Patterson-UTI Energy - 10-K annual report

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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 if disclosure of delinquent filers pursuant to Item 405 ofRegulation S-Kis not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of thisForm 10-Kor any amendment to thisForm 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 the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

 

 

Indicate by check mark whether the registrant is a shell company (as defined inRule 12b-2of 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 29, 2007, the last business day of the registrant’s most recently completed second fiscal quarter, was $4,052,686,260, calculated by reference to the closing price of $26.21 for the common stock on the Nasdaq National Market on that date.

 

As of February 15, 2008, the registrant had outstanding 154,027,206 shares of common stock, $.01 par value, its only class of common stock.

 

Documents incorporated by reference:

 

Definitive Proxy Statement for the 2008 Annual Meeting of Stockholders (Part III).

 

 

Certain statements made in this Annual Report onForm 10-Kand in other public filings and press releases by the Company contain “forward-looking” information (as defined in the Private Securities Litigation Reform Act of 1995) that involves risk and uncertainty. These forward-looking statements may include, but are not limited to, references to liquidity, financing of operations, impact of inflation, future capital expenditures, oil and natural gas prices and demand for drilling rigs. 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,” “expects,” “project,” “will,” “could,” “may,” “plans,” “intends,” “strategy,” or “anticipates,” and other words and expressions of similar meaning. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we can give no assurance that such expectation will prove to have been correct. Forward-looking statements may be made by management orally or in writing, including, but not limited to, Management’s Discussion and Analysis of Financial Condition and Results of Operations included in this Annual Report onForm 10-Kand other sections of our filings with the Securities and Exchange Commission under the Securities Exchange Act of 1934 and the Securities Act of 1933.

 

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, declines in oil and natural gas prices that could adversely affect demand for the Company’s 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, difficulty in integrating acquisitions, demand for oil and natural gas, shortages of rig equipment and ability to retain management and field personnel. Refer to “Risk Factors” contained in Part 1 of this Annual Report onForm 10-Kfor a more complete discussion of these and other factors that might affect our performance and financial results. These forward-looking statements are intended to relay the Company’s 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, future events or otherwise.

 

 

 

This Annual Report onForm 10-K,along with our Quarterly Reports onForm 10-Q,Current Reports onForm 8-Kand amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, 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 United States Securities and Exchange Commission (“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 at1-800-SEC-0330.

 

 

Based on publicly available information, we believe we are the second largest operator of land-based drilling rigs in North America. 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, South Dakota, Pennsylvania and western Canada (Alberta, British Columbia and Saskatchewan).

 

As of December 31, 2007, we had a drilling fleet that consisted of 350 currently marketable land-based drilling rigs. A drilling rig includes the structure, power source and machinery necessary to cause a drill bit to penetrate earth to a depth desired by the customer. A drilling rig is considered currently 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 drilling rig components and equipment.

 

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 provide drilling fluids, completion fluids and related services to oil and natural gas operators offshore in the Gulf of Mexico and on land in Texas, Southeastern New Mexico, Oklahoma and the Gulf Coast region of 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. We 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 West and South Texas, Southeastern New Mexico, Utah and Mississippi.

 

 

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

 

 

All of our industry segments had operating profits in 2007, 2006 and 2005.

 

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.

 

 

General — We market our contract drilling services to major and independent oil and natural gas operators. As of December 31, 2007, we had 350 currently marketable land-based drilling rigs which were based in the following regions:

 

 

Our marketable drilling rigs have rated maximum depth capabilities ranging from 5,000 feet to 30,000 feet. Sixty-nine of these drilling rigs are electric rigs and 281 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 drilling rig components and equipment 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 on an ongoing program to modify and upgrade our drilling rigs to ensure that our drilling equipment is competitive. We have spent $1.4 billion during the last three years on capital expenditures to modify, upgrade and maintain our drilling fleet. During fiscal years 2007, 2006 and 2005, we spent approximately $540 million, $531 million and $329 million, respectively, on these capital expenditures.

Depth and complexity of the well and drill site conditions are the principal factors in determining the size of drilling rig used for a particular job. Our rigs are capable of vertical or horizontal drilling.

