

We have an unsecured revolving credit facility with a maximum borrowing and letter of credit capacity of $240 million. Interest is paid on the outstanding principal amount of borrowings under the revolving credit facility at a floating rate based on, at our election, LIBOR or a base rate. The margin on LIBOR loans ranges from 3.00% to

4.00% and the margin on base rate loans ranges from 2.00% to 3.00%, based on our debt to capitalization ratio. Any outstanding borrowings must be repaid at maturity on January 31, 2012 and letters of credit may remain in effect up to six months after such maturity date. As of December 31, 2009, we had no borrowings outstanding under the revolving credit facility. We had $46.3 million in letters of credit outstanding at December 31, 2009, and as a result, had available borrowing capacity of approximately $194 million at such date.

 

There are customary representations, warranties, restrictions and covenants associated with the revolving credit facility. Financial covenants provide for a maximum debt to capitalization ratio and a minimum interest coverage ratio. As of December 31, 2009, the maximum debt to capitalization ratio was 35% and the minimum interest coverage ratio was 3.00 to 1. We were in compliance with these financial covenants as of December 31, 2009. We do not expect that the restrictions and covenants will impact our ability to operate or react to opportunities that might arise.

 

We believe that the current level of cash, short-term investments and borrowing capacity available under our revolving credit facility, together with cash expected to be generated from operations (including expected income tax refunds in 2010 of approximately $114 million resulting from the carry-back of net operating losses), should be sufficient to meet our current capital needs. From time to time, opportunities to expand our business, including acquisitions and the building of new rigs are evaluated. The timing, size or success of any acquisition and the associated capital commitments are unpredictable. If we pursue opportunities for growth that require capital, we believe we would be able to satisfy these needs through a combination of working capital, cash generated from operations, borrowing capacity under our revolving credit facility or additional debt or equity financing. However, there can be no assurance that such capital will be available on reasonable terms, if at all.

 

Contractual Obligations

 

The following table presents information with respect to our contractual obligations as of December 31, 2009 (dollars in thousands):

 

 

 

 

Off-Balance Sheet Arrangements

 

We had no off-balance sheet arrangements at December 31, 2009.

Results of Operations

 

Comparison of the years ended December 31, 2009 and 2008

 

The following tables summarize operations by business segment for the years ended December 31, 2009 and 2008:

 

 

The demand for our contract drilling services is impacted by the market price of natural gas and, to a lesser extent, oil. The reactivation and construction of new land drilling rigs in the United States in recent years has also contributed to an excess capacity of land drilling rigs compared to demand. The average market price of natural gas for each of the fiscal quarters and full years in 2009 and 2008 follow:

 

 

 

 

Revenues and direct operating costs decreased in 2009 compared to 2008 primarily as a result of a decrease in the number of operating days. The decrease in operating days was due to decreased demand largely caused by lower commodity prices for natural gas and oil. Our average number of rigs operating during 2009 included an average of approximately six rigs under term contracts that earned standby revenues of $22.3 million. This represented an increase from an average of approximately one rig under term contract that earned standby revenues of $4.7 million in 2008. Rigs on standby earn a discounted dayrate as they do not have crews and have lower costs. We recognized approximately $8.0 million of revenues during 2009 from the early termination of drilling contracts compared to approximately $1.3 million in 2008. Average revenue per operating day decreased in 2009 primarily due to decreases in dayrates for rigs that were operating in the spot market and the expiration of term contracts that were entered into at higher rates. Average direct operating costs per operating day decreased in 2009 primarily due to decreases in labor and repair costs. Significant capital expenditures were incurred in 2009 and 2008 to build new drilling rigs, to modify and upgrade our drilling rigs and to acquire additional related equipment such as drill pipe, drill collars, engines, fluid circulating systems, rig hoisting systems and safety enhancement equipment. Depreciation and impairment expense includes approximately $10.5 million in 2009 and approximately $10.4 million in 2008 related to the impairment of drilling equipment primarily related to drilling rigs that were removed from our

marketable fleet. We removed 23 rigs from our marketable fleet in 2009 and removed 22 rigs from our marketable fleet in 2008. Depreciation expense increased as a result of capital expenditures.

