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)
Registrants 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 registrants 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 Companys 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 Companys 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). |
1
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. Anadarkos 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 Companys 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 Companys operations are located onshore United States and in the deepwater Gulf of Mexico, as well as in Algeria, Brazil, China, Cote dIvoire, 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 Anadarkos 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 Companys 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 Anadarkos continuing operations and excludes the discontinued Canadian operations. For additional information, see Note 1Summary 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 SECs 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 Anadarkos 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 ActivitiesUnited States
Overview Anadarkos 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 Anadarkos total proved reserves at year-end 2009. During 2009, the Companys 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
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 Anadarkos 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 Companys operated tight gas assets are located in the Greater Natural Buttes, Wattenberg, Wamsutter and Moxa fields. Pinedale is a non-operated asset within Anadarkos 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. Anadarkos 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 Companys 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 Anadarkos 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.
Anadarkos 2009 onshore exploration program focused primarily on testing and developing emerging shale plays. Anadarko conducted successful exploratory tests in Pennsylvanias 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 Companys 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 Companys 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 Companys existing wells and additional acreage acquisitions by reimbursing a proportionate share of the Companys 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 Anadarkos 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.
Anadarkos 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 ActivitiesInternational
Overview The Companys 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 dIvoire, Ghana, Liberia, Sierra Leone, Mozambique, Indonesia and other countries. Approximately 11% of the Companys 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.
5
Algeria Anadarko is engaged in development and production activities in Algerias 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 Companys 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. Anadarkos 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 Sonatrachs 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 Sonatrachs right under the PSA to renegotiate the PSA in order to re-establish the equilibrium of Anadarkos and Sonatrachs 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 Anadarkos 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 governments 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 15Other Taxes in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.
China Anadarkos 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
6
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 Anadarkos 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 Anadarkos 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 dIvoire Anadarko holds interests in two blocks located in the Ivorian basin. The Company participated in one unsuccessful well offshore Cote dIvoire 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
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 Companys 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 Companys 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 Companys 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 Companys major development projectsEl 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 Companys 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 Companys remaining PUDs booked prior to 2005 are associated with multiple domestic onshore fields and are also scheduled for conversion by 2015.
Evaluation and Review Anadarkos estimates of proved reserves and associated future net cash flows as of December 31, 2009 were made solely by the Companys 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 Anadarkos 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 Companys Finance division, which is separate from its operating divisions, and is responsible for overseeing internal reserve reviews and approving the Companys reserve estimates. The DirectorReserve Administration and the Corporate Reserve Manager manage the RMG and the DirectorCorporate Planning is directly responsible for overseeing the RMG. The DirectorCorporate Planning reports to the Companys Senior Vice President, Finance and Chief Financial Officer, who in turn reports to the Chief Executive Officer.
The Companys 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 Companys 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, Anadarkos 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. Managements 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 Companys Board of Directors meets with management, the Companys 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 Companys annual sales volumes, average sales prices and production costs from continuing operations. The Companys 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 Companys 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 18Major 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. |
10
Sales Revenues and Commodity Derivatives
The following table provides the Companys natural-gas, oil and condensate and NGLs sales revenues and related gains (losses) on commodity derivatives. Anadarko utilizes derivative instruments to manage the Companys cash flow exposure to commodity price risk related to the Companys 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 | ||||||||
11
The Companys 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 |
12
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, Anadarkos 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 Companys 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
13
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 WESs 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 Companys marketing segment actively manages Anadarkos 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 Companys 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 Anadarkos 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 Companys 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 Companys 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 Americas 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.
14
The Company controls a significant amount of natural-gas firm transportation capacity that is used to ensure access to downstream markets, which enhances the Companys 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 Anadarkos crude-oil, condensate and NGLs revenues are derived from production in the United States, Algeria, China and other international areas. Most of the Companys 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 Companys 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 Companys 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 Companys 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 19Segment 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 Companys 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 ResourcesObligations and ContingenciesEnvironmental under Item 7 of this Form 10-K.
15
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.
16
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 Companys 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 Companys expectations include, but are not limited to, the following risks and uncertainties:
|
the Companys 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); |
17
|
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 Companys 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. |
18
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. Presidents 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. |
19
A downgrade in our credit rating could negatively impact our cost of and ability to access capital.
As of December 31, 2009, Standard and Poors (S&P) and Moodys Investors Service (Moodys) 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 Moodys 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 Moodys. 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 8Derivative 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-McGees 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 Tronoxs 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 Tronoxs 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, Tronoxs environmental-remediation and tort claim liabilities. The plaintiffs allege that these purported misstatements and omissions are contained in certain of Tronoxs public filings, including filings made in connection with Tronoxs initial public offering. The plaintiffs seek an unspecified amount of compensatory damages, including interest thereon, as well as litigation fees and costs.
20
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
21
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; |
22
|
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 dIvoire, 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 governments 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 15Other 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.
23
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 lenders 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, employers liability, comprehensive general liability and workers 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. |
24
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.
25
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.
26
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 Tronoxs 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 Tronoxs 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, Tronoxs environmental-remediation and tort claim liabilities. The plaintiffs allege that these purported misstatements and omissions are contained in certain of Tronoxs public filings, including in connection with Tronoxs 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.
27
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 partners 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 firms 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.
28
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.
29
PART II
Item 5. | Market for Registrants 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 Companys 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 ResourcesUses of CashDividends under Item 7 and Note 11Stockholders Equity and Note 12Stock-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 Companys 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 Anadarkos 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 Companys 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 Anadarkos 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 Companys 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
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 OperationsBasic |
$ | (0.28 | ) | $ | 6.79 | $ | 8.01 | $ | 5.33 | $ | 4.17 | |||||||
Income (Loss) from Continuing OperationsDiluted |
$ | (0.28 | ) | $ | 6.78 | $ | 7.99 | $ | 5.31 | $ | 4.14 | |||||||
Income from Discontinued OperationsBasic |
$ | | $ | 0.13 | $ | 0.02 | $ | 4.91 | $ | 0.75 | ||||||||
Income from Discontinued OperationsDiluted |
$ | | $ | 0.13 | $ | 0.02 | $ | 4.88 | $ | 0.75 | ||||||||
Net Income (Loss) Attributable to Common StockholdersBasic |
$ | (0.28 | ) | $ | 6.92 | $ | 8.03 | $ | 10.24 | $ | 4.92 | |||||||
Net Income (Loss) Attributable to Common StockholdersDiluted |
$ | (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 OutstandingBasic |
480 | 465 | 465 | 460 | 470 | |||||||||||||
Average Number of Common Shares OutstandingDiluted |
480 | 466 | 467 | 463 | 474 | |||||||||||||
Cash Provided by Operating ActivitiesContinuing Operations |
$ | 3,926 | $ | 6,447 | $ | 2,766 | $ | 4,671 | $ | 3,221 | ||||||||
Cash Provided by (Used in) Operating ActivitiesDiscontinued 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 1Summary 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 Managements 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 |
||
BcfBillion cubic feet |
MMBOEMillion barrels of oil equivalent | |
MBbls/dThousand barrels per day |
MMcf/dMillion cubic feet per day | |
MBOE/dThousand barrels of oil equivalent per day |
TcfTrillion cubic feet | |
MMBblsMillion barrels |
32
Item 7. | Managements 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 worlds 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 Companys operations are located in the United States, Algeria, Brazil, China, Cote dIvoire, 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
Anadarkos 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 worlds 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. Anadarkos exploration success creates value by expanding its future resource potential, while providing the flexibility to manage risk by monetizing discoveries.
Anadarkos global business development approach transfers core skills across the globe to discover and develop world-class resources that are accretive to the Companys 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 Companys 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.
33
OPERATING HIGHLIGHTS
Significant 2009 operational highlights by area include:
United States Onshore
|
The Companys 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 Companys 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 Algerias 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 dIvoire, 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. |
34
The following discussion pertains to Anadarkos 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 Companys results of operations include, among other things, commodity prices for natural gas, crude oil and NGLs, sales volumes, the Companys 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:
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 1Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K. |
(2) |
See Operating ResultsSegment AnalysisAdjusted 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. |
35
FINANCIAL RESULTS
Income (Loss) from Continuing Operations Attributable to Common Stockholders
Anadarkos 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
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 | ||||||
Anadarkos 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
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 Anadarkos 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 | ||||||
36
The following table provides Anadarkos 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
Natural-Gas Sales Volumes, Average Prices and Revenues
2009 |
Inc/(Dec)
vs. 2008 |
2008 |
Inc/(Dec)
vs. 2007 |
2007 | |||||||||||
(Percentages) | (Percentages) | ||||||||||||||
United States |
|||||||||||||||
Sales volumesBcf |
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 |
Bcfbillion cubic feet
MMcf/dmillion cubic feet per day
The Companys 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.
Anadarkos 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.
37
Anadarkos 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 volumesMMBbls |
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 volumesMMBbls |
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 volumesMMBbls |
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 |
MMBblsmillion barrels
MBbls/dthousand barrels per day
Anadarkos 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.
Anadarkos 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. Anadarkos 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.
38
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 volumesMMBbls |
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 Anadarkos natural-gas production. The Companys 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.
Anadarkos 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.
39
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 Companys 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 ResultsDivestitures 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 DOIs 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 Courts 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 Courts denial of the DOIs 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 14ContingenciesDeepwater 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.
40
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 |
NMnot 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 Companys 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
41
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
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 | ||||||||
Anadarkos 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. Anadarkos 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 ResultsDivestitures and Liquidity and Capital ResourcesUses of CashDebt 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 8Derivative 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 | |||||
42
Anadarko enters into interest-rate swaps to reduce its exposure to cash flow variability resulting from interest-rate changes. For additional information see Note 8Derivative 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 Companys 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 Companys 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 Companys 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 Companys 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 Companys 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.
43
Net Income Attributable to Noncontrolling Interests
For the years ended December 31, 2009, and 2008, the Companys 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 AnalysisAdjusted EBITDAX To assess the operating results of Anadarkos 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). Anadarkos 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 Companys definition of Adjusted EBITDAX also excludes interest expense to allow for assessment of segment operating results without regard to Anadarkos financing methods or capital structure. Management believes that the presentation of Adjusted EBITDAX provides information useful in assessing the Companys financial condition and results of operations and that Adjusted EBITDAX is a widely accepted financial indicator of a companys 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, Anadarkos 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 Anadarkos results as reported under GAAP. Below is a reconciliation of consolidated Adjusted EBITDAX to income
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 | ) |
44
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 Companys 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 Anadarkos midstream segments 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 Anadarkos 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 Anadarkos ownership interest in Petroritupano. At this time, Anadarko is unable to determine when the sale to CVP will be completed. Anadarkos investment in Petroritupano is included in other assets at December 31, 2009.
45
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 2Divestitures 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.
46
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 Anadarkos 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 Anadarkos 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 Anadarkos 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. Anadarkos 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 Anadarkos capital spending program, retire debt, pay income taxes, repurchase Anadarko common stock, pay dividends and redeem preferred stock. Anadarkos 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 Anadarkos 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 Companys 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 Companys liquidity and capital resources are discussed in Outlook that follows.
Sources of Cash
Operating Activities Anadarkos 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,
47
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 Companys 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. Anadarkos 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 Companys interest-rate swap agreements, see Note 8Derivative 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 ResultsDivestitures 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 3Noncontrolling 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 Companys 2007 financing activities, see Note 6Investments and Note 10Debt and Interest Expense in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.
48
Uses of Cash
Capital Expenditures The following table presents the Companys capital expenditures relating to continuing operations, by category.
millions | 2009 | 2008 | 2007 | |||||||||
Property acquisitions |
||||||||||||
Explorationunproved |
$ | 279 | $ | 405 | $ | (293 | ) | |||||
Developmentproved |
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. |
Anadarkos 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 Companys acquisition of its office buildings in The Woodlands, Texas. The Companys 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 Companys 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, Anadarkos 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 Companys debt instruments, such as transactions during the period, years of maturity and interest rates, see Note 6Investments, Note 8Derivative Instruments and Note 10Debt 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 Companys 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 1Summary of Significant Accounting Policies and Note 8Derivative 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 Companys 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 Companys debt-to-capitalization ratio must be considered in order to ensure covenant compliance. Based on these covenants, as of December 31, 2009, the Companys 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 Companys 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
Anadarkos 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 worlds health and welfare. Anadarko employs the following strategy to achieve this mission:
|
identify and commercialize resources; |
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explore in high-potential, proven basins; |
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employ a global business development approach; and |
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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. Anadarkos exploration success creates value by expanding its future resource potential, while providing the flexibility to manage risk by monetizing discoveries.
Anadarkos 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 Companys 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 Companys 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 Companys 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 Companys 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 Companys 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 Anadarkos 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 8Derivative 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 Companys $1.6 billion midstream note contains credit-rating-downgrade triggers that would accelerate the maturity of this debt upon a downgrade of the Companys unsecured credit rating to below BB- by Standard and Poors (S&P) or Ba3 by Moodys Investors Service (Moodys). However, at December 31, 2009, the Companys debt was rated BBB- with a stable outlook by S&P and Baa3 with a stable outlook by Moodys. Moreover, the Companys 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 Companys RCA and the issuance of debt or equity securities.
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Credit Risks
Credit risk is represented by Anadarkos exposure to non-payment or non-performance by the Companys customers and counterparties. Generally, non-payment or non-performance results from a customers or counterpartys inability to satisfy obligations. Anadarko monitors the creditworthiness of its customers and counterparties and establishes credit limits according to the Companys 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 Anadarkos reported debt balance, since the notes and the carrying amount of Anadarkos investments in the investees are presented on the consolidated balance sheet on a net basis. The related interest expense on these obligations and Anadarkos equity earnings attributable to its investments in these entities are recorded in other income (expense), net. Note 6Investments 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 Anadarkos 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 Anadarkos 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 Companys 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 |
|||||||||||||||
Principalcurrent debt |
$ | | $ | | $ | | $ | | $ | | |||||
Principallong-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 liabilitiesother for all periods presented. See Note 6Investments 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 8Derivative Instruments under Item 8 of this Form 10-K. |
(3) |
See Note 16Income Taxes in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K. |
(4) |
This table does not include the Companys pension or postretirement benefit obligations. See Note 20Pension 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 13Commitments 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 Anadarkos 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 Companys 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 Companys Ghana operations. Construction of the FPSO is expected to be complete in the first half of 2010. The Companys 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 Anadarkos 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 Companys 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 Companys construction cost obligation. The Companys 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 Companys 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 Companys 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 8Derivative Instruments, Note 10Debt and Interest Expense, Note 13Commitments, and Note 14Contingencies 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 Anadarkos 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 14Contingencies 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 Companys 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 Companys 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 Companys 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 Companys continuing exploration and development programs.
Another portion of the Companys 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 Companys expected future plans for exploration and development could cause an impairment of the Companys 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 activitiesin 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 Companys 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 managements 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 Companys estimates of future net cash flows are inherently imprecise because they reflect managements expectation of future conditions that are often outside of managements control. However, assumptions used reflect a market participants view of long-term prices, costs and other factors, and are consistent with assumptions used in the Companys 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 companys assets and liabilities and tax-related carryforwards at the merger date, although such estimates may
56
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 goodwillimpairment 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 Companys 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 Companys 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 Anadarkos operations.
For the Companys 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 Companys 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 assets 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 managements 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, managements best estimate of fair value is based on the quoted market price of derivatives with similar characteristics or utilizing industry-standard valuation techniques.
The Companys 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 Anadarkos 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 Companys 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 Companys 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 Companys 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 Companys 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. Anadarkos 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%.
58
Rate of compensation increases
The Companys 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 Companys 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 Companys estimates. The Companys 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.
59
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 Companys 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 Companys 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 1Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.
60
Item 7A. | Quantitative and Qualitative Disclosures About Market Risk |
The Companys 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 Companys 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 ResourcesUses of CashMargin Deposits under Part II, Item 7 of this Form 10-K.
For information regarding the Companys accounting policies and additional information related to the Companys derivative and financial instruments, see Note 1Summary of Significant Accounting Policies, Note 8Derivative Instruments and Note 10Debt and Interest Expense in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.
COMMODITY PRICE RISK The Companys 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 Companys oil and gas properties may be required if future commodity prices experience a sustained and significant decline. Below is a sensitivity analysis of the Companys 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 Companys 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 Companys 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 Companys open interest-rate derivative positions, see Note 8Derivative Instruments in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.
61
Item 8. | Financial Statements and Supplementary Data |
ANADARKO PETROLEUM CORPORATION
INDEX
CONSOLIDATED FINANCIAL STATEMENTS
62
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 Companys 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 Companys 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 Companys financial records and related data, as well as the minutes of the stockholders and Directors meetings.
MANAGEMENTS ASSESSMENT OF INTERNAL CONTROL OVER FINANCIAL REPORTING
Management is responsible for establishing and maintaining adequate internal control over financial reporting. Anadarkos internal control system was designed to provide reasonable assurance to the Companys 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 Companys internal control over financial reporting as of December 31, 2009. This assessment was based on criteria established in Internal ControlIntegrated 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 Companys internal control over financial reporting is effective based on those criteria.
KPMG LLP has issued an attestation report on the Companys internal control over financial reporting as of December 31, 2009.
/s/ J AMES T. H ACKETT |
James T. Hackett Chairman and Chief Executive Officer |
/s/ R OBERT G. G WIN |
Robert G. Gwin Senior Vice President, Finance and Chief Financial Officer |
February 23, 2010 |
63
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders
Anadarko Petroleum Corporation:
We have audited Anadarko Petroleum Corporations internal control over financial reporting as of December 31, 2009, based on criteria established in Internal ControlIntegrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) . Anadarko Petroleum Corporations 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 Managements Assessment of Internal Control Over Financial Reporting . Our responsibility is to express an opinion on the Companys 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 companys 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 companys 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 companys 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 ControlIntegrated 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 |
64
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 Companys 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 Corporations internal control over financial reporting as of December 31, 2009, based on criteria established in Internal ControlIntegrated 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 Companys internal control over financial reporting.
/s/ KPMG LLP |
Houston, Texas |
February 23, 2010 |
65
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 stockholdersbasic |
$ | (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 taxesbasic |
$ | | $ | 0.13 | $ | 0.02 | ||||||
Income from discontinued operations, net of taxesdiluted |
$ | | $ | 0.13 | $ | 0.02 | ||||||
Net income (loss) attributable to common stockholdersbasic |
$ | (0.28 | ) | $ | 6.92 | $ | 8.03 | |||||
Net income (loss) attributable to common stockholdersdiluted |
$ | (0.28 | ) | $ | 6.91 | $ | 8.01 | |||||
Average Number of Common Shares OutstandingBasic |
480 | 465 | 465 | |||||||||
Average Number of Common Shares OutstandingDiluted |
480 | 466 | 467 | |||||||||
Dividends (per Common Share) |
$ | 0.36 | $ | 0.36 | $ | 0.36 |
See accompanying notes to consolidated financial statements.
66
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.
67
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.
68
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.
69
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.
70
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 Companys internally developed assumptions used in pricing an asset or liability (for example, an estimate of future cash flows used in the Companys internally developed present value of future cash flows model that underlies the fair-value measurement). |
71
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 managements 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 Companys 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 Companys 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 Companys 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.