 

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. Typically, the contracts are short-term to drill a single well or a series of wells. Customer demand for drilling contracts with a term of one or more years increased during 2005 due to the scarcity of available drilling rigs in the market place. In response to this demand, we entered into long-term contracts in 2005 and 2006 and, to a lesser extent, in 2007. These long-term contracts provide for the use of drilling rigs for fixed periods of time during which multiple wells are drilled. During 2007, our average number of days to drill a well (which includes moving to the drill site, rigging up and rigging down) was approximately 21 days. We may continue to enter into long-term contracts when considered beneficial to the Company.

 

The 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. We generally 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. The customers generally indemnify us against claims that might arise from other surface and subsurface pollution, except claims that might arise from our gross negligence. Each drilling contract will contain the actual terms setting forth our rights and obligations and those of the particular customer.

 

The contracts provide for payment on a daywork, footage, or turnkey basis, or a combination thereof. In each case, we provide the rig and crews. Our bid for each contract depends upon location, depth and anticipated complexity of the well,on-sitedrilling 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.

 

 

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 assumes certain risks associated with loss of the well from fire, blowouts and other risks. Due to market conditions, we have entered into very few footage contracts in recent years.

 

 

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 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. However, given the increased exposure we have under a turnkey contract, 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: daywork, footage and turnkey. Due to market conditions, we have entered into very few turnkey contracts in recent years.

 

Revenues by Contract Type — Information regarding our revenues by contract type for the last three years follows:

 

 

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 rigs that were currently marketable as of December 31, 2007 to be as follows:

 

 

At December 31, 2007, we owned and operated 324 trucks and 441 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 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, New Mexico, Oklahoma, Wyoming, Utah and Western Canada.

 

 

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. Generally, Appalachian Basin wells require cementing services before production commences. 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, 2007 follows:

 

 

 

General — We provide drilling fluids, completion fluids and related services to oil and natural gas operators offshore in the Gulf of Mexico and on land in Texas, Southeastern New Mexico, Oklahoma and the Gulf Coast region of Louisiana. We serve our offshore customers through six stockpoint facilities located along the Gulf of Mexico in Texas and Louisiana and our land-based customers through fourteen stockpoint facilities in Texas, Louisiana, Oklahoma and New Mexico.

 

Drilling Fluids — Drilling fluid products and systems are used to cool and lubricate the bit during drilling operations, contain formation pressures (thereby minimizing blowout risk), suspend and remove rock cuttings from the hole and maintain the stability of the wellbore. Technical services are provided to ensure that the products and systems are applied effectively to optimize drilling operations.

 

Completion Fluids — After a well is drilled, the well casing is set and cemented into place. At that point, the drilling fluid services are complete and the drilling fluids are circulated out of the well and replaced with completion fluids. Completion fluids, also known as clear brine fluids, are solids-free, clear salt solutions that have high specific gravities. Combined with a range of specialty chemicals, these fluids are used to control bottom-hole pressures and to meet specific corrosion, inhibition, viscosity and fluid loss requirements.

 

Raw Materials — Our drilling and completion fluids operations depend on the availability of the following raw materials:

 

barite and bentonite

calcium chloride, calcium bromide and zinc bromide

 

We obtain these raw materials through purchases made on the spot market and supply contracts with producers of these raw materials.

 

Barite Grinding Facility — We operate a barite grinding facility with two barite grinding mills in Houma, Louisiana. This facility allows us to grind raw barite into the powder additive used in drilling fluids.

 

Other Equipment — We own and operate 20 trucks and 92 trailers and lease another 34 trucks which are used to transport drilling and completion fluids and related equipment.

 

General — 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. 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 West and South Texas, Southeastern New Mexico, Utah and Mississippi.

 

 

The customers of each of our three oil service business segments are oil and natural gas operators. Our customer base includes both major and independent oil and natural gas operators. During 2007, no single customer accounted for 10% or more of our consolidated operating revenues.

 

 

Contract Drilling and Pressure Pumping Businesses — 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. The equipment can also be moved from one market to another in response to market conditions.

 

Drilling and Completion Fluids Business — The drilling and completion fluids industry is highly competitive and price is generally the most important factor. Other competitive factors include the availability of chemicals and experienced personnel, the reputation of the fluids services provider in the drilling industry and relationships with customers. Some of our competitors have substantially more resources and longer operating histories than we have.

