SEC Form 10-K Filing Report

Company: ANADARKO PETROLEUM CORP
CIK: 773910
SIC Code: 1311
Filing Date: 2013-02-19 00:00:00
Market Capitalization: 42044723.29737091

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ITEM 1. BUSINESS

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ITEM 1A. RISK FACTORS
Item 1A. Risk Factors
CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS
Unless the context otherwise requires, the terms “Anadarko” and “Company” refer to Anadarko Petroleum Corporation and its consolidated subsidiaries. The Company has made in this report, and may from time to time make in other public filings, press releases, and management discussions, forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 concerning the Company’s operations, economic performance, and financial condition. These forward-looking statements include information concerning future production and reserves, schedules, plans, timing of development, contributions from oil and gas properties, marketing and midstream activities, and also include 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,” “would,” “will,” “potential,” “continue,” “forecast,” “future,” “likely,” “outlook,” 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 be correct. Anadarko undertakes no obligation to publicly update or revise any forward-looking statements whether as a result of new information, future events, or otherwise.
These forward-looking statements involve risk and uncertainties. Important factors that could cause actual results to differ materially from the Company’s expectations include, but are not limited to, the following risks and uncertainties:
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the Company’s assumptions about the energy market
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production levels
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reserves levels
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operating results
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competitive conditions
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technology
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availability of capital resources, capital expenditures, and other contractual obligations
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supply and demand for, the price of, and the commercializing and transporting of natural gas, crude oil, natural gas liquids (NGLs), and other products or services
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volatility in the commodity-futures market
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weather
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inflation
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availability of goods and services, including unexpected changes in costs
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drilling risks
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future processing volumes and pipeline throughput
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general economic conditions, either internationally or nationally or in the jurisdictions in which the Company or its subsidiaries are doing business
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inability to timely obtain or maintain permits, including those necessary for drilling and/or development projects
Index to Financial Statements
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legislative or regulatory changes, including retroactive royalty or production tax regimes; hydraulic-fracturing regulation; deepwater drilling and permitting regulations; derivatives reform; changes in state, federal, and foreign income taxes; environmental regulation; environmental risks; and liability under federal, state, foreign, and local environmental laws and regulations
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ability of BP Exploration & Production Inc. (BP) to meet its indemnification obligations to the Company for, among other things, damage claims arising under the Oil Pollution Act of 1990 (OPA), claims for natural resource damages (NRD) and associated damage-assessment costs, and any claims arising under the Operating Agreement (OA) for the Macondo well, as well as the ability of BP Corporation North America Inc. (BPCNA) and BP p.l.c. to satisfy their guarantees of such indemnification obligations
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impact of remaining claims related to the Deepwater Horizon events, including, but not limited to, fines, penalties, and punitive damages against the Company, for which it is not indemnified by BP
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legislative and regulatory changes that may impact the Company’s Gulf of Mexico and international offshore operations, including those resulting from the Deepwater Horizon events
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current and potential legal proceedings, or environmental or other obligations related to or arising from Tronox Incorporated (Tronox)
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civil or political unrest or acts of terrorism in a region or country
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creditworthiness and performance of the Company’s counterparties, including financial institutions, operating partners, and other parties
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volatility in the securities, capital, or credit markets and related risks such as general credit, liquidity and interest-rate risk
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the Company’s ability to successfully monetize select assets, repay its debt, and the impact of changes in the Company’s credit ratings
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disruptions in international crude oil cargo shipping activities
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physical, digital, internal, and external security breaches
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supply and demand, technological, political, and commercial conditions associated with long-term development and production projects in domestic and international locations
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other factors discussed below and elsewhere in this Form 10-K, and in the Company’s other public filings, press releases, and discussions with Company management
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.
In January 2009, Tronox Incorporated (Tronox), a former subsidiary of Kerr-McGee Corporation (Kerr-McGee), which is a current subsidiary of Anadarko, and certain of Tronox’s subsidiaries filed voluntary petitions for relief under Chapter 11 of the U.S. Bankruptcy Code in the U.S. Bankruptcy Court for the Southern District of New York. Subsequently, in May 2009, Tronox and certain of its affiliates 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 and seeks, among other things, to recover damages, including interest, in excess of $18.9 billion from Kerr-McGee and Anadarko, as well as litigation fees and costs. An 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, financial condition, and liquidity.
For additional information regarding the nature and status of these and other material legal proceedings, see Note 17-Contingencies-Tronox Litigation in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.
Index to Financial Statements We may be subject to claims and liabilities relating to the Deepwater Horizon events that are not covered by BP’s indemnification obligations under our Settlement Agreement with BP, or that result in losses to the Company, notwithstanding BP’s indemnification against such losses, as a result of BP’s inability to satisfy its indemnification obligations under the Settlement Agreement and BPCNA’s and BP p.l.c.’s inability to satisfy their guarantees of BP’s indemnification obligations.
In October 2011, the Company and BP entered into a settlement agreement, mutual releases, and agreement to indemnify relating to the Deepwater Horizon events (Settlement Agreement). Pursuant to the Settlement Agreement, the Company is fully indemnified by BP against all claims, causes of action, losses, costs, expenses, liabilities, damages, or judgments of any kind arising out of the Deepwater Horizon events, related damage claims arising under OPA, NRD claims and assessment costs, and any claims arising under the OA. This indemnification is guaranteed by BPCNA and, in the event that the net worth of BPCNA declines below an agreed-on amount, BP p.l.c. has agreed to become the sole guarantor.
Any failure or inability on the part of BP to satisfy its indemnification obligations under the Settlement Agreement, or on the part of BPCNA or BP p.l.c. to satisfy their respective guarantee obligations, could subject us to significant monetary liability beyond the terms of the Settlement Agreement, which could have a material adverse effect on our business, prospects, results of operations, financial condition, and liquidity. In November 2012, BP settled all criminal and securities claims brought by the United States against BP, with BP agreeing to pay $4.0 billion over five years to the U.S. Department of Justice with respect to the criminal claims and further agreeing to pay another $525 million over three years to the Securities and Exchange Commission (SEC) with respect to the securities claims. BP represents that it is prepared to vigorously defend itself against remaining civil claims. Furthermore, in certain instances we may be required to recognize a liability for amounts for which we are indemnified in advance of or in connection with recognizing a receivable from BP for the related indemnity payment. Any such liability recognition without collection of the offsetting receivable could adversely impact our results of operations, our financial condition, and our ability to make borrowings.
Under the Settlement Agreement, BP does not indemnify the Company against fines and penalties, punitive damages, shareholder derivative or securities laws claims, or certain other claims. The adverse resolution of any current or future proceeding related to the Deepwater Horizon events for which we are not indemnified by BP could subject us to significant monetary liability, which could have a material adverse effect on our business, prospects, results of operations, financial condition, and liquidity.