 

 

Our customers have increased their focus on the emerging development of unconventional reservoirs in the Appalachian Basin and the larger jobs associated therewith. As a result of this focus on unconventional reservoirs and lower commodity prices, we experienced a decrease in smaller traditional pressure pumping jobs, which contributed to the overall decrease in the number of total jobs. Revenues and direct operating costs decreased as a result of the decrease in the number of total jobs. Increased average revenue per job reflects an increase in the proportion of larger jobs to total jobs, which was driven by demand for services associated with unconventional reservoirs, partially offset by the impact of reduced pricing. Average direct operating costs per job increased due to the increase in larger jobs and as a result of fixed costs being spread over a significantly reduced number of total jobs. In anticipation of increased activity associated with the unconventional reservoirs in the Appalachian Basin, we have added facilities, equipment and personnel in recent years. Delays in the development of these reservoirs and lower commodity prices have caused a slower increase in customer activity than we had expected, negatively impacting the profitability of this business. Selling, general and administrative expenses decreased primarily as a result of cost containment efforts during the downturn in the industry. Significant capital expenditures have been incurred in recent years to add capacity. Depreciation expense increased as a result of capital expenditures.

 

 

Revenues decreased due to lower average sales prices and lower average net daily production of oil and natural gas. Average net daily oil and natural gas production decreased primarily due to production declines on existing wells. Direct operating costs decreased primarily due to decreases in seismic expenses as well as decreased production taxes and other production costs. Depreciation, depletion and impairment expense in 2009 includes approximately $3.7 million incurred to impair certain oil and natural gas properties compared to approximately $4.4 million incurred to impair certain oil and natural gas properties in 2008. Depletion expense decreased approximately $2.3 million primarily due to lower production and the impact of decreases in the carrying value of

properties resulting from previous impairment charges. Capital expenditures decreased in 2009 as a result of declines in commodity prices.

 

 

Selling, general and administrative expense increased in 2009 primarily as a result of increased professional fees. Other operating expenses decreased due to a decrease in bad debt expense. Gains and losses on the disposal of assets are treated as part of our corporate activities because such transactions relate to corporate strategy decisions of our executive management group. Losses on asset disposals in 2009 were primarily related to the disposal of contract drilling equipment. Gains on asset disposals in 2008 were primarily related to gains on the sale of contract drilling equipment and the sale of oil and natural gas properties. Interest expense increased in 2009 due to the amortization of revolving credit facility issuance costs and increased fees associated with outstanding letters of credit and the unused portion of the revolving credit facility. Capital expenditures increased in 2009 due to the purchase and ongoing implementation of a new enterprise resource planning system.

 

 

On January 20, 2010, we exited our drilling and completion fluids services business which had previously been presented as one of our reportable operating segments. On that date, our wholly owned subsidiary, Ambar Lone Star Fluids Services LLC, completed the sale of substantially all of its assets, excluding billed accounts receivable. Upon our exit from this business, we classified our drilling and completion fluids operating segment as a discontinued operation. Accordingly, the assets and liabilities of this business, along with its results of operations, have been reclassified for all periods presented. Drilling and completion fluids revenue and direct operating costs decreased in 2009 due to decreased sales volume both on land and offshore in the Gulf of Mexico. Drilling and completion fluids selling, general and administrative expenses decreased in 2009 primarily due to a decrease in compensation costs for sales and support personnel due to headcount reductions. Goodwill impairment was recognized in the drilling and completion fluids reporting unit in 2008 as a result of our annual impairment testing which indicated that the fair value of goodwill in that reporting unit was zero. Impairment of assets held for sale in 2009 of $1.9 million represents the adjustment recorded to reduce the carrying value of the assets sold to their fair value less transaction

costs as of December 31, 2009. In 2008, income tax expense was recognized despite a pre-tax loss in the drilling and completion fluids business due to the fact that the goodwill impairment recorded in that year was not deductible for tax purposes.