72
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 Companys 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 Companys 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 Companys 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.
73
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 propertys 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 Companys 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.
74
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 Companys 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 Companys consolidated subsidiaries and are presented as a component of equity. Changes in Anadarkos 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.
75
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 Companys 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 Anadarkos continuing operations. See Note 2.
Earnings Per Share The Companys 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 Companys 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 Companys accounting for derivatives, but requires enhanced disclosures regarding the Companys 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 Companys 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
76
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 subsidiarys 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 parents 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 Companys 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 Companys 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 Companys 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
77
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 enterprises 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 Companys 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
78
ANADARKO PETROLEUM CORPORATION
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 Anadarkos 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 Companys 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 WESs 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 | ||
79
ANADARKO PETROLEUM CORPORATION
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.
80
ANADARKO PETROLEUM CORPORATION
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
81
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 liabilitiesother 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 Anadarkos interests were 0.78% for Anadarkos interest in the oil and gas investee entity and 0.70% for Anadarkos interests in gathering and processing investee entities. Anadarkos 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 Anadarkos interests, in 2022 and thereafter. Anadarkos interests are mandatorily redeemable in 2037.
The notes issued by Anadarko have 35-year terms and variable LIBOR-based interest rates that fluctuate with Anadarkos 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 Anadarkos 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 Anadarkos 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 Anadarkos 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 Companys 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. Trinitys 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 Investors Class B member interest until its cumulative preferred return is satisfied, with the remaining earnings allocated to Anadarkos Class A member interest. Anadarko
82
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 Anadarkos 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 Companys 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 Anadarkos 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,
83
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 Companys 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 Companys 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 Companys 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 Companys cash flow exposure to commodity price risk inherent in the Companys 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 Companys 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 Companys 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
84
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 Companys 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 | ) | $ | |
MMBtumillion British thermal units
MMBtu/dmillion 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/dthousand 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.
85
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 Companys swap portfolio.
The Companys 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 | % |
86
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2009, 2008 and 2007
8. Derivative Instruments (Continued)
Effect of Derivative InstrumentsBalance 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 InstrumentsStatement of Income The unrealized and realized gain or loss amounts and classification related to derivative instruments not designated as hedging instruments are as follows:
* | 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:
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
87
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 Companys 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 Companys 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 Companys $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 Companys $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 Companys outstanding derivative positions.
Certain of the Companys derivative instruments contain provisions requiring either full or partial collateralization of the Companys obligations, or the immediate settlement of all such obligations in the event of a downgrade in the Companys 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 Companys 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 Companys 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. |
88
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 Anadarkos 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.
89
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 Anadarkos Midstream Subsidiary Note Payable to a Related Party (see following discussion), none of the Companys notes, debentures or credit agreements contain credit-rating-downgrade triggers that result in accelerating debt maturity. All of the Companys 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.
90
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 Anadarkos 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 | ||||||||
91
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 Anadarkos 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 Anadarkos 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 Companys 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 Anadarkos 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 Anadarkos senior unsecured credit rating were to be rated below BB- by Standard and Poors (S&P) or Ba3 by Moodys Investors Service (Moodys). As of December 31, 2009, the Company was in compliance with all covenants, and S&P and Moodys rated the Companys 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, Anadarkos 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.
92
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.
93
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2009, 2008 and 2007
11. Stockholders Equity (Continued)
The changes in the Companys 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 Companys 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 Companys 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 Companys 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.
94
ANADARKO PETROLEUM CORPORATION
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 Companys 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.
95
ANADARKO PETROLEUM CORPORATION
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 | % |
96
ANADARKO PETROLEUM CORPORATION
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 | |||
97
ANADARKO PETROLEUM CORPORATION
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 Companys 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 Companys 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. |
98
ANADARKO PETROLEUM CORPORATION
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 Companys 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 Companys 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 Companys 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 Companys 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.
99
ANADARKO PETROLEUM CORPORATION
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 Companys 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
100
ANADARKO PETROLEUM CORPORATION
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 Companys 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 Companys 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 Companys Ghana operations. Construction of the FPSO is expected to be complete in the first half of 2010, and the Companys 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 Anadarkos 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 Companys 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 Companys 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 Companys 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.
101
ANADARKO PETROLEUM CORPORATION
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 Companys 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 Anadarkos 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 Companys 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 KMOGs 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 DOIs 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 Courts 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.
102
ANADARKO PETROLEUM CORPORATION
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 Anadarkos 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 Courts denial of the DOIs 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 Companys 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-McGees 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 Companys 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 Companys 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 Companys 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.
103
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 Anadarkos 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 Companys 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 governments 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 Companys 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.
104
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 | ) | |||||||
Othernet |
(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. |
105
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 | ) | ||
106
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 receivableother | $ | 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
107
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 Companys 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 Companys 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 Companys total sales revenues.
108
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2009, 2008 and 2007
19. Segment Information
Anadarkos 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 Companys 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 Anadarkos production, as well as production purchased from third parties.
To assess the operating results of Anadarkos 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). Anadarkos 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 Companys definition of Adjusted EBITDAX also excludes interest expense to allow for assessment of segment operating results without regard to Anadarkos financing methods or capital structure. Management believes that the presentation of Adjusted EBITDAX provides information useful in assessing the Companys financial condition and results of operations and that Adjusted EBITDAX is a widely accepted financial indicator of a companys 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 Companys 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.
109
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 Anadarkos 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 | ||||||||
110
ANADARKO PETROLEUM CORPORATION
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 Anadarkos 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 | ||
111
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 Companys 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.
112
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 Companys 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 Companys 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.
113
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 Companys 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
114
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 Companys 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. Anadarkos 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.
115
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 Companys 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 markets perception of the issuers and changes in interest rates.
116
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.
117
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 |
118
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. |
119
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 Companys 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.
120
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 Anadarkos 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 Companys 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.
121
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 |
122
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 Anadarkos infill drilling programs. |
123
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 Companys 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 | |||
124
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 Companys 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. |
125
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 | |||
126
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 | |||
127
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 Anadarkos 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 Companys consolidated financial statements.
128
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 | |||
129
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 | ||||||
130
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
Anadarkos Chief Executive Officer and Chief Financial Officer performed an evaluation of the Companys 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 issuers 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 Companys disclosure controls and procedures are effective as of December 31, 2009.
Managements Annual Report on Internal Control Over Financial Reporting
See Managements 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 Anadarkos internal controls over financial reporting during the fourth quarter of 2009 that materially affected, or are reasonably likely to materially affect, the Companys 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 GovernanceBoard of Directors, Corporate GovernanceCommittees 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 Companys 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 Companys 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 Companys 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.
131
Item 11. | Executive Compensation |
See Corporate GovernanceBoard of DirectorsCompensation and Benefits Committee Interlocks and Insider Participation, Corporate GovernanceBoard of DirectorsDirector Compensation, Corporate GovernanceDirector 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.
132
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 |
133
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 Agreement1999 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 |
134
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, 2004Robert 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 |
135
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 EmploymentR. 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 |
136
| 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 Companys consolidated financial statements.
137
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.
138
Exhibit 10(xxii)
ANADARKO PETROLEUM
CORPORATION
SAVINGS RESTORATION PLAN
(As Amended and Restated Effective January 1, 2007)
ANADARKO PETROLEUM CORPORATION
SAVINGS RESTORATION PLAN
(As Amended and Restated Effective January 1, 2007)
TABLE OF CONTENTS
Page | ||||
ARTICLE I. SCOPE OF PLAN |
1 | |||
1.01 |
Background and Purpose |
1 | ||
1.02 |
Sources of Payments |
2 | ||
ARTICLE II. DEFINITIONS |
2 | |||
2.01 |
Account |
2 | ||
2.02 |
Affiliate |
3 | ||
2.03 |
Beneficiary |
3 | ||
2.04 |
Board |
3 | ||
2.05 |
Code |
3 | ||
2.06 |
Code Limits |
3 | ||
2.07 |
Committee |
3 | ||
2.08 |
Company |
3 | ||
2.09 |
Company Stock |
3 | ||
2.10 |
Contribution Rate |
3 | ||
2.11 |
ERISA |
4 | ||
2.12 |
Effective Date |
4 | ||
2.13 |
Eligible Employee |
4 | ||
2.14 |
Employee |
4 | ||
2.15 |
Employer |
4 | ||
2.16 |
Fund |
4 | ||
2.17 |
Investment Experience |
4 | ||
2.18 |
Key Employee |
4 | ||
2.19 |
Participant |
4 | ||
2.20 |
Plan |
4 | ||
2.21 |
Plan Year |
4 | ||
2.22 |
Post-2004 KMG Plan Benefits Account |
4 | ||
2.23 |
Post-2004 Savings Restoration Plan Account |
5 | ||
2.24 |
Pre-2005 KMG Plan Benefits Account |
5 | ||
2.25 |
Pre-2005 Savings Restoration Plan Account |
5 | ||
2.26 |
Savings Plan |
5 | ||
2.27 |
Separation from Service |
5 | ||
2.28 |
Valuation Date |
5 | ||
ARTICLE III. ELIGIBILITY AND PARTICIPATION |
5 | |||
ARTICLE IV. AMOUNT OF BENEFITS |
5 | |||
4.01 |
Post-2004 Savings Restoration Plan Account |
5 |
i
4.02 |
Pre-2005 Savings Restoration Plan Account |
6 | ||
4.03 |
Post-2004 and Pre-2005 KMG Plan Benefits Accounts |
6 | ||
ARTICLE V. HYPOTHETICAL INVESTMENT OPTIONS |
7 | |||
5.01 |
Investment of Account in Investment Funds |
7 | ||
5.02 |
No Warranties |
8 | ||
ARTICLE VI. PAYMENT OF BENEFITS |
8 | |||
6.01 |
Payment of Participants Account |
8 | ||
6.02 |
Six-Month Delay |
8 | ||
6.03 |
Vesting |
9 | ||
ARTICLE VII. ADMINISTRATION |
9 | |||
7.01 |
Administration by Committee |
9 | ||
7.02 |
Administration of Plan |
9 | ||
7.03 |
Action by Committee |
9 | ||
7.04 |
Delegation |
9 | ||
7.05 |
Reliance Upon Information |
9 | ||
7.06 |
Rules of Conduct |
10 | ||
7.07 |
Legal, Accounting, Clerical and Other Services |
10 | ||
7.08 |
Indemnification |
10 | ||
7.09 |
Claims Review Procedures |
10 | ||
7.10 |
Finality of Determinations; Exhaustion of Remedies |
13 | ||
7.11 |
Effect of Committee Action |
13 | ||
7.12 |
Effect of Mistake |
14 | ||
ARTICLE VIII. GENERAL PROVISIONS |
14 | |||
8.01 |
Plan Amendment, Suspension and/or Termination |
14 | ||
8.02 |
Plan Not an Employment Contract |
15 | ||
8.03 |
Non-alienation of Benefits |
15 | ||
8.04 |
Special Payment Situations |
15 | ||
8.05 |
Spin-offs |
16 | ||
8.06 |
Duty to Provide Data |
16 | ||
8.07 |
Tax Consequences Not Guaranteed |
17 | ||
8.08 |
Tax Withholding |
17 | ||
8.09 |
Incompetency |
17 | ||
8.10 |
Severability |
17 | ||
8.11 |
Governing Law |
17 | ||
8.12 |
Headings |
18 |
ii
ANADARKO PETROLEUM CORPORATION
SAVINGS RESTORATION PLAN
ARTICLE I.
SCOPE OF PLAN
1.01 Background and Purpose . This Anadarko Petroleum Corporation Savings Restoration Plan (the Plan ) was originally established by Anadarko Petroleum Corporation (the Company ) effective as of January 1, 1995. The Company amended the Plan effective as of January 29, 1998, to add a change of control provision, and as of January 1, 2005, to reflect certain design changes thereto. The Plan has not since been amended.
Effective as of August 10, 2006, the Company acquired Kerr-McGee Corporation ( KMG ). KMG had previously sponsored the Kerr-McGee Corporation Benefits Restoration Plan (the KMG Plan ). The KMG Plan provided benefits that were not payable to eligible employees under its qualified defined contribution plan and its qualified defined benefit pension plan due to benefit limitations under the Internal Revenue Code of 1986, as amended (the Code ). Effective as of January 1, 2007, the Company, acting pursuant to authority granted under the KMG Plan, spun off and transferred from the KMG Plan the portion of the KMG Plan representing benefits attributable to eligible employees under its qualified defined contribution plan (the KMG Plan Benefits ) and merged such portion of the KMG Plan with and into the Plan, with the Plan being the survivor.
The Company hereby amends and restates the Plan under the form of this document generally effective as of January 1, 2007 except as otherwise noted herein (hereafter, the term Plan shall refer to this plan document), primarily for the purposes of (i) incorporating changes required by Code Section 409A, effective as of January 1, 2005, (ii) designating certain amounts held under the Plan as being exempt from the requirements of Code Section 409A as effective January 1, 2005, (iii) incorporating provisions to reflect the spin-off and transfer of the KMG Plan Benefits into the Plan effective as of January 1, 2007, and (iv) incorporating certain other design changes into the Plan.
The Company intends that this amendment and restatement does not constitute a material modification within the meaning of such term under Code Section 409A with respect to (i) amounts held under the Plan prior to January 1, 2005 that qualify as exempt from Code Section 409A and (ii) all balances transferred to the Plan pursuant to the spin-off and transfer of the KMG Plan Benefits with and into the Plan effective as of January 1, 2007. To the extent that any amendments incorporated into this amended and restated Plan document are required for compliance with Code Section 409A as generally effective January 1, 2005, such amendments shall be effective as of January 1, 2005 or as of such other date that is required by Code Section 409A as provided herein.
With respect to Eligible Employees who receive allocations under the Plan as a result of exceeding the Code Limits (as defined herein) due to the application of Code Section 401(a)(17), the Plan is intended as an unfunded plan to be maintained primarily for the purpose of providing deferred compensation for a select group of management or highly compensated employees within the meaning of such phrase for purposes of Sections 201(2), 301(a)(3) and 401(a)(1) of the Employee Retirement Income Security Act of 1974, as amended ( ERISA ), and as such it is
intended that the Plan be exempt from the participation and vesting, funding, and fiduciary responsibility requirements of Title I of ERISA. The Plan is also intended to qualify for simplified reporting under U.S. Department of Labor Regulation Section 2530.104-23, which provides for an alternative method of compliance for plans described in such regulation. With respect to Eligible Employees who are entitled to receive allocations under the Plan as a result of exceeding the Code Limits due to the application of Code Section 415, that portion of the Plan is intended to be an excess benefit plan within the meaning of such phrase for purposes of Sections 3(36) and 4(b)(5) of ERISA. Moreover, the Plan is intended to comply with the requirements of Code Section 409A for nonqualified deferred compensation plans to the extent applicable. The Plan is not intended to satisfy the tax qualification requirements of Code Section 401(a).
1.02 Sources of Payments . Benefits provided by the Plan constitute general obligations of the Company and shall at all times be subject to the claims of the general creditors of the Company, in accordance with the terms hereof. No amounts in respect of such benefits shall be set aside or held in trust, and no recipient of any benefits shall have any right to have the benefit paid out of any particular assets of the Company; provided, however, nothing herein shall be construed to prevent a transfer of funds to a grantor trust for the purpose of paying any benefits under the Plan.
Any grantor trust established by the Company for benefits under the Plan shall be subject to the claims of the Companys general and unsecured creditors in the event that the Company becomes insolvent. The Company intends that any such grantor trust shall constitute an unfunded arrangement and thus not affect the status of the Plan as an unfunded plan that is maintained to provide deferred compensation for a select group of management or highly compensated employees for purposes of Title I of ERISA.
Benefits payable to Participants and their Beneficiaries under the Plan cannot be anticipated, assigned (either at law or in equity), alienated, pledged or encumbered, or subjected to attachment, levy, execution or other legal or equitable process.
ARTICLE II.
DEFINITIONS
The masculine gender when used in the Plan shall be deemed to include the feminine gender, and the single shall include the plural and vice versa, unless the context clearly indicates to the contrary. Where capitalized words and phrases appear in this Plan, they shall have the respective meanings set forth below.
2.01 Account . Account means, with respect to a Participant, all of the ledger accounts maintained by the Committee under the Plan to set out such Participants proportionate interest in the Plan. The following accounts shall be established for each Participant as applicable:
(a) Pre-2005 Savings Restoration Plan Account;
(b) Post-2004 Savings Restoration Plan Account;
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(c) Pre-2005 KMG Plan Benefits Account; and
(d) Post-2004 KMG Plan Benefits Account.
2.02 Affiliate . Affiliate means:
(a) Any corporation other than the Company ( i.e. , either a subsidiary corporation or an affiliated or associated corporation of the Company), which together with the Company is a member of a controlled group of corporations pursuant to Code Section 414(b);
(b) Any organization with which the Company is under common control pursuant to Code Section 414(c);
(c) Any organization which together with the Company is an affiliated service group pursuant to Code Section 414(m); or
(d) Any foreign affiliate of the Company which is covered by an agreement under Code Section 3121(l) pursuant to Code Section 406(a).
2.03 Beneficiary . Beneficiary means the recipients of any benefit payable under the Plan in the event of such Participants death. The Participant shall not have the right to designate a beneficiary under the Plan; rather the Participants Beneficiary hereunder shall be the same as his designated beneficiary under the Savings Plan.
2.04 Board . Board means the then Board of Directors of the Company or any designated committee of the Board, such as the Compensation and Benefits Committee, that is duly authorized by the Board to act under the Plan.
2.05 Code . Code means the Internal Revenue Code of 1986, as amended, and regulations and other authority issued thereunder by the appropriate governmental authority. References to any section of the Code or the regulations thereunder shall include reference to any successor section or provision of the Code or regulations, as applicable.
2.06 Code Limits . Code Limits means either a limitation imposed under Code Section 401(a)(17) or under Code Section 415 with respect to the amount of compensation or benefits which may be earned or taken into account, as applicable, under the Savings Plan.
2.07 Committee . Committee means the persons appointed by the Board to administer the Plan in accordance with Article VII .
2.08 Company . Company means Anadarko Petroleum Corporation, or any successor in interest thereto.
2.09 Company Stock . Company Stock means the common stock, par value $0.10, of the Company.
2.10 Contribution Rate . Contribution Rate means the combined before-tax and after-tax contribution rate that a Participant has elected under the Savings Plan.
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2.11 ERISA . ERISA means the Employee Retirement Income Security Act of 1974, as amended. References to any section of ERISA or the regulations thereunder shall include reference to any successor section of ERISA or regulations, as applicable.
2.12 Effective Date . Effective Date means January 1, 2007, the effective date of the amendment and restatement of the Plan.
2.13 Eligible Employee . Eligible Employee means any Employee who is currently participating in the Savings Plan and whose benefits under the Savings Plan are reduced or limited by the Code Limits and/or as a result of deferring compensation pursuant to any deferred compensation plan maintained by an Employer and designated by the Company as a deferred compensation plan for purposes of the Plan. Any Eligible Employee who exceeds the Code Limits due to the application of Code Section 401(a)(17) must be a member of a select group of management or highly compensated employees for purposes of Title I of ERISA, as determined by the Board or the Committee.