Index to Financial Statements Oil, natural-gas, and NGLs prices are volatile. A substantial or extended decline in the price of these commodities 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 growth rates are highly dependent on the prices we receive for our oil, natural gas, and NGLs. The markets for oil, natural gas, and NGLs have been volatile historically and may continue to be volatile in the future. For example, market prices for natural gas in the United States have declined substantially from 2008 price levels, and the rapid development of shale plays throughout North America has contributed significantly to this trend. Factors influencing the prices of oil, natural gas, and NGLs are beyond our control. These factors include, but are not limited to, the following:
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domestic and worldwide supply of, and demand for, oil, natural gas, and NGLs
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volatile trading patterns in the commodity-futures markets
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cost of exploring for, developing, producing, transporting, and marketing oil, natural gas, and NGLs
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level of global crude-oil and natural-gas inventories
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weather conditions
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potential U.S. exports of liquefied natural gas
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ability of the members of the Organization of Petroleum Exporting Countries (OPEC) and other producing nations to agree to and maintain production levels
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worldwide military and political environment, civil and political unrest in Africa and the Middle East, uncertainty or instability resulting from the escalation or additional outbreak of armed hostilities, or further acts of terrorism in the United States, or elsewhere
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effect of worldwide energy conservation and environmental protection efforts
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price and availability of alternative and competing fuels
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price and level of foreign imports of oil, natural gas, and NGLs
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domestic and foreign governmental regulations and taxes
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proximity to, and capacity of, natural-gas pipelines and other transportation facilities
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general economic conditions worldwide
Index to Financial Statements The long-term effect of these and other factors on the prices of oil, natural gas, and NGLs is uncertain. Prolonged or substantial declines in these commodity prices may have the following effects on our business:
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adversely affecting our financial condition, liquidity, ability to finance planned capital expenditures, and results of operations
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reducing the amount of oil, natural gas, and NGLs that we can produce economically
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causing us to delay or postpone some of our capital projects
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reducing our revenues, operating income, or cash flows
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reducing the amounts of our estimated proved oil and natural-gas reserves
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reducing the carrying value of our oil and natural-gas properties
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reducing the standardized measure of discounted future net cash flows relating to oil and natural-gas reserves
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limiting our access to, or increasing the cost of, sources of capital, such as equity and long-term debt
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, regional, 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, regional, 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, from time to time, legislation has been proposed that could adversely affect our business, financial condition, results of operations, or cash flows related to the following:
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Climate Change. A number of state and regional efforts have emerged that are aimed at tracking and/or reducing emissions of green-house gases (GHGs). In addition, the U.S. Environmental Protection Agency (EPA) has made findings that emissions of GHGs present a danger to public health and the environment and, based on these findings, has adopted regulations that restrict emissions of GHGs under existing provisions of the federal Clean Air Act. We may be required to install “best available control technology” to limit emissions of GHGs from any new or significantly modified facilities that we may seek to construct in the future if they would otherwise emit large volumes of GHGs.
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Deficit Reduction or Tax Reform. Congress may undertake significant deficit reduction or comprehensive tax reform in the coming year. Proposals include provisions that would, if enacted, (i) eliminate the immediate deduction for intangible drilling and development costs, (ii) eliminate the manufacturing deduction for oil and gas qualified production activities, and (iii) eliminate the acceleration of depreciation for tangible property.
Index to Financial Statements Federal, state, and local legislative and regulatory initiatives relating to hydraulic fracturing, as well as governmental reviews of such activities, could result in increased costs, additional operating restrictions or delays, and adversely affect our production.
Hydraulic fracturing is an essential and common practice used to stimulate production of natural gas and/or oil from dense subsurface rock formations such as shales that generally exist between 4,000 and 14,000 feet below ground. We routinely apply hydraulic-fracturing techniques in many of our U.S. onshore oil and natural-gas drilling and completion programs. The process involves the injection of water, sand, and additives under pressure into a targeted subsurface formation. The water and pressure create fractures in the rock formations, which are held open by the grains of sand, enabling the oil or natural gas to flow to the wellbore. The process is typically regulated by state oil and natural-gas commissions; however, the EPA has asserted federal regulatory authority over certain hydraulic-fracturing activities involving diesel under the Safe Drinking Water Act and published draft permitting guidance in May 2012 addressing the performance of such activities using diesel fuels with the public comment period expiring in August 2012. In November 2011, the EPA announced its intent to develop and issue regulations under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing and the agency currently projects to issue an Advance Notice of Proposed Rulemaking in May 2013 that would seek public input on the design and scope of such disclosure regulations. In May 2012, the Department of the Interior (DOI) released draft regulations governing hydraulic fracturing on federal and Indian oil and gas leases to require disclosure of information regarding the chemicals used in hydraulic fracturing, advance approval for well-stimulation activities, mechanical integrity testing of casing, and monitoring of well-stimulation operations. In addition, Congress, from time to time, has considered adopting legislation intended to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic-fracturing process. In the event that a new, federal level of legal restrictions relating to the hydraulic-fracturing process is adopted in areas where we currently or in the future plan to operate, we may incur additional costs to comply with such federal requirements that may be significant in nature, and also could become subject to additional permitting requirements and experience added delays or curtailment in the pursuit of exploration, development, or production activities.
Certain states in which we operate, including Colorado, Pennsylvania, Louisiana, Texas, Ohio, and Wyoming, have adopted, and other states are considering adopting, regulations that could impose new or more stringent permitting, disclosure, and additional well-construction requirements on hydraulic-fracturing operations. For example, Texas adopted a law in June 2011 requiring disclosure to the Railroad Commission of Texas and the public of certain information regarding the components used in the hydraulic-fracturing process. In addition to state laws, local land use restrictions, such as city ordinances, may restrict or prohibit drilling in general and/or hydraulic fracturing in particular. We believe that we follow applicable standard industry practices and legal requirements for groundwater protection in our hydraulic-fracturing activities. Nonetheless, in the event state or local restrictions are adopted in areas where we currently conduct operations, or in the future plan to conduct operations, we may incur additional costs to comply with such requirements. These costs may be significant in nature, and we may experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps be limited or precluded in the drilling of wells or in the amounts that we are ultimately able to produce from our reserves.
Index to Financial Statements There are also certain governmental reviews recently conducted or underway that focus on environmental aspects of hydraulic-fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic-fracturing practices, and the EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with a first progress report outlining work currently underway by the agency released on December 21, 2012, and a final draft report drawing conclusions about the potential impacts of hydraulic fracturing on drinking water resources expected to be available for public comment and peer review by 2014. Moreover, the EPA is developing effluent limitations for the treatment and discharge of wastewater resulting from hydraulic-fracturing activities and plans to propose these standards for shale gas by 2014. In addition, the U.S. Department of Energy has conducted an investigation into practices the agency could recommend to better protect the environment from drilling using hydraulic-fracturing completion methods and, in August 2011, issued a report on immediate and longer-term actions that may be taken to reduce environmental and safety risks of shale-gas development. Also, as discussed above, the DOI is pursuing regulations governing hydraulic fracturing on federal and Indian oil and gas leases. These studies, depending on any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing.
The additional deepwater drilling laws and regulations, both domestically and internationally, delays in the processing and approval of drilling permits and exploration and oil spill-response plans, and other related developments arising after the deepwater drilling moratorium in the Gulf of Mexico may have a material adverse effect on our business, financial condition, or results of operations.
In response to the Deepwater Horizon incident in the Gulf of Mexico in April 2010, the Bureau of Ocean Energy Management (BOEM) and the Bureau of Safety and Environmental Enforcement (BSEE), each agencies of the DOI, issued directives in May and July 2010 requiring lessees and operators of federal oil and gas leases in the Outer Continental Shelf (OCS) regions of the Gulf of Mexico and Pacific Ocean to cease drilling all new deepwater wells, including wellbore sidetracks and bypasses, but excluding workovers, completions, plugging and abandonment, or production, through November 30, 2010. In addition, the agencies issued a series of rules and Notices to Lessees and Operators (NTLs) imposing new and more stringent regulatory safety and performance requirements and permitting procedures for new wells to be drilled in federal waters of the OCS. The federal government may issue further safety and environmental laws and regulations regarding operations in the Gulf of Mexico.