 

Comparison of the years ended December 31, 2008 and 2007

 

The following tables summarize operations by business segment for the years ended December 31, 2008 and 2007:

 

 

The demand for our contract drilling services is impacted by the market price of natural gas and, to a lesser extent, oil. The reactivation and construction of new land drilling rigs in the United States in recent years has also contributed to an excess capacity of land drilling rigs compared to demand. The average market price of natural gas for each of the fiscal quarters and full years in 2008 and 2007 follow:

 

 

 

 

Revenues and direct operating costs increased in 2008 compared to 2007 primarily as a result of an increase in the number of operating days. The increase in operating days was due to increased demand caused by higher prices for natural gas during most of 2008 compared to 2007. Average revenue per operating day in 2008 was relatively flat compared to 2007. Average direct operating costs per operating day increased in 2008 due to incremental costs incurred to activate idle drilling rigs as well as increases in labor, repairs and other related costs. Significant capital expenditures were incurred in 2008 and 2007 to build new drilling rigs, to modify and upgrade our drilling rigs and to acquire additional related equipment such as drill pipe, drill collars, engines, fluid circulating systems, rig hoisting systems and safety enhancement equipment. Depreciation and impairment expense in 2008 includes approximately $10.4 million related to the impairment of drilling equipment primarily related to drilling rigs

thatwere removed from our marketable fleet. We removed 22 rigs from our marketable fleet in 2008. Depreciation expense increased as a result of capital expenditures.

 

 

Our customers increased their focus on the emerging development of unconventional reservoirs in the Appalachian Basin and the larger jobs associated therewith. As a result of this focus on unconventional reservoirs, we experienced a decrease in smaller traditional pressure pumping jobs in 2008, which resulted in an overall decrease in the number of total jobs. Revenues and direct operating costs increased as a result of an increase in the average revenue and average direct operating costs per job. Increased average revenue per job was due to an increase in the proportion of larger jobs to total jobs, which was driven by demand for services associated with unconventional reservoirs. Average direct operating costs per job increased due to the increase in larger jobs and as a result of increases in compensation, maintenance and the cost of materials used in our operations. In anticipation of increased activity associated with the unconventional reservoirs in the Appalachian Basin, we added facilities, equipment and personnel. Delays in the development of these reservoirs caused a slower increase in customer activity than we had expected, negatively impacting the profitability of this business. Selling, general and administrative expense increased primarily as a result of expenses to support expanded operations of this segment. Significant capital expenditures were incurred to add capacity, expand our areas of operation and modify and upgrade existing equipment. Depreciation expense increased as a result of capital expenditures.

 

 

Revenues increased due to higher average sales prices of oil and natural gas. This increase was partially offset by a decrease in the average net daily production of oil and natural gas and by the elimination of well operations revenue due to the fourth quarter 2007 sale of the operating responsibilities associated with oil and natural gas wells. Average net daily oil and natural gas production decreased primarily due to the sale of properties in 2007 and production declines. Direct operating costs increased due to an increase in seismic expenses as well as increased production taxes and other production costs. Selling, general and administrative expense decreased in 2008 due to the sale of the operating responsibilities mentioned above and the resulting elimination of headcount in this

segment. Depreciation, depletion and impairment expense in 2008 includes approximately $4.4 million incurred to impair certain oil and natural gas properties compared to approximately $3.9 million incurred to impair certain oil and natural gas properties in 2007. Depletion expense decreased approximately $1.9 million primarily due to the sale of certain properties in 2007.