 

 

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 have not required the expenditure of significant resources. 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. State and Federal 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. 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.

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 CERCLAand/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 is more comprehensive and stringent than previous oil pollution liability and prevention laws. It 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 aclean-up.

 

The Oil Pollution Act also expands the authority and capability of the Federal government to direct and manage oil spillclean-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 oil and natural gas properties in each of the areas in which we operate and for each of the stockpoints operated by our drilling and completion fluids business. 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.

 

Our operations are also subject to Federal, state and local regulations for the control of air emissions. The Federal Clean Air Act, as amended, and various state and local laws impose certain air quality requirements on us. Amendments to the Clean Air Act revised the definition of “major source” such that emissions from both wellhead and associated equipment involved in oil and natural gas production may be added to determine if a source is a “major source.” As a consequence, more facilities may become major sources and thus would be required to obtain operating permits. This permitting process may require capital expenditures in order to comply with permit limits.

 

 

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 public liability and property damage to others with respect to our operations. However, such insurance may not be sufficient to protect us against liability for all consequences of:

 

 

We also carry insurance to cover physical damage to, or loss of, our drilling rigs. However, it does not 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.

 

We had approximately 8,100 full-time employees at December 31, 2007. 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 does not significantly affect our overall operations. However, our drilling operations in Canada, and our pressure pumping division in the Appalachian Basin to a lesser extent, are subject to slow periods of activity during the Spring thaw.

 

 

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.

 

 

We wish to caution you that there are risks and uncertainties that could affect our business. These risks and uncertainties include, but are not limited to, the risks described below and elsewhere in this Report, particularly found in “Forward Looking Statements.” The following is not intended to be a complete discussion of all potential risks or uncertainties, as it is not possible to predict or identify all risk factors.

 

 

Our revenue, profitability 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 2006, the average market price of natural gas retreated from record highs that were set in 2005. The price dropped from an average of $8.98 per Mcf in 2005 to an average of $6.94 per Mcf in 2006 and an average of $7.18 per Mcf in 2007. This resulted in our customers moderating their increase in drilling activities in 2007. This moderation combined with the reactivation and construction of new land drilling rigs in the United States has resulted in excess capacity compared to recent demand. Additionally, drilling activity in Canada has slowed significantly. As a result of these factors, our average number of rigs operating declined to 244 in 2007 compared to 296 in 2006. 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. A significant decrease in market prices for natural gas could result in a material decrease in demand for drilling rigs and adversely affect our operating results.

 

 

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 during the downturn periods.

 

In addition to adverse effects that future declines in demand could have on us, 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:

 

 

 

As a result of an increase in drilling activity and increased prices for drilling services in 2005 and 2006, construction of new drilling rigs increased significantly in that time period. The addition of new drilling rigs to the market has resulted in excess capacity compared to demand, and construction of new drilling rigs has moderated in 2007. 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.

 

 

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

 

 

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 for the foreseeable future 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.

 

The drilling and completion fluids services industry is highly competitive. Price is generally the most important factor. Other competitive factors include the availability of chemicals and experienced personnel, the reputation of the fluids services provider in the drilling industry and relationships with customers. Some of our competitors have substantially more resources and longer operating histories than we have.

 

 

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, resulting in higher operating costs.

 

 

We have increased our drilling rig fleet in the past through mergers and acquisitions. The land drilling industry has experienced significant consolidation, and there can be no assurance that acquisition opportunities will be available in the future. Additionally, we are likely to continue to face intense competition from other companies for available acquisition opportunities.

There can be no assurance that we will:

 

 

We may incur substantial indebtedness to finance future acquisitions and also may issue equity securities or convertible securities in connection with any such acquisitions. 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.

 

 

Our operations are subject to many hazards inherent in the contract drilling, pressure pumping, and drilling and completion fluids 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.

 

We have 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.

 

 

The drilling of oil and natural gas wells is subject to various Federal, state, foreign, and local laws, rules and regulations. 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, Federal law imposes a variety of regulations 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 Federal law. Our operations and facilities are subject to numerous state and Federal 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.

 

 

At times, a portion of our contract drilling is performed under turnkey and footage contracts, which involve significant risks. Under turnkey drilling contracts, we contract to drill a well to a certain depth under specified conditions at a fixed price. Under footage contracts, we contract to drill a well to a certain depth under specified conditions at a fixed price per foot. The risk to us under these types of drilling contracts are greater than on a well drilled on a daywork basis. Unlike daywork contracts, we must bear the cost of services until the target depth is

reached. In addition, we must assume most of the risk associated with the drilling operations, generally assumed by the operator of the well on a daywork contract, including blowouts, loss of hole from fire, machinery breakdowns and abnormal drilling conditions. Accordingly, if severe drilling problems are encountered in drilling wells under such contracts, we could suffer substantial losses.

 

 

We are a Delaware corporation subject to the Delaware General Corporation Law, including Section 203, an anti-takeover law enacted in 1988. 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 are located in Snyder, Texas and include approximately 37,000 square feet of office and storage space. These headquarters are located at 4510 Lamesa Highway, Snyder, Texas, and our telephone number at that address is(325) 574-6300.We also have administrative offices, yards and stockpoint facilities in many of the areas in which we operate. The facilities are primarily used to support day-to-day operations, including the repair and maintenance of equipment as well as the storage of equipment, inventory and supplies and to facilitate administrative responsibilities and sales.

 

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

 

Drilling and Completion Fluids — Our drilling and completion fluids services are supported by several administrative offices and stockpoint facilities located throughout our areas of operations including Texas, Louisiana, New Mexico and Oklahoma.

 

We own our headquarters 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.

 

 

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

 

 

As of February 15, 2008, there were approximately 2,100 holders of record of our common stock.

 

 

We paid cash dividends during the years ended December 31, 2007 and 2006 as follows:

 

On February 13, 2008, our Board of Directors approved a cash dividend on our common stock in the amount of $0.12 per share to be paid on March 28, 2008 to holders of record as of March 12, 2008. 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.

 

The table below sets forth the information with respect to purchases of our common stock made by us during the quarter ended December 31, 2007.

 

 

 

 

 

Equity compensation to our employees, officers and directors as of December 31, 2007 follows:

 

 

 

 

 

The following graph compares the cumulative stockholder return of our common stock for the period from December 31, 2002 through December 31, 2007, 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 peer group consists of Grey Wolf, Inc., Helmerich & Payne, Inc., Nabors Industries, Ltd., Pioneer Drilling Co. and Unit Corp. All of the companies in our peer group are providers of land-based drilling services. The graph assumes investment of $100 on December 31, 2002 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 the Regulations of 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, 2007, 2006, 2005, 2004 and 2003, and for each of the five years in the period ended December 31, 2007 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 2007 presentation.

 

 

This Item 7 contains forward-looking statements, which are made pursuant to the “Safe Harbor” provisions of the Private Securities Litigation Reform Act of 1995.

 

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, we provide pressure pumping services and drilling and completion fluid services. In addition to the aforementioned contract services, we have also engaged in the development, exploration, acquisition and production of oil and natural gas. For the three years ended December 31, 2007, 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. Our drilling and completion fluids services are provided to operators offshore in the Gulf of Mexico and on land in Texas, Southeastern New Mexico, Oklahoma and the Gulf Coast region of Louisiana. The oil and natural gas properties in which we hold working interests are primarily located in West and South Texas, Southeastern New Mexico, Utah and Mississippi.

 

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 2007, our average number of rigs operating was 244 compared to 296 in 2006 and 276 in 2005. Our average revenue per operating day was $19,550 in 2007 compared to $20,050 in 2006 and $14,770 in 2005. Our consolidated net income for 2007 decreased by $235 million, or 35%, as compared to 2006. This decrease was primarily due to our contract drilling segment experiencing a decrease in the average number of rigs operating, a decrease in the average revenue per operating day and an increase in the average costs per operating day in 2007 as compared to 2006.

 

Our revenues, profitability and cash flows are highly dependent upon the market prices of oil and natural gas. During periods of improved commodity prices, the capital spending budgets of oil and natural gas operators tend to expand, which 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. In addition, our operations are highly impacted by competition, the availability of excess equipment, labor issues and various other factors which are more fully described as “Risk Factors” in Item 1A of this Annual Report.

 

We believe that the liquidity shown on our balance sheet as of December 31, 2007, which includes approximately $228 million in working capital (including $17.4 million in cash) and $266 million available under a $375 million line of credit, provides us with the ability to pursue acquisition opportunities, expand into new regions, make improvements to our assets, pay cash dividends and survive downturns in our industry.

 

Commitments and Contingencies — We maintain letters of credit in the aggregate amount of $59.4 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. No amounts have been drawn under the letters of credit.

 

As of December 31, 2007, we had non-cancelable commitments to purchase approximately $83.0 million of equipment.

A receiver was appointed to take control of and liquidate the assets of our former CFO in connection with his embezzlement of Company funds. In May 2007, the court approved a plan of distribution for the assets recovered by the receiver. We expect to recover a total of approximately $44.5 million pursuant to the approved plan, and we have recognized this recovery in our consolidated statement of income in 2007, net of professional fees incurred as a result of the embezzlement. As of December 31, 2007, we had received cash payments from the receiver of approximately $41.2 million, with the remaining $3.3 million of the recovery consisting of notes receivable, investments and other assets that are being transferred to us.

 

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, money markets and highly rated municipal and commercial bonds.

 

Description of business — We conduct our contract drilling operations in Texas, New Mexico, Oklahoma, Arkansas, Louisiana, Mississippi, Colorado, Utah, Wyoming, Montana, North Dakota, South Dakota, Pennsylvania and western Canada. For the years ended December 31, 2007, 2006 and 2005, revenue earned outside of the United States was $72.9 million, $98.5 million and $84.4 million, respectively. Additionally, we had long-lived assets located outside of the United States of $91.6 million, $78.9 million and $60.7 million as of December 31, 2007, 2006 and 2005, respectively. As of December 31, 2007, we had 350 currently 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. We provide drilling fluids, completion fluids and related services to oil and natural gas operators offshore in the Gulf of Mexico and on land in Texas, Southeastern New Mexico, Oklahoma and the Gulf Coast region of 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. We also invest on a working interest basis in production of oil and natural gas.

 

 

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 assets for impairment when events or changes in circumstances indicate that the carrying values of certain assets either exceed their respective fair values or may not be recovered over their estimated remaining useful lives. 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 to income when estimated future cash flows, on an undiscounted basis, are less than the asset’s net book value. Impairment charges are recorded based on discounted cash flows. There were no material impairment charges related to property and equipment during the years 2007, 2006 or 2005.

 

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. In accordance with Statement of Financial Accounting Standards No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies,” (“SFAS No. 19”) 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 an 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 internally and 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. Unproved oil and natural gas properties are reviewed quarterly to determine impairment. The intent to drill, lease expiration and abandonment of area are considered. Assessment of impairment is made on alease-by-leasebasis. If an unproved property is determined to be impaired, then costs related to that property are expensed. Impairment expense of approximately $3.9 million, $5.0 million and $4.4 million for the years ended December 31, 2007, 2006 and 2005, respectively, is included in depreciation, depletion and impairment in the accompanying financial statements.

 

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.

 

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, as described below. 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 estimated total revenues. We recognize reimbursements received from third parties for out-of-pocket expenses incurred as revenues and account for out-of-pocket expenses as direct costs.

 

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.

 

As of December 31, 2007, we had working capital of $228 million including cash and cash equivalents of $17.4 million. For 2007, our sources of cash flow included:

 

 

During 2007, we used $70.9 million to repurchase shares of our common stock, $68.6 million to pay dividends on our common stock, $70.0 million to repay borrowings under our line of credit, $29.0 million to acquire three electric land-based drilling rigs and $608 million:

 

 

As of December 31, 2007, we had $50.0 million in borrowings outstanding under our $375 million revolving line of credit and $59.4 million in outstanding letters of credit such that we had available borrowing capacity of approximately $266 million at December 31, 2007.

 

We paid cash dividends during the year ended December 31, 2007 as follows:

 

 

On February 13, 2008, our Board of Directors approved a cash dividend on our common stock in the amount of $0.12 per share to be paid on March 28, 2008 to holders of record as of March 12, 2008. 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 (“2007 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, 2007, we purchased 3,308,850 shares of our common stock under the 2007 Program at a cost of approximately $70.4 million. As of December 31, 2007, we are authorized to purchase approximately $180 million of our outstanding common stock under the 2007 Program.

 

We believe that the current level of cash and short-term investments, together with cash generated from operations, should be sufficient to meet our capital needs. From time to time, acquisition opportunities are evaluated. The timing, size or success of any acquisition and the associated capital commitments are unpredictable. Should opportunities for growth requiring capital arise, we believe we would be able to satisfy these needs through a combination of working capital, cash generated from operations, our existing credit facility and additional debt or equity financing. However, there can be no assurance that such capital would be available.

 

The following table presents information with respect to our contractual obligations as of December 31, 2007 (dollars in thousands):

 

 

 

 

 

We had no off-balance sheet arrangements at December 31, 2007.

 

 

 

 

 

The demand for our contract drilling services is impacted by the market price of oil and, to a larger extent, natural gas. However, the reactivation and construction of new land drilling rigs in the United States has resulted in excess capacity compared to recent demand. Additionally, drilling activity in Canada has decreased significantly. As a result, our average rigs operating declined to 244 in 2007 from 296 in 2006. The average market price of natural gas for each of the fiscal quarters and full years in 2007 and 2006 follow:

 

 

 

Revenues in 2007 decreased as compared to 2006 as a result of decreases in the number of operating days and in the average revenues per operating day. Direct operating costs in 2007 decreased as compared to 2006 as a result of the decreased number of operating days, largely offset by an increase in the average direct operating costs per operating day. The increase in average direct operating costs per day resulted primarily from increased compensation costs and an increase in the cost of maintenance for our drilling rigs. Operating days, average rigs operating and average revenue per operating day decreased in 2007 as a result of decreased demand for our contract drilling services resulting from the excess capacity discussed above. Selling, general and administrative expense decreased primarily as a result of the transfer of certain administrative staff to our corporate segment. Significant capital expenditures have been incurred in both 2007 and 2006 to activate additional 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. The increase in depreciation expense is a result of the capital expenditures discussed above.

 

 

Revenues and direct operating costs increased as a result of the increased number of jobs, as well as an increase in the average revenue and average direct operating costs per job. The increase in jobs was attributable to increased demand for our services and increased operating capacity. Increased average revenue per job was due to increased pricing for our services and an increase in the number of larger jobs being driven by demand for services associated with unconventional reservoirs in the Appalachian basin. Average direct operating costs per job increased as a result of increases in compensation, maintenance and the cost of materials used in our operations, as well as an increase in the number of larger jobs. Selling, general and administrative expense increased primarily as a result of expenses to support the expanding operations of the pressure pumping segment. Significant capital expenditures have been incurred in both 2007 and 2006 to add capacity, expand our areas of operation and modify and upgrade existing equipment. The increase in depreciation expense is a result of the capital expenditures discussed above.

 

 

Revenues and direct operating costs decreased as a result of a decrease in the number of large jobs offshore in the Gulf of Mexico caused primarily by a slowdown in drilling activity during 2007 as compared to 2006.

 

 

Revenues increased due to an increase in the average sales price of both oil and natural gas in 2007 compared to 2006. Average net daily oil and natural gas production decreased in 2007 primarily due to the sale of certain properties in the first half of 2007. The decrease in direct operating costs is primarily due to a decrease of approximately $3.0 million in costs associated with the abandonment of exploratory wells in 2007 compared to 2006. Selling, general and administrative expenses decreased in 2007 primarily due to the transfer in the fourth quarter of the operating responsibilities associated with oil and natural gas wells resulting in reduced headcount in our oil and natural gas production and exploration segment. Depreciation, depletion and impairment expense in 2007 includes approximately $3.9 million incurred to impair certain oil and natural gas properties compared to approximately $5.0 million incurred to impair certain oil and natural gas properties in 2006. Depletion expense increased approximately $4.7 million primarily due to the completion of new wells in 2007.

 

 

Selling, general and administrative expense increased primarily as a result of compensation expense related to transfers of certain administrative staff from our drilling segment to our corporate segment as well as increases in stock-based compensation expense. Other operating expenses decreased due to a decrease in bad debt expense of $2.9 million. In 2007, we sold certain oil and natural gas properties resulting in a gain of $21.6 million This gain was reduced by approximately $5.1 million in losses associated with the disposal of other assets. Gains and losses on the disposal of assets are considered as part of our corporate activities due to the fact that such transactions relate to decisions of the executive management group regarding corporate strategy. Embezzlement costs (recoveries) in 2007 includes an expected recovery of $44.5 million reduced by professional fees incurred as a result of the embezzlement. Embezzlement costs (recoveries) in 2006 include professional fees incurred as a result of the embezzlement reduced by insurance proceeds of $2.3 million.

 

 

 

Our average number of rigs operating increased to 296 in 2006 from 276 in 2005. The average market price of natural gas for each of the fiscal quarters and full years in 2006 and 2005 follow:

 

 

 

 

Revenues and direct operating costs increased as a result of the increased number of operating days, as well as an increase in the average revenue and average direct operating cost per operating day. Operating days and average rigs operating increased as a result of increased demand for our contract drilling services and the increase in the number of marketable rigs in our fleet due to our rig activation program. Average revenue per operating day increased as a result of increased demand and pricing for our drilling services. Average direct operating costs per operating day increased primarily as a result of increased compensation costs and an increase in the cost of maintenance for our rigs. Significant capital expenditures were incurred to activate additional 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. The increase in depreciation expense was a result of the capital expenditures and acquisitions.

 

 

Revenues and direct operating costs increased as a result of the increased number of jobs, as well as an increase in the average revenue and average direct operating cost per job. The increase in jobs was attributable to increased demand for our services and increased operating capacity which has been added. Increased average revenue per job was due to increased pricing for our services and an increase in the number of larger jobs. Average direct operating costs per job increased as a result of increases in compensation and the cost of materials used in our operations, as well as an increase in the number of larger jobs. Selling, general and administrative expense increased as a result of additional expenses to support the expanded operations of the pressure pumping segment. Significant capital expenditures were incurred to add capacity and modify and upgrade existing equipment. The increase in depreciation expense was a result of the capital expenditures discussed above.

 

Revenues and direct operating costs increased primarily as a result of an increase in large jobs offshore in the Gulf of Mexico during 2006.

 

 

Direct operating costs increased primarily due to $4.2 million in costs associated with the abandonment of exploratory wells. Depreciation, depletion and impairment expense includes $5.0 million and $4.4 million incurred during 2006 and 2005, respectively, to reflect the impairment of certain oil and natural gas properties. Average net daily oil production increased due to the completion of new wells in 2006. Average net daily natural gas production decreased as a result of production declines and the sale of certain natural gas properties.

 

 

Selling, general and administrative expense increased primarily as a result of an increase of $7.8 million in stock-based compensation expense which was impacted by the adoption of a new accounting standard in 2006 requiring the expensing of stock options. Other operating expenses include bad debt expense of $5.4 million and $1.2 million in 2006 and 2005, respectively. Embezzlement costs in 2005 includes payments made to or for the benefit of Jonathan D. Nelson, our former CFO, for assets and services that were not received by the Company and in 2006 includes continuing professional fees incurred as a result of the embezzlement, net of insurance proceeds of $2.3 million received in connection with the loss. Interest expense in 2006 increased due to borrowings under our line of credit during 2006.

 

 

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 the Domestic Production Activities Deduction. The deduction was enacted as part of the American Jobs Creation Act of 2004 effective for taxable years after December 31, 2004. The act allows a deduction of 3% in 2005 and 2006, 6% in 2007, 2008 and 2009, and 9% in 2010 and after on the lesser of qualified production activities income or taxable income.

 

For tax purposes, we have Federal net operating loss carryforwards of approximately $374,000 available at December 31, 2007. We have alternative minimum tax credit carryforwards of approximately $118,000 available at December 31, 2007. The net operating loss carryforwards, if unused, are scheduled to expire in 2019. The alternative minimum tax credit may be carried forward indefinitely.

 

We record deferred Federal income taxes based primarily on the relationship between the amount of our unused Federal net operating loss carryforwards and the temporary differences between the book basis and tax basis in 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 incurred a deferred tax expense of approximately $38.3 million in 2007, a deferred tax benefit of approximately $4.1 million in 2006 and a deferred tax expense of approximately $17.1 million in 2005.

 

 

Our revenue, profitability, 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 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 2006, the average market price of natural gas retreated from record highs that were set in 2005. The price dropped from an average of $8.98 per Mcf in 2005 to an average of $6.94 per Mcf in 2006 and an average of $7.18 per Mcf in 2007. This resulted in our customers moderating their increase in drilling activities in 2007. This moderation combined with the reactivation and construction of new land drilling rigs in the United States has resulted in excess capacity compared to recent demand. Additionally, drilling activity in Canada has slowed significantly. As a result of these factors, our average rigs operating declined to 244 in 2007 compared to 296 in 2006. 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. A significant decrease in market prices for natural gas could result in a material decrease in demand for drilling rigs and adversely affect our operating results.

 

The North American land drilling industry has experienced many downturns 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 during the downturn periods.

 

 

Inflation has not had a significant impact on our operations during the three years in the period ended December 31, 2007. We believe that inflation will not have a significant near-term impact on our financial position.

 

 

In September 2006, the FASB issued Statement No. 157,Fair Value Measurements (“FAS 157”). FAS 157 defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and

expands disclosures about fair value measurement. FAS 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007 and interim periods within those fiscal years. FAS 157 will be effective for us beginning in the quarter ending March 31, 2008. The application of FAS 157 is not expected to have a material impact to us.

 

In February 2007, the FASB issued Statement No. 159, The Fair Value Option for Financial Assets and Financial Liabilities Including an Amendment of FASB Statement No. 115(“FAS 159”). FAS 159 permits entities to choose to measure many financial instruments and certain other items at fair value. FAS 159 is effective as of the beginning of an entity’s first fiscal year that begins after November 15, 2007 and will be effective for us beginning in the quarter ending March 31, 2008. The application of FAS 159 is not expected to have a material impact to us.

 

In December 2007, the FASB issued Statement No. 141(R),Business Combinations (“FAS 141(R)”) and Statement No. 160, Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51 (“FAS 160”). FAS 141(R) is a revision of Statement No. 141, Business Combinations, and calls for significant changes from current practice in accounting for business combinations. FAS 141(R) is effective for business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. FAS 160 amends ARB 51 to establish accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. FAS 160 is effective for fiscal years beginning on or after December 15, 2008. Both FAS 141(R) and FAS 160 will be effective for us beginning the quarter ending March 31, 2009. The application of FAS 141(R) and FAS 160 are not expected to have a material impact to us.

 

 

We currently have exposure to interest rate market risk associated with borrowings under our credit facility. The revolving credit facility calls for periodic interest payments at a floating rate ranging from LIBOR plus 0.625% to 1.0% or at the prime rate. The applicable rate above LIBOR is based upon our debt to capitalization ratio. A 1% increase (100 basis points) in LIBOR and the prime rate would result in additional annual interest expense of approximately $500,000 based upon the level of borrowings we had outstanding at December 31, 2007.

 

We conduct some 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.

 

 

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

 

 

None.

 

 

 

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 inRules 13a-15(e)and15d-15(e)promulgated under the Securities and Exchange Act of 1934, as amended (the Exchange Act), as of the end of the period covered by this Annual Report onForm 10-K.Based on this evaluation, our CEO and CFO concluded that, as of December 31, 2007, 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.

 

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Exchange ActRule 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, 2007, based on theInternal 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, 2007.

 

The effectiveness of our internal control over financial reporting as of December 31, 2007 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears onpage F-2of this Report and is incorporated by reference into Item 8 of this Annual Report onForm 10-K.

 

 

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.

 

The information required by Part III is omitted from this Report because we will file a definitive 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.

 

 

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.

 

 

(a)(1) Financial Statements

 

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

 

(a)(2) Financial Statement Schedule

 

Schedule II — Valuation and qualifying accounts is filed herewith onpage 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.