Compliance with these new and more stringent rules and regulations, uncertainties or inconsistencies in current decisions and rulings by governmental agencies, delays in the processing and approval of drilling permits and exploration, development, and oil spill-response plans, as a result of the new laws and regulations, and possible additional regulatory initiatives could adversely affect or delay new drilling and ongoing development efforts in the Gulf of Mexico. Among other adverse impacts, these additional measures could delay or disrupt our operations, increase the risk of expired leases due to the time required to develop new technology, result in increased costs and limit activities in certain areas of the Gulf of Mexico, or cause us to incur penalties, fines, or shut-in production at one or all of our facilities. We cannot predict with any certainty the full impact of any new laws or regulations on our drilling operations in the Gulf of Mexico.
Other governments may also adopt safety, environmental or other laws and regulations that would adversely impact our offshore developments in other areas of the world, including offshore Brazil, New Zealand, Africa, and Southeast Asia. Additional U.S. or foreign government laws or regulations would likely increase the costs associated with the offshore operations of our drilling contractors. As a result, our drilling contractors may seek to pass increased operating costs to us through higher day-rate charges or through cost escalation provisions in existing contracts.
Index to Financial Statements In addition to increased governmental regulation, insurance costs may increase across the energy industry and certain insurance coverage may be subject to reduced availability or not available on economically reasonable terms, if at all. In particular, the events in the Gulf of Mexico relating to the Deepwater Horizon incident may make it increasingly difficult to obtain offshore property damage, well control, and similar insurance coverage. The potential increased costs and risks associated with offshore development may also result in certain current participants allocating resources away from offshore development and discourage potential new participants from undertaking offshore development activities. Accordingly, we may encounter increased difficulty identifying suitable partners willing to participate in our offshore drilling projects and prospects.
Further, the deepwater Gulf of Mexico (as well as international deepwater locations) lacks the degree of physical and oilfield service infrastructure present in shallower waters. Therefore, despite the Company’s oil spill-response capabilities, it may be difficult for us to quickly or effectively execute any contingency plans related to future events similar to the Deepwater Horizon incident.
The matters described above, individually or in the aggregate, could have a material adverse effect on our business, prospects, results of operations, financial condition, and liquidity.
The enactment of derivatives legislation could have an adverse effect on the Company’s ability to use derivative instruments to reduce the effect of commodity-price, interest-rate, and other risks associated with its business.
The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act), enacted in 2010, establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as the Company, that participate in that market. The Dodd-Frank Act requires the Commodities Futures Trading Commission (CFTC) and the SEC to promulgate rules and regulations implementing the Dodd-Frank Act. In its rulemaking under the Dodd-Frank Act, the CFTC issued a final rule on position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. Certain bona fide hedging transactions or positions are exempt from these position limits. The position-limits rule was vacated by the U.S. District Court for the District of Colombia in September 2012 and the CFTC recently stated that it will appeal the District Court’s decision. The CFTC also finalized other regulations, including critical rulemakings on the definition of “swap,” “swap dealer,” and “major swap participant.” Some regulations, however, remain to be finalized and it is not possible at this time to predict when this will be accomplished. Depending on the Company’s classification and the particular nature of its derivative activities, the Dodd-Frank Act and regulations may require the Company to comply with margin requirements and with certain clearing and trade-execution requirements in connection with its derivative activities. The Dodd-Frank Act and regulations may also require the counterparties to the Company’s derivative instruments to spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties. The Dodd-Frank Act and regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks the Company encounters, reduce the Company’s ability to monetize or restructure its existing derivative contracts, and increase the Company’s exposure to less-creditworthy counterparties. If the Company reduces its use of derivatives as a result of the Dodd-Frank Act and regulations, the Company’s results of operations may become more volatile and its cash flows may be less predictable, which could adversely affect the Company’s ability to plan for and fund capital expenditures. Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and natural-gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. The Company’s revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on the Company’s consolidated financial position, results of operations, or cash flows.
Index to Financial Statements Our debt and other financial commitments may limit our financial and operating flexibility.
Our total debt was $13.3 billion at December 31, 2012. We also have various commitments for leases, drilling contracts, derivative contracts, firm transportation, and purchase obligations for services and products. Our financial commitments could have important consequences to our business including, but not limited to, the following:
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increasing our vulnerability to general adverse economic and industry conditions
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limiting 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 flows from operations to payments on our debt or to comply with any restrictive terms of our debt
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limiting our flexibility in planning for, or reacting to, changes in the industry in which we operate
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placing us at a competitive disadvantage compared to our competitors that have less debt and/or fewer financial commitments
Additionally, the credit agreement governing our senior secured revolving credit facility ($5.0 billion Facility) contains a number of covenants that impose operating and financial constraints on the Company, including restrictions on our ability to incur additional indebtedness, sell assets, and incur liens. Provisions of the $5.0 billion Facility also require us to maintain specified financial covenants as further described in Liquidity and Capital Resources under Item 7 of this Form 10-K. Our ability to meet such covenants may be affected by events beyond our control.
A downgrade in our credit rating could negatively impact our cost of and ability to access capital.
At December 31, 2012, our debt was rated “BBB-” with a positive outlook by Standard and Poor’s (S&P), “BBB-” with a negative outlook by Fitch Ratings (Fitch), and “Baa3” with a stable outlook by Moody’s Investors Service (Moody’s). Although we are not aware of any current plans of S&P, Fitch, or Moody’s to lower their respective ratings on our debt, we cannot be assured that our credit ratings will not be downgraded. A downgrade in our credit ratings could negatively impact our cost of capital or our ability to effectively execute aspects of our strategy. If our credit rating were 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. In addition, a downgrade could affect the Company’s requirements to provide financial assurance of its performance under certain contractual arrangements and derivative agreements. See Note 12-Derivative Instruments in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.
Index to Financial Statements Our proved reserves are estimates. Any material inaccuracies in our reserves estimates or assumptions underlying our reserves 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 or understated. The reserves 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; however, no reserves audit was conducted by these consultants. Estimation of reserves is not an exact science. Estimates of economically recoverable oil and natural-gas reserves and of future net cash flows depend on a number of variable factors and assumptions, any of which may cause actual results to vary considerably from these estimates. These factors and assumptions may include, but are not limited to, the following:
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historical production from an area compared with production from similar producing areas
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assumed effects of regulation by governmental agencies and court rulings
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assumptions concerning future oil and natural-gas prices, future operating costs and capital expenditures
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estimates of future severance and excise taxes, workover costs, 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 fair value of the estimated oil, natural-gas, and NGLs reserves attributable to our properties. The estimated discounted future net cash flows from proved reserves are based on average 12-month sales prices using the average beginning-of-month price. Actual future prices and costs may differ materially from the SEC regulation-compliant prices used for purposes of estimating future discounted net cash flows from proved reserves.
Failure to replace reserves may negatively affect our business.
Our future success depends on 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, 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.
Certain of our undeveloped leasehold acreage is subject to leases that will expire over the next several years unless production is established on units containing the acreage.
A portion of our leasehold acreage is currently undeveloped. Unless production in sufficient quantities is established on units containing certain of these leases during their terms, the leases will expire. If our leases expire, we will lose our right to develop the related properties. Our drilling plans for these areas are subject to change based on various factors: drilling results, oil and natural-gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints, and regulatory approvals.