 

 

Selling, general and administrative expense increased primarily as a result of additional compensation expense and an increase in payroll tax expense associated with the exercise of stock options during 2008. Other operating expenses increased due to an increase in bad debt expense. Gains and losses on the disposal of assets are considered as part of our corporate activities because such transactions relate to corporate strategy decisions of our executive management group. Gains on asset disposals in 2008 were primarily related to gains on the sale of contract drilling equipment and the sale of oil and natural gas properties. Gains on asset disposals in 2007 were primarily related to the sale of oil and natural gas properties.

 

In November 2005, we discovered that our former Chief Financial Officer, Jonathan D. Nelson (“Nelson”), had fraudulently diverted approximately $77.5 million in Company funds for his own benefit during the period from 1998 through 2005. As a result, the Audit Committee of the Board of Directors commenced an investigation into Nelson’s activities and retained independent counsel and independent forensic accountants to assist with the investigation. Nelson has been sentenced and is serving a term of imprisonment arising out of his embezzlement. A receiver was appointed to take control of and liquidate the assets of Nelson. In May 2007, the court approved a plan of distribution for the assets recovered by the receiver. We recovered a total of approximately $44.5 million pursuant to the approved plan, and we recognized this recovery in our consolidated statement of income in 2007, net of professional fees incurred as a result of the embezzlement.

 

Drilling and completion fluids revenue and direct operating costs increased in 2008 due to increased sales volume both on land and offshore in the Gulf of Mexico. Goodwill impairment was recognized in the drilling and completion fluids reporting unit in 2008 as a result of our annual impairment testing which indicated that the fair value of goodwill in that reporting unit was zero. No impairment of goodwill was recognized in 2007 as the annual impairment testing did not indicate that an impairment existed at that time. In 2008, income tax expense was recognized despite a pre-tax loss in the drilling and completion fluids business due to the fact that the goodwill impairment recorded in that year was not deductible for tax purposes.

 

Income Taxes

 

 

The effective tax rate is a result of a Federal rate of 35.0% adjusted as follows:

 

 

The permanent differences indicated above are largely attributable to our Domestic Production Activities deduction. The Domestic Production Activities Deduction was enacted as part of the American Jobs Creation Act of 2004 (as revised by the Emergency Economic Stabilization Act of 2008, the “Act”) and is effective for taxable years after December 31, 2004. The Act allows a deduction of 6% on the lesser of qualified production activities income or taxable income.

 

We record deferred Federal income taxes based primarily on the temporary differences between the book and tax bases of our assets. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the year in which those temporary differences are expected to be settled. As a result of fully recognizing the benefit of our deferred income taxes, we incur deferred income tax expense as these benefits are utilized. We recognized deferred tax expense of approximately $101 million in 2009, $65.4 million in 2008 and $38.3 million in 2007.

 

Volatility of Oil and Natural Gas Prices and its Impact on Operations and Financial Condition

 

Our revenue, profitability, financial condition and rate of growth are substantially dependent upon prevailing prices for natural gas and, to a lesser extent, oil. For many years, oil and natural gas prices and markets have been extremely volatile. Prices are affected by market supply and demand factors as well as international military, political and economic conditions, and the ability of OPEC to set and maintain production and price targets. All of these factors are beyond our control. During 2008, the monthly average market price of natural gas (monthly average Henry Hub price as reported by the Energy Information Administration) peaked in June at $13.06 per Mcf before rapidly declining to an average of $5.99 per Mcf in December. In 2009, the monthly average market price of natural gas declined further to a low of $3.06 per Mcf in September. This decline in the market price of natural gas resulted in our customers significantly reducing their drilling activities beginning in the fourth quarter of 2008 and drilling activities remained low throughout 2009. This reduction in demand combined with the reactivation and construction of new land drilling rigs in the United States during the last several years has resulted in excess capacity compared to demand. As a result of these factors, our average number of rigs operating has declined significantly. We expect oil and natural gas prices to continue to be volatile and to affect our financial condition,

operations and ability to access sources of capital. Low market prices for natural gas would likely result in demand for our drilling rigs remaining low and adversely affect our operating results, financial condition and cash flows.