2.14 Employee . Employee means each person who is employed by one or more Employers, is on an Employers payroll and classified as a regular employee, and whose wages are subject to FICA tax withholding.
2.15 Employer . Employer means the Company and any Affiliate which adopts the Plan in accordance with its applicable provisions. The adopting Employers are listed in the Adopting Employers Appendix which is attached to the Plan, as such Appendix may be updated by the Committee from time to time without the need for a formal amendment to the Plan.
2.16 Fund . Fund means any mutual fund or any Company Stock fund designated by the Committee for the deemed investment of Account balances pursuant to Article V .
2.17 Investment Experience . Investment Experience means the hypothetical amounts credited (as earnings, gains or appreciation on any hypothetical investments in Funds or other permitted investment measures) or charged (as losses or depreciation on any such hypothetical investments) to the Participants Account balance pursuant to Article V .
2.18 Key Employee . Key Employee means an employee of an Employer who is treated as a Specified Employee under Code Section 409A(a)(2)(B)(i).
2.19 Participant . Participant means an Eligible Employee who meets the requirements to participate in the Plan in accordance with Article III .
2.20 Plan . Plan means the Anadarko Petroleum Corporation Savings Restoration Plan, as it may be amended from time to time.
2.21 Plan Year . Plan Year means the 12-month calendar year beginning on January 1 st and ending on December 31 st .
2.22 Post-2004 KMG Plan Benefits Account . Post-2004 KMG Plan Benefits Account means the separate account under the Participants Account as established pursuant to Section 4.03 .
4
2.23 Post-2004 Savings Restoration Plan Account . Post-2004 Savings Restoration Plan Account means the separate account under the Participants Account as established pursuant to Section 4.01 .
2.24 Pre-2005 KMG Plan Benefits Account . Pre-2005 KMG Plan Benefits Account means the separate account under the Participants Account as established pursuant to Section 4.03 .
2.25 Pre-2005 Savings Restoration Plan Account . Pre-2005 Savings Restoration Plan Account means the separate account under the Participants Account as established pursuant to Section 4.02 .
2.26 Savings Plan . Savings Plan means the Anadarko Employee Savings Plan, as it may be amended from time to time, which Savings Plan is intended to be a 401(k) plan that is qualified under Code Section 401(a).
2.27 Separation from Service . Separation from Service means a separation from service within the meaning of Code Section 409A.
2.28 Valuation Date . Valuation Date means the date on which a Participants Account balance is valued, which date shall be not less often than as of the last day of each calendar quarter during the Plan Year, as well as any interim date as determined by the Committee or Company in its discretion.
ARTICLE III.
ELIGIBILITY AND PARTICIPATION
Any Eligible Employee whose benefits under the Savings Plan are subject to the Code Limits shall be eligible to participate in the Plan; provided, however, an Eligible Employee may be a Participant only if (a) such Employee is participating in the Savings Plan and his compensation or benefits under the Savings Plan are limited by the Code Limits, and (b) the Committee determines that such Employee is an Eligible Employee who is a member of a select group of management or highly compensated employees of the Company or its Affiliates for purposes of Title I of ERISA.
ARTICLE IV.
AMOUNT OF BENEFITS
4.01 Post-2004 Savings Restoration Plan Account . Effective as of January 1, 2005, the Company shall establish a separate account under the Account for each affected Participant, entitled the Post-2004 Savings Restoration Plan Account . The Participants Post-2004 Savings Restoration Plan Account shall be credited with any amount of the Participants Restoration Account balance held under the Plan as of December 31, 2004 that was not vested as of December 31, 2004, as well as any contributions made on such Participants behalf on and after January 1, 2005.
5
With respect to each Plan Year beginning on and after January 1, 2005, the Committee shall credit to the Participants Post-2004 Savings Restoration Plan Account an amount equal to the excess, if any, of (a) over (b), where:
(a) equals the Company Matching Contributions which would have been allocated to such Participants account under the Savings Plan if the Savings Plan had been administered without regard to (i) the Code Limits and (ii) any elective salary and/or bonus compensation arrangement maintained by an Employer which has been designated by the Company as a deferred compensation plan for purposes of the Plan; and
(b) equals the amount of Company Matching Contributions which were in fact allocated for such Plan Year to the account of such Participant under the Savings Plan (without regard to earnings thereon).
In determining the amount to be credited to a Participants Post-2004 Savings Restoration Plan Account for any Plan Year, the following rules are applicable:
(x) the Participant shall only be entitled to allocations to his Post-2004 Savings Restoration Plan Account if he was making elective contributions to the Savings Plan for such Plan Year;
(y) the Participants Contribution Rate at the time the Code Limits are reached shall be the rate the Plan utilizes to determine the Participants benefit under the Plan; and
(z) the Participants compensation shall be deemed to be his Base Compensation as determined under the Savings Plan, but without regard to the dollar limit under Code Section 401(a)(17) as in effect for the Plan Year.
4.02 Pre-2005 Savings Restoration Plan Account . Effective as of January 1, 2005, the Company shall establish for each affected Participant a separate account under the Account, entitled the Pre-2005 Savings Restoration Plan Account . The Company shall credit to the Pre-2005 Savings Restoration Plan Account the total value of the Participants account balance held under the Plan as of December 31, 2004, and such Account shall share in allocated Investment Experience after such date. The Participants Pre-2005 Savings Restoration Plan Account is intended by the Company to be credited only with amounts that are considered to be earned and vested not later than December 31, 2004, within the meaning of Code Section 409A, and thus not subject to Section 409A. No additional contributions shall be made to the Participants Pre-2005 Savings Restoration Plan Account after December 31, 2004.
4.03 Post-2004 and Pre-2005 KMG Plan Benefits Accounts . With respect to benefits spun-off from the KMG Plan, the Company shall establish two separate accounts for each affected Participant, one entitled the Post-2004 KMG Plan Benefits Account and the other entitled the Pre-2005 KMG Plan Benefits Account . The Pre-2005 KMG Plan Benefits Account shall include the total value of the Participants KMG Plan Benefits held under the KMG Plan as of December 31, 2004, including allocable Investment Experience thereon after December 31, 2004. The Post-2004 KMG Plan Benefits Account shall include the total value of the Participants KMG Plan Benefits with respect to contributions made on the Participants
6
behalf on and after January 1, 2005 and until January 1, 2007, including allocable Investment Experience thereon. The Participants Pre-2005 KMG Plan Benefits Account is intended by the Company to be credited only with amounts that are considered to be earned and vested not later than December 31, 2004, within the meaning of Code Section 409A, and thus not subject to Section 409A. To the extent that the amount of a Participants KMG Plan Benefits would not have been considered earned and vested as of December 31, 2004, such amount shall be considered part of the Participants Post-2004 KMG Plan Benefits Account. Any benefits accrued on and after January 1, 2007 for a Participant who was participating in the KMG Plan as of December 31, 2006, shall be credited to such Participants Post-2004 Savings Restoration Plan Account in accordance with the methodology established in Section 4.01 .
ARTICLE V.
HYPOTHETICAL INVESTMENT OPTIONS
5.01 Investment of Account in Investment Funds . The Committee, in its discretion, may permit all Participants to request that their entire Account balances (vested and unvested) be invested in any one or a combination of Funds which have been selected and designated by the Committee as being available for hypothetical investments under the Plan. If a Participant does not elect to invest all or any portion of his Account balance in Funds, the portion of such Account balance that is not directed by the Participant for investment shall automatically be deemed to be invested in the default Fund investment option selected by the Committee. All investments hereunder shall be considered assets of the Company, and the Participant shall remain subject to all applicable provisions of the Plan including, without limitation, Section 1.02 .
The Investment Experience posted and credited to each Participants Account shall be based solely on the Investment Experience of the actual Funds in which the Participants Account balance is deemed to be invested. Investment Experience shall be promptly posted and credited to the Participants Account by the Company as of each Valuation Date .
As authorized by the Committee, each Participant shall have the right to elect hypothetical investments of his Account balance. The Committee (or its delegate) shall prescribe such procedures as it considers necessary to direct the deemed investment of the Participants Account balances. Each Participants Account shall be credited or debited with the increase or decrease in the realizable net asset value of the designated Funds in which such Account balance is deemed to be invested.
Subject to such limitations as may from time to time be required by law, imposed by the Committee or contained elsewhere in the Plan, and subject to such operating rules and procedures as may be imposed from time to time by the Committee, each Participant may communicate requests regarding the deemed investment of his Account balance between and among the designated Funds. Investment directions shall designate the percentage (in any whole percent multiples) of the Participants Account balance that is requested for investment in such Funds, subject to the following rules:
(a) All amounts credited to the Participants Account shall be deemed to be invested in accordance with the Participants then-effective investment
7
direction. As of the effective date of any accepted new investment request, the Participants Account balance at that date shall be reallocated among the designated Funds according to the percentages specified in the new investment request unless and until a subsequent investment request becomes effective.
(b) If the Committee (or its delegate) receives an initial or revised investment request that it deems to be incomplete, unclear, or improper, the Participants investment request then in effect shall remain in effect (or, in the case of a deficiency in an initial investment direction, the Participant shall be deemed to have invested in the designated Fund that is a money market mutual fund), unless the Committee (or its delegate) permits the application of corrective action prior thereto.
(c) If the Committee (or its delegate) possesses at any time directions as to the deemed investment of less than all of a Participants Account, the Participant shall be deemed to have requested that the undesignated portion of his Account balance be deemed for investment in the designated Fund that is a money market mutual fund.
(d) Each Participant, as a condition to his participation in the Plan, agrees to indemnify and hold harmless the Company and the Committee, and their representatives, delegates and agents, from and against any investment losses or damages of any kind relating to, or arising out of, the deemed investment of the Participants Account balance under the Plan.
No assurances are provided by any person or entity that any investment results will be favorable and, as with most investments, there is a risk of loss. All investment earnings or losses resulting from the Participants deemed investments shall be periodically posted to his Account by the Company as allocable Investment Experience.
5.02 No Warranties . The Board, Committee, Employer and officers of the Employer do not warrant or represent in any respect that the value of any Participants Account will increase and not decrease. Each Participant assumes all related investment risk in connection with any change in value.
ARTICLE VI.
PAYMENT OF BENEFITS
6.01 Payment of Participants Account . Payment of any Participants Account balance shall be made at one time (in the form of a lump-sum payment) within ninety (90) days following the Participants Separation from Service.
6.02 Six-Month Delay . Notwithstanding any provision herein to the contrary, distributions with respect to the portion of a Key Employees Post-2004 Savings Restoration Plan Account and Post-2004 KMG Plan Benefits Account shall not be made to a Key Employee upon his Separation from Service before the date which is six months after the date of such Separation from Service (or, if earlier, the date of death of the Key Employee).
8
6.03 Vesting . A Participant shall be 100% vested in his entire Account at all times.
ARTICLE VII.
ADMINISTRATION
7.01 Administration by Committee . The Committee shall, unless otherwise determined by the Board, administer the Plan and its operations. The Committee shall be the plan administrator with respect to the Plan.
The Committee shall be comprised of such officers or other Employees as chosen by the Board to constitute the Committee. Each member of the Committee shall serve at the discretion of the Board, and the Board may remove or replace a member of the Committee at any time pursuant to procedures established by the Board. A member of the Committee may also be a Participant; provided, however, such member shall not vote or otherwise act on any matter relating solely to himself.
The members of the Committee shall not receive any special compensation for serving in their capacities as members, but shall be reimbursed by the Company for any reasonable expenses incurred in connection therewith. No bond or other security need be required of the Committee or any member thereof.
7.02 Administration of Plan . The Committee shall operate, administer, interpret, construe and construct the Plan, including correcting any defect, supplying any omission or reconciling any inconsistency. The Committee shall have all powers necessary or appropriate to implement and administer the terms and provisions of the Plan, including the power to make findings of fact. The determination of the Committee as to the proper interpretation, construction, or application of any term or provision of the Plan shall be final, binding, and conclusive with respect to all interested persons.
7.03 Action by Committee . A majority of the members of the Committee shall constitute a quorum for the transaction of business, and the vote of a majority of those members present at any meeting at which a quorum is present shall decide any question brought before the meeting and shall be the act of the Committee. In addition, the Committee may take any other action otherwise proper under the Plan by an affirmative vote, taken without a meeting, of a majority of its members.
7.04 Delegation . The Committee may, in its discretion, delegate one or more of its duties to its designated agents including, without limitation, to Employees.
7.05 Reliance Upon Information . No member of the Committee shall be liable for any decision, action, omission, or mistake in judgment, provided that he acted in good faith in connection with administration of the Plan. Without limiting the generality of the foregoing, any decision or action taken by the Committee in reasonable reliance upon any information supplied to it by the Board, any Employee, the Employer, the Employers legal counsel, or the Employers independent accountants, shall be deemed to have been taken in good faith.
9
The Committee may consult with legal counsel, who may be counsel for the Employer or other counsel, with respect to its obligations or duties hereunder, or with respect to any action, proceeding or question at law, and shall not be liable with respect to any action taken, or omitted, in good faith pursuant to the advice of such counsel.
7.06 Rules of Conduct . The Committee shall adopt such rules for the conduct of its business and the administration of the Plan as it considers desirable, provided they do not conflict with the provisions of the Plan.
7.07 Legal, Accounting, Clerical and Other Services . The Committee may authorize one or more of its members or any agent to act on its behalf, and may contract for legal, accounting, clerical and other services to effectuate its duties under the Plan. The Committee shall keep records reflecting its administration of the Plan, which shall be subject to review or audit by the Company at any time. The Company shall pay all the expenses of the Committee and the other expenses of administering the Plan.
7.08 Indemnification . The officers and directors of the Company, the members of the Committee, and any Employees who have been assigned duties hereunder regarding administration of the Plan, shall each be indemnified and held harmless by the Company from and against (a) any and all losses, costs, liabilities, or expenses (including reasonable attorneys fees) that may be imposed upon or reasonably incurred by any such person in connection with, or resulting from, any claim, action, suit, or other proceeding to which he is or may be a party, or in which he is or may otherwise be involved, by reason of any action or failure to act under the Plan, and (b) any and all amounts paid by such person in settlement with the Companys written approval, or paid in satisfaction of a judgment in any such action, suit, or other proceeding; provided, however, the foregoing indemnification provisions shall not be applicable to any indemnified person if the loss, cost, liability, or expense is due to such persons fraud, gross negligence or willful misconduct.
7.09 Claims Review Procedures
(a) Filing a Claim . A Participant or his authorized representative hereafter Claimant ) may file a claim for benefits under the Plan by filing a written claim, identified as a claim for benefits, with the Committee. In addition, the Committee may treat any writing or other communication received by it as a claim for benefits, even if the writing or communication is not identified as a claim for benefits.
(b) Acknowledgement of Receipt of Claim . The Committee will send the Claimant a letter acknowledging the receipt of any communication that it treats as a claim for benefits. If the Claimant fails to receive such an acknowledgement within 60 days after making a claim, the Claimant should contact the Committee to determine whether the claim has been received and identified as a claim for benefits.
10
(c) Approval of Claim . A claim is considered approved only if its approval is communicated in writing to a Claimant. If a Claimant does not receive a response to a claim for benefits within the applicable time period, the Claimant may proceed with an appeal under the procedures described in Section 7.09(e) .
(d) Denial of Claim . If a claim is denied in whole or in part, the Committee will notify the Claimant of its decision by written notice, in a manner calculated to be understood by the Claimant.
(1) Timing of Notice . The notice of denial must be given within 90 days after the claim is received by the Committee. If special circumstances (such as a hearing) require a longer period, the Claimant will be notified in writing, before the expiration of the 90-day period, of the expected decision date and the reasons for an extension of time; provided, however, that no extensions will be permitted beyond 90 days after expiration of the initial 90-day period.
(2) Content of Notice . The notice will set forth:
(A) the specific reasons for the denial of the claim;
(B) a reference to specific provisions of the Plan on which the denial is based;
(C) a description of any additional material or information necessary to perfect the claim and an explanation of why such material or information is necessary; and
(D) an explanation of the procedure for review of the denied or partially denied claim, including the Claimants right to bring a civil action under ERISA Section 502(a) following an adverse benefit determination on review.
(e) Request for Review of Denial . Upon denial of a claim in whole or in part, a Claimant has the right to submit a written request to the Committee for a full and fair review of the denied claim, and upon request and free of charge, to reasonable access and copies of all documents, records, and other information relevant to the Claimants claim for benefits and may submit issues and comments in writing.
(1) Scope of Review . The review takes into account all comments, documents, records, and other information submitted by the Claimant relating to the claim, without regard to whether such information was submitted or considered in the initial benefit determination.
(2) Timing of Request for Review . A request for review of a claim must be submitted within 60 days of receipt by the Claimant of written notice of the denial of the claim (or, if the Claimant has not
11
received a response to the initial claim, within 150 days of the filing of the initial claim). If the Claimant fails to file a request for review within 60 days of the denial notification (or deemed denial after 150 days), the claim under the Plan is forever abandoned and the Claimant is precluded from reasserting it.
(3) Contents of Request for Review . If the Claimant files a request for review, his request must include a description of the issues and evidence he deems relevant. Failure to raise issues or present evidence on review will preclude those issues or evidence from being presented in any subsequent proceeding or judicial review of the claim.
(f) Denial Upon Review .
(1) Timing of Denial Notice . The Committee must render its decision on the review of the claim no more than 60 days after the Committees receipt of the request for review, except that this period may be extended for an additional 60 days if the Committee determines that special circumstances (such as a hearing) require such extension. If an extension of time is required, written notice of the expected decision date and the reasons for the extension will be furnished to the Claimant before the end of the initial 60-day period.
(2) Contents of Denial . If the Committee issues a negative decision, it shall provide a prompt written decision to the Claimant setting forth:
(A) the specific reason or reasons for the adverse determination;
(B) a reference to specific Plan provisions on which the adverse determination was made;
(C) a statement that the Claimant is entitled to receive, upon request and free of charge, reasonable access to, and copies of, all documents, records, and other information relevant to the Claimants claim for benefits; and
(D) a statement describing any voluntary appeal procedures offered by the Plan and the Claimants right to obtain the information about such procedures and a statement of the Claimants right to bring an action under ERISA Section 502(a).
(3) Authority of Committee . To the extent of its responsibility to review the denial of benefit claims, the Committee has full authority to interpret and apply in its discretion the provisions of the Plan. The decision of the Committee is final and binding upon any and all Claimants and any person making a claim through or under them.
12
(g) Limits on Right to Judicial Review . A Claimant must follow the claims procedures described by this Section 7.09 before taking action in any other forum regarding a claim for benefits under the Plan. Any lawsuit or other legal action that is initiated by a Claimant under the Plan must be brought by the Claimant no later than one (1) year following a final decision on the claim for benefits under these claims procedures. The one-year statute of limitations on causes of action for benefits applies in any forum where a Claimant initiates such action. If a civil action is not filed within this period, the Claimants benefit claim is deemed permanently waived and abandoned.
(h) Other Claims . Any other claims that arise under or in connection with the Plan, even though not claims for benefits, must be filed with the Committee and are considered in accordance with the claims and appeals procedures in this Section 7.09 .
7.10 Finality of Determinations; Exhaustion of Remedies . To the extent permitted by law, decisions reached under the claims procedures set forth in Section 7.09 shall be final and binding on all Claimants and other interested persons and entities. No legal action for benefits under the Plan shall be brought unless and until the Claimant has exhausted his remedies under Section 7.09 . In any such legal action, the Claimant may only present evidence and theories which the Claimant presented during the claims procedures under Section 7.09 . Any claims which the Claimant does not in good faith pursue though the review stage of these procedures shall be treated as having been irrevocably waived. Judicial review of a Claimants denied claim shall be limited to a determination of whether the denial was an abuse of discretion based only on the evidence and theories that the Claimant presented during the claims procedure.
7.11 Effect of Committee Action . The Plan shall be interpreted by the Committee in accordance with its terms and provisions. The Committee has the reserved discretion under the Plan to make any findings of fact it deems necessary or appropriate in the administration of the Plan, and shall have the discretion to interpret or construe ambiguous, unclear or implied (but omitted) terms in any fashion it deems to be appropriate in its sole judgment. The validity of any such finding of fact, interpretation, construction or decision shall not be given de novo review if challenged in court, by arbitration or in any other forum, and shall be upheld unless clearly arbitrary or capricious. To the extent the Committee has been granted discretionary authority under the Plan, the Committees prior exercise of such authority shall not obligate it to exercise its authority in a like fashion thereafter. If, due to errors in drafting, any Plan provision does not accurately reflect its intended meaning, as demonstrated by consistent interpretations or other evidence of intent, or as determined by the Committee in its sole and exclusive judgment, the provision shall be considered ambiguous and shall be interpreted by the Committee in a fashion consistent with its intent, as determined by the Committee in its sole discretion. The Committee, without the need for the Boards approval, may amend the Plan retroactively to cure any such ambiguity as deemed necessary or appropriate by the Committee. This Section 7.11 may not be invoked by any Claimant or other person to require the Plan to be interpreted in a manner which is inconsistent with its interpretation by the Committee. All actions taken and all determinations made in good faith by the Committee shall be final and binding upon all Claimants and other persons claiming any interest in or under the Plan.
13
7.12 Effect of Mistake . If, in the sole opinion of the Committee, a mistake occurred affecting (a) the eligibility of an Eligible Employee or a Participant or (b) the amount of benefit payments to, or on behalf of, a Participant or Claimant, the Committee shall, to the extent it deems appropriate and practicable, cause an adjustment to be made to correct such mistake.
ARTICLE VIII.
GENERAL PROVISIONS
8.01 Plan Amendment, Suspension and/or Termination . The Board may, in its discretion, from time to time, amend, suspend or terminate in whole or in part, and if terminated, reinstate any or all of the provisions of the Plan, except that no amendment, suspension or termination may apply so as to decrease the payment to any Participant (or Beneficiary) of any benefit under this Plan accrued prior to the effective date of such amendment, suspension or termination. The Committee may amend the Plan as prescribed in Section 7.11 .
Upon termination of the Plan, distribution of benefits shall be made to Participants and Beneficiaries in the manner and at the time described in the Plan, unless one of the following termination events occurs, in which case, all such amounts shall be distributed in a lump sum upon termination, or upon the earliest date allowable under Code Section 409A: (1) the Companys termination and liquidation of the Plan within 12 months of a corporate dissolution taxed under Code Section 331, or with the approval of a bankruptcy court pursuant to 11 U.S.C. Section 503(b)(1)(A); (2) the Companys termination and liquidation of the Plan pursuant to irrevocable action taken by the Company within the 30 days preceding or 12 months following a change in control event (within the meaning of Code Section 409A), provided that all agreements, methods, programs, and other arrangements sponsored by the Company that are aggregated under Code Section 409A are terminated and liquidated with respect to each Participant that experiences the change in control event; or (3) the Companys termination and liquidation of the Plan, provided that (a) the termination and liquidation does not occur proximate to a downturn in the financial health of the Company, (b) the Company terminates and liquidates all agreements, methods, programs, and other arrangements sponsored by the Company that would be aggregated under Code Section 409A if the same Participant had deferrals of compensation under all of the agreements, methods, programs, and other arrangements sponsored by the Company that are terminated and liquidated, (c) no payments in liquidation of the Plan are made within 12 months of the date the Company takes all necessary action to irrevocably terminate and liquidate the Plan other than payments that would have been payable absent the termination and liquidation, (d) all payments are made within 24 months of the date the Company takes all necessary action to irrevocably terminate and liquidate the Plan, and (e) the Company does not adopt a new plan that would be aggregated with any terminated and liquidated plan under Code Section 409A if the same Participant participated in both plans, at any time within three years following the date the Company takes all necessary action to irrevocably terminate and liquidate the Plan.
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8.02 Plan Not an Employment Contract . The Plan is strictly a voluntary undertaking on the part of the Company and does not constitute a contract of employment between the Company or its Affiliates and any Eligible Employee, or consideration for, or an inducement or condition of, the employment of an Eligible Employee. Nothing contained in the Plan shall give any Eligible Employee the right to be retained in the service of the Company or its Affiliates or to interfere with or restrict the right of the Company or its Affiliates, which is hereby expressly reserved, to discharge or retire any Eligible Employee at any time for any reason not prohibited by law, without the Company or its Affiliates being required to show cause for the termination. Participation in the Plan shall not give any Eligible Employee any right or claim to any benefit hereunder except to the extent such right has specifically become fixed under the terms of the Plan. The doctrine of substantial performance shall have no application to Eligible Employees, Participants or Beneficiaries.
8.03 Non-alienation of Benefits . Except as provided in this Section 8.03 and to the extent permitted by law, benefits payable under the Plan shall not, without the Committees prior consent, be subject in any manner to anticipation, alienation, sale, transfer, assignment, pledge, encumbrance, charge, garnishment, execution, or levy of any kind, either voluntary or involuntary. An unauthorized attempt to charge or otherwise dispose of any right to benefits hereunder shall be subject to seizure by legal process resulting from any attempt by creditors of, or claimants against, any Participant (or Beneficiary), or any person claiming under or through the foregoing, to attach any Account balance under the Plan. Notwithstanding the foregoing, the anti-alienation restrictions of this Section 8.03 shall not apply to qualified domestic relations order ( QDRO ) as described in Code Section 414(p). The Committee shall establish procedures to determine whether domestic relations orders submitted to the Committee are QDROs and to administer distributions under any valid QDROs. Nothing in this Section 8.03 shall preclude the Company or its Affiliates from withholding from amounts payable to a Participant or his Beneficiary under the Plan any amount that the Participant owes to the Company or its Affiliates, regardless of whether such amount is related to the Plan.
8.04 Special Payment Situations . The following provisions shall apply to the extent permitted under Code Section 409A.
(a) Missing Participant or Beneficiary . Payment of benefits to the person entitled thereto may be sent by first class mail, address correction requested, to the last known address on file with the Committee. If, within two months from the date of issuance of the payment, the payment letter cannot be delivered to the person entitled thereto or the payment has not been negotiated, the payment shall be treated as forfeited. However, if the person to whom the benefit became payable subsequently appears and identifies himself to the satisfaction of the Committee, the amount forfeited (without earnings thereon) shall be distributed to the person entitled thereto. The right of any person to restoration of a benefit which was forfeited pursuant to this Section 8.04(a) shall cease upon termination of the Plan.
(b) Private Investigators . If the Committee retains a private investigator or other person or service to assist in locating a missing person, all costs incurred for such services shall be charged against the benefit to which the
15
missing person was believed to be entitled and the benefit shall be reduced by the amount of the costs incurred, except as the Committee may otherwise direct in his discretion.
(c) Delayed Payment . Payments to Participants or Beneficiaries may be postponed by the Committee until any anticipated taxes, expenses, or amounts to be paid under a qualified domestic relations order, have been paid in full or until it is determined that such charges will not be imposed. A payment to a Participant or Beneficiary may also be delayed in the event payment might defeat an adverse potential or asserted claim by some other person to the payment. The cost incurred by the Company in dealing with any such adverse claim shall be charged against the benefit to which the claim relates, except as the Committee may otherwise direct in its discretion.
8.05 Spin-offs . If a Participant ceases to be employed by the Company or its Affiliates because of the disposition by the Company or its Affiliates of its interest in a subsidiary, plant, facility or other business unit, or if an entity which employs a Participant ceases to be an Affiliate, such Participants employment shall be considered terminated for all Plan purposes. To the extent permitted under Code Section 409A, this Section 8.05 shall not apply to the extent it is overridden by any contrary or inconsistent provision in the applicable sales documents (or any related documents), whether adopted before or after the sale, as determined by the Committee in its discretion and, if so determined, any such contrary or inconsistent provision shall instead apply and be incorporated into the Plan by this reference.
8.06 Duty to Provide Data .
(a) Data Requests . Every person with an interest in the Plan or claiming benefits under the Plan shall furnish the Committee, on a timely and accurate basis, with such documents, evidence or information as it considers necessary or desirable for the purpose of administering the Plan. The Committee may postpone payment of benefits (without accrual of any interest or other earnings) until such information and such documents have been furnished.
(b) Addresses . Every person claiming a benefit under the Plan shall give written notice to the Committee of his post office address and each change of post office address. Any communication, statement or notice addressed to such a person at his latest post office address as filed with the Committee will, on deposit in the United States mail with postage prepaid, be as binding upon such person for all purposes of the Plan as if it had been received, regardless of whether it is actually received or it is alleged not to have been received. If a person fails to give notice of his correct address, the Committee, the Company and its Affiliates shall not be obliged to search for, or to ascertain, his whereabouts.
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(c) Failure to Comply . If benefits which are otherwise currently payable cannot be paid to the person entitled to the benefits because the individual has failed to comply with this Section 8.06 or any other Plan provision relating to his claim for benefits, any unpaid past due amount shall be forfeited on the individuals death or presumed death.
8.07 Tax Consequences Not Guaranteed . The Company does not warrant that this Plan will have any particular tax consequences for Participants or Beneficiaries and shall not be liable to them if tax consequences they anticipate do not actually occur. The Employer shall have no obligation to indemnify a Participant or Beneficiary for lost tax benefits (or other damage or loss) in the event benefits are cancelled as permitted under Section 8.01 , or accelerated due to change in Plan design or funding, e.g. , establishment of a secular trust.
8.08 Tax Withholding . The Company or other payor shall withhold from a benefit payment under the Plan any Federal, state or local taxes required by law to be withheld with respect to such payment, and may withhold such sum as the payor may reasonably estimate as necessary to cover any taxes for which the Employer may be liable or which it determines may be assessed with regard to such payment.
8.09 Incompetency . Any person receiving or claiming benefits under the Plan shall be conclusively presumed to be mentally competent until the date on which the Committee receives a written notice, in an acceptable form and manner, that such person is incompetent and a guardian or other person legally vested with the care of his estate has been appointed. If the Committee finds that any person to whom a benefit is payable under the Plan is unable to care for his affairs because of any disability or infirmity and no legal guardian of such persons estate has been appointed, any payment due may be paid to the spouse, a child, a parent, a sibling, or to any other person or entity deemed by the Committee to have incurred expense for such person otherwise entitled to payment. Any such payment shall be a complete discharge of any liability under the Plan to the full extent of such payment. If a guardian of the estate of any person receiving or claiming benefits under the Plan shall be appointed by a court of competent jurisdiction, then benefit payments may be made to such guardian provided that proper proof of appointment and qualification is furnished in such form and manner as acceptable to the Committee. Any such payment shall be a complete discharge of any liability therefor under the Plan.
8.10 Severability . If any provision of the Plan is held invalid or illegal for any reason, such illegality or invalidity shall not affect the remaining provisions of the Plan, and the Plan shall be construed and enforced as if the illegal or invalid provision was not contained. The Company shall have the privilege and opportunity to correct and remedy such questions of illegality or invalidity by amendment.
8.11 Governing Law . This Plan is subject to ERISA, but is exempt from most parts of ERISA since it is an unfunded, deferred compensation plan, that is maintained for a select group of management or highly compensated employees for purposes of Title I of ERISA. In no event shall any references to ERISA in the Plan be construed to mean that the Plan is subject to any particular provisions of ERISA. The Plan shall be governed and construed in accordance with the laws of the State of Texas without regard to its conflicts of law provisions, except to the extent such laws are preempted by ERISA or other applicable federal law.
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8.12 Headings . The headings of Articles and Sections herein are included solely for convenience of reference, and, if there is any conflict between such headings and the text of the Plan, the text shall control and govern.
[Signature page follows.]
18
IN WITNESS WHEREOF, Anadarko Petroleum Corporation has caused this amended and restated Plan to be adopted and executed by its duly authorized officer, on this 3 rd day of November, 2008.
ATTEST: | ANADARKO PETROLEUM CORPORATION | |||||||
By: | /s/ Lynn Moffett | By: | /s/ Robert G. Gwin | |||||
Name: | Lynn Moffett | Name: | Robert G. Gwin | |||||
Title: | HR Advisor | Title: | Senior Vice President |
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ADOPTING EMPLOYERS APPENDIX
Effective as of January 1, 2007, the Company and the following subsidiaries of the Company have adopted the Plan as Employers thereunder:
Kerr-McGee Corporation
Western Gas Resources, Inc.
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Exhibit 10(xxix)
Execution Copy
SECOND AMENDMENT TO
ANADARKO PETROLEUM CORPORATION
MANAGEMENT LIFE INSURANCE PLAN
WHEREAS, Anadarko Petroleum Corporation (the Company) has heretofore adopted the Anadarko Petroleum Corporation Management Life Insurance Plan, as amended and restated effective November 1, 2002, and amended from time to time thereafter (the Plan); and
WHEREAS, the Company now desires to amend the Plan to comply with the requirements of Section 409A of the Internal Revenue Code of 1986, as amended (the Code), including regulations or other authoritative guidance thereunder, in the manner and to the extent herein provided;
NOW, THEREFORE, this Second Amendment (Amendment) is hereby made with all the amendments set forth herein to be effective as of January 1, 2008 (the Effective Date), as follows:
Section 2.01(1) is deleted, in its entirety, and replaced by the following new Section 2.01(1):
(1) Administrator : The Vice President of Human Resources.
Section 2.01(4) is deleted, in its entirety, and replaced by the following new Section 2.01(4):
(4) Benefit Salary : Benefit Salary is a Participants Base Annual Salary (if in $1,000 increments) or his Base Annual Salary rounded up to the next $1,000.
Section 2.01(7) is deleted, in its entirety, and replaced by the following new Section 2.01(7):
(7) | Disabled Participant : The Participant is deemed to be a Disabled Participant if one of the following requirements is met, as determined by the Administrator: (i) the Participant is unable to engage in any substantial gainful activity by reason of any medically determinable physical or mental impairment that can be expected to result in death or can be expected to last for a continuous period of not less than 12 months, or (ii) the Participant, by reason of any medically determinable physical or mental impairment that can be expected to result in death or to last for a continuous period of not less than 12 months, is receiving income replacement benefits for a period of not less than three months under an accident and health plan covering Employees of the Company. |
The following new sentence is added to the end of Section 2.01(13):
Retirees are listed in Appendix A to the Plan.
The following new Section 2.01(14) is added to the Plan:
(14) | Separation from Service : Separation from Service means a separation from service within the meaning of Code Section 409A. |
The following new Section 2.01(15) is added to the Plan:
(15) | Specified Employee : Specified Employee means a Participant who is a specified employee as defined in Code Section 409A. For purposes of this Section 2.01(15), a Specified employee under Code Section 409A is an Employee who, as of the date of his Separation from Service, is a key employee (within the meaning of Code Section 416(i) without regard to paragraph 5 thereof relating to beneficiaries) of the Company or any entity which is considered to be a single employer with the Company under Code Section 414(b) or 414(c) (the Controlled Group). A Participant shall be a Specified Employee if the Participant is (i) an officer of the Company having annual compensation greater than $130,000 ($150,000 for 2008 and as indexed thereafter under Code Section 416(i)), (ii) a 5-percent owner of the Company, or (iii) a 1-percent owner of the Company having annual compensation of more than $150,000, at any time during the twelve (12) month period ending on December 31, but only if a Controlled Group member has any stock that is publicly traded on an established securities market or otherwise. A Participant will be considered to be a Specified Employee for the period April 1 through March 31 following such December 31. The Administrator may apply an alternative method to identify Specified Employees in accordance with Code Section 409A and authoritative guidance thereunder, provided that the alternative method (i) is reasonably designed to include all Specified Employees, (ii) is an objectively determinable standard, and (iii) results in either all Employees or no more than 200 Employees being identified as Specified Employees as of any date. |
The phrase as soon as administratively feasible following the date of his or her death is deleted everywhere that it appears in Section 3.04.
Section 3.05 is deleted, in its entirety, and replaced by the following new Section 3.05:
3.05 Time for Payment .
(1) | The benefits which are payable hereunder with respect to a Participant shall be paid within 90 days after the Participants death. |
(2) | Notwithstanding Section 3.05(1), if the Participant is a member of the group listed in Appendix A and the Participant has attained at least 55 years of age and at least 10 years of service to the Company at the time of his Separation from Service, then the benefits which are payable hereunder with respect to a Participant shall be paid within 90 days after the earlier of (i) the Participants death or (ii) the Participants Separation from Service. If benefits under this Plan are paid upon the Participants Separation from Service, the Participant shall receive the actuarial present value of the Benefit Payment and Gross-Up Payment based on the interest rate and mortality assumptions used for determining lump sum payments under the Anadarko Retirement Plan as in effect at the time of Separation from Service. |
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(3) | Notwithstanding Sections 3.05(1) and 3.05(2), if a Participant is a member of the group listed in Appendix A, and his employment with the Company was terminated during the period of September 1, 2006 through August 31, 2007 under the Anadarko Petroleum Corporation Severance Plan or any other applicable severance plan or program or an employment contract providing for severance pay benefits (individually and collectively, the Severance Plans), or the Participant was notified of his termination prior to August 31, 2007 under the Severance Plans, and his age plus his years of service to the Company (both rounded down to the nearest whole number) total at least 65, then the benefits which are payable hereunder with respect to such Participant shall be paid within 90 days after the Participants Separation from Service. If benefits under this Plan are paid upon the Participants Separation from Service, the Participant shall receive the actuarial present value of the Benefit Payment and Gross-Up Payment based on the interest rate and mortality assumptions used for determining lump sum payments under the Anadarko Retirement Plan as in effect at the time of Separation from Service. |
(4) | Notwithstanding any provision to the contrary, if benefits under the Plan are payable to a Specified Employee as a result of a Separation from Service, no payment shall be made before the date which is six (6) months after the date the Specified Employee has a Separation from Service from the Company, or such earlier date upon which such amount can be paid or provided under Code Section 409A without being subject to additional taxes thereunder. |
Section 4.04 is deleted, in its entirety, and replaced by the following new Section 4.04:
4.04 Claims for Benefits .
(a) Filing a Claim . A Participant or his authorized representative may file a claim for benefits under the Plan. Any claim must be in writing and submitted to the Compensation and Benefits Committee of the Companys Board of Directors (the Committee) at such address as may be specified from time to time. Claimants will be notified in writing of approved claims, which will be processed as claimed. A claim is considered approved only if its approval is communicated in writing to a claimant.
(b) Denial of Claim . In the case of the denial of a claim respecting benefits paid or payable with respect to a Participant, a written notice will be furnished to the claimant within 90 days of the date on which the claim is received by the Committee. If special circumstances (such as for a hearing) require a longer period, the claimant will be notified in writing, prior to the expiration of the 90-day period, of the reasons for an extension of time; provided, however, that no extensions will be permitted beyond 90 days after the expiration of the initial 90-day period.
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(c) Reasons for Denial . A denial or partial denial of a claim will be dated and signed by the Committee and will clearly set forth:
(i) | the specific reason or reasons for the denial; |
(ii) | specific reference to pertinent Plan provisions on which the denial is based; |
(iii) | a description of any additional material or information necessary for the claimant to perfect the claim and an explanation of why such material or information is necessary; and |
(iv) | an explanation of the procedure for review of the denied or partially denied claim set forth below, including the claimants right to bring a civil action under ERISA Section 502(a) following an adverse benefit determination on review. |
(d) Review of Denial . Upon denial of a claim, in whole or in part, a claimant or his duly authorized representative will have the right to submit a written request to the Committee for a full and fair review of the denied claim by filing a written notice of appeal with the Committee within 60 days of the receipt by the claimant of written notice of the denial of the claim. A claimant or the claimants authorized representative will have, upon request and free of charge, reasonable access to, and copies of, all documents, records, and other information relevant to the claimants claim for benefits and may submit issues and comments in writing. The review will take into account all comments, documents, records, and other information submitted by the claimant relating to the claim, without regard to whether such information was submitted or considered in the initial benefit determination.
If the claimant fails to file a request for review within 60 days of the denial notification, the claim will be deemed abandoned and the claimant precluded from reasserting it. If the claimant does file a request for review, his request must include a description of the issues and evidence he deems relevant. Failure to raise issues or present evidence on review will preclude those issues or evidence from being presented in any subsequent proceeding or judicial review of the claim.
(e) Decision Upon Review . The Committee will provide a prompt written decision on review. If the claim is denied on review, the decision shall set forth:
(i) | the specific reason or reasons for the adverse determination; |
(ii) | specific reference to pertinent Plan provisions on which the adverse determination is based; |
(iii) | a statement that the claimant is entitled to receive, upon request and free of charge, reasonable access to, and copies of, all documents, records, and other information relevant to the claimants claim for benefits; and |
(iv) | a statement describing any voluntary appeal procedures offered by the Plan and the claimants right to obtain the information about such procedures, as well as a statement of the claimants right to bring an action under ERISA Section 502(a). |
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A decision will be rendered no more than 60 days after the Committees receipt of the request for review, except that such period may be extended for an additional 60 days if the Committee determines that special circumstances (such as for a hearing) require such extension. If an extension of time is required, written notice of the extension will be furnished to the claimant before the end of the initial 60-day period.
To the extent of its responsibility to review the denial of benefit claims, the Committee will have full authority to interpret and apply in its discretion the provisions of the Plan. The decision of the Committee will be final and binding upon any and all claimants, including, but not limited to, Participants, and any other individuals making a claim through them.
(f) Other Procedures . Notwithstanding the foregoing, the Committee in its discretion, may adopt different procedures for different claims without being bound by past actions. Any procedures adopted, however, shall be designed to afford a claimant a full and fair review of his claim and shall comply with applicable regulations under ERISA.
(g) Finality of Determinations; Exhaustion of Remedies . To the extent permitted by law, decisions reached under the claims procedures set forth in this Section shall be final and binding on all parties. No legal action for benefits under the Plan shall be brought unless and until the claimant has exhausted his remedies under this Section. In any such legal action, the claimant may only present evidence and theories which the claimant presented during the claims procedure. Any claims which the claimant does not in good faith pursue through the review stage of the procedure shall be treated as having been irrevocably waived. Judicial review of a claimants denied claim shall be limited to a determination of whether the denial was an abuse of discretion based on the evidence and theories the claimant presented during the claims procedure. Any suit or legal action initiated by a claimant under the Plan must be brought by the claimant no later than one year following a final decision on the claim for benefits by the Committee. The one-year limitation on suits for benefits will apply in any forum where a claimant initiates such suit or legal action.
(h) Effect of Committee Action . The Plan shall be interpreted by the Committee in accordance with the terms of the Plan and their intended meanings. However, the Committee shall have the discretion to make any findings of fact needed in the administration of the Plan, and shall have the discretion to interpret or construe ambiguous, unclear or implied (but omitted) terms in any fashion they deem to be appropriate in their sole judgment. The validity of any such finding of fact, interpretation, construction or decision shall not be given de novo review if challenged in court, by arbitration or in any other forum, and shall be upheld unless clearly arbitrary or capricious. To the extent the Committee has been granted discretionary authority under the Plan, the Committees prior exercise of such authority shall not obligate it to exercise its authority in a like fashion thereafter. If, due to errors in drafting, any Plan provision does not accurately reflect its intended meaning, as demonstrated by consistent interpretations or other evidence of intent, or as determined by the Committee in it sole and exclusive judgment, the provision shall be considered ambiguous and shall be interpreted by the Committee in a fashion consistent with its intent, as determined by the Committee in its sole discretion. The
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Committee, without the need for approval by the Companys Board of Directors, may amend the Plan retroactively to cure any such ambiguity. This Section may not be invoked by any person to require the Plan to be interpreted in a manner which is inconsistent with its interpretation by the Committee. All actions taken and all determinations made in good faith by the Committee shall be final and binding upon all persons claiming any interest in or under the Plan.
Section 5.02 is deleted, in its entirety, and replaced by the following new Section 5.02:
5.02 Right to Terminate . The Company hopes and expects to continue this Plan for the Participants indefinitely. The Company reserves the right at will, and without prior notice, to terminate or partially terminate the Plan or any portion thereof. No amendment or termination of the Plan shall adversely affect the rights of Beneficiaries of deceased Participants with respect to benefits which became payable as a result of death prior to the effective date of such termination of the Plan. Upon termination of the Plan, distribution of benefits shall be made to Participants and Beneficiaries in the manner and at the time described in the Plan, unless one of the following termination events occurs, in which case, all such amounts shall be distributed in a lump sum upon termination, or upon the earliest date allowable under Code Section 409A: (1) the Companys termination and liquidation of the Plan within 12 months of a corporate dissolution taxed under Code Section 331, or with the approval of a bankruptcy court pursuant to 11 U.S.C. Section 503(b)(1)(A); (2) the Companys termination and liquidation of the Plan pursuant to irrevocable action taken by the Company within the 30 days preceding or 12 months following a change in control event (within the meaning of Code Section 409A), provided that all agreements, methods, programs, and other arrangements sponsored by the Company that are aggregated under Code Section 409A are terminated and liquidated with respect to each Participant that experiences the change in control event; or (3) the Companys termination and liquidation of the Plan, provided that (a) the termination and liquidation does not occur proximate to a downturn in the financial health of the Company, (b) the Company terminates and liquidates all agreements, methods, programs, and other arrangements sponsored by the Company that would be aggregated under Code Section 409A if the same Participant had deferrals of compensation under all of the agreements, methods, programs, and other arrangements sponsored by the Company that are terminated and liquidated, (c) no payments in liquidation of the Plan are made within 12 months of the date the Company takes all necessary action to irrevocably terminate and liquidate the Plan other than payments that would have been payable absent the termination and liquidation, and (d) the Company does not adopt a new plan that would be aggregated with any terminated and liquidated plan under Code Section 409A if the same Participant participated in both plans, at any time within three years following the date the Company takes all necessary action to irrevocably terminate and liquidate the Plan.
As expressly amended hereby, the Plan is ratified and confirmed in all respects and shall continue in full force and effect.
[ Signature page follows. ]
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IN WITNESS WHEREOF, the undersigned, being a duly authorized officer of the Company, has approved, ratified and executed this Amendment on this 16 th day of June, 2008.
ANADARKO PETROLEUM CORPORATION | ||
By: | /s/ Robert G. Gwin | |
Name: | Robert G. Gwin | |
Title: | Senior Vice President |
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Exhibit 10(xlvi)
Anadarko Petroleum Corporation
Deferred Compensation Plan
Amended and Restated effective as of January 1, 2010
Table of Contents
PURPOSE |
1 | |||
ARTICLE 1 DEFINITIONS |
1 | |||
1.1 |
Account | 1 | ||
1.2 |
Administrator | 1 | ||
1.3 |
Annual Retainer Fees | 1 | ||
1.4 |
Base Pay | 1 | ||
1.5 |
Beneficiary | 2 | ||
1.6 |
Board | 2 | ||
1.7 |
Bonus | 2 | ||
1.8 |
Change of Control | 2 | ||
1.9 |
Code | 3 | ||
1.10 |
Company | 3 | ||
1.11 |
Compensation Committee | 4 | ||
1.12 |
Contingent Beneficiary | 4 | ||
1.13 |
Director | 4 | ||
1.14 |
Director Compensation | 4 | ||
1.15 |
Disabled | 4 | ||
1.16 |
Effective Date | 4 | ||
1.17 |
Eligible Employee | 4 | ||
1.18 |
ERISA | 4 | ||
1.19 |
Key Employee | 4 | ||
1.20 |
Meeting Fees | 5 | ||
1.21 |
Participant | 5 | ||
1.22 |
Plan | 5 | ||
1.23 |
Plan Year | 5 | ||
1.24 |
Retirement | 5 | ||
1.25 |
Section 16 Officer | 5 | ||
1.26 |
Separation from Service | 5 | ||
1.27 |
Unforeseeable Emergency | 6 | ||
1.28 |
Valuation Date | 6 | ||
ARTICLE 2 PARTICIPATION |
6 | |||
2.1 |
Participation | 6 | ||
2.2 |
Termination of Participation | 6 | ||
2.3 |
Suspension of Participation | 6 | ||
ARTICLE 3 DEFERRAL ELECTIONS |
6 | |||
3.1 |
Deferral Agreement | 6 | ||
3.2 |
Election to Defer Base Pay | 7 | ||
3.3 |
Election to Defer Bonus | 7 | ||
3.4 |
Election to Defer Director Compensation | 7 | ||
3.5 |
Timing of Election to Defer | 7 | ||
3.6 |
Election of Payment Schedule and Form of Payment | 8 | ||
ARTICLE 4 PARTICIPANT ACCOUNT |
10 |
i
4.1 |
Individual Accounts | 10 | ||
ARTICLE 5 INVESTMENT OF CONTRIBUTIONS |
10 | |||
5.1 |
Investment Options | 10 | ||
5.2 |
Adjustment of Accounts | 11 | ||
5.3 |
Distributions from the Company Stock Fund | 11 | ||
ARTICLE 6 RIGHT TO BENEFITS |
11 | |||
6.1 |
Vesting | 11 | ||
6.2 |
Death | 11 | ||
6.3 |
Disability | 12 | ||
ARTICLE 7 DISTRIBUTION OF BENEFITS |
12 | |||
7.1 |
Amount of Benefits | 12 | ||
7.2 |
Method and Timing of Distributions | 13 | ||
7.3 |
Unforeseeable Emergency | 13 | ||
7.4 |
Cashouts of Minimal Interests | 13 | ||
7.5 |
Distribution to a Key Employee | 14 | ||
ARTICLE 8 AMENDMENT AND TERMINATION |
14 | |||
8.1 |
Amendment by Company | 14 | ||
8.2 |
Retroactive Amendments | 14 | ||
8.3 |
Special Plan and Deferral Election Amendments | 14 | ||
8.4 |
Plan Termination | 15 | ||
8.5 |
Distribution Upon Termination of the Plan | 15 | ||
ARTICLE 9 THE TRUST |
16 | |||
9.1 |
Establishment of Trust | 16 | ||
9.2 |
Grantor Trust | 16 | ||
9.3 |
Investment of Trust Funds | 16 | ||
9.4 |
Participants Rights under a Trust | 16 | ||
ARTICLE 10 MISCELLANEOUS |
17 | |||
10.1 |
Unsecured General Creditor of the Company | 17 | ||
10.2 |
Limitation of Rights | 17 | ||
10.3 |
The Companys Liability | 17 | ||
10.4 |
Satisfaction of Benefit Obligation | 17 | ||
10.5 |
Spendthrift Provision | 18 | ||
10.6 |
Incapacity of Participant or Beneficiary | 18 | ||
10.7 |
Waiver | 18 | ||
10.8 |
Notices | 19 | ||
10.9 |
Tax Withholding | 19 | ||
10.10 |
Governing Law | 19 | ||
10.11 |
Intention to Comply with Code Section 409A | 19 | ||
ARTICLE 11 PLAN ADMINISTRATION |
20 | |||
11.1 |
Powers and Responsibilities of the Administrator | 20 | ||
11.2 |
Interpretation of the Plan | 20 | ||
11.3 |
Claims and Review Procedures | 20 | ||
11.4 |
Plan Administrative Costs | 21 |
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PURPOSE
The Anadarko Petroleum Corporation Deferred Compensation Plan (the Plan) was originally established effective as of January 1, 2005, and is hereby amended and restated effective as of January 1, 2010. The purpose of the Plan is to permit eligible employees and non-employee directors to defer receipt of certain compensation into a subsequent tax year which would otherwise be payable to them in the then-current tax year.
The Plan is intended to be a plan which is unfunded and is maintained by an employer primarily for the purpose of providing deferred compensation for a select group of management or highly compensated employees within the meaning of Sections 201(2), 301(a)(3) and 401(a)(1) of ERISA and shall be implemented and administered in a manner consistent therewith. The Plan is also intended to (i) be exempt from the participation and vesting, funding, and fiduciary responsibility requirements of Title I of ERISA and (ii) qualify for simplified reporting under the U.S. Department of Labor Regulation Section 2530.104-23, as may be amended from time to time.
ARTICLE 1 DEFINITIONS
Pronouns used in the Plan are in the masculine gender but include the feminine gender unless the context clearly indicates otherwise. Wherever used herein, the following terms have the meanings set forth below, unless a different meaning is clearly required by the context:
1.1 Account means an account established by the Administrator for the purpose of recording amounts credited on behalf of each Participant under the Plan, and any income, expenses, gains, losses or distributions included thereon. The Account shall be a bookkeeping entry only and shall be utilized solely as a device for the measurement and determination of the amounts to be paid to each Participant pursuant to the Plan.
1.2 Administrator means, with respect to Participants who are Directors or Section 16 Officers, the Compensation Committee. With respect to all other Participants, the term Administrator means the Company, or a person, persons or committee that is designated by the Company to be the Administrator of the Plan.
1.3 Annual Retainer Fees means the annual fees (other than Meeting Fees) paid to a Director by the Company for service on the Board or committee(s) of the Board, including the Board retainer, lead director retainer, committee chair and member retainers and any other forms of retainer paid to a Director for service on the Board.
1.4 Base Pay means base compensation per payroll period paid by the Company to an Eligible Employee (including amounts which the Eligible Employee could have received in cash had he not elected to contribute to an employee benefit plan maintained by the Company), excluding overtime pay, bonuses, employee benefits, added premiums, differentials, components of foreign service assignments, and any other form of incentive compensation.
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1.5 Beneficiary means the persons, trusts, estates or other entities designated under Section 6.2 to receive benefits under the Plan upon the death of a Participant. Contingent Beneficiary means the persons, trusts, estates or other entities designated under Section 6.2 to receive benefits under the Plan upon the death of a Participant and in the event that the designated Beneficiary predeceases a Participant.
1.6 Board means the Board of Directors of the Company.
1.7 Bonus means the bonus otherwise payable currently to a Participant for the Plan Year under the Anadarko Petroleum Corporation 2008 Omnibus Incentive Compensation Plan, or any predecessor or successor plans thereto, or any other incentive or bonus arrangement implemented after the Effective Date by the Company if the Company designates payments under such program or arrangement as being Bonuses which may be deferred pursuant to this Plan.
1.8 Change of Control means that a Change of Control of the Company shall be deemed to have occurred on the date as of the first day any one or more of the following conditions shall have been satisfied:
(a) The acquisition by any individual, entity or group (within the meaning of Section 13(d)(3) or 14(d)(2) of the Securities Exchange Act of 1934, as amended (the Exchange Act )) (a Person ) of beneficial ownership (within the meaning of Rule 13d-3 promulgated under the Exchange Act) of 20% or more of either (i) the then outstanding shares of common stock of the Company (the Outstanding Company Common Stock ) or (ii) the combined voting power of the then outstanding voting securities of the Company entitled to vote generally in the election of directors (the Outstanding Company Voting Securities ); provided, however, that for purposes of this subsection (a), the following acquisitions shall not constitute a Change of Control: (A) any acquisition directly from the Company, (B) any acquisition by the Company, (C) any acquisition by any employee benefit plan (or related trust) sponsored or maintained by the Company or any corporation controlled by the Company or (D) any acquisition pursuant to a transaction which complies with clauses (A), (B) or (C) of this subsection (a); or
(b) Individuals who, as of the Effective Date, constitute the Board (the Incumbent Board ) cease for any reason to constitute at least a majority of the Board; provided, however, that any individual becoming a director subsequent to the Effective Date, whose election, or nomination for election by the Companys stockholders, was approved by a vote of at least a majority of the directors then comprising the Incumbent Board shall be considered as though such individual were a member of the Incumbent Board, but excluding, for this purpose, any such individual whose initial assumption of office occurs as a result of an actual or threatened election contest with respect to the election or removal of directors or other actual or threatened solicitation of proxies or consents by or on behalf of a Person other than the Board; or
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(c) Consummation by the Company of a reorganization, merger or consolidation or sale or other disposition of all or substantially all of the assets of the Company or the acquisition of assets of another entity (a Business Combination ), in each case, unless, following such Business Combination, (i) all or substantially all of the individuals and entities who were the beneficial owners, respectively, of the Outstanding Company Common Stock and Outstanding Company Voting Securities immediately prior to such Business Combination beneficially own, directly or indirectly, more than sixty percent (60%) of, respectively, the then outstanding shares of common stock and the combined voting power of the then outstanding voting securities entitled to vote generally in the election of directors, as the case may be, of the corporation resulting from such Business Combination (including, without limitation, a corporation which as a result of such transaction owns the Company or all or substantially all of the Companys assets either directly or through one or more subsidiaries) in substantially the same proportions as their ownership, immediately prior to such Business Combination of the Outstanding Company Common Stock and Outstanding Company Voting Securities, as the case may be, (ii) no Person (excluding any employee benefit plan (or related trust) of the Company or such corporation resulting from such Business Combination) beneficially owns, directly or indirectly, twenty percent (20%) or more of, respectively, the then outstanding shares of common stock of the corporation resulting from such Business Combination or the combined voting power of the then outstanding voting securities of such corporation except to the extent that such ownership existed prior to the Business Combination, and (iii) at least a majority of the members of the board of directors of the corporation resulting from such Business Combination were members of the Incumbent Board at the time of the execution of the initial agreement, or of the action of the Board, providing for such Business Combination; or
(d) Approval by the stockholders of the Company of a complete liquidation or dissolution of the Company.
Notwithstanding the foregoing provisions of this Section 1.8 or any provision of this Plan to the contrary, to the extent that any payment or acceleration of payment of any amount under the Plan is subject to, and not exempt under, Code Section 409A, then the determination of whether a Change in Control has occurred hereunder as affecting the payment, or timing of payment, of such amount shall be made within the meaning of such term as set forth in Code Section 409A to the extent inconsistent with the foregoing provisions of this definition, as determined in the discretion of the Administrator.
1.9 Code means the Internal Revenue Code of 1986, as amended from time to time. All references herein to any Section of the Code shall include any successor provision thereto and the Treasury Regulations and other authority issued under such Section by the appropriate governmental authority.
1.10 Company means Anadarko Petroleum Corporation and its wholly owned subsidiaries, unless the context requires otherwise.
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1.11 Compensation Committee means the Compensation and Benefits Committee of the Board, the composition of which may change from time to time.
1.12 Contingent Beneficiary shall have the definition set forth in Section 1.5.
1.13 Director means a non-employee member of the Board.
1.14 Director Compensation means Annual Retainer Fees and Meeting Fees.
1.15 Disabled or Disability means a Participant shall be deemed to have become permanently disabled if the Participant (i) is unable to engage in any substantial gainful activity by reason of any medically determinable physical or mental impairment which can be expected to result in death or can be expected to last for a continuous period of not less than twelve (12) months, or (ii) is, by reason of any medically determinable physical or mental impairment which can be expected to result in death or can be expected to last for a continuous period of not less than twelve (12) months, receiving income replacement benefits for a period of not less than three (3) months under a disability plan or an accident and health plan maintained by the Company, if applicable.
1.16 Effective Date means January 1, 2010, the effective date of this amendment and restatement of the Plan.
1.17 Eligible Employee means an employee of the Company who is (1) paid on the Companys U.S. payroll, (b) determined by the Company to be a member of a select group of management or highly compensated employees (within the meaning of Sections 201(2), 301(a)(3) and 401(a)(1) of ERISA) and is designated by the Company as an Eligible Employee for purposes of the Plan, and (c) not on a foreign service assignment outside of the United States, as determined by the Company in its discretion.
1.18 ERISA means the Employee Retirement Income Security Act of 1974, as may be amended from time to time. All references herein to any Section of ERISA shall include any successor provision thereto and the regulations and other authority issued under such Section by the appropriate governmental authority.
1.19 Key Employee means a Participant who is a specified employee as defined in Code Section 409A. For purposes of this definition, a specified employee under Code Section 409A is an employee who, as of the date of his Separation from Service, is a key employee (within the meaning of Code Section 416(i) without regard to paragraph 5 thereof relating to beneficiaries) of the Company or any entity which is considered to be a single employer with the Company under Code Section 414(b) or 414(c) (the Controlled Group). A Participant shall be a Key Employee if the Participant is (i) an officer of the Company having annual compensation greater than $160,000 for 2010 (and as indexed thereafter under Code Section 416(i)), (ii) a 5-percent (5%) owner of the Company, or (iii) a 1-percent (1%) owner of the Company having annual compensation of more than $150,000, at any time during the twelve (12) month period ending on December 31, but
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only if a Controlled Group member has any stock that is publicly traded on an established securities market or otherwise. A Participant will be considered to be a Key Employee for the period April 1 through March 31 following such December 31 determination. The Company may apply an alternative method to identify Key Employees in accordance with Code Section 409A, provided that the alternative method (i) is reasonably designed to include all Key Employees, (ii) is an objectively determinable standard, and (iii) results in either all employees or no more than 200 employees being identified as Key Employees as of any date.
1.20 Meeting Fees means fees paid to a Director for attendance at meetings of the Board or meetings of the Boards committees.
1.21 Participant means any Eligible Employee or any Director who participates in the Plan in accordance with Article 2.
1.22 Plan means the Anadarko Petroleum Corporation Deferred Compensation Plan, as amended and restated and, set forth herein, and as it may be further amended from time to time.
1.23 Plan Year means the twelve (12) consecutive month period beginning January 1 st and ending December 31 st of any given year.
1.24 Retirement means, in the case of an Eligible Employee who is eligible to retire under the Anadarko Retirement Plan (the Anadarko Plan), his Separation from Service; provided, however, that the Eligible Employee has, as of such date, both attained age fifty-five (55) and been credited with at least five (5) years of Credited Service as that term is defined under the Anadarko Plan. Retirement means, in the case of an Eligible Employee who is eligible to retire under the Kerr-McGee Corporation Retirement Plan (the KMG Plan), his Separation from Service; provided, however, that the Eligible Employee has, as of such date, both attained age fifty-two (52) and been credited with at least ten (10) years of Credited Service as that term is defined under the KMG Plan. Retirement means, in the case of a Director, Separation from Service from the Board after the first to occur of: (a) the Director having attained age sixty-five (65), (b) the Director having completed ten (10) years of service as a Director, or (c) the Director having attained both age fifty-five (55) and completed five (5) years of service as a Director. A Directors total years of service as a Director as of any date shall be determined by dividing his total completed full months of service as a Director by twelve (12).
1.25 Section 16 Officer means an Eligible Employee who is subject to the requirements of Section 16 of the Securities Exchange Act of 1934, as amended, and the rules and regulations promulgated thereunder.
1.26 Separation from Service means a separation from service of an Eligible Employee or Director within the meaning of Code Section 409A.
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1.27 Unforeseeable Emergency means a severe financial hardship to the Participant resulting from an illness or accident of the Participant, the Participants spouse, the Participants Beneficiary, or a dependent (as defined in Code Section 152(a)) of the Participant, loss of the Participants property due to casualty, or other similar extraordinary and unforeseeable circumstance arising as a result of events beyond the control of the Participant.
1.28 Valuation Date means each business day of the Plan Year and such other date(s) as designated by the Company.
ARTICLE 2 PARTICIPATION
2.1 Participation. Each Eligible Employee and Director shall become a Participant in the Plan by executing a deferral agreement in accordance with the provisions of Article 3.
2.2 Termination of Participation. A Participants participation in the Plan as an active Participant shall, in the case of an Eligible Employee, cease upon his Separation from Service for any reason or his ceasing to qualify as an Eligible Employee or, in the case of a Director, upon his termination of service on the Board. Compensation subject to a valid deferral election under the Plan and earned through such date of such Separation from Service or other termination shall be deferred pursuant to such election, even if such crediting of such amount to his Account occurs after the termination date. In addition, at the direction of the Company or the Administrator, a Participants participation in the Plan as an active Participant who is eligible to make deferral elections may be discontinued effective as of the first day of the next Plan Year. Upon any termination of active participation, a Participants deferrals shall cease but the provisions of Section 7.2 shall continue to apply. A former Eligible Employee or Director shall remain a Participant while he still has an undistributed Account balance under the Plan.
2.3 Suspension of Participation. As provided by the Company, a Participants active participation in the Plan will be suspended during an unpaid authorized leave of absence and will resume upon his return to active service with the Company (subject to such terms and conditions as the Company or Administrator may determine), provided that he continues to qualify as an Eligible Employee or Director upon his return to service. In addition, the Company, in its sole discretion, may suspend a Participants participation in the Plan as it deems to be necessary or appropriate to comply with applicable law or regulations, or coordination with other benefits plans of the Company.
ARTICLE 3 DEFERRAL ELECTIONS
3.1 Deferral Agreement. Each Eligible Employee and Director may elect to defer compensation amounts otherwise payable to him currently for a Plan Year by executing a deferral agreement in accordance with (a) rules and procedures established by the Administrator, (b) the provisions of this Article 3, and (c) Code Section 409A. The deferral agreement may separately specify for each discrete type of compensation ( e.g., Base Pay, Bonus, Director Compensation, or individual components of each) the whole
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number percentage multiple (in one percent (1%) increments and subject to the percentage limitations otherwise described herein) that the Participant elects to defer, the payment schedule and form of payment of the deferred amount.
A new deferral agreement must be executed in a timely manner (as set forth in this Article 3) for each Plan Year during which the Eligible Employee or Director elects to defer compensation. An Eligible Employee or Director who does not execute a deferral agreement in a timely manner shall be deemed to have elected zero deferrals for such Plan Year.
A deferral agreement may be changed or revoked at any time during the respective election periods specified in Section 3.5. A deferral agreement becomes irrevocable at the close of the respective election period.
3.2 Election to Defer Base Pay. An Eligible Employee may elect to defer Base Pay for a Plan Year in an amount not exceeding seventy-five percent (75%) of Base Pay.
3.3 Election to Defer Bonus. An Eligible Employee may elect to defer up to one hundred percent (100%) of his Bonus for a Plan Year, subject to any limitation that may be established by the Administrator and specified on the deferral agreement.
3.4 Election to Defer Director Compensation. A Director may elect to defer up to one hundred (100%) of his Director Compensation for a Plan Year.
3.5 Timing of Election to Defer. Each Eligible Employee who desires to defer Base Pay otherwise payable during a Plan Year must execute a deferral agreement in accordance with the procedures established by the Administrator and within the election period preceding the Plan Year during which the Base Pay will be earned, as specified by the Administrator (but not later than December 31 st immediately preceding such Plan Year and will be irrevocable as of such date). Each Eligible Employee who desires to defer a Bonus which may be earned with respect to services performed during a Plan Year must execute a deferral agreement in accordance with the rules and procedures established by the Administrator (but not later than December 31 st immediately preceding such Plan Year except that if the plan or arrangement providing for such Bonus is performance based compensation which is based upon services performed over a period of at least twelve months (as described in Code Section 409A(a)(4)(B)(iii)), then such deferral election must be executed no later than the date that is six (6) months before the end of the performance period over which the Bonus is earned and will be irrevocable as of such date).
A Director who desires to defer his Director Compensation otherwise payable during a Plan Year must execute a deferral agreement in accordance with the procedures established by the Administrator (but not later than December 31 st immediately preceding such Plan Year and will be irrevocable as of such date).
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An employee who is first designated as an Eligible Employee during a Plan Year may elect to defer Base Pay and/or Bonus in accordance with the rules of this Section 3.5, except that his initial deferral agreement must be executed within the thirty (30)-day period beginning on the date such employee is designated as an Eligible Employee. A new Director may elect to defer his Director Compensation in accordance with the rules of this Section 3.5 except that his initial deferral agreement must be executed within the thirty (30)-day period beginning on the date he first becomes a Director.
3.6 Election of Payment Schedule and Form of Payment. At the time an Eligible Employee or Director completes a deferral agreement provided by the Administrator, the Eligible Employee or Director may separately elect for each type of compensation being deferred ( i.e. , Base Pay, Bonus, Director Compensation, or individual components of each) the following items: (i) the date of distribution or commencement of distribution of each deferred amount, (ii) the form of payment in which each deferred amount will be distributed ( e.g ., lump sum or annual installments), and (iii) if applicable and as may be provided by the Administrator, whether the amount distributed will be in cash, Company Stock (as defined in Section 5.3) or a combination of cash and Company Stock. Subject to the provisions of Article 7, an Eligible Employee or Director may elect to receive distribution of his deferred amount in a single lump sum or annual installment distributions over a period certain not exceeding fifteen (15) years. If the Participant should elect installment payments over a designated time period, each installment payment shall be considered a separate payment for purposes of Code Section 409A.
The portion of the Participants Account that has been earned and vested as of January 1, 2010 (as well as any subsequent earnings, expenses, gains and losses attributed to such balance) ( Pre-2010 Account ) shall be distributed as follows:
(a) If the Participants Separation from Service occurs before he becomes eligible for Retirement, notwithstanding any other election, his distribution shall be made as follows:
(1) If the Participant initially elected to be paid upon his Separation from Service following Retirement, his distribution shall be made in a lump-sum payment no later than ninety (90) days after the date of his Separation from Service; or
(2) If the Participant initially elected to be paid upon an identified and specific date that is at least three (3) years after the date the deferral agreement was effective, then if payment has not already commenced, his distribution shall be made or shall commence on such identified and specific date; or
(3) If the Participant initially elected to be paid upon the earlier of (A) Separation from Service following Retirement or (B) an identified and specific date that is at least three (3) years after the date the deferral agreement was effective, then if payment has not already been made or commenced, his distribution shall be made in a lump sum payment no later than ninety (90) days after the date of his Separation from Service.
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(b) If the Participants Separation from Service occurs after he becomes eligible for Retirement, then the distribution or commencement of distribution shall be one of the following options as previously elected by the Participant:
(1) Separation from Service; or
(2) an identified and specific date that is at least three (3) years after the date the deferral agreement was executed; or
(3) the earlier of (A) Separation from Service or (B) an identified and specific date that is at least three (3) years after the date the deferral agreement was executed. This option (3) provides that the date of distribution specified in the deferral agreement will be honored unless a Separation from Service intervenes before the scheduled date of distribution, in which case payment will be made, in the form originally elected by the Participant, not later than the date that is ninety (90) days after the Separation from Service date.
The portion of the Participants Account that is earned and vested on and after January 1, 2010 (as well as any subsequent earnings, expenses, gains and losses attributed to such balance) ( Post-2009 Account ) shall be distributed as follows:
(a) If the Participants Separation from Service occurs before he becomes eligible for Retirement, notwithstanding any other election, his distribution shall be made as follows:
(1) If the Participant initially elected to be paid upon his Separation from Service following Retirement, his distribution shall be made in a lump-sum payment no later than ninety (90) days after the date of his Separation from Service; or
(2) If the Participant initially elected to be paid upon an identified and specific date that is at least one (1) year after the date the deferral agreement was effective, then if payment has not already commenced, his distribution shall be made or shall commence on such identified and specific date; or
(3) If the Participant initially elected to be paid upon the earlier of (A) Separation from Service following Retirement or (B) an identified and specific date that is at least one (1) year after the date the deferral agreement was effective, then if payment has not already been made or commenced, his distribution shall be made in a lump sum payment no later than ninety (90) days after the date of his Separation from Service.
(b) If the Participants Separation from Service occurs after he becomes eligible for Retirement, then the distribution or commencement of distribution shall be one of the following options as previously elected by the Participant:
(1) Separation from Service; or
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(2) an identified and specific date which is at least one (1) year after the date the deferral agreement was executed; or
(3) the earlier of (A) Separation from Service or (B) an identified and specific date which is at least one (1) year after the date the deferral agreement was executed. This option (3) provides that the date of distribution specified in the deferral agreement will be honored unless a Separation from Service intervenes before the scheduled date of distribution, in which case payment will be made, in the form originally elected by the Participant, not later than the date that is ninety (90) days after the Separation from Service date.
In addition, regardless of whether Retirement is attained by the Participant, he may elect a Change of Control Override. A Change of Control Override election provides that the date and form of distribution specified in the deferral agreement will be honored unless a Change of Control intervenes before the scheduled date of distribution, in which case, payment will be made in a single lump sum within ninety (90) days after the effective date of the Change of Control without regard to whether Participant has incurred a Separation from Service. Notwithstanding any provision in the Plan to the contrary, for purposes of effectuating an accelerated payment hereunder pursuant to a Change of Control Override, the term Change of Control shall mean a Change of Control (as defined in Section 1.8 of the Plan) but only to the extent that the event causing the Change of Control qualifies under Code Section 409A(a)(2)(v).
ARTICLE 4 PARTICIPANT ACCOUNT
4.1 Individual Accounts. The Administrator will establish and maintain an Account for each Participant that reflects deferrals made pursuant to Article 3, together with earnings, expenses, gains and losses that are attributable to investments of such Account as provided in Article 5. The amount a Participant elects to defer in accordance with Article 3 shall be credited to the Participants Account at the time the amount subject to the deferral election would otherwise have been payable to the Participant but for his deferral election. The Administrator will establish and maintain such other accounts and records as it determines, in its discretion, to be reasonably required or appropriate to discharge its duties under the Plan.
ARTICLE 5 INVESTMENT OF CONTRIBUTIONS
5.1 Investment Options. The amount credited to a Participants Account shall be treated as invested in the investment options as designated for this purpose by the Administrator. Such investment options may be different for Eligible Employees, Section 16 Officers and Directors, as determined by the Administrator in its discretion.
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5.2 Adjustment of Accounts. The amount credited to a Participants Account shall be adjusted for hypothetical investment earnings or losses in an amount equivalent to the earnings or losses reported by the investment options selected by the Participant or Beneficiary from among the investment options provided in Section 5.1. A Participant may, in accordance with rules and procedures established by the Administrator, change the investments to be used for the purpose of calculating future hypothetical investment adjustments to the Participants Account or to future Participant deferrals, which election change shall be effective as of the Valuation Date coincident with or next following notice to the Administrator. The Account of each Participant shall be adjusted as of each Valuation Date to reflect: (a) the hypothetical investment earnings and/or losses described above; (b) Participant deferrals; and (c) distributions or withdrawals from the Account.
5.3 Distributions from the Company Stock Fund. To the extent that any portion (including a percentage thereof as provided by the Administrator) of a Participants Account is invested in an investment fund maintained under the Plan which invests primarily in the common stock of the Company (either directly or in the form of phantom shares) (Company Stock Fund), such Participant may have the right to elect to receive distribution in shares of common stock of the Company (Company Stock), but only with respect to the portion of his Account balance that is invested in the Company Stock Fund, with such election to be made at such time and in such form as determined by the Administrator. Any fractional shares of Company Stock allocated to the Participants Account shall be distributed in cash. If a Participant does not elect to receive his distribution in shares of Company Stock, then the entire balance shall be made in cash.
ARTICLE 6 RIGHT TO BENEFITS
6.1 Vesting. At all times, each Participant has a one hundred percent (100%) nonforfeitable interest in all amounts credited to his Account. Notwithstanding the foregoing or any provision of the Plan to the contrary, if otherwise provided pursuant to a Company plan or program for which a benefit has been deferred under the Plan, a Participant may be subject to certain claw back or forfeiture of benefits in certain circumstances, in which case a Participants Account may be reduced in an amount necessary to satisfy such claw back or forfeiture.
6.2 Death. Notwithstanding any prior election regarding the form or timing of his distribution, the balance or remaining balance credited to a Participants Account shall be paid to his Beneficiary in a single lump-sum cash payment within ninety (90) days following the receipt by the Administrator of a certified copy of the death certificate. If multiple Beneficiaries have been designated by the Participant, each Beneficiary shall receive a single lump-sum cash payment of his specified portion of the Participants Account balance within ninety (90) days following the receipt by the Administrator of a certified copy of the death certificate. If the Participant has not specified percentages for multiple Beneficiaries, his Account will be divided and distributed to them on a per capita basis.
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A Participant may designate a Beneficiary or Beneficiaries, or change any prior designation of Beneficiary or Beneficiaries in accordance with rules and procedures established by the Administrator (including, but not limited to, the right to require the consent of a Participants spouse in the event the spouse is not named as the sole primary Beneficiary).
If a designated Beneficiary predeceases a Participant, the amount apportioned to that designated Beneficiary shall be payable to the designated Contingent Beneficiary, if any. If a Beneficiary dies within thirty (30) days of the date the Participant dies, the Beneficiary shall be considered to have predeceased the Participant for purposes of this Section 6.2.
If the Administrator finds either that there is no designated Beneficiary for all or a portion of a Participants Account, or that the designated Beneficiary and any Contingent Beneficiary for all or a portion of a Participants account have predeceased the Participant, the amount in question shall be paid as follows: (a) if the Participant leaves a surviving spouse, the entire Account balance shall be paid to the surviving spouse, and (b) only if the Participant leaves no surviving spouse, the entire Account balance shall be paid (i) first to the executor or administrator of the Participants estate, or (ii) if there is no administration of his estate, to the Participants heirs at law, as determined by the Administrator.
Notwithstanding the preceding provisions of this Article 6 and to the extent not prohibited by state or federal law, if a Participant is divorced from his spouse and, at the time of his death, is not remarried to the person from whom he was divorced, any designation of such divorced spouse shall be null and void unless the contrary is expressly stated in a writing that is filed by the Participant with the Administrator and accepted by the Administrator. The amount that would otherwise have been paid to such divorced spouse shall instead be paid to the persons specified in accordance with the applicable provisions of this Article 6 as if such divorced spouse did not survive the Participant.
If the Administrator is in doubt as to the right of any person to receive any amount hereunder, the Administrator, in its discretion, may direct that the entire Account balance be paid into any court of competent jurisdiction in an interpleader action, and such payment shall be a full and complete discharge of any liability or obligation under the Plan to the full extent of such payment.
6.3 Disability. Notwithstanding any prior election regarding the form or timing of his distribution, the balance or remaining balance credited to a Participants Account shall be paid to the Participant in a single lump-sum cash payment within ninety (90) days following the date the Participant is determined to be Disabled.
ARTICLE 7 DISTRIBUTION OF BENEFITS
7.1 Amount of Benefits. The amount credited to a Participants Account as determined under Articles 4 and 6 shall determine and constitute the basis for the value of benefits payable to the Participant under the Plan.
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7.2 Method and Timing of Distributions. Subject to Sections 7.3 and 7.4, distributions under the Plan shall be made at the time and in the manner provided in Section 3.6. If allowed by the Administrator, a Participant may elect to further delay the payment date for a minimum period of sixty (60) months from the originally scheduled date of payment, provided that such election to delay payment (a) is made at least twelve (12) months before a scheduled date of payment and (b) is not effective until at least twelve (12) months after the date on which the election is made. A re-deferral election must be made in accordance with procedures and rules established by the Administrator, which shall be construed and administered in accordance with Code Section 409A. The Participant may, at the same time the date of payment is re-deferred, change the form of payment provided that such change in the form of payment does not effectuate an acceleration of payment. Notwithstanding any provision contained herein to the contrary, a distribution made to a Key Employee shall not be made before the date which is six (6) months after the date the Key Employee has a Separation from Service unless otherwise permitted under Code Section 409A, such as in the event of his death.
7.3 Unforeseeable Emergency. A Participant may request a distribution due to an Unforeseeable Emergency. The request must be in writing and must be submitted to the Administrator along with evidence that the circumstances constitute an Unforeseeable Emergency. The Administrator has the discretion to require whatever evidence it deems necessary to determine whether a distribution is warranted. Whether a Participant has incurred an Unforeseeable Emergency will be determined by the Administrator on the basis of the relevant facts and circumstances in its sole discretion, but, in no event, will an Unforeseeable Emergency be deemed to exist if the hardship can be relieved: (a) through reimbursement or compensation by insurance or otherwise, (b) by liquidation of the Participants assets to the extent such liquidation would not itself cause severe financial hardship, or (c) by cessation of deferrals under the Plan. A distribution due to an Unforeseeable Emergency must be limited to the amount reasonably necessary to satisfy the emergency need and may also include any amount necessary to pay any federal, state or local income taxes or penalties that are reasonably anticipated to result from the distribution. The distribution will be made in the form of a single lump-sum cash payment without regard to any prior distribution election. Any distribution under this Section 7.3 shall be deducted from the Participants Account balance as of the date of the distribution.
7.4 Cashouts of Minimal Interests. If the amount credited to the Participants Account does not exceed the current dollar limitation under Code Section 402(g)(1)(B) ($16,500 in 2010, as adjusted under the Code in future years, or such higher dollar amount as Treasury Regulations may establish for cashouts of minimal interests under Code Section 409A), at the time he has a Separation from Service, and such Participant is not a Key Employee, the Company reserves the right to pay such amount to the Participant in a single lump-sum cash payment within ninety (90) days following such Separation from Service, regardless of whether the Participant (i) had made a different election regarding time or form of payment or (ii) was receiving installment payments at the time of Separation from Service. In the case of a Key Employee, such cashout payment shall not
13
be made before the date that is at least six (6) months from the date of his Separation from Service or such earlier date upon which such amount can be paid under Code Section 409A without being subject to taxation thereunder.
7.5 Distribution to a Key Employee. Notwithstanding any provision of the Plan to contrary, any lump sum or installment payment distribution payable to a Participant who is a Key Employee due to his Separation from Service (for any reason except due to his death) shall not be made before the date that is six (6) months after the date of his Separation from Service.
ARTICLE 8 AMENDMENT AND TERMINATION
8.1 Amendment by Company. The Company reserves the right to amend the Plan through action of the Board or the Compensation Committee. An amendment must be in writing and executed by an officer authorized to take such action. Each amendment shall not be effective prior to approval by the Board or the Compensation Committee in its resolution, unless necessary to comply with applicable laws or regulations. No amendment can directly or indirectly deprive any current or former Participant or Beneficiary of all or any portion of his Account balance that has accrued as of the date of such amendment. An amendment that does not materially affect the rights of any Participant under the Plan and is desirable for administrative purposes, or is necessary to comply with any applicable law or regulation, may be approved and executed, without action of the Board or the Compensation Committee, by any officer of the Company so authorized by the Board or the Compensation Committee.
Notwithstanding the preceding paragraph of this Section 8.1, the Plan may be amended if required to ensure that the Plan is characterized as a top-hat plan of deferred compensation maintained for a select group of management or highly compensated employees as described under ERISA Sections 201(2), 301(a)(3), and 401(a)(1), or to conform the Plan to the requirements of ERISA for top-hat plans or the requirements of the Code for deferred compensation plans including Code Section 409A. No such amendment for this exclusive purpose shall be considered prejudicial to the interest of a Participant or a Beneficiary hereunder.
8.2 Retroactive Amendments. An amendment made by the Company in accordance with Section 8.1 may be made effective on a date prior to the first day of the Plan Year in which it is adopted if such amendment is necessary or appropriate to enable the Plan to satisfy the applicable requirements of the Code, ERISA or to any other change in federal law or to any regulations or ruling thereunder. Any retroactive amendment by the Company shall be subject to the provisions of Section 8.1.
8.3 Special Plan and Deferral Election Amendments. Notwithstanding Sections 8.1 or 8.2 or any other provision of the Plan or a deferral election agreement to the contrary, the Company has reserved the unilateral right and discretion to amend the Plan and a Participants deferral elections hereunder to the extent necessary to comply with Code Section 409A, or to be exempt from the application of Code Section 409A, to the maximum extent permitted under Code Section 409A.
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8.4 Plan Termination. The Plan has been adopted with the intention and expectation that it will be continued indefinitely. The Company, however, reserves the right to terminate the Plan at any time without any liability for any such discontinuance or termination.
In the event of the termination of the Plan, no additional vesting shall accrue on a Participants behalf after the termination date. In accordance with Code Section 409A, termination of the Plan shall not, by itself, create a distribution event.
Upon termination of the Plan, distribution of benefits shall be made to Participants and Beneficiaries in the same manner and at the same time as described in the Plan, unless one of the following termination events occurs, in which case, all such amounts shall be distributed in a lump sum upon termination, or upon the earliest date allowable under Code Section 409A:
(a) the Companys termination and liquidation of the Plan within twelve (12) months of a corporate dissolution taxed under Code Section 331, or with the approval of a bankruptcy court pursuant to 11 U.S.C. Section 503(b)(1)(A);
(b) the Companys termination and liquidation of the Plan pursuant to irrevocable action taken by the Company within the thirty (30) days preceding or twelve (12) months following a change of control event (within the meaning of Code Section 409A), provided that all agreements, methods, programs, and other arrangements sponsored by the Company or an affiliated entity that are aggregated under Code Section 409A are terminated and liquidated with respect to each Participant that experiences the change in control event; or
(c) the Companys termination and liquidation of the Plan, provided that (1) the termination and liquidation does not occur proximate to a downturn in the financial health of the Company; (2) the Company terminates and liquidates all agreements, methods, programs, and other arrangements sponsored by the Company that would be aggregated under Code Section 409A if the same Participant had deferrals of compensation under all of the agreements, methods, programs, and other arrangements sponsored by the Company that are terminated and liquidated; (3) no payments in liquidation of the Plan are made within twelve (12) months of the date the Company takes all necessary action to irrevocably terminate and liquidate the Plan other than payments that would have been payable absent the termination and liquidation; and (4) the Company does not adopt a new plan that would be aggregated with any terminated and liquidated plan under Code Section 409A if the same Participant participated in both plans, at any time within three (3) years following the date the Company takes all necessary action to irrevocably terminate and liquidate the Plan.
8.5 Distribution Upon Termination of the Plan. Upon termination of the Plan, no further contributions that have not accrued as of the termination date shall be made under the Plan. Each Participants Account at the time of termination shall continue to be governed by the terms of the Plan until fully distributed in accordance with the terms of the Plan.
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ARTICLE 9 THE TRUST
9.1 Establishment of Trust. The Company may, but is not required to, establish a trust, or use an existing trust, to hold amounts which the Company may contribute from time to time to correspond to some or all amounts credited to Participants under Section 4.1. If the Company elects to establish a trust, the provisions of Sections 9.2 and 9.3 shall be operative.
9.2 Grantor Trust. The Company may establish a trust, or use an existing trust, between the Company and a trustee pursuant to a separate written trust agreement. Any such trust shall be created as a grantor trust under the Code Sections 671-678, and the establishment of the trust shall not cause the Participant to realize current income on amounts contributed to the trust. In the event that the Company establishes such a trust or uses an existing trust, the Company shall be under no obligation to place assets in such trust to secure the Companys payment obligations under the Plan.
9.3 Investment of Trust Funds. Any amounts contributed to a trust described in this Article 9 may be invested by the trustee in accordance with the provisions of the trust agreement and the instructions of the Administrator or the Company. Trust investments need not reflect the hypothetical investments selected by Participants under Section 5.1 for the purpose of adjusting Account balances, and the investment results of the trust shall not affect the hypothetical investment adjustments to Accounts under the Plan.
9.4 Participants Rights under a Trust. The assets of any trust hereunder shall be held for the benefit of the Participants in accordance with the terms of the Plan and the trust agreement. The assets of the trust shall remain subject to the claims of the general creditors of the Company, and the rights of the Participants to the amounts in the trust shall be limited in the event that the Company becomes insolvent. No Participant or Beneficiary shall have any preferred claim to, or any beneficial ownership interest in, any assets of the trust fund.
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ARTICLE 10 MISCELLANEOUS
10.1 Unsecured General Creditor of the Company. Participants and their Beneficiaries, heirs, successors and assigns shall have no legal or equitable rights, interests or claims in any property or assets of the Company as the result of participating in the Plan. For purposes of the payment of benefits under the Plan, any and all of the Companys assets shall be, and shall remain, the general, unpledged, unrestricted assets of the Company, and as such, shall remain subject to the claims of the general creditors of the Company. The Companys obligation under the Plan shall be merely that of an unfunded and unsecured promise to pay compensation in the future.
10.2 Limitation of Rights . Nothing in this plan shall be construed to:
(a) Give any individual who is employed by the Company any right to be a Participant unless and until such person is selected under the terms of the Plan;
(b) Give any Participant any rights, other than as an unsecured general creditor of the Company;
(c) Limit in any way the right of the Company to terminate an Eligible Employees employment;
(d) Give a Participant or any other person any interest in any trust, fund or in any specific asset of the Company; or
(e) Be evidence of any agreement or understanding, express or implied, that the Company will employ a Participant in any particular position, at any particular rate of remuneration, or for any particular time period.
10.3 The Companys Liability. The Companys liability for the payment of benefits under the Plan shall be defined only by the Plan and by the deferral agreements, and form and timing of payment elections, as entered into between a Participant and the Company under the Plan. The Company shall have no obligation or liability to a Participant under the Plan except as provided by the Plan.
10.4 Satisfaction of Benefit Obligation. The Company may, but is not obligated, to purchase an annuity or other insurance/financial product to satisfy the payment of benefit obligations for some or all of the Participants under the Plan. In the event that such an annuity or other product is utilized and a Participant or his Beneficiary has received the benefits entitled under the Plan from such annuity or other product, then such benefit obligation under the Plan shall be considered satisfied. Any annuity or other product used to provide funding under the Plan shall be an asset of the Company, and no Participant shall have any beneficial ownership interest in such asset of the Company.
In order to meet its contingent obligations under the Plan, the Company shall not set aside any assets or otherwise create any type of fund in which any Participant (or any person claiming under such Participant) has an interest other than that of an unsecured general
17
creditor of the Company or that would provide any Participant, or any person claiming under such Participant, with a legally enforceable right to priority over any general creditor of the Company in the event that the Company becomes insolvent.
10.5 Spendthrift Provision. No amount payable or to become payable from the Plan will be subject to: (a) anticipation or assignment by any person entitled to receive benefits under the Plan; (b) attachment by, interference with, or control of any creditor of any person entitled to receive benefits under the Plan; or (c) being taken or reached by any legal or equitable process in satisfaction of any debt or liability of any person entitled to receive benefits under the Plan. Any attempted conveyance, transfer, assignment, mortgage, pledge, or encumbrance of the Plan, any part of it or any interest in it, by any person entitled to receive benefits under the Plan prior to distribution will be void, regardless of whether that conveyance, transfer, assignment, mortgage, pledge, or encumbrance is intended to be effective before or after any distribution of benefits under the Plan. In addition, the Administrator shall not recognize any conveyance, transfer, assignment, mortgage, pledge or encumbrance by any person entitled to receive benefits under the Plan, and shall not pay any amount to any creditor or assignee of such person for any cause whatsoever. However, this Section 10.6 shall not affect the provisions of Section 10.1 regarding the claims of general creditors of the Company.
In the event that any Participants or Beneficiarys benefits hereunder are attempted to be garnished or attached by order of any court, the Company, in its discretion, may bring an action or a declaratory judgment in a court of competent jurisdiction to determine the proper recipient of the benefits to be paid under the Plan.
10.6 Incapacity of Participant or Beneficiary. If the Administrator determines, in its discretion, that any Participant or Beneficiary to whom a payment is payable under the Plan is unable to care for his affairs because of illness or accident or is under a legal disability, any payment due (unless a prior claim therefore shall have been made by a duly appointed legal representative), at the discretion of the Administrator, may be paid to the spouse, child, parent, sibling of such Participant or Beneficiary or to any person whom the Administrator has determined has incurred expense for such Participant or Beneficiary. In the event that a guardian, conservator or other person legally vested with the care of any person receiving a benefit under the Plan is appointed by a court of competent jurisdiction, payments shall be made to such guardian, conservator or other person, provided that proper proof of appointment is furnished in a form and manner acceptable to the Administrator. Any payment made in accordance with this Section 10.7 shall be a complete discharge of the obligations of the Company under the Plan.
10.7 Waiver. No term or condition of the Plan shall be deemed to have been waived, nor shall there be an estoppel against the enforcement of any provision of the Plan, except by written instrument of the party charged with such waiver or estoppel. No such written waiver shall be deemed a continuing waiver unless specifically stated therein, and each such waiver shall operate only as to the specific term or condition waived and shall not constitute a waiver of such term or condition for the future or as to any act other than that specifically waived.
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10.8 Notices. Any notice or other communication in connection with the Plan shall be deemed delivered in writing if addressed as provided below and if either actually delivered at said address or, in the case of a letter, five (5) business days shall have elapsed after the same shall have been deposited in the U.S. mails, first-class postage prepaid and registered or certified:
(a) The Company or Administrator If the notice is sent to the Company or Administrator, it must be sent to the then-current corporate headquarters address of the Company, provided that the envelope includes Attn: Benefits Department Human Resources; or
(b) Participant The mailing or electronic address of the Participant as reflected in the then-current records of the Company. Each Participant is responsible for ensuring that the Company or Administrator has the Participants current mailing address under the procedure for updating mailing addresses utilized by the Company or Administrator.
10.9 Tax Withholding. The Company shall have the right to deduct from all payments or deferrals made under the Plan any tax required by law to be withheld. If the Company concludes that tax is owing with respect to any deferral or payment hereunder, the Company shall withhold such amounts from any payments due the Participant, as permitted by law, or otherwise make appropriate arrangements with the Participant or his Beneficiary for satisfaction of such obligation. A tax, for purposes of this Section 10.10 means any federal, state, local or any other governmental income tax, employment or payroll tax, excise tax, or any other tax or assessment that is owed with respect to amounts deferred (and any earnings thereon) and any payments made to Participants under the Plan.
With respect to deferred compensation elections under the Plan, the Company shall withhold the required share of FICA, FUTA and other applicable employment and payroll taxes from the other non-deferred compensation of an Eligible Employee who is a Participant. These required payroll taxes shall be withheld at the same time that the deferred compensation contributions are credited to his Account.
10.10 Governing Law. The Plan will be construed, administered and enforced according to ERISA, the Code and other controlling federal law, and to the extent not preempted thereby, the laws of the State of Texas without regard to its conflicts of law principles.
10.11 Intention to Comply with Code Section 409A. The Plan is intended to comply with Code Section 409A and any ambiguous provision will be construed in a manner that is compliant with, or exempt from, the application of Code Section 409A. It is intended that since January 1, 2009, the Plan will comply with provisions of Code Section 409A and the final regulations and other authoritative guidance thereunder. It is also intended that during the period beginning January 1, 2005 and ending December 31, 2008, the Plan was operated in reasonable good faith compliance with the provisions of Code Section 409A and the interim authoritative guidance thereunder. If any provision of the
19
Plan would cause a Participant to incur any additional tax or interest under Code Section 409A, the Company may reform such provision to comply with Code Section 409A to the maximum extent permitted under Code Section 409A as determined by the Company.
ARTICLE 11 PLAN ADMINISTRATION
11.1 Powers and Responsibilities of the Administrator. The Administrator has the full power, full discretion and the full responsibility to administer the Plan in all of its details, subject, however, to the applicable requirements of applicable law. The Administrators powers and responsibilities include, but are not limited to, the following:
(a) To make and enforce such rules and procedures as it deems necessary or proper for the efficient administration of the Plan;
(b) To interpret the Plan, its interpretation thereof in good faith to be final and conclusive on all persons claiming benefits under the Plan;
(c) To decide all questions concerning the Plan and the eligibility of any person to participate in the Plan;
(d) To administer the claims and review procedures specified in Section 11.3, including determining all facts pertaining to a claim;
(e) To compute the amount of benefits which will be payable to any Participant, former Participant or Beneficiary in accordance with the provisions of the Plan;
(f) To determine the person or persons to whom such benefits will be paid;
(g) To authorize the payment of benefits;
(h) To comply with the reporting and disclosure requirements of Part 1 of Subtitle B of Title I of ERISA;
(i) To appoint such agents, counsel, accountants, and consultants as may be required to assist in administering the Plan;
(j) By written instrument, to allocate and delegate its responsibilities hereunder to designated persons or entities, including without limitation, to employees of the Company; and
(k) To address and resolve any and all matters that may arise with regard to the Plan and its administration.
11.2 Interpretation of the Plan. The Administrator shall interpret, construe and construct the Plan, including correcting any defect, supplying any omission or reconciling any inconsistency. The Administrator shall have all powers necessary or appropriate to implement and administer the terms and provisions of the Plan, including the power to make findings of fact. The determination of the Administrator as to the proper interpretation, construction, or application of any term or provision of the Plan shall be final, binding, and conclusive with respect to all Participants and other interested persons.
11.3 Claims and Review Procedures. Claims for Plan benefits and reviews of appeals of benefit claims arising under the Plan that have been denied or modified are to be processed in accordance with written Plan claims procedures established by the Administrator and adopted by the Company. The Plans claims and appeal procedures shall be established and administered in accordance with the applicable requirements for such procedures under ERISA.
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11.4 Plan Administrative Costs. Unless otherwise determined by the Administrator, all reasonable costs and expenses (including legal, accounting, and employee communication fees) incurred by the Administrator in administering the Plan shall be paid by the Company.
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IN WITNESS WHEREOF, the Company, by its duly authorized officer, has caused the amended and restated Plan to be adopted on this 12 th day of November, 2009, to be effective as of January 1, 2010.
ANADARKO PETROLEUM CORPORATION | ||
By: | /s/ Julia A. Struble | |
Julia A. Struble | ||
Vice President, Human Resources |
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EXHIBIT 12
ANADARKO PETROLEUM CORPORATION
CONSOLIDATED STATEMENT OF COMPUTATION OF RATIOS OF
EARNINGS TO FIXED CHARGES AND EARNINGS TO
COMBINED FIXED CHARGES AND PREFERRED STOCK DIVIDENDS
Years Ended December 31
(Unaudited) |
||||||||||||||||||||
millions except ratio amounts | 2009 | 2008 | 2007 | 2006 | 2005 | |||||||||||||||
Income from continuing operations before income taxes (a) |
$ | (108 | ) | $ | 5,368 | $ | 6,329 | $ | 3,737 | $ | 3,253 | |||||||||
Equity (income) adjustment |
(76 | ) | (134 | ) | (158 | ) | | | ||||||||||||
Fixed charges, to the extent they affect current year earnings |
982 | 1,269 | 1,450 | 858 | 279 | |||||||||||||||
Distributions from equity investees |
49 | 136 | 104 | (21 | ) | | ||||||||||||||
Capitalized interest |
(69 | ) | (123 | ) | (122 | ) | (80 | ) | (45 | ) | ||||||||||
Total Earnings |
778 | 6,516 | 7,603 | 4,494 | 3,487 | |||||||||||||||
Interest expense including capitalized interest |
758 | 876 | 1,214 | 730 | 266 | |||||||||||||||
Interest expense included in other (income) expense |
57 | 123 | 102 | | | |||||||||||||||
Estimated interest portion of rental expenditures (b) |
262 | 356 | 316 | 128 | 13 | |||||||||||||||
Total Fixed Charges |
1,077 | 1,355 | 1,632 | 858 | 279 | |||||||||||||||
Preferred Stock Dividends |
| 2 | 5 | 5 | 8 | |||||||||||||||
Combined Fixed Charges and Preferred Stock Dividends |
1,077 | 1,357 | 1,637 | 863 | 287 | |||||||||||||||
Ratio of Earnings to Fixed Charges* |
0.72 | 4.81 | 4.66 | 5.24 | 12.50 | |||||||||||||||
Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends* |
0.72 | 4.80 | 4.64 | 5.21 | 12.15 | |||||||||||||||
* | As a result of the Companys net loss in 2009, Anadarkos earnings did not cover fixed charges nor combined fixed charges by $299 million. |
These ratios were computed by dividing earnings by either fixed charges or combined fixed charges and preferred stock dividends. For this purpose, earnings include pre-tax income from continuing operations before adjustment for income or loss from equity investees, fixed charges to the extent they affect current year earnings, amortization of capitalized interest, adding distributed income of equity investees, and subtracting interest capitalized during the year. Fixed charges include interest expensed and capitalized, amortized premiums, discounts and capitalized expenses related to indebtedness, and estimates of interest within rental expenses. Preferred stock dividends are adjusted to reflect the amount of pretax earnings required for payment.
(a) | Pretax income from continuing operations for the year ended December 31, 2007 includes gain on asset divestitures of $4.66 billion. Gains (losses) on asset divestitures for other periods presented did not have a significant effect on the corresponding ratios of earnings to fixed charges and to combined fixed charges and preferred stock dividends. |
(b) | Reflects a portion of rental expenditures representative of interest factor, whether such rentals are expensed or capitalized when incurred. For the years ended December 31, 2009, 2008 and 2007, estimated interest component in rentals includes approximately $185 million, $270 million and $225 million, respectively, associated with the Companys drilling rig leases. |
EXHIBIT 21
LIST OF SUBSIDIARIES (1)
Anadarko Algeria Company LLC
a Delaware limited liability company,
Anadarko China Holdings 2 Company
a Cayman Islands corporation,
Anadarko E&P Company LP *
a Delaware limited partnership,
Anadarko Energy Services Company *
a Delaware corporation,
Anadarko Global Funding 1 Company
a Cayman Islands corporation,
Anadarko Global Funding II Ltd.
a Bahama Islands limited liability company,
Anadarko Global Holdings Company
a Delaware corporation,
Anadarko Holding Company
a Utah corporation,
Anadarko International Trading Corporation
a Delaware corporation,
Anadarko Land Corp
a Nebraska corporation,
Anadarko Limited Resources LLC
a Delaware limited liability company,
Anadarko Midkiff/Chaney Dell LLC
a Delaware limited liability company,
Anadarko Uintah Midstream, LLC
a Delaware limited liability company,
Anadarko WCTP Company
a Cayman Islands corporation,
Anadarko West Texas LLC
a Delaware limited liability company,
* | Subsidiary meets the conditions of a significant subsidiary under the Securities and Exchange Commission Regulation S-X 210.1-02(w). |
(1) | The names of certain subsidiaries have been omitted since, considered in the aggregate as a single subsidiary, they would not constitute a significant subsidiary, as of the end of the year covered by this report, as defined under the Securities and Exchange Commission Regulation S-X 210.1-02(w). |
LIST OF SUBSIDIARIES (1)
Anadarko Worldwide Holdings CV *
a Netherlands limited partnership,
Bitter Creek Coal Company
a Utah corporation,
Headwater LLC
a Delaware limited liability company,
Howell Petroleum Corporation
a Delaware corporation,
Kerr-McGee (Nevada) LLC
a Nevada limited liability company,
Kerr-McGee China Petroleum LTD.
a Bahama Islands limited liability company,
Kerr-McGee Corporation *
a Delaware corporation,
Kerr-McGee Energy Services Corporation
a Delaware corporation,
Kerr-McGee Gathering LLC
a Colorado limited liability company,
Kerr-McGee Oil and Gas Corporation *
a Delaware corporation,
Kerr-McGee Oil and Gas Onshore LP *
a Delaware limited partnership,
Kerr-McGee Onshore Holding LLC *
a Delaware limited liability company,
Kerr-McGee Shared Services Company LLC *
a Delaware limited liability company,
Kerr-McGee Worldwide Corporation *
a Delaware corporation,
KM BM-C Seven Ltd. *
a Bahamas limited liability company,
* | Subsidiary meets the conditions of a significant subsidiary under the Securities and Exchange Commission Regulation S-X 210.1-02(w). |
(1) | The names of certain subsidiaries have been omitted since, considered in the aggregate as a single subsidiary, they would not constitute a significant subsidiary, as of the end of the year covered by this report, as defined under the Securities and Exchange Commission Regulation S-X 210.1-02(w). |
LIST OF SUBSIDIARIES (1)
KM Denmark Overseas ApS
a Denmark corporation,
KM Global LTD.
a Delaware corporation,
KM Investment Corporation *
a Nevada corporation,
Lance Oil & Gas Company, Inc.
a Delaware corporation,
Mountain Gas Resources LLC
a Delaware limited liability company,
Resources Holding Inc.
a Delaware corporation,
Rock Springs Royalty Company LLC
a Utah limited liability company,
Upland Industries Corporation
a Nebraska corporation,
Western Gas Partners, LP
a Delaware limited partnership,
Western Gas Resources, Inc. *
a Delaware corporation,
WGR Asset Holding Company LLC
a Delaware limited liability company,
WHL, Inc. *
a Delaware corporation,
* | Subsidiary meets the conditions of a significant subsidiary under the Securities and Exchange Commission Regulation S-X 210.1-02(w). |
(1) | The names of certain subsidiaries have been omitted since, considered in the aggregate as a single subsidiary, they would not constitute a significant subsidiary, as of the end of the year covered by this report, as defined under the Securities and Exchange Commission Regulation S-X 210.1-02(w). |
EXHIBIT 23(i)
Consent of Independent Registered Public Accounting Firm
The Board of Directors
Anadarko Petroleum Corporation:
We consent to the incorporation by reference in the registration statements on Form S-3 and S-8 (No. 33-8643), Form S-3 (No. 333- 161370) and Form S-8 (Nos. 333-152049 and 333-161367) of Anadarko Petroleum Corporation of our reports dated February 23, 2010, with respect to the consolidated balance sheets of Anadarko Petroleum Corporation 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 the effectiveness of internal control over financial reporting as of December 31, 2009, which reports appear in the December 31, 2009 annual report on Form 10-K of Anadarko Petroleum Corporation.
/s/ KPMG LLP
Houston, Texas
February 23, 2010
EXHIBIT 23(ii)
February 23, 2010
Anadarko Petroleum Corporation | ||
1201 Lake Robbins Drive | ||
The Woodlands, TX 77380 | ||
Re: Securities and Exchange Commission |
||
Form 10-K of Anadarko Petroleum Corporation |
Gentlemen:
We hereby consent to the incorporation by reference in the
Registration Statements on Form S-3 and S-8 (No. 33-8643),
Form S-3 (No. 333-161370) and Form S-8 (Nos. 333-152049 and 333-161367) of Anadarko Petroleum Corporation of our Procedures and Methods Review Letter dated February 23, 2010,
regarding the Anadarko Petroleum Corporation Proved Reserves and Future Net Revenues as of December 31, 2009, and of references to our firm which are to be included in Form 10-K for the year ended December 31, 2009 to be filed by Anadarko
Petroleum Corporation with the Securities and Exchange Commission.
Miller and Lents, Ltd. has no financial interest in Anadarko Petroleum Corporation or in any of its affiliated companies or subsidiaries and is not to receive any such interest as payment for such letter. Miller and Lents, Ltd. also has no director, officer, or employee employed or otherwise connected with Anadarko Petroleum Corporation. We are not employed by Anadarko Petroleum Corporation on a contingent basis.
Very truly yours, | ||
MILLER AND LENTS, LTD. | ||
Texas Registered Engineering Firm No. F-1442 | ||
By: | /s/ ROBERT J. OBERST | |
Robert J. Oberst, P.E. | ||
Senior Vice President |
EXHIBIT 24
POWER OF ATTORNEY
KNOW ALL BY THESE PRESENTS that each undersigned Director of ANADARKO PETROLEUM CORPORATION (the Company), a Delaware corporation, does hereby constitute and appoint ROBERT G. GWIN, M. CATHY DOUGLAS, and ROBERT K. REEVES, and each of them, with full power to act without the other, his or her true and lawful attorney and agent to do any and all acts and things and execute any and all instruments which, with the advice of counsel, said attorney and agent may deem necessary or advisable to enable the Company to comply with the Securities Exchange Act of 1934, as amended, and any rules, regulations and requirements of the Securities and Exchange Commission in connection with the filing under said Act of the Form 10-K Annual Report for the Year Ended December 31, 2009, including specifically, but without limitation thereof, to sign his or her name as a Director of the Company to the Form 10-K Annual Report for the Year Ended December 31, 2009 filed with the Securities and Exchange Commission, and to any instrument or document filed as a part of, or in connection with, said Form 10-K Annual Report for the Year Ended December 31, 2009 or amendment thereto; and the undersigned does hereby ratify and confirm all that said attorney and agent shall do or cause to be done by virtue thereof.
IN WITNESS WHEREOF, the undersigned have subscribed these presents this 17th day of February, 2010.
/s/ JAMES T. HACKETT James T. Hackett |
/s/ ROBERT J. ALLISON, JR. Robert J. Allison, Jr. |
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/s/ JOHN R. BUTLER, JR. John R. Butler, Jr. |
/s/ LUKE R. CORBETT Luke R. Corbett |
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/s/ H. PAULETT EBERHART H. Paulett Eberhart |
/s/ PETER J. FLUOR Peter J. Fluor |
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/s/ PRESTON M. GEREN III Preston M. Geren III |
/s/ JOHN R. GORDON John R. Gordon |
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/s/ PAULA ROSPUT REYNOLDS Paula Rosput Reynolds |
EXHIBIT 31(i)
CERTIFICATIONS
I, James T. Hackett, certify that:
1. | I have reviewed this annual report on Form 10-K of Anadarko Petroleum Corporation; |
2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; |
4. | The registrants other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: |
a) | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
b) | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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; |
c) | Evaluated the effectiveness of the registrants disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
d) | Disclosed in this report any change in the registrants internal control over financial reporting that occurred during the registrants most recent fiscal quarter (the registrants fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrants internal control over financial reporting; and |
5. | The registrants other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrants auditors and the audit committee of the registrants board of directors (or persons performing the equivalent functions): |
a) | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrants ability to record, process, summarize and report financial information; and |
b) | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrants internal control over financial reporting. |
Date: February 23, 2010
/s/ JAMES T. HACKETT |
Chairman and Chief Executive Officer |
EXHIBIT 31(ii)
CERTIFICATIONS
I, Robert G. Gwin, certify that:
1. | I have reviewed this annual report on Form 10-K of Anadarko Petroleum Corporation; |
2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; |
4. | The registrants other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: |
a) | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
b) | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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; |
c) | Evaluated the effectiveness of the registrants disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
d) | Disclosed in this report any change in the registrants internal control over financial reporting that occurred during the registrants most recent fiscal quarter (the registrants fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrants internal control over financial reporting; and |
5. | The registrants other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrants auditors and the audit committee of the registrants board of directors (or persons performing the equivalent functions): |
a) | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrants ability to record, process, summarize and report financial information; and |
b) | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrants internal control over financial reporting. |
Date: February 23, 2010
/s/ ROBERT G. GWIN |
Senior Vice President, Finance and Chief Financial Officer |
EXHIBIT 32
SECTION 1350 CERTIFICATION OF PERIODIC REPORT
Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350, James T. Hackett, Chairman and Chief Executive Officer of Anadarko Petroleum Corporation (Company) and Robert G. Gwin, Senior Vice President, Finance and Chief Financial Officer of the Company, certify that:
(1) | the Annual Report on Form 10-K of the Company for the period ending December 31, 2009, as filed with the Securities and Exchange Commission on the date hereof (Report), fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and |
(2) | the information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Company. |
February 23, 2010
/s/ JAMES T. HACKETT | ||
James T. Hackett | ||
Chairman and Chief Executive Officer | ||
February 23, 2010 |
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/s/ ROBERT G. GWIN | ||
Robert G. Gwin | ||
Senior Vice President, Finance and Chief | ||
Financial Officer |
This certification is made solely pursuant to 18 U.S.C. Section 1350, and not for any other purpose. A signed original of this written statement required by Section 906 will be retained by Anadarko and furnished to the Securities and Exchange Commission or its staff upon request.
EXHIBIT 99
February 23, 2010
Mr. Robert G. Gwin | ||
Senior Vice President, Finance | ||
and Chief Financial Officer | ||
Anadarko Petroleum Corporation | ||
1201 Lake Robbins Drive | ||
The Woodlands, TX 77380 | ||
Re: Procedures and Methods Review of |
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Anadarko Petroleum Corporation |
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Proved Reserves and Future Net Cash Flows |
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As of December 31, 2009 |
Dear Mr. Gwin:
At your request, Miller and Lents, Ltd. reviewed the procedures and methods employed by Anadarko Petroleum Corporation (Anadarko) in preparing its internal estimates of proved reserves and future net revenues (hereafter referred to as future net cash flows to be consistent with Anadarkos terminology in its 10K) as of December 31, 2009. The purpose of the review was to determine that the procedures and methods used by Anadarko to estimate its proved reserves are based on generally accepted petroleum engineering and evaluation principles and are in accordance with the definitions contained in the Securities and Exchange Commission (SEC) Regulation S-X, Rule 4-10(a).
From July through December 2009, we participated in the review of 17 fields which included major assets in the United States and Algeria. Reserves estimates for these properties were approximately 1,857 million barrels of oil equivalent, or approximately 81 percent of Anadarkos total proved reserves as of December 31, 2009. In each review, Anadarkos technical staff presented us with an overview of the data, methods, and assumptions used in its reserve estimates. 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, we were provided with additional data and information that we requested in certain instances to satisfy ourselves that the procedures and methods used were in accordance with standard industry practices.
Based upon these reviews and our subsequent due diligence, it is our judgment that the general procedures and methods employed by Anadarko in estimating its December 31, 2009 proved reserves and future net cash flows are reasonable and in accordance with the SEC reserves definitions.
Anadarkos proved reserves were estimated generally by extrapolation of well-established historical production performance trends and/or were supported by other geologic and engineering studies. Where sufficient performance data did not exist, Anadarkos reserves were estimated by volumetric calculations or by analogy to similar producing properties.
The ownership, reversions, test and production data, operating costs, estimated capital expenditures and other information presented by Anadarko during the reviews were accepted as represented. We did not conduct any field inspections or other tests in conjunction with this procedures and methods review.
Our work was a review of Anadarkos procedures and methods only and does not constitute a complete review, study, or audit of Anadarkos estimated proved reserves and future net cash flows. Furthermore, our judgments are based on accepted standards of professional investigation but are subject to those generally recognized uncertainties associated with interpretation of geological, geophysical, and engineering information.
Miller and Lents, Ltd. is an international oil and gas consulting firm, founded in 1948, offering services and expertise in many phases of the oil and gas industry. The firm is registered with the Texas Board of Professional Engineers and is authorized to provide professional engineering services in the State of Texas. Our registration certificate number is F-1442, and current registration is effective to September 30, 2010. The engineering staff that performed the procedures and methods reviews are all university graduates, with degrees in petroleum engineering and/or advanced degrees in petroleum or chemical engineering. All are licensed professional engineers. Each is a qualified reserve evaluator with over 20 years of relevant experience in the estimation, assessment, and evaluation of oil and gas reserves.
Miller and Lents, Ltd. is independent with respect to Anadarko as provided in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. No director, officer, or key employee of Miller and Lents, Ltd. has any direct financial ownership in Anadarko or any affiliate. Our compensation for the required investigations is not contingent on the results obtained and reported, and we have not performed other work that would affect our objectivity.
Any distribution or publication of this letter or any part thereof must include this letter in its entirety.
Very truly yours, | ||
M ILLER AND L ENTS , L TD . | ||
Texas Registered Engineering Firm No. F-1442 | ||
By | /s/ ROBERT J. OBERST | |
Robert J. Oberst, P.E. | ||
Senior Vice President |
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