Index to Financial Statements Poor general economic, business, or industry conditions may have a material adverse effect on our results of operations, liquidity, and financial condition.
During the last few years, concerns over inflation, energy costs, geopolitical issues, the availability and cost of credit, the U.S. mortgage market, uncertainties with regard to European sovereign debt, and a declining real estate market in the United States have contributed to increased economic uncertainty and diminished expectations for the global economy. Concerns about global economic conditions have had a significant adverse impact on global financial markets and commodity prices. If economic recovery in the United States or abroad is prolonged, demand for petroleum products could 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 goodwill impairments.
As a result of mergers and acquisitions, we had approximately $5.5 billion of goodwill on our Consolidated Balance Sheet at December 31, 2012. Goodwill must be tested at least annually for impairment, and more frequently when circumstances indicate likely impairment. Goodwill is considered impaired to the extent that its carrying amount exceeds its implied fair value. Various factors could lead to an impairment of goodwill, such as the Company’s inability to replace the value of its depleting asset base, or other adverse events, such as lower sustained oil and natural-gas prices, which could reduce the fair value of the associated reporting unit. An impairment of goodwill could have a substantial negative effect on our profitability.
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, regional, state, tribal, local, and foreign laws and regulations governing the release of pollutants or otherwise relating to environmental protection. These laws and regulations govern the following, among other things:
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issuance of permits in connection with exploration, drilling, production, and midstream activities
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protection of endangered species
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amounts and types of emissions and discharges
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generation, management, and disposition of waste materials
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offshore oil and gas operations and decommissioning of abandoned facilities
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reclamation and abandonment of wells and facility sites
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remediation of contaminated sites
In addition, these laws and regulations may impose substantial liabilities for our failure to comply or for any contamination resulting from our operations. Future environmental laws and regulations, such as the restriction against emission of pollutants from previously unregulated activities or the designation of previously unprotected species as threatened or endangered in areas where we operate, may negatively impact our industry. The cost of satisfying these requirements may have an adverse effect on our financial condition, results of operations, or cash flows or could result in limitations on our exploration and production activities, which could have an adverse impact on our ability to develop and produce our reserves. For a description of certain environmental proceedings in which we are involved, see Note 17-Contingencies in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.
Index to Financial Statements 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, Liberia, Sierra Leone, Kenya, Côte d’Ivoire, New Zealand, and other countries. Our operations and financial results could be significantly impacted by conditions in some of these areas because we are vulnerable to certain unique risks associated with operating offshore, including those relating to the following:
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hurricanes and other adverse weather conditions
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oilfield service costs and availability
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compliance with environmental and other laws and regulations
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terrorist attacks, such as piracy
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remediation and other costs and regulatory changes resulting from oil spills or releases of hazardous materials
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failure of equipment or facilities
In addition, we conduct some of our exploration in deep waters (greater than 1,000 feet) where operations are more difficult and costly than in shallower waters. The deep waters in the Gulf of Mexico, as well as international deepwater locations, lack the physical and oilfield service infrastructure present in its shallower waters. As a result, deepwater operations may require significant 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 reserves 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 foreign countries and are subject to political, economic, and other uncertainties.
Our operations outside the United States are based primarily in Algeria, Brazil, China, Côte d’Ivoire, Ghana, Kenya, Liberia, Mozambique, New Zealand, 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 the following, among other things:
•
loss of revenue, property, and equipment as a result of hazards such as expropriation, war, piracy, acts of terrorism, insurrection, civil unrest, and other political risks
•
transparency issues in general and, more specifically, the U.S. Foreign Corrupt Practices Act, the U.K. Bribery Act, and other anti-corruption compliance laws and issues
•
increases in taxes and governmental royalties
•
unilateral renegotiation of contracts by governmental entities
•
redefinition of international boundaries or boundary disputes
•
difficulties enforcing our rights against a governmental agency because of the doctrine of sovereign immunity and foreign sovereignty over international operations
Index to Financial Statements
•
changes in laws and policies governing operations of foreign-based companies
•
foreign-exchange restrictions
•
international monetary fluctuations and changes in the relative value of the U.S. dollar as compared to the currencies of other countries in which we conduct business
For example, Ghana and Côte d’Ivoire are currently engaged in a dispute regarding the international maritime and land boundaries between the two countries. As a result, Côte d’Ivoire claims to be entitled to the maritime area which covers a portion of the Deepwater Tano Block where we are currently conducting exploration and appraisal activities. In the event Côte d’Ivoire is successful in its maritime border claims, our operations in the block could be materially impacted.
Outbreaks of civil and political unrest and acts of terrorism have occurred in several countries in Africa and the Middle East, including countries where we conduct operations, such as Algeria and Tunisia. As exhibited by the events in Tunisia, Egypt, and Libya, outbreaks of civil and political unrest have resulted in established governing bodies being overthrown. Continued or escalated civil and political unrest and acts of terrorism in the countries in which we operate could result in our curtailing operations. In the event that countries in which we operate experience civil or political unrest or acts of terrorism, especially in events where such unrest leads to an unseating of the established government, our operations in such countries could be materially impaired.
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, or cash flows.
Our commodity-price risk-management and trading activities may prevent us from fully benefiting 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 flows 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 the following occur:
•
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
•
a sudden unexpected event materially impacts oil and natural-gas prices
Index to Financial Statements Deterioration in the credit or equity markets could adversely affect us.
We have exposure to different counterparties. For example, 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 by our counterparty. Deterioration in the credit markets may impact the credit ratings of our current and potential counterparties and affect their ability to fulfill existing obligations to us and their willingness to enter into future transactions with us. We have exposure to these financial institutions through our derivative transactions. In addition, if any lender under our credit facility is unable to fund its commitment, our liquidity will be reduced by an amount up to the aggregate amount of such lender’s commitment under our credit facility. Moreover, to the extent that purchasers of the Company’s production rely on access to the credit or equity markets to fund their operations, there is a risk that those purchasers could default in their contractual obligations to the Company if such purchasers were unable to access the credit or equity markets for an extended period of time.
We are not 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 blowouts, cratering and fire, any of which could result in damage to, or destruction of, oil and natural-gas wells or formations, production facilities, and other property, as well as injury to persons. For protection against financial loss resulting from these operating hazards, we maintain insurance coverage, including insurance coverage for certain physical damage, blowout/control of a well, comprehensive general liability, aviation liability, and worker’s compensation and employer’s liability. However, our insurance coverage may not be sufficient to cover us against 100% of potential losses arising as a result of the foregoing, and for certain risks, such as political risk, business interruption, war, terrorism, and piracy, for which we have limited or no coverage. In addition, we are not insured against all risks in all aspects of our business, such as hurricanes. The occurrence of a significant event against which we are not fully insured could have a material adverse effect on our consolidated financial position, results of operations, or cash flows.
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 the following:
•
project approvals by joint-venture partners
•
timely issuance of permits and licenses by governmental agencies
•
weather conditions
•
availability of personnel
•
civil and political environment of the country or region in which the project is located
•
manufacturing and delivery schedules of critical equipment
•
commercial arrangements for pipelines and related equipment to transport and market hydrocarbons
Delays and differences between estimated and actual timing of critical events may affect the forward-looking statements related to large development projects and could have a material adverse effect on our results of operations.