 

The North American land drilling industry has experienced downturns in demand during the last decade. During these periods, there have been substantially more drilling rigs available than necessary to meet demand. As a result, drilling contractors have had difficulty sustaining profit margins and, at times, have incurred losses during the downturn periods.

 

Impact of Inflation

 

Inflation has not had a significant impact on our operations during the three years in the period ended December 31, 2009. We believe that inflation will not have a significant near-term impact on our financial position.

 

Recently Issued Accounting Standards

 

In June 2008, the FASB issued a new accounting standard which clarifies that share-based payment awards that entitle their holders to receive non-forfeitable dividends before vesting should be considered participating securities and, as such, should be included in the calculation of basic earnings-per-share using the two-class method. Certain of our share-based payment awards entitle the holders to receive non-forfeitable dividends. This standard is effective for financial statements issued for fiscal years beginning after December 15, 2008, as well as interim periods within those years and became effective for us on January 1, 2009. The impact of the adoption of this standard is discussed in Note 1 of our Consolidated Financial Statements.

 

In December 2008, the SEC issued a Final Rule, Modernization of Oil and Gas Reporting (“Final Rule”). The Final Rule revises certain oil and gas reporting disclosures in Regulation S-K and Regulation S-X under the Securities Act, and the Exchange Act, as well as Industry Guide 2. The amendments are designed to modernize and update oil and gas disclosure requirements to align them with current practices and changes in technology. The disclosure requirements are effective for registration statements filed on or after January 1, 2010 and for annual financial statements filed on or after December 31, 2009. We applied the provisions of the Final Rule in connection with our December 31, 2009 oil and natural gas reserve estimation process. The application of the Final Rule did not have a material impact on us.

 

In April 2009, the FASB issued a staff position to provide additional guidance for determining whether a market for a financial asset is not active and a transaction is not distressed for fair value measurements under generally accepted accounting principles. The provisions of this staff position are effective for financial statements issued for interim and annual periods ending after June 15, 2009 and became effective for us in the quarter ended June 30, 2009. The adoption of this staff position did not have a material impact on us.

 

In April 2009, the FASB issued a staff position which increases the frequency of fair value disclosures for financial instruments from annual only to quarterly reporting periods. The provisions of this staff position are effective for financial statements issued for interim and annual periods ending after June 15, 2009 and became effective for us in the quarter ended June 30, 2009. The adoption of this staff position did not have a material impact on us.

 

In June 2009, the FASB issued a new accounting standard that amends the accounting and disclosure requirements for the consolidation of variable interest entities. This new standard removes the previously existing exception from applying consolidation guidance to qualifying special-purpose entities and requires ongoing reassessments of whether an enterprise is the primary beneficiary of a variable interest entity. Before this new standard, generally accepted accounting principles required reconsideration of whether an enterprise is the primary beneficiary of a variable interest entity only when specific events occurred. This new standard is effective as of the beginning of each reporting entity’s first annual reporting period that begins after November 15, 2009, for interim periods within that first annual reporting period, and for interim and annual reporting periods thereafter. This new standard became effective for us on January 1, 2010. The adoption of this standard did not impact our consolidated financial statements.

 

In June 2009, the FASB issued the FASB Accounting Standards Codification (“Codification”). Effective for financial statements issued for interim and annual periods ending after September 15, 2009, the Codification

became the source of authoritative U.S. generally accepted accounting principles. The FASB will no longer issue new standards in the form of Statements, FASB Staff Positions or EITF Abstracts. Instead, it will issue Accounting Standards Updates to update the Codification. The adoption of the Codification did not impact our consolidated financial statements.

 

 

We currently have exposure to interest rate market risk associated with any borrowings that we have under our revolving credit facility. The revolving credit facility calls for periodic interest payments at a floating rate ranging from LIBOR plus 3.00% to 4.00% or at the prime rate. The applicable rate above LIBOR is based upon our debt to capitalization ratio. As of December 31, 2009, we had no borrowings outstanding under our revolving credit facility.

