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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
| x | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended December 31, 2009
or
| ¨ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to
Commission File No. 1-8968
ANADARKO PETROLEUM CORPORATION
(Exact name of registrant as specified in its charter)
| Delaware | 76-0146568 | |
| (State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) |
1201 Lake Robbins Drive, The Woodlands, Texas 77380-1046
(Address of principal executive offices)
Registrant’s telephone number, including area code (832) 636-1000
Securities registered pursuant to Section 12(b) of the Act:
| Title of each class |
Name of each exchange on which registered | |
| Common Stock, par value $0.10 per share | New York Stock Exchange |
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes x No ¨ .
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No x.
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 x No ¨.
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No ¨.
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is 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 this Form 10-K or any amendment to this Form 10-K. ¨.
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer x Accelerated filer ¨ Non-accelerated filer ¨ Smaller reporting company ¨.
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ¨ No x.
The aggregate market value of the Company’s common stock held by non-affiliates of the registrant on June 30, 2009 was $22.2 billion based on the closing price as reported on the New York Stock Exchange.
The number of shares outstanding of the Company’s common stock as of January 29, 2010 is shown below:
| Title of Class | Number of Shares Outstanding | |
| Common Stock, par value $0.10 per share | 492,562,381 |
| Part of Form 10-K |
Documents Incorporated By Reference | |
| Part III |
Portions of the Proxy Statement for the Annual Meeting of Stockholders of Anadarko Petroleum Corporation to be held May 18, 2010 (to be filed with the Securities and Exchange Commission prior to April 9, 2010). |
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PART I
Items 1 and 2. Business and Properties
Anadarko Petroleum Corporation is among the largest independent oil and gas exploration and production companies in the world, with 2.3 billion barrels of oil equivalent (BOE) of proved reserves as of December 31, 2009. Anadarko’s primary business segments are managed separately due to the nature of the products and services, as well as to the unique technology, distribution and marketing requirements. The Company’s three operating segments are:
Oil and gas exploration and production – This segment explores for and produces natural gas, crude oil, condensate and natural gas liquids (NGLs). The Company’s operations are located onshore United States and in the deepwater Gulf of Mexico, as well as in Algeria, Brazil, China, Cote d’Ivoire, Ghana, Indonesia, Mozambique, Sierra Leone and other countries.
Midstream – This segment provides gathering, processing, treating and transportation services to Anadarko and third-party oil and gas producers. The Company owns and operates natural-gas gathering, processing, treating and transportation systems in the United States.
Marketing – This segment sells much of Anadarko’s production, as well as hydrocarbons purchased from third parties. The Company actively markets oil, natural gas and NGLs in the United States, and actively markets oil from Algeria and China.
The Company owns interests in several coal, trona (natural soda ash) and industrial mineral properties through non-operated joint ventures and royalty arrangements within and adjacent to its land grant acreage position (Land Grant). The Land Grant consists of land granted by the federal government in the mid-1800s, which passes through Colorado and Wyoming and into Utah. Within the Land Grant, the Company has fee ownership of the mineral rights under approximately 8 million acres.
Unless the context otherwise requires, the terms “Anadarko” or “Company” refer to Anadarko Petroleum Corporation and its consolidated subsidiaries. The Company’s corporate headquarters is located at 1201 Lake Robbins Drive, The Woodlands, Texas 77380-1046, and its telephone number is (832) 636-1000. Additionally, unless noted otherwise, the following information relates to Anadarko’s continuing operations and excludes the discontinued Canadian operations. For additional information, see Note 1—Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.
Available Information The Company files or furnishes Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, registration statements and other items with the Securities and Exchange Commission (SEC). Anadarko provides access free of charge to all of these SEC filings, as soon as reasonably practicable after filing or furnishing, on its Internet site located at www.anadarko.com. The Company will also make available to any stockholder, without charge, copies of its Annual Report on Form 10-K as filed with the SEC. For copies of this report, or any other filing, please contact Anadarko Petroleum Corporation, Investor Relations Department, P.O. Box 1330, Houston, Texas 77251-1330 or call (832) 636-1216.
In addition, the public may read and copy any materials Anadarko files with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Room 1580, Washington, DC 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC maintains an Internet site (www.sec.gov) that contains reports, proxy and information statements and other information regarding issuers, like Anadarko, that file electronically with the SEC.
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OIL AND GAS PROPERTIES AND ACTIVITIES
The map below illustrates the locations of Anadarko’s domestic and international oil and gas exploration and production operations. The Company plans to allocate approximately 90% of its 2010 capital budget to the oil and gas exploration and production segment.
Properties and Activities—United States
Overview Anadarko’s active areas in the United States include onshore in the Lower 48 states and Alaska, and the deepwater Gulf of Mexico. Proved reserves in the United States comprised 89% of Anadarko’s total proved reserves at year-end 2009. During 2009, the Company’s drilling efforts in the United States resulted in 979 natural-gas wells, 40 oil wells and 21 dry holes. The Company plans to allocate approximately 65% of its 2010 oil and gas exploration and production segment capital budget to properties in the United States.
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2010
*West Africa includes:
Africa
Alaska
Algeria
Anadarko
Anadarko Petroleum Corporation
Brazil
China
Corporation
Cote d'Ivoire
Ghana
Gulf of Mexico
includes
Indonesia
January
January 2010
Leone
Liberia
Mozambique
OPERATIONS
Petroleum
Rockies
Sierra
Sierra Leone
Southern
West
West Africa*
WORLDWIDE
WORLDWIDE OPERATIONS
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Onshore The Company plans to allocate approximately 45% of its 2010 oil and gas exploration and production segment capital budget to onshore properties.
Rocky Mountain Region Anadarko’s Rocky Mountain Region (Rockies) properties are located in Colorado, Utah and Wyoming with a primary focus on natural-gas plays. Anadarko operates approximately 13,000 wells and has an interest in approximately 9,400 non-operated wells in the Rockies. Anadarko is an operator of tight gas and coalbed methane (CBM) natural-gas assets, as well as enhanced oil recovery (EOR) projects within the region. Tight gas is found in low-permeability reservoirs containing natural gas. The Company also earns royalty revenues from many operated and non-operated wells located within its Land Grant acreage. Activities in the Rockies focus on expanding the potential of mature fields to increase production and add proved reserves through infill drilling operations, re-completions and re-fracture stimulations of pre-existing wells. In 2009, the Company drilled 724 wells in the Rockies and plans to maintain an active drilling program in the region in 2010.
The Company’s operated tight gas assets are located in the Greater Natural Buttes, Wattenberg, Wamsutter and Moxa fields. Pinedale is a non-operated asset within Anadarko’s tight gas portfolio. Anadarko uses fracture-stimulation technology to create an enhanced migration pathway for the natural gas to flow to the wellhead. Anadarko operates 7,000 wells and has an interest in 4,000 non-operated wells in these tight gas areas. The Company also benefits from third-party-operator success in the Wyoming portion of its Land Grant acreage and actively pursues farm-out projects to capture incremental royalty revenues from exploration and development activity in the area. In 2010, Anadarko plans to maintain an active drilling program in these tight gas areas.
Anadarko also operates multiple CBM properties in the Rockies. CBM is natural gas that is stored in coal seams. To produce it, water is extracted from the coal seam, which reduces pressure and releases natural gas which then flows to the wellhead. Anadarko’s primary CBM properties are located in the Powder River Basin and Atlantic Rim areas in Wyoming and the Helper, Clawson and Cardinal Draw areas in Utah. Anadarko operates approximately 4,600 shallow, low-cost CBM wells and has an interest in approximately 5,200 outside-operated CBM wells in the Rockies. In 2010, Anadarko will continue its active CBM development program primarily in the Powder River Basin of Wyoming.
The Company’s EOR operations increase the amount of oil that can be produced from mature reservoirs after primary recovery methods have been completed. During 2009, the Company continued to pursue phased development of its Rockies EOR assets at the Salt Creek and Monell areas in Wyoming. Each area has experienced year-over-year increases in production due to CO 2 injection operations. The Company expects the phased development to continue throughout 2010 for these assets.
Southern Region Anadarko’s Southern Region properties are primarily natural-gas plays located in Texas, Pennsylvania and Kansas. Operations in these areas are focused on finding and producing natural-gas resources from tight sands, naturally fractured carbonates and emerging shale plays.
Anadarko is active in the Bossier, Haley, Carthage, Chalk, South Texas and Ozona areas of Texas, where the Company employs vertical and horizontal drilling programs. In 2009, the Company drilled 166 development wells in these areas. Early in 2009, Anadarko reduced its activity in the Bossier and Carthage areas due to a then-existing misalignment between high service costs and low commodity prices. During the course of 2009, drilling efficiency improved in every actively developed field in these areas with almost 30% of all wells drilled setting field records for cycle time. These efficiency gains, combined with lower service costs during the second half of 2009, resulted in a significant improvement in capital efficiency. As a result, increased activity is expected in Carthage in 2010. Although the Hugoton area in Southern Kansas has historically been a long-life, slow-decline asset for Anadarko, the Company expects an increased activity level in the area in 2010 due to recent changes in local regulations controlling the number of wells that may be drilled in a given area.
Anadarko’s 2009 onshore exploration program focused primarily on testing and developing emerging shale plays. Anadarko conducted successful exploratory tests in Pennsylvania’s Marcellus shale play as well as in Texas’ Eagleford, Pearsall and Haynesville shale plays. In the Appalachian basin, where the Marcellus shale is being developed, 11 operated horizontal wells were spud and six of the wells were completed in 2009. As a non-operating partner, Anadarko also participated in 40 new horizontal wells and 12 wells were completed in 2009. As of December 31, 2009, Anadarko held interests in approximately 716,000 gross acres (approximately 350,000 net acres) in the Marcellus shale play and operated about half of the acreage with an average working
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interest of approximately 50%. In February 2010, the Company announced a joint-venture agreement which permits a third party to participate with the Company as a 32.5% partner in the Company’s Marcellus Shale assets, primarily located in north-central Pennsylvania, for approximately $1.4 billion. The third party will earn an interest in approximately 100,000 net acres in exchange for funding 100% of the Company’s share of 2010 development costs, and 90% of these costs thereafter, with an estimated funding-completion date of 2013. The third party will also have the opportunity to purchase a 32.5% share of the Company’s existing wells and additional acreage acquisitions by reimbursing a proportionate share of the Company’s prior expenditures. Closing of this transaction is subject to applicable regulatory approvals and other contractual conditions.
In the Maverick basin, where the Eagleford and Pearsall shale plays are being developed, 15 wells were spud and 10 wells were completed in 2009. As of December 31, 2009, Anadarko held approximately 380,000 gross acres (approximately 180,000 net acres) with an average working interest of approximately 50% in this area. Anadarko is also focusing on the Haynesville shale play in Texas where it currently has eight producing wells. Anadarko drilled six wells and completed five wells in 2009 and is transitioning to a development program. The Company plans to increase its activity in each of these areas in 2010.
Alaska Anadarko’s activity in Alaska is concentrated primarily on the North Slope. Development activity continued at the Colville River Unit through 2009 with seven wells drilled. In 2010, the Company anticipates sanctioning of the Alpine West satellite project and participating in approximately 10 development wells.
Gulf of Mexico In the Gulf of Mexico, Anadarko owns an average 66% working interest in 575 blocks and has access to an additional six blocks through participation agreements. The Company operates eight floating platforms, holds interests in 26 producing fields and is in the process of delineating and developing seven additional fields in the area. Anadarko plans to allocate approximately 20% of its 2010 oil and gas exploration and production segment capital budget to the deepwater Gulf of Mexico.
In 2009, Anadarko drilled seven development wells in the Gulf of Mexico. The Company plans to drill nine development wells in the area in 2010. Anadarko utilizes a hub-and-spoke infrastructure in the Gulf of Mexico in order to develop resources more quickly and at a substantial cost savings. In September 2008, Hurricane Ike damaged third-party-owned export pipelines downstream of the Marco Polo complex and the Constitution/Ticonderoga fields, thereby limiting production from certain Anadarko fields. Production from these fields returned to full capacity in the third quarter of 2009 as repairs to the third-party-owned infrastructure were completed.
In 2009, Anadarko is continuing to make progress on the Caesar Tonga development project, which is on schedule for first production in early 2011. The field is a sub-sea tieback to the Anadarko-operated and owned Constitution spar. This project is being accelerated by two years through a hub-and-spoke strategy utilizing the existing spar. In 2009, topside construction, modification and installation began on the Constitution spar. Construction, installation, drilling and completion activities will continue to advance the project in 2010.
Anadarko’s Gulf of Mexico exploration program is currently focused in the deepwaters of the extensive middle-to-lower Miocene play in the central Gulf of Mexico and the developing lower-Tertiary play in the western Gulf of Mexico. During 2009, Anadarko participated in five successful deepwater wells (Heidelberg, Shenandoah, Samurai, Vito and Lucius) and two delineation wells, at Lucius and Vito, which were still drilling at the end of 2009. Anadarko also drilled four unsuccessful wells in the Gulf of Mexico in 2009. The Company expects to participate in approximately two to four exploration wells and several delineation wells in the area in 2010.
Properties and Activities—International
Overview The Company’s international oil and gas production and development operations are located primarily in Algeria, China and Ghana. The Company also has exploration acreage in Brazil, Cote d’Ivoire, Ghana, Liberia, Sierra Leone, Mozambique, Indonesia and other countries. Approximately 11% of the Company’s proved reserves were located in these international locations at year-end 2009. Anadarko drilled 44 wells in international areas in 2009. In 2010, the Company expects to drill approximately 24 development and 20 exploration wells at various international locations. Anadarko plans to allocate approximately 35% of its 2010 oil and gas exploration and production segment capital budget to international areas.
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Algeria Anadarko is engaged in development and production activities in Algeria’s Sahara Desert in Blocks 404 and 208. Currently, all production is from fields in Block 404, which produce through the Hassi Berkine South and Ourhoud Central Production Facilities (CPF). Anadarko reached a major milestone during the year with the awarding of all major contracts for the construction of the CPF and associated infrastructure for the El Merk development project in Block 208. At December 31, 2009, site preparation was well advanced, contractor personnel were being mobilized to the site and long-lead items had been ordered. Initial production is scheduled for late 2011. During 2009, six development wells were drilled in Blocks 404 and 208. During 2010, the Company expects to drill approximately 10 development wells in the two blocks, with a focus on El Merk drilling.
Contracts and Partners Since October 1989, the Company’s operations in Algeria have been governed by a Production Sharing Agreement (PSA) between Anadarko, two third parties, and Sonatrach, the national oil and gas company of Algeria. Anadarko’s interest in the PSA for Blocks 404 and 208 is 50% before participation at the exploitation stage by Sonatrach. The Company has two partners, each with a 25% interest, also prior to participation by Sonatrach. Under the terms of the PSA, oil reserves that are discovered, developed and produced are shared by Sonatrach, Anadarko and its two partners. Sonatrach is responsible for 51% of the development and production costs. Anadarko and its partners have completed the exploration program on Blocks 404 and 208 and now participate only in development activity on these blocks. Anadarko and its joint-venture partners funded Sonatrach’s share of exploration costs and are entitled to recover these exploration costs from production during the development phase.
In March 2006, Anadarko received a letter from Sonatrach purporting to give notice under the PSA that enactment of a law in 2005 (2005 Law), relating to hydrocarbons, triggered Sonatrach’s right under the PSA to renegotiate the PSA in order to re-establish the equilibrium of Anadarko’s and Sonatrach’s interests. Anadarko and Sonatrach reached an impasse over whether Sonatrach had a right to renegotiate the PSA based on the 2005 Law and entered into a formal non-binding conciliation process under the terms of the PSA in an attempt to resolve this dispute. The conciliation on the 2005 Law dispute was concluded in 2007 without a definitive resolution. There have been no further developments on the 2005 Law dispute. At this time, Anadarko is unable to reasonably estimate the economic impact under the PSA if Sonatrach were to succeed in modifying the PSA.
Exceptional Profits Tax In July 2006, the Algerian parliament approved legislation establishing an exceptional profits tax on foreign companies’ Algerian oil production and issued regulations implementing this legislation. These regulations provide for an exceptional profits tax imposed on gross production at rates of taxation ranging from 5% to 50% based on average daily production volumes for each calendar month in which the price of Brent crude averages over $30 per barrel. Based on the Application Procedure issued in April 2007 by ALNAFT, an agency under the control of the Algerian Ministry of Energy and Mines, the exceptional profits tax is applied to the full value of production and not just to the amount in excess of $30 per barrel.
In January 2007, Sonatrach advised Anadarko that it would begin collecting the exceptional profits tax from Anadarko’s share of production commencing with March 2007 liftings, including for the prior months since the new tax went into effect. In response to the Algerian government’s imposition of the exceptional profits tax, the Company notified Sonatrach of its disagreement with the collection of the exceptional profits tax. The Company believes that the PSA provides fiscal stability through several of its provisions that require Sonatrach to pay all taxes and royalties. To facilitate discussions between the parties in an effort to resolve the dispute, on October 31, 2007, the Company initiated a conciliation proceeding on the exceptional profits tax as provided in the PSA. Any recommendation issued by a conciliation board (Conciliation Board) arising out of the conciliation proceeding is non-binding on the parties. The Conciliation Board issued its non-binding recommendation on November 26, 2008, which the Company received on December 1, 2008. On February 15, 2009, the Company initiated arbitration against Sonatrach with regard to the exceptional profits tax. In conformance with the terms of the PSA, a notice of arbitration was submitted to Sonatrach. For additional information, see Note 15—Other Taxes in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.
China Anadarko’s development and production activities in China are located offshore in Bohai Bay. Development drilling and recompletion activity was ongoing throughout 2009, and Anadarko drilled 14 wells
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during the year. Development continued during 2009 with the approval of a facility expansion and an infill drilling program implemented in order to sustain current-level production. Development drilling activity in 2010 is expected to be similar to 2009 levels. Anadarko drilled one unsuccessful exploration well in Bohai Bay in 2009. During 2010, the Company plans to drill one deepwater exploration well in the South China Sea.
Ghana Anadarko’s exploration and development activities in Ghana are located offshore in the West Cape Three Points block and the Deepwater Tano block. A significant milestone was achieved in 2009 with the Ghanaian government formally approving the Jubilee field Phase I Plan of Development and Unitization Agreement. During 2009, the Company and its partners drilled six development wells in the field and awarded all contracts. Approximately 84% of the construction work on a floating production, storage and offloading vessel had been completed by a third-party shipbuilder at December 31, 2009. Anadarko expects initial production from the Jubilee field in late 2010. During 2009, the Company also participated in four successful exploration and appraisal wells. The Tweneboa discovery was announced in early 2009 and an appraisal well was drilling at December 31, 2009. In 2010, the Company plans to participate in five to seven exploration and appraisal wells in the two blocks.
Brazil Anadarko holds exploration interests in seven blocks located offshore Brazil in the Campos and Espírito Santo basins. In these areas, Anadarko drilled three exploration wells and one appraisal well in 2009, including three successful wells at Coalho, Itaipu and Wahoo North. In 2010, Anadarko expects to participate in three to four deepwater exploration and appraisal wells.
Indonesia Anadarko has participating interests in approximately 4.5 million exploration acres in Indonesia through a combination of several operated and non-operated Production Sharing Contracts. The Company participated in two unsuccessful exploration wells in 2009 and plans to participate in two to four exploration wells in 2010.
Mozambique The Company has participating interests in two blocks (one onshore and one offshore) totaling approximately 6.4 million acres. During 2009, Anadarko participated in one offshore exploration well that was drilling at December 31, 2009. Anadarko also drilled one unsuccessful onshore exploration well in 2009. In 2010, the Company plans to drill two to four deepwater exploration wells in this area.
Sierra Leone Anadarko’s exploration activities in Sierra Leone are located in blocks 6 and 7 in the Liberian basin. In 2009, Anadarko announced a deepwater discovery at the Venus prospect, which confirmed the presence of an active petroleum system in this frontier basin. In 2010, the Company plans to drill one to three exploration and appraisal wells in the Liberian basin.
Cote d’Ivoire Anadarko holds interests in two blocks located in the Ivorian basin. The Company participated in one unsuccessful well offshore Cote d’Ivoire in 2009. In 2010, Anadarko expects to drill one to two exploration wells in the area.
Other Anadarko also has active exploration projects in Liberia and Kenya as well as activities in other potential exploration and new venture areas overseas.
In December 2008, the SEC released the final rule for “Modernization of Oil and Gas Reporting.” The new rule requires disclosure of oil and gas proved reserves by significant geographic area, using the 12-month average beginning-of-month price for the year, rather than year-end prices, and allows the use of reliable technologies to estimate proved oil and gas reserves, if those technologies have been demonstrated to result in reliable conclusions about reserves volumes. In addition, companies are required to report on the independence and qualifications of its reserves preparer or auditor, and file reports when a third party is relied upon to prepare reserves estimates or conduct a reserves audit.
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Reserve and related information for 2009 is presented consistent with the requirements of the new rule. The new rule does not allow prior-year reserve information to be restated, so all information related to periods prior to 2009 is presented consistent with prior SEC rules for the estimation of proved reserves. Prior years have been reclassified to conform to the current-year presentation of significant geographic areas.
Estimates of volumes of proved reserves, net of royalty interests, of natural gas, oil, condensate and NGLs owned at year end are presented in billions of cubic feet (Bcf) at a pressure base of 14.73 pounds per square inch for natural gas and in millions of barrels (MMBbls) for oil, condensate and NGLs. Total volumes are presented in millions of barrels of oil equivalent (MMBOE). For this computation, one barrel is the equivalent of 6,000 cubic feet of gas. NGLs are included with oil and condensate reserves and any associated shrinkage has been deducted from the gas reserves.
Summary of Oil and Gas Reserves as of December 31, 2009
| Natural Gas (Bcf) |
Oil, Condensate, NGLs (MMBbls) |
Total (MMBOE) | ||||
| Proved |
||||||
| Developed |
||||||
| United States |
5,884 | 499 | 1,480 | |||
| International |
— | 144 | 144 | |||
| Undeveloped |
||||||
| United States |
1,880 | 261 | 574 | |||
| International |
— | 106 | 106 | |||
| Total proved |
7,764 | 1,010 | 2,304 |
The Company’s estimates of proved reserves, proved developed reserves and proved undeveloped reserves (PUDs) at December 31, 2009, 2008 and 2007 and changes in proved reserves during the last three years are contained in the Supplemental Information on Oil and Gas Exploration and Production Activities (Supplemental Information) in the Consolidated Financial Statements under Item 8 of this Form 10-K. The Company files annual estimates of certain proved oil and gas reserves with the U.S. Department of Energy, which are within 5% of the amounts included in the above estimates.
Also contained in the Supplemental Information in the Consolidated Financial Statements are the Company’s estimates of future net cash flows and discounted future net cash flows from proved reserves. See Operating Results and Critical Accounting Estimates under Item 7 of this Form 10-K for additional information on the Company’s proved reserves.
Proved Undeveloped Reserves The Company annually reviews all PUDs to ensure an appropriate plan for development exists. Generally, onshore United States PUDs are converted to proved developed reserves within five years. Projects such as enhanced oil recovery, arctic development, deepwater development and international programs may take longer than five years. The Company had 1.9 Tcf and 367 MMBbls of PUDs, totaling 680 MMBOE at December 31, 2009, compared to 677 MMBOE of PUDs at December 31, 2008. In 2009, the Company converted 100 MMBOE, or 15% of the total year-end 2008 PUDs to proved developed reserves (PDP). Approximately $1.0 billion was spent in 2009 associated with development of PUDs. Of the total $1.0 billion spent in 2009, approximately 40% related to three of the Company’s major development projects—El Merk in Algeria, and K2 and Caesar Tonga in the Gulf of Mexico, and approximately 50% was spent on domestic infill drilling programs in the Rockies and Southern Region. The remainder of 2009 PUD spending was primarily associated with other Gulf of Mexico PUD conversions.
The Company has 136 MMBOE of PUDs, as of December 31, 2009, which were reported prior to 2005. Approximately 54% of the Company’s PUDs booked prior to 2005 are in Algeria and are being developed according to an Algerian government-approved plan. Nearly all of the Algerian PUDs are associated with the El
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Merk development project located on Block 208 in the Berkine basin. Construction of the El Merk CPF is underway and development drilling continues with a targeted production-initiation date of late 2011. Another 20% of the pre-2005 PUDs are associated with various phases of the Salt Creek EOR phased-development program in the Rockies. Since 2003, APC has invested $20 to $145 million per year to develop six different Salt Creek phase areas. The remaining EOR pre-2005 PUD phase areas are scheduled for completion by 2015. Approximately 8% of the pre-2005 PUDs are associated with Gulf of Mexico sidetrack opportunities where platform well slots are currently not available. The Company expects to take advantage of these opportunities by 2015 as it currently awaits the depletion of an existing producing well. The Company’s remaining PUDs booked prior to 2005 are associated with multiple domestic onshore fields and are also scheduled for conversion by 2015.
Evaluation and Review Anadarko’s estimates of proved reserves and associated future net cash flows as of December 31, 2009 were made solely by the Company’s engineers and are the responsibility of management. To ensure confidence in its estimates, the Company maintains internal policies for estimating and recording reserves to comply with the SEC definitions and guidance. Compliance with the SEC reserve guidelines is the primary responsibility of Anadarko’s Reserve Management Group (RMG). The Company requires that reserve estimates be made by qualified reserves estimators (QREs), as defined by the Society of Petroleum Engineers’ standards. All QREs receive education on the fundamentals of SEC reserves reporting, including internal training programs administered by the RMG as well as external industry training.
The RMG is managed through the Company’s Finance division, which is separate from its operating divisions, and is responsible for overseeing internal reserve reviews and approving the Company’s reserve estimates. The Director–Reserve Administration and the Corporate Reserve Manager manage the RMG and the Director–Corporate Planning is directly responsible for overseeing the RMG. The Director–Corporate Planning reports to the Company’s Senior Vice President, Finance and Chief Financial Officer, who in turn reports to the Chief Executive Officer.
The Company’s principal engineer, who is primarily responsible for overseeing the preparation of proved reserve estimates, has over 20 years of experience in the oil and gas industry, including over 16 years as either a reserve evaluator, trainer or manager. Further professional qualifications include a degree in petroleum engineering, extensive internal and external reserve training, and asset evaluation and management. In addition, the principal engineer is an active participant in industry reserve seminars, professional industry groups and has been a member of the Society of Petroleum Engineers for over 20 years.
Throughout the year, the RMG performs internal audits of significant fields and significant reserve additions and revisions. The procedures and methods of over 80% of the Company’s estimates of proved reserves and future net cash flows, as of December 31, 2009, were reviewed by Miller and Lents, Ltd. (M&L). The purpose of the review was to determine that procedures and methods used by Anadarko to estimate its proved reserves were based on generally accepted engineering and evaluation principles and are in accordance with definitions contained in the rules of the SEC. In each review, Anadarko’s technical staff presented M&L with an overview of the reserves data, as well as the methods and assumptions used in estimating reserves. The data presented included pertinent seismic information, geologic maps, well logs, production tests, material balance calculations, reservoir simulation models, well performance data, operating procedures and relevant economic criteria. Subsequent to the reviews, M&L was provided with additional data and information that was requested in certain instances to satisfy M&L that the procedures and methods used were in accordance with standard industry practice. Management’s intent in retaining M&L to review its procedures and methods is to provide objective third-party input on these procedures and methods and to gather industry information applicable to its reserve estimation and reporting process.
The Audit Committee of the Company’s Board of Directors meets with management, the Company’s senior reserves engineering personnel and the independent petroleum consultants, M&L, to discuss matters and policies related to reserves.
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Sales Volumes, Prices and Production Costs
The following table provides the Company’s annual sales volumes, average sales prices and production costs from continuing operations. The Company’s sales volumes for 2009, 2008 and 2007 were 220 MMBOE, 206 MMBOE and 211 MMBOE, respectively. Sales volumes for 2007 include approximately 15 MMBOE associated with properties that were divested during 2007. Production costs are costs to operate and maintain the Company’s wells and related equipment and include the cost of labor, well service and repair, location maintenance, power and fuel, transportation, cost of product, property taxes and production-related general and administrative costs. Additional information on volumes, prices and production costs is contained in Financial Results under Item 7 of this Form 10-K. Additional detail regarding production costs is contained in the Supplemental Information in the Consolidated Financial Statements under Item 8 of this Form 10-K. Information on major customers is contained in Note 18—Major Customers in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.
| Sales Volumes | Average Sales Prices(1) | Average Production Costs(2) | ||||||||||||||||
| Natural Gas (Bcf) |
Oil & Condensate (MMBbls) |
NGLs (MMBbls) |
Natural Gas (Per Mcf) |
Oil & Condensate (Per Bbl) |
NGLs (Per Bbl) |
Production Costs (Per BOE) | ||||||||||||
| Year Ended |
||||||||||||||||||
| United States |
809 | 44 | 17 | $ | 3.61 | $ | 58.56 | $ | 31.42 | $ | 8.59 | |||||||
| International |
— | 24 | — | — | 59.01 | — | 6.01 | |||||||||||
| Total |
809 | 68 | 17 | $ | 3.61 | $ | 58.72 | $ | 31.42 | $ | 8.30 | |||||||
| Year Ended |
||||||||||||||||||
| United States |
750 | 40 | 14 | $ | 7.69 | $ | 96.20 | $ | 56.11 | $ | 9.99 | |||||||
| International |
— | 27 | — | — | 95.83 | — | 9.02 | |||||||||||
| Total |
750 | 67 | 14 | $ | 7.69 | $ | 96.05 | $ | 56.11 | $ | 9.86 | |||||||
| Year Ended |
||||||||||||||||||
| United States |
698 | 48 | 16 | $ | 5.80 | $ | 66.88 | $ | 45.87 | $ | 8.66 | |||||||
| International |
— | 31 | — | — | 71.86 | — | 6.66 | |||||||||||
| Total |
698 | 79 | 16 | $ | 5.80 | $ | 68.83 | $ | 45.87 | $ | 8.36 | |||||||
| (1) | Excludes the impact of commodity derivatives. |
| (2) | Excludes ad valorem and severance taxes. |
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Sales Revenues and Commodity Derivatives
The following table provides the Company’s natural-gas, oil and condensate and NGLs sales revenues and related gains (losses) on commodity derivatives. Anadarko utilizes derivative instruments to manage the Company’s cash flow exposure to commodity price risk related to the Company’s sales volumes. The gains and losses related to these commodity derivatives are reported in other (income) expense. Additional information on derivative instruments is contained in Note 1 and Note 8 in the Notes to Consolidated Financial Statements under Item 8 of the Form 10-K.
| Natural Gas | Oil & Condensate | NGLs | ||||||||||||||||||||||
| millions | Sales Revenue |
Realized Gain (Loss) on Derivatives |
Unrealized Gain (Loss) on Derivatives |
Sales Revenue |
Realized Gain (Loss) on Derivatives |
Unrealized Gain (Loss) on Derivatives |
Sales Revenue | |||||||||||||||||
| Year Ended December 31, 2009 |
||||||||||||||||||||||||
| United States |
$ | 2,924 | $ | 277 | $ | (444 | ) | $ | 2,585 | $ | 34 | $ | (223 | ) | $ | 536 | ||||||||
| International |
— | — | — | 1,437 | 16 | (68 | ) | — | ||||||||||||||||
| Total |
$ | 2,924 | $ | 277 | $ | (444 | ) | $ | 4,022 | $ | 50 | $ | (291 | ) | $ | 536 | ||||||||
| Year Ended |
||||||||||||||||||||||||
| United States |
$ | 5,770 | $ | 104 | $ | 380 | $ | 3,849 | $ | (326 | ) | $ | 327 | $ | 802 | |||||||||
| International |
— | — | — | 2,576 | (117 | ) | 193 | — | ||||||||||||||||
| Total |
$ | 5,770 | $ | 104 | $ | 380 | $ | 6,425 | $ | (443 | ) | $ | 520 | $ | 802 | |||||||||
| Year Ended |
||||||||||||||||||||||||
| United States |
$ | 4,043 | $ | 471 | $ | (395 | ) | $ | 3,197 | $ | 53 | $ | (514 | ) | $ | 719 | ||||||||
| International |
— | — | — | 2,210 | — | (139 | ) | — | ||||||||||||||||
| Total |
$ | 4,043 | $ | 471 | $ | (395 | ) | $ | 5,407 | $ | 53 | $ | (653 | ) | $ | 719 | ||||||||
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The Company’s 2009 drilling program focused on proven and emerging oil and natural-gas basins in the United States (onshore and deepwater Gulf of Mexico), and various international locations. Exploration activity consisted of 67 gross completed wells, including 54 onshore U.S. wells, six offshore Gulf of Mexico wells, and seven international wells. Development activity consisted of 1,020 gross completed wells, which included 974 onshore wells, six offshore Gulf of Mexico wells, and 40 international wells.
The following table shows the number of oil and gas wells completed in each of the last three years:
| Net Exploratory | Net Development | |||||||||||||
| Productive | Dry Holes | Total | Productive | Dry Holes | Total | Total | ||||||||
| 2009 |
||||||||||||||
| United States |
30.6 | 5.0 | 35.6 | 587.2 | 7.3 | 594.5 | 630.1 | |||||||
| International |
— | 3.3 | 3.3 | 10.7 | — | 10.7 | 14.0 | |||||||
| Total |
30.6 | 8.3 | 38.9 | 597.9 | 7.3 | 605.2 | 644.1 | |||||||
| 2008 |
||||||||||||||
| United States |
12.1 | 4.6 | 16.7 | 1,566.1 | 8.0 | 1,574.1 | 1,590.8 | |||||||
| International |
— | 1.6 | 1.6 | 4.9 | 0.4 | 5.3 | 6.9 | |||||||
| Total |
12.1 | 6.2 | 18.3 | 1,571.0 | 8.4 | 1,579.4 | 1,597.7 | |||||||
| 2007 |
||||||||||||||
| United States |
18.1 | 4.2 | 22.3 | 902.1 | 2.4 | 904.5 | 926.8 | |||||||
| International |
0.3 | 3.8 | 4.1 | 4.6 | — | 4.6 | 8.7 | |||||||
| Total |
18.4 | 8.0 | 26.4 | 906.7 | 2.4 | 909.1 | 935.5 | |||||||
The following table shows the number of wells in the process of drilling or in active completion stages and the number of wells suspended or waiting on completion as of December 31, 2009:
| Wells in the process of drilling or in active completion |
Wells suspended or waiting on completion | |||||||
| Exploration | Development | Exploration | Development | |||||
| United States |
||||||||
| Gross |
26 | 261 | 56 | 133 | ||||
| Net |
12.5 | 167.0 | 26.0 | 82.6 | ||||
| International |
||||||||
| Gross |
6 | 2 | 15 | 14 | ||||
| Net |
2.5 | 0.8 | 5.3 | 4.1 | ||||
| Total |
||||||||
| Gross |
32 | 263 | 71 | 147 | ||||
| Net |
15.0 | 167.8 | 31.3 | 86.7 | ||||
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As of December 31, 2009, the Company had an ownership interest in productive wells as follows:
| Oil Wells* | Gas Wells* | |||
| United States |
||||
| Gross |
3,982 | 26,942 | ||
| Net |
3,088.7 | 16,703.0 | ||
| International |
||||
| Gross |
282 | — | ||
| Net |
70.9 | — | ||
| Total |
||||
| Gross |
4,264 | 26,942 | ||
| Net |
3,159.6 | 16,703.0 | ||
|
* Includes wells containing multiple completions as follows: |
||||
| Gross |
346 | 1,786 | ||
| Net |
325.8 | 1,443.7 | ||
The following schedule shows the number of developed lease, undeveloped lease and fee mineral acres in which Anadarko held interests at December 31, 2009:
| Developed Lease |
Undeveloped Lease |
Fee Minerals | Total | |||||||||||||
| thousands of acres | Gross | Net | Gross | Net | Gross | Net | Gross | Net | ||||||||
| United States |
||||||||||||||||
| Onshore |
5,347 | 3,155 | 7,070 | 3,120 | 10,272 | 8,422 | 22,689 | 14,697 | ||||||||
| Offshore |
371 | 176 | 2,955 | 1,939 | — | — | 3,326 | 2,115 | ||||||||
| Total |
5,718 | 3,331 | 10,025 | 5,059 | 10,272 | 8,422 | 26,015 | 16,812 | ||||||||
| International |
349 | 92 | 28,140 | 13,396 | — | — | 28,489 | 13,488 | ||||||||
MIDSTREAM PROPERTIES AND ACTIVITIES
Anadarko invests in midstream (gathering, processing, treating and transporting) systems to complement its oil and gas operations in regions where the Company has natural-gas production. Through ownership and operation of these facilities, the Company is better able to manage its costs associated with, and value received for gathering, processing, treating and transporting natural gas. In addition, Anadarko’s midstream business also provides midstream services to third-party customers, including major and independent producers. Anadarko generates revenues from its midstream activities through fixed-fee, percent-of-proceeds, and keep-whole agreements. For 2010, Anadarko plans to allocate approximately 8% of the Company’s capital budget to the midstream segment.
Anadarko significantly increased the size and scope of its midstream business through its 2006 acquisitions of Western Gas Resources, Inc. (Western) and Kerr-McGee Corporation (Kerr-McGee). At the end of 2009, Anadarko had 28 systems located throughout major onshore producing basins in Wyoming, Colorado, Utah, New Mexico, Kansas, Oklahoma and Texas.
In 2008, Western Gas Partners, LP (WES), a subsidiary of Anadarko, completed its initial public offering of 20.8 million common units for net proceeds of $321 million ($343 million less $22 million for underwriting
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discounts and structuring fees). WES is a Delaware publicly traded limited partnership formed by Anadarko to own, operate, acquire and develop midstream assets. Anadarko contributed assets to WES in exchange for an aggregate 59.6% limited partner interest (consisting of common and subordinated limited partner units) in WES, a 2% general partner interest and incentive distribution rights (IDRs). IDRs entitle the holder to specified increasing percentages of cash distributions as WES’s per-unit cash distributions increase. In addition, Anadarko maintains control over the assets owned by WES through its ownership of the general partner. Anadarko holds an aggregate 54.8% limited partner interest in WES, a 2% general partner interest and IDRs as of December 31, 2009.
The following table provides key statistics for Company-owned gathering and processing facilities at December 31, 2009.
| Gathering and Processing Facilities |
Miles of Gathering Pipelines |
Total Horsepower |
2009 Average Throughput (MMcf/d) | |||
| Hugoton Gathering |
2,030 | 102,260 | 120 | |||
| Wattenberg |
1,730 | 64,470 | 260 | |||
| Powder River CBM |
1,640 | 549,210 | 770 | |||
| Greater Natural Buttes |
960 | 117,280 | 380 | |||
| Granger Complex |
750 | 46,970 | 240 | |||
| Red Desert Complex |
740 | 67,110 | 140 | |||
| Dew Gathering |
320 | 43,520 | 170 | |||
| Pinnacle |
270 | 1,340 | 220 | |||
| Other |
4,180 | 270,950 | 1,520 | |||
| Total |
12,620 | 1,263,110 | 3,820 | |||
The Company’s marketing segment actively manages Anadarko’s natural-gas, crude-oil, condensate and NGLs sales. In marketing its production, the Company attempts to minimize market-related shut-ins, maximize realized prices, and manage credit-risk exposure. The Company’s sales of natural gas, crude oil, condensate and NGLs are generally made at the market prices for those products at the time of sale. The Company also purchases natural-gas, crude-oil, condensate and NGLs volumes from third parties, primarily near Anadarko’s production areas, to aggregate larger volumes, which in turn, better positions the Company to fully utilize transportation capacity, attract creditworthy customers, facilitate efforts to maximize prices received and minimize balancing issues with customers and pipelines during operational disruptions.
The Company sells natural gas under a variety of contracts. The Company has the marketing capability to move large volumes of gas into and out of the daily gas market to capitalize on price volatility. The Company may also engage in limited trading activities for the purpose of generating profits from exposure to changes in market prices of natural gas, crude oil, condensate and NGLs. The Company does not engage in market-making practices and limits its marketing activities to natural-gas, crude-oil and NGLs commodity contracts. The Company’s marketing risk position is typically a net short position (reflecting agreements to sell natural gas, crude oil and NGLs in the future for specific prices) that is offset by the Company’s natural long position as a producer (reflecting ownership of underlying natural-gas and crude-oil reserves). See Energy Price Risk under item 7A of this Form 10-K.
Natural Gas Natural gas continues to fulfill a significant portion of North America’s energy needs and the Company believes the importance of natural gas in meeting this energy need will continue. Anadarko markets its natural-gas production to maximize the commodity value and to reduce the inherent risks of the physical- commodity markets. Anadarko Energy Services Company, a wholly owned subsidiary of Anadarko, is a marketing company offering supply-assurance, competitive-pricing and risk-management services in addition to other services which are tailored to its customers’ needs. The Company sells natural gas under a variety of contracts and may also receive a service fee related to the level of reliability and service required by the customer.
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The Company controls a significant amount of natural-gas firm transportation capacity that is used to ensure access to downstream markets, which enhances the Company’s ability to produce its natural gas. This transportation capacity also provides the opportunity to capture incremental value when pricing differentials between physical locations are present. The Company also stores natural gas in contracted storage facilities to minimize operational disruptions to its ongoing operations and to take advantage of seasonal price differentials. Normally, the Company will have forward contracts in place (physical-delivery or financial derivative instruments) to sell the stored gas at a fixed price.
Crude Oil, Condensate and NGLs Anadarko’s crude-oil, condensate and NGLs revenues are derived from production in the United States, Algeria, China and other international areas. Most of the Company’s U.S. crude-oil and NGLs production is sold under contracts with prices based on market indices, adjusted for location, quality and transportation. Oil from Algeria is sold by tanker as Saharan Blend to customers primarily in the Mediterranean area. Saharan Blend is a high-quality crude that provides refiners large quantities of premium products such as jet and diesel fuel. Oil from China is sold by tanker as Cao Fei Dian (CFD) Blend to customers primarily in the Far East markets. CFD Blend is a heavy sour crude oil which is sold into both the prime fuels refining market and the heavy fuel oil blend stock market. The Company also purchases and sells third-party-produced crude oil, condensate and NGLs in the Company’s domestic and international market areas, as well as utilizes contracted NGLs storage facilities to capture market opportunities and to help minimize fractionation and downstream infrastructure disruptions.
CURRENT MARKET CONDITIONS AND COMPETITION
In 2008, most segments in the global economy experienced a sharp downturn. Markets improved in 2009, but economic uncertainty remained. This economic uncertainty, along with recent commodity price volatility, has made the creditworthiness, liquidity and financial position of the Company’s counterparties increasingly difficult to evaluate. For this reason, the Company has emphasized its monitoring of counterparty risk. Although Anadarko has not experienced any material financial losses associated with third-party credit deterioration, in certain situations, the Company has declined to transact with some counterparties and has changed its sales terms to require some counterparties to pay in advance or post letters of credit for purchases.
The oil and gas business is highly competitive in the exploration for and acquisition of reserves and in the gathering and marketing of oil and gas production. The Company’s competitors include national oil companies, major oil and gas companies, independent oil and gas companies, individual producers, gas marketers and major pipeline companies, as well as participants in other industries supplying energy and fuel to industrial, commercial and individual consumers.
For additional information on operations by segment location, see Note 19—Segment Information in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.
As of December 31, 2009, the Company had approximately 4,300 employees. Anadarko considers its relations with its employees to be satisfactory. The Company’s employees are not represented by any union. The Company has had no significant work stoppages or strikes associated with its employees.
REGULATORY MATTERS, ENVIRONMENTAL AND ADDITIONAL FACTORS AFFECTING BUSINESS
See Risk Factors under Item 1A and Liquidity and Capital Resources—Obligations and Contingencies—Environmental under Item 7 of this Form 10-K.
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As is customary in the oil and gas industry, only a preliminary title review is conducted at the time properties believed to be suitable for drilling operations are acquired by the Company. Prior to the commencement of drilling operations, a thorough title examination of the drill site tract is conducted and curative work is performed with respect to significant defects, if any, before proceeding with operations. Anadarko believes the title to its leasehold properties is good and defensible in accordance with standards generally acceptable in the oil and gas industry subject to such exceptions that, in the opinion of legal counsel for the Company, are not so material as to detract substantially from the use of such properties.
The leasehold properties owned by the Company are subject to royalty, overriding royalty and other outstanding interests customary in the industry. The properties may be subject to burdens such as liens incident to operating agreements and current taxes, development obligations under oil and gas leases and other encumbrances, easements and restrictions. Anadarko does not believe any of these burdens will materially interfere with its use of these properties.
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| Item 1A. | Risk Factors |
CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS
The Company has made in this report, and may from time to time otherwise make in other public filings, press releases and discussions with Company management, forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 concerning the Company’s operations, economic performance and financial condition. These forward-looking statements include information concerning future production and reserves, schedules, plans, timing of development, contributions from oil and gas properties, marketing and midstream activities and those statements preceded by, followed by or that otherwise include the words “may,” “could,” “believes,” “expects,” “anticipates,” “intends,” “estimates,” “projects,” “target,” “goal,” “plans,” “objective,” “should” or similar expressions or variations on such expressions. For such statements, the Company claims the protection of the safe harbor for forward-looking statements contained in the Private Securities Litigation Reform Act of 1995. Although the Company believes that the expectations reflected in such forward-looking statements are reasonable, it can give no assurance that such expectations will prove to have been correct. Anadarko undertakes no obligation to publicly update or revise any forward-looking statements whether as a result of new information, future events or otherwise.
These forward-looking statements involve risk and uncertainties. Important factors that could cause actual results to differ materially from the Company’s expectations include, but are not limited to, the following risks and uncertainties:
| • | the Company’s assumptions or expectations regarding energy markets; |
| • | production levels; |
| • | reserve levels; |
| • | operating results; |
| • | competitive conditions; |
| • | technology; |
| • | the availability of capital resources, capital expenditures and other contractual obligations; |
| • | the supply and demand for and the price of natural gas, oil, NGLs and other products or services; |
| • | volatility in the commodity-futures market; |
| • | the weather; |
| • | inflation; |
| • | the availability of goods and services; |
| • | drilling risks; |
| • | future processing volumes and pipeline throughput; |
| • | general economic conditions, either internationally or nationally or in the jurisdictions in which the Company or its subsidiaries are doing business; |
| • | legislative or regulatory changes, including retroactive royalty or production tax regimes, hydraulic-fracturing regulation, derivatives reform, changes in state and federal corporate taxes, environmental regulation, environmental risks and liability under federal, state, foreign and local environmental laws and regulations; |
| • | current and potential legal proceedings, environmental or other obligations arising from Tronox Incorporated (Tronox); |
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| • | the securities, capital or credit markets; |
| • | our ability to repay debt; |
| • | the outcome of any proceedings related to the Algerian exceptional profits tax; and |
| • | other factors discussed below and elsewhere in this Form 10-K and in the Company’s other public filings, press releases and discussions with Company management. |
Oil, natural-gas and NGLs prices are volatile. A substantial or extended decline in prices could adversely affect our financial condition and results of operations.
Prices for oil, natural gas and NGLs can fluctuate widely. Our revenues, operating results and future rate of growth are highly dependent on the prices we receive for our oil, natural gas and NGLs. Historically, the markets for oil, natural gas and NGLs have been volatile and may continue to be volatile in the future. The factors influencing the prices of oil, natural gas and NGLs are beyond our control. These factors include, among others:
| • | domestic and worldwide supply of, and demand for, oil, natural gas and NGLs; |
| • | volatile trading patterns in the commodity-futures markets; |
| • | the cost of exploring for, developing, producing, transporting and marketing oil, natural gas and NGLs; |
| • | weather conditions; |
| • | the ability of the members of the Organization of Petroleum Exporting Countries (OPEC) and other producing nations to agree to and maintain production levels; |
| • | the worldwide military and political environment, uncertainty or instability resulting from the escalation or additional outbreak of armed hostilities or further acts of terrorism in the United States, or elsewhere; |
| • | the effect of worldwide energy conservation efforts; |
| • | the price and availability of alternative and competing fuels; |
| • | the price and level of foreign imports of oil, natural gas and NGLs; |
| • | domestic and foreign governmental regulations and taxes; |
| • | the proximity to, and capacity of, natural-gas pipelines and other transportation facilities; and |
| • | general economic conditions worldwide. |
The long-term effect of these and other factors on the prices of oil, natural gas and NGLs are uncertain. Prolonged or substantial declines in these commodity prices may have the following effects on our business:
| • | adversely affecting our financial condition, liquidity, ability to finance planned capital expenditures and results of operations; |
| • | reducing the amount of oil, natural gas and NGLs that we can produce economically; |
| • | causing us to delay or postpone some of our capital projects; |
| • | reducing our revenues, operating income and cash flows; |
| • | reducing the amounts of our estimated proved oil and natural-gas reserves; |
| • | reducing the carrying value of our oil and natural-gas properties; |
| • | reducing the standardized measure of discounted future net cash flows relating to oil and natural-gas reserves; and |
| • | limiting our access to sources of capital, such as equity and long-term debt. |
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Our domestic operations are subject to governmental risks that may impact our operations.
Our domestic operations have been, and at times in the future may be, affected by political developments and are subject to complex federal, state, tribal, local and other laws and regulations such as restrictions on production, permitting, changes in taxes, deductions, royalties and other amounts payable to governments or governmental agencies, price or gathering-rate controls, hydraulic fracturing and environmental protection regulations. In order to conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state, tribal and local governmental authorities. We may incur substantial costs in order to maintain compliance with these existing laws and regulations. In addition, our costs of compliance may increase if existing laws, including environmental and tax laws, and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations. For example, currently proposed federal legislation, that, if adopted, could adversely affect our business, financial condition and results of operations, includes the following:
| • | Climate Change. Climate-change legislation establishing a “cap-and-trade” plan for green-house gases (GHGs) has been approved by the U.S. House of Representatives. It is not possible at this time to predict whether or when the U.S. Senate may act on climate-change legislation. The U.S. Environmental Protection Agency (EPA) has also taken recent action related to GHGs. Based on recent developments, the EPA now purports to have a basis to begin regulating emissions of GHGs under existing provisions of the federal Clean Air Act. |
| • | Taxes. The U.S. President’s Fiscal Year 2011 Budget Proposal includes provisions that would, if enacted, make significant changes to United States tax laws. These changes include, but are not limited to, (i) eliminating the immediate deduction for intangible drilling and development costs, (ii) eliminating the deduction from income for domestic production activities relating to oil and natural-gas exploration and development, and (iii) implementing certain international tax reforms. |
| • | Hydraulic Fracturing. The U.S. Congress is currently considering legislation to amend the federal Safe Drinking Water Act to require the disclosure of chemicals used by the oil and natural-gas industry in the hydraulic-fracturing process. Currently, regulation of hydraulic fracturing is primarily conducted at the state level through permitting and other compliance requirements. This legislation, if adopted, could establish an additional level of regulation and permitting at the federal level. |
| • | Derivatives. The U.S. Congress is currently considering derivatives reform legislation focusing on expanding Federal regulation surrounding the use of financial derivative instruments, including credit default swaps, commodity derivatives and other over-the-counter derivatives. Among the recommendations included in the proposals are the requirements for centralized clearing or settling of such derivatives as well as the expansion of collateral margin requirements for certain derivative market participants. |
Our debt and other financial commitments may limit our financial and operating flexibility.
As of December 31, 2009, our total debt was approximately $12.7 billion, which included a $1.6 billion note payable from a midstream subsidiary to a related party. We also have various commitments for operating leases, drilling contracts and transportation and purchase obligations for services and products. Our financial commitments could have important consequences to our business. For example, they could:
| • | increase our vulnerability to general adverse economic and industry conditions; |
| • | limit our ability to fund future working capital and capital expenditures, to engage in future acquisitions or development activities, or to otherwise realize the value of our assets and opportunities fully because of the need to dedicate a substantial portion of our cash flow from operations to payments on our debt or to comply with any restrictive terms of our debt; |
| • | limit our flexibility in planning for, or reacting to, changes in the industry in which we operate; and |
| • | place us at a competitive disadvantage compared to our competitors that have less debt and fewer financial commitments. |
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A downgrade in our credit rating could negatively impact our cost of and ability to access capital.
As of December 31, 2009, Standard and Poor’s (S&P) and Moody’s Investors Service (Moody’s) rated our debt at “BBB-” and “Baa3,” respectively, both with a stable outlook. Although we are not aware of any current plans of S&P or Moody’s to lower their respective ratings on our debt, we cannot be assured that our credit ratings will not be downgraded. A downgrade in our credit ratings could negatively impact our cost of capital or our ability to effectively execute aspects of our strategy. If we were to be downgraded, it could be difficult for us to raise debt in the public debt markets and the cost of that new debt could be much higher than our outstanding debt. The only outstanding debt we have that contains credit-rating-downgrade triggers that would accelerate the maturity date of the outstanding debt is a $1.6 billion midstream note held by one of our subsidiaries, the maturity of which could accelerate if our senior unsecured credit rating were to be rated below BB- by S&P or Ba3 by Moody’s. The $1.6 billion midstream note is unconditionally guaranteed by Anadarko and, jointly and severally, by certain midstream subsidiaries. In addition, a downgrade in our credit ratings to below investment grade could result in additional collateralization requirements related to financial derivative liabilities with certain counterparties. At December 31, 2009, the Company had liabilities of $146 million subject to credit-rating-downgrade triggers. See Note 8—Derivative Instruments in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.
We are, and in the future may become, involved in legal proceedings related to Tronox and, as a result, may incur substantial costs in connection with those proceedings.
Prior to its acquisition by Anadarko, Kerr-McGee, through an initial public offering and spin-off transaction, disposed of its chemical manufacturing business. A new publicly traded corporation, Tronox, resulted from this transaction. After the Tronox initial public offering and spin off, Kerr-McGee was acquired by Anadarko and as a result became a subsidiary of Anadarko. Under the terms of a Master Separation Agreement, which was entered into in connection with the Tronox initial public offering, Kerr-McGee agreed to reimburse Tronox for certain qualifying environmental-remediation costs associated with those businesses, subject to certain limitations and conditions and up to a maximum aggregate amount of $100 million. However, as described below, Tronox and third parties have claimed that Kerr-McGee and Anadarko have additional liability for costs allegedly attributable to the facilities and operations owned by Tronox and for Kerr-McGee’s activities prior to the date Anadarko acquired Kerr-McGee.
In January 2009, Tronox and certain of its subsidiaries filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the Southern District of New York. In connection with these bankruptcy cases, Tronox filed a lawsuit against Anadarko and Kerr-McGee asserting a number of claims, including claims for actual and constructive fraudulent conveyance. Tronox alleges, among other things, that it was insolvent or undercapitalized at the time it was spun off from Kerr-McGee. Tronox seeks to recover an unspecified amount of damages, including interest, from Kerr-McGee and Anadarko as well as punitive damages, and litigation fees and costs. In addition, Tronox seeks to equitably subordinate and/or disallow all claims asserted by the Company in the bankruptcy cases.
The United States filed a motion to intervene in the Tronox lawsuit, asserting that it has an independent cause of action against Anadarko, Kerr-McGee and Tronox under the Federal Debt Collection Procedures Act relating primarily to environmental cleanup obligations allegedly owed to the United States by Tronox. That motion to intervene has been granted, and the United States is now a co-plaintiff against Anadarko and Kerr-McGee in Tronox’s pending bankruptcy litigation.
In addition, a consolidated class action complaint has been filed in the United States District Court for the Southern District of New York on behalf of purported purchasers of Tronox’s equity and debt securities between November 21, 2005 and January 12, 2009 against Kerr-McGee, Anadarko and others. The complaint alleges causes of action arising pursuant to the Securities Exchange Act of 1934 for purported misstatements and omissions regarding, among other things, Tronox’s environmental-remediation and tort claim liabilities. The plaintiffs allege that these purported misstatements and omissions are contained in certain of Tronox’s public filings, including filings made in connection with Tronox’s initial public offering. The plaintiffs seek an unspecified amount of compensatory damages, including interest thereon, as well as litigation fees and costs.
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The adverse resolution of any proceedings related to Tronox could subject us to significant monetary damages and other penalties, which could have a material adverse effect on our business, prospects, results of operations and financial condition.
For additional information regarding the nature and status of these and other material legal proceedings, please see Legal Proceedings under Item 3 of this Form 10-K.
Our proved reserves are estimates. Any material inaccuracies in our reserve estimates or assumptions underlying our reserve estimates could cause the quantities and net present value of our reserves to be overstated or understated.
There are numerous uncertainties inherent in estimating quantities of proved reserves, including many factors beyond our control that could cause the quantities and net present value of our reserves to be overstated. The reserve information included or incorporated by reference in this report represents estimates prepared by our internal engineers. The procedures and methods for estimating the reserves by our internal engineers were reviewed by independent petroleum consultants. Estimation of reserves is not an exact science. Estimates of economically recoverable oil and natural-gas reserves and of future net cash flows necessarily depend upon a number of variable factors and assumptions, any of which may cause these estimates to vary considerably from actual results, such as:
| • | historical production from an area compared with production from similar producing areas; |
| • | assumed effects of regulation by governmental agencies; |
| • | assumptions concerning future oil and natural-gas prices, future operating costs and capital expenditures; and |
| • | estimates of future severance and excise taxes, workover and remedial costs. |
Estimates of reserves based on risk of recovery and estimates of expected future net cash flows prepared by different engineers, or by the same engineers at different times, may vary substantially. Actual production, revenues and expenditures with respect to our reserves will likely vary from estimates, and the variance may be material. The discounted cash flows included in this report should not be construed as the current market value of the estimated oil and natural-gas reserves attributable to our properties. In accordance with SEC requirements effective January 1, 2010, the estimated discounted future net cash flows from proved reserves are based upon average 12-month sales prices using the average beginning-of-month price, while actual future prices and costs may be materially higher or lower.
Failure to replace reserves may negatively affect our business.
Our future success depends upon our ability to find, develop or acquire additional oil and natural-gas reserves that are economically recoverable. Our proved reserves generally decline when reserves are produced, unless we conduct successful exploration or development activities or acquire properties containing proved reserves, or both. We may be unable to find, develop or acquire additional reserves on an economic basis. Furthermore, if oil and natural-gas prices increase, our costs for finding or acquiring additional reserves could also increase.
Poor general economic, business or industry conditions may have a material adverse effect on our results of operations, liquidity and financial condition.
Recently, concerns over inflation, energy costs, geopolitical issues, the availability and cost of credit, the United States mortgage market and a declining real estate market in the United States have contributed to increased economic uncertainty and diminished expectations for the global economy.
These factors, combined with volatile oil, natural-gas and NGLs prices, declining business and consumer confidence, and increased unemployment, have precipitated an economic slowdown and a recession. Concerns
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about global economic conditions have had a significant adverse impact on global financial markets and commodity prices. If the economic climate in the United States or abroad continues to deteriorate, or if an economic recovery is slow or prolonged, demand for petroleum products could continue to diminish or stagnate, which could impact the price at which we can sell our oil, natural gas and NGLs, affect our vendors’, suppliers’ and customers’ ability to continue operations, and ultimately adversely impact our results of operations, liquidity and financial condition.
Our results of operations could be adversely affected by asset impairments.
As a result of mergers and acquisitions, at December 31, 2009 we had approximately $5.3 billion of goodwill on our balance sheet. Goodwill is not amortized, but instead must be tested at least annually for impairment, and more frequently when circumstances indicate likely impairment, by applying a fair-value-based test. Goodwill is considered impaired to the extent that its carrying amount exceeds its implied fair value. Various factors could lead to goodwill impairments that could have a substantial negative effect on our profitability, such as if the Company is unable to replace the value of its depleting asset base or if other adverse events, such as lower sustained oil and gas prices, reduce the fair value of the associated reporting unit.
We are subject to complex laws and regulations relating to environmental protection that can adversely affect the cost, manner and feasibility of doing business.
Our operations and properties are subject to numerous federal, state, tribal, local and foreign laws and regulations relating to environmental protection from the time projects commence until abandonment. These laws and regulations govern, among other things:
| • | the amounts and types of substances and materials that may be released; |
| • | the issuance of permits in connection with exploration, drilling, production and midstream activities; |
| • | the protection of endangered species; |
| • | the release of emissions; |
| • | the discharge and disposition of generated waste materials; |
| • | offshore oil and gas operations; |
| • | the reclamation and abandonment of wells and facility sites; and |
| • | the remediation of contaminated sites. |
In addition, these laws and regulations may impose substantial liabilities for our failure to comply with them or for any contamination resulting from our operations. Future environmental laws and regulations, such as proposed legislation regulating climate change, may negatively impact our industry. The cost of meeting these requirements may have an adverse effect on our financial condition, results of operations and cash flows. For a description of certain environmental proceedings in which we are involved, see Legal Proceedings under Item 3 of this Form 10-K.
We are vulnerable to risks associated with our offshore operations that could negatively impact our operations and financial results.
We conduct offshore operations in the Gulf of Mexico, Ghana, Mozambique, Brazil, China and other countries in West Africa. Our operations and financial results could be significantly impacted by conditions in some of these areas, such as the Gulf of Mexico, because we explore and produce extensively in those areas. As a result of this activity, we are vulnerable to the risks associated with operating offshore, including those relating to:
| • | hurricanes and other adverse weather conditions; |
| • | oil field service costs and availability; |
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| • | compliance with environmental and other laws and regulations; |
| • | terrorist attacks, such as piracy; |
| • | remediation and other costs resulting from oil spills or releases of hazardous materials; and |
| • | failure of equipment or facilities. |
In addition, we are currently conducting some of our exploration in the deep waters (greater than 1,000 feet) of the Gulf of Mexico, where operations are more difficult and costly than in shallower waters. The deep waters in the Gulf of Mexico lack the physical and oilfield service infrastructure present in its shallower waters. As a result, deepwater operations may require a significant amount of time between a discovery and the time that we can market our production, thereby increasing the risk involved with these operations.
Further, production of reserves from reservoirs in the Gulf of Mexico generally declines more rapidly than from reservoirs in many other producing regions of the world. This results in recovery of a relatively higher percentage of reserves from properties in the Gulf of Mexico during the initial few years of production and, as a result, our reserve replacement needs from new prospects may be greater there than for our operations elsewhere. Also, our revenues and return on capital will depend significantly on prices prevailing during these relatively short production periods.
We operate in other countries and are subject to political, economic and other uncertainties.
Our operations outside the United States are based primarily in Algeria, Brazil, China, Cote d’Ivoire, Ghana, Indonesia, Liberia, Mozambique and Sierra Leone. As a result, we face political and economic risks and other uncertainties with respect to our international operations. These risks may include, among other things:
| • | loss of revenue, property and equipment as a result of hazards such as expropriation, war, piracy, acts of terrorism, insurrection and other political risks; |
| • | transparency issues in general and, more specifically, the U.S. Foreign Corrupt Practices Act and other anti-corruption compliance issues; |
| • | increases in taxes and governmental royalties; |
| • | unilateral renegotiation of contracts by governmental entities; |
| • | difficulties enforcing our rights against a governmental agency because of the doctrine of sovereign immunity and foreign sovereignty over international operations; |
| • | changes in laws and policies governing operations of foreign-based companies; |
| • | foreign-exchange restrictions; and |
| • | international monetary fluctuations and changes in the relative value of the U.S. dollar as compared with the currencies of other countries in which we conduct business. |
For example, in 2006, the Algerian parliament approved legislation establishing an exceptional profits tax on foreign companies’ Algerian oil production and issued regulations implementing this legislation. In response to the Algerian government’s imposition of the exceptional profits tax, we notified Sonatrach of our disagreement with the collection of the exceptional profits tax. In February 2009, we initiated arbitration against Sonatrach with regard to the exceptional profits tax. For additional information, see Note 15—Other Taxes of the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.
Our international operations may also be adversely affected by laws and policies of the United States affecting foreign trade and taxation.
Realization of any of the factors listed above could materially and adversely affect our financial position, results of operations and cash flows.
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Our commodity-price-risk management and trading activities may prevent us from benefiting fully from price increases and may expose us to other risks.
To the extent that we engage in commodity-price-risk management activities to protect our cash flow from commodity price declines, we may be prevented from realizing the full benefits of price increases above the levels of the derivative instruments used to manage price risk. In addition, our commodity-price-risk management and trading activities may expose us to the risk of financial loss in certain circumstances, including instances in which:
| • | our production is less than the hedged volumes; |
| • | there is a widening of price basis differentials between delivery points for our production and the delivery point assumed in the hedge arrangement; |
| • | the counterparties to our hedging or other price-risk management contracts fail to perform under those arrangements; or |
| • | a sudden unexpected event materially impacts oil and natural-gas prices. |
The credit risk of financial institutions could adversely affect us.
We have exposure to different counterparties, and we have entered into transactions with counterparties in the financial services industry, including commercial banks, investment banks, insurance companies, investment funds and other institutions. These transactions expose us to credit risk in the event of default of our counterparty. Deterioration in the credit markets may impact the credit ratings of our current and potential counterparties and affect their ability to fulfill their existing obligations to us and their willingness to enter into future transactions with us. We have exposure to these financial institutions through our derivative transactions. In addition, if any lender under our credit facility is unable to fund its commitment, our liquidity will be reduced by an amount up to the aggregate amount of such lender’s commitment under our credit facility.
We may not be insured against all of the operating risks to which our business is exposed.
Our business is subject to all of the operating risks normally associated with the exploration for and production, gathering, processing and transportation of oil and gas, including hurricanes, blowouts, cratering and fire, any of which could result in damage to, or destruction of, oil and natural-gas wells or formations or production facilities and other property and injury to persons. As protection against financial loss resulting from these operating hazards, we maintain insurance coverage, including certain physical damage, employer’s liability, comprehensive general liability and worker’s compensation insurance. However, we are not fully insured against all risks in all aspects of our business, such as political risk, business-interruption risk and risk of major terrorist attacks and piracy. The occurrence of a significant event against which we are not fully insured could have a material adverse effect on our financial position.
Material differences between the estimated and actual timing of critical events may affect the completion of and commencement of production from development projects.
We are involved in several large development projects. Key factors that may affect the timing and outcome of such projects include:
| • | project approvals by joint-venture partners; |
| • | timely issuance of permits and licenses by governmental agencies; |
| • | weather conditions; |
| • | manufacturing and delivery schedules of critical equipment; and |
| • | commercial arrangements for pipelines and related equipment to transport and market hydrocarbons. |
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Delays and differences between estimated and actual timing of critical events may affect the forward-looking statements related to large development projects.
The oil and gas exploration and production industry is very competitive, and some of our exploration and production competitors have greater financial and other resources than we do.
The oil and gas business is highly competitive in the search for and acquisition of reserves and in the gathering and marketing of oil and gas production. Our competitors include national oil companies, major oil and gas companies, independent oil and gas companies, individual producers, gas marketers and major pipeline companies, as well as participants in other industries supplying energy and fuel to industrial, commercial and individual consumers. Some of our competitors may have greater and more diverse resources upon which to draw than we do. If we are not successful in our competition for oil and gas reserves or in our marketing of production, our financial condition and results of operations may be adversely affected.
The high cost or unavailability of drilling rigs, equipment, supplies, personnel and other oil field services could adversely affect our ability to execute our exploration and development plans on a timely basis and within our budget, which could have a material adverse effect on our business, financial condition or results of operations.
Our industry is cyclical and, from time to time, there is a shortage of drilling rigs, equipment, supplies or qualified personnel. During these periods, the costs of rigs, equipment, supplies and personnel are substantially greater and their availability may be limited. Additionally, these services may not be available on commercially reasonable terms. The high cost or unavailability of drilling rigs, equipment, supplies, personnel and other oil field services could adversely affect our ability to execute our exploration and development plans on a timely basis and within our budget, which could have a material adverse effect on our business, financial condition or results of operations.
Our drilling activities may not be productive.
Drilling for oil and natural gas involves numerous risks, including the risk that we will not encounter commercially productive oil or gas reservoirs. The costs of drilling, completing and operating wells are often uncertain, and drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including:
| • | unexpected drilling conditions; |
| • | pressure or irregularities in formations; |
| • | equipment failures or accidents; |
| • | fires, explosions, blow-outs and surface cratering; |
| • | marine risks such as capsizing, collisions and hurricanes; |
| • | title problems; |
| • | other adverse weather conditions; and |
| • | shortages or delays in the delivery of equipment. |
Certain of our future drilling activities may not be successful and, if unsuccessful, this failure could have an adverse effect on our future results of operations and financial condition. While all drilling, whether developmental or exploratory, involves these risks, exploratory drilling involves greater risks of dry holes or failure to find commercial quantities of hydrocarbons. Because of the percentage of our capital budget devoted to high-risk exploratory projects, it is likely that we will continue to experience significant exploration and dry hole expenses.
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We have limited control over the activities on properties we do not operate.
Other companies operate some of the properties in which we have an interest. We have limited ability to influence or control the operation or future development of these non-operated properties or the amount of capital expenditures that we are required to fund with respect to them. Our dependence on the operator and other working interest owners for these projects and our limited ability to influence or control the operation and future development of these properties could materially adversely affect the realization of our targeted returns on capital and lead to unexpected future costs.
Our ability to sell our natural-gas and crude-oil production could be materially harmed if we fail to obtain adequate services such as transportation.
The marketability of our production depends in part upon the availability, proximity and capacity of pipeline facilities and tanker transportation. If any of the pipelines or tankers become unavailable, we would be required to find a suitable alternative to transport the gas and oil, which could increase our costs and/or reduce the revenues we might obtain from the sale of the gas and oil.
Provisions in our corporate documents and Delaware law could delay or prevent a change of control of Anadarko, even if that change would be beneficial to our stockholders.
Our restated certificate of incorporation and by-laws contain provisions that may make a change of control of Anadarko difficult, even if it may be beneficial to our stockholders, including provisions governing the classification, nomination and removal of directors, prohibiting stockholder action by written consent and regulating the ability of our stockholders to bring matters for action before annual stockholder meetings, and the authorization given to our Board of Directors to issue and set the terms of preferred stock.
In addition, Section 203 of the Delaware General Corporation Law imposes restrictions on mergers and other business combinations between us and any holder of 15% or more of our outstanding common stock.
We may reduce or cease to pay dividends on our common stock.
We can provide no assurance that we will continue to pay dividends at the current rate or at all. The amount of cash dividends, if any, to be paid in the future will depend upon their declaration by our Board of Directors and upon our financial condition, results of operations, cash flow, the levels of our capital and exploration expenditures, our future business prospects and other related matters that our Board of Directors deems relevant.
The loss of key members of our management team, or difficulty attracting and retaining experienced technical personnel, could reduce our competitiveness and prospects for future success.
The successful implementation of our strategies and handling of other issues integral to our future success will depend, in part, on our experienced management team. The loss of key members of our management team, including James T. Hackett, our Chairman and Chief Executive Officer, could have an adverse effect on our business. We entered into an employment agreement with Mr. Hackett to secure his employment with us. We do not carry key man insurance. Our exploratory drilling success and the success of other activities integral to our operations will depend, in part, on our ability to attract and retain experienced explorationists, engineers and other professionals. Competition for such professionals is intense. If we cannot retain our technical personnel or attract additional experienced technical personnel, our ability to compete could be harmed.
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| Item 1B. | Unresolved Staff Comments |
The Company has no outstanding or unresolved SEC staff comments.
| Item 3. | Legal Proceedings |
GENERAL The Company is a defendant in a number of lawsuits and is involved in governmental proceedings arising in the ordinary course of business, including, but not limited to, royalty claims, contract claims and environmental claims. The Company has also been named as a defendant in various personal injury claims, including claims by employees of third-party contractors alleging exposure to asbestos, silica and benzene while working at refineries (previously owned by predecessors of acquired companies) located in Texas, California and Oklahoma. While the ultimate outcome and impact on the Company cannot be predicted with certainty, management believes that the resolution of these proceedings will not have a material adverse effect on the consolidated financial position, results of operations or cash flow of the Company.
TRONOX PROCEEDINGS In January 2009, Tronox and certain of its subsidiaries filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the Southern District of New York. In connection with those bankruptcy cases, Tronox filed a lawsuit against Anadarko and Kerr-McGee asserting a number of claims, including claims for actual and constructive fraudulent conveyance. Tronox alleges, among other things, that it was insolvent or undercapitalized at the time it was spun off from Kerr-McGee. Tronox seeks, among other things, to recover an unspecified amount of damages, including interest, from Kerr-McGee and Anadarko as well as punitive damages, and litigation fees and costs. In addition, Tronox seeks to equitably subordinate and/or disallow all claims asserted by Anadarko and Kerr-McGee in the bankruptcy cases. Anadarko and Kerr-McGee have moved to dismiss the complaint in its entirety. That motion has been briefed and argued, and is currently awaiting decision by the Court.
The United States filed a motion to intervene in the Tronox lawsuit, asserting that it has an independent cause of action against Anadarko, Kerr-McGee and Tronox under the Federal Debt Collection Procedures Act relating primarily to environmental cleanup obligations allegedly owed to the United States by Tronox. That motion to intervene has been granted, and the United States is now a co-plaintiff against Anadarko and Kerr-McGee in Tronox’s pending bankruptcy litigation. Anadarko and Kerr-McGee have moved to dismiss the United States’ intervention complaint, but that motion currently has been stayed by order of the Court.
Tronox and the United States have entered into an agreement that contemplates, among other things, that the United States will receive an 88% interest in any recovery from the claims against Anadarko and Kerr-McGee that Tronox has asserted in the litigation described above. The remaining 12% interest in any recovery will be distributed to certain persons who have filed tort claims against the Tronox debtors in the bankruptcy cases. That agreement is subject to certain contingencies, including various levels of governmental approvals, definitive and final documentation, and final approval from the Court. That agreement could be opposed by other interested parties, including Anadarko and Kerr-McGee. Therefore, it is unclear whether this or any other such agreement between Tronox and the United States will be approved or implemented, or what, if any, effect such an agreement might have on the course, cost or outcome of the bankruptcy litigation.
In addition, a consolidated class action complaint has been filed in the United States District Court for the Southern District of New York on behalf of purported purchasers of Tronox’s equity and debt securities between November 21, 2005 and January 12, 2009 against Kerr-McGee, Anadarko and others. The complaint alleges causes of action arising pursuant to the Securities Exchange Act of 1934 for purported misstatements and omissions regarding, among other things, Tronox’s environmental-remediation and tort claim liabilities. The plaintiffs allege that these purported misstatements and omissions are contained in certain of Tronox’s public filings, including in connection with Tronox’s initial public offering. The plaintiffs seek an unspecified amount of compensatory damages, including interest thereon, as well as litigation fees and costs.
These proceedings are at a very early stage and the Company intends to defend itself vigorously.
OTHER MATTERS The Company is subject to other legal proceedings, claims and liabilities which arise in the ordinary course of its business. In the opinion of Anadarko, the liability with respect to these actions will not have a material effect on the consolidated financial position, results of operations or cash flow of the Company.
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| Item 4. | Submission of Matters to a Vote of Security Holders |
There were no matters submitted to a vote of security holders during the fourth quarter of 2009.
EXECUTIVE OFFICERS OF THE REGISTRANT
| Name |
Age at End of 2010 |
Position | ||
| James T. Hackett |
56 | Chairman of the Board and Chief Executive Officer | ||
| R. A. Walker |
53 | President and Chief Operating Officer | ||
| Robert P. Daniels |
51 | Senior Vice President, Worldwide Exploration | ||
| Robert G. Gwin |
47 | Senior Vice President, Finance and Chief Financial Officer | ||
| Charles A. Meloy |
50 | Senior Vice President, Worldwide Operations | ||
| Robert K. Reeves |
53 | Senior Vice President, General Counsel and Chief Administrative Officer | ||
| M. Cathy Douglas |
54 | Vice President and Chief Accounting Officer |
Mr. Hackett was named Chief Executive Officer in December 2003 and assumed the additional role of Chairman of the Board in January 2006. He also served as President from December 2003 to February 2010. Prior to joining Anadarko, he served as President and Chief Operating Officer of Devon Energy Corporation following its merger with Ocean Energy, Inc. in April 2003. Mr. Hackett served as President and Chief Executive Officer of Ocean Energy, Inc. from March 1999 to April 2003 and as Chairman of the Board from January 2000 to April 2003. He currently serves as a director of Fluor Corporation and Halliburton Company and serves as Chairman of the Board of the Federal Reserve Bank of Dallas.
Mr. Walker was named Chief Operating Officer in March 2009 and assumed the additional role of President in February 2010. He previously served as Senior Vice President, Finance and Chief Financial Officer from September 2005 until his appointment as Chief Operating Officer. Prior to joining Anadarko, he served as Managing Director for the Global Energy Group of UBS Investment Bank from 2003 to 2005. He has served as a director of Temple- Inland, Inc. since November 2008. Since August 2007, he has also served as a director of Western Gas Holdings, LLC, the general partner of WES, and served as the general partner’s Chairman of the Board from August 2007 to September 2009.
Mr. Daniels was named Senior Vice President, Worldwide Exploration in December 2006, Senior Vice President, Exploration and Production in 2004 and Vice President, Canada in 2001. Prior to this position, he served in various managerial roles in the Exploration Department for Anadarko Algeria Company, LLC. He has worked for the Company since 1985.
Mr. Gwin was named Senior Vice President, Finance and Chief Financial Officer in March 2009 and had previously served as Senior Vice President since March 2008. He also has served as Chairman of the Board of Western Gas Holdings, LLC since October 2009 and as a director since August 2007. Mr. Gwin also served as President of Western Gas Holdings, LLC from August 2007 to September 2009 and as Chief Executive Officer of Western Gas Holdings, LLC from August 2007 to January 2010. He joined Anadarko in January 2006 as Vice President, Finance and Treasurer. Prior to joining Anadarko, he served as President and CEO of Prosoft Learning Corporation from November 2002 to November 2004 and as Chairman from November 2002 to February 2006, and prior to that served as its Chief Financial Officer from August 2000 to November 2002. Previously, Mr. Gwin spent 10 years at Prudential Capital Group in merchant banking roles of increasing responsibility, including serving as Managing Director with responsibility for the firm’s energy investments worldwide.
Mr. Meloy was named Senior Vice President, Worldwide Operations in December 2006 and had served as Senior Vice President, Gulf of Mexico and International Operations since the acquisition of Kerr-McGee in August 2006. Prior to joining Anadarko, he served Kerr-McGee as Vice President of Exploration and Production from 2005 to 2006, Vice President of Gulf of Mexico Exploration, Production and Development from 2004 to 2005, Vice President and Managing Director of Kerr-McGee North Sea (U.K.) Limited from 2002 to 2004 and Vice President of Gulf of Mexico Deep Water from 2000 to 2002. Mr. Meloy has also served as a director of Western Gas Holdings, LLC since February 2009.
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Mr. Reeves was named Senior Vice President, General Counsel and Chief Administrative Officer in February 2007. He had previously served as Senior Vice President, Corporate Affairs & Law and Chief Governance Officer since 2004. Prior to joining Anadarko, he served as Executive Vice President, Administration and General Counsel of North Sea New Ventures from 2003 to 2004, and as Executive Vice President, General Counsel and Secretary of Ocean Energy, Inc. and its predecessor companies from 1997 to 2003. He has also served as a director of Key Energy Services, Inc., a publicly traded oilfield services company, since October 2007, and as a director of Western Gas Holdings, LLC since August 2007.
Ms. Douglas was named Vice President and Chief Accounting Officer in November 2008 and had served as Corporate Controller from September 2007 to March 2009. She served as Assistant Controller from July 2006 to September 2007. Ms. Douglas also served as Director, Accounting, Policy and Coordination from October 2006 to September 2007 and Financial Reporting and Policy Manager from January 2003 to October 2006. She joined Anadarko in 1979.
Officers of Anadarko are elected at an organizational meeting of the Board of Directors following the annual meeting of stockholders, which is expected to occur on May 18, 2010, and hold office until their successors are duly elected and shall have qualified. There are no family relationships between any directors or executive officers of Anadarko.
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PART II
| Item 5. | Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities |
As of January 31, 2010, there were approximately 15,680 record holders of Anadarko common stock. The common stock of Anadarko is traded on the New York Stock Exchange. The following shows information regarding the closing market price of and dividends declared and paid on the Company’s common stock by quarter for 2009 and 2008.
| First Quarter |
Second Quarter |
Third Quarter |
Fourth Quarter | |||||||||
| 2009 |
||||||||||||
| Market Price |
||||||||||||
| High |
$ | 43.84 | $ | 51.96 | $ | 64.85 | $ | 69.36 | ||||
| Low |
$ | 31.15 | $ | 40.52 | $ | 41.66 | $ | 57.11 | ||||
| Dividends |
$ | 0.09 | $ | 0.09 | $ | 0.09 | $ | 0.09 | ||||
| 2008 |
||||||||||||
| Market Price |
||||||||||||
| High |
$ | 66.75 | $ | 79.86 | $ | 74.47 | $ | 48.21 | ||||
| Low |
$ | 54.02 | $ | 62.56 | $ | 44.86 | $ | 27.17 | ||||
| Dividends |
$ | 0.09 | $ | 0.09 | $ | 0.09 | $ | 0.09 | ||||
The amount of future common stock dividends will depend on earnings, financial condition, capital requirements and other factors, and will be determined by the Board of Directors on a quarterly basis. For additional information, see Liquidity and Capital Resources—Uses of Cash—Dividends under Item 7 and Note 11—Stockholders’ Equity and Note 12—Stock-Based Compensation in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.
Common Stock Repurchase Table In August 2008, the Company announced a share-repurchase program to purchase up to $5 billion in shares of common stock. The program replaces a prior share-repurchase program and is authorized to extend through August 2011; however, the program does not obligate Anadarko to acquire any specific number of shares and may be discontinued at any time. The following table sets forth information with respect to repurchases by the Company of its shares of common stock during the fourth quarter of 2009.
| Period |
Total number of shares purchased(1) |
Average price paid per share |
Total number of shares purchased as part of publicly announced plans or programs |
Approximate dollar value of shares that may yet be purchased under the plans or programs | ||||||
| October 1-31 |
1,010 | $ | 61.96 | — | ||||||
| November 1-30 |
1,540 | $ | 61.80 | — | ||||||
| December 1-31 |
291,374 | $ | 61.37 | — | ||||||
| Fourth Quarter 2009 |
293,924 | $ | 61.37 | — | $ | 4,400,000,000 | ||||
| (1) | During the fourth quarter of 2009, all purchased shares related to stock received by the Company for the payment of withholding taxes due on employee stock plan share issuances, which are not within the scope of the Company’s share-repurchase program. |
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PERFORMANCE GRAPH
The following performance graph and related information shall not be deemed “soliciting material” or to be “filed” with the SEC, nor shall such information be incorporated by reference into any future filing under the Securities Act of 1933 or Securities Exchange Act of 1934, each as amended, except to the extent that the Company specifically incorporates it by reference into such filing.
The following graph compares the cumulative five-year total return to stockholders on Anadarko’s common stock relative to the cumulative total returns of the S&P 500 index and two 11-company peer groups. The companies included in the 2009 peer group are Apache Corporation, Chevron Corporation, ConocoPhillips, Devon Energy Corporation, EOG Resources, Inc., Hess Corporation, Marathon Oil Corporation, Noble Energy, Inc., Occidental Petroleum Corporation, Pioneer Natural Resources Company and Plains Exploration and Production Company. The companies included in the 2008 peer group are Apache Corporation, ConocoPhillips, Devon Energy Corporation, EnCana Corporation, EOG Resources Inc., Hess Corporation, Marathon Oil Corporation, Noble Energy Inc., Occidental Petroleum Corporation, Pioneer Natural Resources Company and Talisman Energy Inc. The peer-group change from the 2008 peer group to the 2009 peer group was based on the Company’s decision to focus the comparison on U.S.-based companies which vary in size – some larger, some smaller than Anadarko – as well as to remove those companies whose equity performance may be affected by factors that do not affect Anadarko’s equity performance.
Comparison of 5 Year Cumulative Total Return Among
Anadarko Petroleum Corporation, the S&P 500 Index,
the 2008 Peer Group and the 2009 Peer Group
An investment of $100 (with reinvestment of all dividends) is assumed to have been made in the Company’s common stock, in the index and in the peer groups on December 31, 2004 and its relative performance is tracked through December 31, 2009.
| Fiscal Year Ended December 31 | 2004 | 2005 | 2006 | 2007 | 2008 | 2009 | ||||||
| Anadarko Petroleum Corporation |
100.00 | 147.42 | 136.46 | 207.47 | 122.58 | 200.03 | ||||||
| S&P 500 |
100.00 | 104.91 | 121.48 | 128.16 | 80.74 | 102.11 | ||||||
| 2008 Peer Group |
100.00 | 151.75 | 174.66 | 245.08 | 157.48 | 199.46 | ||||||
| 2009 Peer Group |
100.00 | 132.64 | 164.57 | 225.58 | 157.14 | 184.32 |
31
Table of Contents
| Item 6. | Selected Financial Data |
| Summary Financial Information* | ||||||||||||||||||
| millions except per share amounts | 2009 | 2008 | 2007 | 2006 | 2005 | |||||||||||||
| Sales Revenues(1) |
$ | 8,210 | $ | 14,079 | $ | 11,656 | $ | 10,116 | $ | 6,197 | ||||||||
| Gains (Losses) on Divestitures and Other, net |
133 | 1,083 | 4,760 | 114 | 111 | |||||||||||||
| Reversal of Accrual for DWRRA Dispute |
657 | — | — | — | — | |||||||||||||
| Total Revenues and Other |
9,000 | 15,162 | 16,416 | 10,230 | 6,308 | |||||||||||||
| Operating Income |
377 | 5,601 | 7,871 | 4,381 | 3,398 | |||||||||||||
| Income (Loss) from Continuing Operations |
(103 | ) | 3,220 | 3,767 | 2,471 | 1,970 | ||||||||||||
| Income from Discontinued Operations, net of taxes |
— | 63 | 11 | 2,275 | 356 | |||||||||||||
| Net Income (Loss) Attributable to Common Stockholders |
(135 | ) | 3,260 | 3,778 | 4,746 | 2,326 | ||||||||||||
| Per Common Share: |
||||||||||||||||||
| Income (Loss) from Continuing Operations—Basic |
$ | (0.28 | ) | $ | 6.79 | $ | 8.01 | $ | 5.33 | $ | 4.17 | |||||||
| Income (Loss) from Continuing Operations—Diluted |
$ | (0.28 | ) | $ | 6.78 | $ | 7.99 | $ | 5.31 | $ | 4.14 | |||||||
| Income from Discontinued Operations—Basic |
$ | — | $ | 0.13 | $ | 0.02 | $ | 4.91 | $ | 0.75 | ||||||||
| Income from Discontinued Operations—Diluted |
$ | — | $ | 0.13 | $ | 0.02 | $ | 4.88 | $ | 0.75 | ||||||||
| Net Income (Loss) Attributable to Common Stockholders—Basic |
$ | (0.28 | ) | $ | 6.92 | $ | 8.03 | $ | 10.24 | $ | 4.92 | |||||||
| Net Income (Loss) Attributable to Common Stockholders—Diluted |
$ | (0.28 | ) | $ | 6.91 | $ | 8.01 | $ | 10.19 | $ | 4.89 | |||||||
| Dividends |
$ | 0.36 | $ | 0.36 | $ | 0.36 | $ | 0.36 | $ | 0.36 | ||||||||
| Average Number of Common Shares Outstanding—Basic |
480 | 465 | 465 | 460 | 470 | |||||||||||||
| Average Number of Common Shares Outstanding—Diluted |
480 | 466 | 467 | 463 | 474 | |||||||||||||
| Cash Provided by Operating Activities—Continuing Operations |
$ | 3,926 | $ | 6,447 | $ | 2,766 | $ | 4,671 | $ | 3,221 | ||||||||
| Cash Provided by (Used in) Operating Activities—Discontinued Operations |
— | (5 | ) | 134 | (178 | ) | 591 | |||||||||||
| Net Cash Provided by Operating Activities |
3,926 | 6,442 | 2,900 | 4,493 | 3,812 | |||||||||||||
| Capital Expenditures |
$ | 4,558 | $ | 4,881 | $ | 3,990 | $ | 4,212 | $ | 2,644 | ||||||||
| Current Debt |
$ | — | $ | 1,472 | $ | 1,396 | $ | 11,471 | $ | 80 | ||||||||
| Long-term Debt |
11,149 | 9,128 | 11,151 | 11,520 | 3,547 | |||||||||||||
| Midstream subsidiary note payable to a related party |
1,599 | 1,739 | 2,200 | — | — | |||||||||||||
| Total Debt |
$ | 12,748 | $ | 12,339 | $ | 14,747 | $ | 22,991 | $ | 3,627 | ||||||||
| Total Stockholders’ Equity |
19,928 | 18,795 | 16,364 | 12,403 | 8,649 | |||||||||||||
| Total Assets |
$ | 50,123 | $ | 48,923 | $ | 48,451 | $ | 54,964 | $ | 18,902 | ||||||||
| Annual Sales Volumes: |
||||||||||||||||||
| Continuing Operations |
||||||||||||||||||
| Gas (Bcf) |
809 | 750 | 698 | 558 | 414 | |||||||||||||
| Oil and Condensate (MMBbls) |
68 | 67 | 79 | 70 | 57 | |||||||||||||
| Natural Gas Liquids (MMBbls) |
17 | 14 | 16 | 15 | 13 | |||||||||||||
| Total (MMBOE)** |
220 | 206 | 211 | 178 | 139 | |||||||||||||
| Discontinued Operations (MMBOE) |
— | — | — | 17 | 20 | |||||||||||||
| Total (MMBOE)** |
220 | 206 | 211 | 195 | 159 | |||||||||||||
| Average Daily Sales Volumes: |
||||||||||||||||||
| Continuing Operations |
||||||||||||||||||
| Gas (MMcf/d) |
2,217 | 2,049 | 1,912 | 1,529 | 1,136 | |||||||||||||
| Oil and Condensate (MBbls/d) |
187 | 182 | 215 | 193 | 155 | |||||||||||||
| Natural Gas Liquids (MBbls/d) |
47 | 39 | 43 | 42 | 36 | |||||||||||||
| Total (MBOE/d) |
604 | 563 | 577 | 489 | 380 | |||||||||||||
| Discontinued Operations (MBOE/d) |
— | — | — | 46 | 55 | |||||||||||||
| Total (MBOE/d) |
604 | 563 | 577 | 535 | 435 | |||||||||||||
| Reserves: |
||||||||||||||||||
| Continuing Operations |
||||||||||||||||||
| Gas Reserves (Tcf) |
7.8 | 8.1 | 8.5 | 10.5 | 6.6 | |||||||||||||
| Oil Reserves (MMBbls) |
1,010 | 926 | 1,014 | 1,264 | 1,090 | |||||||||||||
| Total Reserves (MMBOE) |
2,304 | 2,277 | 2,431 | 3,011 | 2,187 | |||||||||||||
| Discontinued Operations (MMBOE) |
— | — | — | — | 262 | |||||||||||||
| Total Reserves (MMBOE) |
2,304 | 2,277 | 2,431 | 3,011 | 2,449 | |||||||||||||
| Number of Employees |
4,300 | 4,300 | 4,000 | 5,200 | 3,300 | |||||||||||||
| (1) | Commodity derivative activity previously reported in Sales Revenues, has been reclassified to Other (income) expense. See Basis of Presentation in Note 1—Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K. |
| * | Consolidated for Anadarko and its subsidiaries. Certain amounts for prior years have been reclassified to conform to the current presentation. Factors that materially affect the comparability of this information are disclosed in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Item 7 of this Form 10-K. |
| ** | Natural gas is converted to equivalent barrels at the rate of 6,000 cubic feet of gas per barrel. |
| Table of Measures |
||
| Bcf—Billion cubic feet |
MMBOE—Million barrels of oil equivalent | |
| MBbls/d—Thousand barrels per day |
MMcf/d—Million cubic feet per day | |
| MBOE/d—Thousand barrels of oil equivalent per day |
Tcf—Trillion cubic feet | |
| MMBbls—Million barrels |
||
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Table of Contents
| Item 7. | Management’s Discussion and Analysis of Financial Condition and Results of Operations |
The following discussion should be read together with the Consolidated Financial Statements and the Notes to Consolidated Financial Statements, which are included in this report in Item 8, and the information set forth in Risk Factors under Item 1A.
OVERVIEW
Anadarko Petroleum Corporation is among the world’s largest independent oil and natural-gas exploration and production companies. Anadarko is engaged in the exploration, development, production and marketing of natural gas, crude oil, condensate and NGLs. The Company also engages in the gathering, processing, treating and transporting of natural gas. The Company’s operations are located in the United States, Algeria, Brazil, China, Cote d’Ivoire, Ghana, Indonesia, Mozambique, Sierra Leone and several other countries.
Anadarko achieved its key operational objectives in 2009 by increasing sales volumes by 7% year-over-year, while spending 35% less on near-term projects, reducing lease operating expenses per unit by more than 20% year-over-year, and adding 314 million barrels of oil equivalent (BOE) of proved reserves before price revisions and divestitures. Anadarko ended 2009 with approximately $3.5 billion of cash on hand and retains the availability of its undrawn $1.3 billion revolving credit agreement (RCA), along with access to credit markets. Management expects this liquidity position and cash flow from operations to position the Company to satisfy its 2010 operational objectives and capital commitments.
MISSION AND STRATEGY
Anadarko’s mission is to deliver a competitive and sustainable rate of return to shareholders by exploring for, acquiring and developing oil and natural-gas resources vital to the world’s health and welfare. Anadarko employs the following strategy to achieve this mission:
| • | identify and commercialize resources; |
| • | explore in high-potential, proven basins; |
| • | employ a global business development approach; and |
| • | ensure financial discipline and flexibility. |
Developing a portfolio of primarily unconventional resources provides the Company a stable base of capital-efficient, predictable and repeatable development opportunities which, in turn, positions the Company for consistent growth at competitive rates.
Exploring in high-potential, proven and emerging basins worldwide provides the Company with differential growth. Anadarko’s exploration success creates value by expanding its future resource potential, while providing the flexibility to manage risk by monetizing discoveries.
Anadarko’s global business development approach transfers core skills across the globe to discover and develop world-class resources that are accretive to the Company’s net asset value. These resources help form an optimized, global portfolio where both surface and subsurface risks are actively managed.
A strong balance sheet is essential for the development of the Company’s assets and the ability to manage through commodity price cycles. Maintaining financial discipline enables the Company to capitalize on the flexibility of its global portfolio, while allowing the Company to pursue new strategic and tactical growth opportunities.
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Table of Contents
OPERATING HIGHLIGHTS
Significant 2009 operational highlights by area include:
United States Onshore
| • | The Company’s Rocky Mountain region achieved total-year production of approximately 250 thousand barrels of oil equivalent per day (MBOE/d), representing a 15% increase over 2008. |
| • | The Company reduced spud-to-spud cycle times in its onshore operating areas by 30% year-over-year relative to 2008. |
| • | In the Marcellus shale, the Company spud 11 and completed six operated horizontal wells and participated in 40 new horizontal wells and 12 completions as a non-operating partner. |
Gulf of Mexico
| • | The Company’s Gulf of Mexico region achieved production of 151 MBOE/d, representing a 13% sales-volume increase over 2008. |
| • | The Company announced five deepwater discoveries in the Gulf of Mexico at Heidelberg (44.25% WI), Shenandoah (30% WI), Samurai (33.3% WI), Vito (20% WI) and Lucius (50% WI). |
| • | The Company declared four deepwater wells as dry holes and expensed approximately $27 million of additional well costs associated with properties that were pending further evaluation as of December 31, 2008. |
International
| • | The Company announced two deepwater discoveries offshore Ghana and one deepwater discovery in each of offshore Sierra Leone and Brazil. |
| • | The Company announced successful appraisal wells offshore Ghana and Brazil. |
| • | The Ghanaian government formally approved the Jubilee field Phase I Plan of Development and Unitization Agreement. Jubilee remains on schedule to achieve first production during the fourth quarter of 2010. |
| • | All major contracts were awarded for development of the El Merk project in Algeria’s Block 208. First production is scheduled for late 2011. |
| • | The Company declared two dry holes in Indonesia and one dry hole in each of Brazil, Cote d’Ivoire, China, and Mozambique, and expensed approximately $22 million of additional well costs associated with properties that were pending further evaluation as of December 31, 2008. |
FINANCIAL HIGHLIGHTS
Significant 2009 financial highlights include:
| • | The Company generated $3.9 billion of cash flow from continuing operating activities compared to $6.4 billion in 2008 due to lower average commodity prices for the year and ended the year with $3.5 billion of cash on hand. |
| • | The Company completed two public debt offerings generating net proceeds of $2.0 billion, and repaid debt of $1.6 billion, including the repayment of $1.4 billion in aggregate principal amount of floating-rate notes due in 2009. |
| • | The Company completed a public offering of 30 million shares of common stock at $45.50 per share generating net proceeds of approximately $1.3 billion. |
| • | The Company reversed its $735 million accrued liability for potential royalties and interest related to the Deepwater Royalty Relief Act (DWRRA) dispute. |
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Table of Contents
The following discussion pertains to Anadarko’s financial condition, results of operations and changes in financial condition. Unless noted otherwise, the following information relates to continuing operations and any increases or decreases “for the year ended December 31, 2009” refer to the comparison of the year ended December 31, 2009, to the year ended December 31, 2008. Similarly, any increases or decreases “for the year ended December 31, 2008” refer to the comparison of the year ended December 31, 2008, to the year ended December 31, 2007. The primary factors that affect the Company’s results of operations include, among other things, commodity prices for natural gas, crude oil and NGLs, sales volumes, the Company’s ability to discover additional oil and natural-gas reserves, as well as the cost of finding reserves and costs required for continuing operations. Unless the context otherwise requires, the terms “Anadarko” or “Company” refer to Anadarko Petroleum Corporation and its consolidated subsidiaries. Following is an index by major category of discussion including a brief description of contents:
| Table of Contents | ||
| Page | ||
| Financial Results — comparative discussion of financial results of operations |
36 | |
| Operating Results — discussion of business activities |
44 | |
| Liquidity and Capital Resources — discussion of sources and uses of cash, outlook on operations and material financial arrangements, obligations and commitments |
47 | |
| Critical Accounting Estimates — discussion of significant judgments and estimates |
54 | |
| Recent Accounting Developments — discussion of accounting guidance effective in future periods |
60 | |
RESULTS OF CONTINUING OPERATIONS
Selected Data
| millions except per share amounts and percentages | 2009 | 2008 | 2007 | |||||||||
| Financial Results |
||||||||||||
| Sales revenues(1) |
$ | 8,210 | $ | 14,079 | $ | 11,656 | ||||||
| Gains on divestitures and other, net |
133 | 1,083 | 4,760 | |||||||||
| Reversal of accrual for DWRRA dispute |
657 | — | — | |||||||||
| Total revenues and other |
9,000 | 15,162 | 16,416 | |||||||||
| Costs and expenses |
8,623 | 9,561 | 8,545 | |||||||||
| Other (income) expense(1) |
485 | 233 | 1,545 | |||||||||
| Income tax expense (benefit) |
(5 | ) | 2,148 | 2,559 | ||||||||
| Income (loss) from continuing operations attributable to common stockholders |
$ | (135 | ) | $ | 3,197 | $ | 3,767 | |||||
| Income (loss) from continuing operations per common share attributable to common stockholders — diluted |
$ | (0.28 | ) | $ | 6.78 | $ | 7.99 | |||||
| Average number of common shares outstanding — diluted |
480 | 466 | 467 | |||||||||
| Operating Results |
||||||||||||
| Adjusted EBITDAX(2) |
$ | 5,316 | $ | 10,863 | $ | 11,205 | ||||||
| Total proved reserves (MMBOE) |
2,304 | 2,277 | 2,431 | |||||||||
| Annual sales volumes (MMBOE)(3) |
220 | 206 | 211 | |||||||||
| Capital Resources and Liquidity |
||||||||||||
| Cash provided by operating activities |
$ | 3,926 | $ | 6,447 | $ | 2,766 | ||||||
| Capital expenditures |
4,558 | 4,881 | 3,990 | |||||||||
| Total debt |
12,748 | 12,339 | 14,747 | |||||||||
| Stockholders’ equity |
$ | 19,928 | $ | 18,795 | $ | 16,364 | ||||||
| Debt to total capitalization ratio |
39.0 | % | 39.6 | % | 47.4 | % | ||||||
| (1) | Commodity derivative activity previously reported in Sales revenues, has been reclassified to Other (income) expense. See Basis of Presentation in Note 1—Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K. |
| (2) | See Operating Results—Segment Analysis—Adjusted EBITDAX below for a description of Adjusted EBITDAX, which is not a U.S. Generally Accepted Accounting Principles (GAAP) measure, and a reconciliation of Adjusted EBITDAX to income (loss) from continuing operations before income taxes, which is presented in accordance with GAAP. |
| (3) | Sales volumes for 2007 include 15 MMBOE associated with properties that were divested during 2007. |
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Table of Contents
FINANCIAL RESULTS
Income (Loss) from Continuing Operations Attributable to Common Stockholders Anadarko’s loss from continuing operations attributable to common stockholders for 2009 totaled $135 million, or $0.28 per share (diluted), compared to income from continuing operations attributable to common stockholders for 2008 of $3.2 billion, or $6.78 per share (diluted). Anadarko had income from continuing operations attributable to common stockholders in 2007 of $3.8 billion, or $7.99 per share (diluted).
Sales Revenues
| Inc/(Dec) vs. 2008 |
Inc/(Dec) vs. 2007 |
||||||||||||||
| millions except percentages | 2009 | 2008 | 2007 | ||||||||||||
| Gas sales |
$ | 2,924 | (49 | )% | $ | 5,770 | 43 | % | $ | 4,043 | |||||
| Oil and condensate sales |
4,022 | (37 | ) | 6,425 | 19 | 5,407 | |||||||||
| Natural-gas-liquids sales |
536 | (33 | ) | 802 | 12 | 719 | |||||||||
| Gathering, processing and marketing sales |
728 | (33 | ) | 1,082 | (27 | ) | 1,487 | ||||||||
| Total |
$ | 8,210 | (42 | ) | $ | 14,079 | 21 | $ | 11,656 | ||||||
Anadarko’s sales revenues for the year ended December 31, 2009, decreased due to lower commodity prices, partially offset by increased production volumes. The increase for the year ended December 31, 2008, was due to higher commodity prices, partially offset by lower 2008 sales volumes, attributable to 2007 property divestitures.
Analysis of Oil and Gas Operations Sales Revenues and Volumes
The following table provides a summary of the effects of changes in volumes and prices on Anadarko’s sales revenues for the year ended December 31, 2009, compared to 2008 and 2007.
| millions | Natural Gas |
Oil and Condensate |
NGLs | |||||||||
| 2007 sales revenues |
$ | 4,043 | $ | 5,407 | $ | 719 | ||||||
| Changes associated with sales volumes |
303 | (803 | ) | (63 | ) | |||||||
| Changes in prices |
1,424 | 1,821 | 146 | |||||||||
| 2008 sales revenues |
$ | 5,770 | $ | 6,425 | $ | 802 | ||||||
| Changes associated with sales volumes |
454 | 155 | 154 | |||||||||
| Changes in prices |
(3,300 | ) | (2,558 | ) | (420 | ) | ||||||
| 2009 sales revenues |
$ | 2,924 | $ | 4,022 | $ | 536 | ||||||
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Table of Contents
The following table provides Anadarko’s sales volumes for the year ended December 31, 2009, compared to 2008 and 2007.
| 2009 | Inc/(Dec) vs. 2008 |
2008 | Inc/(Dec) vs. 2007 |
2007 | ||||||||
| Barrels of Oil Equivalent (MMBOE except percentages) |
||||||||||||
| United States |
196 | 9 | % | 179 | (1 | )% | 180 | |||||
| International |
24 | (11 | ) | 27 | (13 | ) | 31 | |||||
| Total |
220 | 7 | 206 | (2 | ) | 211 | ||||||
| Barrels of Oil Equivalent per Day (MBOE/d except percentages) |
||||||||||||
| United States |
537 | 10 | 489 | (1 | ) | 492 | ||||||
| International |
67 | (9 | ) | 74 | (13 | ) | 85 | |||||
| Total |
604 | 7 | 563 | (2 | ) | 577 | ||||||
Sales volumes represent actual production volumes adjusted for changes in commodity inventories. Anadarko employs strategies to manage volumes and mitigate the effect of price volatility, which is likely to continue in the future. Production of natural gas, crude oil and NGLs is usually not affected by seasonal swings in demand.
Natural-Gas Sales Volumes, Average Prices and Revenues
| 2009 | Inc/(Dec) vs. 2008 |
2008 | Inc/(Dec) vs. 2007 |
2007 | |||||||||||
| (Percentages) | (Percentages) | ||||||||||||||
| United States |
|||||||||||||||
| Sales volumes—Bcf |
809 | 8 | % | 750 | 7 | % | 698 | ||||||||
| MMcf/d |
2,217 | 8 | 2,049 | 7 | 1,912 | ||||||||||
| Price per Mcf |
$ | 3.61 | (53 | ) | $ | 7.69 | 33 | $ | 5.80 | ||||||
| Gas sales revenues (millions) |
$ | 2,924 | (49 | ) | $ | 5,770 | 43 | $ | 4,043 | ||||||
Bcf—billion cubic feet
MMcf/d—million cubic feet per day
The Company’s daily natural-gas sales volumes increased 168 MMcf/d for the year ended December 31, 2009, primarily due to increased production in the Rocky Mountain Region (Rockies) of 138 MMcf/d due to positive results from base production resulting from dewatering coalbed methane wells and higher production uptime due to favorable weather. An increase in production in the Gulf of Mexico of 54 MMcf/d related to favorable weather conditions as compared to hurricane-related downtime experienced during 2008. Also, runtime at Independence Hub increased during 2009 as compared to 2008 when export pipeline repair work resulted in downtime, partially offset by a decrease in production due to scheduled maintenance at Independence Hub. These increases were partially offset by a 24 MMcf/d decrease in the Southern Region resulting from natural production declines experienced while drilling programs were shifted from established fields to emerging shale plays.
Anadarko’s daily natural-gas sales volumes increased for the year ended December 31, 2008, excluding 2007 divested property volumes of 156 MMcf/d. The increase was primarily due to higher sales volumes in the Gulf of Mexico of 175 MMcf/d as a result of the start up of the Independence Hub and increased production in the Rockies of 162 MMcf/d due to improved drilling efficiencies allowing for more overall drilling, partially offset by decreased production in the Southern Region of 44 MMcf/d.
The average natural-gas price Anadarko received decreased for the year ended December 31, 2009. This decrease was primarily due to higher year-over-year natural-gas production and storage volumes coupled with lower United States demand for natural gas, triggered by the economic downturn in the United States.
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Table of Contents
Anadarko’s average natural-gas price increased for the year ended December 31, 2008. The increase was primarily attributable to lower year-over-year natural-gas storage volumes coupled with lower liquefied natural-gas volumes available to the United States consumer, both of which were caused principally by increased demand in both Europe and Asia.
Crude-Oil and Condensate Sales Volumes, Average Prices and Revenues
| 2009 | Inc/(Dec) vs. 2008 |
2008 | Inc/(Dec) vs. 2007 |
2007 | |||||||||||
| (Percentages) | (Percentages) | ||||||||||||||
| United States |
|||||||||||||||
| Sales volumes—MMBbls |
44 | 10 | % | 40 | (17 | )% | 48 | ||||||||
| MBbls/d |
120 | 11 | 108 | (17 | ) | 130 | |||||||||
| Price per barrel |
$ | 58.56 | (39 | ) | $ | 96.20 | 44 | $ | 66.88 | ||||||
| International |
|||||||||||||||
| Sales volumes—MMBbls |
24 | (11 | ) | 27 | (13 | ) | 31 | ||||||||
| MBbls/d |
67 | (9 | ) | 74 | (13 | ) | 85 | ||||||||
| Price per barrel |
$ | 59.01 | (38 | ) | $ | 95.83 | 33 | $ | 71.86 | ||||||
| Total |
|||||||||||||||
| Sales volumes—MMBbls |
68 | 1 | 67 | (15 | ) | 79 | |||||||||
| MBbls/d |
187 | 3 | 182 | (15 | ) | 215 | |||||||||
| Total price per barrel |
$ | 58.72 | (39 | ) | $ | 96.05 | 40 | $ | 68.83 | ||||||
| Total oil and condensate sales revenues (millions) |
$ | 4,022 | (37 | ) | $ | 6,425 | 19 | $ | 5,407 | ||||||
MMBbls—million barrels
MBbls/d—thousand barrels per day
Anadarko’s daily crude-oil and condensate sales volumes increased for the year ended December 31, 2009, primarily due to higher crude-oil sales volumes of 8 MBbls/d in the Gulf of Mexico and 3 MBbls/d in the Rockies. The increase in the Gulf of Mexico is attributable to additional production that came online during the fourth quarter of 2008, and favorable weather conditions as compared to 2008, which was impacted by export pipeline repair work and hurricane-related disruptions. The Rockies increase is attributable to production efficiencies related to an oil pipeline that was placed in service in 2009. These increases were offset by lower Algerian crude-oil sales volumes of 6 MBbls/d due to the timing of cargo liftings and variances in OPEC quotas.
Anadarko’s daily crude-oil and condensate sales volumes decreased for the year ended December 31, 2008, excluding 2007 divested property volumes of 15 MBbls/d, primarily due to lower crude-oil sales volumes of 13 MBbls/d in the Gulf of Mexico attributable to pipeline repairs resulting from 2008 hurricane activity, lower crude-oil sales volumes of 7 MBbls/d in Algeria, primarily from lower production due to maintenance, a statutory shutdown and production constraints implemented by OPEC during the fourth quarter of 2008, and lower crude-oil sales volumes of 3 MBbls/d in Alaska, partially offset by higher crude-oil sales volumes of 5 MBbls/d in the Rockies.
The average crude-oil price Anadarko received decreased for the year ended December 31, 2009, primarily due to increased spare OPEC production capacity coupled with decreased global demand, particularly in the United States, Europe and Japan as a result of the economic downturn. Anadarko’s average crude-oil price increased for the year ended December 31, 2008. Crude-oil prices were strong in the first half of 2008, primarily due to limited excess production capacity, heightened geopolitical tension and increased demand in Asia.
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Table of Contents
Natural-Gas-Liquids Sales Volumes, Average Prices and Revenues
| 2009 | Inc/(Dec) vs. 2008 |
2008 | Inc/(Dec) vs. 2007 |
2007 | |||||||||||
| (Percentages) | (Percentages) | ||||||||||||||
| United States |
|||||||||||||||
| Sales volumes—MMBbls |
17 | 21 | % | 14 | (13 | )% | 16 | ||||||||
| MBbls/d |
47 | 21 | 39 | (9 | ) | 43 | |||||||||
| Price per barrel |
$ | 31.42 | (44 | ) | $ | 56.11 | 22 | $ | 45.87 | ||||||
| Natural-gas-liquids sales revenues (millions) |
$ | 536 | (33 | ) | $ | 802 | 12 | $ | 719 | ||||||
NGLs sales represent revenues from the sale of product derived from the processing of Anadarko’s natural-gas production. The Company’s daily NGLs sales volumes increased for the year ended December 31, 2009, primarily attributable to a new processing train placed in service during the second quarter of 2009 at the Chipeta natural-gas processing plant, increased gas production in the Rockies, and improved recoveries in the Southern Region.
Anadarko’s daily NGLs sales volumes were down for the year ended December 31, 2008, primarily due to a 4 MBbls/d decrease associated with the 2007 divestitures.
The average NGLs price decreased for the year ended December 31, 2009, primarily due to decreased global petrochemical demand as a result of the economic downturn. For the year ended December 31, 2008, average NGLs prices increased primarily due to increased global petrochemical demand for the first three quarters of 2008. NGLs production is dependent on natural-gas and NGLs prices as well as the economics of the processing of natural gas to extract NGLs.
Gathering, Processing and Marketing Margin
| millions except percentages | 2009 | Inc/(Dec) vs. 2008 |
2008 | Inc/(Dec) vs. 2007 |
2007 | ||||||||||
| Gathering, processing and marketing sales |
$ | 728 | (33 | )% | $ | 1,082 | (27 | )% | $ | 1,487 | |||||
| Gathering, processing and marketing expenses |
617 | (23 | ) | 800 | (22 | ) | 1,025 | ||||||||
| Margin |
$ | 111 | (61 | ) | $ | 282 | (39 | ) | $ | 462 | |||||
For the year ended December 31, 2009, gathering, processing and marketing margin decreased $171 million. The decrease was primarily due to lower prices for natural gas, NGLs and condensate, which led to reduced gas processing margins, lower margins associated with firm transportation contracts due to price differentials between supply and market areas, and unrealized losses on derivatives related to gas-storage activity which is seasonal in nature, i.e., the margin realized on the future sale of stored volumes covered by these derivative instruments will more than offset the recorded unrealized losses. These amounts were partially offset by increases in crude-oil marketing margins, and in NGLs marketing margins primarily due to inventory write-downs to market value taken in the fourth quarter of 2008.
For the year ended December 31, 2008, gathering, processing and marketing margin decreased $180 million. The decrease resulted from lower marketing sales of $231 million primarily due to lower margins on firm transportation contracts and decreased third-party-marketing activity, a write-down of storage inventory due to lower commodity prices in the fourth quarter of 2008 and lower gathering and processing sales of $174 million, primarily due to lower volumes as a result of the 2007 divestitures. These amounts were partially offset by a $183 million decrease in costs associated with gathering and processing operations, primarily due to 2007 divestitures, a $39 million decrease in marketing transportation costs, and a reduction of accrued expenses related to a prior period of $29 million.
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Gains (Losses) on Divestitures and Other, net
Gains on divestitures in 2009 were $44 million, primarily related to proceeds from the sale of oil and gas properties in Qatar. Gains on divestitures in 2008 were $1.2 billion, primarily related to the divestiture of certain oil and gas properties in Brazil, onshore United States and the Gulf of Mexico. Gains on divestitures in 2007 related primarily to the Company’s asset-realignment program. During 2007, net gains of $4.1 billion related to divestitures of oil and gas properties and net gains of $574 million related to the divestiture of certain gathering and processing facilities. For additional information, see Operating Results—Divestitures below.
In 2008, gains (losses) on divestitures and other, net includes a net $82 million ($52 million after tax) reduction related to corrections resulting from the analysis of property records after the adoption of the successful efforts method of accounting. This net amount includes a reduction of $163 million related to 2007. Management concluded that this misstatement was not material to 2007 interim and annual results, or to the 2008 period, and corrected the error in the first quarter of 2008.
Reversal of Accrual for DWRRA Dispute
On March 17, 2006 Kerr-McGee Oil and Gas Corp (KMOG) filed a lawsuit styled Kerr-McGee Oil and Gas Corp. v. C. Stephen Allred, Assistant Secretary for Land & Minerals Mgt. and the Dept of the Interior (Kerr-McGee v. Allred) in the U.S. District Court for the Western District of Louisiana against the Department of the Interior (DOI) for injunctive and declaratory relief with respect to the DOI’s claims for additional royalties on the eight leases listed in the order issued by the DOI in 2006. In May 2007, KMOG filed a motion for summary judgment with the District Court for the Western District of Louisiana which ruled in favor of KMOG in October 2007. The DOI appealed the decision to the U.S. Court of Appeals for the Fifth Circuit (Fifth Circuit). In January 2009, a three-judge Fifth Circuit panel unanimously affirmed the District Court’s ruling in favor of KMOG. At the end of March 2009, the DOI filed a petition for rehearing by the full Fifth Circuit (en banc), which was denied on April 14, 2009. On July 13, 2009, the DOI filed a petition for a writ of certiorari with the U.S. Supreme Court, which was denied on October 5, 2009.
Based on the U.S. Supreme Court’s denial of the DOI’s petition for review by the court, Anadarko reversed its $657 million accrued liability for royalties that could have been owed on leases listed in the 2006 Order, similar orders to pay issued in 2008 and 2009, and other deepwater Gulf of Mexico leases with similar price-threshold provisions. In addition, the Company reversed its $78 million accrued liability for unpaid interest on these amounts.
Effective October 1, 2009, royalties and interest are no longer being accrued for deepwater Gulf of Mexico leases with price-threshold provisions. For more information on the DWRRA dispute, see Note 14—Contingencies—Deepwater Royalty Relief Act in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.
Costs and Expenses
| millions except percentages | 2009 | Inc/(Dec) vs. 2008 |
2008 | Inc/(Dec) vs. 2007 |
2007 | ||||||||||
| Oil and gas operating |
$ | 933 | (15 | )% | $ | 1,104 | — | % | $ | 1,101 | |||||
| Oil and gas transportation and other |
590 | 7 | 553 | 22 | 453 | ||||||||||
| Exploration |
1,107 | (19 | ) | 1,369 | 51 | 905 | |||||||||
For the year ended December 31, 2009, oil and gas operating expenses decreased primarily as a result of cost savings programs initiated in response to the reduction in oil and gas prices experienced from 2008 into 2009. Cost savings were achieved through operating efficiencies, deferral of certain workovers and vendor negotiations. Additional reductions were due to lower production handling rates in the Gulf of Mexico, and a decrease in outside-operated expenses in Alaska and Algeria. For the year ended December 31, 2008, oil and gas operating expenses increased primarily due to workovers and other field initiatives implemented to capture the increase in product prices from 2007 to 2008. Expenses for 2008 also included a full year of operations at Independence Hub. These amounts were partially offset by a decrease in costs associated with 2007 property divestitures.
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For the year ended December 31, 2009, oil and gas transportation and other expenses increased due to incremental transportation fees paid on increasing volumes in the Rockies, new processing agreements in certain areas of both the Rockies and Southern Region and drilling rig contract termination fees paid during the year. These increases were partially offset by a decline in certain fees related to surface owner agreements and certain processing agreements that are tied to product prices. For the year ended December 31, 2008, oil and gas transportation and other expenses increased due to incremental transportation fees paid on increasing volumes in the Rockies, new processing agreements in certain areas of both the Rockies and Southern Region, a full year of demand fees at Independence Hub and an increase in certain fees tied to product prices.
Exploration expense decreased by $262 million for the year ended December 31, 2009, primarily due to lower impairments of unproved properties of $205 million and lower geological and geophysical expense of $87 million. The decrease in impairments of unproved properties related primarily to Gulf of Mexico properties, partially offset by an increase in unproved property impairments in China. The decrease in geological and geophysical expense was primarily related to seismic data which was acquired and expensed in 2008 for Mozambique and Indonesia. Exploration expense increased by $464 million for the year ended December 31, 2008, primarily due to a $337 million impairment of unproved properties in the Gulf of Mexico, a $55 million impairment of unproved properties in Trinidad, a $40 million impairment of unproved properties in Brazil, and a $34 million increase in geological and geophysical costs, primarily related to the acquisition of seismic data for Mozambique.
| millions except percentages | 2009 | Inc/(Dec) vs. 2008 |
2008 | Inc/(Dec) vs. 2007 |
2007 | ||||||||||
| General and administrative |
$ | 983 | 14 | % | $ | 866 | (7 | )% | $ | 936 | |||||
| Depreciation, depletion and amortization |
3,532 | 11 | 3,194 | 12 | 2,840 | ||||||||||
| Other taxes |
746 | (49 | ) | 1,452 | 18 | 1,234 | |||||||||
| Impairments |
115 | (48 | ) | 223 | NM | 51 | |||||||||
NM—not meaningful
For the year ended December 31, 2009, general and administrative (G&A) expense increased primarily due to bonus plan expense. The increase was primarily related to a supplemental bonus plan, the payment of which was triggered by the Company’s total-shareholder-return performance relative to a group of peer companies. The performance resulted in significantly increased market value relative to the peer-group-average performance, and all non-officer employees qualified for prescribed payments under the plan. For the year ended December 31, 2008, G&A expense decreased primarily due to a decrease in employee severance and termination benefits, lower compensation expense and a decrease in contract labor expense, partially offset by higher pension plan expenses.
For the year ended December 31, 2009, depreciation, depletion, and amortization (DD&A) expense increased $338 million primarily due to a $237 million increase attributable to higher sales volumes and to $84 million of higher accumulated costs associated with acquiring, finding and developing oil and gas reserves. For the year ended December 31, 2008, DD&A expense increased $354 million primarily due to a $416 million increase attributable to oil and gas properties due to higher costs associated with acquiring, finding and developing oil and gas reserves. This increase was partially offset by a decrease of approximately $43 million due to lower sales volumes and a decrease in depreciation of other properties and equipment of $28 million primarily due to divestitures.
For the year ended December 31, 2009, other taxes decreased primarily due to lower commodity prices, which resulted in lower United States production and severance taxes of $343 million, Algerian exceptional profits tax of $269 million, and Chinese windfall profits tax of $60 million as well as decreased ad valorem taxes of $32 million. For the year ended December 31, 2008, other taxes increased primarily due to increased production and severance taxes of $194 million, Chinese windfall profits tax of $55 million and ad valorem taxes of $43 million. These increases were triggered primarily by higher commodity prices and were partially offset by a decrease in the Algerian exceptional profits tax expense attributable to a change in the estimate of the 2006 exceptional profits tax recognized during the first quarter of 2007.
Impairments for the year ended December 31, 2009, related to $86 million of marketing operating segment assets, $22 million of oil and gas exploration and production operating segment properties in the United States
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and $7 million of midstream operating segment assets. The marketing operating segment impairments related to the impairment of firm transportation contracts and LNG facility-site properties. Impairments for the year ended December 31, 2008, related to $113 million of oil and gas exploration and production operating segment properties in the United States, $98 million of midstream operating segment assets and $12 million of marketing operating segment assets. The oil and gas exploration and production operating segment and midstream operating segment impairments were primarily a result of lower commodity prices at year-end 2008. The marketing operating segment impairments related to the impairment of firm transportation contracts.
Other (Income) Expense
| millions except percentages | 2009 | Inc/(Dec) vs. 2008 |
2008 | Inc/(Dec) vs. 2007 |
2007 | |||||||||||||
| Interest Expense |
||||||||||||||||||
| Gross interest expense— |
||||||||||||||||||
| Current debt, long-term debt and other |
$ | 732 | (2 | )% | $ | 746 | (38 | )% | $ | 1,203 | ||||||||
| Midstream subsidiary note payable to a related party |
39 | (64 | ) | 109 | NM | 2 | ||||||||||||
| Capitalized interest |
(69 | ) | (44 | ) | (123 | ) | 1 | (122 | ) | |||||||||
| Net interest expense |
$ | 702 | (4 | ) | $ | 732 | (32 | ) | $ | 1,083 | ||||||||
Anadarko’s gross interest expense decreased for the year ended December 31, 2009, primarily due to the reversal of $78 million of previously accrued interest expense related to the DWRRA dispute, lower interest expense of $70 million due to the partial retirement of the Midstream Subsidiary Note Payable to a Related Party and lower interest expense of $60 million due to the retirement of $1.4 billion in aggregate principal amount of Floating-Rate Notes during 2009, partially offset by interest expense of $108 million on $2.0 billion of debt issued in 2009. Anadarko’s gross interest expense decreased for the year ended December 31, 2008, primarily due to lower average debt levels in 2008 and decreases in average floating interest rates. For additional information see Operating Results—Divestitures and Liquidity and Capital Resources—Uses of Cash—Debt Repayment below and Interest-Rate Risk under Item 7A of this Form 10-K.
For the year ended December 31, 2009, capitalized interest decreased $54 million primarily due to lower capitalized costs that qualified for interest capitalization. The amount of capitalized interest for the years ended December 31, 2008, and 2007, was comparable.
| millions except percentages | 2009 | Inc/(Dec) vs. 2008 |
2008 | Inc/(Dec) vs. 2007 |
2007 | |||||||||||||
| (Gains) Losses on Commodity Derivatives, net |
||||||||||||||||||
| Realized (gains) losses |
$ | (327 | ) | 196 | % | $ | 339 | (165 | )% | $ | (524 | ) | ||||||
| Unrealized (gains) losses |
735 | (182 | ) | (900 | ) | 186 | 1,048 | |||||||||||
| Total (gain) loss on commodity derivatives, net |
$ | 408 | (173 | ) | $ | (561 | ) | NM | $ | 524 | ||||||||
The Company utilizes commodity derivative instruments to reduce its exposure to cash flow variability resulting from commodity price changes. For additional information on (gains) losses on commodity derivatives, see Note 8—Derivative Instruments in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.
| millions except percentages | 2009 | Inc/(Dec) vs. 2008 |
2008 | Inc/(Dec) vs. 2007 |
2007 | ||||||||||
| (Gains) Losses on Other Derivatives, net |
|||||||||||||||
| Realized (gains) losses |
$ | (525 | ) | NM | $ | — | NM | $ | — | ||||||
| Unrealized (gains) losses |
(57 | ) | NM | 10 | (11 | )% | 9 | ||||||||
| Total (gain) loss on other derivatives, net |
$ | (582 | ) | NM | $ | 10 | (11 | ) | $ | 9 | |||||
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Anadarko enters into interest-rate swaps to reduce its exposure to cash flow variability resulting from interest-rate changes. For additional information see Note 8—Derivative Instruments in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.
| millions except percentages | 2009 | Inc/(Dec) vs. 2008 |
2008 | Inc/(Dec) vs. 2007 |
2007 | |||||||||||||
| Other (Income) Expense, net |
||||||||||||||||||
| Interest income |
$ | (19 | ) | (57 | )% | $ | (44 | ) | (48 | )% | $ | (84 | ) | |||||
| Other |
(24 | ) | 125 | 96 | NM | 13 | ||||||||||||
| Total other (income) expense, net |
$ | (43 | ) | 183 | $ | 52 | (173 | ) | $ | (71 | ) | |||||||
For 2009, the Company had total other income of $43 million compared to total other expense of $52 million for 2008. The increase of $95 million was primarily related to foreign currency gains of $70 million primarily related to exchange-rate changes applicable to cash held in escrow pending final determination of the Company’s Brazilian tax liability attributable to its 2008 divestiture of the Peregrino field offshore Brazil.
For 2008, the Company had total other expense of $52 million compared to total other income of $71 million for 2007. The decrease of $123 million was primarily related to lower interest income of $40 million due to lower average cash levels and lower interest rates in 2008, a $40 million loss related to environmental reserve adjustments and $54 million of impairment losses related to equity investments.
Income Tax Expense
| millions except percentages | 2009 | 2008 | 2007 | |||||||||
| Income tax expense (benefit) |
$ | (5 | ) | $ | 2,148 | $ | 2,559 | |||||
| Effective tax rate |
5 | % | 40 | % | 40 | % | ||||||
The variance between the Company’s effective tax rate and the 35% statutory rate in 2009 is primarily attributable to:
| • | the accrual of the Algerian exceptional profits tax, |
| • | other foreign taxes in excess of the federal statutory rate, and |
| • | U.S. residual income tax on foreign income. |
These amounts were largely offset by:
| • | benefits associated with changes in uncertain tax positions, |
| • | state income taxes, including a change in the state income tax rate expected to be in effect at the time the Company’s deferred state income tax liability is expected to be settled or realized, and |
| • | U.S. income tax impact from losses and restructuring of foreign operations and other items. |
The variance between the Company’s effective tax rate and the 35% statutory rate in 2008 is primarily attributable to the accrual of the Algerian exceptional profits tax, U.S. tax on foreign income, state income taxes and other items. In 2007, the variance from the 35% statutory rate is due to the Algerian exceptional profits tax, other foreign taxes in excess of federal statutory rates and state income taxes, partially offset by the foreign tax rate applicable to the Company’s divestiture of its 50% interest in the Peregrino field offshore Brazil, which had a rate lower than the 35% U.S. statutory rate, and other items.
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Net Income Attributable to Noncontrolling Interests
For the years ended December 31, 2009, and 2008, the Company’s net income attributable to noncontrolling interests was $32 million and $23 million, respectively. These amounts for the years ended December 31, 2009 and 2008 related primarily to a 43.2% and 36.7% average public ownership interest, respectively, in Western Gas Partners, LP (WES), a consolidated subsidiary of the Company.
OPERATING RESULTS
Segment Analysis—Adjusted EBITDAX To assess the operating results of Anadarko’s segments, the chief operating decision maker analyzes income from continuing operations before income taxes, interest expense, exploration expense, DD&A expense and impairments, less net income attributable to noncontrolling interests (Adjusted EBITDAX). Anadarko’s definition of Adjusted EBITDAX, which is not a GAAP measure, excludes exploration expense because exploration expense is not an indicator of operating efficiency for a given reporting period. However, exploration expense is monitored by management as part of costs incurred in exploration and development activities. Similarly, DD&A expense and impairments are excluded from Adjusted EBITDAX as a measure of segment operating performance because capital expenditures are evaluated at the time capital costs are incurred. The Company’s definition of Adjusted EBITDAX also excludes interest expense to allow for assessment of segment operating results without regard to Anadarko’s financing methods or capital structure. Management believes that the presentation of Adjusted EBITDAX provides information useful in assessing the Company’s financial condition and results of operations and that Adjusted EBITDAX is a widely accepted financial indicator of a company’s ability to incur and service debt, fund capital expenditures and make distributions to stockholders.
Adjusted EBITDAX, as defined by Anadarko, may not be comparable to similarly titled measures used by other companies. Therefore, Anadarko’s consolidated Adjusted EBITDAX should be considered in conjunction with income (loss) from continuing operations attributable to common stockholders and other performance measures prepared in accordance with GAAP, such as operating income or cash flow from operating activities. Adjusted EBITDAX has important limitations as an analytical tool because it excludes certain items that affect income from continuing operations attributable to common stockholders and net cash provided by operating activities. Adjusted EBITDAX should not be considered in isolation or as a substitute for an analysis of Anadarko’s results as reported under GAAP. Below is a reconciliation of consolidated Adjusted EBITDAX to income (loss) from continuing operations before income taxes.
Adjusted EBITDAX
| millions except percentages | 2009 | Inc/(Dec) vs. 2008 |
2008 | Inc/(Dec) vs. 2007 |
2007 | ||||||||||||
| Income (loss) from continuing operations before income taxes |
$ | (108 | ) | (102 | )% | $ | 5,368 | (15 | )% | $ | 6,326 | ||||||
| Exploration expense |
1,107 | (19 | ) | 1,369 | 51 | 905 | |||||||||||
| Depreciation, depletion and amortization expense |
3,532 | 11 | 3,194 | 12 | 2,840 | ||||||||||||
| Impairments |
115 | (48 | ) | 223 | NM | 51 | |||||||||||
| Interest expense |
702 | (4 | ) | 732 | (32 | ) | 1,083 | ||||||||||
| Less: Net income attributable to noncontrolling interests |
32 | 39 | 23 | NM | — | ||||||||||||
| Consolidated Adjusted EBITDAX |
$ | 5,316 | (51 | ) | $ | 10,863 | (3 | ) | $ | 11,205 | |||||||
| Adjusted EBITDAX by segment— |
|||||||||||||||||
| Oil and gas exploration and production |
$ | 5,386 | (48 | ) | $ | 10,332 | (7 | ) | $ | 11,120 | |||||||
| Midstream |
324 | (24 | ) | 428 | (52 | ) | 894 | ||||||||||
| Marketing |
(72 | ) | NM | 63 | (77 | ) | 275 | ||||||||||
| Other and intersegment eliminations |
(322 | ) | NM | 40 | 104 | (1,084 | ) | ||||||||||
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Oil and Gas Exploration and Production The decrease in Adjusted EBITDAX for the year ended December 31, 2009, was primarily due to the impact of lower commodity prices, partially offset by higher natural-gas sales volumes primarily in the Rockies and the reversal of amounts previously accrued in connection with the DWRRA dispute. The decrease in Adjusted EBITDAX for the year ended December 31, 2008, was primarily due to a decrease in gains on divestitures and other, net of $3.1 billion and lower sales volumes as a result of the 2007 divestitures, partially offset by the impact of higher commodity prices and higher natural-gas sales volumes primarily in the Rockies and the Gulf of Mexico.
Midstream The decrease in Adjusted EBITDAX for the year ended December 31, 2009, resulted primarily from a decrease in revenue due to lower prices for natural gas, NGLs, and condensate, which impacted revenues earned under the Company’s percent-of-proceeds and keep-whole contracts, partially offset by lower cost of product. The decrease in Adjusted EBITDAX for the year ended December 31, 2008, resulted primarily from a decrease in gains on divestitures and other, net of $531 million and lower volumes as a result of the 2007 divestitures, partially offset by higher product prices and gathering rates. During July 2007, the Company divested its interests in two natural-gas gathering systems and associated processing plants. These divested facilities accounted for $75 million, or 21%, of Anadarko’s midstream segment’s Adjusted EBITDAX for 2007, excluding gains on divestitures.
Marketing Marketing earnings represent primarily the margin earned on sales of gas, oil and NGLs purchased from third parties. The decrease in Adjusted EBITDAX for the year ended December 31, 2009, was primarily due to a decrease of approximately 30% in marketed third-party volumes, and lower margins associated with firm transportation contracts due to price differentials between supply and market areas. These amounts were partially offset by higher crude-oil marketing margins, and higher NGLs marketing margins primarily due to inventory write-downs to market value taken in the fourth quarter of 2008. The decrease in Adjusted EBITDAX for the year ended December 31, 2008, was primarily due to lower margins on firm transportation contracts and the write-down of storage inventory due to lower commodity prices in the fourth quarter of 2008.
Other and Intersegment Eliminations Other and intersegment eliminations consists primarily of corporate costs that are not allocated to the operating segments, realized and unrealized gains and losses on derivatives and income from hard minerals investments and royalties. The decrease in Adjusted EBITDAX for the year ended December 31, 2009, was primarily due to realized and unrealized gains and losses on commodity derivatives, partially offset by realized and unrealized gains and losses on interest-rate swaps. The increase in Adjusted EBITDAX for the year ended December 31, 2008, was primarily due to realized and unrealized gains and losses on commodity derivatives, and decreases in employee severance and termination benefits, compensation expense and contract labor expense, partially offset by higher benefit plan expense and losses related to equity investments.
Divestitures In 2009, Anadarko divested certain oil and gas properties, primarily in Qatar, onshore United States and other international properties for proceeds of $109 million and certain midstream properties for proceeds of $67 million.
In 2008, the Company divested certain oil and gas properties, primarily in Brazil, onshore United States and the Gulf of Mexico for approximately $2.5 billion. Proceeds from 2008 divestitures were used to reduce debt.
In April 2008, Anadarko entered into an agreement to sell its wholly owned subsidiary that owns an 18% interest in Petroritupano, S.A. (Petroritupano), a Venezuelan company also owned by Petróleos de Venezuela, S.A. (PDVSA) and Petrobras Energía, S.A., for $200 million. The closing of this transaction was subject to customary closing conditions, including receipt of approvals by Venezuelan authorities. Anadarko was informed by the Venezuelan Ministry of Energy and Petroleum that it would not grant approval for the sale because PDVSA intends to acquire Anadarko’s interest in Petroritupano. Anadarko subsequently received a letter from Corporacion Venezolana del Petroleo, S.A. (CVP), an affiliate of PDVSA, in which CVP stated its interest in acquiring Anadarko’s ownership interest in Petroritupano. At this time, Anadarko is unable to determine when the sale to CVP will be completed. Anadarko’s investment in Petroritupano is included in other assets at December 31, 2009.
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As a result of an asset-realignment program stemming from the acquisitions of Kerr-McGee and Western, Anadarko divested certain properties during 2007 for approximately $11.1 billion before income taxes. Net proceeds from these divestitures were used to reduce debt.
For additional information, see Note 2—Divestitures and Other in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.
Proved Reserves Anadarko focuses on growth and profitability. Reserve replacement is a key to growth. Future profitability depends partially upon the cost of finding and developing oil and gas reserves. Reserve growth can be achieved through successful exploration and development drilling, improved recovery or acquisition of producing properties.
The following is a discussion of proved reserves, reserve additions and revisions and future net cash flows from proved reserves. Additional reserve information is contained in the Supplemental Information on Oil and Gas Exploration and Production Activities (Supplemental Information) under Item 8 of this Form 10-K.
| MMBOE | 2009 | 2008 | 2007 | ||||||
| Proved Reserves |
|||||||||
| Beginning of year |
2,277 | 2,431 | 3,011 | ||||||
| Reserve additions and revisions |
275 | 188 | 252 | ||||||
| Sales in place |
(24 | ) | (137 | ) | (620 | ) | |||
| Production |
(224 | ) | (205 | ) | (212 | ) | |||
| End of year |
2,304 | 2,277 | 2,431 | ||||||
| Proved Developed Reserves |
|||||||||
| Beginning of year |
1,600 | 1,625 | 1,989 | ||||||
| End of year |
1,624 | 1,600 | 1,625 | ||||||
Reserve Additions and Revisions During 2009, the Company added 275 MMBOE of proved reserves as a result of additions (purchases in place, discoveries and extensions) and revisions. The Company expects the majority of future reserve growth to come from positive revisions associated with infill drilling and extensions of current fields and new discoveries onshore in North America and the deepwaters of the Gulf of Mexico, as well as through improved recovery operations, purchases of proved properties in strategic areas and successful exploration in international growth areas. The success of these operations will directly impact reserve additions or revisions in the future.
Additions During 2009, Anadarko added 70 MMBOE of proved reserves primarily as the result of successful drilling in the United States and at international locations. The Company also acquired 32 MMBOE of proved reserves in place related to onshore domestic assets in 2009. During 2008, Anadarko added 102 MMBOE of proved reserves primarily as the result of successful drilling in the Rockies and development and appraisal wells in the deepwater Gulf of Mexico. During 2007, Anadarko added 131 MMBOE of proved reserves. Of this amount, 130 MMBOE were a result of successful drilling in CBM and conventional plays of the Rockies and the initial recognition of proved reserves at the Peregrino field offshore Brazil.
Revisions Total revisions in 2009 were 173 MMBOE or 8% of the beginning-of-year reserve base. The revisions included an increase of 212 MMBOE primarily related to large onshore natural-gas plays, such as the Greater Natural Buttes and Pinedale fields, as a result of successful infill drilling (where the reserve bookings for the infill wells are treated as a positive revision). The revisions include a decrease of 39 MMBOE driven by lower natural-gas prices. Total revisions in 2008 were 86 MMBOE or 4% of the beginning-of-year reserve base. The revisions included an increase of 188 MMBOE primarily related to Greater Natural Buttes, Wattenberg and Pinedale fields, as a result of successful infill drilling, and positive revisions to the Peregrino heavy-oil field, offshore Brazil, which was sold in 2008, partially offset by a decrease of 102 MMBOE related to prices for oil and NGLs. Total revisions for 2007 were 121 MMBOE, related primarily to infill drilling in large onshore natural-gas plays, and higher oil and natural-gas prices.
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Sales in Place During 2009, the Company sold properties located onshore United States representing 24 MMBOE of proved reserves. In 2008, the Company sold properties located in the United States and Brazil representing 46 MMBOE and 91 MMBOE of proved reserves, respectively. In 2007, the Company sold properties located in the United States and Qatar representing 609 MMBOE and 11 MMBOE of proved reserves, respectively.
Discounted Future Net Cash Flows At December 31, 2009, the discounted (at 10%) estimated future net cash flow from Anadarko’s proved reserves was $13.6 billion (stated in accordance with the new regulations of the Securities and Exchange Commission (SEC) and the Financial Accounting Standards Board (FASB)). This discounted future net cash flow was calculated based on beginning-of-month average prices for the year, held flat for the life of the reserves, adjusted for any contractual provisions. For reporting periods prior to December 31, 2009, year-end prices were used for calculating discounted future net cash flows. The increase of $1.6 billion or 13% in 2009 compared to 2008 is primarily due to positive performance from exploration and development programs. See Supplemental Information under Item 8 of this Form 10-K.
The present value of future net cash flows does not purport to be an estimate of the fair market value of Anadarko’s proved reserves. A fair-value estimate would also take into account, among other things, anticipated changes in future prices and costs, the expected recovery of reserves in excess of proved reserves and a discount factor more representative of the time value of money and the risks inherent in producing oil and gas.
LIQUIDITY AND CAPITAL RESOURCES
Overview Anadarko’s primary sources of cash during 2009 were cash flow from operating activities and proceeds from the issuance of debt and common stock. The Company used cash primarily to fund its capital program, retire debt and pay dividends. Anadarko’s primary sources of cash during 2008 were cash flow from operating activities, proceeds from divestitures and the initial public offering of WES. In 2008, the Company used cash primarily to fund Anadarko’s capital spending program, retire debt, pay income taxes, repurchase Anadarko common stock, pay dividends and redeem preferred stock. Anadarko’s primary sources of cash during 2007 were proceeds from divestitures, cash flow from operating activities and proceeds from the issuance of a midstream subsidiary note to a related party. In 2007, the Company used cash primarily to retire debt, fund Anadarko’s capital spending program and pay income taxes and dividends.
The Company has in place a $1.3 billion five-year RCA, entered into in March 2008 with a syndicate of United States and foreign lenders, and as of December 31, 2009, the Company had no outstanding borrowings under its RCA. Under the terms of the RCA, the Company can, under certain conditions, request an increase in the borrowing capacity under the RCA up to a total available credit amount of $2.0 billion. Anadarko was in compliance with existing covenants and the full amount of the RCA was available for borrowing at December 31, 2009.
The Company continuously monitors its leverage position and coordinates its capital expenditure program with its expected cash flows and projected debt-repayment schedule. The Company will continue to monitor the financial markets and evaluate funding alternatives, including property divestitures, borrowings under the Company’s RCA and the issuance of debt or equity securities, based on its capital requirements. To facilitate a potential debt or equity securities issuance, the Company has the ability to sell securities under its shelf registration statement filed with the SEC in August 2009.
The following section discusses significant sources and uses of cash for the three-year period ending December 31, 2009. Forward-looking information related to the Company’s liquidity and capital resources are discussed in Outlook that follows.
Sources of Cash
Operating Activities Anadarko’s cash flow from continuing operating activities in 2009 was $3.9 billion compared to $6.4 billion in 2008 and $2.8 billion in 2007. The decrease in cash flow from continuing operations for the year ended December 31, 2009, is primarily attributable to lower commodity prices, partially offset by higher sales volumes and realized gains on interest-rate derivatives. In December 2008 and January 2009,
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Anadarko entered into interest-rate swap agreements with a combined notional principal amount of $3.0 billion. In May and June 2009, the Company revised the contractual terms of this swap portfolio to increase the weighted-average interest rate it is required to pay and realized $552 million in cash.
The increase in cash flow from continuing operations for the year ended December 31, 2008, was attributable to higher commodity prices and lower income tax payments in 2008 compared to 2007, when income tax payments were substantially higher as a result of 2007 divestiture activity. This increase in cash flow was partially offset by the cash impact of lower 2008 sales volumes which decreased as a result of 2007 divestiture activity, and an increase in realized derivative losses in 2008.
Fluctuations in commodity prices have been the primary reason for the Company’s short-term changes in cash flow from operating activities; however, Anadarko holds commodity derivative instruments that help to manage these cash flow fluctuations. Sales-volume changes also impact short-term cash flow, but have not been as volatile as commodity prices. Anadarko’s long-term cash flow from operating activities is dependent upon commodity prices, production sales volumes, reserve replacement and the level of costs and expenses required for continued operations.
For additional information on the Company’s interest-rate swap agreements, see Note 8—Derivative Instruments in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.
Investing Activities During 2009, 2008, and 2007, Anadarko closed several property divestiture transactions, and received proceeds of approximately $176 million, $2.5 billion and $8.3 billion before income taxes, respectively. For additional information, see Operating Results—Divestitures above.
Financing Activities During 2009, Anadarko raised a total of $3.3 billion through the issuance of debt and equity as follows:
| millions | |||||
| Date |
Issuance |
Net Proceeds | |||
| March 2009 |
7.625% Notes due 2014 | $ | 495 | ||
| 8.700% Notes due 2019 | 593 | ||||
| May 2009 |
Equity offering | 1,337 | |||
| June 2009 |
5.75% Notes due 2014 | 272 | |||
| 6.95% Notes due 2019 | 294 | ||||
| 7.95% Notes due 2039 | 321 | ||||
| $ | 3,312 | ||||
During 2008, Anadarko raised $321 million in connection with the initial public offering of 20.8 million common units of its consolidated affiliate, WES. See Note 3—Noncontrolling Interest in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K. Proceeds from the offering were used to reduce debt.
During 2007, Anadarko raised a total of $2.2 billion through the issuance of a midstream subsidiary note payable to a related party and an additional $2.8 billion through borrowings from affiliates. For additional information on the Company’s 2007 financing activities, see Note 6—Investments and Note 10—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.
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Uses of Cash
Capital Expenditures The following table presents the Company’s capital expenditures relating to continuing operations, by category.
| millions | 2009 | 2008 | 2007 | |||||||||
| Property acquisitions |
||||||||||||
| Exploration—unproved |
$ | 279 | $ | 405 | $ | (293 | ) | |||||
| Development—proved |
266 | 26 | (591 | ) | ||||||||
| Exploration |
1,229 | 1,031 | 834 | |||||||||
| Development |
2,886 | 3,530 | 2,805 | |||||||||
| Total oil and gas costs incurred* |
4,660 | 4,992 | 2,755 | |||||||||
| Less: Corporate acquisitions and non-cash property exchanges |
(284 | ) | (106 | ) | 1,001 | |||||||
| Less: Asset retirement costs |
(63 | ) | (263 | ) | (194 | ) | ||||||
| Less: Geological and geophysical, exploration overhead and delay rentals expenses and other |
(312 | ) | (344 | ) | (261 | ) | ||||||
| Less: Amortization of acquired drilling rig contract intangibles |
— | (5 | ) | (86 | ) | |||||||
| Total oil and gas capital expenditures |
4,001 | 4,274 | 3,215 | |||||||||
| Gathering, processing and marketing and other |
557 | 607 | 775 | |||||||||
| Total capital expenditures* |
$ | 4,558 | $ | 4,881 | $ | 3,990 | ||||||
| * | Oil and gas costs incurred represent costs related to finding and developing oil and gas reserves. Capital expenditures represent additions to property and equipment excluding corporate acquisitions, property exchanges and asset retirement costs. Capital expenditures and costs incurred are presented on an accrual basis. Additions to properties and equipment on the consolidated statement of cash flows include certain adjustments that give effect to the timing of actual cash payments in order to provide a cash-basis presentation. |
Anadarko’s capital expenditures decreased 7% for the year ended December 31, 2009 primarily due to declines in development drilling expenditures onshore United States and expenditures on gathering and processing facilities. These declines were partially offset by an increase in development drilling expenditures in Ghana, exploration drilling expenditures onshore United States, property acquisition costs and capital expenditures related to the Company’s acquisition of its office buildings in The Woodlands, Texas. The Company’s capital spending increased 22% for the year ended December 31, 2008. The 2008 increase was due to an increase in development drilling expenditures primarily onshore in the U.S. and exploration lease acquisition activity primarily offshore in the U.S., partially offset by a decrease in expenditures related to construction, and gathering and processing facilities. Additionally, both 2008 and 2007 were impacted by rising service and materials costs. The mix of oil and gas spending reflects the Company’s available opportunities based on the near-term ranking of projects by net asset value potential.
Property acquisitions in 2009 primarily related to exploratory non-producing leases onshore United States and proved property acquisitions related to property exchanges in the Rockies. Property acquisitions in 2008 primarily related to exploratory non-producing leases. Proved and unproved property acquisitions in 2007 include adjustments of $(600) million and $(484) million, respectively, related to finalizing the allocation of fair value to oil and gas properties acquired in connection with the acquisitions of Kerr-McGee and Western in 2006.
See Outlook below for information regarding sources of cash used to fund capital expenditures for 2010.
Debt Repayments At year-end 2009, Anadarko’s total debt was $12.7 billion compared to total debt of $12.3 billion at year-end 2008 and $14.7 billion at year-end 2007. In 2009, the Company repaid an aggregate principal amount of $1.6 billion of debt that was outstanding at December 31, 2008, including $1.4 billion in aggregate principal amount of Floating-Rate Notes due in 2009.
In 2008, the Company repaid an aggregate principal amount of $2.4 billion of debt that was outstanding at December 31, 2007, including a variable-rate 354-day facility and $580 million in aggregate principal amount of Floating-Rate Notes due September 2009.
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During 2007, Anadarko repaid $10.5 billion of indebtedness incurred in connection with its 2006 acquisitions of Kerr-McGee and Western.
For additional information on the Company’s debt instruments, such as transactions during the period, years of maturity and interest rates, see Note 6—Investments, Note 8—Derivative Instruments and Note 10—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.
Margin Deposits Both exchange and over-the-counter traded derivative instruments may be subject to margin deposit requirements. Exchange-broker margin requirements are determined by a standard industry algorithm, which requires a market-risk-based margin level be maintained on positions outstanding, from the date of trade execution through settlement. For derivatives with over-the-counter counterparties, the Company is required to provide margin deposits whenever its unrealized losses on derivative positions exceed predetermined credit limits. The Company manages its exposure to over-the-counter margin requirements through negotiated credit arrangements with counterparties, which may include collateral caps. When credit thresholds are exceeded, the Company utilizes available cash or letters of credit to satisfy margin requirements and maintains ample available committed credit facilities to meet its obligations. The Company’s working capital position and its RCA are sufficient to satisfy margin deposit requirements resulting from a significant increase in commodity prices or from entering into additional derivative positions. The Company had margin deposits outstanding and held cash collateral of $105 million and zero, respectively, at December 31, 2009. The Company had margin deposits outstanding and held cash collateral of $10 million and $3 million, respectively, at December 31, 2008. See Note 1—Summary of Significant Accounting Policies and Note 8—Derivative Instruments in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.
Common Stock Repurchase Program In August 2008, the Company announced a $5 billion share-repurchase program under which shares may be repurchased either in the open market or through privately negotiated transactions. The program is authorized to extend through August 2011. The program does not obligate Anadarko to acquire any specific number of shares and may be discontinued at any time. During 2008, Anadarko purchased 10 million shares of common stock for $600 million under the program through purchases in the open market and under share-repurchase agreements. During 2009 and 2007, no shares were repurchased under the programs in effect at those times.
Dividends In 2009, 2008 and 2007, Anadarko paid $176 million, $170 million and $170 million, respectively, in dividends to its common stockholders (nine cents per share per quarter). Anadarko has paid a dividend to its common stockholders continuously since becoming an independent public company in 1986. The amount of future dividends for Anadarko common stock will depend on earnings, financial conditions, capital requirements and other factors, and will be determined by the Board of Directors on a quarterly basis.
As of December 31, 2009, the covenants contained in certain of the Company’s credit and lease agreements provided for a maximum debt-to-capitalization ratio of 65%. The covenants do not specifically restrict the payment of dividends; however, the impact of dividends paid on the Company’s debt-to-capitalization ratio must be considered in order to ensure covenant compliance. Based on these covenants, as of December 31, 2009, the Company’s debt-to-capitalization ratio was 39% and retained earnings of approximately $13.3 billion were not limited as to the payment of dividends.
The following table shows the Company’s debt-to-capitalization ratio.
| December 31, | December 31, | |||||||
| millions except percentages | 2009 | 2008 | ||||||
| Current debt |
$ | — | $ | 1,472 | ||||
| Long-term debt |
11,149 | 9,128 | ||||||
| Total debt excluding related party debt |
11,149 | 10,600 | ||||||
| Midstream subsidiary note payable to a related party |
1,599 | 1,739 | ||||||
| Total debt |
$ | 12,748 | $ | 12,339 | ||||
| Stockholders’ Equity |
$ | 19,928 | $ | 18,795 | ||||
| Debt-to-capitalization ratio |
39.0 | % | 39.6 | % | ||||
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Outlook
Anadarko’s mission is to deliver a competitive and sustainable rate of return to shareholders by exploring for, acquiring and developing oil and natural-gas resources vital to the world’s health and welfare. Anadarko employs the following strategy to achieve this mission:
| • | identify and commercialize resources; |
| • | explore in high-potential, proven basins; |
| • | employ a global business development approach; and |
| • | ensure financial discipline and flexibility. |
Developing a portfolio of primarily unconventional resources provides the Company a stable base of capital-efficient, predictable and repeatable development opportunities which, in turn, positions the Company for consistent growth at competitive rates.
Exploring in high-potential, proven and emerging basins worldwide provides the Company with differential growth opportunities. Anadarko’s exploration success creates value by expanding its future resource potential, while providing the flexibility to manage risk by monetizing discoveries.
Anadarko’s global business development approach transfers core skills across the globe to assist in the discovery and development of world-class resources that are accretive to the Company’s performance. These resources help form an optimized global portfolio where both surface and subsurface risks are actively managed.
A strong balance sheet is essential for the development of the Company’s assets, and Anadarko is committed to disciplined investments in its businesses to manage through commodity price cycles. Maintaining financial discipline enables the Company to capitalize on the flexibility of its global portfolio, while allowing the Company to pursue new strategic and tactical growth opportunities.
The Company’s capital budgeting process is ongoing. The Company plans to allocate approximately 65% of its capital spending to development activities, 25% to exploration activities and 10% to gas-gathering and processing activities and other items. The Company expects capital spending by area to be approximately 40% for the U.S. onshore region, which includes the Lower 48 region and Alaska, 20% for the Gulf of Mexico, 30% for International and 10% for Midstream and other. The Company’s primary emphasis will be on managing near-term growth opportunities with a commitment to worldwide exploration and the continued development of large oil projects in Algeria, offshore Ghana and in the deepwater Gulf of Mexico. Anadarko believes that its expected level of operating cash flows and cash on hand as of December 31, 2009, will be sufficient to fund the Company’s projected operational and capital programs for 2010. However, if capital expenditures exceed operating cash flow and cash on hand, funds would likely be supplemented as needed through short-term borrowings under Anadarko’s fully available $1.3 billion RCA or through the issuance of debt or equity.
In addition, to support 2010 cash flows, Anadarko has entered into strategic derivative positions as of December 31, 2009, on approximately 75% of its anticipated natural-gas sales volumes and approximately 70% of its anticipated oil and condensate sales volumes for 2010. In addition, the Company has entered into commodity-price-risk management derivative positions for the years 2011 and 2012. See Note 8—Derivative Instruments in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.
The Company may choose to refinance certain portions of its short-term borrowings by issuing long-term debt or equity under its shelf registration statement filed with the SEC in August 2009, or both. Also, the Company’s $1.6 billion midstream note contains credit-rating-downgrade triggers that would accelerate the maturity of this debt upon a downgrade of the Company’s unsecured credit rating to below “BB-” by Standard and Poor’s (S&P) or “Ba3” by Moody’s Investors Service (Moody’s). However, at December 31, 2009, the Company’s debt was rated “BBB-” with a stable outlook by S&P and “Baa3” with a stable outlook by Moody’s. Moreover, the Company’s access to its $1.3 billion RCA and cash on hand is sufficient to fund the repayment of the $1.6 billion midstream note.
The Company continuously monitors its leverage position and coordinates its capital expenditure program with its expected cash flows and projected debt-repayment schedule. The Company will continue to evaluate funding alternatives as needed, including property divestitures or borrowings under the Company’s RCA and the issuance of debt or equity securities.
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Credit Risks
Credit risk is represented by Anadarko’s exposure to non-payment or non-performance by the Company’s customers and counterparties. Generally, non-payment or non-performance results from a customer’s or counterparty’s inability to satisfy obligations. Anadarko monitors the creditworthiness of its customers and counterparties and establishes credit limits according to the Company’s credit policies and guidelines. The Company has the ability to require cash collateral as well as letters of credit from its financial counterparties to mitigate its exposure above assigned credit thresholds. With respect to physical counterparties, the Company has the ability to require prepayments or letters of credit to offset credit exposure when necessary. The Company routinely exercises its contractual right to net realized gains against realized losses when settling with its financial counterparties, and utilizes netting agreements with physical counterparties where possible.
Off-Balance Sheet Arrangements
We may enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. As of December 31, 2009, the material off-balance sheet arrangements and transactions that we have entered into include operating lease arrangements and undrawn letters of credit. Other than the off-balance sheet arrangements above, we have no transactions, arrangements or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect our liquidity or availability of or requirements for capital resources. See Obligations and Commitments for more information regarding off-balance sheet arrangements.
Other
In 2007, Anadarko contributed certain of its oil and gas properties and gathering and processing assets, with an aggregate fair value of approximately $2.9 billion at the time of contribution, to newly formed unconsolidated entities in exchange for noncontrolling mandatorily redeemable interests in those entities. Subsequent to their formation, the investee entities loaned Anadarko an aggregate of $2.9 billion, which the Company used to repay its 2006 acquisition-related debt. Anadarko has a legal right to setoff and intends to net-settle its obligations under each of the notes payable to the investees with the distributable fair value of its interest in the corresponding investee. Accordingly, the $2.9 billion aggregate principal amount of such notes does not affect Anadarko’s reported debt balance, since the notes and the carrying amount of Anadarko’s investments in the investees are presented on the consolidated balance sheet on a net basis. The related interest expense on these obligations and Anadarko’s equity earnings attributable to its investments in these entities are recorded in other income (expense), net. Note 6—Investments in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K provides additional information with respect to each of these transactions. Completion of these transactions resulted in Anadarko divesting control of its interests in certain non-core exploration and production and midstream assets and operations, while retaining a participating 5% interest in profits, losses and residual value of the investees.
With respect to each investee, liquidation of the investee or redemption of Anadarko’s interest in the investee is expected to result in Anadarko net-settling in cash its obligation under the corresponding note payable with the distributable fair value of its interest in the investee. The Company does not currently expect such net settlement to have a material effect on its future financial condition, results of operations or cash flows. Each of Anadarko’s noncontrolling interests in the investees is optionally redeemable by Anadarko or the controlling investor in or after 2022 and is mandatorily redeemable in 2037.
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Obligations and Commitments
The following is a summary of the Company’s obligations as of December 31, 2009:
| Obligations by Period | |||||||||||||||
| millions | 1 Year | 2-3 Years |
4-5 Years |
More than 5 Years |
Total | ||||||||||
| Total debt |
|||||||||||||||
| Principal—current debt |
$ | — | $ | — | $ | — | $ | — | $ | — | |||||
| Principal—long-term debt |
— | 1,877 | 775 | 10,257 | 12,909 | ||||||||||
| Midstream subsidiary note payable to a related party |
— | 1,599 | — | — | 1,599 | ||||||||||
| Investee entities’ debt(1) |
— | — | — | 2,853 | 2,853 | ||||||||||
| Interest |
756 | 1,371 | 1,181 | 7,877 | 11,185 | ||||||||||
| Investee entities’ interest(1) |
37 | 73 | 72 | 996 | 1,178 | ||||||||||
| Operating leases |
|||||||||||||||
| Drilling rig commitments |
807 | 1,372 | 291 | — | 2,470 | ||||||||||
| Production platforms |
61 | 108 | 105 | 249 | 523 | ||||||||||
| Other |
103 | 168 | 82 | 47 | 400 | ||||||||||
| Asset retirement obligations |
31 | 235 | 260 | 920 | 1,446 | ||||||||||
| Midstream and marketing activities |
190 | 328 | 227 | 310 | 1,055 | ||||||||||
| Oil and gas activities |
1,446 | 1,122 | 238 | 395 | 3,201 | ||||||||||
| Derivative liabilities(2) |
180 | 28 | — | — | 208 | ||||||||||
| FIN 48 liabilities, interest and penalties(3) |
5 | 28 | — | 12 | 45 | ||||||||||
| Environmental liabilities |
21 | 25 | 8 | 42 | 96 | ||||||||||
| Total(4) |
$ | 3,637 | $ | 8,334 | $ | 3,239 | $ | 23,958 | $ | 39,168 | |||||
| (1) | Anadarko has legal right of setoff and intends to net-settle its obligations under each of the notes payable to the investees with the distributable fair value of its interest in the corresponding investee. Accordingly, the investment and the obligation are presented net on the consolidated balance sheet and included in other long-term liabilities—other for all periods presented. See Note 6—Investments in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K and Off-Balance Sheet Arrangements and Other discussed above. |
| (2) | Represents gross derivative liability after impact of netting margin and collateral balances deposited with counterparties. See Note 8—Derivative Instruments under Item 8 of this Form 10-K. |
| (3) | See Note 16—Income Taxes in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K. |
| (4) | This table does not include the Company’s pension or postretirement benefit obligations. See Note 20—Pension Plans, Other Postretirement Benefits and Employee Savings Plans in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K. |
Operating Leases Operating lease obligations include several deepwater drilling rig commitments. Anadarko continues to manage its access to rigs in order to execute its worldwide deepwater drilling strategy over the next several years. The Company believes these rig commitments offer compelling economics and facilitate its strategy. The portion of lease payments associated with successful exploratory wells and development wells, net of amounts billed to partners, will be capitalized as a component of oil and gas properties.
The Company also has $0.9 billion in commitments under noncancelable operating lease agreements for production platforms and equipment, buildings, facilities and aircraft.
For additional information see Note 13—Commitments in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.
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Asset Retirement Obligations Anadarko is obligated to dispose of long-lived assets upon their abandonment. The majority of Anadarko’s asset retirement obligations (AROs) relate to the plugging and abandonment of oil and gas properties. The ARO is recorded at its estimated fair value, measured by reference to the expected future cash outflows required to satisfy the retirement obligation discounted at the Company’s credit-adjusted risk-free interest rate. Revisions to estimated AROs can result from changes in retirement cost estimates, revisions to estimated inflation rates and changes in the estimated timing of abandonment.
Midstream and Marketing Activities Anadarko has entered into various transportation, storage and purchase agreements in order to access markets and provide flexibility for the sale of its natural gas and crude oil in certain areas.
Oil and Gas Activities Anadarko has various long-term contractual commitments pertaining to exploration, development and production activities, which extend beyond 2010. The Company has work-related commitments for, among other things, drilling wells, obtaining and processing seismic and fulfilling rig commitments. The preceding table includes long-term drilling and work-related commitments of $3,201 million, comprised of $1,857 million related to the United States and $1,344 million related to international locations.
The Company is obligated for approximately 27% of the construction costs of a floating production, storage and offloading vessel (FPSO) that will be used in the Company’s Ghana operations. Construction of the FPSO is expected to be complete in the first half of 2010. The Company’s share of total construction costs is estimated to be approximately $224 million. At December 31, 2009, the Company has accrued a net liability of $129 million representing Anadarko’s net share of construction costs incurred to date, less amounts funded by Anadarko through loans or other payments to the contractor of approximately $60 million. The Company’s obligation for construction costs is reported net of amounts previously funded as Anadarko has a contractual right to offset collection of the loans against the Company’s construction cost obligation. The Company’s remaining $35 million funding obligation is included in oil and gas activities in the preceding table.
Marketing and Trading Contracts At December 31, 2009, the fair value of the Company’s marketing and trading portfolio of physical delivery and financially settled derivative instruments was $6 million. See Critical Accounting Estimates for an explanation of how the fair value for derivatives is calculated.
Environmental Anadarko is subject to various environmental-remediation and reclamation obligations arising from federal, state and local laws and regulations. As of December 31, 2009, the Company’s balance sheet included a $96 million liability for remediation and reclamation obligations, most of which were incurred by companies acquired by Anadarko. The Company continually monitors the liability recorded and the remediation and reclamation process, and believes the amount recorded is appropriate. For additional information on environmental issues, see Risk Factors under Item 1A of this Form 10-K.
For additional information on contracts, obligations and arrangements the Company enters into from time to time, see Note 8—Derivative Instruments, Note 10—Debt and Interest Expense, Note 13—Commitments, and Note 14—Contingencies in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.
Discontinued Operations In November 2006, Anadarko sold its wholly owned subsidiary, Anadarko Canada Corporation. The results of Anadarko’s Canadian operations have been classified as discontinued operations in the consolidated statements of income and cash flows for 2008 and 2007 primarily related to adjustments to an indemnity obligation provided by the Company to the purchaser, as well as expenses associated with finalizing exit activities. See Note 14—Contingencies in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.
CRITICAL ACCOUNTING ESTIMATES
In preparing financial statements in accordance with GAAP, management makes informed judgments and estimates that affect the reported amounts of assets and liabilities as of the date of the financial statements and affect the reported amounts of revenues and expenses during the periods reported. On an ongoing basis, management reviews its estimates, including those related to the determination of properties and equipment,
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proved reserves, goodwill, asset retirement obligations, litigation, environmental liabilities, pension liabilities and costs, income taxes and fair values. Changes in facts and circumstances or the discovery of new information may result in revised estimates and actual results may differ from these estimates. Management considers the following to be its most critical accounting estimates that involve judgment and discusses the selection and development of these estimates with the Company’s Audit Committee.
Oil and Gas Activities
Anadarko applies the successful efforts method of accounting to account for its oil and gas activities. Under this method, acquisition costs and the costs associated with drilling exploratory wells are capitalized pending the determination of proved oil and gas reserves. Geological and geophysical costs and other costs of carrying properties such as delay rentals are expensed as incurred.
Acquisition Costs
Acquisition costs of unproved properties are assessed for impairment during the holding period and transferred to proved oil and gas properties to the extent the costs are associated with successful exploration activities. Significant undeveloped leases are assessed individually for impairment, based on the Company’s current exploration plans, and a valuation allowance is provided if impairment is indicated.
For unproved oil and gas properties with individually insignificant lease acquisition costs, costs are amortized on a group basis over the average lease terms at rates that provide for full amortization of unsuccessful leases upon lease expiration. Costs of expired or abandoned leases are charged against the valuation allowance, while costs of productive leases are transferred to proved oil and gas properties. Amortization of individually insignificant leases and impairment of unsuccessful leases are included in exploration expense.
Significant undeveloped leasehold costs are assessed for impairment at a lease level or resource play (for example, the Greater Natural Buttes area in the Rockies), while leasehold acquisition costs associated with prospective areas that have had limited or no previous exploratory drilling are generally assessed for impairment by major prospect area.
A majority of the Company’s unproved leasehold costs are associated with properties acquired in the Kerr-McGee and Western acquisitions in 2006 and to which proved developed producing reserves are also attributed. Generally, economic recovery of unproved reserves in such areas is not yet supported by actual production or conclusive formation tests, but may be confirmed by the Company’s continuing exploration and development programs.
Another portion of the Company’s unproved leasehold costs are associated with the Land Grant acreage, where the Company owns mineral interests in perpetuity and plans to continue to explore and evaluate the acreage.
A change in the Company’s expected future plans for exploration and development could cause an impairment of the Company’s unproved property.
Exploratory Costs
Under the successful efforts method of accounting, exploratory costs associated with a discovery well are initially capitalized, or suspended, pending determination of whether proved reserves can be attributed to the area as a result of drilling. At the end of each quarter, management reviews the status of all suspended exploratory drilling costs in light of ongoing exploration activities—in particular, whether the Company is making sufficient progress in its ongoing exploration and appraisal efforts or, in the case of discoveries requiring government sanctioning, whether development negotiations are underway or proceeding as planned. If management determines that future appraisal drilling or development activities are unlikely to occur, associated suspended exploratory drilling costs are expensed. Therefore, at any point in time, the Company may have capitalized costs on its consolidated balance sheet associated with exploratory wells that may be charged to exploration expense in a future period. At December 31, 2009, suspended exploratory drilling costs were $579 million compared to $279 million at December 31, 2008.
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Proved Reserves
In December 2009, Anadarko adopted revised oil and gas reserve estimation and disclosure requirements which conforms the definition of proved reserves with the SEC Modernization of Oil and Gas Reporting rules, which were issued by the SEC at the end of 2008. The new accounting standard requires that the average, first-day-of-the-month price during the 12-month period preceding the end of the year, rather than the year-end price, be used when estimating reserve quantities and permits the use of reliable technologies to determine proved reserves, if those technologies have been demonstrated to result in reliable conclusions about reserves volumes. Prior-year data are presented in accordance with FASB oil and gas disclosure requirements effective during those periods; however, historical information has been reclassified to conform to the significant geographic areas required to be disclosed in 2009 under the revised accounting standard.
Anadarko estimates its proved oil and gas reserves as defined by the SEC and the FASB. This definition includes crude oil, natural gas, and NGLs which geological and engineering data demonstrate with reasonable certainty to be economically producible in future periods from known reservoirs under existing economic conditions, operating methods, government regulations, etc., i.e., at prices as described above and costs as of the date the estimates are made. Prices include consideration of changes in existing prices provided only by contractual arrangements, and do not include adjustments based upon expected future conditions.
The Company’s estimate of proved reserves is made using available geological and reservoir data as well as production performance data. These estimates are reviewed annually by internal reservoir engineers and revised, either upward or downward, as warranted by additional data. Revisions are necessary due to changes in, among other things, reservoir performance, prices, economic conditions and governmental restrictions, as well as changes in the expected recovery associated with infill drilling. Decreases in prices, for example, may cause a reduction in some proved reserves due to reaching economic limits earlier. A material adverse change in the estimated volumes of proved reserves could have a negative impact on DD&A expense and could result in the recognition of an impairment.
Fair Value
The Company estimates fair value for derivatives, long-lived assets for impairment testing, reporting units for goodwill impairment testing, certain exchanges, guarantees, pension plan assets, the initial measurement of an asset retirement obligation, and assets and liabilities acquired in a business combination. When the Company is required to measure fair value, and there is not a market-observable price for the asset or liability, or a market-observable price for a similar asset or liability, the Company generally utilizes an income valuation approach. This approach is based upon management’s best assumptions regarding expectations of projected cash flows, and discounts the expected cash flows using a commensurate risk-adjusted discount rate. Such evaluations involve significant judgment and the results are based on expected future events or conditions, such as sales prices, estimates of future oil and gas production or throughput, development and operating costs and the timing thereof, economic and regulatory climates and other factors. The Company’s estimates of future net cash flows are inherently imprecise because they reflect management’s expectation of future conditions that are often outside of management’s control. However, assumptions used reflect a market participant’s view of long-term prices, costs and other factors, and are consistent with assumptions used in the Company’s business plans and investment decisions.
Business Combinations
Accounting for the acquisition of a business requires the allocation of the purchase price to the various assets and liabilities of the acquired business and recording deferred taxes for any differences between the allocated values and tax basis of assets and liabilities. Any excess of the purchase price over the amounts assigned to assets and liabilities is recorded as goodwill.
Purchase Price Allocation
The purchase price allocation is accomplished by recording each asset and liability at its estimated fair value. Estimated deferred taxes are based on available information concerning the tax basis of the acquired company’s assets and liabilities and tax-related carryforwards at the merger date, although such estimates may
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change in the future as additional information becomes known. The amount of goodwill recorded in any particular business combination can vary significantly depending upon the values attributed to assets acquired and liabilities assumed relative to the total acquisition cost.
Goodwill
At December 31, 2009, the Company had $5.3 billion of goodwill recorded related to past business combinations. Goodwill is required to be assessed for impairment annually, or more often as facts and circumstances warrant. The first step in assessing whether an impairment of goodwill is necessary is to compare the fair value of the reporting unit to which goodwill has been assigned to the carrying amount of the associated net assets and goodwill. A reporting unit is an operating segment or a component that is one level below an operating segment. Anadarko has allocated goodwill to three reporting units. These reporting units are oil and gas exploration and production, gathering and processing, and transportation. As of December 31, 2009, these reporting units have a goodwill balance of $5.2 billion, $135 million and $5 million, respectively.
During 2009, the Company changed its goodwill–impairment testing date from January 1 to October 1. The Company completed its January 1, 2009, and October 1, 2009, annual goodwill impairment tests with no goodwill impairment indicated. Although Anadarko cannot predict when or if goodwill will be impaired in the future, impairment charges may occur if the Company is unable to replace the value of its depleting asset base or if other adverse events (for example, lower sustained oil and gas prices) reduce the fair value of the associated reporting unit.
Because quoted market prices for the Company’s reporting units are not available, management must apply judgment in determining the estimated fair value of reporting units for purposes of performing the goodwill impairment test. Management uses all available information to make these fair-value estimates, including the present values of expected future cash flows using discount rates commensurate with the risks associated with the assets and observed for the oil and gas exploration and production reporting unit, and market multiples of earnings before interest, taxes, depreciation and amortization (EBITDA) for the gathering and processing and transportation reporting units.
In estimating the fair value of its oil and gas reporting unit, the Company assumes production profiles utilized in its estimation of reserves that are disclosed in the Company’s supplemental oil and gas disclosures, market prices based on the forward price curve for oil and gas as of the test date (adjusted for location and quality differentials), capital and operating costs consistent with pricing and expected inflation rates, and discount rates that management believes a market participant would utilize based upon the risks inherent in Anadarko’s operations.
For the Company’s gathering and processing and transportation reporting units, the Company estimates fair value by applying an estimated multiple to projected 2010 EBITDA. The Company considered the relatively few observable transactions in the market, as well as trading multiples for peers to determine an appropriate multiple to apply against the Company’s projected EBITDA for its gathering and processing and transportation reporting units.
A lower fair-value estimate in the future for any of these reporting units could result in a goodwill impairment. Factors that could trigger a lower fair-value estimate include sustained price declines, cost increases, regulatory or political environment changes, and other changes in market conditions such as decreased prices in market-based transactions for similar assets. Based on our most recent goodwill impairment test, we concluded that the fair value of each reporting unit substantially exceeded the carrying value of the reporting unit. Therefore, no goodwill impairment was indicated.
Impairment of Assets
A long-lived asset other than unproved oil and gas property is evaluated for potential impairment whenever events or changes in circumstances indicate that its carrying value may be greater than its future net undiscounted cash flows. Impairment, if any, is measured as the excess of an asset’s carrying amount over its estimated fair value. The Company utilizes an income approach when market information for the same or similar assets does not exist. This fair-value approach requires us to use management’s best estimates, including asset production profiles and cost expectations, combined with inputs a market participant would use e.g., prices and discount rates.
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Derivative Instruments
All derivative instruments, other than those that satisfy specific exceptions, are recorded at fair value. If market quotes are not available to estimate fair value, management’s best estimate of fair value is based on the quoted market price of derivatives with similar characteristics or utilizing industry-standard valuation techniques.
The Company’s derivative instruments are either exchange-traded or transacted in an over-the-counter market. Valuation is determined by reference to readily available public data for similar instruments. Option fair values are measured using the Black-Scholes option-pricing model and verified by comparing a sample to market quotes for similar options. Unrealized gains or losses on derivatives are recorded within Anadarko’s current earnings.
Benefit Plan Obligations
The Company has non-contributory defined-benefit pension plans, including both qualified and supplemental plans, and a foreign contributory defined-benefit pension plan. The Company also provides certain health care and life insurance benefits for retired employees. Determination of the projected benefit obligations for the Company’s defined-benefit pension and postretirement plans impacts the recorded amounts for such obligations on the balance sheet, the amount of benefit expense recorded to the income statement, and the Company’s decision regarding amounts to be contributed to the plans.
Accounting for pension and other postretirement benefit obligations involves numerous assumptions, the most significant of which relate to the discount rate used for measuring the present value of future plan obligations, the fair value and expected long-term rates of return on plan assets, rate of future increases in compensation levels and health care cost projections. Anadarko analyzes demographics and utilizes third-party actuaries to assist in the measurement of these obligations.
Discount rate
The discount-rate assumption used by the Company reflects the interest rate at which the pension and other postretirement obligations could effectively be settled on the measurement date. The Company currently uses a yield curve analysis to support the discount-rate assumption for the plans. This analysis involves the creation of a hypothetical Aa spot yield curve represented by a series of high-quality, non-callable, marketable bonds, then discounts the projected cash flows from each plan at interest rates on the created curve specifically applicable to the timing of each respective cash flow. The present values of the cash flows are then accumulated, and a weighted-average discount rate is calculated by imputing the single discount rate that equates to the total present value of the cash flows. The consolidated discount-rate assumption is determined by evaluation of the weighted-average discount rates determined for each of the Company’s significant pension and postretirement plans. The weighted-average discount-rate assumption used by the Company as of December 31, 2009, was 5.25% and 5.5% for pension plans and other postretirement plans, respectively.
Expected long-term rate of return
The expected long-term rate of return on assets assumption was determined using the year-end 2009 pension investment balances by category and projected long-term target asset allocations. The expected return for each of these categories was determined by using capital-market projections. The Company’s capital-market projection uses a forward-looking building-block approach and is not strictly based upon historical returns. Equity returns are generally developed as the sum of inflation, expected real earnings growth and expected long-term dividend yield. Bond returns are generally developed as the sum of inflation, real bond yield and risk spread (as appropriate), adjusted for the expected effect on returns from changing yields. Other asset class returns are derived from their relationship to the equity and bond markets. Consideration was also given to current market conditions. Anadarko’s expected long-term rate of return is expected to be fairly consistent from year to year; however, it may change due to changes in asset-allocation targets, changes in financial market conditions and changes in the general economic outlook. The weighted-average expected long-term rate of return on plan assets assumption used by the Company as of December 31, 2009, was 7.5%.
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Rate of compensation increases
The Company’s assumption is based on its long-term plans for compensation increases specific to covered employee groups and expected economic conditions. The assumed rate of salary increases includes the effects of merit increases, promotions and general inflation. The weighted-average rate of increase in long-term compensation levels assumption used by the Company as of December 31, 2009, was 5.0%.
Health care cost trend rate
The health care cost trend assumptions are developed based on historical cost data, the near-term outlook and an assessment of likely long-term trends. A 9.0% annual rate of increase in the per-capita cost of covered health care benefits was assumed for 2010, decreasing gradually to 5.0% in 2018 and later years.
Environmental Obligations and Other Contingencies
Management makes judgments and estimates in accordance with applicable accounting rules when it establishes reserves for environmental remediation, litigation and other contingent matters. Provisions for such matters are charged to expense when it is probable that a liability has been incurred and reasonable estimates of the liability can be made. Estimates of environmental liabilities are based on a variety of matters, including, but not limited to, the stage of investigation, the stage of the remedial design, evaluation of existing remediation technologies, and presently enacted laws and regulations. In future periods, a number of factors could significantly change the Company’s estimate of environmental-remediation costs, such as changes in laws and regulations, changes in the interpretation or administration of laws and regulations, revisions to the remedial design, unanticipated construction problems, identification of additional areas or volumes of contaminated soil and groundwater, and changes in costs of labor, equipment and technology. Consequently, it is not possible for management to reliably estimate the amount and timing of all future expenditures related to environmental or other contingent matters and actual costs may vary significantly from the Company’s estimates. The Company’s in-house legal counsel and environmental personnel regularly assess these contingent liabilities and, in certain circumstances, third-party legal counsel or consultants are utilized.
Income Taxes
The amount of income taxes recorded by the Company requires interpretations of complex rules and regulations of various tax jurisdictions throughout the world. The Company has recognized deferred tax assets and liabilities for temporary differences, operating losses and tax credit carryforwards. The Company routinely assesses the realizability of its deferred tax assets and reduces such assets by a valuation allowance if it is more likely than not that some portion or all of the deferred tax assets will not be realized. The Company routinely assesses potential uncertain tax positions and, if required, establishes accruals for such amounts. The accruals for deferred tax assets and liabilities are subject to a significant amount of judgment by Company management and are reviewed and adjusted routinely based on changes in facts and circumstances. Although management considers its tax accruals adequate, material changes in these accruals may occur in the future, based on the progress of ongoing tax audits, changes in legislation and resolution of pending tax matters.
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RECENT ACCOUNTING DEVELOPMENTS
In June 2009, the FASB issued amendments to the consolidation standard applicable to variable interest entities. The amendments significantly reduce the previously required quantitative consolidation analysis, and require ongoing reassessments of whether the Company is the primary beneficiary of a variable interest entity. This standard is effective for the Company on January 1, 2010. The adoption of this standard will not have an impact on the Company’s consolidated financial position, results of operations or cash flows.
In January 2010, the FASB adopted changes to the definition of proved reserves, requiring proved reserves to be computed using the average, first-day-of-the-month price during the 12-month period before the end of the year, as well as allowing the use of reliable technology in determining estimates of proved reserves. These new reserve estimates will be used in determining depletion expense for the Company’s oil and gas properties beginning January 1, 2010. Adoption of these new definitions will not have a material impact on depletion expense recorded in future periods.
For additional information on recently issued accounting standards not yet adopted, see Note 1—Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.
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| Item 7A. | Quantitative and Qualitative Disclosures About Market Risk |
The Company’s primary market risks are attributable to fluctuations in energy prices and interest rates. These fluctuations can affect revenues and cash flow from operating, investing and financing activities. The Company’s risk-management policies provide for the use of derivative instruments to manage these risks. The types of derivative instruments utilized by the Company include futures, swaps, options and fixed-price physical-delivery contracts. The volume of commodity derivative instruments utilized by the Company may vary from year to year and is governed by risk-management policies with levels of authority delegated by the Board of Directors. Both exchange and over-the-counter traded commodity derivative instruments may be subject to margin deposit requirements, and the Company may be required from time to time to deposit cash or provide letters of credit with exchange brokers or its counterparties in order to satisfy these margin requirements. For additional information see Liquidity and Capital Resources—Uses of Cash—Margin Deposits under Part II, Item 7 of this Form 10-K.
For information regarding the Company’s accounting policies and additional information related to the Company’s derivative and financial instruments, see Note 1—Summary of Significant Accounting Policies, Note 8—Derivative Instruments and Note 10—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.
COMMODITY PRICE RISK The Company’s most significant market risk relates to the pricing for natural gas, crude oil and NGLs. Management expects the prices of these commodities to remain volatile and unpredictable. As these prices decline or rise significantly, revenues and cash flow will also decline or rise significantly. In addition, a non-cash write-down of the Company’s oil and gas properties may be required if future commodity prices experience a sustained and significant decline. Below is a sensitivity analysis of the Company’s commodity-price-related derivative instruments.
Derivative Instruments Held for Non-Trading Purposes The Company had derivative instruments in place to reduce the price risk associated with future equity production of approximately 1 trillion cubic feet (Tcf) of natural gas and 49 MMBbls of crude oil as of December 31, 2009. At December 31, 2009, the Company had a net liability derivative position of $101 million related to these derivative instruments. Utilizing actual derivative contractual volumes, a 10% increase in underlying commodity prices would reduce the fair value of these instruments by approximately $528 million, while a 10% decrease in underlying commodity prices would increase the fair value of these instruments by approximately $478 million. However, a gain or loss would be substantially offset by a decrease or increase, respectively, in the actual sales value of production covered by the derivative instruments.
Derivative Instruments Held for Trading Purposes At December 31, 2009, the Company had a net asset derivative position of $6 million related to derivative instruments entered into for trading purposes. Utilizing actual derivative contractual volumes, a 10% increase or decrease in underlying commodity prices would result in a loss or gain, respectively, on these derivative instruments of approximately $8 million or $9 million, respectively.
For additional information regarding the Company’s marketing and trading portfolio, see Marketing Activities under Items 1 and 2 of this Form 10-K.
INTEREST-RATE RISK As of December 31, 2009, Anadarko had outstanding $1.6 billion of variable-rate debt (Midstream Subsidiary Note Payable to a Related Party) and $11.1 billion of fixed-rate debt. A 10% increase in LIBOR interest rates would increase gross interest expense by approximately $0.4 million per year.
In December 2008 and January 2009, Anadarko entered into interest-rate swap agreements with a combined notional principal amount of $3.0 billion, whereby the Company locked in a fixed interest rate in exchange for a floating interest rate indexed to the three-month London Interbank Offered Rate (LIBOR). The Company’s intent is to settle these positions at the earlier of the related debt issuance or the start date of the swaps. A 10% increase or decrease in the three-month LIBOR interest-rate curve would increase or decrease, respectively, the fair value of outstanding interest-rate swap agreements by approximately $117 million. At December 31, 2009, the Company had a net asset derivative position of $50 million related to interest-rate swaps. For a summary of the Company’s open interest-rate derivative positions, see Note 8—Derivative Instruments in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.
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| Item 8. | Financial Statements and Supplementary Data |
ANADARKO PETROLEUM CORPORATION
INDEX
CONSOLIDATED FINANCIAL STATEMENTS
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ANADARKO PETROLEUM CORPORATION
REPORT OF MANAGEMENT
Management prepared, and is responsible for, the consolidated financial statements and the other information appearing in this annual report. The consolidated financial statements present fairly the Company’s financial position, results of operations and cash flows in conformity with accounting principles generally accepted in the United States. In preparing its consolidated financial statements, the Company includes amounts that are based on estimates and judgments that Management believes are reasonable under the circumstances. The Company’s financial statements have been audited by KPMG LLP, an independent registered public accounting firm appointed by the Audit Committee of the Board of Directors. Management has made available to KPMG LLP all of the Company’s financial records and related data, as well as the minutes of the stockholders’ and Directors’ meetings.
MANAGEMENT’S ASSESSMENT OF INTERNAL CONTROL OVER FINANCIAL REPORTING
Management is responsible for establishing and maintaining adequate internal control over financial reporting. Anadarko’s internal control system was designed to provide reasonable assurance to the Company’s Management and Directors regarding the preparation and fair presentation of published 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.
Management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2009. This assessment was based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on our assessment, we believe that as of December 31, 2009 the Company’s internal control over financial reporting is effective based on those criteria.
KPMG LLP has issued an attestation report on the Company’s internal control over financial reporting as of December 31, 2009.
| /s/ JAMES T. HACKETT |
| James T. Hackett Chairman and Chief Executive Officer |
| /s/ ROBERT G. GWIN |
| Robert G. Gwin Senior Vice President, Finance and Chief Financial Officer |
| February 23, 2010 |
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Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders
Anadarko Petroleum Corporation:
We have audited Anadarko Petroleum Corporation’s internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Anadarko Petroleum Corporation’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 Assessment of Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, Anadarko Petroleum Corporation and subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Anadarko Petroleum Corporation and subsidiaries as of December 31, 2009 and 2008, and the related consolidated statements of income, equity, comprehensive income, and cash flows for each of the years in the three-year period ended December 31, 2009, and our report dated February 23, 2010 expressed an unqualified opinion on those consolidated financial statements.
| /s/ KPMG LLP |
| Houston, Texas |
| February 23, 2010 |
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Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders
Anadarko Petroleum Corporation:
We have audited the accompanying consolidated balance sheets of Anadarko Petroleum Corporation and subsidiaries as of December 31, 2009 and 2008, and the related consolidated statements of income, equity, comprehensive income, and cash flows for each of the years in the three-year period ended December 31, 2009. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Anadarko Petroleum Corporation and subsidiaries as of December 31, 2009 and 2008, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2009, in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Anadarko Petroleum Corporation’s internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 23, 2010 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.
| /s/ KPMG LLP |
| Houston, Texas |
| February 23, 2010 |
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ANADARKO PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
| Years Ended December 31 | ||||||||||||
| 2009 | 2008 | 2007 | ||||||||||
| millions except per share amounts | ||||||||||||
| Revenues and Other |
||||||||||||
| Gas sales |
$ | 2,924 | $ | 5,770 | $ | 4,043 | ||||||
| Oil and condensate sales |
4,022 | 6,425 | 5,407 | |||||||||
| Natural-gas-liquids sales |
536 | 802 | 719 | |||||||||
| Gathering, processing and marketing sales |
728 | 1,082 | 1,487 | |||||||||
| Gains (losses) on divestitures and other, net |
133 | 1,083 | 4,760 | |||||||||
| Reversal of accrual for DWRRA dispute (Note 14) |
657 | — | — | |||||||||
| Total |
9,000 | 15,162 | 16,416 | |||||||||
| Costs and Expenses |
||||||||||||
| Oil and gas operating |
933 | 1,104 | 1,101 | |||||||||
| Oil and gas transportation and other |
590 | 553 | 453 | |||||||||
| Exploration |
1,107 | 1,369 | 905 | |||||||||
| Gathering, processing and marketing |
617 | 800 | 1,025 | |||||||||
| General and administrative |
983 | 866 | 936 | |||||||||
| Depreciation, depletion and amortization |
3,532 | 3,194 | 2,840 | |||||||||
| Other taxes |
746 | 1,452 | 1,234 | |||||||||
| Impairments |
115 | 223 | 51 | |||||||||
| Total |
8,623 | 9,561 | 8,545 | |||||||||
| Operating Income |
377 | 5,601 | 7,871 | |||||||||
| Other (Income) Expense |
||||||||||||
| Interest expense |
702 | 732 | 1,083 | |||||||||
| (Gains) losses on commodity derivatives, net |
408 | (561 | ) | 524 | ||||||||
| (Gains) losses on other derivatives, net |
(582 | ) | 10 | 9 | ||||||||
| Other (income) expense, net |
(43 | ) | 52 | (71 | ) | |||||||
| Total |
485 | 233 | 1,545 | |||||||||
| Income (Loss) from Continuing Operations Before Income Taxes |
(108 | ) | 5,368 | 6,326 | ||||||||
| Income Tax Expense (Benefit) |
(5 | ) | 2,148 | 2,559 | ||||||||
| Income (Loss) from Continuing Operations |
(103 | ) | 3,220 | 3,767 | ||||||||
| Income from Discontinued Operations, net of taxes |
— | 63 | 11 | |||||||||
| Net Income (Loss) |
(103 | ) | 3,283 | 3,778 | ||||||||
| Net Income Attributable to Noncontrolling Interests |
32 | 23 | — | |||||||||
| Net Income (Loss) Attributable to Common Stockholders |
$ | (135 | ) | $ | 3,260 | $ | 3,778 | |||||
| Amounts Attributable to Common Stockholders |
||||||||||||
| Income (loss) from continuing operations attributable to common stockholders |
$ | (135 | ) | $ | 3,197 | $ | 3,767 | |||||
| Income from discontinued operations, net of taxes |
— | 63 | 11 | |||||||||
| Net income (loss) attributable to common stockholders |
$ | (135 | ) | $ | 3,260 | $ | 3,778 | |||||
| Per Common Share (amounts attributable to common stockholders): |
||||||||||||
| Income (loss) from continuing operations attributable to common stockholders—basic |
$ | (0.28 | ) | $ | 6.79 | $ | 8.01 | |||||
| Income (loss) from continuing operations attributable to common stockholders— diluted |
$ | (0.28 | ) | $ | 6.78 | $ | 7.99 | |||||
| Income from discontinued operations, net of taxes—basic |
$ | — | $ | 0.13 | $ | 0.02 | ||||||
| Income from discontinued operations, net of taxes—diluted |
$ | — | $ | 0.13 | $ | 0.02 | ||||||
| Net income (loss) attributable to common stockholders—basic |
$ | (0.28 | ) | $ | 6.92 | $ | 8.03 | |||||
| Net income (loss) attributable to common stockholders—diluted |
$ | (0.28 | ) | $ | 6.91 | $ | 8.01 | |||||
| Average Number of Common Shares Outstanding—Basic |
480 | 465 | 465 | |||||||||
| Average Number of Common Shares Outstanding—Diluted |
480 | 466 | 467 | |||||||||
| Dividends (per Common Share) |
$ | 0.36 | $ | 0.36 | $ | 0.36 | ||||||
See accompanying notes to consolidated financial statements.
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ANADARKO PETROLEUM CORPORATION
CONSOLIDATED BALANCE SHEETS
| December 31 | ||||||||
| 2009 | 2008 | |||||||
| millions | ||||||||
| ASSETS |
||||||||
| Current Assets |
||||||||
| Cash and cash equivalents |
$ | 3,531 | $ | 2,360 | ||||
| Accounts receivable, net of allowance: |
||||||||
| Customers |
1,019 | 791 | ||||||
| Others |
1,033 | 896 | ||||||
| Other current assets |
500 | 1,048 | ||||||
| Total |
6,083 | 5,095 | ||||||
| Properties and Equipment |
||||||||
| Cost |
50,344 | 47,073 | ||||||
| Less accumulated depreciation, depletion and amortization |
13,140 | 10,026 | ||||||
| Net properties and equipment |
37,204 | 37,047 | ||||||
| Other Assets |
1,514 | 1,368 | ||||||
| Goodwill and Other Intangible Assets |
5,322 | 5,413 | ||||||
| Total Assets |
$ | 50,123 | $ | 48,923 | ||||
| LIABILITIES AND EQUITY |
||||||||
| Current Liabilities |
||||||||
| Accounts payable |
$ | 2,876 | $ | 3,166 | ||||
| Accrued expenses |
948 | 898 | ||||||
| Current debt |
— | 1,472 | ||||||
| Total |
3,824 | 5,536 | ||||||
| Long-term Debt |
11,149 | 9,128 | ||||||
| Midstream Subsidiary Note Payable to a Related Party |
1,599 | 1,739 | ||||||
| Other Long-term Liabilities |
||||||||
| Deferred income taxes |
9,925 | 9,974 | ||||||
| Other |
3,211 | 3,390 | ||||||
| Total |
13,136 | 13,364 | ||||||
| Equity |
||||||||
| Stockholders’ Equity |
||||||||
| Common stock, par value $0.10 per share |
50 | 47 | ||||||
| Paid-in capital |
7,243 | 5,696 | ||||||
| Retained earnings |
13,868 | 14,179 | ||||||
| Treasury stock (12.4 million and 11.7 million shares as of December 31, 2009 and 2008, respectively) |
(721 | ) | (686 | ) | ||||
| Accumulated other comprehensive income (loss): |
||||||||
| Gains (losses) on derivative instruments |
(96 | ) | (118 | ) | ||||
| Foreign currency translation adjustments |
— | (1 | ) | |||||
| Pension and other postretirement plans |
(416 | ) | (322 | ) | ||||
| Total |
(512 | ) | (441 | ) | ||||
| Total Stockholders’ Equity |
19,928 | 18,795 | ||||||
| Noncontrolling Interests |
487 | 361 | ||||||
| Total Equity |
20,415 | 19,156 | ||||||
| Commitments and Contingencies (Note 13 and Note 14) |
||||||||
| Total Liabilities and Equity |
$ | 50,123 | $ | 48,923 | ||||
See accompanying notes to consolidated financial statements.
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ANADARKO PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF EQUITY
| Total Stockholders’ Equity | Total Stockholders’ Equity |
Non- controlling Interests |
Total Equity |
||||||||||||||||||||||||||||||||
| Preferred Stock |
Common Stock |
Paid-in Capital |
Retained Earnings |
Treasury Stock |
Accumulated Other Comprehensive Income (Loss) |
||||||||||||||||||||||||||||||
| millions | |||||||||||||||||||||||||||||||||||
| Balance at December 31, 2006 |
$ | 46 | $ | 47 | $ | 5,255 | $ | 7,409 | $ | (20 | ) | $ | (334 | ) | $ | 12,403 | $ | — | $ | 12,403 | |||||||||||||||
| Net income |
— | — | — | 3,778 | — | — | 3,778 | — | 3,778 | ||||||||||||||||||||||||||
| Preferred stock repurchased and retired |
(1 | ) | — | — | — | — | — | (1 | ) | — | (1 | ) | |||||||||||||||||||||||
| Common stock issued |
— | — | 256 | — | — | — | 256 | — | 256 | ||||||||||||||||||||||||||
| Dividends — common |
— | — | — | (170 | ) | — | — | (170 | ) | — | (170 | ) | |||||||||||||||||||||||
| Adoption of accounting standard for uncertain tax positions |
— | — | — | 72 | — | — | 72 | — | 72 | ||||||||||||||||||||||||||
| Repurchase of common stock |
— | — | — | — | (35 | ) | — | (35 | ) | — | (35 | ) | |||||||||||||||||||||||
| Previously deferred losses on derivative instruments |
— | — | — | — | — | 5 | 5 | — | 5 | ||||||||||||||||||||||||||
| Foreign currency translation adjustments |
— | — | — | — | — | (1 | ) | (1 | ) | — | (1 | ) | |||||||||||||||||||||||
| Pensions and other postretirement plans adjustments |
— | — | — | — | — | 57 | 57 | — | 57 | ||||||||||||||||||||||||||
| Balance at December 31, 2007 |
45 | 47 | 5,511 | 11,089 | (55 | ) | (273 | ) | 16,364 | — | 16,364 | ||||||||||||||||||||||||
| Net income |
— | — | — | 3,260 | — | — | 3,260 | 23 | 3,283 | ||||||||||||||||||||||||||
| Preferred stock repurchased and retired |
(45 | ) | — | — | — | — | — | (45 | ) | — | (45 | ) | |||||||||||||||||||||||
| Common stock issued |
— | — | 189 | — | — | — | 189 | — | 189 | ||||||||||||||||||||||||||
| Dividends — common |
— | — | — | (170 | ) | — | — | (170 | ) | — | (170 | ) | |||||||||||||||||||||||
| Repurchase of common stock |
— | — | — | — | (631 | ) | — | (631 | ) | — | (631 | ) | |||||||||||||||||||||||
| Sale of subsidiary units |
— | — | — | — | — | — | — | 343 | 343 | ||||||||||||||||||||||||||
| Contributions from (distributions to) noncontrolling interest owners and other, net |
— | — | (4 | ) | — | — | — | (4 | ) | (5 | ) | (9 | ) | ||||||||||||||||||||||
| Previously deferred losses on derivative instruments |
— | — | — | — | — | 14 | 14 | — | 14 | ||||||||||||||||||||||||||
| Pensions and other postretirement plans adjustments |
— | — | — | — | — | (182 | ) | (182 | ) | — | (182 | ) | |||||||||||||||||||||||
| Balance at December 31, 2008 |
— | 47 | 5,696 | 14,179 | (686 | ) | (441 | ) | 18,795 | 361 | 19,156 | ||||||||||||||||||||||||
| Net income (loss) |
— | — | — | (135 | ) | — | — | (135 | ) | 32 | (103 | ) | |||||||||||||||||||||||
| Common stock issued |
— | 3 | 1,547 | — | — | — | 1,550 | — | 1,550 | ||||||||||||||||||||||||||
| Dividends — common |
— | — | — | (176 | ) | — | — | (176 | ) | — | (176 | ) | |||||||||||||||||||||||
| Repurchase of common stock |
— | — | — | — | (35 | ) | — | (35 | ) | — | (35 | ) | |||||||||||||||||||||||
| Sale of subsidiary units |
— | — | — | — | — | — | — | 120 | 120 | ||||||||||||||||||||||||||
| Contributions from and (distributions to) noncontrolling interest owners, net |
— | — | — | — | — | — | — | (26 | ) | (26 | ) | ||||||||||||||||||||||||
| Previously deferred losses on derivative instruments |
— | — | — | — | — | 22 | 22 | — | 22 | ||||||||||||||||||||||||||
| Foreign currency translation adjustments |
— | — | — | — | — | 1 | 1 | — | 1 | ||||||||||||||||||||||||||
| Pensions and other postretirement plans adjustments |
— | — | — | — | — | (94 | ) | (94 | ) | — | (94 | ) | |||||||||||||||||||||||
| Balance at December 31, 2009 |
$ | — | $ | 50 | $ | 7,243 | $ | 13,868 | $ | (721 | ) | $ | (512 | ) | $ | 19,928 | $ | 487 | $ | 20,415 | |||||||||||||||
See accompanying notes to consolidated financial statements.
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ANADARKO PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
| Years Ended December 31 | ||||||||||||
| 2009 | 2008 | 2007 | ||||||||||
| millions | ||||||||||||
| Net Income (Loss) |
$ | (103) | $ | 3,283 | $ | 3,778 | ||||||
| Other Comprehensive Income (Loss), net of taxes |
||||||||||||
| Previously deferred losses on derivative instruments(1) |
22 | 14 | 5 | |||||||||
| Foreign currency translation adjustments |
1 | — | (1 | ) | ||||||||
| Pension and other postretirement plans adjustments: |
||||||||||||
| Net gain (loss) incurred during period(2) |
(124 | ) | (187 | ) | 42 | |||||||
| Amortization of net (gain) loss included in net periodic pension cost(3) |
30 | 9 | 11 | |||||||||
| Prior service credit (cost) incurred during period(4) |
— | (4 | ) | 4 | ||||||||
| Total pension and other postretirement plans adjustments |
(94 | ) | (182 | ) | 57 | |||||||
| Other |
— | 1 | 3 | |||||||||
| Total |
(71 | ) | (167 | ) | 64 | |||||||
| Comprehensive Income (Loss) |
(174 | ) | 3,116 | 3,842 | ||||||||
| Comprehensive Income Attributable to Noncontrolling Interests |
32 | 23 | — | |||||||||
| Comprehensive Income (Loss) Attributable to Common Stockholders |
$ | (206 | ) | $ | 3,093 | $ | 3,842 | |||||
| (1) | Net of income tax benefit (expense) of $(12) million, $(8) million, and $(3) million for the year ended December 31, 2009, 2008, and 2007, respectively. |
| (2) | Net of income tax benefit (expense) of $70 million, $107 million, and $(23) million for the year ended December 31, 2009, 2008, and 2007, respectively. |
| (3) | Net of income tax benefit (expense) of $(17) million, $(5) million, and $(7) million for the year ended December 31, 2009, 2008, and 2007, respectively. |
| (4) | Net of income tax benefit (expense) of zero, $2 million, and $(2) million for the year ended December 31, 2009, 2008, and 2007, respectively. |
See accompanying notes to consolidated financial statements.
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ANADARKO PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
| Years Ended December 31 | ||||||||||||
| 2009 | 2008 | 2007 | ||||||||||
| millions | ||||||||||||
| Cash Flow from Operating Activities |
||||||||||||
| Net income (loss) |
$ | (103 | ) | $ | 3,283 | $ | 3,778 | |||||
| Less income from discontinued operations, net of taxes |
— | 63 | 11 | |||||||||
| Adjustments to reconcile net income (loss) to net cash provided by operating activities: |
||||||||||||
| Depreciation, depletion and amortization |
3,532 | 3,194 | 2,840 | |||||||||
| Deferred income taxes |
(165 | ) | (22 | ) | (1,057 | ) | ||||||
| Dry hole expense and impairments of unproved properties |
780 | 1,005 | 632 | |||||||||
| Impairments |
115 | 223 | 51 | |||||||||
| (Gains) losses on divestitures, net |
(44 | ) | (993 | ) | (4,660 | ) | ||||||
| Unrealized (gains) losses on derivatives |
717 | (919 | ) | 1,048 | ||||||||
| Reversal of accrual for DWRRA dispute (Note 14) |
(657 | ) | — | — | ||||||||
| Other non-cash items |
183 | 125 | 175 | |||||||||
| Changes in assets and liabilities: |
||||||||||||
| (Increase) decrease in accounts receivable |
(290 | ) | 803 | 391 | ||||||||
| Increase (decrease) in accounts payable and accrued expenses |
269 | 158 | (1,521 | ) | ||||||||
| Other items-net |
(411 | ) | (347 | ) | 1,100 | |||||||
| Cash provided by (used in) operating activities — continuing operations |
3,926 | 6,447 | 2,766 | |||||||||
| Cash provided by (used in) operating activities — discontinued operations |
— | (5 | ) | 134 | ||||||||
| Net cash provided by (used in) operating activities |
3,926 | 6,442 | 2,900 | |||||||||
| Cash Flow from Investing Activities |
||||||||||||
| Additions to properties and equipment and dry hole costs |
(4,352 | ) | (4,801 | ) | (4,246 | ) | ||||||
| Divestitures of properties and equipment and other assets |
176 | 2,455 | 8,260 | |||||||||
| Investment in Trinity Associates LLC |
— | — | (100 | ) | ||||||||
| Other-net |
(60 | ) | (182 | ) | (70 | ) | ||||||
| Cash provided by (used in) investing activities — continuing operations |
(4,236 | ) | (2,528 | ) | 3,844 | |||||||
| Cash provided by (used in) investing activities — discontinued operations |
— | — | (66 | ) | ||||||||
| Net cash provided by (used in) investing activities |
(4,236 | ) | (2,528 | ) | 3,778 | |||||||
| Cash Flow from Financing Activities |
||||||||||||
| Borrowings, net of issuance costs |
1,975 | — | (40 | ) | ||||||||
| Borrowings from affiliates, net of issuance costs |
— | 1 | 2,848 | |||||||||
| Issuance of midstream subsidiary note payable, net of issuance costs |
— | — | 2,176 | |||||||||
| Repayments of debt |
(1,470 | ) | (1,960 | ) | (10,475 | ) | ||||||
| Repayments on midstream subsidiary note payable |
(140 | ) | (461 | ) | — | |||||||
| Increase (decrease) in accounts payable, banks |
(139 | ) | 89 | (29 | ) | |||||||
| Dividends paid |
(176 | ) | (170 | ) | (170 | ) | ||||||
| Settlement of derivatives with a financing element |
— | 6 | (306 | ) | ||||||||
| Repurchase of common stock |
(35 | ) | (631 | ) | (35 | ) | ||||||
| Repurchase and retirement of preferred stock |
— | (45 | ) | (1 | ) | |||||||
| Issuance of common stock |
1,372 | 25 | 114 | |||||||||
| Sale of subsidiary units |
120 | 343 | — | |||||||||
| Distributions to noncontrolling interest owners |
(29 | ) | (16 | ) | — | |||||||
| Contributions from noncontrolling interest owners |
3 | 7 | — | |||||||||
| Other financing activities |
— | (10 | ) | (3 | ) | |||||||
| Net cash provided by (used in) financing activities |
1,481 | (2,822 | ) | (5,921 | ) | |||||||
| Net Increase (Decrease) in Cash and Cash Equivalents |
1,171 | 1,092 | 757 | |||||||||
| Cash and Cash Equivalents at Beginning of Period |
2,360 | 1,268 | 511 | |||||||||
| Cash and Cash Equivalents at End of Period |
$ | 3,531 | $ | 2,360 | $ | 1,268 | ||||||
See accompanying notes to consolidated financial statements.
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ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2009, 2008 and 2007
1. Summary of Significant Accounting Policies
General Anadarko Petroleum Corporation is engaged in the exploration, development, production, and marketing of natural gas, crude oil, condensate and natural gas liquids (NGLs). The Company also engages in the gathering, processing, treating and transporting of natural gas, as well as participates in the hard minerals business through its ownership in non-operated joint ventures and royalty arrangements. The terms “Anadarko” and “Company” refer to Anadarko Petroleum Corporation and its consolidated subsidiaries.
Basis of Presentation The consolidated financial statements have been prepared in conformity with accounting principles generally accepted in the United States. The consolidated financial statements include the accounts of Anadarko and entities in which it holds a controlling financial interest. Undivided interests in oil and gas joint ventures are consolidated on a proportionate basis. All intercompany transactions have been eliminated. Investments in non-controlled entities over which Anadarko exercises significant influence are accounted for under the equity method. Other investments are carried at cost. Certain amounts for prior periods have been reclassified to conform to the current presentation.
The Company changed the manner in which gains and losses on commodity derivatives, used to economically hedge production, are presented within the Consolidated Statements of Income to provide enhanced transparency into asset-operating performance. Previously, all realized and unrealized gains and losses on commodity derivatives were reported in gas sales, oil and condensate sales, or NGLs sales. (Gains) losses on commodity derivatives are now presented as a separate line item on the Consolidated Statements of Income. Prior periods have been reclassified to conform to this presentation. See Derivative Instruments below.
Use of Estimates In preparing financial statements in accordance with accounting principles generally accepted in the United States, management makes informed judgments and estimates that affect the reported amounts of assets and liabilities as of the date of the financial statements and the reported amounts of revenues and expenses during the periods reported. Management reviews its estimates periodically, including those related to the carrying value of properties and equipment, proved reserves, goodwill, intangible assets, asset retirement obligations, litigation reserves, environmental liabilities, pension assets and liabilities and costs, income taxes, and fair values. Changes in facts and circumstances or additional information may result in revised estimates and actual results may differ from these estimates.
Fair Value Fair value is defined as the price that would be received to sell an asset or price paid to transfer a liability in an orderly transaction between market participants at the measurement date. The standard characterizes inputs used in determining fair value according to a hierarchy that prioritizes those inputs based upon the degree to which they are observable. The three levels of the fair-value-measurement hierarchy are as follows:
| Level 1 - inputs represent quoted prices in active markets for identical assets or liabilities (for example, exchange-traded commodity derivatives).
Level 2 - inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly (for example, quoted market prices for similar assets or liabilities in active markets or quoted market prices for identical assets or liabilities in markets not considered to be active, inputs other than quoted prices that are observable for the asset or liability, or market-corroborated inputs).
Level 3 - inputs that are not observable from objective sources, such as the Company’s internally developed assumptions used in pricing an asset or liability (for example, an estimate of future cash flows used in the Company’s internally developed present value of future cash flows model that underlies the fair-value measurement). |
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ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2009, 2008 and 2007
1. Summary of Significant Accounting Policies (Continued)
In determining fair value, the Company utilizes observable market data when available, or models that incorporate observable market data. In addition to market information, the Company incorporates transaction-specific details that, in management’s judgment, market participants would take into account in measuring fair value.
In arriving at fair-value estimates, the Company utilizes the most observable inputs available for the valuation technique employed. If a fair-value measurement reflects inputs at multiple levels within the hierarchy, the fair-value measurement is characterized based upon the lowest level of input that is significant to the fair-value measurement. For Anadarko, recurring fair-value measurements are performed for interest-rate derivatives, commodity derivatives, investments in trading securities and pension assets.
The carrying amount of cash and cash equivalents, accounts receivable and accounts payable reported on the balance sheet approximates fair value.
Nonfinancial assets and liabilities initially measured at fair value include certain assets and liabilities acquired in a business combination, impaired long-lived assets (asset groups), intangible assets and goodwill, and asset retirement obligations and exit or disposal costs.
Revenues The Company recognizes sales revenues for gas, oil and condensate, and NGLs based on the amount of each product sold to purchasers when delivery to the purchaser has occurred and title has transferred. This occurs when product has been delivered to a pipeline or a tanker lifting has occurred. The Company follows the sales method of accounting for natural-gas production imbalances. If the Company’s sales volumes for a well exceed the estimated remaining recoverable reserves of the well, a liability is recognized. No receivables are recorded for those wells on which the Company has taken less than its proportionate share of production.
Realized gains and losses on derivative instruments that received cash flow hedge accounting treatment are included in gas sales, oil and condensate sales and NGLs sales. The Company discontinued hedge accounting effective January 1, 2007, as discussed in Derivative Instruments below.
The Company enters into buy/sell arrangements for a portion of its crude-oil production. Under these arrangements, barrels are sold at prevailing market prices at a location, and in an additional transaction entered into in contemplation of the sale transaction with the same third party, barrels are re-purchased at a different location at the market prices prevailing at that location. The barrels are then sold at prevailing market prices at the re-purchase location. These arrangements are often required by private transporters. In these transactions, the re-purchase price is more than the original sales price with the difference representing a transportation fee. Other buy/sell arrangements are entered in order to shift the ultimate sales point of the Company’s production to a more liquid location, thereby avoiding potential marketing fees and other market-price reductions. In these transactions, the sales price in the field and the re-purchase price are each at prevailing market prices at the respective locations. Anadarko uses these buy/sell arrangements in its marketing and trading activities and, as such, reports these transactions in the income statement on a net basis.
Anadarko provides gathering, processing, treating, and transportation services pursuant to a variety of contracts. Under these arrangements, the Company receives fees, or retains a percentage of products or a percentage of the proceeds from the sale of products and recognizes revenue at the time the services are performed or product is sold. These revenues are included in gathering, processing and marketing sales.
Marketing margins related to the Company’s production are included in gas sales, oil and condensate sales and NGLs sales. Marketing margins related to sales of commodities purchased from third parties, as well as realized and unrealized gains and losses on such marketing activities, are included in gathering, processing and marketing sales.
Cash Equivalents The Company considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents.
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ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2009, 2008 and 2007
1. Summary of Significant Accounting Policies (Continued)
Inventories Commodity inventories are stated at the lower of average cost or market.
Properties and Equipment Properties and equipment are stated at cost less accumulated depreciation, depletion and amortization (DD&A). Costs of improvements that appreciably improve the efficiency or productive capacity of existing properties or extend their lives are capitalized. Maintenance and repairs are expensed as incurred. Upon retirement or sale, the cost of properties and equipment, net of the related accumulated DD&A, is removed and, if appropriate, gain or loss is recognized in gains (losses) on divestitures and other, net.
Oil and Gas Properties The Company applies the successful efforts method of accounting for oil and gas properties. Under successful efforts, exploration costs such as exploratory geological and geophysical costs, delay rentals and exploration overhead are charged against earnings as incurred. Acquisition costs and costs of drilling exploratory wells are capitalized pending determination of whether proved reserves can be attributed to the area as a result of drilling the well. If management determines that commercial quantities of hydrocarbons have not been discovered, capitalized costs associated with exploratory wells are charged to exploration expense. Acquisition costs of unproved leaseholds are assessed for impairment during the holding period and transferred to proved oil and gas properties to the extent associated with successful exploration activities. Significant undeveloped leases are assessed individually for impairment, based on the Company’s current exploration plans, and a valuation allowance is provided if impairment is indicated. Unproved oil and gas properties with individually insignificant lease acquisition costs are amortized on a group basis (thereby establishing a valuation allowance) over the average terms of the leases, at rates that provide for full amortization of unsuccessful leases upon lease expiration or abandonment. Costs of expired or abandoned leases are charged against the valuation allowance, while costs of productive leases are transferred to proved oil and gas properties. Costs of maintaining and retaining undeveloped leaseholds, as well as amortization of individually insignificant leases and impairment of unsuccessful leases, are included in exploration expense.
Capitalized Interest Interest is capitalized as part of the historical cost of developing and constructing assets for significant projects. Significant oil and gas investments in unproved properties, significant exploration and development projects for which DD&A expense is not currently recognized, and exploration or development activities that are in progress qualify for interest capitalization. Interest is capitalized until the asset is ready for service. Capitalized interest is determined by multiplying the Company’s weighted-average borrowing cost on debt by the average amount of qualifying costs incurred. Once an asset subject to interest capitalization is completed and placed in service, the associated capitalized interest is expensed through depreciation or impairment, along with other capitalized costs related to that asset.
Asset Retirement Obligations An asset retirement obligation associated with the retirement of a tangible long-lived asset is recognized as a liability in the period incurred, with an associated increase in the carrying amount of the related long-lived asset. The cost of the tangible asset, including the asset retirement cost, is depreciated over the useful life of the asset. The asset retirement obligation is recorded at its estimated fair value, measured by reference to the expected future cash outflows required to satisfy the retirement obligation discounted at the Company’s credit-adjusted risk-free interest rate. Accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value. If the estimated future cost of the asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the long-lived asset. Revisions to estimated asset retirement obligations can result from changes in retirement cost estimates, revisions to estimated inflation rates and changes in the estimated timing of abandonment.
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ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2009, 2008 and 2007
1. Summary of Significant Accounting Policies (Continued)
Impairments Properties and equipment, net of salvage value, are reviewed for impairment at the lowest level for which identifiable cash flows are independent of cash flows from other assets when facts and circumstances indicate that their net book values may not be recoverable. In performing this review, an undiscounted cash flow test is performed on the impairment unit. If the sum of these undiscounted estimated future net cash flows is less than the net book value of the property, an impairment loss is recognized for the excess, if any, of the property’s net book value over its estimated fair value.
Depreciation, Depletion and Amortization Costs of drilling and equipping successful exploratory wells, development wells, costs to construct or acquire facilities other than offshore platforms and associated asset retirement costs are depreciated using the unit-of-production method based on total estimated proved developed oil and gas reserves. Costs of acquiring proved properties, including leasehold acquisition costs transferred from unproved leaseholds and costs to construct or acquire offshore platforms and associated asset retirement costs, are depleted using the unit-of-production method based on total estimated proved developed and undeveloped reserves. Mineral properties are depleted using the unit-of-production method. All other properties are stated at historical acquisition cost, net of allowance for impairment, and depreciated using the straight-line method over the useful lives of the assets, which range from 3 to 15 years for furniture and equipment, up to 40 years for buildings, and up to 47 years for gathering facilities.
Goodwill and Other Intangible Assets Goodwill represents the excess of the purchase price of a business over the estimated fair value of the assets acquired and liabilities assumed. The Company assesses the carrying amount of goodwill by testing the goodwill for impairment annually, unless facts and circumstances make it necessary to test more frequently. During 2009, the Company changed its annual goodwill impairment testing date from January 1 to October 1. As a result, goodwill was tested for impairment at both January 1 and October 1 in 2009. The impairment test requires an allocation of goodwill and all other assets and liabilities to business levels referred to as reporting units. A reporting unit is an operating segment or a component that is one level below an operating segment. Anadarko has allocated goodwill to three reporting units: oil and gas exploration and production, gathering and processing, and transportation. The fair value of each reporting unit is determined and compared to the carrying value of the reporting unit. If the fair value of the reporting unit is less than the carrying value, including goodwill, then the goodwill is written down to the implied fair value of the goodwill through a charge to expense.
Changes in goodwill may result from, among other things, impairments, future acquisitions or future divestitures.
Other intangible assets represent contractual rights obtained in connection with a business combination that had favorable contractual terms relative to market as of the acquisition date. Other intangible assets are amortized over their estimated useful lives and are reviewed for impairment whenever impairment indicators are present. See Note 7.
Derivative Instruments Anadarko utilizes derivative instruments in its marketing and trading activities and to manage price risk attributable to the Company’s forecasted sales of oil, natural-gas and NGLs production. Anadarko also periodically utilizes derivatives to manage its exposure associated with natural-gas processing, interest rates and foreign currency exchange rates. All derivatives that do not satisfy the normal purchases and sales exception criteria are carried on the balance sheet at fair value and are included in other current assets, other assets, accrued expenses or other long-term liabilities, depending on the derivative position and the expected timing of settlement. To the extent a legal right of offset with a counterparty exists, the Company reports derivative assets and liabilities on a net basis. Anadarko has exposure to credit risk to the extent the derivative-instrument counterparty is unable to satisfy its settlement commitment. The Company actively monitors the creditworthiness of each counterparty and assesses the impact, if any, on its derivative positions.
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ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2009, 2008 and 2007
1. Summary of Significant Accounting Policies (Continued)
Through the end of 2006, Anadarko applied hedge accounting to certain commodity and interest-rate derivatives whereby gains and losses on these instruments were recognized in earnings in the same period in which the specifically identified hedged transactions affected earnings. Effective January 1, 2007, Anadarko discontinued its application of hedge accounting to all derivatives. As a result of this change, both realized and unrealized gains and losses on derivative instruments are recognized on a current basis. Net derivative losses attributable to derivatives previously subject to hedge accounting reside in accumulated other comprehensive income as of December 31, 2009 and will be reclassified to earnings in future periods as the economic transactions to which the derivatives relate affect earnings. See Note 8.
Accounts Payable Accounts payable includes property expenditure accruals of $741 million and $579 million at December 31, 2009 and 2008, respectively. Also included in accounts payable at December 31, 2009 and 2008 are liabilities of $252 million and $391 million, respectively, representing the amount by which checks issued, but not presented to the Company’s banks for collection, exceed balances in applicable bank accounts, and changes in these liabilities are reflected in cash flows from financing activities.
Legal Contingencies The Company is subject to legal proceedings, claims and liabilities which arise in the ordinary course of its business. Except for legal contingencies acquired in a business combination, which are recorded at fair value, the Company accrues for losses associated with legal claims when such losses are probable and can be reasonably estimated. These estimates are adjusted as additional information becomes available or circumstances change. See Note 14.
Environmental Contingencies Except for environmental contingencies acquired in a business combination, which are recorded at fair value, the Company accrues for losses associated with environmental-remediation obligations when such losses are probable and can be reasonably estimated. Accruals for estimated losses from environmental-remediation obligations are recognized no later than the time of the completion of the remediation feasibility study. These accruals are adjusted as additional information becomes available or as circumstances change. Costs of future expenditures for environmental-remediation obligations are not discounted to their present value. Recoveries of environmental-remediation costs from other parties are recorded at undiscounted value as assets when receipt is deemed probable. See Note 14.
Pension Plans, Other Postretirement Benefits and Employee Savings Plans The Company measures pension plan assets at fair value. Pension plans are actuarially evaluated, incorporating the use of various assumptions. Critical assumptions for pension and other postretirement plans include the discount rate and the expected rate of return on plan assets (for funded pension plans). Other assumptions involve demographic factors such as retirement, mortality, turnover and the rate of compensation increases. The Company evaluates assumptions annually and modifies the assumptions as necessary. See Note 20.
Noncontrolling Interests Noncontrolling interests represent third-party ownership in the net assets of the Company’s consolidated subsidiaries and are presented as a component of equity. Changes in Anadarko’s ownership interests in subsidiaries that do not result in deconsolidation are recognized in equity. See Note 3.
Income Taxes The Company files various United States federal, state and foreign income tax returns. Deferred federal, state and foreign income taxes are provided on temporary differences between the financial statement carrying amounts of assets and liabilities and their respective tax bases. The Company recognizes a tax benefit from an uncertain position when it is more likely than not that the position will be sustained upon examination, based on the technical merits of the position and will record the largest amount of tax benefit that is greater than 50% likely of being realized upon settlement with a taxing authority. See Note 16.
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YEARS ENDED DECEMBER 31, 2009, 2008 and 2007
1. Summary of Significant Accounting Policies (Continued)
Stock-Based Compensation The Company accounts for stock-based compensation at fair value. The Company grants various types of stock-based awards including stock options, non-vested equity shares (restricted stock awards and units) and performance-based awards. The fair value of stock option awards is determined using the Black-Scholes option-pricing model. Restricted stock awards and units are valued using the market price of Anadarko common stock on the grant date. For performance-based awards, the fair value of the market-condition portion of the award is measured using a Monte Carlo simulation, and the performance-condition portion is measured at the market price of Anadarko common stock on the grant date. Liability-classified awards are remeasured at estimated fair value at the end of each period based on the specifications of each plan. The Company records compensation cost, net of estimated forfeitures, for stock-based compensation awards over the requisite service period. As each award vests, an adjustment is made to compensation cost for any difference between the estimated forfeitures and the actual forfeitures related to the vested awards. For equity awards that contain service and market conditions, compensation cost is recorded using the straight-line method. If the requisite service period is satisfied, compensation cost is not adjusted unless the award contains a performance condition. If an award contains a performance condition, expense is recognized only for those shares that ultimately vest using the per-share fair value measured at the grant date. See Note 12.
Discontinued Operations The Company’s Canadian operations have been classified as discontinued operations for 2007 and 2008. Unless otherwise indicated, information presented in the notes to the financial statements relates only to Anadarko’s continuing operations. See Note 2.
Earnings Per Share The Company’s basic earnings per share (EPS) amounts have been computed based on the average number of shares of common stock outstanding for the period and include the effect of any participating securities as appropriate. Diluted EPS includes the effect of the Company’s outstanding stock options, restricted stock awards, restricted stock units and performance-based stock awards if the inclusion of these items is dilutive. Diluted net loss per share for the year ended December 31, 2009, does not assume an increase in the average number of shares outstanding from future stock option exercises, unvested restricted stock or performance-based stock awards because the inclusion of shares attributable to these sources would have an anti-dilutive effect. See Note 11.
Changes in Accounting Principles The Company adopted a new fair-value-measurement standard as of January 1, 2008. The standard defines fair value, establishes a framework for measuring fair value under existing accounting pronouncements that require fair-value measurements and expands fair-value-measurement disclosures. The Company elected to implement the standard with the one-year deferral permitted for nonfinancial assets and nonfinancial liabilities, except those nonfinancial items recognized or disclosed at fair value on a recurring basis (at least annually). The deferral period ended on January 1, 2009. Accordingly, the Company now applies the fair-value framework to nonfinancial assets and nonfinancial liabilities initially measured at fair value, such as assets and liabilities acquired in a business combination, impaired long-lived assets (asset groups), intangible assets and goodwill, and initial recognition of asset retirement obligations and exit or disposal costs. Also, during the fourth quarter of 2009, Anadarko adopted a standard that requires expanded fair-value-measurement disclosures related to pensions.
The Company adopted a new standard for its derivative instruments and hedging activities, effective January 1, 2009. The standard does not change the Company’s accounting for derivatives, but requires enhanced disclosures regarding the Company’s methodology and purpose for entering into derivative instruments, accounting for derivative instruments and related hedged items (if any), and the impact of derivative instruments on the Company’s consolidated financial position, results of operations and cash flows. See Note 8.
The Company adopted new accounting and reporting standards for noncontrolling interests in a subsidiary and for the deconsolidation of subsidiaries, effective January 1, 2009. Specifically, these standards require the
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YEARS ENDED DECEMBER 31, 2009, 2008 and 2007
1. Summary of Significant Accounting Policies (Continued)
recognition of noncontrolling interests (formerly referred to as minority interests) as a component of total equity. Prior to January 1, 2009, the share of a subsidiary’s net assets allocable to minority interest investors was reported outside of equity. These standards also establish a single method of accounting for changes in a parent’s ownership interest in a subsidiary that do not result in deconsolidation and specifically provide that dispositions of subsidiary stock are required to be accounted for as equity transactions with no gain or loss recognized upon disposal. Finally, consolidated net income and comprehensive income are presented to include amounts attributable to both the parent and noncontrolling interests. All prior periods have been conformed to the current-year presentation.
The Company adopted a new accounting standard for business combinations, effective January 1, 2009. The standard applies prospectively to the Company for future business combinations. The standard expands the definition of what qualifies as a business, thereby increasing the scope of transactions that qualify as business combinations. Furthermore, under the standard, changes in estimates of income tax liabilities existing at the date of, or arising in connection with, past business combinations are accounted for as adjustments to current-period income as opposed to adjustments to goodwill. The adoption of the standard had no impact on the Company’s consolidated financial position, results of operations or cash flows.
The Company adopted a new standard on determining whether instruments granted in share-based payment transactions constitute participating securities, effective January 1, 2009. This standard addresses whether instruments granted in share-based payment transactions are participating securities prior to vesting, and therefore included in the allocation of earnings for purposes of computing EPS. Unvested share-based payment awards, whether paid or unpaid, that contain nonforfeitable rights to dividends or dividend equivalents constitute participating securities and are included in the computation of EPS. The Company’s restricted stock awards and restricted stock units contain nonforfeitable rights to dividends, thereby qualifying these instruments as participating securities and requiring the underlying securities to be taken into account for purposes of computing EPS. However, because the Company’s restricted stock awards and restricted stock units do not participate in losses, these instruments were not taken into account for purposes of calculating EPS for the year ended December 31, 2009. All prior periods have been conformed to the current-year presentation. See Note 11.
The Company adopted a new standard on subsequent events, effective April 1, 2009. The standard defines subsequent events as either recognized subsequent events (events that provide additional evidence about conditions at the balance sheet date) or nonrecognized subsequent events (events that provide evidence about conditions that arose after the balance sheet date). Recognized subsequent events are recorded in the financial statements for the current period presented, while nonrecognized subsequent events are not. Both types of subsequent events require disclosure in the consolidated financial statements if nondisclosure of such events causes the financial statements to be misleading. The adoption of this standard had no impact on the financial statements of the Company. The Company has evaluated subsequent events through February 23, 2010.
During the third quarter of 2009, the Company changed its annual goodwill impairment testing date from January 1 to October 1 of each year. This change ensures the completion of the annual goodwill impairment test prior to the end of the annual reporting period, thereby aligning impairment testing procedures with year-end financial reporting. Accordingly, management considers this accounting change preferable. This change did not accelerate, delay, avoid, or cause an impairment charge, nor did this change result in adjustments to previously issued financial statements. The Company completed its annual goodwill impairment test during the fourth quarter of 2009, with no impairment indicated.
In December 2009, Anadarko adopted revised oil and gas reserve estimation and disclosure requirements. The primary impact of the new disclosures for Anadarko is to align the definition of proved reserves with the Securities and Exchange Commission (SEC) Modernization of Oil and Gas Reporting rules, which were issued by the SEC at the end of 2008. The accounting standards update revised the definition of proved oil and gas reserves to require that the average, first-day-of-the-month price during the 12-month period preceding the end of
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YEARS ENDED DECEMBER 31, 2009, 2008 and 2007
1. Summary of Significant Accounting Policies (Continued)
the year rather than the year-end price, must be used when estimating whether reserve quantities are economical to produce. This same 12-month average price is also used in calculating the aggregate amount of (and changes in) future cash inflows related to the standardized measure of discounted future net cash flows. The rules also allow for the use of reliable technology to estimate proved oil and gas reserves, if those technologies have been demonstrated to result in reliable conclusions about reserve volumes. The unaudited supplemental information on oil and gas exploration and production activities for 2009 has been presented following these new reserve estimation and disclosure rules, which may not be applied retrospectively. The 2006, 2007, and 2008 data are presented in accordance with the Financial Accounting Standards Board (FASB) oil and gas disclosure requirements effective during those respective periods. However, historical information has been reclassified to conform to the geographic areas required to be disclosed in 2009 under the revised accounting standard. Adoption of the new rules had no effect on the 2009 consolidated financial statements. The effect of applying the new reserve estimation requirements did not significantly impact 2009 net proved reserve volumes, nor will the requirements have a material impact on depletion expense in future periods.
Recently Issued Accounting Standards Not Yet Adopted In June 2009, the FASB issued amendments to the consolidation standard applicable to variable interest entities. The amendments reduce the previously required quantitative consolidation analysis, and require ongoing reassessments of whether the Company is the primary beneficiary of a variable interest entity. This standard requires enhanced disclosures about an enterprise’s involvement with a variable interest entity. This standard is effective for the first annual reporting period beginning after November 15, 2009. The adoption of this standard will not have an impact on the Company’s consolidated financial position, results of operations or cash flows, other than the expanded disclosures.
2. Divestitures and Other
Gains (Losses) on Divestitures and Other During 2009, 2008 and 2007, the Company closed several unrelated property divestiture transactions, realizing proceeds of approximately $176 million, $2.5 billion, and $11.1 billion before income taxes, respectively. During 2009, 2008 and 2007, net gains on divestitures were $44 million, $1.2 billion, and $4.7 billion, respectively. The 2009 gains included $29 million primarily related to divestitures of certain oil and gas properties in Qatar.
In December 2009, Anadarko entered into a non-monetary exchange for certain oil and gas properties in the Rockies area. The properties received were recorded at fair value of approximately $230 million and the properties conveyed were accounted for as a retirement as the conveyance did not significantly affect the depletion rate of the properties.
During 2008, the Company entered into an agreement to divest its 50% interest in the Peregrino field, offshore Brazil, and certain related assets. The Peregrino divestiture closed in December 2008. Anadarko received approximately $1.4 billion in net after-tax cash proceeds from the sale, recognizing a gain of approximately $800 million. In connection with the sale of its interest in the Peregrino field, Anadarko may receive contingent consideration in future periods. Contingent consideration is based on the value of oil produced from properties subject to the sale transaction. The Company has not recorded any amounts for this contingent consideration. Additionally, the Company has cash on deposit with the Brazilian federal court pending a decision regarding the appropriate rate of tax on the sale of the Peregrino field.
The 2007 gains included $4.1 billion related to the divestiture of certain oil and gas properties and $0.6 billion related to the divestiture of certain gathering and processing facilities.
In 2008, gains (losses) on divestitures and other, net included a net $82 million ($52 million after tax) reduction related to corrections resulting from analysis of property records after the adoption of the successful efforts method of accounting. This net amount included a reduction of $163 million related to 2007. Management
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2009, 2008 and 2007
2. Divestitures and Other (Continued)
concluded that this misstatement was not material relative to 2007 interim and annual results, or to the 2008 periods, and corrected the error in the first quarter of 2008.
Discontinued Operations In November 2006, Anadarko sold its wholly owned subsidiary, Anadarko Canada Corporation. The results of Anadarko’s Canadian operations have been classified as discontinued operations in the consolidated statements of income and cash flows for 2008 and 2007 primarily related to adjustments to an indemnity obligation provided by the Company to the purchaser, as well as expenses associated with finalizing exit activities. See Note 14.
Severance and Asset-Realignment Expenses During 2007, general and administrative expense included charges of $85 million associated with employee severance and benefits arising from the Company’s post-acquisition asset-realignment and restructuring efforts initiated in the fourth quarter of 2006. These expenses were not material in 2008 or 2009.
During 2007, oil and gas operating expense included charges of $20 million for employee-related severance costs associated with field operations. At December 31, 2008, there was no remaining liability.
3. Noncontrolling Interest
During the second quarter of 2008, Western Gas Partners, LP (WES) completed its initial public offering of 20.8 million common units (representing a 38.4% limited partner interest) for net proceeds of $321 million ($343 million less $22 million for underwriting discounts and structuring fees). WES is a limited partnership formed by Anadarko to own, operate, acquire and develop midstream assets. Anadarko contributed assets to WES in exchange for an aggregate 59.6% initial limited partner interest (consisting of common and subordinated limited partner units) in WES, a 2% general partner interest and incentive distribution rights (IDRs). IDRs entitle the holder to specified increasing percentages of cash distributions as WES’s per-unit cash distributions increase. In addition, Anadarko maintains control over the assets owned by WES through ownership of the general partner. Proceeds from the offering were used to reduce debt.
All proceeds from the sale of the common units to the public is reported as noncontrolling interests in the consolidated balance sheet, including $29 million that will be transferred to paid-in capital if and when the WES subordinated units convert to common units. The results of operations and financial position of WES are included in the consolidated financial statements of Anadarko. The portion of WES’ results of operations that is attributable to common units held by the public (units not held by Anadarko) is recorded as noncontrolling interests.
In December 2009, WES issued 6.9 million common units representing limited partner interests to the public. This offering raised proceeds of approximately $120 million and was recorded as noncontrolling interests. Anadarko holds an aggregate 54.8% limited partner interest in WES as of December 31, 2009.
4. Inventories
The major classes of inventories, which are included in other current assets, are as follows:
| millions | 2009 | 2008 | ||||
| Crude oil and NGLs |
$ | 142 | $ | 89 | ||
| Natural gas |
94 | 51 | ||||
| Total |
$ | 236 | $ | 140 | ||
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2009, 2008 and 2007
5. Properties and Equipment
A summary of the cost of properties and equipment by function follows:
| millions | 2009 | 2008 | ||||
| Oil and gas (includes unproved properties of $9,505 and $10,428 |
$ | 44,328 | $ | 41,496 | ||
| Gathering, processing and marketing |
3,705 | 3,510 | ||||
| Minerals |
1,188 | 1,196 | ||||
| Other |
1,123 | 871 | ||||
| Total |
$ | 50,344 | $ | 47,073 | ||
During 2009, the Company recognized total impairments of $41 million related to long-lived assets. This includes $22 million related to the oil and gas exploration and production operating segment, which was triggered by the current economic and commodity price environment. In addition, certain midstream operating segment assets were impaired by $7 million due to reduced operating activity, and an LNG facility site, included in the marketing operating segment, was impaired by $12 million. All assets were impaired to fair value resulting in Level 3 measurements, and, along with current-year depreciation, reduced the net book value to $26 million.
During 2008 and 2007, the Company recognized impairments of $211 million and $51 million, respectively. Impairments in 2008 included $113 million associated with United States properties included in the oil and gas exploration and production operating segment, and $98 million associated with certain gathering and processing facilities in the United States included in the midstream operating segment. These impairments resulted primarily from lower commodity prices at year-end 2008.
Suspended Exploratory Drilling Costs If an exploratory well provides evidence as to the existence of sufficient quantities of hydrocarbons to justify potential completion as a producing well, drilling costs associated with the well are initially capitalized, or suspended, pending a determination as to whether a commercially sufficient quantity of proved reserves can be attributed to the area as a result of drilling. This determination may take longer than one year in certain areas (generally, deepwater and international locations) depending upon, among other things, the amount of hydrocarbons discovered, the outcome of planned geological and engineering studies, the need for additional appraisal drilling activities to determine whether the discovery is sufficient to support an economic development plan and, the requirement for government sanctioning in certain international locations before proceeding with development activities.
At the end of each quarter, management reviews the status of all suspended exploratory drilling costs in light of ongoing exploration activities — in particular, whether the Company is making sufficient progress in its ongoing exploration and appraisal efforts or, in the case of discoveries requiring government sanctioning, whether development negotiations are underway and proceeding as planned. If management determines that future appraisal drilling or development activities are unlikely to occur, any associated suspended exploratory drilling costs are expensed in that period.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2009, 2008 and 2007
5. Properties and Equipment (Continued)
The following table presents the amount of suspended exploratory drilling costs relating to continuing operations at December 31 for each of the last three years, and changes in those amounts during the years then ended. The table excludes amounts capitalized and subsequently reclassified to proved oil and gas properties or charged to expense in the same year.
| millions | 2009 | 2008 | 2007 | |||||||||
| Balance at January 1 |
$ | 279 | $ | 308 | $ | 312 | ||||||
| Additions pending the determination of proved reserves |
483 | 211 | 252 | |||||||||
| Reclassifications to proved properties |
(120 | ) | (175 | ) | (87 | ) | ||||||
| Charges to exploration expense |
(63 | ) | (65 | ) | (169 | ) | ||||||
| Balance at December 31 |
$ | 579 | $ | 279 | $ | 308 | ||||||
The following table presents the total amount of suspended exploratory drilling costs as of December 31, 2009 by geographic area, including the year the costs were originally incurred.
| Year Costs Incurred | ||||||||||||
| millions | Total | 2009 | 2008 | 2007 and prior | ||||||||
| United States — Onshore |
$ | 147 | $ | 115 | $ | 32 | $ | — | ||||
| United States — Offshore |
174 | 100 | 74 | — | ||||||||
| International |
258 | 186 | 69 | 3 | ||||||||
| $ | 579 | $ | 401 | $ | 175 | $ | 3 | |||||
| Suspended exploratory drilling costs capitalized for a period greater than one year after completion of drilling at December 31, 2009 (included in the table above) |
$ | 146 | ||||||||||
Well costs that have been suspended for longer than one year are associated with eight projects. The majority of these costs is associated with deepwater Gulf of Mexico projects and is suspended pending the completion of an economic evaluation including, but not limited to, results of additional appraisal drilling, facilities, infrastructure, well-test analysis, additional geological and geophysical data and approval of a development plan. The international projects with costs suspended for longer than one year are primarily suspended pending the results of additional appraisal drilling, which is currently ongoing. Management believes these projects with suspended exploratory drilling costs exhibit sufficient quantities of hydrocarbons to justify potential development and is actively pursuing efforts to assess whether reserves can be attributed to their respective areas. If additional information becomes available that raises substantial doubt as to the economic or operational viability of any of these projects, the associated costs will be expensed at that time.
6. Investments
Noncontrolling Mandatorily Redeemable Interests In 2007, Anadarko contributed certain of its oil and gas properties ($1.0 billion fair value at date of contribution) and gathering and processing assets ($1.9 billion fair value at date of contribution), to newly formed unconsolidated entities in exchange for noncontrolling mandatorily redeemable interests. The common equity of the investee entities is 95% owned by third parties that
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YEARS ENDED DECEMBER 31, 2009, 2008 and 2007
6. Investments (Continued)
also maintain operational control over the assets. Distributions to the interest holders, including Anadarko, are payable quarterly. Subsequent to their formation, the investee entities loaned Anadarko an aggregate of $2.9 billion. These loans were funded through third-party equity contributions to the investee entities. The Company accounts for its investment in these entities under the equity method of accounting. Anadarko has legal right of setoff and intends to net-settle its obligations under each of the notes payable to the investees and the distributable fair value of its interest in the corresponding investee entity. Accordingly, the investments and the obligations are presented net on the consolidated balance sheet with the excess of the notes payable to investee entities over the aggregate investment carrying amounts included in other long-term liabilities—other for all periods presented.
The noncontrolling mandatorily redeemable interests entitle Anadarko to a LIBOR-based preferred return on the value of the contributed assets plus a common return consisting of a 5% participation in profits, losses and any residual value of the investee entities. At December 31, 2009, the priority return rates applicable to Anadarko’s interests were 0.78% for Anadarko’s interest in the oil and gas investee entity and 0.70% for Anadarko’s interests in gathering and processing investee entities. Anadarko’s interest in these entities also provides the Company with limited consent rights with respect to certain matters, such as acquisition and disposition of assets and incurrence of debt. Anadarko may redeem its noncontrolling interests, and the owners of the controlling interests may cause a redemption of Anadarko’s interests, in 2022 and thereafter. Anadarko’s interests are mandatorily redeemable in 2037.
The notes issued by Anadarko have 35-year terms and variable LIBOR-based interest rates that fluctuate with Anadarko’s credit rating. At December 31, 2009, the applicable interest rate for all above-described notes was 1.25%. Interest on the notes is due quarterly, while principal is due at maturity, subject to the net-settlement provisions. The notes are equal in seniority to Anadarko’s other unsecured unsubordinated indebtedness. The note with the oil and gas entity contains a maximum 67% debt-to-capitalization covenant. Proceeds from the notes were used to repay a portion of Anadarko’s indebtedness related to its 2006 acquisitions. Anadarko recognized gains of approximately $443 million and $300 million on the exchange with the oil and gas investee entity and the gathering and processing investee entities, respectively, in 2007.
At December 31, 2009, the carrying amount of these investments was $2.8 billion, while the carrying amount of notes payable to the investee entities was $2.9 billion. Other (income) expense for 2009, 2008 and 2007 included interest expense on the notes payable to the investee entities of $57 million, $123 million and $102 million, respectively, and equity in earnings from Anadarko’s investments in the investee entities of $(42) million, $(89) million and $(98) million, respectively.
Midstream Financing Arrangement As further discussed in Note 10, in December 2007, Anadarko and an entity formed by a group of unrelated third-party investors (the Investor) formed Trinity Associates LLC (Trinity). Trinity was initially capitalized with a $100 million cash contribution from Anadarko in exchange for Class A member and managing member interests in Trinity and a $2.2 billion cash contribution from the Investor in exchange for a Class B member cumulative preferred interest. Trinity invested $100 million in a U.S. Government securities money market fund and loaned $2.2 billion to a wholly owned subsidiary of Anadarko, Midstream Holding. The Company used all of the loan proceeds received by Midstream Holding to repay a portion of the Company’s indebtedness related to the 2006 acquisitions. See Note 10 for additional information about the Midstream Subsidiary Note Payable to a Related Party.
Through its Class A member and managing member interests, Anadarko has significant influence over Trinity and accounts for its investment in Trinity under the equity method of accounting. Trinity’s earnings, which consist primarily of interest income from the Midstream Holding note and the government money market fund investment, are to be allocated first to the Investor’s Class B member interest until its cumulative preferred return is satisfied, with the remaining earnings allocated to Anadarko’s Class A member interest. Anadarko
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YEARS ENDED DECEMBER 31, 2009, 2008 and 2007
6. Investments (Continued)
absorbs first-dollar losses of Trinity, if any, until its Class A member capital account in Trinity is reduced to zero. As of December 31, 2009, the carrying amount of Anadarko’s investment in Trinity was $100 million and is included in other assets. Investment earnings are included in other (income) expense and were not material.
Other During the fourth quarter of 2008, Anadarko changed the method of accounting for its investment in Petroritupano, S.A. (Petroritupano), a Venezuelan mixed company, to the cost method. The Company determined that it was no longer appropriate to account for the investment under the equity method. At December 31, 2009 and 2008, the Company’s investment in Petroritupano is included in other assets.
7. Goodwill and Other Intangible Assets
Changes in the carrying amount of goodwill by segment for 2009 and 2008 are as follows:
| 2009 | 2008 | |||||||||||||||||||
| millions | Oil and Gas Exploration & Production |
Midstream | Total | Oil and Gas Exploration & Production |
Midstream | Total | ||||||||||||||
| Balance at beginning of year |
$ | 5,143 | $ | 139 | $ | 5,282 | $ | 4,847 | $ | 108 | $ | 4,955 | ||||||||
| Goodwill associated with 2006 acquisitions |
— | — | — | 298 | 31 | 329 | ||||||||||||||
| Other changes, net |
— | — | — | (2 | ) | — | (2 | ) | ||||||||||||
| Balance at end of year |
$ | 5,143 | $ | 139 | $ | 5,282 | $ | 5,143 | $ | 139 | $ | 5,282 | ||||||||
During 2008, the carrying amount of goodwill increased $327 million largely attributable to revisions in estimates of deferred tax liabilities recorded upon the acquisitions of Kerr-McGee Corporation (Kerr-McGee) and Western Gas Resources, Inc. (Western). None of Anadarko’s goodwill is deductible for tax purposes.
Intangible assets subject to amortization at December 31, 2009 and 2008 are as follows:
| millions | Gross Carrying Amount |
Accumulated Amortization |
Net Carrying Amount | |||||||
| Balance at December 31, 2009 |
||||||||||
| Drilling contracts |
$ | 155 | $ | (155 | ) | $ | — | |||
| Transportation contracts |
171 | (163 | ) | 8 | ||||||
| Offshore platform leases |
60 | (28 | ) | 32 | ||||||
| $ | 386 | $ | (346 | ) | $ | 40 | ||||
| Balance at December 31, 2008 |
||||||||||
| Drilling contracts |
$ | 155 | $ | (153 | ) | $ | 2 | |||
| Transportation contracts |
171 | (76 | ) | 95 | ||||||
| Offshore platform leases |
60 | (26 | ) | 34 | ||||||
| $ | 386 | $ | (255 | ) | $ | 131 | ||||
Costs associated with acquired drilling contract intangibles were initially capitalized as intangible assets. Amortization of these costs is recorded to oil and gas properties as exploratory and development drilling costs and ultimately expensed through depletion. In 2009, 2008 and 2007, $2 million, $35 million and $81 million,
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YEARS ENDED DECEMBER 31, 2009, 2008 and 2007
7. Goodwill and Other Intangible Assets (Continued)
respectively, of drilling contract intangible value was amortized and recorded to oil and gas properties. Drilling contract intangibles relate to the Company’s oil and gas exploration and production operating segment.
The Company recognized impairments of $74 million, $12 million and zero for 2009, 2008 and 2007, respectively, related to certain transportation contracts included in intangible assets due to changes in price differentials at specific locations. These assets were impaired to fair value, determined using a discounted cash flow approach, which incorporates market-based inputs that represent a Level 2 fair-value measurement. Amortization expense for the transportation contracts was $13 million, $26 million and $28 million for 2009, 2008 and 2007, respectively. The transportation contract impairments and amortization relate to the marketing operating segment.
Costs associated with offshore platform leases were capitalized as intangible assets. Amortization expense for the offshore platform lease intangibles was $2 million, $7 million and $19 million for 2009, 2008 and 2007, respectively. Offshore platform lease intangibles relate to the Company’s oil and gas exploration and production operating segment.
The estimated aggregate amortization expense for all intangible assets for the next five years is $3 million, $5 million, $6 million, $1 million, and $1 million, respectively.
8. Derivative Instruments
Objective and Strategy The Company is exposed to commodity price and interest-rate risk, and management considers it prudent to periodically reduce the Company’s exposure to cash flow variability resulting from commodity price changes and interest-rate fluctuations. Accordingly, the Company enters into certain derivative instruments in order to manage its exposure to these risks.
Futures, swaps and options are used to manage the Company’s cash flow exposure to commodity price risk inherent in the Company’s oil and gas production and gas-processing operations (Oil and Gas Production/Processing Derivative Activities). Futures contracts and commodity swap agreements are used to fix the price of expected future oil and gas sales at major industry trading locations, such as Henry Hub, Louisiana for gas and Cushing, Oklahoma for oil. Basis swaps are used to fix or float the price differential between the product price at one market location versus another. Options are used to establish a floor and a ceiling price (collar) for expected future oil and gas sales. Derivative instruments are also used to manage commodity price risk inherent in customer pricing requirements and to fix margins on the future sale of natural gas and NGLs from the Company’s leased storage facilities (Marketing and Trading Derivative Activities).
The Company may also enter into physical-delivery sales contracts to manage cash flow variability. These contracts call for the receipt or delivery of physical product at a specified location and price, which may be fixed or market-based.
Interest-rate swaps are used to fix or float interest rates on existing or anticipated indebtedness. The purpose of these instruments is to mitigate the Company’s existing or anticipated exposure to unfavorable interest-rate changes.
The Company does not apply hedge accounting to any of its derivative instruments. The application of hedge accounting was discontinued by the Company for periods beginning on or after January 1, 2007. As a result, both realized and unrealized gains and losses associated with derivative instruments are recognized in earnings. Net derivative losses attributable to derivatives previously subject to hedge accounting reside in accumulated other comprehensive income (loss) and are reclassified to earnings in future periods as the economic transactions to which the derivatives relate are recorded in earnings.
The accumulated other comprehensive loss balances related to commodity derivatives at December 31, 2009 and December 31, 2008, were $10 million ($7 million after tax) and $22 million ($14 million after tax), respectively. The accumulated other comprehensive loss balances related to interest-rate derivatives at
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YEARS ENDED DECEMBER 31, 2009, 2008 and 2007
8. Derivative Instruments (Continued)
December 31, 2009 and December 31, 2008, were $141 million ($89 million after tax) and $163 million ($104 million after tax), respectively.
Oil and Gas Production/Processing Derivative Activities Below is a summary of the Company’s derivative instruments related to its oil and gas production as of December 31, 2009. The natural-gas prices listed below are New York Mercantile Exchange (NYMEX) Henry Hub prices. The crude-oil prices listed below reflect a combination of NYMEX Cushing and London Brent Dated prices.
| 2010 | 2011 | 2012 | |||||||||
| Natural Gas |
|||||||||||
| Three-Way Collars (thousand MMBtu/d) |
1,630 | 480 | 500 | ||||||||
| Average price per MMBtu |
|||||||||||
| Ceiling sold price (call) |
$ | 8.23 | $ | 8.29 | $ | 9.03 | |||||
| Floor purchased price (put) |
$ | 5.59 | $ | 6.50 | $ | 6.50 | |||||
| Floor sold price (put) |
$ | 4.22 | $ | 5.00 | $ | 5.00 | |||||
| Fixed-Price Contracts (thousand MMBtu/d) |
90 | 90 | — | ||||||||
| Average price per MMBtu |
$ | 6.10 | $ | 6.17 | $ | — | |||||
| Basis Swaps (thousand MMBtu/d) |
620 | 45 | — | ||||||||
| Price per MMBtu |
$ | (0.98 | ) | $ | (1.74 | ) | $ | — | |||
MMBtu—million British thermal units
MMBtu/d—million British thermal units per day
| 2010 | 2011 | 2012 | |||||||
| Crude Oil |
|||||||||
| Three-Way Collars (MBbls/d) |
129 | 3 | 2 | ||||||
| Average price per barrel |
|||||||||
| Ceiling sold price (call) |
$ | 90.73 | $ | 86.00 | $ | 92.50 | |||
| Floor purchased price (put) |
$ | 64.34 | $ | 50.00 | $ | 50.00 | |||
| Floor sold price (put) |
$ | 49.34 | $ | 35.00 | $ | 35.00 | |||
MBbls/d—thousand barrels per day
A three-way collar is a combination of three options: a sold call, a purchased put and a sold put. The sold call establishes the maximum price that the Company will receive for the contracted commodity volumes. The purchased put establishes the minimum price that the Company will receive for the contracted volumes unless the market price for the commodity falls below the sold put strike price, at which point the minimum price equals the reference price (i.e., NYMEX) plus the excess of the purchased put strike price over the sold put strike price.
Marketing and Trading Derivative Activities In addition to the positions in the above tables, the Company also engages in marketing and trading activities, which include physical product sales and derivative transactions entered into to reduce commodity price risk associated with certain physical product sales. At December 31, 2009 and December 31, 2008, the Company had outstanding physical transactions for 46 billion cubic feet (Bcf) and 51 Bcf, respectively, offset by derivative transactions for 17 Bcf and 34 Bcf, respectively, for net positions of 29 Bcf and 17 Bcf, respectively.
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ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2009, 2008 and 2007
8. Derivative Instruments (Continued)
Interest-Rate Derivatives As discussed in Note 10, during 2009, Anadarko issued fixed-rate senior notes in the aggregate principal amount of $2.0 billion. In advance of certain of these debt issuances, Anadarko entered into derivative financial instruments, effectively hedging the U.S. Treasury portion of the coupon rate on a portion of this debt. These derivative instruments were settled concurrently with the associated debt issuances, resulting in a realized loss of $16 million for the year ended December 31, 2009, reflected in (gains) losses on other derivatives, net.
As of December 31, 2009, the Company had scheduled debt maturities of approximately $3.5 billion in 2011 and 2012. In anticipation of refinancing a portion of these maturing debt obligations, in December 2008 and January 2009 Anadarko entered into interest-rate swap agreements to hedge a portion of the fixed interest rate it would pay on an aggregate notional principal amount of $3.0 billion, over a reference term of either 10 years or 30 years, beginning in 2011 and 2012. The swap instruments include a provision that requires both the termination of the swaps and cash settlement in full at the start of the reference period. A summary of the swaps detailing the outstanding notional principal amounts and the associated reference periods is shown in the table below.
Increases in the reference U.S. Treasury rates since contract inception have increased the value of this swap portfolio to Anadarko, the fixed-rate payor. During the second quarter of 2009, the Company revised the contractual terms of this swap portfolio to increase the weighted-average interest rate it is required to pay from approximately 3.25% to approximately 4.80%, and realized $552 million in cash. This realized gain was recorded to (gains) losses on other derivatives, net, as were unrealized gains of $57 million, for the year ended December 31, 2009, which were attributable to further fair-value changes of the Company’s swap portfolio.
The Company’s interest-rate derivative positions outstanding as of December 31, 2009, are as follows:
| millions |
Reference Period | Weighted-Average Interest Rate |
|||||
| Notional Principal Amount: | Start | End | |||||
| $750 |
October 2011 | October 2021 | 4.72 | % | |||
| $1,250 |
October 2011 | October 2041 | 4.83 | % | |||
| $250 |
October 2012 | October 2022 | 4.91 | % | |||
| $750 |
October 2012 | October 2042 | 4.80 | % | |||
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ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2009, 2008 and 2007
8. Derivative Instruments (Continued)
Effect of Derivative Instruments—Balance Sheet The fair value of all oil and gas and interest-rate derivative instruments not designated as hedging instruments (including physical-delivery sales contracts) is included in the table below.
| millions
Derivatives |
Balance Sheet |
Gross Asset Derivatives |
Gross Liability Derivatives |
|||||||||||||
| December 31, 2009 |
December 31, 2008 |
December 31, 2009 |
December 31, 2008 |
|||||||||||||
| Commodity |
Other Current Assets |
$ | 140 | $ | 709 | $ | (63 | ) | $ | (134 | ) | |||||
| Other Assets |
82 | 156 | (6 | ) | (24 | ) | ||||||||||
| Accrued Expenses |
195 | — | (417 | ) | (14 | ) | ||||||||||
| Other Liabilities |
25 | 1 | (52 | ) | (28 | ) | ||||||||||
| Total Commodity Derivatives |
442 | 866 | (538 | ) | (200 | ) | ||||||||||
| Interest Rate |
Other Assets |
53 | 3 | — | — | |||||||||||
| Accrued Expenses |
— | — | — | (10 | ) | |||||||||||
| Other Liabilities |
— | — | (3 | ) | — | |||||||||||
| Total Derivatives |
$ | 495 | $ | 869 | $ | (541 | ) | $ | (210 | ) | ||||||
Effect of Derivative Instruments—Statement of Income The unrealized and realized gain or loss amounts and classification related to derivative instruments not designated as hedging instruments are as follows:
| millions
Derivatives |
Classification of (Gain) Loss Recognized |
Amount of (Gain) Loss Recognized | |||||||||||
| 2009 | 2008 | 2007 | |||||||||||
| Commodity |
Gathering, Processing and Marketing Sales* |
$ | 37 | $ | (4 | ) | $ | 80 | |||||
| (Gains) Losses on Commodity Derivatives, net |
408 | (561 | ) | 524 | |||||||||
| Interest Rate |
(Gains) Losses on Other Derivatives, net |
(582 | ) | 10 | 9 | ||||||||
| Total Derivative (Gain) Loss |
$ | (137 | ) | $ | (555 | ) | $ | 613 | |||||
| * | Represents the effect of marketing and trading derivative activities. |
The unrealized gain or loss amounts and classification related to derivative instruments included in the table above not designated as hedging instruments are as follows:
| millions | Amount of Unrealized (Gain) Loss Recognized | ||||||||||||
| Derivatives |
Classification of Unrealized (Gain) Loss Recognized |
2009 | 2008 | 2007 | |||||||||
| Commodity |
Gathering, Processing and Marketing Sales |
$ | 39 | $ | (29 | ) | $ | 52 | |||||
| (Gains) Losses on Commodity Derivatives, net |
735 | (900 | ) | 1,048 | |||||||||
| Interest Rate |
(Gains) Losses on Other Derivatives, net |
(57 | ) | 10 | 9 | ||||||||
| Total Derivative Unrealized (Gain) Loss |
$ | 717 | $ | (919 | ) | $ | 1,109 | ||||||
Credit-Risk Considerations The financial integrity of exchange-traded contracts are assured by NYMEX or the Intercontinental Exchange through their systems of financial safeguards and transaction guarantees and are subject to nominal credit risk. Over-the-counter traded swaps, options and futures contracts expose the Company
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ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2009, 2008 and 2007
8. Derivative Instruments (Continued)
to counterparty credit risk. The Company monitors the creditworthiness of each of its counterparties, establishes credit limits according to the Company’s credit policies and guidelines, and assesses the impact, if any, of counterparties’ creditworthiness on fair value. The Company has the ability to require cash collateral or letters of credit to mitigate credit-risk exposure. The Company also routinely exercises its contractual right to net realized gains against realized losses when settling with its counterparties.
The Company’s net asset derivatives recorded at fair value on the balance sheet include amounts attributable to agreements entered into with financial institutions. Approximately $442 million of the Company’s $495 million gross derivative asset balance at December 31, 2009 was attributable to open positions with financial institutions. The Company has netting and setoff agreements with each of these counterparties, which permit the net settlement of these gross derivative assets against gross derivative liabilities with this same group of counterparties. As of December 31, 2009, $321 million of the Company’s $541 million gross derivative liability balance is permitted to offset the gross derivative asset balance. The table below includes the financial impact of our netting arrangements on the fair value of the Company’s outstanding derivative positions.
Certain of the Company’s derivative instruments contain provisions requiring either full or partial collateralization of the Company’s obligations, or the immediate settlement of all such obligations in the event of a downgrade in the Company’s credit rating to a level below investment grade from major credit rating agencies. The aggregate fair value of all derivative instruments with credit-risk-related contingent features for which a net liability position existed on December 31, 2009 was $146 million. This amount represents the amount that the Company would have to either collateralize or cash settle in the event the Company’s credit rating was downgraded to a level below investment grade and the credit-risk-related features of such instruments were exercised.
Fair Value The fair value of commodity-futures contracts are based on inputs that are quoted prices in active markets for identical assets or liabilities, resulting in Level 1 categorization of such measurements. The valuation of physical-delivery purchase and sale agreements, over-the-counter financial swaps and three-way collars are based on similar transactions observable in active markets or industry-standard models that primarily rely on market-observable inputs. Substantially all of the assumptions for industry-standard models are observable in active markets throughout the full term of the instrument. Therefore, the Company categorizes these measurements as Level 2.
The following tables set forth, by level within the fair-value hierarchy, the fair value of the Company’s financial assets and liabilities.
December 31, 2009
| millions | Level 1 | Level 2 | Level 3 | Netting and Collateral(1) |
Total | ||||||||||||||
| Assets: |
|||||||||||||||||||
| Commodity derivatives |
$ | 4 | $ | 438 | $ | — | $ | (289 | ) | $ | 153 | ||||||||
| Interest-rate derivatives |
— | 53 | — | — | 53 | ||||||||||||||
| Total |
$ | 4 | $ | 491 | $ | — | $ | (289 | ) | $ | 206 | ||||||||
| Liabilities: |
|||||||||||||||||||
| Commodity derivatives |
$ | (6 | ) | $ | (532 | ) | $ | — | $ | 333 | $ | (205 | ) | ||||||
| Interest-rate derivatives |
— | (3 | ) | — | — | (3 | ) | ||||||||||||
| Total |
$ | (6 | ) | $ | (535 | ) | $ | — | $ | 333 | $ | (208 | ) | ||||||
| (1) | Represents the impact of netting assets, liabilities and collateral with counterparties with which the right of setoff exists. Cash collateral held by counterparties from Anadarko was $105 million at December 31, 2009. Anadarko held no cash collateral from counterparties at December 31, 2009. |
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ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2009, 2008 and 2007
8. Derivative Instruments (Continued)
December 31, 2008
| millions | Level 1 | Level 2 | Level 3 | Netting and Collateral(1) |
Total | ||||||||||||||
| Assets: |
|||||||||||||||||||
| Commodity derivatives |
$ | 34 | $ | 832 | $ | — | $ | (161 | ) | $ | 705 | ||||||||
| Interest-rate derivatives |
— | 3 | — | — | 3 | ||||||||||||||
| Total |
$ | 34 | $ | 835 | $ | — | $ | (161 | ) | $ | 708 | ||||||||
| Liabilities: |
|||||||||||||||||||
| Commodity derivatives |
$ | (13 | ) | $ | (187 | ) | $ | — | $ | 158 | $ | (42 | ) | ||||||
| Interest-rate derivatives |
— | (10 | ) | — | — | (10 | ) | ||||||||||||
| Total |
$ | (13 | ) | $ | (197 | ) | $ | — | $ | 158 | $ | (52 | ) | ||||||
| (1) | Represents the impact of netting assets, liabilities and collateral with counterparties with which the right of setoff exists. Cash collateral held by counterparties was $10 million at December 31, 2008. Cash collateral held by Anadarko from counterparties was $3 million at December 31, 2008. |
9. Asset Retirement Obligations
The majority of Anadarko’s asset retirement obligations relate to the plugging and abandonment of oil and gas properties. The following table provides a rollforward of the asset retirement obligations. Liabilities settled include settlement payments for obligations as well as obligations that were assumed by the purchasers of divested properties. Revisions to estimated liabilities during the period relate primarily to changes in estimates of asset retirement costs and include, but are not limited to, revisions of estimated inflation rates, changes in property lives and the expected timing of settling asset retirement obligations.
| millions | 2009 | 2008 | ||||||
| Carrying amount of asset retirement obligations at beginning of year |
$ | 1,368 | $ | 1,101 | ||||
| Liabilities incurred |
46 | 84 | ||||||
| Liabilities settled |
(60 | ) | (84 | ) | ||||
| Accretion expense |
89 | 70 | ||||||
| Revisions in estimated liabilities |
3 | 197 | ||||||
| Carrying amount of asset retirement obligations at end of year |
$ | 1,446 | $ | 1,368 | ||||
At December 31, 2009 and 2008, long-term asset retirement obligations of $1.4 billion were included in other long-term liabilities.
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ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2009, 2008 and 2007
10. Debt and Interest Expense
| December 31, | ||||||||||||||||||
| 2009 | 2008 | |||||||||||||||||
| millions | Principal | Carrying Value |
Fair Value |
Principal | Carrying Value |
Fair Value | ||||||||||||
| 7.30% Notes due 2009 |
$ | — | $ | — | $ | — | $ | 52 | $ | 52 | $ | 52 | ||||||
| Floating-Rate Notes due 2009 |
— | — | — | 1,420 | 1,420 | 1,359 | ||||||||||||
| 6.75% Notes due 2011 |
950 | 940 | 1,004 | 950 | 934 | 950 | ||||||||||||
| 6.875% Notes due 2011 |
675 | 688 | 726 | 675 | 695 | 668 | ||||||||||||
| 6.125% Notes due 2012 |
170 | 169 | 180 | 170 | 169 | 168 | ||||||||||||
| 5.00% Notes due 2012 |
82 | 82 | 85 | 82 | 82 | 77 | ||||||||||||
| 5.75% Notes due 2014 |
275 | 274 | 296 | — | — | — | ||||||||||||
| 7.625% Notes due 2014 |
500 | 499 | 571 | — | — | — | ||||||||||||
| 5.95% Notes due 2016 |
1,750 | 1,744 | 1,893 | 1,750 | 1,744 | 1,546 | ||||||||||||
| 7.05% Debentures due 2018 |
114 | 108 | 120 | 114 | 108 | 107 | ||||||||||||
| 6.95% Notes due 2019 |
300 | 297 | 340 | — | — | — | ||||||||||||
| 8.70% Notes due 2019 |
600 | 598 | 749 | — | — | — | ||||||||||||
| 6.95% Notes due 2024 |
650 | 673 | 704 | 650 | 674 | 570 | ||||||||||||
| 7.50% Debenture due 2026 |
112 | 106 | 115 | 112 | 106 | 100 | ||||||||||||
| 7.00% Debentures due 2027 |
54 | 54 | 54 | 54 | 54 | 47 | ||||||||||||
| 7.125% Debentures due 2027 |
150 | 157 | 152 | 150 | 157 | 132 | ||||||||||||
| 6.625% Debentures due 2028 |
17 | 17 | 17 | 17 | 17 | 14 | ||||||||||||
| 7.15% Debentures due 2028 |
235 | 215 | 233 | 235 | 215 | 204 | ||||||||||||
| 7.20% Debentures due 2029 |
135 | 135 | 139 | 135 | 135 | 119 | ||||||||||||
| 7.95% Debentures due 2029 |
117 | 117 | 127 | 117 | 116 | 109 | ||||||||||||
| 7.50% Notes due 2031 |
900 | 858 | 1,010 | 900 | 856 | 796 | ||||||||||||
| 7.875% Notes due 2031 |
500 | 580 | 583 | 500 | 581 | 460 | ||||||||||||
| Zero-Coupon Notes due 2036 |
2,360 | 591 | 623 | 2,360 | 561 | 572 | ||||||||||||
| 6.45% Notes due 2036 |
1,750 | 1,742 | 1,827 | 1,750 | 1,742 | 1,380 | ||||||||||||
| 7.95% Notes due 2039 |
325 | 324 | 398 | — | — | — | ||||||||||||
| 7.73% Debentures due 2096 |
61 | 60 | 66 | 61 | 61 | 55 | ||||||||||||
| 7.50% Debentures due 2096 |
78 | 72 | 74 | 78 | 72 | 66 | ||||||||||||
| 7.25% Debentures due 2096 |
49 | 49 | 47 | 49 | 49 | 41 | ||||||||||||
| Midstream Subsidiary Note Payable to a Related Party due 2012 |
1,599 | 1,599 | 1,599 | 1,739 | 1,739 | 1,739 | ||||||||||||
| Total debt |
14,508 | 12,748 | 13,732 | 14,120 | 12,339 | 11,331 | ||||||||||||
| Less: Current maturities |
— | — | — | 1,472 | 1,472 | 1,411 | ||||||||||||
| Total long-term debt |
$ | 14,508 | $ | 12,748 | $ | 13,732 | $ | 12,648 | $ | 10,867 | $ | 9,920 | ||||||
The fair value of debt is the estimated amount the Company would have to pay to repurchase its debt, including any premium or discount attributable to the difference between the stated interest rate and market rate of interest at the balance sheet date. Fair values are based on quoted market prices or average valuations of similar debt instruments at the balance sheet date for those debt instruments for which quoted market prices are not available.
Except for Anadarko’s Midstream Subsidiary Note Payable to a Related Party (see following discussion), none of the Company’s notes, debentures or credit agreements contain credit-rating-downgrade triggers that result in accelerating debt maturity. All of the Company’s debt, with the exception of the WES credit facility, is senior unsecured debt of the Company. As of December 31, 2009, the Company had approximately $340 million in undrawn letters of credit.
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ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2009, 2008 and 2007
10. Debt and Interest Expense (Continued)
The net unamortized debt discount, represented in the previous table, of $1.8 billion as of December 31, 2009 and 2008 is being amortized to interest expense over the terms of the related debt. See Note 6 for Anadarko’s notes payable to certain investees that do not affect the reported debt balance.
The following table presents the debt activity of the Company for 2009 and 2008.
| millions | Activity |
Principal | Carrying Value |
Description | ||||||||
| Balance as of December 31, 2007 |
$ | 16,558 | $ | 14,747 | ||||||||
| First Quarter 2008 |
||||||||||||
| Repayments |
(1,000 | ) | (1,000 | ) | Acquisition Facility due 2008 | |||||||
| Other, net |
— | 7 | Accretion and discount amortization | |||||||||
| Second Quarter 2008 |
||||||||||||
| Repayments |
(350 | ) | (350 | ) | 3.25% Notes due 2008 | |||||||
| Repayments |
(330 | ) | (330 | ) | Midstream Subsidiary Note Payable to a Related Party | |||||||
| Repayments |
(47 | ) | (46 | ) | 6.75% Notes due 2008 | |||||||
| Other, net |
— | 7 | Accretion and discount amortization | |||||||||
| Third Quarter 2008 |
||||||||||||
| Repayments |
(344 | ) | (344 | ) | Floating-Rate Notes due 2009 | |||||||
| Other, net |
— | 7 | Accretion and discount amortization | |||||||||
| Fourth Quarter 2008 |
||||||||||||
| Repayments |
(236 | ) | (236 | ) | Floating-Rate Notes due 2009 | |||||||
| Repayments |
(131 | ) | (131 | ) | Midstream Subsidiary Note Payable to a Related Party | |||||||
| Other, net |
— | 8 | Accretion and discount amortization | |||||||||
| Balance as of December 31, 2008 |
$ | 14,120 | $ | 12,339 | ||||||||
| First Quarter 2009 |
||||||||||||
| Issuance |
500 | 499 | 7.625% Notes due 2014 | |||||||||
| Issuance |
600 | 598 | 8.70% Notes due 2019 | |||||||||
| Repayments |
(452 | ) | (452 | ) | Floating-Rate Notes due 2009 | |||||||
| Other, net |
— | 6 | Accretion and discount amortization | |||||||||
| Second Quarter 2009 |
||||||||||||
| Issuance |
275 | 274 | 5.75% Notes due 2014 | |||||||||
| Issuance |
300 | 297 | 6.95% Notes due 2019 | |||||||||
| Issuance |
325 | 324 | 7.95% Notes due 2039 | |||||||||
| Repayments |
(968 | ) | (968 | ) | Floating-Rate Notes due 2009 | |||||||
| Repayments |
(52 | ) | (52 | ) | 7.30% Notes due 2009 | |||||||
| Other, net |
— | 8 | Accretion and discount amortization | |||||||||
| Third Quarter 2009 |
||||||||||||
| Repayments |
(100 | ) | (100 | ) | Midstream Subsidiary Note Payable to a Related Party | |||||||
| Other, net |
— | 7 | Accretion and discount amortization | |||||||||
| Fourth Quarter 2009 |
||||||||||||
| Repayments |
(40 | ) | (40 | ) | Midstream Subsidiary Note Payable to a Related Party | |||||||
| Other, net |
— | 8 | Accretion and discount amortization | |||||||||
| Balance as of December 31, 2009 |
$ | 14,508 | $ | 12,748 | ||||||||
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ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2009, 2008 and 2007
10. Debt and Interest Expense (Continued)
In October 2006, the Company received $500 million of proceeds from a private offering of Zero-Coupon Senior Notes due 2036 with an aggregate principal amount at maturity of $2.4 billion. The Company presents the note in long-term debt. The carrying amount as of December 31, 2009 includes $30 million, $28 million and $28 million related to accretion expense recognized in 2009, 2008 and 2007, respectively. The notes were issued with a yield to maturity of 5.24%, and the holder has an option to put the notes back to the Company annually, starting in 2010, at the accreted value, which approximates carrying value. If the put option is exercised in 2010, the Company intends to refinance the debt under its Revolving Credit Agreement (RCA).
Midstream Subsidiary Note Payable to a Related Party In December 2007, Anadarko and the Investor formed Trinity, with initial capitalization totaling $2.3 billion. Note 6 provides additional information regarding Anadarko’s interest in Trinity. Trinity extended a $2.2 billion loan to a wholly owned subsidiary of Anadarko, referred to herein as Midstream Holding, which holds and operates substantially all of Anadarko’s midstream assets, directly and through its subsidiaries. The Company used all of the loan proceeds received by Midstream Holding to repay a portion of the Company’s indebtedness related to the 2006 acquisitions.
The principal balance owed by Midstream Holding to Trinity is reflected in the accompanying consolidated balance sheet as Midstream Subsidiary Note Payable to a Related Party. The loan has an initial maturity date of December 27, 2012, subject to renewals for additional five-year periods on market terms at the time of renewal. Interest on the loan is based on three-month LIBOR plus a margin. The rate in effect at the beginning of 2010 is 1.32%.
Midstream Holding may repay the loan in whole or in part at any time prior to maturity. In December 2008, Anadarko provided a parental guaranty for the payment of principal and interest on the remaining balance of the Midstream Subsidiary Note Payable to a Related Party in exchange for the removal of various covenants in the loan agreement, including a ceiling on the maximum ratio of debt-to-earnings before interest, taxes, depreciation and amortization as defined in the loan agreement. Midstream Holding was in compliance with all previously existing covenants as of the date the Anadarko parental guaranty was provided. The amended loan agreement requires customary representations and warranties and affirmative and negative covenants, and includes the same financial covenants as the RCA discussed below. The Midstream Subsidiary Note Payable to a Related Party has the same priority with respect to the payment of principal and interest as Anadarko’s other debt.
Following a sale or transfer of assets to third parties or other entities within the Anadarko consolidated group, Midstream Holding and/or its subsidiaries will be required to repay a portion of the loan principal. Further, maturity of the loan could be accelerated if Anadarko’s senior unsecured credit rating were to be rated below “BB-” by Standard and Poor’s (S&P) or “Ba3” by Moody’s Investors Service (Moody’s). As of December 31, 2009, the Company was in compliance with all covenants, and S&P and Moody’s rated the Company’s debt at “BBB-” and “Baa3”, respectively.
Anadarko Revolving Credit Agreement In March 2008, the Company entered into a $1.3 billion, five-year RCA with a syndicate of United States and foreign lenders. Under the terms of the RCA, the Company can, under certain conditions, request an increase in the borrowing capacity under the RCA up to a total available credit amount of $2.0 billion. The RCA has a maximum 65% debt-to-capitalization covenant. The RCA terminates in March 2013. As of December 31, 2009, the Company had no outstanding borrowings under the RCA. Anadarko was in compliance with existing covenants and the full amount of the RCA was available for borrowing at December 31, 2009.
WES Revolving Credit Facility In October 2009, Anadarko’s consolidated subsidiary, WES, entered into a three-year senior unsecured revolving credit facility (RCF) with a group of banks. The aggregate initial commitments of the lenders under the RCF are $350 million and are expandable to a maximum of $450 million.
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ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2009, 2008 and 2007
10. Debt and Interest Expense (Continued)
The RCF matures in October 2012. The RCF contains various customary covenants including a limitation on debt to earnings before interest, taxes, depreciation and amortization and a minimum interest coverage requirement. As of December 31, 2009, WES had no outstanding borrowings under the RCF. WES was in compliance with existing covenants at December 31, 2009.
Scheduled Maturities Total maturities related to debt for the five years ending December 31, 2014 are shown below.
| millions | |||
| 2010 |
$ | — | |
| 2011 |
1,625 | ||
| 2012 |
1,850 | ||
| 2013 |
— | ||
| 2014 |
775 | ||
Interest Expense The following table summarizes the amounts included in interest expense.
| millions | 2009 | 2008 | 2007 | |||||||||
| Interest Expense |
||||||||||||
| Gross interest expense— |
||||||||||||
| Current debt, long-term debt and other(1) |
$ | 732 | $ | 746 | $ | 1,203 | ||||||
| Midstream subsidiary note payable to a related party |
39 | 109 | 2 | |||||||||
| Capitalized interest(2) |
(69 | ) | (123 | ) | (122 | ) | ||||||
| Net interest expense |
$ | 702 | $ | 732 | $ | 1,083 | ||||||
| (1) | Included in 2009 is the reversal of the $78 million liability for unpaid interest related to the DWRRA dispute. See Note 14. |
| (2) | Included in 2008 is additional capitalized interest related to a prior period of $16 million. |
See Note 6 for interest expense incurred on certain notes payable to unconsolidated affiliates which is reported in other (income) expense.
11. Stockholders’ Equity
Common Stock In August 2008, the Company announced a $5 billion share-repurchase program under which shares may be repurchased either in the open market or through privately negotiated transactions. The program is authorized to extend through August 2011 and replaced the $1 billion stock-buyback program authorized in 2005. The repurchase program does not obligate Anadarko to acquire any specific number of shares and may be discontinued at any time. During 2008, Anadarko purchased 10 million shares of common stock for $600 million under the program through purchases in the open market and under share-repurchase agreements. During 2009 and 2007, no shares were repurchased under the programs in effect at those times.
In May 2009, Anadarko completed a public offering of 30 million shares of common stock at $45.50 per share. After deducting the underwriting discount and other offering costs of $28 million, net proceeds to the Company were approximately $1.3 billion. Net proceeds from the offering were used for general corporate purposes, including capital expenditures.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2009, 2008 and 2007
11. Stockholders’ Equity (Continued)
The changes in the Company’s shares of common stock are as follows:
| millions | 2009 | 2008 | 2007 | |||
| Shares of common stock issued |
||||||
| Beginning of year |
472 | 469 | 463 | |||
| Issuance of common stock |
30 | — | — | |||
| Exercise of stock options |
1 | 1 | 4 | |||
| Issuance of restricted stock |
2 | 2 | 2 | |||
| End of year |
505 | 472 | 469 | |||
| Shares of common stock held in treasury |
||||||
| Beginning of year |
12 | 1 | — | |||
| Purchase of treasury stock |
— | 10 | — | |||
| Shares received for restricted stock vested and options exercised |
— | 1 | 1 | |||
| End of year |
12 | 12 | 1 | |||
| Shares of common stock outstanding at end of year |
493 | 460 | 468 | |||
The number of shares of common stock issued and outstanding presented in the table above excludes 4 million shares held by the Anadarko Petroleum Corporation Executives and Directors Benefits Trust, a grantor trust associated with the Company’s obligations under certain of its pension and deferred-compensation plans.
For all periods presented, quarterly dividends of nine cents per share were paid to holders of common stock. As of December 31, 2009, the covenants contained in certain of the Company’s credit and lease agreements provided for a maximum debt-to-capitalization ratio of 65%. The covenants do not specifically restrict the payment of dividends; however, the impact of dividends paid on the Company’s debt-to-capitalization ratio must be considered in order to ensure covenant compliance. Based on these covenants, as of December 31, 2009, retained earnings of approximately $13.3 billion were not limited as to the payment of dividends.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2009, 2008 and 2007
11. Stockholders’ Equity (Continued)
The reconciliation between basic and diluted EPS from continuing operations attributable to common stockholders is as follows:
| millions except per share amounts | 2009 | 2008 | 2007 | |||||||
| Income: |
||||||||||
| Income (loss) from continuing operations attributable to common stockholders |
$ | (135 | ) | $ | 3,197 | $ | 3,767 | |||
| Less: Distributions to participating securities |
— | 2 | 2 | |||||||
| Less: Undistributed income allocated to participating securities |
— | 37 | 40 | |||||||
| Basic |
$ | (135 | ) | $ | 3,158 | $ | 3,725 | |||
| Diluted |
$ | (135 | ) | $ | 3,158 | $ | 3,725 | |||
| Shares: |
||||||||||
| Basic |
||||||||||
| Weighted-average common shares outstanding |
480 | 465 | 465 | |||||||
| Dilutive effect of stock options and performance-based stock awards |
— | 1 | 2 | |||||||
| Diluted |
480 | 466 | 467 | |||||||
| Income (loss) per common share: |
||||||||||
| Basic |
$ | (0.28 | ) | $ | 6.79 | $ | 8.01 | |||
| Diluted |
$ | (0.28 | ) | $ | 6.78 | $ | 7.99 | |||
All prior-period EPS data presented above have been adjusted retrospectively to conform to the requirements of a new accounting standard, which addresses whether instruments granted in share-based payment transactions constitute participating securities. For 2009, basic EPS was not impacted by the two-class method because the Company’s participating securities are not obligated to share in the losses of the Company, and diluted EPS was not impacted because the inclusion of these securities would have had an anti-dilutive effect. Basic and diluted EPS, as previously reported, decreased $0.08 and $0.06, respectively, in 2008 and decreased $0.08 and $0.06, respectively, in 2007 under the two-class method.
For 2009, 2008 and 2007, awards for 14.2 million, 7.6 million and 6.6 million average shares, respectively, of common stock were excluded from the diluted EPS calculation because the inclusion of these shares would have had an anti-dilutive effect.
See Note 12 for information related to common stock issued under stock-based compensation plans.
Preferred Stock In the second quarter of 2008, Anadarko redeemed and subsequently retired its 5.46% Series B Cumulative Preferred Stock for $45 million. Holders of the shares were entitled to receive, when and as declared by the Board of Directors, cumulative cash dividends at an annual rate of $5.46 per share.
Dividends of $27.30 per share for 2008 and $54.60 per share for 2007 (equivalent to $2.73 and $5.46, respectively, per Depositary Share) were paid to holders of preferred stock.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2009, 2008 and 2007
12. Stock-Based Compensation
The Company generally issues new shares to satisfy employee share-based payment plans. At December 31, 2009, 24 million shares of the 35 million shares of Anadarko common stock originally authorized for awards under the active share-based compensation plans remain available for future issuance. The number of shares available is reduced by awards granted. A summary of stock-based compensation cost is presented below:
| millions | 2009 | 2008 | 2007 | ||||||
| Compensation cost: |
|||||||||
| Restricted stock |
$ | 138 | $ | 131 | $ | 115 | |||
| Value Creation Plan and other |
171 | 43 | 55 | ||||||
| Total compensation cost, pretax |
309 | 174 | 170 | ||||||
| Income tax benefit |
112 | 63 | 62 | ||||||
For 2009, 2008 and 2007, $12.3 million, $9.4 million and $23.4 million, respectively, in excess tax benefits were included in cash flow from financing activities. Cash received from stock option exercises for 2009, 2008 and 2007 was $22.3 million, $14.1 million and $88.7 million, respectively.
Equity-Classified Awards
Stock Options Certain employees may be granted options to purchase shares of Anadarko common stock with an exercise price equal to, or greater than, the fair market value of Anadarko common stock on the date of grant. These stock options vest over service periods ranging from three to four years and will terminate at the earlier of seven years from the date of grant or the date of exercise.
Nonemployee directors may be granted nonqualified stock options with an exercise price equal to the fair market value of Anadarko common stock on the date of grant. These stock options vest over a one-year service period from the date of grant and terminate at the earlier of ten years from the date of grant or the date of exercise.
The fair value of stock option awards is determined using the Black-Scholes option-pricing model. The expected life of the option is estimated based upon historical exercise behavior. The expected forfeiture rate is estimated based upon historical forfeiture experience. The volatility assumption was estimated based upon expectations of volatility over the life of the option as measured by historical and implied volatility. The risk-free interest rate was based on the U.S. Treasury rate for a term commensurate with the expected life of the option. The dividend yield was based upon a 12-month average dividend yield. The Company used the following weighted-average assumptions to estimate the fair value of stock options granted during 2009, 2008 and 2007.
| 2009 | 2008 | 2007 | |||||||
| Expected option life — years |
4.9 | 4.9 | 5.0 | ||||||
| Volatility |
46.3 | % | 37.3 | % | 28.9 | % | |||
| Risk-free interest rate |
1.9 | % | 2.5 | % | 4.4 | % | |||
| Dividend yield |
0.8 | % | 0.6 | % | 0.8 | % |
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2009, 2008 and 2007
12. Stock-Based Compensation (Continued)
A summary of stock option activity for the year ended December 31, 2009 is presented below:
| Shares (millions) |
Weighted- Average Exercise Price |
Weighted- Average Remaining Contractual Term (years) |
Aggregate Intrinsic Value (millions) | ||||||||
| Outstanding at January 1, 2009 |
6.39 | $ | 42.59 | ||||||||
| Granted |
3.95 | $ | 38.42 | ||||||||
| Exercised |
(0.78 | ) | $ | 28.59 | |||||||
| Forfeited or expired |
(0.08 | ) | $ | 41.87 | |||||||
| Outstanding at December 31, 2009 |
9.48 | $ | 42.01 | 5.0 | $ | 197.1 | |||||
| Vested or expected to vest at December 31, 2009 |
9.30 | $ | 42.03 | 5.0 | $ | 193.1 | |||||
| Exercisable at December 31, 2009 |
3.87 | $ | 44.38 | 3.6 | $ | 70.6 | |||||
The weighted-average grant-date fair value of stock options granted during 2009, 2008 and 2007 was $15.23, $13.93 and $16.51, respectively, using the Black-Scholes option-pricing model. The total intrinsic value of stock options exercised during 2009, 2008 and 2007 was $24.3 million, $12.5 million and $78.9 million, respectively, based on the difference between the market price at the exercise date and the option price. As of December 31, 2009, there was $64.2 million of total unrecognized compensation cost related to stock options, which is expected to be recognized over a weighted-average period of 2.1 years.
Restricted Stock Certain employees may be granted restricted stock in the form of restricted stock awards or restricted stock units. Restricted stock is subject to forfeiture restrictions and cannot be sold, transferred or disposed of during the restriction period. The holders of restricted stock awards have the same rights as a stockholder of the Company with respect to such shares, including the right to vote and receive dividends or other distributions paid with respect to the shares. A restricted stock unit is equivalent to a restricted stock award except that unit holders receive cash dividend equivalents during the restriction period and do not have the right to vote the units. Restricted stock vests over service periods ranging from the date of grant up to four years and is not considered issued and outstanding until it vests.
Nonemployee directors are granted deferred shares that are held in a grantor trust by the Company and become payable when the director ceases to serve on the Board of Directors.
A summary of restricted stock activity for the year ended December 31, 2009 is presented below:
| Shares (millions) |
Weighted-Average Grant-Date Fair Value | |||||
| Nonvested at January 1, 2009 |
4.76 | $ | 56.01 | |||
| Granted |
1.65 | $ | 40.65 | |||
| Vested |
(2.50 | ) | $ | 53.74 | ||
| Forfeited |
(0.08 | ) | $ | 51.28 | ||
| Nonvested at December 31, 2009 |
3.83 | $ | 50.98 | |||
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2009, 2008 and 2007
12. Stock-Based Compensation (Continued)
The weighted-average grant-date fair value of restricted stock granted during 2008 and 2007 was $61.20 and $52.53, respectively. The total fair value of restricted shares vested during 2009, 2008 and 2007 was $122.0 million, $110.3 million and $119.1 million, respectively, based on the market price at the vesting date. As of December 31, 2009, there was $126.2 million of total unrecognized compensation cost related to restricted stock, which is expected to be recognized over a weighted-average period of 1.6 years.
Performance-Based Share Awards Key officers of the Company were provided Performance Unit Award Agreements in 2004, 2005 and 2006 with three-year performance periods ending December 2007, 2008 and 2009, respectively. The number of shares of common stock to be issued was determined based on a market objective and a performance objective, with both objectives equally weighted. The number of shares of common stock to be issued with respect to the market objective was determined by comparing the Company’s total shareholder return to the total shareholder return of a predetermined group of peer companies over the performance period. The number of shares of common stock to be issued with respect to the performance objective was determined based on the Company’s return on capital over the performance period. The fair value per share for the performance-based objective is $31.54, $47.14 and $49.86 for the agreements related to the three-year periods ending December 2007, 2008 and 2009, respectively. The table below summarizes these awards:
| Year Granted |
Award Type |
Maximum Shares of Common Stock |
Performance Period | Shares of Common Stock Issued |
Year Issued | |||||||||
| 2004 |
Annual | 200,400 | 1.1.2005 -12.31.2007 | 21,800 | (1) | 2006 | ||||||||
| 2005 |
Annual | (2) | 506,000 | 1.1.2006 -12.31.2008 | 39,000 | (1) | 2006 | |||||||
| 17,600 | (1) | 2007 | ||||||||||||
| 2006 |
Annual | (2) | 358,200 | 1.1.2007 -12.31.2009 | 12,400 | (1) | 2006 | |||||||
| 7,100 | (1) | 2007 |
| (1) | No shares were issued to current key officers. Shares shown as issued reflect shares issued to certain key officers whose employment with the Company terminated prior to the end of the performance period and the determination of actual performance. |
| (2) | In November 2007, the Company cancelled, without value and with the consent of the key officers, the outstanding 2005 and 2006 Performance Unit Award Agreements. |
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2009, 2008 and 2007
12. Stock-Based Compensation (Continued)
In November 2007, in place of the cancelled awards, two new Performance Unit Award Agreements were provided to key officers. The number of shares of common stock awarded under these agreements is based solely on a comparison of the Company’s total shareholder return to the total shareholder return of a predetermined group of peer companies over performance periods ranging from one to three years. The table below summarizes these awards:
| Year Granted |
Award Type |
Maximum Shares of Common Stock |
Performance Period | Shares of Common Stock Issued |
Year Issued | |||||||||
| 2007 |
Transitional | (1) | 184,512 | 1.1.2008 -12.31.2008 | 6,162 | (2) | 2008 | |||||||
| 184,512 | 1.1.2008 -12.31.2009 | 7,719 | (2) | 2009 | ||||||||||
| 128,505 | (3) | 2010 | ||||||||||||
| Annual | 282,700 | 1.1.2008 -12.31.2009 | 5,700 | (2) | 2008 | |||||||||
| 125,706 | (3) | 2010 | ||||||||||||
| 282,700 | 1.1.2008 -12.31.2010 | 29,100 | (2) | 2009 |
| (1) | Recognized incremental compensation cost of $7 million attributable to the modification of the cancelled awards. |
| (2) | No shares of common stock were issued to current key officers. Shares shown as issued reflect shares issued to certain key officers whose employment with the Company terminated prior to the end of the performance period and the determination of actual performance. |
| (3) | During 2010, 336,865 shares were awarded to current key officers for the performance periods that ended December 2009. |
As of December 31, 2009, there was $2.6 million of total estimated unrecognized compensation cost related to performance-based share awards, which is expected to be recognized over a weighted-average period of one year.
Liability-Classified Awards
Value Creation Plan As a part of its employee compensation program, the Company offers an incentive compensation program that generally provides non-officer employees the opportunity to earn cash bonus awards based on the Company’s total shareholder return for the year, compared to the total shareholder return of a predetermined group of peer companies. As of December 31, 2009, the Company has accrued approximately $105 million for the 2009 performance period.
Performance-Based Unit Awards In November 2008 and 2009, key officers of the Company were provided Performance Unit Award Agreements with a two-year performance period ending December 31, 2010 and 2011, respectively, and a three-year performance period ending December 31, 2011 and 2012, respectively. The vesting of these units is based solely on comparing the Company’s total shareholder return to the total shareholder return of a predetermined group of peer companies over the specified performance period. Each performance unit represents the value of one share of the Company’s common stock. At the end of each performance period, the value of the vested performance units, if any, will be paid in cash. As of December 31, 2009, the liability under Performance Unit Award Agreements was $16.7 million, and there was $38.4 million of total estimated unrecognized compensation cost related to these awards, which is expected to be recognized over a weighted-average period of two years.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2009, 2008 and 2007
13. Commitments
Leases The Company has $2.5 billion in long-term drilling rig commitments that satisfy operating lease criteria. The Company also has various commitments under noncancelable operating lease agreements of $0.9 billion for production platforms and equipment, buildings, facilities and aircraft. These operating leases expire at various dates through 2024. Certain of these operating leases contain residual value guarantees at the end of the lease term; however, at December 31, 2009, no material liabilities were accrued for these guarantees. At December 31, 2009, future minimum lease payments under existing operating leases are as follows:
| millions | Operating Leases | ||
| 2010 |
$ | 971 | |
| 2011 |
872 | ||
| 2012 |
776 | ||
| 2013 |
383 | ||
| 2014 |
95 | ||
| Later years |
296 | ||
| Total future minimum lease payments |
$ | 3,393 | |
Total rent expense, net of sublease income, amounted to $188 million in 2009, $226 million in 2008 and $229 million in 2007. Total rent expense includes contingent rent expense related to processing fees of $39 million, $32 million and $6 million in 2009, 2008 and 2007, respectively.
Drilling Rig Commitments Anadarko has entered into various agreements to secure a portion of the drilling rigs necessary to execute its drilling plans over the next several years. The table of future minimum lease payments above includes approximately $2.3 billion related to 5 offshore drilling vessels and $186 million related to certain contracts for onshore United States drilling rigs. The portion of these lease payments associated with exploratory wells and development wells, net of amounts billed to partners, will initially be capitalized as a component of oil and gas properties, and either depreciated in future periods or written off as exploration expense.
Production Platforms During 2004, Anadarko and a group of energy companies (Atwater Valley Producers Group) executed agreements with third parties for the dedication, processing and gathering of natural-gas and condensate production from several natural-gas fields in the deepwater Gulf of Mexico. Third parties constructed and own Independence Hub, a semi-submersible platform in the deepwater Gulf of Mexico. Anadarko became operator of the platform structure upon mechanical completion in 2007.
The table of future minimum lease payments above includes $72 million related to the monthly demand charges due under the above-described agreements. The agreements do not contain any purchase options, purchase obligations or value guarantees.
Spar Platform and Production Vessel Leases Anadarko has operating leases related to certain spar platforms in the Gulf of Mexico and a floating production, storage and offloading vessel in China. The table of future minimum lease payments above includes approximately $450 million for these agreements. These agreements also contain residual value guarantees totaling $37 million at the end of the lease periods.
Buildings The table of future minimum lease payments above includes the Company’s lease payment obligations of $99 million related to office building leases, including the corporate office building located in Denver, Colorado. In December 2009, the Company exercised its purchase option under a lease covering two
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2009, 2008 and 2007
13. Commitments (Continued)
corporate office buildings in The Woodlands, Texas (The Woodlands lease). The Woodlands lease contained various covenants including covenants regarding the Company’s financial condition. The Company was in compliance with these covenants at the time it exercised its purchase option.
Aircraft The table of future minimum lease payments above includes the Company’s lease payment obligations of $11 million related to aircraft leases. Some of these leases provide for a residual value guarantee for any deficiency resulting from a sale of aircraft for less than the sale option amount (approximately $31 million in the aggregate). In addition, the Company is entitled to any proceeds from a sale of an aircraft in excess of the sale option amount.
Other Equipment Leases Included in the table of future minimum lease payments above are lease payments of approximately $243 million related to equipment associated with various gas gathering and processing systems. In the event the Company does not purchase the equipment at the end of the leases, the Company may be required to make payments in connection with residual value guarantees for a total of up to $54 million.
Other Commitments In the normal course of business, the Company enters into other contractual agreements to purchase natural gas or crude oil, pipeline capacity, storage capacity, utilities and other services. Aggregate future payments under these contracts total $4.3 billion, of which $1.6 billion is expected to be paid in 2010, $890 million in 2011, $560 million in 2012, $311 million in 2013, $154 million in 2014 and $705 million thereafter.
The Company is obligated for approximately 27% of the construction costs of a floating production, storage and offloading vessel (FPSO) that will be used in the Company’s Ghana operations. Construction of the FPSO is expected to be complete in the first half of 2010, and the Company’s share of total construction costs is estimated to be approximately $224 million. At December 31, 2009, the Company has accrued a net liability of $129 million representing Anadarko’s net share of construction costs incurred to date, less amounts funded by Anadarko through loans and other payments to the contractor of approximately $60 million. The Company’s obligation for construction costs is reported net of amounts previously funded as Anadarko has a contractual right to offset collection of the loans made by Anadarko against the Company’s construction cost obligation.
Sale of Future Hard Minerals Royalty Revenues In 2004, the Company conveyed a limited-term non-participating royalty interest, which was carved out of the Company’s existing royalty interests, that entitles a third party to receive future coal and trona royalty revenue over an 11-year period. Additionally, the third party is entitled to receive 5% of the aggregate royalties earned during the first ten years of the agreement that exceed $400 million. The specified cumulative future amount that the third-party investor expects to receive, prior to the 5% of any excess royalties described above, is $100 million. This amount and the payment timing are subject to change based upon the actual royalties received by the Company during the term of the agreement. The third party relies solely on royalty payments to recover its investment; therefore, the third party bears the risk associated with the royalties being insufficient to recover the original investment over the term of the agreement.
Proceeds from this transaction were accounted for as deferred revenues and classified as liabilities on the balance sheet. The deferred revenues are amortized to other sales on a unit-of-revenue basis over the term of the agreement. For each of the years 2009, 2008 and 2007, the Company amortized $16 million of deferred revenues to other sales revenues related to this agreement.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2009, 2008 and 2007
14. Contingencies
General Litigation charges of $24 million, $112 million and $56 million were expensed during 2009, 2008 and 2007, respectively. The Company is a defendant in a number of lawsuits and is involved in governmental proceedings, including, but not limited to, royalty claims, contract claims and environmental claims. The Company has also been named as a defendant in various personal injury claims, including claims by employees of third-party contractors alleging exposure to asbestos, silica and benzene while working at refineries (previously owned by predecessors of acquired companies) located in Texas, California and Oklahoma. While the ultimate outcome and impact on the Company cannot be predicted with certainty, management believes that the resolution of these proceedings will not have a material adverse effect on the consolidated financial position, results of operations or cash flows of the Company.
Litigation The Company is subject to various claims from its royalty owners in the regular course of business as an oil and gas producer, including disputes regarding measurement, post-production costs and expenses and royalty valuations. The Company was named as a defendant in a case styled U.S. of America ex rel. Harold E. Wright v. AGIP Company, et al. filed in September 2000 in the U.S. District Court for the Eastern District of Texas, Lufkin Division. Kerr-McGee was also named as a defendant in this legal proceeding. This lawsuit generally alleges that the Company, including Kerr-McGee, and other industry defendants knowingly undervalued natural gas in connection with royalty payments on production from federal and Indian lands. Based on the Company’s present understanding of these various governmental and False Claims Act proceedings, the Company believes that it has substantial defenses to these claims and is vigorously asserting such defenses. However, if the Company is found to have violated the False Claims Act, the Company could be subject to a variety of damages, including treble damages and substantial monetary fines. The discovery process is ongoing. The court has entered an order whereby the case will be tried in phases. The claims against the Company have yet to be set for trial. The Company is currently in settlement discussions with the U.S. government in efforts to globally resolve this litigation against Anadarko and Kerr-McGee, as well as any related administrative actions. Management has accrued a liability for only the settlement amount. The Company believes that an additional loss is unlikely to have a material adverse effect on Anadarko’s consolidated financial position, results of operations or cash flows.
Deepwater Royalty Relief Act In 1995, the United States Congress passed the Deepwater Royalty Relief Act (DWRRA) to stimulate exploration and production of oil and natural gas by providing relief from the obligation to pay royalties on certain federal leases located in the deep waters of the Gulf of Mexico. The Company currently owns interests in several deepwater Gulf of Mexico leases granted during the 1996-2000 time period (some originally owned by Kerr-McGee). After the passage of the DWRRA, the Minerals Management Service (MMS), an agency of the Department of the Interior (DOI), inserted price thresholds into leases issued in 1996, 1997 and 2000 that effectively eliminated the DWRRA royalty relief if these price thresholds were exceeded. The Company’s 1998 and 1999 leases did not contain price-threshold provisions.
In January 2006, the DOI issued an order (the 2006 Order) to Kerr-McGee Oil and Gas Corporation (KMOG), a subsidiary of Kerr-McGee, to pay oil and gas royalties and accrued interest on KMOG’s deepwater Gulf of Mexico production associated with eight 1996, 1997 and 2000 leases, for which KMOG considered royalties to be suspended under the DWRRA. On March 17, 2006, KMOG filed a lawsuit styled Kerr-McGee Oil and Gas Corp. v. C. Stephen Allred, Assistant Secretary for Land & Minerals Mgt. and the Dept of the Interior (Kerr-McGee v. Allred) in the U.S. District Court for the Western District of Louisiana against the DOI for injunctive and declaratory relief with respect to the DOI’s claims for additional royalties on the eight leases listed in the 2006 Order. In May 2007, KMOG filed a motion for summary judgment with the District Court for the Western District of Louisiana which ruled in favor of KMOG in October 2007. The DOI appealed the decision to the U.S. Court of Appeals for the Fifth Circuit (Fifth Circuit). In January 2009, a three-judge Fifth Circuit panel unanimously affirmed the District Court’s ruling in favor of KMOG. At the end of March 2009, the DOI filed a petition for rehearing by the full Fifth Circuit (en banc) which was denied on April 14, 2009. The DOI filed a petition for a writ of certiorari with the U.S. Supreme Court which was denied on October 5, 2009.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2009, 2008 and 2007
14. Contingencies (Continued)
The MMS issued two additional orders to Anadarko in 2008 and 2009 to pay “past-due” royalties and interest covering several deepwater Gulf of Mexico leases, including certain leases contained in the 2006 Order. Generally, the orders issued in 2008 and 2009 cover time periods not included in the 2006 Order. Anadarko has filed administrative appeals of the 2008 and 2009 orders with the MMS and the appeals are currently stayed pending a final non-appealable judgment of Kerr-McGee v. Allred. The MMS has approved Anadarko’s request to “self-bond” the appeal of the order issued in 2008 in lieu of filing a letter of credit or other surety instrument. Anadarko is awaiting a response from the MMS on its request to “self-bond” the appeal of the 2009 order.
Based on the U.S. Supreme Court’s denial of the DOI’s petition for review by the court, Anadarko reversed its $657 million accrued liability for royalties in September 2009 that could be owed on leases listed in the 2006 Order, similar orders to pay issued in 2008 and 2009, and other deepwater Gulf of Mexico leases with similar price-threshold provisions. The Company’s accrued liability of $657 million related to royalties on production from January 2003 through September 2009, including a $165 million liability related to pre-acquisition contingencies recorded in purchase accounting. In addition, the Company reversed its $78 million accrued liability for interest on these unpaid royalty amounts, substantially all of which related to post-acquisition periods.
Guarantees and Indemnifications Under the terms of the Master Separation Agreement entered into between Kerr-McGee and Tronox Incorporated (Tronox), a former wholly owned subsidiary that held Kerr-McGee’s chemical business, Kerr-McGee agreed to reimburse Tronox for 50% of certain qualifying environmental-remediation costs incurred and paid by Tronox and its subsidiaries before November 28, 2012, subject to certain limitations and conditions. The reimbursement obligation is limited to a maximum aggregate reimbursement of $100 million. As of December 31, 2009, the Company has a $95 million liability recorded for the guarantee obligation.
The Company is guarantor for specific financial obligations of a trona mining affiliate. The investment in this entity is accounted for under the equity method. The Company has guaranteed a portion of amounts due under a term loan. The Company’s guarantee under the term loan expires in 2010, coinciding with the maturity of that agreement. The Company would be obligated to pay $15 million under the term loan if the affiliate defaulted on the obligation. No liability has been recorded for this guarantee as of December 31, 2009.
In connection with its various acquisitions, the Company routinely indemnifies the former officers and directors of acquired companies in respect to acts or omissions occurring prior to the effective date of the acquisition. The Company also agrees to maintain directors’ and officers’ liability insurance on these individuals with respect to acts or omissions occurring prior to the acquisition, generally for a period of six years. No liability has been recognized for these indemnifications.
The Company also provides certain indemnifications in relation to dispositions of assets. These indemnifications typically relate to disputes, litigation or tax matters existing at the date of disposition. In connection with the 2006 sale of its Canadian subsidiary, the Company indemnified the purchaser for potential future audit adjustments that may be imposed by the Canadian taxing authorities for tax years prior to the sale. During 2008, the purchaser notified Anadarko that $90 million of the indemnity is no longer relevant as a result of the effective settlement of the underlying contingent obligation. Accordingly, the Company reversed a portion of its recorded liability. At December 31, 2009, other long-term liabilities included a $49 million liability for this contingency. The Company believes it is probable that the remaining indemnification will be settled with the purchaser in cash.
Other The Company is subject to other legal proceedings, claims and liabilities which arise in the ordinary course of its business. In the opinion of Anadarko, the liability (if any) with respect to these claims will not have a material adverse effect on the Company’s consolidated financial position, results of operations or cash flows.
Anadarko is also subject to various environmental-remediation and reclamation obligations arising from federal, state and local laws and regulations. As of December 31, 2009, the Company’s balance sheet included a $96 million liability for remediation and reclamation obligations. The Company continually monitors the remediation and reclamation process and the liability recorded.
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ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2009, 2008 and 2007
15. Other Taxes
Taxes incurred, other than income taxes, are as follows:
| 2009 | 2008 | 2007 | |||||||
| Production and severance |
$ | 523 | $ | 1,135 | $ | 998 | |||
| Ad valorem |
189 | 221 | 178 | ||||||
| Other |
34 | 96 | 58 | ||||||
| Total |
$ | 746 | $ | 1,452 | $ | 1,234 | |||
In July 2006, the Algerian parliament approved legislation establishing an exceptional profits tax on foreign companies’ Algerian oil production. In December 2006, implementing regulations regarding this legislation were issued. These regulations provide for an exceptional profits tax imposed on gross production at rates of taxation ranging from 5% to 50% based on average daily production volumes for each calendar month in which the price of Brent crude averages over $30 per barrel, retroactively effective to August-2006 production. Uncertainty existed at that time as to whether the exceptional profits tax would apply to the full value of production or only to the value of production in excess of $30 per barrel. In 2006, Anadarko recorded a $103 million accrual for the tax, assuming the tax would be applied only to the amounts in excess of $30 per barrel.
In January 2007, Sonatrach, the national oil and gas company of Algeria, advised Anadarko that it would begin collecting the exceptional profits tax from Anadarko’s share of production commencing with March 2007 liftings, including for the prior months since the new tax went into effect. In April 2007, ALNAFT, an agency under the control of the Algerian Ministry of Energy and Mines responsible for overseeing the Algerian hydrocarbons industry, issued the Application Procedure further defining the procedure and conditions under which the exceptional profits tax is applied and the methodology for its calculation. The Application Procedure and other information supplied by Sonatrach revealed that the exceptional profits tax applied to the full value of production rather than to the amounts in excess of $30 per barrel. This was evidenced by changes in the Company’s crude-oil lifting schedule, which was conveyed to Anadarko by Sonatrach. As a result, Anadarko changed the measurement basis for the exceptional profits tax liability in the first quarter of 2007 to reflect the application of the tax rate to the full value of production. On that measurement basis, the Company recognized production tax expense of $379 million, $648 million and $705 million for 2009, 2008 and 2007, respectively. Of the 2007 amount, $87 million, or $0.19 per diluted share, was related to 2006 sales and income from continuing operations.
In response to the Algerian government’s imposition of the exceptional profits tax, the Company has notified Sonatrach of its disagreement with the collection of the exceptional profits tax, based on the Company’s interpretation of the Production Sharing Agreement (PSA), which provides for fiscal stability through several provisions that require Sonatrach to pay all taxes and royalties. To facilitate discussions between the parties in an effort to resolve the dispute, on October 31, 2007, the Company initiated a conciliation proceeding on the exceptional profits tax as provided in the PSA. Any recommendation issued by a conciliation board (Conciliation Board) arising out of the conciliation proceeding is non-binding on the parties. The Conciliation Board issued its non-binding recommendation on November 26, 2008, which the Company received on December 1, 2008. On February 15, 2009, the Company initiated arbitration against Sonatrach with regard to the exceptional profits tax. In conformance with the terms of the PSA, a notice of arbitration was submitted to Sonatrach.
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ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2009, 2008 and 2007
16. Income Taxes
Components of income tax expense (benefit) are as follows:
| millions | 2009 | 2008 | 2007 | |||||||||
| Current |
||||||||||||
| Federal |
$ | (233 | ) | $ | 1,111 | $ | 2,764 | |||||
| State |
(13 | ) | 40 | 189 | ||||||||
| Foreign |
409 | 1,031 | 658 | |||||||||
| Total |
163 | 2,182 | 3,611 | |||||||||
| Deferred |
||||||||||||
| Federal |
(25 | ) | 89 | (989 | ) | |||||||
| State |
(91 | ) | (7 | ) | (40 | ) | ||||||
| Foreign |
(52 | ) | (116 | ) | (23 | ) | ||||||
| Total |
(168 | ) | (34 | ) | (1,052 | ) | ||||||
| Total income tax expense (benefit) |
$ | (5 | ) | $ | 2,148 | $ | 2,559 | |||||
Total income taxes differed from the amounts computed by applying the statutory income tax rate to income (loss) from continuing operations before income taxes. The sources of these differences are as follows:
| millions except percentages | 2009 | 2008 | 2007 | |||||||||
| Income (loss) from continuing operations before income taxes |
||||||||||||
| Domestic |
$ | (660 | ) | $ | 3,297 | $ | 5,446 | |||||
| Foreign |
552 | 2,071 | 880 | |||||||||
| Total |
$ | (108 | ) | $ | 5,368 | $ | 6,326 | |||||
| Statutory tax rate |
35 | % | 35 | % | 35 | % | ||||||
| Tax computed at statutory rate |
$ | (38 | ) | $ | 1,879 | $ | 2,215 | |||||
| Adjustments resulting from: |
||||||||||||
| State income taxes (net of federal income tax benefit) |
(68 | ) | 23 | 111 | ||||||||
| Texas margin tax law change (net of federal income tax benefit) |
— | — | (14 | ) | ||||||||
| Foreign taxes greater than (less than) federal statutory tax rate |
46 | (56 | ) | 59 | ||||||||
| Non-deductible Algerian exceptional profits tax(1) |
144 | 246 | 268 | |||||||||
| U.S. tax on foreign income inclusions and distributions |
119 | 120 | 142 | |||||||||
| Excess U.S. foreign tax credit generated |
(8 | ) | — | (102 | ) | |||||||
| U.S. tax impact from losses and restructuring of foreign operations |
(94 | ) | (36 | ) | (36 | ) | ||||||
| Net changes in tax contingencies |
(110 | ) | 45 | 2 | ||||||||
| Federal manufacturing deduction |
19 | (71 | ) | (66 | ) | |||||||
| Other—net |
(15 | ) | (2 | ) | (20 | ) | ||||||
| Total income tax expense (benefit) |
$ | (5 | ) | $ | 2,148 | $ | 2,559 | |||||
| Effective tax rate |
5 | % | 40 | % | 40 | % | ||||||
| (1) | Exceptional profits tax is not deductible for Algerian income tax purposes. |
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ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2009, 2008 and 2007
16. Income Taxes (Continued)
Certain tax effects have been recorded directly to the balance sheet at December 31, 2009 and 2008. Tax effects related to internal restructuring of certain foreign operations in prior years have been recorded to other long-term liabilities and are being recognized in the income statement over the estimated life of the related properties. During 2008 and 2007, liabilities of $47 million and $184 million, respectively, were recorded to other long-term liabilities. During 2009, $51 million of the liabilities recorded in prior years were reversed to income. As of December 31, 2009, the balance in other long-term liabilities related to the restructuring of certain foreign operations was $93 million. This balance will be recognized into tax expense in future periods.
Additionally, the Company recorded increases in tax liabilities of approximately $310 million and $16 million for 2008 and 2007, respectively, related to certain acquired subsidiaries for years prior to their acquisition by the Company. The increased tax liabilities were due to completion of audits and administrative appeals, filing amended returns, re-evaluation of contingencies, re-establishment of deferred income tax liabilities related to prior acquisitions and changes to the tax basis of acquired assets and liabilities. Accordingly, these liabilities were recorded with an offsetting increase in goodwill.
The tax effects of temporary differences that give rise to significant portions of the deferred tax assets (liabilities) at December 31, 2009 and 2008 are as follows:
| millions | 2009 | 2008 | ||||||
| Net current deferred tax assets |
$ | 134 | $ | 34 | ||||
| Net long-term deferred tax assets |
13 | 2 | ||||||
| Oil and gas exploration and development operations |
(8,599 | ) | (9,121 | ) | ||||
| Mineral operations |
(411 | ) | (418 | ) | ||||
| Midstream and other depreciable properties |
(1,286 | ) | (862 | ) | ||||
| Other |
(853 | ) | (718 | ) | ||||
| Gross long-term deferred tax liabilities |
(11,149 | ) | (11,119 | ) | ||||
| Oil and gas exploration and development costs |
79 | 215 | ||||||
| Net operating loss carryforward |
416 | 322 | ||||||
| Foreign tax credit carryforward |
76 | 59 | ||||||
| Other |
1,071 | 1,058 | ||||||
| Gross long-term deferred tax assets |
1,642 | 1,654 | ||||||
| Less: valuation allowance on deferred tax assets not expected to be realized |
(418 | ) | (509 | ) | ||||
| Net long-term deferred tax assets |
1,224 | 1,145 | ||||||
| Net long-term deferred tax liabilities |
(9,925 | ) | (9,974 | ) | ||||
| Total deferred taxes |
$ | (9,778 | ) | $ | (9,938 | ) | ||
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ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2009, 2008 and 2007
16. Income Taxes (Continued)
Changes to the valuation allowance, due to a change in judgment about the realizability of the related deferred assets in future years, were $10 million for 2009.
| millions | December 31, 2009 |
December 31, 2008 |
||||||
| Federal |
$ | (9,347 | ) | $ | (9,391 | ) | ||
| State, net of federal |
(296 | ) | (358 | ) | ||||
| Foreign |
(135 | ) | (189 | ) | ||||
| Total deferred tax asset (liability) |
$ | (9,778 | ) | $ | (9,938 | ) | ||
Current taxes receivable (payable) are as follows:
| millions |
Balance Sheet Classification |
December 31, 2009 |
December 31, 2008 |
|||||||
| Income taxes receivable |
Accounts receivable—other | $ | 115 | $ | 96 | |||||
| Other assets | 57 | — | ||||||||
| Total income taxes receivable |
172 | 96 | ||||||||
| Income taxes payable |
Accrued expense | (20 | ) | (356 | ) | |||||
| Total income taxes receivable/(payable) |
$ | 152 | $ | (260 | ) | |||||
Tax carryforwards at December 31, 2009, which are available for utilization on future income tax returns, are as follows:
| millions | Domestic | Foreign | Expiration | |||||
| Net operating loss — regular tax |
$ | — | $ | 274 | 2010-indef. | |||
| Net operating loss — state |
$ | 4,630 | $ | — | 2010-2029 | |||
| Foreign tax credits |
$ | 77 | $ | — | 2014-2019 | |||
| Texas margins tax credit |
$ | 39 | $ | — | 2027 | |||
Changes in the balance of unrecognized tax benefits excluding tax interest and penalties are as follows:
| millions | Assets (Liabilities) | |||
| Balance at January 1, 2009 |
$ | (132 | ) | |
| Increases related to prior-year tax positions |
(17 | ) | ||
| Decreases related to prior-year tax positions |
89 | |||
| Increases related to current-year tax positions |
(6 | ) | ||
| Decreases related to current-year tax positions |
8 | |||
| Settlements |
29 | |||
| Balance at December 31, 2009 |
$ | (29 | ) | |
Included in the balance of unrecognized tax benefits are potential benefits of $6 million that would affect the effective tax rate on income from continuing operations if recognized. Also included in the balance at December 31, 2009 are $23 million related to tax positions for which the ultimate deductibility is highly certain but the timing of such deductibility is uncertain. The Company estimates that $3 to $8 million of unrecognized tax benefits related to adjustments to taxable income, credits and associated interest previously recorded pursuant
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ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2009, 2008 and 2007
16. Income Taxes (Continued)
to the accounting standard for accounting for uncertainty in income taxes will reverse within the next 12 months due to the expiration of statutes of limitation and audit settlements.
The Company recognizes interest and penalties related to unrecognized tax benefits in income tax expense. As of December 31, 2009 and 2008, the Company had approximately $16 million and $28 million, respectively, of accrued interest related to uncertain tax positions. During 2009 and 2008, the Company recognized $(6) million and $8 million, respectively, in income tax expense (benefit) for interest and penalties.
The following is a list of tax years subject to examination by major tax jurisdiction:
| Tax Year | ||
| United States |
2006-2009 | |
| China |
2005-2008 | |
| Algeria |
2006-2008 |
17. Statements of Cash Flows Supplemental Information
In cash flow from operating activities for 2007, the changes reported as other items-net include increases in other long-term liabilities-other of $619 million related to operating activities.
The following table presents amounts of cash paid for interest (net of amounts capitalized) and income taxes, including amounts related to discontinued operations, and non-cash transactions.
| millions | 2009 | 2008 | 2007 | ||||||
| Cash paid: |
|||||||||
| Interest |
$ | 724 | $ | 762 | $ | 1,107 | |||
| Income taxes(1) |
$ | 194 | $ | 1,060 | $ | 2,241 | |||
| Non-cash investing activities: |
|||||||||
| Receipt of interest in oil and gas investee entity in exchange for interests in oil and gas properties (See Note 6) |
$ | — | $ | — | $ | 1,000 | |||
| Receipt of interest in gathering and processing investee entities in exchange |
$ | — | $ | — | $ | 1,848 | |||
| Fair value of properties and equipment received in non-cash exchange transactions |
$ | 280 | $ | 108 | $ | 88 | |||
| (1) | Includes $378 million and $2.3 billion in 2008 and 2007, respectively, related to taxable gains on divestitures. Also, 2008 includes $567 million of federal income tax refunds. |
18. Major Customers
The Company’s natural gas is sold to interstate and intrastate gas pipelines, direct end-users, industrial users, local distribution companies and gas marketers. Crude oil and condensate are sold to marketers, gatherers and refiners. NGLs are sold to direct end-users, refiners and marketers. These purchasers are located in the United States and China. The majority of the Company’s receivables are paid within two months following the month of purchase.
The Company conducts credit analyses of customers prior to making any sales to new customers or increasing credit for existing customers. Based upon these analyses, the Company may require a standby letter of credit or a financial guarantee. As of December 31, 2009 and 2008, accounts receivable are shown net of allowance for uncollectible accounts of $11 million and $24 million, respectively.
In 2009, 2008 and 2007, there were no sales to individual customers that exceeded 10% of the Company’s total sales revenues.
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ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2009, 2008 and 2007
19. Segment Information
Anadarko’s primary business segments are vertically integrated within the oil and gas industry. These segments are separately managed because of the nature of their products and services, as well as unique technology, distribution and marketing requirements. The Company’s three reportable operating segments are oil and gas exploration and production, midstream, and marketing. The exploration and production segment explores for and produces natural gas, crude oil, condensate and NGLs. The midstream segment engages in gathering, processing, treating and transporting Anadarko and third-party oil and gas production. The marketing segment sells most of Anadarko’s production, as well as production purchased from third parties.
To assess the operating results of Anadarko’s segments, the chief operating decision maker (CODM) analyzes income from continuing operations before income taxes, interest expense, exploration expense, DD&A and impairments less net income attributable to noncontrolling interests (Adjusted EBITDAX). Anadarko’s definition of Adjusted EBITDAX excludes exploration expense, as exploration expense is not an indicator of operating efficiency for a given reporting period, but is monitored by management as part of costs incurred in exploration and development activities. Similarly, DD&A expense and impairments are excluded from Adjusted EBITDAX as a measure of segment operating performance, because capital expenditures are evaluated at the time capital costs are incurred. The Company’s definition of Adjusted EBITDAX also excludes interest expense to allow for assessment of segment operating results without regard to Anadarko’s financing methods or capital structure. Management believes that the presentation of Adjusted EBITDAX provides information useful in assessing the Company’s financial condition and results of operations and that Adjusted EBITDAX is a widely accepted financial indicator of a company’s ability to incur and service debt, fund capital expenditures and make distributions to stockholders.
Adjusted EBITDAX may not be comparable to similarly titled measures used by other companies. Adjusted EBITDAX should be considered in conjunction with income (loss) from continuing operations attributable to common stockholders and other performance measures, such as operating income or cash flow from operating activities. Below is a reconciliation of consolidated Adjusted EBITDAX to income (loss) from continuing operations before income taxes.
| millions | 2009 | 2008 | 2007 | |||||||
| Income (loss) from continuing operations before income taxes |
$ | (108 | ) | $ | 5,368 | $ | 6,326 | |||
| Exploration expense |
1,107 | 1,369 | 905 | |||||||
| Depreciation, depletion and amortization |
3,532 | 3,194 | 2,840 | |||||||
| Impairments |
115 | 223 | 51 | |||||||
| Interest expense |
702 | 732 | 1,083 | |||||||
| Less: Net income attributable to noncontrolling interests |
32 | 23 | — | |||||||
| Consolidated Adjusted EBITDAX |
$ | 5,316 | $ | 10,863 | $ | 11,205 | ||||
The Company’s accounting policies for individual segments are the same as those described in the summary of significant accounting policies, with the following exception: certain intersegment commodity contracts may meet the Generally Accepted Accounting Principles (GAAP) definition of a derivative instrument, which would be accounted for at fair value under GAAP. However, Anadarko accounts for such intersegment arrangements as executory contracts. Additionally, intersegment asset transfers are accounted for at historical cost basis, and do not give rise to gain or loss recognition.
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ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2009, 2008 and 2007
19. Segment Information (Continued)
The following table presents selected financial information for Anadarko’s operating segments. Information presented below as “Other and Intersegment Eliminations” includes results from hard minerals non-operated joint ventures and royalty arrangements, operating activities that are not considered operating segments, as well as corporate, financing and certain hedging activities.
| millions | Oil and Gas Exploration & Production |
Midstream | Marketing | Other and Intersegment Eliminations |
Total | |||||||||||||
| 2009 |
||||||||||||||||||
| Sales revenues |
$ | 3,767 | $ | 222 | $ | 4,221 | $ | — | $ | 8,210 | ||||||||
| Intersegment revenues |
3,479 | 718 | (3,842 | ) | (355 | ) | — | |||||||||||
| Gains (losses) on divestitures and other, net |
43 | 1 | — | 89 | 133 | |||||||||||||
| Reversal of accrual for DWRRA dispute |
657 | — | — | — | 657 | |||||||||||||
| Total revenues and other |
7,946 | 941 | 379 | (266 | ) | 9,000 | ||||||||||||
| Operating costs and expenses(1) |
2,560 | 585 | 451 | 273 | 3,869 | |||||||||||||
| (Gains) losses on commodity derivatives, net |
— | — | — | 408 | 408 | |||||||||||||
| (Gains) losses on other derivatives, net |
— | — | — | (582 | ) | (582 | ) | |||||||||||
| Other (income) expense, net |
— | — | — | (43 | ) | (43 | ) | |||||||||||
| Net income attributable to noncontrolling interests |
— | 32 | — | — | 32 | |||||||||||||
| Total costs and expenses |
2,560 | 617 | 451 | 56 | 3,684 | |||||||||||||
| Adjusted EBITDAX |
$ | 5,386 | $ | 324 | $ | (72 | ) | $ | (322 | ) | $ | 5,316 | ||||||
| Net properties and equipment |
$ | 32,338 | $ | 3,091 | $ | 9 | $ | 1,766 | $ | 37,204 | ||||||||
| Capital expenditures |
$ | 4,001 | $ | 303 | $ | — | $ | 254 | $ | 4,558 | ||||||||
| Goodwill |
$ | 5,143 | $ | 139 | $ | — | $ | — | $ | 5,282 | ||||||||
| 2008 |
||||||||||||||||||
| Sales revenues |
$ | 5,760 | $ | 267 | $ | 8,052 | $ | — | $ | 14,079 | ||||||||
| Intersegment revenues |
6,933 | 1,088 | (7,532 | ) | (489 | ) | — | |||||||||||
| Gains (losses) on divestitures and other, net |
992 | 1 | — | 90 | 1,083 | |||||||||||||
| Total revenues and other |
13,685 | 1,356 | 520 | (399 | ) | 15,162 | ||||||||||||
| Operating costs and expenses(1) |
3,353 | 905 | 457 | 60 | 4,775 | |||||||||||||
| (Gains) losses on commodity derivatives, net |
— | — | — | (561 | ) | (561 | ) | |||||||||||
| (Gains) losses on other derivatives, net |
— | — | — | 10 | 10 | |||||||||||||
| Other (income) expense, net |
— | — | — | 52 | 52 | |||||||||||||
| Net income attributable to noncontrolling interests |
— | 23 | — | — | 23 | |||||||||||||
| Total costs and expenses |
3,353 | 928 | 457 | (439 | ) | 4,299 | ||||||||||||
| Adjusted EBITDAX |
$ | 10,332 | $ | 428 | $ | 63 | $ | 40 | $ | 10,863 | ||||||||
| Net properties and equipment |
$ | 32,436 | $ | 2,987 | $ | 27 | $ | 1,597 | $ | 37,047 | ||||||||
| Capital expenditures |
$ | 4,274 | $ | 513 | $ | — | $ | 94 | $ | 4,881 | ||||||||
| Goodwill |
$ | 5,143 | $ | 139 | $ | — | $ | — | $ | 5,282 | ||||||||
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2009, 2008 and 2007
19. Segment Information (Continued)
| millions | Oil and Gas Exploration & Production |
Midstream | Marketing | Other and Intersegment Eliminations |
Total | |||||||||||||
| 2007 |
||||||||||||||||||
| Sales revenues |
$ | 5,973 | $ | 202 | $ | 5,544 | $ | (63 | ) | $ | 11,656 | |||||||
| Intersegment revenues |
3,872 | 1,268 | (4,850 | ) | (290 | ) | — | |||||||||||
| Gains (losses) on divestitures and other, net |
4,129 | 532 | — | 99 | 4,760 | |||||||||||||
| Total revenues and other |
13,974 | 2,002 | 694 | (254 | ) | 16,416 | ||||||||||||
| Operating costs and expenses(1) |
2,854 | 1,108 | 419 | 368 | 4,749 | |||||||||||||
| (Gains) losses on commodity derivatives, net |
— | — | — | 524 | 524 | |||||||||||||
| (Gains) losses on other derivatives, net |
— | — | — | 9 | 9 | |||||||||||||
| Other (income) expense, net |
— | — | — | (71 | ) | (71 | ) | |||||||||||
| Total costs and expenses |
2,854 | 1,108 | 419 | 830 | 5,211 | |||||||||||||
| Adjusted EBITDAX |
$ | 11,120 | $ | 894 | $ | 275 | $ | (1,084 | ) | $ | 11,205 | |||||||
| Net properties and equipment |
$ | 33,150 | $ | 2,694 | $ | 28 | $ | 1,579 | $ | 37,451 | ||||||||
| Capital expenditures |
$ | 3,215 | $ | 665 | $ | 22 | $ | 88 | $ | 3,990 | ||||||||
| Goodwill |
$ | 4,847 | $ | 108 | $ | — | $ | — | $ | 4,955 | ||||||||
| (1) | Operating costs and expenses exclude exploration, DD&A and impairment expenses since they are excluded from Adjusted EBITDAX. |
The following table shows Anadarko’s sales revenues and other (based on the origin of the sales) and net properties and equipment by geographic area:
| millions | 2009 | 2008 | 2007 | ||||||
| Sales Revenues |
|||||||||
| United States |
$ | 6,773 | $ | 11,503 | $ | 9,446 | |||
| Algeria |
1,133 | 2,082 | 1,780 | ||||||
| Other International |
304 | 494 | 430 | ||||||
| Total |
$ | 8,210 | $ | 14,079 | $ | 11,656 | |||
| millions | 2009 | 2008 | ||||
| Net Properties and Equipment |
||||||
| United States |
$ | 34,385 | $ | 35,014 | ||
| Algeria |
813 | 610 | ||||
| Other International |
2,006 | 1,423 | ||||
| Total |
$ | 37,204 | $ | 37,047 | ||
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ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2009, 2008 and 2007
20. Pension Plans, Other Postretirement Benefits and Employee Savings Plans
Pension Plans and Other Postretirement Benefits The Company has non-contributory defined-benefit pension plans, including both qualified and supplemental plans, and a foreign contributory defined-benefit pension plan. The Company also provides certain health care and life insurance benefits for retired employees. Retiree health care benefits are funded by contributions from the Company and the retiree. The Company’s retiree life insurance plan is noncontributory.
In 2009, the Company made contributions of $144 million to its funded pension plans, $19 million to its unfunded pension plans and $16 million to its unfunded other postretirement benefit plans. Although reported benefit obligations exceed the fair value of pension and other postretirement plan assets at December 31, 2009, the Company monitors the funded status of its funded pension and other postretirement benefit plans to ensure that plan funds are sufficient to continue paying benefits. Contributions to the funded plans increase the plan assets while contributions to unfunded plans are used for current benefit payments. The Company expects to contribute up to $114 million to its funded pension plans in 2010. In addition, the Company expects to contribute $19 million to its unfunded pension plans and $19 million to its unfunded other postretirement benefit plans in 2010.
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ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2009, 2008 and 2007
20. Pension Plans, Other Postretirement Benefits and Employee Savings Plans (Continued)
The following table sets forth changes in the benefit obligations and fair value of plan assets for the Company’s pension and other postretirement benefit plans for the years ended December 31, 2009 and 2008, as well as the funded status of the plans and amounts recognized in the financial statements as of December 31, 2009 and 2008.
| Pension Benefits | Other Benefits | |||||||||||||||
| millions | 2009 | 2008 | 2009 | 2008 | ||||||||||||
| Change in benefit obligations |
||||||||||||||||
| Benefit obligations at beginning of year |
$ | 1,280 | $ | 1,321 | $ | 319 | $ | 327 | ||||||||
| Service cost |
54 | 56 | 9 | 14 | ||||||||||||
| Interest cost |
79 | 78 | 17 | 20 | ||||||||||||
| Plan amendments |
— | 7 | 3 | — | ||||||||||||
| Actuarial (gain) loss |
313 | (23 | ) | (16 | ) | (23 | ) | |||||||||
| Contributions by plan participants |
1 | 1 | 4 | 5 | ||||||||||||
| Settlements |
(17 | ) | — | — | — | |||||||||||
| Benefit payments |
(87 | ) | (140 | ) | (20 | ) | (24 | ) | ||||||||
| Foreign currency exchange rate changes |
7 | (20 | ) | — | — | |||||||||||
| Benefit obligations at end of year |
$ | 1,630 | $ | 1,280 | $ | 316 | $ | 319 | ||||||||
| Change in plan assets |
||||||||||||||||
| Fair value of plan assets at beginning of year |
$ | 748 | $ | 1,088 | $ | — | $ | — | ||||||||
| Actual return on plan assets |
165 | (260 | ) | — | — | |||||||||||
| Employer contributions |
163 | 76 | 16 | 19 | ||||||||||||
| Contributions by plan participants |
1 | 1 | 4 | 5 | ||||||||||||
| Settlements |
(17 | ) | — | — | — | |||||||||||
| Benefit payments |
(87 | ) | (140 | ) | (20 | ) | (24 | ) | ||||||||
| Foreign currency exchange rate changes |
6 | (17 | ) | — | — | |||||||||||
| Fair value of plan assets at end of year |
$ | 979 | $ | 748 | $ | — | $ | — | ||||||||
| Funded status of the plans at end of year |
$ | (651 | ) | $ | (532 | ) | $ | (316 | ) | $ | (319 | ) | ||||
| Total recognized amounts in the balance sheet consist of: |
||||||||||||||||
| Other assets |
$ | 2 | $ | — | $ | — | $ | — | ||||||||
| Accrued expenses |
(123 | ) | (8 | ) | (18 | ) | (22 | ) | ||||||||
| Other long-term liabilities — other |
(530 | ) | (524 | ) | (298 | ) | (297 | ) | ||||||||
| Total |
$ | (651 | ) | $ | (532 | ) | $ | (316 | ) | $ | (319 | ) | ||||
| Total recognized amounts in accumulated other comprehensive income consist of: |
||||||||||||||||
| Prior service cost |
$ | 8 | $ | 9 | $ | 3 | $ | 2 | ||||||||
| Net actuarial (gain) loss |
670 | 509 | (28 | ) | (14 | ) | ||||||||||
| Total |
$ | 678 | $ | 518 | $ | (25 | ) | $ | (12 | ) | ||||||
The accumulated benefit obligation for all defined-benefit pension plans was $1.5 billion and $1.2 billion as of December 31, 2009 and 2008, respectively. For the Company’s defined-benefit pension plans with accumulated benefit obligations in excess of plan assets, the projected benefit obligation, accumulated benefit obligation and fair value of plan assets were $1.6 billion, $1.4 billion and $897 million, respectively, as of December 31, 2009, and $1.2 billion, $1.1 billion and $699 million, respectively, as of December 31, 2008.
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ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2009, 2008 and 2007
20. Pension Plans, Other Postretirement Benefits and Employee Savings Plans (Continued)
The following table sets forth the Company’s pension and other postretirement benefit cost and amounts recognized in other comprehensive income (before tax benefit).
| Pension Benefits | Other Benefits | ||||||||||||||||||||||
| millions | 2009 | 2008 | 2007 | 2009 | 2008 | 2007 | |||||||||||||||||
| Components of net periodic benefit cost |
|||||||||||||||||||||||
| Service cost |
$ | 54 | $ | 56 | $ | 58 | $ | 9 | $ | 14 | $ | 15 | |||||||||||
| Interest cost |
79 | 78 | 80 | 17 | 20 | 20 | |||||||||||||||||
| Expected return on plan assets |
(71 | ) | (80 | ) | (82 | ) | — | — | — | ||||||||||||||
| Settlements |
11 | — | 4 | — | — | — | |||||||||||||||||
| Curtailments |
— | — | (4 | ) | — | — | 2 | ||||||||||||||||
| Termination benefits |
— | — | 31 | — | — | 5 | |||||||||||||||||
| Amortization of prior service (credit) cost |
1 | 1 | 1 | (1 | ) | (1 | ) | — | |||||||||||||||
| Amortization of actuarial (gain) loss |
49 | 10 | 15 | (2 | ) | — | 1 | ||||||||||||||||
| Net periodic benefit cost |
$ | 123 | $ | 65 | $ | 103 | $ | 23 | $ | 33 | $ | 43 | |||||||||||
| Amounts recognized in other comprehensive income (expense) |
|||||||||||||||||||||||
| Net actuarial gain (loss) |
$ | (221 | ) | $ | (312 | ) | $ | 31 | $ | 16 | $ | 22 | $ | 34 | |||||||||
| Amortization of net actuarial (gain) loss |
49 | 10 | 17 | (2 | ) | — | 1 | ||||||||||||||||
| Settlements |
11 | — | — | — | — | — | |||||||||||||||||
| Prior service credit (cost) |
— | (6 | ) | — | — | — | 6 | ||||||||||||||||
| Amortization of prior service (credit) cost |
1 | 1 | — | (1 | ) | (1 | ) | — | |||||||||||||||
| Total amounts recognized in other comprehensive income (expense) |
$ | (160 | ) | $ | (307 | ) | $ | 48 | $ | 13 | $ | 21 | $ | 41 | |||||||||
The estimated portion of net actuarial loss and prior service cost for the pension plans that will be amortized from accumulated other comprehensive income into net periodic benefit cost in 2010, is $54 million, of which $52 million represents amortization of net actuarial losses and $2 million represents amortization of net prior service cost.
Following are the weighted-average assumptions used by the Company in determining the pension and other postretirement benefit obligations as of December 31, 2009 and 2008:
| Pension Benefits | Other Benefits | |||||||||||
| percent | 2009 | 2008 | 2009 | 2008 | ||||||||
| Discount rate |
5.25 | % | 6.00 | % | 5.50 | % | 6.00 | % | ||||
| Rates of increase in compensation levels |
5.00 | % | 5.00 | % | n/a | n/a | ||||||
The discount-rate assumption used by the Company is meant to reflect the interest rate at which the pension and other postretirement obligations could effectively be settled on the measurement date. The Company currently uses a yield curve analysis to support the discount-rate assumption for the plans. This analysis involves the creation of a hypothetical Aa spot yield curve represented by a series of high-quality, non-callable, marketable bonds, then discounts the projected cash flows from each plan at interest rates on the created curve specifically applicable to the timing of each respective cash flow. The present values of the cash flows are then accumulated, and a weighted-average discount rate is calculated by imputing the single discount rate that equates
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ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2009, 2008 and 2007
20. Pension Plans, Other Postretirement Benefits and Employee Savings Plans (Continued)
to the total present value of the cash flows. The consolidated discount-rate assumption is determined by evaluating the weighted-average discount rates determined for each of the Company’s significant pension and postretirement plans.
Following are the weighted-average assumptions used by the Company in determining the net periodic pension and other postretirement benefit cost for 2009, 2008 and 2007:
| Pension Benefits | Other Benefits | |||||||||||||||||
| percent | 2009 | 2008 | 2007 | 2009 | 2008 | 2007 | ||||||||||||
| Discount rate |
6.00 | % | 6.00 | % | 5.75 | % | 6.00 | % | 6.00 | % | 5.75 | % | ||||||
| Long-term rate of return on plan assets |
7.50 | % | 7.75 | % | 7.75 | % | n/a | n/a | n/a | |||||||||
| Rates of increase in compensation levels |
5.00 | % | 5.00 | % | 5.00 | % | n/a | n/a | 5.00 | % | ||||||||
Plan Assets
Investment Policies and Strategies The Company has adopted a balanced, diversified investment strategy, with the intent of maximizing returns without exposure to undue risk. Investments are typically made through investment managers across several investment categories (Domestic Large and Small Cap, International, Domestic Fixed Income, Real Estate, Hedge Funds and Private Equity), with selective exposure to Growth/Value investment styles. Performance for each investment is measured relative to the appropriate index benchmark for its category. Target asset-allocation percentages by major category are 45%-55% equity securities, 20%-30% fixed income and up to 25% in a combination of other investments such as real estate, hedge funds and private equity. Investment managers have full discretion as to investment decisions regarding all funds under their management to the extent permitted within investment guidelines.
There are no direct investments in Anadarko securities included in plan assets; however, there may be indirect investments in Anadarko securities through the plans’ mutual fund investments. The expected long-term rate of return on plan assets assumption was determined starting with the year-end 2009 pension investment balances by category and projected target asset allocations for 2010. The expected return for each of these categories was determined by using capital-market projections. Anadarko’s expected long-term rate of return for U.S. defined-benefit pension plan assets is a blended average of the projected long-term returns for the various asset classes, weighted by the asset allocation. Returns on asset classes are developed using a forward-looking building-block approach and are not strictly based upon historical returns. Equity returns are generally developed as the sum of inflation, expected real earnings growth and expected long-term dividend yield. Bond returns are generally developed as the sum of inflation, real bond yield and risk spread (as appropriate), adjusted for the expected effect on returns from changing yields. Other asset class returns are derived from their relationship to the equity and bond markets. Consideration was also given to current market conditions.
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ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2009, 2008 and 2007
20. Pension Plans, Other Postretirement Benefits and Employee Savings Plans (Continued)
The fair value of the Company’s pension plan assets as of December 31, 2009 by asset category and level within the fair-value hierarchy are as follows:
| millions except percentages | Level 1 | Level 2 | Level 3 | Total | Percentage of Total |
||||||||||
| Fixed Income |
$ | 90 | $ | 244 | $ | — | $ | 334 | 34 | % | |||||
| Equity Securities: |
|||||||||||||||
| International |
81 | 174 | — | 255 | 26 | ||||||||||
| Large Cap |
215 | 29 | — | 244 | 25 | ||||||||||
| Small Cap |
36 | 21 | — | 57 | 6 | ||||||||||
| Other: |
|||||||||||||||
| Real Estate |
24 | — | — | 24 | 2 | ||||||||||
| Hedge Funds |
27 | — | 9 | 36 | 4 | ||||||||||
| Private Equity |
— | — | 29 | 29 | 3 | ||||||||||
| Total |
$ | 473 | $ | 468 | $ | 38 | $ | 979 | 100 | % | |||||
Investments in securities traded in active markets are measured based on quoted prices and are included as Level 1 measurements in the table above. Investments presented as Level 2 measurements include investments in funds where fair value is estimated using the net asset value, which is based on the fair value of the underlying assets that are traded in active markets and have quoted market prices. Fair value of investments included as Level 3 measurements are estimates based on the net asset values, but the underlying assets are not traded in active markets.
The following table sets forth a summary of changes in the fair value of the Level 3 assets for the year ended December 31, 2009.
| millions | 2009 | |||
| Balance at January 1 |
$ | 25 | ||
| Actual return on plan assets: |
||||
| Relating to assets still held at the reporting date |
17 | |||
| Relating to assets sold during the reporting period |
(1 | ) | ||
| Purchases, sales and settlements |
(3 | ) | ||
| Balance at December 31 |
$ | 38 | ||
Risks and Uncertainties The plan assets include various investment securities. Investment securities are exposed to various risks, such as interest-rate, credit and market risks. Due to the level of risk associated with certain investment securities, it is reasonably possible that changes in the values of investment securities could significantly impact the plan assets.
The plan assets may include securities with contractual cash flows, such as asset-backed securities, collateralized mortgage obligations and commercial mortgage-backed securities, including securities backed by subprime mortgage loans. The value, liquidity and related income of those securities are sensitive to changes in economic conditions, including real estate value, delinquencies or defaults, or both, and may be adversely affected by shifts in the market’s perception of the issuers and changes in interest rates.
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ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2009, 2008 and 2007
20. Pension Plans, Other Postretirement Benefits and Employee Savings Plans (Continued)
Benefit payments, which reflect expected future service as appropriate, are expected to be paid as follows:
| millions | Pension Benefit Payments |
Other Benefit Payments | ||||
| 2010 |
$ | 163 | $ | 19 | ||
| 2011 |
171 | 20 | ||||
| 2012 |
173 | 21 | ||||
| 2013 |
170 | 22 | ||||
| 2014 |
170 | 23 | ||||
| 2015-2019 |
778 | 124 | ||||
For December 31, 2008 and 2009 balances, a 9% annual rate of increase in the per-capita cost of covered health care benefits was assumed for 2009 and 2010, respectively, decreasing gradually to 5% in 2017 and 2018, respectively, and later years. The assumed health care cost trend rate has a significant effect on the cost and obligation amounts reported for the health care plan. A 1% change in the assumed health care cost trend rate over the projected period would have the following effects:
| millions | 1% Increase | 1% Decrease | |||||
| Effect on total of service and interest cost components |
$ | 2 | $ | (1 | ) | ||
| Effect on other postretirement benefit obligation |
$ | 18 | $ | (15 | ) | ||
Employee Savings Plan The Company has employee savings plans (ESP) which are defined-contribution plans. The Company matches a portion of employees’ contributions. Participation in the ESP is voluntary and all regular employees of the Company are eligible to participate. The Company charged to expense plan contributions of $34 million, $43 million and $25 million for 2009, 2008 and 2007, respectively.
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ANADARKO PETROLEUM CORPORATION
SUPPLEMENTAL QUARTERLY INFORMATION
(Unaudited)
Quarterly Financial Data
The following table shows summary quarterly financial data for 2009 and 2008. The Company changed the manner in which gains and losses on commodity derivatives used to economically hedge production are presented within the Consolidated Statements of Income. Previously, all realized and unrealized gains and losses on commodity derivatives were reported in sales revenues. For all periods presented, realized and unrealized gains and losses on commodity derivatives are included within income (loss) from continuing operations.
| First Quarter |
Second Quarter |
Third Quarter |
Fourth Quarter | |||||||||||
| millions except share amounts |
||||||||||||||
| 2009 |
||||||||||||||
| Sales revenues |
$ | 1,751 | $ | 1,894 | $ | 2,167 | $ | 2,398 | ||||||
| Gains (losses) on divestitures and other, net |
$ | 45 | $ | 19 | $ | 50 | $ | 19 | ||||||
| Reversal of accrual for DWRRA dispute |
$ | — | $ | — | $ | 657 | $ | — | ||||||
| Operating income (loss) |
$ | (271 | ) | $ | (322 | ) | $ | 779 | $ | 191 | ||||
| Income (loss) from continuing operations |
$ | (331 | ) | $ | (216 | ) | $ | 206 | $ | 238 | ||||
| Income from discontinued operations, net of taxes |
$ | — | $ | — | $ | — | $ | — | ||||||
| Net income (loss) |
$ | (331 | ) | $ | (216 | ) | $ | 206 | $ | 238 | ||||
| Net income attributable to noncontrolling interests |
$ | 7 | $ | 10 | $ | 6 | $ | 9 | ||||||
| Net income (loss) attributable to common stockholders |
$ | (338 | ) | $ | (226 | ) | $ | 200 | $ | 229 | ||||
| Amounts attributable to common stockholders: |
||||||||||||||
| Income (loss) from continuing operations attributable to common stockholders |
$ | (338 | ) | $ | (226 | ) | $ | 200 | $ | 229 | ||||
| Income from discontinued operations, net of taxes |
$ | — | $ | — | $ | — | $ | — | ||||||
| Net income (loss) attributable to common stockholders |
$ | (338 | ) | $ | (226 | ) | $ | 200 | $ | 229 | ||||
| Earnings per share: |
||||||||||||||
| Income (loss) from continuing operations attributable to common stockholders — basic |
$ | (0.73 | ) | $ | (0.48 | ) | $ | 0.40 | $ | 0.46 | ||||
| Income (loss) from continuing operations attributable to common stockholders — diluted |
$ | (0.73 | ) | $ | (0.48 | ) | $ | 0.40 | $ | 0.46 | ||||
| Income from discontinued operations, net of taxes — basic |
$ | — | $ | — | $ | — | $ | — | ||||||
| Income from discontinued operations, net of taxes — diluted |
$ | — | $ | — | $ | — | $ | — | ||||||
| Net income (loss) attributable to common stockholders — basic |
$ | (0.73 | ) | $ | (0.48 | ) | $ | 0.40 | $ | 0.46 | ||||
| Net income (loss) attributable to common stockholders — diluted |
$ | (0.73 | ) | $ | (0.48 | ) | $ | 0.40 | $ | 0.46 | ||||
| Average number common shares outstanding — basic |
460 | 477 | 491 | 492 | ||||||||||
| Average number common shares outstanding — diluted |
460 | 477 | 493 | 494 | ||||||||||
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ANADARKO PETROLEUM CORPORATION
SUPPLEMENTAL QUARTERLY INFORMATION
(Unaudited)
Quarterly Financial Data (Continued)
| First Quarter |
Second Quarter |
Third Quarter |
Fourth Quarter | |||||||||||
| millions except share amounts |
||||||||||||||
| 2008 |
||||||||||||||
| Sales revenues |
$ | 3,557 | $ | 4,379 | $ | 4,029 | $ | 2,114 | ||||||
| Gains (losses) on divestitures and other, net (1) |
$ | (40 | ) | $ | 370 | $ | (60 | ) | $ | 813 | ||||
| Operating income |
$ | 1,334 | $ | 2,357 | $ | 1,377 | $ | 533 | ||||||
| Income from continuing operations |
$ | 236 | $ | 21 | $ | 2,174 | $ | 789 | ||||||
| Income from discontinued operations, net of taxes |
$ | 50 | $ | 7 | $ | 1 | $ | 5 | ||||||
| Net income |
$ | 286 | $ | 28 | $ | 2,175 | $ | 794 | ||||||
| Net income attributable to noncontrolling interests |
$ | — | $ | 5 | $ | 10 | $ | 8 | ||||||
| Net income attributable to common stockholders |
$ | 286 | $ | 23 | $ | 2,165 | $ | 786 | ||||||
| Amounts attributable to common stockholders: |
||||||||||||||
| Income from continuing operations attributable to common stockholders |
$ | 236 | $ | 16 | $ | 2,164 | $ | 781 | ||||||
| Income from discontinued operations, net of taxes |
$ | 50 | $ | 7 | $ | 1 | $ | 5 | ||||||
| Net income attributable to common stockholders |
$ | 286 | $ | 23 | $ | 2,165 | $ | 786 | ||||||
| Earnings per share: |
||||||||||||||
| Income from continuing operations attributable to common stockholders — basic |
$ | 0.50 | $ | 0.03 | $ | 4.59 | $ | 1.68 | ||||||
| Income from continuing operations attributable to common stockholders — diluted |
$ | 0.50 | $ | 0.03 | $ | 4.58 | $ | 1.68 | ||||||
| Income from discontinued operations, net of taxes — basic |
$ | 0.11 | $ | 0.02 | $ | — | $ | 0.01 | ||||||
| Income from discontinued operations, net of taxes — diluted |
$ | 0.11 | $ | 0.02 | $ | — | $ | 0.01 | ||||||
| Net income attributable to common stockholders — basic |
$ | 0.61 | $ | 0.05 | $ | 4.59 | $ | 1.69 | ||||||
| Net income attributable to common stockholders — diluted |
$ | 0.60 | $ | 0.05 | $ | 4.58 | $ | 1.69 | ||||||
| Average number common shares outstanding — basic |
468 | 468 | 466 | 459 | ||||||||||
| Average number common shares outstanding — diluted |
469 | 469 | 467 | 460 | ||||||||||
| (1) | In March 2008, gains (losses) on divestitures and other, net included a net $82 million reduction related to corrections resulting from analysis of property records after the adoption of the successful efforts method of accounting. This net amount included reductions of $75 million and $88 million related to the first and second quarters of 2007, respectively. Management concluded that this misstatement was not material relative to 2007 interim and annual results, or to the 2008 periods, and corrected the error in the first quarter of 2008. After considering the effect of income taxes, the adjustments recorded in the first quarter of 2008 related to the adoption of the successful efforts method of accounting in the third quarter of 2007, reduced net earnings for the year ended December 31, 2008 by $52 million. |
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ANADARKO PETROLEUM CORPORATION
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION
AND PRODUCTION ACTIVITIES
(Unaudited)
In December 2009, Anadarko adopted revised oil and gas reserve estimation and disclosure requirements. The primary impact of the new disclosures is to conform the definition of proved reserves with the SEC Modernization of Oil and Gas Reporting rules, which were issued by the SEC at the end of 2008. The accounting standards update revised the definition of proved oil and gas reserves to require that the average, first-day-of-the-month price during the 12-month period before the end of the year rather than the year-end price, must be used when estimating whether reserve quantities are economical to produce. This same 12-month average price is also used in calculating the aggregate amount of (and changes in) future cash inflows related to the standardized measure of discounted future net cash flows. The rules also allow for the use of reliable technology to estimate proved oil and gas reserves if those technologies have been demonstrated to result in reliable conclusions about reserve volumes. The unaudited supplemental information on oil and gas exploration and production activities for 2009 has been presented in accordance with the new reserve estimation and disclosure rules, which may not be applied retrospectively. The 2006, 2007 and 2008 data are presented in accordance with FASB oil and gas disclosure requirements effective during those periods. However, historical information has been reclassified to conform to the geographic areas required to be disclosed for 2009 under the revised accounting standard. Disclosures by geographic area include the United States and International geographic areas, which are located primarily in Algeria, China and Ghana. The effect of applying the new definition of reliable technology and other non-price related aspects of the updated rules did not significantly impact 2009 net proved reserve volumes. Less than 1% of the Company’s total proved reserves, as of year-end 2009, were added as a result of pressure-gradient analyses, well-control and seismic reliable technologies. The effect of applying the 12-month average price, versus the 2009 year-end price, decreased the net remaining reserve volumes by less than 3% of total proved reserves. The standardized measure of discounted future net cash flows for 2009 decreased by $8.3 billion as a result of using the 12-month average price rather than the year-end 2009 price.
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ANADARKO PETROLEUM CORPORATION
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION
AND PRODUCTION ACTIVITIES
(Unaudited)
Oil and Gas Reserves
The reserve disclosures that follow reflect estimates of proved reserves, proved developed reserves and proved undeveloped reserves, net of royalty interests, of natural gas, crude oil, condensate and NGLs owned at year end and changes in proved reserves during the last three years. Natural-gas volumes are in billions of cubic feet (Bcf) at a pressure base of 14.73 pounds per square inch and volumes for oil, condensate and NGLs are in millions of barrels (MMBbls). Total volumes are in millions of barrels of oil equivalent (MMBOE). For this computation, one barrel is assumed to be the equivalent of 6,000 cubic feet of gas. NGLs are included with oil and condensate reserves and associated shrinkage has been deducted from the gas reserves.
International reserves are calculated in accordance with the terms of their respective agreements using the economic interest method. The international reserves include estimated quantities allocated to Anadarko for recovery of costs and income taxes and Anadarko’s net equity share after recovery of such costs.
The estimates of proved reserves are made using available geological and reservoir data as well as production performance data. These estimates are reviewed annually and revised, either upward or downward, as warranted by additional data. Revisions are necessary due to changes in, among other things, reservoir performance, prices, economic conditions and governmental restrictions as well as changes in the expected recovery rates associated with infill drilling.
During 2009, Anadarko added 70 MMBOE of proved reserves primarily as the result of successful drilling in the United States and at international locations. Reserve revisions for 2009 include an increase of 212 MMBOE primarily related to large onshore natural-gas plays, such as the Greater Natural Buttes and Pinedale fields, as a result of successful infill drilling (where the reserve bookings for the infill wells are treated as a positive revision). The revisions include a decrease of 39 MMBOE driven by lower gas pricing. Sales and acquisitions of proved reserves in place were 24 and 32 MMBOE, respectively, related to onshore domestic assets. In 2008, Anadarko added 102 MMBOE of proved reserves primarily as the result of successful drilling in the Rockies and developments and appraisals in the deepwater Gulf of Mexico. Reserve revisions for 2008 included an increase of 188 MMBOE primarily as a result of successful infill drilling related to the large onshore natural-gas plays, such as the Greater Natural Buttes, Wattenberg and Pinedale fields, in addition to positive revisions to the Peregrino field offshore Brazil which was sold in 2008, partially offset by a decrease of 102 MMBOE related to price impacts for oil and NGLs. Sales of proved reserves in place for 2008 totaled 137 MMBOE, related to properties located in the United States and Brazil. During 2007, sales of proved reserves in place associated with the Company’s asset-realignment program totaled 620 MMBOE. Excluding the effect of divestitures, the Company added approximately 252 MMBOE of proved reserves in 2007. Reserve adds were primarily driven by successful drilling in coalbed methane and conventional plays and successful infill drilling onshore in the United States, as well as the initial recognition of proved reserves for the Peregrino development offshore Brazil.
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ANADARKO PETROLEUM CORPORATION
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION
AND PRODUCTION ACTIVITIES
(Unaudited)
Oil and Gas Reserves (Continued)
| Natural Gas (Bcf) |
Oil, Condensate and NGLs (MMBbls) |
||||||||||||||||
| United States | International | Total | United States | International | Total | ||||||||||||
| Proved Reserves |
|||||||||||||||||
| December 31, 2006 |
10,486 | — | 10,486 | 925 | 339 | 1,264 | |||||||||||
| Revisions of prior estimates |
464 | — | 464 | 33 | 2 | 35 | |||||||||||
| Extensions, discoveries and other additions |
460 | — | 460 | 8 | 54 | 62 | |||||||||||
| Purchases in place |
4 | — | 4 | — | — | — | |||||||||||
| Sales in place |
(2,212 | ) | — | (2,212 | ) | (240 | ) | (11 | ) | (251 | ) | ||||||
| Production |
(698 | ) | — | (698 | ) | (64 | ) | (32 | ) | (96 | ) | ||||||
| December 31, 2007 |
8,504 | — | 8,504 | 662 | 352 | 1,014 | |||||||||||
| Revisions of prior estimates |
199 | — | 199 | 59 | (1 | ) | 58 | ||||||||||
| Extensions, discoveries and other additions |
336 | — | 336 | 40 | — | 40 | |||||||||||
| Sales in place |
(184 | ) | — | (184 | ) | (15 | ) | (91 | ) | (106 | ) | ||||||
| Production |
(750 | ) | — | (750 | ) | (54 | ) | (26 | ) | (80 | ) | ||||||
| December 31, 2008 |
8,105 | — | 8,105 | 692 | 234 | 926 | |||||||||||
| Revisions of prior estimates |
228 | — | 228 | 114 | 21 | 135 | |||||||||||
| Extensions, discoveries and other additions |
210 | — | 210 | 15 | 20 | 35 | |||||||||||
| Purchases in place |
149 | — | 149 | 7 | — | 7 | |||||||||||
| Sales in place |
(111 | ) | — | (111 | ) | (5 | ) | — | (5 | ) | |||||||
| Production |
(817 | ) | — | (817 | ) | (63 | ) | (25 | ) | (88 | ) | ||||||
| December 31, 2009 |
7,764 | — | 7,764 | 760 | 250 | 1,010 | |||||||||||
| Proved Developed Reserves |
|||||||||||||||||
| December 31, 2006 |
7,618 | — | 7,618 | 505 | 214 | 719 | |||||||||||
| December 31, 2007 |
6,308 | — | 6,308 | 392 | 182 | 574 | |||||||||||
| December 31, 2008 |
6,117 | — | 6,117 | 435 | 145 | 580 | |||||||||||
| December 31, 2009 |
5,884 | — | 5,884 | 499 | 144 | 643 | |||||||||||
| Proved Undeveloped Reserves |
|||||||||||||||||
| December 31, 2006 |
2,868 | — | 2,868 | 420 | 125 | 545 | |||||||||||
| December 31, 2007 |
2,196 | — | 2,196 | 270 | 170 | 440 | |||||||||||
| December 31, 2008 |
1,988 | — | 1,988 | 257 | 89 | 346 | |||||||||||
| December 31, 2009 |
1,880 | — | 1,880 | 261 | 106 | 367 | |||||||||||
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ANADARKO PETROLEUM CORPORATION
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION
AND PRODUCTION ACTIVITIES
(Unaudited)
Oil and Gas Reserves (Continued)
| Total (MMBOE) |
|||||||||
| United States | International | Total | |||||||
| Proved Reserves |
|||||||||
| December 31, 2006 |
2,672 | 339 | 3,011 | ||||||
| Revisions of prior estimates(1) |
110 | 2 | 112 | ||||||
| Extensions, discoveries and other additions |
85 | 54 | 139 | ||||||
| Purchases in place |
1 | — | 1 | ||||||
| Sales in place |
(609 | ) | (11 | ) | (620 | ) | |||
| Production |
(180 | ) | (32 | ) | (212 | ) | |||
| December 31, 2007 |
2,079 | 352 | 2,431 | ||||||
| Revisions of prior estimates(1) |
93 | (1 | ) | 92 | |||||
| Extensions, discoveries and other additions |
96 | — | 96 | ||||||
| Sales in place |
(46 | ) | (91 | ) | (137 | ) | |||
| Production |
(179 | ) | (26 | ) | (205 | ) | |||
| December 31, 2008 |
2,043 | 234 | 2,277 | ||||||
| Revisions of prior estimates(1) |
152 | 21 | 173 | ||||||
| Extensions, discoveries and other additions |
50 | 20 | 70 | ||||||
| Purchases in place |
32 | — | 32 | ||||||
| Sales in place |
(24 | ) | — | (24 | ) | ||||
| Production |
(199 | ) | (25 | ) | (224 | ) | |||
| December 31, 2009 |
2,054 | 250 | 2,304 | ||||||
| Proved Developed Reserves |
|||||||||
| December 31, 2006 |
1,775 | 214 | 1,989 | ||||||
| December 31, 2007 |
1,443 | 182 | 1,625 | ||||||
| December 31, 2008 |
1,455 | 145 | 1,600 | ||||||
| December 31, 2009 |
1,480 | 144 | 1,624 | ||||||
| Proved Undeveloped Reserves |
|||||||||
| December 31, 2006 |
897 | 125 | 1,022 | ||||||
| December 31, 2007 |
636 | 170 | 806 | ||||||
| December 31, 2008 |
588 | 89 | 677 | ||||||
| December 31, 2009 |
574 | 106 | 680 | ||||||
| (1) | Revisions of prior estimates for 2009, 2008 and 2007 include 125 MMBOE, 158 MMBOE and 109 MMBOE, respectively, of additions generated by Anadarko’s infill drilling programs. |
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Table of Contents
ANADARKO PETROLEUM CORPORATION
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION
AND PRODUCTION ACTIVITIES
(Unaudited)
Capitalized Costs
Capitalized costs include the cost of properties, equipment and facilities for oil and gas-producing activities. Capitalized costs for proved properties include costs for oil and gas leaseholds where proved reserves have been identified, development wells, and related equipment and facilities, including development wells in progress. Capitalized costs for unproved properties include costs for acquiring oil and gas leaseholds where no proved reserves have been identified, including costs of exploratory wells that are in the process of drilling or in active completion, and costs of exploratory wells suspended or waiting on completion. Capitalized costs associated with activities of the Company’s midstream and marketing segments, and other corporate activities are not included.
| United States | International | Total | |||||||
| millions | |||||||||
| 2009 |
|||||||||
| Capitalized |
|||||||||
| Unproved properties |
$ | 8,476 | $ | 1,029 | $ | 9,505 | |||
| Proved properties |
32,069 | 2,753 | 34,822 | ||||||
| 40,545 | 3,782 | 44,327 | |||||||
| Accumulated DD&A |
11,010 | 979 | 11,989 | ||||||
| Net capitalized costs |
$ | 29,535 | $ | 2,803 | $ | 32,338 | |||
| 2008 |
|||||||||
| Capitalized |
|||||||||
| Unproved properties |
$ | 9,489 | $ | 939 | $ | 10,428 | |||
| Proved properties |
29,209 | 1,859 | 31,068 | ||||||
| 38,698 | 2,798 | 41,496 | |||||||
| Accumulated DD&A |
8,260 | 800 | 9,060 | ||||||
| Net capitalized costs |
$ | 30,438 | $ | 1,998 | $ | 32,436 | |||
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Table of Contents
ANADARKO PETROLEUM CORPORATION
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION
AND PRODUCTION ACTIVITIES
(Unaudited)
Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development
Amounts reported as costs incurred include both capitalized costs and costs charged to expense during the year for oil and gas property acquisition, exploration and development activities. Costs incurred also include new asset retirement obligations established in the current year, as well as increases or decreases to the asset retirement obligations resulting from changes to cost estimates during the year. Exploration costs include the costs of drilling and equipping successful exploration wells, as well as dry hole costs, leasehold impairments, geological and geophysical expenses, and the costs of retaining undeveloped leaseholds. Development costs include the costs of drilling and equipping development wells, and construction of related production facilities. Costs associated with activities of the Company’s midstream and marketing segments, and other corporate activities are not included.
| United States | International | Total | |||||||||
| millions | |||||||||||
| 2009 |
|||||||||||
| Property acquisitions |
|||||||||||
| Unproved |
$ | 270 | $ | 9 | $ | 279 | |||||
| Proved |
266 | — | 266 | ||||||||
| Exploration |
743 | 486 | 1,229 | ||||||||
| Development |
2,005 | 881 | 2,886 | ||||||||
| Total Costs Incurred |
$ | 3,284 | $ | 1,376 | $ | 4,660 | |||||
| 2008 |
|||||||||||
| Property acquisitions |
|||||||||||
| Unproved |
$ | 391 | $ | 14 | $ | 405 | |||||
| Proved |
26 | — | 26 | ||||||||
| Exploration |
622 | 409 | 1,031 | ||||||||
| Development |
3,240 | 290 | 3,530 | ||||||||
| Total Costs Incurred |
$ | 4,279 | $ | 713 | $ | 4,992 | |||||
| 2007 |
|||||||||||
| Property acquisitions |
|||||||||||
| Unproved(1) |
$ | (500 | ) | $ | 207 | $ | (293 | ) | |||
| Proved(2) |
(604 | ) | 13 | (591 | ) | ||||||
| Exploration |
575 | 259 | 834 | ||||||||
| Development |
2,623 | 182 | 2,805 | ||||||||
| Total Costs Incurred |
$ | 2,094 | $ | 661 | $ | 2,755 | |||||
| (1) | Includes purchase price adjustments related to finalizing the allocation of fair value to unproved properties acquired with the Kerr-McGee and Western acquisitions in 2006 of $(608) million and $124 million associated with properties in the United States and international areas, respectively. |
| (2) | Includes purchase price adjustments related to finalizing the allocation of fair value to proved properties acquired with the Kerr-McGee and Western acquisitions in 2006 of $(613) million and $13 million associated with properties in the United States and international areas, respectively. |
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Table of Contents
ANADARKO PETROLEUM CORPORATION
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION
AND PRODUCTION ACTIVITIES
(Unaudited)
Results of Operations for Producing Activities
Results of operations for producing activities consist of all activities within the Oil and Gas Exploration & Production segment. Net revenues from production include only the revenues from the production and sale of gas, oil, condensate and NGLs. Gains on property dispositions represent net gains on sales of oil and gas properties. Reversal of accrual for DWRRA dispute represents reversal of the liability accrued for potential additional royalties due on leases subject to litigation with the Department of Interior as described in Note 14 to the consolidated financial statements. Production costs are those incurred to operate and maintain wells and related equipment and facilities used in oil and gas operations. Exploration expenses include dry hole costs, leasehold impairments, geological and geophysical expenses, and the costs of retaining undeveloped leaseholds. Income tax expense is calculated by applying the current statutory tax rates to the revenues after deducting costs, which include DD&A allowances, after giving effect to permanent differences. The results of operations exclude general office overhead and interest expense attributable to oil and gas activities.
| United States | International | Total | ||||||||
| millions | ||||||||||
| 2009 |
||||||||||
| Net revenues from production |
||||||||||
| Third-party sales |
$ | 2,957 | $ | 1,046 | $ | 4,003 | ||||
| Sales to consolidated affiliates |
3,088 | 391 | 3,479 | |||||||
| Gains on property dispositions |
2 | 41 | 43 | |||||||
| Reversal of accrual for DWRRA dispute |
657 | — | 657 | |||||||
| 6,704 | 1,478 | 8,182 | ||||||||
| Production costs |
||||||||||
| Oil and gas operating |
845 | 88 | 933 | |||||||
| Oil and gas transportation and other |
567 | 22 | 589 | |||||||
| Production-related general and administrative expenses |
294 | 12 | 306 | |||||||
| Other taxes |
304 | 408 | 712 | |||||||
| 2,010 | 530 | 2,540 | ||||||||
| Exploration expenses |
810 | 297 | 1,107 | |||||||
| Depreciation, depletion and amortization |
3,138 | 181 | 3,319 | |||||||
| Impairments related to oil and gas properties |
22 | — | 22 | |||||||
| 724 | 470 | 1,194 | ||||||||
| Income tax expense |
279 | 624 | 903 | |||||||
| Results of operations |
$ | 445 | $ | (154 | ) | $ | 291 | |||
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Table of Contents
ANADARKO PETROLEUM CORPORATION
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION
AND PRODUCTION ACTIVITIES
(Unaudited)
Results of Operations for Producing Activities (Continued)
| United States | International | Total | |||||||
| millions | |||||||||
| 2008 |
|||||||||
| Net revenues from production |
|||||||||
| Third-party sales |
$ | 4,444 | $ | 1,620 | $ | 6,064 | |||
| Sales to consolidated affiliates |
5,977 | 956 | 6,933 | ||||||
| Gains on property dispositions |
137 | 855 | 992 | ||||||
| 10,558 | 3,431 | 13,989 | |||||||
| Production costs |
|||||||||
| Oil and gas operating |
1,004 | 100 | 1,104 | ||||||
| Oil and gas transportation and other |
528 | 24 | 552 | ||||||
| Production-related general and administrative expenses |
256 | 26 | 282 | ||||||
| Other taxes |
685 | 737 | 1,422 | ||||||
| 2,473 | 887 | 3,360 | |||||||
| Exploration expenses |
1,011 | 358 | 1,369 | ||||||
| Depreciation, depletion and amortization |
2,818 | 175 | 2,993 | ||||||
| Impairments related to oil and gas properties |
113 | — | 113 | ||||||
| 4,143 | 2,011 | 6,154 | |||||||
| Income tax expense |
1,430 | 912 | 2,342 | ||||||
| Results of operations |
$ | 2,713 | $ | 1,099 | $ | 3,812 | |||
| 2007 |
|||||||||
| Net revenues from production |
|||||||||
| Third-party sales |
$ | 4,575 | $ | 1,722 | $ | 6,297 | |||
| Sales to consolidated affiliates |
3,384 | 488 | 3,872 | ||||||
| Gains on property dispositions |
3,940 | 189 | 4,129 | ||||||
| 11,899 | 2,399 | 14,298 | |||||||
| Production costs |
|||||||||
| Oil and gas operating |
993 | 106 | 1,099 | ||||||
| Oil and gas transportation and other |
426 | 25 | 451 | ||||||
| Production-related general and administrative expenses |
137 | 42 | 179 | ||||||
| Other taxes |
446 | 738 | 1,184 | ||||||
| 2,002 | 911 | 2,913 | |||||||
| Exploration expenses |
671 | 234 | 905 | ||||||
| Depreciation, depletion and amortization |
2,435 | 176 | 2,611 | ||||||
| Impairments related to oil and gas properties |
13 | 11 | 24 | ||||||
| 6,778 | 1,067 | 7,845 | |||||||
| Income tax expense |
2,392 | 624 | 3,016 | ||||||
| Results of operations |
$ | 4,386 | $ | 443 | $ | 4,829 | |||
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Table of Contents
ANADARKO PETROLEUM CORPORATION
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION
AND PRODUCTION ACTIVITIES
(Unaudited)
Standardized Measure for Discounted Future Net Cash Flows
Estimates of future net cash flows from proved reserves of gas, oil, condensate and NGLs for 2009 are computed using the average first-day-of-the-month price during the 12-month period for 2009 and using year-end prices for 2008 and 2007. Prices used for all periods are adjusted only for fixed and determinable amounts under provisions in existing contracts. Estimated future net cash flows for all periods presented are reduced by estimated future development, production, abandonment and dismantlement costs based on existing costs, assuming continuation of existing economic conditions, and by estimated future income tax expense. These estimates also include assumptions about the timing of future production of proved reserves, and timing of future development, production costs, and abandonment and dismantlement. Income tax expense, both U.S. and foreign, is calculated by applying the existing statutory tax rates, including any known future changes, to the pretax net cash flows giving effect to any permanent differences and reduced by the applicable tax basis. The effect of tax credits is considered in determining the income tax expense. The 10-percent discount factor is prescribed by GAAP.
The present value of future net cash flows does not purport to be an estimate of the fair market value of Anadarko’s proved reserves. An estimate of fair value would also take into account, among other things, anticipated changes in future prices and costs, the expected recovery of reserves in excess of proved reserves and a discount factor more representative of the time value of money and the risks inherent in producing oil and gas. Significant changes in estimated reserve volumes or commodity prices could have a material effect on the Company’s consolidated financial statements.
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Table of Contents
ANADARKO PETROLEUM CORPORATION
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION
AND PRODUCTION ACTIVITIES
(Unaudited)
Standardized Measure of Discounted Future Net Cash Flows
Relating to Proved Oil and Gas Reserves
| United States | International | Total | |||||||
| millions | |||||||||
| 2009 |
|||||||||
| Future cash inflows |
$ | 60,555 | $ | 14,699 | $ | 75,254 | |||
| Future production costs |
21,312 | 5,665 | 26,977 | ||||||
| Future development costs |
7,243 | 1,644 | 8,887 | ||||||
| Future income tax expenses |
10,537 | 3,641 | 14,178 | ||||||
| Future net cash flows |
21,463 | 3,749 | 25,212 | ||||||
| 10% annual discount for estimated timing of cash flows |
9,938 | 1,721 | 11,659 | ||||||
| Standardized measure of discounted future net cash flows |
$ | 11,525 | $ | 2,028 | $ | 13,553 | |||
| 2008 |
|||||||||
| Future cash inflows |
$ | 61,086 | $ | 7,529 | $ | 68,615 | |||
| Future production costs |
20,925 | 4,265 | 25,190 | ||||||
| Future development costs |
9,290 | 1,112 | 10,402 | ||||||
| Future income tax expenses |
10,037 | 939 | 10,976 | ||||||
| Future net cash flows |
20,834 | 1,213 | 22,047 | ||||||
| 10% annual discount for estimated timing of cash flows |
9,431 | 645 | 10,076 | ||||||
| Standardized measure of discounted future net cash flows |
$ | 11,403 | $ | 568 | $ | 11,971 | |||
| 2007 |
|||||||||
| Future cash inflows |
$ | 106,439 | $ | 31,699 | $ | 138,138 | |||
| Future production costs |
27,124 | 11,417 | 38,541 | ||||||
| Future development costs |
8,358 | 2,080 | 10,438 | ||||||
| Future income tax expenses |
24,257 | 9,628 | 33,885 | ||||||
| Future net cash flows |
46,700 | 8,574 | 55,274 | ||||||
| 10% annual discount for estimated timing of cash flows |
22,424 | 3,933 | 26,357 | ||||||
| Standardized measure of discounted future net cash flows |
$ | 24,276 | $ | 4,641 | $ | 28,917 | |||
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Table of Contents
ANADARKO PETROLEUM CORPORATION
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION
AND PRODUCTION ACTIVITIES
(Unaudited)
Changes in Standardized Measure of Discounted Future Net Cash Flows
Relating to Proved Oil and Gas Reserves
| United States | International | Total | ||||||||||
| millions | ||||||||||||
| 2009 |
||||||||||||
| Beginning of year |
$ | 11,403 | $ | 568 | $ | 11,971 | ||||||
| Sales and transfers of oil and gas produced, net of production costs |
(4,035 | ) | (907 | ) | (4,942 | ) | ||||||
| Net changes in prices and production costs |
(2,064 | ) | 2,999 | 935 | ||||||||
| Changes in estimated future development costs |
1,196 | (243 | ) | 953 | ||||||||
| Extensions, discoveries, additions and improved recovery, less related costs |
717 | 264 | 981 | |||||||||
| Development costs incurred during the period |
720 | 273 | 993 | |||||||||
| Revisions of previous quantity estimates |
2,389 | (26 | ) | 2,363 | ||||||||
| Purchases of minerals in place |
206 | — | 206 | |||||||||
| Sales of minerals in place |
(70 | ) | — | (70 | ) | |||||||
| Accretion of discount |
1,642 | 171 | 1,813 | |||||||||
| Net change in income taxes |
(192 | ) | (1,044 | ) | (1,236 | ) | ||||||
| Other |
(387 | ) | (27 | ) | (414 | ) | ||||||
| End of year |
$ | 11,525 | $ | 2,028 | $ | 13,553 | ||||||
| 2008 |
||||||||||||
| Beginning of year |
$ | 24,276 | $ | 4,641 | $ | 28,917 | ||||||
| Sales and transfers of oil and gas produced, net of production costs |
(7,948 | ) | (1,689 | ) | (9,637 | ) | ||||||
| Net changes in prices and production costs |
(15,973 | ) | (6,935 | ) | (22,908 | ) | ||||||
| Changes in estimated future development costs |
(19 | ) | 46 | 27 | ||||||||
| Extensions, discoveries, additions and improved recovery, less related costs |
137 | — | 137 | |||||||||
| Development costs incurred during the period |
806 | 149 | 955 | |||||||||
| Revisions of previous quantity estimates |
2,212 | 1,238 | 3,450 | |||||||||
| Sales of minerals in place |
(1,096 | ) | (2,216 | ) | (3,312 | ) | ||||||
| Accretion of discount |
3,602 | 1,008 | 4,610 | |||||||||
| Net change in income taxes |
6,734 | 4,293 | 11,027 | |||||||||
| Other |
(1,328 | ) | 33 | (1,295 | ) | |||||||
| End of year |
$ | 11,403 | $ | 568 | $ | 11,971 | ||||||
| 2007 |
||||||||||||
| Beginning of year |
$ | 21,354 | $ | 4,279 | $ | 25,633 | ||||||
| Sales and transfers of oil and gas produced, net of production costs |
(5,957 | ) | (1,299 | ) | (7,256 | ) | ||||||
| Net changes in prices and production costs |
11,735 | 3,067 | 14,802 | |||||||||
| Changes in estimated future development costs |
(11 | ) | (1,129 | ) | (1,140 | ) | ||||||
| Extensions, discoveries, additions and improved recovery, less related costs |
196 | 1,601 | 1,797 | |||||||||
| Development costs incurred during the period |
900 | 86 | 986 | |||||||||
| Revisions of previous quantity estimates |
1,700 | (240 | ) | 1,460 | ||||||||
| Purchases of minerals in place |
16 | — | 16 | |||||||||
| Sales of minerals in place |
(9,088 | ) | (214 | ) | (9,302 | ) | ||||||
| Accretion of discount |
3,173 | 754 | 3,927 | |||||||||
| Net change in income taxes |
(1,375 | ) | (2,176 | ) | (3,551 | ) | ||||||
| Other |
1,633 | (88 | ) | 1,545 | ||||||||
| End of year |
$ | 24,276 | $ | 4,641 | $ | 28,917 | ||||||
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Table of Contents
| Item 9. | Changes in and Disagreements with Accountants on Accounting and Financial Disclosure |
None.
| Item 9A. | Controls and Procedures |
Evaluation of Disclosure Controls and Procedures
Anadarko’s Chief Executive Officer and Chief Financial Officer performed an evaluation of the Company’s disclosure controls and procedures. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under the Securities Exchange Act of 1934 is accumulated and communicated to the issuer’s management, including its Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. Based on this evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that the Company’s disclosure controls and procedures are effective as of December 31, 2009.
Management’s Annual Report on Internal Control Over Financial Reporting
See Management’s Assessment of Internal Control Over Financial Reporting under Item 8 of this Form 10-K.
Attestation Report of the Registered Public Accounting Firm
See Report of Independent Registered Public Accounting Firm under Item 8 of this Form 10-K.
Changes in Internal Control Over Financial Reporting
There were no changes in Anadarko’s internal controls over financial reporting during the fourth quarter of 2009 that materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
| Item 9B. | Other Information |
None.
PART III
| Item 10. | Directors, Executive Officers and Corporate Governance |
See Anadarko Board of Directors, Corporate Governance—Board of Directors, Corporate Governance—Committees of the Board and Section 16(a) Beneficial Ownership Reporting Compliance in the Anadarko Petroleum Corporation Proxy Statement (Proxy Statement), for the Annual Meeting of Stockholders of Anadarko Petroleum Corporation to be held May 18, 2010 (to be filed with the Securities and Exchange Commission prior to April 9, 2010), each of which is incorporated herein by reference.
See list of Executive Officers of the Registrant under Item 4 of this Form 10-K, which is incorporated herein by reference.
The Company’s Code of Business Conduct and Ethics and the Code of Ethics for the Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer (Code of Ethics) can be found on the Company’s internet website located at www.anadarko.com. Any stockholder may request a printed copy of the Code of Ethics by submitting a written request to the Company’s Corporate Secretary. If the Company amends the Code of Ethics or grants a waiver, including an implicit waiver, from the Code of Ethics, the Company will disclose the information on its internet website. The waiver information will remain on the website for at least 12 months after the initial disclosure of such waiver.
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Table of Contents
| Item 11. | Executive Compensation |
See Corporate Governance—Board of Directors—Compensation and Benefits Committee Interlocks and Insider Participation, Corporate Governance—Board of Directors—Director Compensation, Corporate Governance—Director Compensation Table for 2009, Compensation and Benefits Committee Report on 2009 Executive Compensation, Compensation Discussion and Analysis and Executive Compensation in the Proxy Statement, each of which is incorporated herein by reference. The Compensation and Benefits Committee Report and related information incorporated by reference herein shall not be deemed “soliciting material” or to be “filed” with the Securities and Exchange Commission, nor shall such information be incorporated by reference into any future filing under the Securities Act of 1933 or Securities Exchange Act of 1934, each as amended, except to the extent that the Company specifically incorporates it by reference into such filing.
| Item 12. | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters |
See Security Ownership of Certain Beneficial Owners and Management in the Proxy Statement, which is incorporated herein by reference.
EQUITY COMPENSATION PLAN TABLE The following table sets forth information with respect to the equity compensation plans available to directors, officers and employees of the Company as of December 31, 2009:
| Plan category |
(a) Number of securities to be issued upon exercise of outstanding options, warrants and rights |
(b) Weighted-average exercise price of outstanding options, warrants and rights |
(c) Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column(a)) | |||
| Equity compensation plans approved by security holders |
9,479,527 | 42.01 | 24,226,218 | |||
| Equity compensation plans not approved by security holders |
— | — | — | |||
| Total |
9,479,527 | 42.01 | 24,226,218 |
| Item 13. | Certain Relationships and Related Transactions, and Director Independence |
See Corporate Governance — Board of Directors and Transactions with Related Persons in the Proxy Statement, each of which is incorporated herein by reference.
| Item 14. | Principal Accounting Fees and Services |
See Independent Auditor in the Proxy Statement, which is incorporated herein by reference.
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Table of Contents
PART IV
| Item 15. | Exhibits, Financial Statement Schedules |
(a) Exhibits The following documents are filed as a part of this report or incorporated by reference:
| (1) | The consolidated financial statements of Anadarko Petroleum Corporation are listed on the Index to this report, page 62. |
| (2) | Exhibits not incorporated by reference to a prior filing are designated by an asterisk (*) and are filed herewith or designated by asterisks (**) and are furnished herewith; all exhibits not so designated are incorporated herein by reference to a prior filing as indicated. |
| Exhibit Number |
Description |
Originally Filed as Exhibit |
File Number | |||||
| 2(i) | Agreement and Plan of Merger dated as of June 22, 2006, among Anadarko Petroleum Corporation, APC Merger Sub, Inc. and Western Gas Resources, Inc. | 2.1 to Form 8-K dated June 26, 2006 | 1-8968 | |||||
| (ii) | Amendment No. 1 to Agreement and Plan of Merger dated as of June 22, 2006, among Anadarko Petroleum Corporation, APC Merger Sub, Inc. and Western Gas Resources, Inc. | 2.1 to Form 8-K dated July 12, 2006 | 1-8968 | |||||
| (iii) | Agreement and Plan of Merger dated as of June 22, 2006, among Anadarko Petroleum Corporation, APC Acquisition Sub, Inc. and Kerr-McGee Corporation | 2.2 to Form 8-K dated June 26, 2006 | 1-8968 | |||||
| 3(i) | Restated Certificate of Incorporation of Anadarko Petroleum Corporation, dated May 21, 2009 | 3.3 to Form 8-K dated May 21, 2009 | 1-8968 | |||||
| (ii) | By-Laws of Anadarko Petroleum Corporation, amended and restated as of May 21, 2009 | 3.4 to Form 8-K dated May 21, 2009 | 1-8968 | |||||
| 4(i) | Trustee Indenture dated as of September 19, 2006, Anadarko Petroleum Corporation to The Bank of New York Trust Company, N.A. | 4.1 to Form 8-K dated September 19, 2006 | 1-8968 | |||||
| (ii) | Second Supplemental Indenture dated October 4, 2006, among Anadarko Petroleum Corporation, Kerr-McGee Corporation, and Citibank, N.A. | 4.1 to Form 8-K dated October 5, 2006 | 1-8968 | |||||
| (iii) | Ninth Supplemental Indenture dated October 4, 2006, among Anadarko Petroleum Corporation, Kerr-McGee Corporation, and Citibank, N.A. | 4.2 to Form 8-K dated October 5, 2006 | 1-8968 | |||||
| (iv) | Officers’ Certificate of Anadarko Petroleum Corporation, dated March 2, 2009 establishing the 7.625% Senior Notes due 2014 and the 8.700% Senior Notes due 2019 | 4.1 to Form 8-K dated March 5, 2009 | 1-8968 | |||||
| (v) | Form of 7.625% Senior Notes due 2014 | 4.2 to Form 8-K dated March 5, 2009 | 1-8968 | |||||
| (vi) | Form of 8.700% Senior Notes due 2019 | 4.3 to Form 8-K dated March 5, 2009 | 1-8968 | |||||
| (vii) | Officers’ Certificate of Anadarko Petroleum Corporation, dated June 9, 2009 establishing the 5.75% Senior Notes due 2014, the 6.95% Senior Notes due 2019 and the 7.95% Senior Notes due 2039 | 4.1 to Form 8-K dated June 12, 2009 | 1-8968 | |||||
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| Exhibit Number |
Description |
Originally Filed as Exhibit |
File Number | |||||
| 4(viii) | Form of 5.75% Senior Notes due 2014 | 4.2 to Form 8-K dated June 12, 2009 | 1-8968 | |||||
| (ix) | Form of 6.95% Senior Notes due 2019 | 4.3 to Form 8-K dated June 12, 2009 | 1-8968 | |||||
| (x) | Form of 7.95% Senior Notes due 2039 | 4.4 to Form 8-K dated June 12, 2009 | 1-8968 | |||||
| † | 10(i) | 1998 Director Stock Plan of Anadarko Petroleum Corporation, effective January 30, 1998 | Appendix A to DEF 14A filed March 16, 1998 | 1-8968 | ||||
| † | (ii) | Form of Anadarko Petroleum Corporation 1998 Director Stock Plan Stock Option Agreement | 10.1 to Form 8-K dated November 17, 2005 | 1-8968 | ||||
| † | (iii) | Anadarko Petroleum Corporation Amended and Restated 1999 Stock Incentive Plan | Appendix A to DEF 14A filed March 18, 2005 | 1-8968 | ||||
| † | (iv) | Form of Anadarko Petroleum Corporation Executive 1999 Stock Incentive Plan Stock Option Agreement | 10.2 to Form 8-K dated November 17, 2005 | 1-8968 | ||||
| † | (v) | Form of Anadarko Petroleum Corporation Non-Executive 1999 Stock Incentive Plan Stock Option Agreement | 10.3 to Form 8-K dated November 17, 2005 | 1-8968 | ||||
| † | (vi) | Form of Stock Option Agreement—1999 Stock Incentive Plan (UK Nationals) | 10.4 to Form 8-K dated November 17, 2005 | 1-8968 | ||||
| † | (vii) | Amendment to Stock Option Agreement Under the Anadarko Petroleum Corporation 1999 Stock Incentive Plan | 10.1 to Form 8-K dated January 23, 2007 | 1-8968 | ||||
| † | (viii) | Anadarko Petroleum Corporation 1999 Stock Incentive Plan (Amendment to Performance Unit Agreement) | 10.3 to Form 8-K dated November 13, 2007 | 1-8968 | ||||
| † | (ix) | Form of Anadarko Petroleum Corporation 1999 Stock Incentive Plan Restricted Stock Agreement | 10(b)(xxiv) to Form 10-K for year ended December 31, 1999 | 1-8968 | ||||
| † | (x) | Anadarko Petroleum Corporation 1999 Stock Incentive Plan Performance Share Agreement | 10(b) to Form 10-Q for quarter ended March 31, 2004 | 1-8968 | ||||
| † | (xi) | Anadarko Petroleum Corporation 1999 Stock Incentive Plan Performance Unit Agreement | 10.1 to Form 8-K dated December 14, 2004 | 1-8968 | ||||
| † | (xii) | Form of Anadarko Petroleum Corporation 1999 Stock Incentive Plan Performance Unit Agreement | 10.1 to Form 8-K dated December 9, 2005 | 1-8968 | ||||
| † | (xiii) | Form of Anadarko Petroleum Corporation 1999 Stock Incentive Plan Performance Unit Agreement | 10.2 to Form 8-K dated December 11, 2006 | 1-8968 | ||||
| † | (xiv) | Form of Anadarko Petroleum Corporation 1999 Stock Incentive Plan Performance Unit Agreement | 10.5 to Form 8-K dated November 13, 2007 | 1-8968 | ||||
| † | (xv) | Form of Anadarko Petroleum Corporation 1999 Stock Incentive Plan Performance Unit Agreement | 10.6 to Form 8-K dated November 13, 2007 | 1-8968 | ||||
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| Exhibit Number |
Description |
Originally Filed as Exhibit |
File Number | |||||
| † | 10(xvi) | Form of Anadarko Petroleum Corporation 1999 Stock Incentive Plan Restricted Stock Unit Award Letter | 10.1 to Form 8-K dated November 13, 2007 | 1-8968 | ||||
| † | (xvii) | The Approved UK Sub-Plan of the Anadarko Petroleum Corporation 1999 Stock Incentive Plan | 10(b)(xxiv) to Form 10-K for year ended December 31, 2003 | 1-8968 | ||||
| † | (xviii) | Key Employee Change of Control Contract | 10(b)(xxii) to Form 10-K for year ended December 31, 1997 | 1-8968 | ||||
| † | (xix) | First Amendment to Anadarko Petroleum Corporation Key Employee Change of Control Contract | 10(b) to Form 10-Q for quarter ended September 30, 2000 | 1-8968 | ||||
| † | (xx) | Form of Amendment to Anadarko Petroleum Corporation Key Employee Change of Control Contract | 10(b)(ii) to Form 10-Q for quarter ended June 30, 2003 | 1-8968 | ||||
| † | (xxi) | Letter Agreement regarding Post-Retirement Benefits, dated February 16, 2004—Robert J. Allison, Jr. | 10(b)(xxxiv) to Form 10-K for year ended December 31, 2003 | 1-8968 | ||||
| † | *(xxii) | Anadarko Petroleum Corporation Savings Restoration Plan (As Amended and Restated Effective January 1, 2007) | ||||||
| † | (xxiii) | Anadarko Retirement Restoration Plan (As Amended and Restated Effective as of November 7, 2007) | 10.2 to Form 8-K dated November 13, 2007 | 1-8968 | ||||
| † | (xxiv) | Anadarko Petroleum Corporation Estate Enhancement Program | 10(b)(xxxiv) to Form 10-K for year ended December 31, 1998 | 1-8968 | ||||
| † | (xxv) | Estate Enhancement Program Agreement between Anadarko Petroleum Corporation and Eligible Executives | 10(b)(xxxv) to Form 10-K for year ended December 31, 1998 | 1-8968 | ||||
| † | (xxvi) | Estate Enhancement Program Agreements effective November 29, 2000 | 10(b)(xxxxii) to Form 10-K for year ended December 31, 2000 | 1-8968 | ||||
| † | (xxvii) | Anadarko Petroleum Corporation Management Life Insurance Plan, restated November 1, 2002 | 10(b)(xxxii) to Form 10-K for year ended December 31, 2002 | 1-8968 | ||||
| † | (xxviii) | First Amendment to Anadarko Petroleum Corporation Management Life Insurance Plan, effective June 30, 2003 | 10(b)(xliii) to Form 10-K for year ended December 31, 2003 | 1-8968 | ||||
| † | *(xxix) | Second Amendment to Anadarko Petroleum Corporation Management Life Insurance Plan, effective January 1, 2008 | ||||||
| † | (xxx) | Anadarko Petroleum Corporation Officer Severance Plan | 10(b)(iv) to Form 10-Q for quarter ended September 30, 2003 | 1-8968 | ||||
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| Exhibit Number |
Description |
Originally Filed as Exhibit |
File Number | |||||
| † | 10(xxxi) | Form of Termination Agreement and Release of All Claims Under Officer Severance Plan | 10(b)(v) to Form 10-Q for quarter ended September 30, 2003 | 1-8968 | ||||
| † | (xxxii) | Director and Officer Indemnification Agreement | 10 to Form 8-K dated September 3, 2004 | 1-8968 | ||||
| † | (xxxiii) | Summary of Material Terms of Employment—R. A. Walker | 10.1 to Form 8-K dated August 11, 2005 | 1-8968 | ||||
| † | (xxxiv) | Compensatory Arrangements for Certain Officers | Form 8-K dated January 17, 2007 | 1-8968 | ||||
| (xxxv) | $1.3 billion Revolving Credit Agreement, dated as of March 4, 2008, by and among Anadarko Petroleum Corporation, Western Gas Partners, LP, JPMorgan Chase Bank, N.A., The Royal Bank of Scotland, PLC, BNP Paribas, Bank of America, N.A., BMO Capital Markets Financing, Inc., The Bank of Tokyo-Mitsubishi UFJ, LTD., and each of the Lenders named therein | 10.14 to Form S-1 dated April 15, 2008 | 333-146700 | |||||
| (xxxvi) | $2.2 billion Term Loan Agreement, dated as of December 27, 2007, among WGR Asset Holding Company LLC and Trinity Associates LLC | 10(liv) to Form 10-K for year ended December 31, 2007 | 1-8968 | |||||
| (xxxvii) | Amended and Restated Limited Liability Company Agreement of Trinity Associates LLC, dated as of December 27, 2007 | 10(lv) to Form 10-K for year ended December 31, 2007 | 1-8968 | |||||
| (xxxviii) | Sponsor Payment Guaranty, dated as of December 19, 2008 made by Anadarko Petroleum Corporation | 10.1 to Form 8-K dated December 19, 2008 | 1-8968 | |||||
| † | (xxxix) | Anadarko Petroleum Corporation 2008 Omnibus Incentive Compensation Plan, effective as of May 20, 2008 | 10.1 to Form 8-K dated May 20, 2008 | 1-8968 | ||||
| † | (xl) | Form of Anadarko Petroleum Corporation 2008 Omnibus Incentive Compensation Plan Stock Option Award Agreement | 10.3 to Form 8-K dated November 13, 2009 | 1-8968 | ||||
| † | (xli) | Form of Anadarko Petroleum Corporation 2008 Omnibus Incentive Compensation Plan Restricted Stock Unit Award Agreement | 10.1 to Form 8-K dated November 13, 2009 | 1-8968 | ||||
| † | (xlii) | Form of Anadarko Petroleum Corporation 2008 Omnibus Incentive Compensation Plan Performance Unit Award Agreement | 10.2 to Form 8-K dated November 13, 2009 | 1-8968 | ||||
| † | (xliii) | Anadarko Petroleum Corporation 2008 Director Compensation Plan, effective as of May 20, 2008 | 10.2 to Form 8-K dated May 20, 2008 | 1-8968 | ||||
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| Exhibit Number |
Description |
Originally Filed as Exhibit |
File Number | |||||
| † |
10(xliv) |
Form of Award Letter for Anadarko Petroleum Corporation 2008 Director Compensation Plan | 10.3 to Form 8-K dated May 20, 2008 | 1-8968 | ||||
| † |
(xlv) |
Anadarko Petroleum Corporation Benefits Trust Agreement, amended and restated effective as of November 5, 2008 | 10(lvi) to Form 10-K dated February 25, 2009 | 1-8968 | ||||
| † |
*(xlvi) |
Anadarko Petroleum Corporation Deferred Compensation Plan (as amended and restated effective as of January 1, 2010) | ||||||
| † |
(xlvii) |
Amended and Restated Employment Agreement between James T. Hackett and Anadarko Petroleum Corporation, dated November 11, 2009 | 10.4 to Form 8-K dated November 13, 2009 | 1-8968 | ||||
| * 12 |
Computation of Ratios of Earnings to Fixed Charges and Earnings to Combined Fixed Charges and Preferred Stock Dividends | |||||||
| * 21 |
List of Subsidiaries | |||||||
| * 23(i) |
Consent of KPMG LLP | |||||||
| * 23(ii) |
Consent of Miller and Lents, Ltd. | |||||||
| * 24 |
Power of Attorney | |||||||
| * 31(i) |
Rule 13a-14(a)/15d-14(a) Certification—Chief Executive Officer | |||||||
| * 31(ii) |
Rule 13a-14(a)/15d-14(a) Certification—Chief Financial Officer | |||||||
| * 32 |
Section 1350 Certifications | |||||||
| * 99 |
2009 Report of Miller and Lents, Ltd. | |||||||
| **101.INS |
XBRL Instance Document | |||||||
| **101.SCH |
XBRL Schema Document | |||||||
| **101.CAL |
XBRL Calculation Linkbase Document | |||||||
| **101.LAB |
XBRL Label Linkbase Document | |||||||
| **101.PRE |
XBRL Presentation Linkbase Document | |||||||
| **101.DEF |
XBRL Definition Linkbase Document | |||||||
| † | Management contracts or compensatory plans or arrangements required to be filed pursuant to Item 15. |
The total amount of securities of the registrant authorized under any instrument with respect to long-term debt not filed as an exhibit does not exceed 10% of the total assets of the registrant and its subsidiaries on a consolidated basis. The registrant agrees, upon request of the Securities and Exchange Commission, to furnish copies of any or all of such instruments to the Securities and Exchange Commission.
(b) Financial Statement Schedules Financial statement schedules have been omitted because they are not required, not applicable or the information is included in the Company’s consolidated financial statements.
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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
| ANADARKO PETROLEUM CORPORATION | ||||
| February 23, 2010 |
By: | /s/ ROBERT G. GWIN | ||
| (Robert G. Gwin, Senior Vice President, Finance and Chief Financial Officer) | ||||
Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on February 23, 2010.
| Name and Signature |
Title | |||
| (i) Principal executive officer:* |
||||
| JAMES T. HACKETT (James T. Hackett) |
Chairman of the Board and Chief Executive Officer | |||
| (ii) Principal financial officer: |
||||
| /s/ ROBERT G. GWIN (Robert G. Gwin) |
Senior Vice President, Finance and Chief Financial Officer | |||
| (iii) Principal accounting officer: |
||||
| /s/ M. CATHY DOUGLAS (M. Cathy Douglas) |
Vice President and Chief Accounting Officer | |||
| (iv) Directors:* |
||||
| ROBERT J. ALLISON, JR. JOHN R. BUTLER, JR. LUKE R. CORBETT H. PAULETT EBERHART PETER J. FLUOR PRESTON M. GEREN III JOHN R. GORDON JAMES T. HACKETT PAULA ROSPUT REYNOLDS |
||||
|
* Signed on behalf of each of these persons and on his own behalf: | ||||
| By: | /s/ ROBERT G. GWIN |
|||
| (Robert G. Gwin, Attorney-in-Fact) | ||||
138