Index to Financial Statements 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 consumers. Some of our competitors may have greater and more diverse resources on 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 oilfield 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 to us 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 oilfield 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 natural-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 the following:
•
unexpected drilling conditions
•
pressure or irregularities in formations
•
equipment failures or accidents
•
fires, explosions, blowouts, and surface cratering
•
marine risks such as capsizing, collisions, and hurricanes
•
difficulty identifying and retaining qualified personnel
•
title problems
•
other adverse weather conditions
•
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.
Index to Financial Statements 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 gas and oil production could be materially harmed if we fail to obtain adequate services such as transportation.
The marketability of our production depends in part on the availability, proximity, and capacity of pipeline facilities and tanker transportation. If any pipelines or tankers become unavailable, we would, to the extent possible, be required to find a suitable alternative to transport the natural 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 nomination and removal of directors, the prohibition of stockholder action by written consent and regulation of stockholders’ ability 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 on actions taken by our Board of Directors, as well as, our financial condition, results of operations, cash flows, levels of capital and exploration expenditures, future business prospects, expected liquidity needs, 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 could have an adverse effect on our business. 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.
Index to Financial Statements

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ITEM 1B. UNRESOLVED STAFF COMMENTS
Item 1B. Unresolved Staff Comments
None.

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ITEM 2. PROPERTIES

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ITEM 3. LEGAL PROCEEDINGS
Item 3. Legal Proceedings
GENERAL The Company is a defendant in a number of lawsuits and is involved in governmental proceedings and regulatory controls arising in the ordinary course of business, including, but not limited to, personal injury claims, title disputes, tax disputes, royalty claims, contract claims, oil-field contamination claims, and environmental claims, including claims involving assets owned by acquired companies. Anadarko is also subject to various environmental-remediation and reclamation obligations arising from federal, state, and local laws and regulations. While the ultimate outcome and impact on the Company cannot be predicted with certainty, after consideration of recorded expense and liability accruals, management believes that the resolution of pending proceedings will not have a material adverse effect on the Company’s consolidated financial position, results of operations, or cash flows.
See Note 17-Contingencies in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K, which is incorporated herein by reference, for a discussion of material legal proceedings to which the Company is a party.

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ITEM 4. RESERVED
Item 4. Mine Safety Disclosures
Not applicable.
Index to Financial Statements PART II

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ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
MARKET INFORMATION, HOLDERS, AND DIVIDENDS
At January 31, 2013, there were approximately 12,800 holders of record of Anadarko common stock. The common stock of Anadarko is traded on the New York Stock Exchange. The following shows information regarding the market price of and dividends declared and paid on the Company’s common stock by quarter for 2012 and 2011:
The amount of future common stock dividends will depend on earnings, financial condition, capital requirements, the effect a dividend payment would have on the Company’s compliance with its financial covenants, and other factors, and will be determined by the Board of Directors on a quarterly basis. For additional information, see Liquidity and Capital Resources-Uses of Cash-Common Stock Dividends and Distributions to Noncontrolling Interest Owners under Item 7 of this Form 10-K.
Index to Financial Statements SECURITIES AUTHORIZED FOR ISSUANCE UNDER EQUITY COMPENSATION PLANS
The following table sets forth information with respect to the equity compensation plans available to directors, officers, and employees of the Company at December 31, 2012:
PURCHASES OF EQUITY SECURITIES BY THE ISSUER AND AFFILIATED PERSONS
The following sets forth information with respect to repurchases made by the Company of its shares of common stock during the fourth quarter of 2012:
(1) During the fourth quarter of 2012, all purchased shares related to stock received by the Company for the payment of withholding taxes due on employee stock plan share issuances.
For additional information, see Note 15-Share-Based Compensation in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.
Index to Financial Statements PERFORMANCE GRAPH
The following performance graph and related information shall not be deemed “soliciting material” or to be “filed” with the SEC, nor shall 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 of Anadarko’s common stock relative to the cumulative total returns of the S&P 500 index and a peer group of 11 companies. The companies included in the 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.
Comparison of 5-Year Cumulative Total Return Among
Anadarko Petroleum Corporation, the S&P 500 Index,
and a Peer Group
Copyright© 2013 S&P, a division of The McGraw-Hill Companies Inc. All rights reserved.
An investment of $100 (with reinvestment of all dividends) is assumed to have been made in the Company’s common stock, in the S&P 500 Index, and in the peer group on December 31, 2007, and its relative performance is tracked through December 31, 2012.
Index to Financial Statements

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ITEM 6. SELECTED FINANCIAL DATA
Item 6. Selected Financial Data
(1) Consolidated for Anadarko and its subsidiaries. Certain amounts for prior years have been reclassified to conform to the current presentation.
(2) Natural gas is converted to equivalent barrels at the rate of 6,000 cubic feet of gas per barrel.
Table of Measures
Bcf-Billion cubic feet
MBbls/d-Thousand barrels per day
MMBbls-Million barrels
MBOE/d-Thousand barrels of oil equivalent per day
MMBOE-Million barrels of oil equivalent
Tcf-Trillion cubic feet
MMcf/d-Million cubic feet per day
Index to Financial Statements

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion should be read together with the Consolidated Financial Statements and the Notes to Consolidated Financial Statements, which are included in this report in Item 8, and the information set forth in Risk Factors under Item 1A. Unless the context otherwise requires, the terms “Anadarko” and “Company” refer to Anadarko Petroleum Corporation and its consolidated subsidiaries.
OVERVIEW
Anadarko met or exceeded its key operational objectives in 2012. The Company increased sales volumes by approximately 8% over 2011 and added 370 million barrels of oil equivalent (BOE) of proved reserves. Additionally, the Company continued its offshore exploration and appraisal drilling success with an approximate 67% success rate for wells completed in 2012. Anadarko fully repaid $2.5 billion of borrowings under the Company’s five-year $5.0 billion senior secured revolving credit facility ($5.0 billion Facility) with cash on hand and cash realized from the resolution of the Algeria exceptional profits tax dispute. The Company ended 2012 with $2.5 billion cash on hand, availability of the $5.0 billion Facility, and access to credit and capital markets as needed. Management believes that the Company is positioned to satisfy its operational objectives and capital commitments with cash on hand, available borrowing capacity, and cash flows from operations.
Mission and Strategy
Anadarko’s mission is to deliver a competitive and sustainable rate of return to shareholders by developing, acquiring, and exploring for oil and natural-gas resources vital to the world’s health and welfare. Anadarko employs the following strategy to achieve this mission:
•
explore in high-potential, proven basins
•
identify and commercialize resources
•
employ a global business development approach
•
ensure financial discipline and flexibility
Exploring in high-potential, proven, and emerging basins worldwide provides the Company with growth opportunities. Anadarko’s exploration success has created value by increasing its future resource potential, while providing the flexibility to mitigate risk by monetizing discoveries.
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.
Anadarko’s global business development approach transfers core skills across the globe to assist in the discovery and development of world-class resources that are accretive to the Company’s performance. These resources help form an optimized global portfolio where both surface and subsurface risks are actively managed.
A strong balance sheet is essential for the development of the Company’s assets, and Anadarko is committed to disciplined investing 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 growth opportunities.
Index to Financial Statements Significant 2012 operating and financial activities include the following:
Overall
•
Anadarko’s total-year sales volumes were 732 thousand barrels of oil equivalent per day (MBOE/d), representing an 8% increase over 2011.
•
Anadarko’s liquids sales volumes were 316 thousand barrels per day (MBbls/d), representing a 9% increase over 2011.
•
The Company achieved an approximate 67% success rate from offshore exploration and appraisal drilling completed in 2012.
U.S. Onshore
•
The Rocky Mountains Region (Rockies) total-year sales volumes were 321 MBOE/d, representing a 6% increase over 2011, primarily from the Wattenberg field and the Greater Natural Buttes area.
•
The Southern and Appalachia Region total-year sales volumes were 198 MBOE/d, representing a 36% increase over 2011, primarily from the Marcellus, Eagleford, and Haynesville shales.
Gulf of Mexico
•
Gulf of Mexico total-year sales volumes were 116 MBOE/d, representing an 11% decrease from 2011, primarily due to natural production declines.
•
The Company achieved first production from the Caesar/Tonga development (33.75% working interest) in the Green Canyon area during March 2012, utilizing Anadarko’s Constitution spar floating production facility.
•
The Company entered into a carried-interest arrangement that requires a third-party partner to fund $556 million of Anadarko’s capital costs to earn a 7.2% working interest in the Lucius development.
International
•
International total-year sales volumes were 84 MBOE/d, representing a 2% decrease from 2011.
•
The Company drilled five successful exploration wells: two in Mozambique and one each in Ghana, Côte d’Ivoire, and Sierra Leone.
•
The Company drilled ten successful appraisal wells: seven in Mozambique, two in Ghana, and one in Brazil.
Financial
•
Anadarko’s net income attributable to common stockholders for 2012, including $1.8 billion related to the favorable resolution of the Algeria exceptional profits tax dispute and $845 million of certain unproved property impairments, totaled $2.4 billion. In 2011, Anadarko’s net loss attributable to common stockholders was $2.6 billion, and included the effect of the $4.0 billion settlement agreement, mutual releases, and agreement to indemnify relating to the Deepwater Horizon events (Settlement Agreement).
•
The Company generated $8.3 billion of cash flows from operations in 2012, including $1.0 billion collected related to the resolution of the Algeria exceptional profits tax dispute, and ended 2012 with $2.5 billion of cash on hand. Anadarko’s $2.5 billion of cash flows from operations in 2011 included the effect of the $4.0 billion payment made as a result of the Settlement Agreement.
•
The Company fully repaid $2.5 billion of borrowings under its $5.0 billion Facility.
•
Western Gas Equity Partners, LP (WGP), a consolidated subsidiary formed to own Anadarko’s partnership interests in Western Gas Partners, LP (WES), also a consolidated subsidiary of Anadarko, completed its initial public offering (IPO) of approximately 20 million common units representing limited partner interests in WGP at a price of $22.00 per common unit.
Index to Financial Statements The following discussion pertains to Anadarko’s results of operations, financial condition, and changes in financial condition. Any increases or decreases “for the year ended December 31, 2012” refer to the comparison of the year ended December 31, 2012, to the year ended December 31, 2011. Similarly, any increases or decreases “for the year ended December 31, 2011” refer to the comparison of the year ended December 31, 2011, to the year ended December 31, 2010. The primary factors that affect the Company’s results of operations include commodity prices for natural gas, crude oil, and natural gas liquids (NGLs); sales volumes; the Company’s ability to discover additional reserves; the cost of finding such reserves; and operating costs.
RESULTS OF OPERATIONS
Selected Data
MMBOE-million barrels of oil equivalent
(1) Includes Deepwater Horizon settlement and related costs of $18 million in 2012, $3.9 billion in 2011, and $15 million in 2010, and a credit of $1.8 billion for previously recorded expenses related to the favorable resolution of the Algeria exceptional profits tax dispute in 2012.
(2)
See Operating Results-Segment Analysis-Adjusted EBITDAX for a description of Adjusted EBITDAX, which is not a U.S. Generally Accepted Accounting Principles (GAAP) measure, and for a reconciliation of Adjusted EBITDAX to income (loss) before income taxes, which is presented in accordance with GAAP.
Index to Financial Statements FINANCIAL RESULTS
Net Income (Loss) Attributable to Common Stockholders Anadarko’s net income attributable to common stockholders for 2012 totaled $2.4 billion, or $4.74 per share (diluted), compared to a net loss attributable to common stockholders for 2011 of $2.6 billion, or $5.32 per share (diluted). Anadarko’s net income attributable to common stockholders in 2010 was $761 million, or $1.52 per share (diluted). Anadarko’s net income for 2012 included $1.8 billion related to the favorable resolution of the exceptional profits tax dispute and $845 million related to certain unproved property impairments. Anadarko’s net loss for 2011 included the effect of the $4.0 billion Settlement Agreement with BP Exploration & Production Inc. (BP) related to the Deepwater Horizon events.
Sales Revenues and Volumes
Anadarko’s total sales revenues for the year ended December 31, 2012, decreased primarily due to lower average natural-gas and NGLs prices, partially offset by higher sales volumes for all products. Total sales revenues for the year ended December 31, 2011, increased primarily due to higher prices for crude oil and NGLs, as well as increased liquids volumes, partially offset by lower average natural-gas prices.
Index to Financial Statements The following table provides Anadarko’s sales volumes for the years ended December 31, 2012, 2011, and 2010:
Sales volumes represent actual production volumes adjusted for changes in commodity inventories. Anadarko employs marketing strategies to minimize market-related shut-ins, maximize realized prices, and manage credit-risk exposure. For additional information, see Note 12-Derivative Instruments in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K and Other (Income) Expense-(Gains) Losses on Commodity Derivatives, net. Production of natural gas, crude oil, and NGLs is usually not affected by seasonal swings in demand.
Natural-Gas Sales Volumes, Average Prices, and Revenues
Bcf-billion cubic feet
MMcf/d-million cubic feet per day
Mcf-thousand cubic feet
The Company’s natural-gas sales volumes increased 161 MMcf/d for the year ended December 31, 2012, primarily due to higher sales volumes in the Southern and Appalachia Region of 220 MMcf/d as a result of bringing wells drilled in previous years online at Eagleford and Marcellus shales due to infrastructure expansions during 2012 and new wells drilled in the Haynesville shale. Also, the Company had higher sales volumes in the Rockies of 52 MMcf/d associated with drilling in the Greater Natural Buttes area and the Wattenberg field. These increases were partially offset by reduced sales volumes in the Gulf of Mexico of 111 MMcf/d primarily due to natural production declines.
The Company’s natural-gas sales volumes increased 62 MMcf/d for the year ended December 31, 2011, primarily due to higher sales volumes in the Rockies of 84 MMcf/d, resulting from increased drilling in the Greater Natural Buttes area and the Wattenberg field, as well as higher sales volumes in the Southern and Appalachia Region of 66 MMcf/d, primarily related to increased drilling in the Marcellus shale. These increases were partially offset by lower sales volumes in the Gulf of Mexico of 86 MMcf/d, primarily due to 2010 price-related royalty relief that did not apply in 2011 and natural production declines.
Index to Financial Statements The average natural-gas price Anadarko received decreased for the year ended December 31, 2012, due to continued growth in U.S. natural-gas production, reduced U.S. natural-gas demand as a result of mild winter temperatures, and above-average U.S. natural-gas storage levels in 2012. Anadarko’s average natural-gas price received decreased for the year ended December 31, 2011, primarily due to the industry’s supply growing at a faster pace than demand in 2011.
Crude-Oil and Condensate Sales Volumes, Average Prices, and Revenues
MMBbls-million barrels
MBbls/d-thousand barrels per day
Anadarko’s crude-oil and condensate sales volumes increased 16 MBbls/d for the year ended December 31, 2012. Increased horizontal drilling in the Wattenberg field led to a 9 MBbls/d sales-volume improvement in the Rockies. Horizontal drilling in the Eagleford shale and Bone Spring/Avalon formations also contributed to increased sales volumes in the Southern and Appalachia Region of 8 MBbls/d.
Anadarko’s crude-oil and condensate sales volumes increased 16 MBbls/d for the year ended December 31, 2011. This increase primarily resulted from an additional 15 MBbls/d in Ghana, where the Company’s first lifting occurred in the first quarter of 2011. Increased drilling in the Wattenberg field led to a 5 MBbls/d sales-volume improvement in the Rockies. Additionally, increased activity in the Eagleford shale and Bone Spring/Avalon formations increased sales volumes from those areas by approximately 170%, contributing to an 8 MBbls/d sales-volume increase in the Southern and Appalachian Region. Partially offsetting these increases was a 9 MBbls/d sales-volume decline in the Gulf of Mexico principally caused by downtime for repairs at the Company’s Constitution spar and a third-party oil pipeline in 2011, and natural production declines.
Anadarko’s average crude-oil price received increased for the years ended December 31, 2012 and 2011, primarily due to supply disruption concerns associated with political and civil unrest in the Middle East and North Africa, and steady global demand growth. Additionally, average realized crude-oil prices for 2012 and 2011 were enhanced by the wide differential between West Texas Intermediate and Brent crude, as approximately 70% of Anadarko’s crude-oil sales volumes were based on prices that were either directly indexed to, or highly correlated to, Brent crude. The price increase for the year ended December 31, 2012, was offset by downward price pressure caused by macroeconomic concerns in Europe and China.
Index to Financial Statements Natural-Gas Liquids Sales Volumes, Average Prices, and Revenues
NGLs sales represent revenues from the sale of products derived from the processing of Anadarko’s natural-gas production. The Company’s NGLs sales volumes increased by 9 MBbls/d for the year ended December 31, 2012, as a result of drilling in liquids-rich areas, primarily in the Eagleford and Haynesville shales in the Southern and Appalachia Region.
Anadarko’s NGLs sales volumes increased by 11 MBbls/d for the year ended December 31, 2011, as a result of the Company’s increased focus on liquids-rich areas, expanded horizontal drilling programs in the Wattenberg field, and increases related to the acquisition of an additional 93% interest in a natural-gas processing plant (Wattenberg Plant).
Anadarko’s average NGLs price decreased for the year ended December 31, 2012, primarily due to lower market prices for ethane and propane. Ethane demand was reduced by down-time for maintenance and conversion upgrades at petrochemical facilities. Mild winter temperatures across much of the United States in 2011 reduced demand for propane and contributed to above-average levels of propane stockpiles. Also, increased production from continued liquids-rich development has created further downward pricing pressures for NGLs. The average NGLs price increased for the year ended 2011, primarily due to higher crude-oil prices and sustained global petrochemical demand.
Gathering, Processing, and Marketing Margin
For the year ended December 31, 2012, the gathering, processing, and marketing margin decreased $109 million. This decrease was due primarily to lower commodity prices, which led to reduced natural-gas processing margins and decreased marketing margins on sales from inventory. Also, for the year ended December 31, 2012, transportation expenses increased primarily due to higher unutilized demand fees. These decreases for the year ended December 31, 2012, were partially offset by additional margin provided by midstream assets acquired in February 2011 and May 2011, and an increase in gathering and processing revenues associated with increased throughput volumes across several of Anadarko’s fee-based systems.
For the year ended December 31, 2011, the gathering, processing, and marketing margin increased $39 million. This increase was primarily due to increased natural-gas processing margins from higher NGLs prices and volumes, lower prices for natural-gas purchases, and favorable impacts attributable to 2011 asset acquisitions discussed above. These increases were partially offset by lower margins associated with natural-gas sales from inventory.
Index to Financial Statements Gains (Losses) on Divestitures and Other, net
For the year ended December 31, 2012, gains (losses) on divestitures and other, net increased $19 million primarily due to increased mineral revenue of $36 million related to increased mining of soda ash on Anadarko’s Land Grant and higher per-ton average sales prices. Increased mineral revenue was partially offset by an increase in net losses on divestitures of $17 million. In January 2013, the Company divested its equity interest in the OCI soda ash business for $310 million and additional potential consideration while retaining its royalty interest in minerals mined from the Company’s Land Grant.
Gains (losses) on divestitures for 2012 included net losses of $71 million, primarily related to the sale of oil and gas exploration and production reporting segment properties in Indonesia.
Gains (losses) on divestitures for 2011 included net losses of $54 million, primarily related to write-downs of $422 million of assets held for sale. In 2011, the Company began marketing certain domestic properties from the oil and gas exploration and production reporting segment and the midstream reporting segment in order to redirect its operating activities and capital investment to other areas. Also included in 2011 was a $76 million loss, which occurred in connection with the Company’s purchase of the Wattenberg Plant. This loss was associated with the effective elimination, for purposes of consolidated financial reporting, of a pre-existing third-party relationship between the Company and the previous owner of the plant related to natural-gas processing contracts. The loss represents the aggregate amount by which the Company’s contracts with the previous owner of the Wattenberg Plant were unfavorable as compared to market transactions for the same or similar services at the date of the Company’s acquisition of the plant. These losses were partially offset by 2011 gains of $419 million for receipt and final settlement of contingent consideration related to the 2008 divestiture of its interest in the Peregrino field offshore Brazil and $21 million from the acquisition-date fair-value remeasurement of the Company’s pre-acquisition 7% equity interest in the Wattenberg Plant.
For the year ended December 31, 2011, gains (losses) on divestitures and other, net decreased $57 million primarily due to 2011 net losses on divestitures discussed above.
Costs and Expenses
For the year ended December 31, 2012, oil and gas operating expenses decreased by $17 million primarily due to lower workover expenses of $67 million associated with fewer workovers, primarily in the Gulf of Mexico and the Rockies, partially offset by $52 million of higher operating expenses from increased activity in Ghana. Per-BOE oil and gas operating expenses decreased by $0.35 for the year ended December 31, 2012, primarily as a result of increased sales volumes, while efficiently maintaining production costs, and lower workover expenses discussed above. For the year ended December 31, 2011, oil and gas operating expenses increased by $163 million primarily due to (i) $47 million from increased workovers and related freight costs, primarily in the Gulf of Mexico and the Rockies, (ii) $36 million related to increased joint-venture activity primarily in the Rockies, Bone Spring and Marcellus shale in the Southern and Appalachia Region, and in Alaska, (iii) $34 million in operating costs resulting from the start of production in Ghana, and (iv) $10 million in higher surface maintenance costs primarily in the Rockies. Oil and gas operating expenses per BOE increased by $0.46 for the year ended December 31, 2011, primarily due to the higher costs discussed above, partially offset by increased sales volumes.