 

We conduct a portion of our business in Canadian dollars through our Canadian land-based drilling operations. The exchange rate between Canadian dollars and U.S. dollars has fluctuated during the last several years. If the value of the Canadian dollar against the U.S. dollar weakens, revenues and earnings of our Canadian operations will be reduced and the value of our Canadian net assets will decline when they are translated to U.S. dollars.

 

The carrying values of cash and cash equivalents, trade receivables and accounts payable approximate fair value due to the short-term maturity of these items.

 

 

Financial Statements are filed as a part of this Report at the end of Part IV hereof beginning at page F-1, Index to Consolidated Financial Statements, and are incorporated herein by this reference.

 

 

None.

 

 

Disclosure Controls and Procedures:

 

Under the supervision and with the participation of our management, including our Chief Executive Officer (CEO) and Chief Financial Officer (CFO), we conducted an evaluation of the effectiveness of our disclosure controls and procedures, as such term is defined in Rules 13a-15(e) and 15d-15(e) promulgated under the Exchange Act, as of the end of the period covered by this Report. Based on this evaluation, our CEO and CFO concluded that, as of December 31, 2009, our disclosure controls and procedures were effective to ensure that information required to be disclosed by us in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms and is accumulated and reported to our management, including our CEO and CFO, as appropriate to allow timely decisions regarding required disclosure.

 

Management’s Report on Internal Control over Financial Reporting:

 

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Exchange Act Rule 13a-15(f). Under the supervision and with the participation of our management, including our CEO and CFO, we carried out an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2009, based on the Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, our management has concluded that our internal control over financial reporting was effective as of December 31, 2009.

 

The effectiveness of our internal control over financial reporting as of December 31, 2009 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears on page F-2 of this Report and is incorporated by reference into Item 8 of this Report.

Changes in Internal Control over Financial Reporting:

 

There have been no changes in our internal control over financial reporting during the most recently completed fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

 

 

None.

PART III

 

The information required by Part III is omitted from this Report because we expect to file a definitive proxy statement (the “Proxy Statement”) pursuant to Regulation 14A of the Securities Exchange Act of 1934 no later than 120 days after the end of the fiscal year covered by this Report and certain information included therein is incorporated herein by reference.

 

 

The information required by this Item is incorporated herein by reference to the Proxy Statement.

 

We have adopted a Code of Business Conduct and Ethics for Senior Financial Executives, which covers, among others, our principal executive officer, principal financial officer and principal accounting officer. The text of this code is located on our website under “Governance.” Our Internet address is www.patenergy.com. We intend to disclose any amendments to or waivers from this code on our website.

 

 

The information required by this Item is incorporated herein by reference to the Proxy Statement.

 

 

The information required by this Item is incorporated herein by reference to the Proxy Statement.

 

 

The information required by this Item is incorporated herein by reference to the Proxy Statement.

 

 

The information required by this Item is incorporated herein by reference to the Proxy Statement.

PART IV

 

 

(a)(1) Financial Statements

 

See Index to Consolidated Financial Statements on page F-1 of this Report.

 

(a)(2) Financial Statement Schedule

 

Schedule II — Valuation and qualifying accounts is filed herewith on page S-1.

 

All other financial statement schedules have been omitted because they are not applicable or the information required therein is included elsewhere in the financial statements or notes thereto.

 

(a)(3) Exhibits

 

The following exhibits are filed herewith or incorporated by reference herein.

 

 

 

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

 

 

To the Board of Directors and Shareholders

  of Patterson-UTI Energy, Inc.:

 

In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of Patterson-UTI Energy, Inc. and its subsidiaries (the “Company”) at December 31, 2009 and 2008, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on these financial statements, on the financial statement schedule, and on the Company’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

 

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

 

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

 

/s/ PricewaterhouseCoopers LLP

 

Houston, Texas

February 19, 2010

PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES