ITEM 1A. RISK FACTORS
The nature of the business activities conducted by the Company subjects it to certain hazards and risks. The following is a summary of some of the material risks relating to the Company's business activities. Other risks are described in "Item 1. Business - Competition, Markets and Regulations" and "Item 7A. Quantitative and Qualitative Disclosures About Market Risk". These risks are not the only risks facing the Company. The Company's business could also be impacted by additional risks and uncertainties not currently known to the Company or that it currently deems to be immaterial. If any of these risks actually occur, they could materially harm the Company's business, financial condition or results of operations and impair Pioneer's ability to implement business plans or complete development projects as scheduled. In that case, the market price of the Company's common stock could decline.
The prices of oil, NGL and gas are at historically high levels and are highly volatile. A sustained decline in these commodity prices could adversely affect the Company's financial condition and results of operations.
The Company's revenues, profitability, cash flow and future rate of growth are highly dependent on commodity prices. Oil prices have recently been at historically high levels and gas prices have been at high levels over the past several years when compared to prior periods. Commodity prices may fluctuate widely in response to relatively minor changes in the supply of and demand for oil and gas, market uncertainty and a variety of additional factors that are beyond our control, such as:
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domestic and worldwide supply of and demand for oil, NGL and gas;
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weather conditions;
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overall domestic and global political and economic conditions, including those in the Middle East, Africa and South America;
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actions of OPEC and other state-controlled oil companies relating to oil price and production controls;
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the impact of increasing LNG deliveries to the United States;
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technological advances affecting energy consumption and energy supply;
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domestic and foreign governmental regulations and taxation;
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the impact of energy conservation efforts;
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the proximity, capacity, cost and availability of pipelines and other transportation facilities; and
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the price and availability of alternative fuels.
In the past, commodity prices have been extremely volatile, and the Company expects this volatility to continue. A significant downward trend in commodity prices would have a material adverse effect on the Company's revenues, profitability and cash flow. The Company makes price assumptions that are used for planning purposes, and a significant portion of the Company's cash outlays, including rent, salaries and noncancellable capital commitments, are largely fixed in nature. Accordingly, if commodity prices are below expectations, the Company's financial results are likely to be adversely and disproportionately affected because these cash outlays are not variable in the short term and cannot be quickly reduced to respond to unanticipated decreases in commodity prices.
The Company's hedging activities could result in financial losses.
To reduce exposure to fluctuations in commodity prices, the Company has entered into, and expects in the future to enter into, hedging arrangements for a portion of its oil and gas production. These hedging arrangements may expose the Company to risk of financial loss in certain circumstances, including when:
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production is less than the hedged volumes;
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the counterparty to the hedging contract defaults on their contract obligations; or
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the hedging arrangements limit the benefit the Company would otherwise receive from increases in commodity prices.
Exploration and development drilling may not result in commercially productive reserves.
Drilling involves numerous risks, including the risk that no commercially productive oil or gas reservoirs will be encountered. The cost of drilling, completing and operating wells is often uncertain and drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including:
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unexpected drilling conditions;
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pressure or irregularities in formations;
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equipment failures or accidents;
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adverse weather conditions;
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restricted access to land for drilling or laying pipelines; and
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costs of, or shortages or delays in the delivery of, drilling rigs and equipment.
The Company's future drilling activities may not be successful and, if unsuccessful, such failure could have an adverse effect on the Company's future results of operations and financial condition. While all drilling, whether developmental, extension or exploratory, involves these risks, exploratory and extension drilling involves greater risks of dry holes or failure to find commercial quantities of hydrocarbons. The Company expects that it will continue to experience exploration and abandonment expense in 2008. Increased levels of drilling activity in the oil and gas industry in recent periods have led to increased costs of some drilling equipment, materials and supplies. If these trends continue in the future, they may impact the Company's profitability, cash flow and ability to complete development projects as scheduled.
Future price declines could result in a reduction in the carrying value of the Company's proved oil and gas properties, which could adversely affect the Company's results of operations.
Declines in commodity prices may result in the Company having to make substantial downward adjustments to the Company's estimated proved reserves. If this occurs, or if the Company's estimates of production or economic factors change, accounting rules may require the Company to write-down, as a noncash charge to earnings, the carrying value of the Company's oil and gas properties for impairments. The Company is required to perform impairment tests on proved assets whenever events or changes in circumstances warrant a review of the Company's proved oil and gas properties. To the extent such tests indicate a reduction of the estimated useful life or estimated future cash flows of the Company's oil and gas properties, the carrying value may not be recoverable and therefore require a write-down. The Company may incur impairment charges in the future, which could materially affect the Company's results of operations in the period incurred.
The Company periodically evaluates its unproved oil and gas properties, and could be required to recognize noncash charges in the earnings of future periods.
At December 31, 2007, the Company carried unproved property costs of $277.5 million. GAAP requires periodic evaluation of these costs on a project-by-project basis in comparison to their estimated fair value. These evaluations will be affected by the results of exploration activities, commodity price outlooks, planned future sales or expiration of all or a portion of the leases, contracts and permits appurtenant to such projects. If the quantity of potential reserves determined by such evaluations is not sufficient to fully recover the cost invested in each project, the Company will recognize noncash charges in the earnings of future periods.
The Company may be unable to make attractive acquisitions, and any acquisition it completes is subject to substantial risks that could impact its business.
Acquisitions of producing oil and gas properties have been an important element of the Company's growth. The Company's growth following the full development of its existing property base could be impeded if it is unable to acquire additional oil and gas reserves on a profitable basis. Acquisition opportunities in the oil and gas industry are very competitive, which can increase the cost of, or cause the Company to refrain from, completing acquisitions. In addition, higher recent commodity prices have increased the cost of properties available for acquisition. The success of any acquisition will depend on a number of factors and involve potential risks, including among other things:
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the ability to estimate accurately the costs to develop the reserves, the recoverable volumes of reserves, rates of future production and future net cash flows attainable from the reserves;
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the assumption of unknown liabilities, losses or costs for which the Company is not indemnified or for which the indemnity the Company receives is inadequate;
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the validity of assumptions about costs, including synergies;
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the impact on the Company's liquidity or financial leverage of using available cash or debt to finance acquisitions;
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the diversion of management's attention from other business concerns; and
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an inability to hire, train or retain qualified personnel to manage and operate the Company's growing business and assets.
All of these factors affect whether an acquisition will ultimately generate cash flows sufficient to provide a suitable return on investment. Even though the Company performs a review of the properties it seeks to acquire that it believes is consistent with industry practices, such reviews are often limited in scope. As a result, among other risks, the Company's initial estimates of reserves may be subject to revision following an acquisition, which may materially and adversely impact the desired benefits of the acquisition.
The Company may be unable to dispose of nonstrategic assets on attractive terms, and may be required to retain liabilities for certain matters.
The Company regularly reviews its property base for the purpose of identifying nonstrategic assets, the disposition of which would increase capital resources available for other activities and create organizational and operational efficiencies. Various factors could materially affect the ability of the Company to dispose of nonstrategic assets, including the availability of purchasers willing to purchase the nonstrategic assets at prices acceptable to the Company. Sellers typically retain certain liabilities or indemnify buyers for certain matters. The magnitude of any such retained liability or indemnification obligation may be difficult to quantify at the time of the transaction and ultimately may be material. Also, as is typical in divestiture transactions, third parties may be unwilling to release the Company from guarantees or other credit support provided prior to the sale of the divested assets. As a result, after a sale the Company may remain secondarily liable for the obligations guaranteed or supported to the extent that the buyer of the assets fails to perform these obligations.
The Company periodically evaluates its goodwill for impairment, and could be required to recognize noncash charges in the earnings of future periods.
At December 31, 2007, the Company carried goodwill of $310.9 million associated with its United States reporting unit. Goodwill is tested for impairment at least annually, requiring an estimate of the fair values of the Company's assets and liabilities. If the fair value of the Company's net assets is not sufficient to fully support the goodwill balance, the Company will reduce the carrying value of goodwill for the impaired value, with a corresponding noncash charge to earnings in the period in which goodwill is determined to be impaired.
The Company's gas processing operations are subject to operational risks, which could result in significant damages and the loss of revenue.
As of December 31, 2007, the Company owned interests in four gas processing plants and ten treating facilities. The Company operates two of the gas processing plants and all ten treating facilities. There are significant risks associated with the operation of gas processing plants. Gas and NGLs are volatile and explosive and may include carcinogens. Damage to or misoperation of a gas processing plant or facility could result in an explosion or the discharge of toxic gases, which could result in significant damage claims in addition to interrupting a revenue source.
The Company's operations involve many operational risks, some of which could result in substantial losses to the Company and unforeseen interruptions to the Company's operations for which the Company may not be adequately insured.
The Company's operations are subject to all the risks normally incident to the oil and gas exploration and production business, including:
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blowouts, cratering, explosions and fires;
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adverse weather effects;
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environmental hazards, such as gas leaks, oil spills, pipeline ruptures and discharges of toxic gases;
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high costs, shortages or delivery delays of equipment, labor or other services;
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facility or equipment malfunctions, failures or accidents;
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title problems;
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pipe or cement failures or casing collapses;
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compliance with environmental and other governmental requirements;
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lost or damaged oilfield workover and service tools;
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unusual or unexpected geological formations or pressure or irregularities in formations; and
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natural disasters.
Any of these risks could result in substantial losses to the Company due to injury or loss of life, damage to or destruction of wells, production facilities or other property, clean-up responsibilities, regulatory investigations and penalties and suspension of operations.
Although the Company currently maintains insurance coverage that it considers reasonable and that is similar to that maintained by comparable companies in the oil and gas industry, it is not fully insured against certain of the risks described above, either because such insurance is not available or because of the high premium costs and deductibles associated with obtaining such insurance. Additionally, the Company relies to a large extent on facilities owned and operated by third-parties, and damage to or destruction of those third-party facilities could affect the ability of the Company to produce, transport and sell its hydrocarbons.
The Company may not be able to obtain access to pipelines, gas gathering, transmission and processing facilities to market its oil and gas production.
The marketing of oil and gas production depends in large part on the availability, proximity and capacity of pipelines, gas gathering systems and other transportation, processing and refining facilities, as well as the existence of adequate markets. If there were insufficient capacity available on these systems, or if these systems were unavailable to the Company, the price offered for the Company's production could be significantly depressed, or the Company could be forced to shut-in some production or delay or discontinue drilling plans and commercial production following a discovery of hydrocarbons while it constructs its own facility. The Company also relies (and expects to rely in the future) on facilities developed and owned by third parties in order to process, transmit and sell its oil and gas production. The Company's plans to develop and sell its oil and gas reserves could be materially and adversely affected by the inability or unwillingness of third parties to provide sufficient transmission or processing facilities to the Company.
The nature of the Company's assets exposes it to significant costs and liabilities with respect to environmental and operational safety matters.
The oil and gas business is subject to environmental hazards, such as oil spills, produced water spills, gas leaks and ruptures and discharges of substances or gases that could expose the Company to substantial liability due to pollution and other environmental damage. A variety of United States federal, state and local, as well as foreign laws and regulations govern the environmental aspects of the oil and gas business. Noncompliance with these laws and regulations may subject the Company to administrative, civil or criminal penalties, remedial cleanups, and natural resource damages or other liabilities, and compliance with these laws and regulations may increase the cost of the Company's operations. Such laws and regulations may also affect the costs of acquisitions. See "Item 1. Business - Competition, Markets and Regulations - Environmental matters and regulations" above for additional discussion related to environmental risks.
The Company does not believe that its environmental risks are materially different from those of comparable companies in the oil and gas industry. Nevertheless, no assurance can be given that existing or future environmental
laws will not result in a curtailment of production or processing activities, result in a material increase in the costs of production, development, exploration or processing operations or adversely affect the Company's future operations and financial condition. Pollution and similar environmental risks generally are not fully insurable.
The Company's credit facility and debt instruments have substantial restrictions and financial covenants that may restrict its business and financing activities.
The Company is a borrower under fixed rate senior notes, senior convertible notes and a credit facility. The terms of the Company's borrowings under the senior notes, senior convertible notes and the credit facility specify scheduled debt repayments and require the Company to comply with certain associated covenants and restrictions. The Company's ability to comply with the debt repayment terms, associated covenants and restrictions is dependent on, among other things, factors outside the Company's direct control, such as commodity prices and interest rates. See Note F of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for information regarding the Company's outstanding debt as of December 31, 2007 and the terms associated therewith.
The Company's ability to obtain additional financing is also impacted by the Company's debt credit ratings and competition for available debt financing. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" for a discussion of the Company's debt credit ratings.
The Company faces significant competition and many of its competitors have resources in excess of the Company's available resources.
The oil and gas industry is highly competitive. The Company competes with a large number of companies, producers and operators in a number of areas such as:
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seeking to acquire oil and gas properties suitable for development or exploration;
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marketing oil, NGL and gas production; and
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seeking to acquire the equipment and expertise, including trained personnel, necessary to operate and develop properties.
Many of the Company's competitors are larger and have substantially greater financial and other resources than the Company. See "Item 1. Business - Competition, Markets and Regulations" above for additional discussion regarding competition.
The Company's business depends to a significant extent upon the continued service and performance of key senior managers and technical personnel.
The Company's business depends to a significant extent upon the continued service and performance of a relatively small number of key senior managers and technical personnel. The loss of any existing key personnel, or the inability to attract, motivate and retain additional key personnel, could harm the Company's business, financial condition and results of operations.
The Company is subject to regulations that may cause it to incur substantial costs.
The Company's business is regulated by a variety of federal, state, local and foreign laws and regulations. There can be no assurance that present or future regulations will not adversely affect the Company's business and operations. See "Item 1. Business - Competition, Markets and Regulations" above for additional discussion regarding government regulation.
The Company's international operations may be adversely affected by economic, political and other factors.
At December 31, 2007, approximately three percent of the Company's proved reserves were located outside the United States. The success and profitability of international operations may be adversely affected by risks associated with international activities, including:
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economic and labor conditions;
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war, terrorist acts and civil disturbances;
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political instability;
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loss of revenue, property and equipment as a result of actions taken by foreign countries where the Company has operations, such as expropriation or nationalization of assets and renegotiation, modification or nullification of existing contracts;
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changes in taxation policies (including host-country import-export, excise and income taxes and United States taxes on foreign subsidiaries);
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laws and policies of the United States and foreign jurisdictions affecting foreign investment, trade and business conduct; and
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changes in the value of the U.S. dollar versus the local currencies in which oil and gas producing activities may be denominated.
In some cases, the market for the Company's production in foreign countries is limited to some extent. For example, all of the Company's gas and condensate production from the South Coast Gas project in South Africa is currently committed by contract to a single, government-affiliated gas-to-liquids facility. If such facility ceased to purchase the gas because of an unforeseen event excusing performance, it might be difficult to find an alternative market for the production, and if such a market were secured, the price received by the Company might be less than that provided under its current gas sales contract. See "Critical Accounting Estimates" included in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations", "Qualitative Disclosures - Foreign currency, operations and price risk" in "Item 7A. Quantitative and Qualitative Disclosures About Market Risk" and Note B of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for information regarding other risks associated with the Company's international operations.
Estimates of proved reserves and future net cash flows are not precise. The actual quantities and net cash flows of the Company's proved reserves may prove to be lower than estimated.
Numerous uncertainties exist in estimating quantities of proved reserves and future net cash flows therefrom. The estimates of proved reserves and related future net cash flows set forth in this Report are based on various assumptions, which may ultimately prove to be inaccurate.
Petroleum engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact manner. Estimates of economically recoverable oil and gas reserves and of future net cash flows depend upon a number of variable factors and assumptions, including the following:
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historical production from the area compared with production from other producing areas;
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the quality and quantity of available data;
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the interpretation of that data;
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the assumed effects of regulations by governmental agencies;
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assumptions concerning future commodity prices; and
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assumptions concerning future operating costs, severance, ad valorem and excise taxes, development costs and workover and remedial costs.
Because all reserve estimates are to some degree subjective, each of the following items may differ materially from those assumed in estimating reserves:
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the quantities of oil and gas that are ultimately recovered;
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the production and operating costs incurred;
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the amount and timing of future development expenditures; and
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future commodity prices.
Furthermore, different reserve engineers may make different estimates of reserves and cash flows based on the same available data. The Company's actual production, revenues and expenditures with respect to reserves will likely be different from estimates and the differences may be material.
As required by the SEC, the estimated discounted future net cash flows from proved reserves are based on prices and costs as of the date of the estimate, while actual future prices and costs may be materially higher or lower. Actual future net cash flows also will be affected by factors such as:
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the amount and timing of actual production;
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levels of future capital spending;
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increases or decreases in the supply of or demand for oil and gas; and
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changes in governmental regulations or taxation.
The Company reports all proved reserves held under production sharing arrangements and concessions utilizing the "economic interest" method, which excludes the host country's share of proved reserves. Estimated quantities of production sharing arrangements reported under the "economic interest" method are subject to fluctuations in commodity prices and recoverable operating expenses and capital costs. If costs remain stable, reserve quantities attributable to recovery of costs will change inversely to changes in commodity prices.
Standardized Measure is a reporting convention that provides a common basis for comparing oil and gas companies subject to the rules and regulations of the SEC. It requires the use of commodity prices, as well as operating and development costs, prevailing as of the date of computation. Consequently, it may not reflect the prices ordinarily received or that will be received for oil and gas production because of seasonal price fluctuations or other varying market conditions, nor may it reflect the actual costs that will be required to produce or develop the oil and gas properties. Accordingly, estimates included herein of future net cash flows may be materially different from the future net cash flows that are ultimately received. In addition, the ten percent discount factor, which is required by the SEC to be used in calculating discounted future net cash flows for reporting purposes, may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with the Company or the oil and gas industry in general. Therefore, the estimates of discounted future net cash flows or Standardized Measure in this Report should not be construed as accurate estimates of the current market value of the Company's proved reserves.
The Company's actual production could differ materially from its forecasts.
From time to time the Company provides forecasts of expected quantities of future oil and gas production. These forecasts are based on a number of estimates, including expectations of production decline rates from existing wells and the outcome of future drilling activity. Should these estimates prove inaccurate, actual production could be adversely impacted. Downturns in commodity prices could make certain drilling activities or production uneconomical, which would also adversely impact production.
The Company may be unable to complete its plans to repurchase its common stock.
The Board of Directors (the "Board") approves share repurchase programs and sets limits on the price per share at which Pioneer's common stock can be repurchased. From time to time, the Company may not be permitted to repurchase its stock during certain periods because of scheduled and unscheduled trading blackouts. Additionally, business conditions and availability of capital may dictate that repurchases be suspended or canceled. As a result, there can be no assurance that additional repurchase programs will be commenced and, if so, that they will be completed.
The Company may be unable to complete its plans to form a master limited partnership in the time expected, or at all, and the structure and terms of any master limited partnership could change materially from those anticipated.
In April, 2007, the Company announced an intention to form two new master limited partnerships, which would own interests in long-lived, low-decline oil and gas assets. Although the Company's subsidiary, Pioneer Southwest Energy Partners L.P. ("Pioneer Southwest"), has filed a preliminary registration statement (subject to completion) with the SEC for an initial public offering of limited partner interests, the Company announced in February 2008 that the offering had been postponed due to market conditions. In addition to market conditions, the completion of the Company's plans to form the master limited partnerships is subject to numerous other risks beyond the control of the Company, and therefore it is possible that one or both of the master limited partnerships will not be formed, will not complete an offering of securities, will not raise the planned amount of capital even if an offering of securities is completed, and will not be able to complete its proposed actions. Furthermore, the structure, nature, purpose, proposed assets and liabilities, and proposed manner of offering of the master limited partnerships may change materially from those anticipated. In addition, the Company's retained investment in any master limited partnership formed would be subject to the risks normally attendant to businesses in the oil and gas exploration and production industry, including most of the same risks to which the Company is subject. The Company's announcement of its plan with respect to Pioneer Southwest's initial public offering did not, and this report does not, constitute an offer to sell or the solicitation of an offer to buy any securities. Any offers, solicitations of offers to buy, or any sales of securities of either master limited partnership will be made only in accordance with the registration requirements of the Securities Act of 1933 or an exemption therefrom. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" and Note W of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for discussions of Pioneer Southwest's proposed initial public offering.
ITEM 1B.
ITEM 1B.
UNRESOLVED STAFF COMMENTS
None.
The information included in this Report about the Company's proved reserves as of December 31, 2007, 2006 and 2005, which were located in the United States, Argentina, Canada, South Africa and Tunisia, were based on evaluations prepared by the Company's engineers and audited by Netherland, Sewell & Associates, Inc. ("NSAI") with respect to the Company's major properties and prepared by the Company's engineers with respect to all other properties. The reserve audits performed by NSAI in aggregate represented 86 percent, 89 percent and 82 percent of the Company's 2007, 2006 and 2005 proved reserves, respectively; and, 80 percent, 83 percent and 76 percent of the Company's 2007, 2006 and 2005 associated pre-tax present value of proved reserves discounted at ten percent, respectively.
NSAI follows the general principles set forth in the standards pertaining to the estimating and auditing of oil and gas reserve information promulgated by the Society of Petroleum Engineers ("SPE"). A reserve audit as defined by the SPE is not the same as a financial audit. The SPE's definition of a reserve audit includes the following concepts:
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A reserve audit is an examination of reserve information that is conducted for the purpose of expressing an opinion as to whether such reserve information, in the aggregate, is reasonable and has been presented in conformity with generally accepted petroleum engineering and evaluation principles.
•
The estimation of proved reserves is an imprecise science due to the many unknown geologic and reservoir factors that cannot be estimated through sampling techniques. Since reserves are only estimates, they cannot be audited for the purpose of verifying exactness. Instead, reserve information is audited for the purpose of reviewing in sufficient detail the policies, procedures and methods used by a company in estimating its reserves so that the reserve auditors may express an opinion as to whether, in the aggregate, the reserve information furnished by a company is reasonable.
•
The methods and procedures used by a company, and the reserve information furnished by a company, must be reviewed in sufficient detail to permit the reserve auditor, in its professional judgment, to express an opinion as to the reasonableness of the reserve information. The auditing procedures require the reserve auditor to prepare its own estimates of reserve information for the audited properties.
To further clarify, in conjunction with the audit of the Company's proved reserves and associated pre-tax present value discounted at ten percent, Pioneer provided to NSAI its external and internal engineering and geoscience technical data and analyses. Following NSAI's review of that data, it had the option of honoring Pioneer's interpretation, or making its own interpretation. No data was withheld from NSAI. NSAI accepted without independent verification the accuracy and completeness of the historical information and data furnished by Pioneer with respect to ownership interest; oil and gas production; well test data; commodity prices; operating and development costs; and any agreements relating to current and future operations of the properties and sales of production. However, if in the course of its evaluation something came to its attention that brought into question the validity or sufficiency of any such information or data, NSAI did not rely on such information or data until it had satisfactorily resolved its questions relating thereto or had independently verified such information or data.
In the course of its evaluations, NSAI prepared, for all of the audited properties, its own estimates of the Company's proved reserves and the pre-tax present value of such reserves discounted at ten percent. NSAI reviewed its audit differences with the Company, and, in a number of cases, held joint meetings with the Company to review additional reserves work performed by the technical teams and any updated performance data related to the reserve differences. Such data was incorporated, as appropriate, by both parties into the reserve estimates. NSAI's estimates, including any adjustments resulting from additional data, of those proved reserves and the pre-tax present value of such reserves discounted at ten percent did not differ from Pioneer's estimates by more than ten percent in the aggregate. However, when compared on a lease-by-lease, field-by-field or area-by-area basis, some of the Company's estimates were greater than those of NSAI and some were less than the estimates of NSAI. When such differences do not exceed ten percent in the aggregate and NSAI is satisfied that the proved reserves and pre-tax present value of such reserves discounted at ten percent are reasonable and that its audit objectives have been met, NSAI will issue an unqualified audit opinion. Remaining differences are not resolved due to the limited cost benefit of continuing such analyses by the Company and NSAI. At the conclusion of the audit process, it was NSAI's opinion, as set forth in its audit letter, that Pioneer's estimates of the Company's proved oil and gas reserves and
associated pre-tax future net revenues discounted at ten percent are, in the aggregate, reasonable and have been prepared in accordance with petroleum engineering and evaluation principles.
The Company did not provide estimates of total proved oil and gas reserves during 2007, 2006 or 2005 to any federal authority or agency, other than the SEC. The Company's reserve estimates do not include any probable or possible reserves. Also, see "Item 1A. Risk Factors" and "Critical Accounting Estimates" in "Item 7. Management's Discussion and Analysis and Results of Operations" for additional discussions regarding proved reserves and their related cash flows.
Proved Reserves
The Company's proved reserves totaled 963.8 MMBOE, 904.9 MMBOE and 986.7 MMBOE at December 31, 2007, 2006 and 2005, respectively, representing $9.0 billion, $4.7 billion and $7.3 billion, respectively, of Standardized Measure. The Company's proved reserves include field fuel, which is gas consumed to operate field equipment (primarily compressors) prior to the gas being delivered to a sales point. The following table shows the changes in the Company's proved reserve volumes by geographic area during the year ended December 31, 2007 (in MBOE):
Production. Production volumes include 2,891 MBOE of field fuel and 2,950 MBOE of production associated with divested assets being presented as discontinued operations.
Extensions and discoveries. Extensions and discoveries are primarily the result of extension drilling in the Raton field and Spraberry field in the United States and the Horseshoe Canyon field in Canada and lower-risk exploratory drilling in the Company's South Texas Edwards Trend and Tunisian resource plays.
Purchases of minerals-in-place. Purchases of minerals-in-place are primarily attributable to bolt-on acquisitions in the Company's Spraberry oil field, Raton gas field and the entry into the Barnett Shale gas field.
Sales of minerals-in-place. Sales of minerals-in-place are principally related to the Company's divestiture of its Canadian assets and the Tunisian government's election to participate in 50 percent of the Company's discoveries in the Cherouq concession in the Jenein Nord permit. See Note N of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data."
Revisions of previous estimates. Revisions of previous estimates are comprised of 20 MMBOE of positive price revisions offset by 2 MMBOE of negative technical revisions. The Company's proved reserves at December 31, 2007 were determined using year-end NYMEX equivalent prices of $95.92 per barrel of oil and $6.80 per Mcf of gas, compared to $60.82 per barrel of oil and $5.64 per Mcf of gas at December 31, 2006.
On a BOE basis, 62 percent of the Company's total proved reserves at December 31, 2007 were proved developed reserves. Based on reserve information as of December 31, 2007, and using the Company's production information for the year then ended, excluding production associated with divested assets included in discontinued operations, the reserve-to-production ratio associated with the Company's proved reserves was in excess of 20 years on a BOE basis. The following table provides information regarding the Company's proved reserves and average daily sales volumes by geographic area as of and for the year ended December 31, 2007:
___________
(a)
The gas reserves contain 290,599 MMcf of gas that will be produced and utilized as field fuel.
(b)
The 2007 average daily sales volumes are from continuing operations and (i) do not include the field fuel produced, which averaged 47,526 Mcf per day, and (ii) were calculated using a 365-day year and without making pro forma adjustments for any acquisitions, divestitures or drilling activity that occurred during the year.
The following table represents the estimated timing and cash flows of developing the Company's proved undeveloped reserves as of December 31, 2007 (dollars in thousands):
___________
(a)
Beginning in 2009 and thereafter, the production and cash flows represent the drilling results from the respective year plus the incremental effects of proved undeveloped drilling since 2008.
Description of Properties
United States
Approximately 89 percent of the Company's proved reserves at December 31, 2007 are located in the Spraberry field in the Permian Basin area, the Hugoton and West Panhandle fields in the Mid-Continent area and the Raton field in the Rocky Mountains area. These fields generate substantial operating cash flow and the Spraberry and Raton fields have a large portfolio of low-risk drilling opportunities. The cash flows generated from these fields provide funding for the Company's other development and exploration activities both domestically and internationally.
The following tables summarize the Company's United States development and exploration/extension drilling activities during 2007:
___________
(a)
Includes $22.0 million of capitalized interest related to the Oooguruk project.
Spraberry field. The Spraberry field was discovered in 1949 and encompasses eight counties in West Texas. The field is approximately 150 miles long and 75 miles wide at its widest point. The oil produced is West Texas Intermediate Sweet, and the gas produced is casinghead gas with an average energy content of 1,400 Btu. The oil and gas are produced primarily from three formations, the upper and lower Spraberry and the Dean, at depths ranging from 6,700 feet to 9,200 feet. In addition, the Company has started completing the majority of its wells in the Wolfcamp formation at depths ranging from 9,300 feet to 10,300 feet with successful results. The Company believes the Spraberry field offers excellent opportunities to enhance oil and gas production because of the numerous undeveloped drilling locations, many of which are reflected in the Company's proved undeveloped reserves, and the ability to contain operating expenses and drilling costs through economies of scale.
During July 2007, the Company entered into an agreement under which the Company has the option to purchase an additional 22 percent interest in the Spraberry Midkiff-Benedum gas processing system for $230 million, subject to normal closing adjustments. The additional 22 percent can be purchased in 2008 and 2009 and, if exercised, will increase the Company's interest in the system to 49 percent. In conjunction with this transaction, the Company extended its percent of proceeds ("POP") contract with the plant to 2022 and negotiated incremental increases in the Company's POP beginning in 2009.
In December 2007, the Company acquired approximately 44,000 gross acres in the Spraberry field for $89.4 million, with Pioneer being operator of the acquired properties. Proved reserves associated with the acquisition are approximately 15 MMBOE. The Company estimates that the acquisition provides more than 600 potential drilling locations utilizing 40-acre spacing.
During 2007, the Company (a) drilled 350 wells, an increase of over 17 percent compared to 2006, (b) acquired approximately 185,000 gross acres, bringing its total acreage position to approximately 869,000 gross acres (688,000 net acres), (c) completed several bolt-on property acquisitions and joint ventures and (d) successfully drilled a majority of the wells to the Wolfcamp formation. The Company plans to drill approximately 350 wells in 2008 and continue to pursue acreage expansions and bolt-on acquisitions.
Hugoton field. The Hugoton field in southwest Kansas is one of the largest producing gas fields in the continental United States. The gas is produced from the Chase and Council Grove formations at depths ranging from 2,700 feet to 3,000 feet. The Company's gas in the Hugoton field has an average energy content of 1,025 Btu. The Company's Hugoton properties are located on approximately 285,000 gross acres (247,000 net acres), covering approximately 400 square miles. The Company has working interests in approximately 1,200 wells in the Hugoton field, approximately 990 of which it operates, and partial royalty interests in approximately 500 wells. The Company owns substantially all of the gathering and processing facilities, primarily the Satanta plant, which service its production from the Hugoton field. Such ownership allows the Company to control the production, gathering, processing and sale of its gas and NGL production.
The Company's Hugoton operated wells are capable of producing approximately 65 MMcf of wet gas per day (i.e., gas production at the wellhead before processing or field fuel use and before reduction for royalties). Pioneer successfully led a cooperative effort with other operators in this field to effect rule changes which will enable further field development in future years. As part of the rule changes, the state-regulated production allowables were canceled as of December 31, 2007, and the Company received regulatory approval to commingle production from the Panoma and Council Grove formations. A commingling pilot program has been initiated and the Company is monitoring its production performance. To capitalize on these rule changes, future completion designs are being developed and continued optimization is planned for the existing field compression system.
West Panhandle field. The West Panhandle properties are located in the panhandle region of Texas. These stable, long-lived reserves are attributable to the Red Cave, Brown Dolomite, Granite Wash and fractured Granite formations at depths no greater than 3,500 feet. The Company's gas in the West Panhandle field has an average energy content of 1,365 Btuand is produced from approximately 675 wells on more than 250,000 gross acres (240,000 net acres) covering over 375 square miles. The Company controls 100 percent of the wells, production equipment, gathering system and the Fain gas processing plant for the field. As this field is operated at or below vacuum conditions, Pioneer continually works to improve compressor / gathering system efficiency. As part of this effort, approximately 17 miles of 16 inch pipeline was recently replaced in the heart of the field. The Company received regulatory relief in parts of the West Panhandle field to allow for future infill drilling locations.
Rocky Mountains
Raton field. The Raton Basin properties are located in the southeast portion of Colorado. Exploration for CBM in the Raton Basin began in the late 1970s and continued through the late 1980s, with several companies drilling and testing more than 100 wells during this period. The absence of a pipeline to transport gas from the Raton Basin prevented full scale development until January 1995, when Colorado Interstate Gas Company completed the construction of the Picketwire lateral pipeline system. The Company's gas in the Raton Basin has an average energy content of 1,000 Btu. Since the completion of the Picketwire lateral, production has continued to grow, resulting in expansion of the system's capacity by its operator, the most recent expansion of which was in 2005. The Company owns approximately 318,000 gross acres (231,000 net acres) in the center of the Raton Basin with current production from coal seams in the Vermejo and Raton formations. The Company owns the majority of the well servicing and frac equipment that it utilizes in the Raton field to control costs and insure availability. In the Raton field, the Company sells its gas at a Mid-Continent index price which historically has generally provided higher realized gas prices as compared to the Rockies-based indexes.
In December 2007, the Company acquired approximately 30,000 net acres in the Raton Basin for $205.3 million. The acquired acreage has approximately 95 Bcf of proved reserves.
During 2007, the Company (a) drilled 230 wells, and put 301 wells on production, (b) added wellhead compression and (c) continued efforts to optimize gathering and compression facilities. During 2008, the Company expects to complete approximately 175 wells.
Piceance/Uinta Basins. The Piceance Basin is located in the central portion of western Colorado, and the Uinta Basin is located in the central portion of eastern Utah. The Company owns approximately 244,000 gross acres covering producing and prospective regions of the Piceance and Uinta Basins. Currently, production is established from various tight sandstone, coal and shale formations. The Company's significant projects in the area are CBM plays at Columbine Springs and Castlegate and a deep gas play at Main Canyon.
Sand Wash Basin. The Sand Wash Basin is the site of a potential CBM project located north of the Company's Piceance Basin properties. The Company holds a 50 percent operated interest in 114,000 gross acres in the Lay Creek field. At Lay Creek, the Company has drilled 18 wells in six separate pilot areas and completed workovers and recompletions on 14 wells drilled by a previous operator. The Company completed the water treatment facilities and initiated sales of production in 2007. Determination of success of the pilot project is dependent on the ability to dewater the formation and determine if commercial quantities of gas can be produced. The pilot project is currently in the dewatering phase and a determination of commerciality should be known by the end of 2008.
Gas prices. In general, industry drilling success in the Rocky Mountains area (which affects the Company's properties in the Piceance/Uinta Basins and Sand Wash Basin) has created more supply than can be transported by the currently available pipeline infrastructure. As a result, gas prices in the region have experienced greater volatility and at the end of the third quarter of 2007 spot gas prices for the area were approximately $.60 per MMBtu. As a result of the extremely low gas prices during September and October of 2007, the Company shut-in approximately 5 to 6 MMcfpd of gas production in the Uinta/Piceance area. Additional pipeline capacity was added in the first quarter of 2008 with the start-up of the Rockies Express pipeline, which should alleviate the capacity constraints, allowing more gas to reach consumer markets at improved price levels. Prices have rebounded in the area since September 30, 2007 and the Company believes that gas prices will continue to improve as a result of the Rockies Express pipeline being in service.
South Texas. In 2007, the South Texas drilling program focused on the Edwards Trend, a tight gas limestone reservoir characterized by narrow bands of dry gas fields extending over 250 miles in length. The Company's drilling activity occurred in both established areas such as Pawnee field and growth areas along the Trend. To date the Company has acquired over 305,000 gross acres in the Edwards Trend. In addition to the Pawnee field, the Company has operations in the SW Kenedy, Sawfish, Word, Three Rivers and Washburn fields. Production depths in the Edwards Trend range from 9,500 feet to 14,500 feet.
During 2007, the Company drilled 20 exploration and appraisal wells targeting new field discoveries in the Edwards Trend growth areas with 100 percent success, exceeding expectations and increasing proved gas reserves. Nine of these new wells have been added to production, three wells are awaiting pipelines or testing, four are
awaiting stimulation, and four are waiting on the horizontal lateral portion of the well to be completed. In previously established areas, including the Pawnee field, 14 wells were drilled with 100 percent success.
The acquisition of 3-D seismic data has significantly enhanced field development in all areas of the Edwards Trend, allowing the Company to more accurately locate and orient the horizontal wells for optimal results. To expand its 3-D data coverage to include new discoveries and additional prospects, the Company is in the process of shooting and interpreting approximately 900 square miles of new data. Multiple surveys were completed in 2007 and more are planned for 2008.
In order to accommodate its rapidly growing Edwards Trend production, the Company significantly expanded its existing gas gathering and processing infrastructure during 2007. The expansion included over 30 miles of gathering system and three additional treating facilities were installed.
In 2008, the Company expects a comparable drilling program to that in 2007. Also planned are additional facilities expansions to accommodate increasing production.
Mississippi. The Company has built an acreage position covering multiple plays in the Mississippi Salt Basin and now holds leases and option interests covering approximately 150,000 net acres. Over the next two to three years, the Company expects to test a number of opportunities and to continue technical work that is currently underway.
The Company drilled two successful Cotton Valley wells in the Bolton field and installed a gas treating facility to process the gas. The Company is permitting for a 3-D seismic shoot in 2008 for the Bolton field to better define the resource potential and future drilling plans.
During 2007, the Company participated in the drilling of six successful exploration wells on its approximate 9,300 gross acres in the Barnett Shale play that it acquired in the second quarter of 2007.
In December 2007, the Company expanded its Barnett Shale acreage position by completing a $144.3 million acquisition. The Company estimates proved reserves on the acreage to be approximately 13.5 MMBOE. The acreage being acquired contains more than 300 potential drilling locations, with most locations covered by 3-D seismic data.
The Company's total holdings in the Barnett Shale play now approximate 80,000 gross acres, with more than 450 potential drilling locations. The Company plans to drill 20 wells in 2008 with the expectation of increasing its drilling program in 2009.
Oooguruk. In 2002, the Company acquired a 70 percent working interest and operatorship in ten state leases on Alaska's North Slope, and in 2003 drilled three exploratory wells to test a possible extension of the productive sands in the Kuparuk River field in the shallow waters offshore the North Slope of Alaska. Although all three of the wells found the sands filled with oil, they were too thin to be considered commercial on a stand-alone basis. However, the wells also encountered thick sections of oil-bearing Jurassic-aged sands, and the first well flowed at a rate of approximately 1,300 Bbls per day. In January 2004, the Company farmed-into a large acreage block to the southwest of the Company's discovery. In 2004, Pioneer completed an extensive technical and economic evaluation of the resource potential within this area. As a result of this evaluation, the Company performed front-end engineering and permitting activities during 2005 to further define the scope of the project. In early 2006, the Company announced that it had approved the development of the Oooguruk field in the project area.
The Company constructed and armored the gravel drilling and production island site in 2006. Installation of a subsea flowline and production facilities to carry produced liquids to existing onshore processing facilities at the Kuparuk River Unit was completed in 2007. Pioneer assembled the drilling rig on location and commenced drilling the first of approximately 40 horizontal development and injector wells in December of 2007. The Company estimates that first production will occur during the first half of 2008 and that first sales will occur mid-year 2008. During 2008, the Company expects to drill 13 to 15 of the 40 planned wells.
Cosmopolitan. In 2005, the Company acquired an interest in the Cosmopolitan Unit in the Cook Inlet of Alaska. Through a series of transactions, the Company now owns 100 percent of the Cosmopolitan Unit. The
previous operator of the Cosmopolitan Unit had an oil discovery for which economic viability was not determined. During 2005 and 2006, the Company completed and interpreted a 3-D seismic shoot. During 2007, the Company drilled a lateral sidetrack from an existing wellbore at an onshore site to further appraise the resource potential of the unit. The initial unstimulated production test results were encouraging. The Company plans to begin permitting activities and continue facilities planning during 2008 for a future potential development of the project and to drill another appraisal well in 2009.
Onshore North Slope area. During the 2006-2007 winter drilling season, the Company participated in drilling two exploratory wells in the National Petroleum Reserve - Alaska ("NPRA") area, both of which were noncommercial.
Gulf of Mexico
Gulf of Mexico area. During 2005, the Company announced a discovery on its Clipper prospect in the Green Canyon Blocks 299 and 300 in the deepwater Gulf of Mexico. During 2006, the Company drilled two successful Clipper appraisal wells, but drilled an unsuccessful exploratory well at the Flying Cloud prospect, a prospect near the Clipper discovery. The Company began evaluation plans for the potential development of the discovery, but projected capital costs for the project doubled during the evaluation, which resulted in the Company electing to not pursue the development of the Clipper project. Accordingly, the Company recognized an exploration and abandonment charge of $72.1 million in the fourth quarter of 2007.
As a result of Hurricane Rita, the Company's East Cameron facility, located on the Gulf of Mexico shelf, was destroyed. Operations to reclaim and abandon the East Cameron facility began in 2007. During the second quarter of 2007, the Company increased the estimated cost to reclaim and abandon the East Cameron facility by $66.0 million to an aggregate estimated cost of $185 million. The estimate to reclaim and abandon the East Cameron facility is based upon an analysis prepared by a third-party engineering firm for the majority of the work, an estimate by the Company for the remaining work that was not covered by the third-party analysis and actual abandonment activity to date. See Note U of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information on the East Cameron 322 facility.
International
The Company's international operations are located offshore South Africa and onshore in southern Tunisia. Additionally, the Company has an exploration permit in Equatorial Guinea. During 2007, the Company also disposed of its interests in Block 320 in Nigeria, and relinquished its remaining interest in Block 256 in Nigeria due to unsuccessful exploratory drilling results. The Company is currently winding up its efforts to exit Nigeria completely. In November 2007, the Company closed the sale of all of the Company's common stock in its Canadian subsidiaries for net proceeds of $525.7 million, resulting in a gain of $101.3 million. See Notes N, S and V of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for a description of the Nigerian and Canadian divestitures. As of December 31, 2007, approximately three percent of the Company's proved reserves were located in Africa.
The following tables summarize the Company's international development and exploration/extension drilling activities during 2007:
___________
(a)
Includes $10.5 million of capitalized interest related to the South Coast Gas project.
South Africa. The Company has agreements to explore for oil and gas covering over 3.6 million acres offshore the southern coast of South Africa in water depths generally less than 650 feet. The Sable oil field began producing in August 2003 and the majority of the gas from the field has been reinjected. The Company has a 40 percent working interest in the Sable field.
In 2005, the Company sanctioned the non-operated South Coast Gas development project, which includes the subsea tie-back of gas from the Sable field and five additional gas accumulations to an existing production facility on the F-A platform for transportation via existing pipelines to a gas-to-liquids plant. Pioneer has a 45 percent working interest in the project. As part of sanctioning of the South Coast Gas project, the Company signed a six-year contract for the sale of all of its gas and condensate production from the project. The contract contains an obligation for the purchaser to take or pay for a total of 91.4 BCF and associated condensate if the anticipated deliverability estimates are achieved. The price for both gas and condensate is indexed to Brent oil prices. During 2007, two additional wells were drilled and installation of pipeline and facilities infrastructure was completed as part of the South Coast Gas project. First production from the South Coast Gas project was achieved in the third quarter of 2007 at approximately 15 to 20 MMcfpd (gross). It is expected that the simultaneous production of both oil and gas from the Sable field will increase the ultimately recoverable oil reserves.
A significant portion of the gas reserves associated with the South Coast Gas project is in the Sable field. Initially, the gas production from the Sable field was not expected to commence until the oil production was completed. However, as a result of production performance from the Sable field and improved oil prices, which have had the effect of extending the economic life of the Sable oil field, facilities modifications are being planned that would allow for the simultaneous production of oil and gas from the Sable field. The modifications are currently expected to be completed in late 2008 or early 2009.
Tunisia. The Company holds interests in four separate onshore permits located in the southern portion of Tunisia. These permits cover a gross area of approximately 11,900 square kilometers containing two production concessions targeting the Acacus formation with additional future upside exploration potential from this and other formations.
•
Jenein Nord Permit and Cherouq Concession. The Jenein Nord Permit covers approximately 1,200 square kilometers. Over the past two years, the Company has conducted an intensive exploration program over the area. As a result of an aggressive seismic data acquisition and exploration drilling program, the Company achieved a significant number of hydrocarbon discoveries. Based on the success, the Company, along with the government oil agency, Enterprise Tunisienne d'Activities Petrolieres ("ETAP"), submitted a joint application on November 10, 2007 to the Directeur Général de l'Energie for the development of a portion of the permit area called the Cherouq Concession.
On December 17, 2007, the Consultative Committee of Hydrocarbons, the advisory committee to the Directeur Général de l'Energie, approved the Cherouq Concession resulting in the Company and ETAP each holding a 50 percent working interest in the concession. The concession covers approximately 760 square kilometers of the Jenein Nord Permit. During 2007, the Company drilled seven exploration wells and first production from the concession was achieved in late fourth quarter 2007.
The Company plans to drill up to seven additional wells and acquire an additional 295 square kilometers of 3-D seismic data over the Cherouq Concession during 2008.
•
Borj El Khadra Permit and Adam Concession. The Borj El Khadra Permit, including the Adam Concession, covers approximately 2,900 square kilometers. Production from the Adam Concession began in May 2003, for which the Company now has a 20 percent working interest. During 2007, the Company continued its exploratory and appraisal activities on the Adam Concession by drilling four wells, of which all were successful, and completed drilling of two wells in the Borj El Khadra Permit, of which one was successful. The Company plans to drill an additional four wells in the Adam Concession and two wells in the Borj El Khadra exploration permit during 2008.
•
El Hamra Permit. The El Hamra exploration permit covers approximately 4,000 square kilometers, of which the Company is operator with a 50 percent working interest during the exploration period. In 2007, the Company completed the acquisition of 310 kilometers of seismic data and began processing the data. Processing and interpretation of the seismic data is scheduled to be completed during the second quarter of 2008. The Company anticipates drilling an exploration well in the second half of 2008.
•
Anaguid Permit. The Anaguid exploration permit covers approximately 3,800 square kilometers. In 2007, the Company acquired an additional 15 percent interest in the Anaguid exploration permit, thereby increasing its interest to 60 percent (during the exploration period) and resulting in the transfer of operations to Pioneer. The Company intends to acquire an additional 900 square kilometers of 3-D seismic data and expects to drill up to two exploration wells in the second half of 2008.
Equatorial Guinea. The Company owns a 50 percent interest in Block H in deepwater Equatorial Guinea, which covers over 240,000 acres. In late 2006, the Republic of Equatorial Guinea ratified a new hydrocarbons law, which among other things, appears to entitle Equatorial Guinea to increase substantially its carried interest in all concessions, including Block H. In addition, drilling costs have increased significantly beyond those originally anticipated. Given these and other facts, the Company and the other participants in the block have been unable to reach an agreement as to their respective rights and obligations under a joint operating agreement relating to the well operations in the block and as a result, the parties have commenced arbitration. In connection with the ongoing arbitration among the parties, the Company recognized an impairment charge of approximately $10.3 million to write off its remaining basis in Block H. See Note I of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for specific information regarding the Company's arbitration associated with Block H.
Selected Oil and Gas Information
The following tables set forth selected oil and gas information from continuing operations for the Company as of and for each of the years ended December 31, 2007, 2006 and 2005. Because of normal production declines, increased or decreased drilling activities and the effects of acquisitions or divestitures, the historical information presented below should not be interpreted as being indicative of future results.
Production, price and cost data. The following tables set forth production, price and cost data with respect to the Company's properties for 2007, 2006 and 2005. These amounts represent the Company's historical results from continuing operations without making pro forma adjustments for any acquisitions, divestitures or drilling activity that occurred during the respective years. The production amounts will not agree to the reserve volume tables in the "Unaudited Supplementary Information" section included in "Item 8. Financial Statements and Supplementary Data" due to field fuel volumes and production from discontinued operations being included in the reserve volume tables.
PRODUCTION, PRICE AND COST DATA
PRODUCTION, PRICE AND COST DATA - (Continued)
PRODUCTION, PRICE AND COST DATA - (Continued)
Productive wells. The following table sets forth the number of productive oil and gas wells attributable to the Company's properties as of December 31, 2007, 2006 and 2005:
PRODUCTIVE WELLS (a)
__________
(a)
Productive wells consist of producing wells and wells capable of production, including shut-in wells. One or more completions in the same well bore are counted as one well. If any well in which one of the multiple completions is an oil completion, then the well is classified as an oil well. As of December 31, 2007, the Company owned interests in seven gross wells containing multiple completions.
Leasehold acreage. The following table sets forth information about the Company's developed, undeveloped and royalty leasehold acreage as of December 31, 2007:
LEASEHOLD ACREAGE
The following table sets forth the expiration dates of the leases on the Company's gross and net undeveloped acres as of December 31, 2007:
__________
(a)
Acres expiring are based on contractual lease maturities.
(b)
Acres subject to expiration during 2008 include 827,308 gross acres (201,341 net acres) in Tunisia and 198,889 gross acres (153,427 net acres) in North America. In Tunisia, the Company has received extensions, plans to make the necessary expenditures to extend the acreage or intends to seek extensions on the 2008 expirations. As to the remaining acreage, the Company may extend the leases prior to their expiration based upon 2008 planned activities or for other business reasons. In certain leases, the extension is only subject to the Company's election to extend and the fulfillment of certain capital expenditures commitments. In other cases, the extensions are subject to the consent of third parties, and no assurance can be given that the requested extensions will be granted. See "Description of Properties" above for information regarding the Company's drilling operations.
Drilling activities. The following table sets forth the number of gross and net productive and dry hole wells in which the Company had an interest that were drilled during 2007, 2006 and 2005. This information should not be considered indicative of future performance, nor should it be assumed that there was any correlation between the number of productive wells drilled and the oil and gas reserves generated thereby or the costs to the Company of productive wells compared to the costs of dry holes.
DRILLING ACTIVITIES
__________
(a)
Represents the ratio of those wells that were successfully completed as producing wells or wells capable of producing to total wells drilled and evaluated.
The following table sets forth information about the Company's wells upon which drilling was in progress as of December 31, 2007:
The Company is party to the legal proceedings that are described under "Legal actions" in Note I of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data". The Company is also party to other proceedings and claims incidental to its business. While many of these matters involve inherent uncertainty, the Company believes that the amount of the liability, if any, ultimately incurred with respect to such other proceedings and claims will not have a material adverse effect on the Company's consolidated financial position as a whole or on its liquidity, capital resources or future annual results of operations.
PART II
The Company's common stock is listed and traded on the NYSE under the symbol "PXD". The Board declared dividends to the holders of the Company's common stock of $.27 per share and $.25 per share during each of the years ended December 31, 2007 and 2006, respectively. On February 12, 2008, the Board declared a $.14 per share dividend to the holders of the Company's common stock on March 31, 2008.
The following table sets forth quarterly high and low prices of the Company's common stock and dividends declared per share for the years ended December 31, 2007 and 2006:
On February 15, 2008, the last reported sales price of the Company's common stock, as reported in the NYSE composite transactions, was $43.94 per share.
As of February 15, 2008, the Company's common stock was held by approximately 25,000 holders of record.
Purchases of Equity Securities by the Issuer and Affiliated Purchasers
The following table summarizes the Company's purchases of treasury stock during the three months ended December 31, 2007:
__________
(a)
Amounts include shares withheld to satisfy tax withholding on employees' share-based awards.
During February 2007, the Board approved a share repurchase program authorizing the purchase of up to $300 million of the Company's common stock. In April 2007, the Board approved an increase of $450 million to the existing share repurchase program bringing the aggregate authorized share repurchase program to $750 million. During 2007, the Company purchased $212.8 million of common stock pursuant to the 2007 program.
ITEM 6.
ITEM 6.
SELECTED FINANCIAL DATA
The following selected consolidated financial data as of and for each of the five years ended December 31, 2007 for the Company should be read in conjunction with "Item 7.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The following quantitative and qualitative information is provided about financial instruments to which the Company was a party as of December 31, 2007 and 2006, and from which the Company may incur future gains or losses from changes in market interest rates, foreign exchange rates or commodity prices. Although certain derivative contracts to which the Company has been a party did not qualify as hedges, the Company does not enter into derivative or other financial instruments for trading purposes.
The fair value of the Company's derivative contracts is determined based on counterparties' estimates and valuation models. The Company did not change its valuation method during 2007. During 2007, the Company was a party to commodity, interest rate and foreign exchange rate swap contracts and commodity collar contracts. See Note J of Notes to Consolidated Financial Statements included in "Item 8.
ITEM 9A.
CONTROLS AND PROCEDURES
Evaluation of disclosure controls and procedures. The Company's management, with the participation of its principal executive officer and principal financial officer, have evaluated, as required by Rule 13a-15(b) under the Exchange Act, the Company's disclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e)) as of the end of the period covered by this Report. Based on that evaluation, the principal executive officer and principal financial officer concluded that the design and operation of the Company's disclosure controls and procedures are effective in ensuring that information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms.
Changes in internal control over financial reporting. There have been no changes in the Company's internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that occurred during the Company's last fiscal quarter that have materially affected or are reasonably likely to materially affect the Company's internal control over financial reporting.
MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
The management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting. The Company's internal control over financial reporting is a process designed under the supervision of the Company's Chief Executive Officer and Chief Financial Officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the Company's financial statements for external purposes in accordance with generally accepted accounting principles.
As of December 31, 2007, management assessed the effectiveness of the Company's internal control over financial reporting based on the criteria for effective internal control over financial reporting established in "Internal Control - Integrated Framework", issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the assessment, management determined that the Company maintained effective internal control over financial reporting as of December 31, 2007, based on those criteria.
Ernst & Young LLP, the independent registered public accounting firm that audited the consolidated financial statements of the Company included in this Annual Report on Form 10-K, has issued an attestation report on the effectiveness of the Company's internal control over financial reporting as of December 31, 2007. The report, which expresses an unqualified opinion on the effectiveness of the Company's internal control over financial reporting as of December 31, 2007, is included in this Item under the heading "Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting".
REPORT OF INDEPENDENT REGISTERED PUBLIC
ACCOUNTING FIRM ON INTERNAL CONTROL OVER FINANCIAL REPORTING
The Board of Directors and Stockholders of
Pioneer Natural Resources Company:
We have audited Pioneer Natural Resources Company's internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Pioneer Natural Resources Company's management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management's Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, Pioneer Natural Resources Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Pioneer Natural Resources Company as of December 31, 2007 and 2006 and the related consolidated statements of operations, stockholders' equity, cash flows and comprehensive income for each of the three years in the period ended December 31, 2007, and our report dated February 19, 2008 expressed an unqualified opinion thereon.
Ernst & Young LLP
Dallas, Texas
February 19, 2008
ITEM 9B.