Index to Financial Statements For the year ended December 31, 2012, oil and gas transportation and other expenses increased $64 million primarily due to higher gas-gathering and transportation costs attributable to higher volumes and increased costs attributable to growth in the Company’s U.S. onshore asset base. For the year ended December 31, 2011, oil and gas transportation and other expenses increased $75 million due to higher volumes, higher natural-gas processing fees that rise with increases in NGLs prices, and increased costs attributable to growth in U.S. onshore plays. These increases were partially offset by the 2010 expensing of amounts attributable to drilling rig lease payments for rigs that sat idle during the moratorium, as well as rig termination fees incurred in 2010 related to deepwater drilling rigs in the Gulf of Mexico. Oil and gas transportation and other expenses per BOE decreased by $0.02 for the year ended December 31, 2012, primarily due to increased sales volumes, partially offset by the higher costs discussed above. For the year ended December 31, 2011, oil and gas transportation and other expenses per BOE increased by $0.11, primarily due to the higher costs discussed above, partially offset by increased sales volumes.
Exploration expense increased $870 million for the year ended December 31, 2012, primarily due to increases of $633 million in impairments of unproved properties and $286 million in dry hole expense, partially offset by a $95 million decrease in geological and geophysical expenses.
The increase in 2012 impairments of unproved properties was primarily due to $845 million of impairments for certain unproved properties in the Rockies and the Gulf of Mexico. Approximately $721 million of the impairments were due to lower natural-gas prices associated with Powder River coalbed methane properties in the Rockies and $124 million related to a Gulf of Mexico natural-gas property that the Company does not plan to pursue under the forecasted natural-gas price environment. These increases were partially offset by 2011 impairments of certain unproved properties in the Gulf of Mexico of $124 million and Indonesia of $63 million due to decreases in the estimated recoverable cash flows.
The $286 million increase in dry hole expense for the year ended December 31, 2012, was primarily due to wells in Brazil, Sierra Leone, Côte d’Ivoire, Mozambique, and the Gulf of Mexico. The $95 million decrease in geological and geophysical expense was primarily due to fewer seismic purchases in Kenya, Liberia, New Zealand, and Mozambique.
For the year ended December 31, 2012, exploration overhead and other increased $46 million primarily due to increased exploration activity onshore United States and in Mozambique.
Exploration expense increased $102 million for the year ended December 31, 2011, due to $143 million of higher geological and geophysical expense, primarily associated with increased seismic purchases in the Rockies, Gulf of Mexico, the Marcellus shale, Indonesia, Liberia, and East Africa. These additional expenses were partially offset by $48 million of lower dry hole expense, primarily in the Gulf of Mexico.
Index to Financial Statements
NM-not meaningful
For the year ended December 31, 2012, general and administrative (G&A) expense increased by $186 million due to higher employee-related expenses of $150 million primarily related to expense associated with general partner Unit Appreciation Rights (UARs) awarded in prior years to certain officers of the general partner of WES, pursuant to the WGH Equity Incentive Plan. This increase was related to the change in fair value of the UARs upon the WGP IPO. In addition, G&A expense increased by $41 million due to higher legal-related and consulting expenses primarily related to the Tronox litigation. For the year ended December 31, 2011, G&A expense increased by $93 million primarily due to higher employee-related costs of $67 million primarily from operational expansions and changes in pension discount rates, and increased insurance costs of $9 million related to higher industry-specific rates as a result of the Deepwater Horizon events.
For the year ended December 31, 2012, depreciation, depletion, and amortization (DD&A) expense increased by $134 million primarily due to higher sales volumes, accelerated expense in 2012 associated with the depletion of fields in the Gulf of Mexico, and the start of production at Caesar/Tonga in March 2012. These increases were partially offset by lower per-barrel DD&A rates resulting from asset impairments recorded in the fourth quarter of 2011 and reserves additions in 2012 related to the Southern and Appalachia Region. For the year ended December 31, 2011, DD&A expense increased by $116 million primarily attributable to higher sales volumes, partially offset by a lower average DD&A rate, largely the result of an $89 million DD&A expense recognized in 2010 associated with depleted fields in the Gulf of Mexico.
For the year ended December 31, 2012, other taxes decreased by $268 primarily related to lower Algeria exceptional profits taxes of $184 million due to a lower Algeria effective tax rate resulting from the resolution of the Algeria exceptional profits tax dispute. Other taxes also decreased due to lower commodity prices, which resulted in lower U.S. production and severance taxes of $55 million, and lower ad valorem taxes of $27 million. For the year ended December 31, 2011, other taxes increased by $424 million primarily due to higher crude-oil prices and total sales volumes, resulting in increased Algerian exceptional profits tax of $172 million, increased U.S. production and severance taxes of $152 million, and increased Chinese windfall profits tax of $55 million. Additionally, ad valorem taxes increased by $46 million in 2011 due to higher assessed property values.
Impairment expense was $389 million for the year ended December 31, 2012. The Company recognized impairments of $363 million related to oil and gas exploration and production reporting segment properties located in the United States, $13 million related to midstream properties, and $13 million related to the Company’s Venezuelan cost-method investment. Impairment expense for U.S. oil and gas exploration and production reporting segment properties included $259 million related to lower natural-gas prices. Impairment expense for U.S. properties also included $79 million related to downward reserves revisions for a Gulf of Mexico property that was near the end of its economic life and $25 million for a platform in the Gulf of Mexico with no salvage value. Also during 2012, the Company recognized impairment expense of $13 million related to the Company’s Venezuelan cost-method investment due to declines in estimated recoverable reserves and lower crude-oil prices. Further declines in commodity prices or negative reserves revisions could result in additional impairments. See Risk Factors under Item 1A of this Form 10-K for further discussion on the risks associated with oil, natural-gas, and NGLs prices.
Index to Financial Statements Impairment expense of $1.8 billion for the year ended December 31, 2011, included $1.2 billion related to oil and gas exploration and production reporting segment properties located in the United States, $458 million for midstream reporting segment properties, and $91 million related to the Company’s Venezuelan cost-method investment. Impairment expense of $952 million for U.S. onshore oil and gas properties and $446 million for associated midstream properties was triggered by lower natural-gas prices. Impairment expense also included $162 million for certain Gulf of Mexico properties related to declines in estimated recoverable reserves, and $100 million related to onshore properties due to changes in projected cash flows resulting from the Company’s intent to divest of the subject properties. All of these assets were impaired to fair value.
Impairment expense for the year ended December 31, 2010, included $114 million related to a production platform included in the oil and gas exploration and production reporting segment that remains idle with no immediate plan for use, and for which a limited market exists, and $61 million related to the Company’s Venezuelan cost-method investment.
In March 2012, Anadarko and Sonatrach resolved the exceptional profits tax dispute. The resolution provided for delivery to the Company of crude oil valued at approximately $1.7 billion and the elimination of $62 million of the Company’s previously recorded and unpaid transportation charges. The crude oil is to be delivered to the Company over a 12-month period that began in June 2012. The Company recognized a $1.8 billion credit in the Costs and Expenses section of the Consolidated Statement of Income for the year ended December 31, 2012, to reflect the effect of this agreement for previously recorded expenses. During 2012, the Company collected $1.0 billion associated with the Algeria exceptional profits tax receivable. The Company expects to collect the balance of the Algeria exceptional profits tax receivable during the first half of 2013.
In October 2011, the Company and BP entered into the Settlement Agreement, pursuant to which the Company agreed to pay $4.0 billion in cash and transfer its interest in the Macondo well and the Mississippi Canyon Block 252 lease (Lease) to BP, and BP agreed to accept this consideration in full satisfaction of its claims against Anadarko for $6.1 billion of invoices issued through the settlement date as well as for potential reimbursements of subsequent costs incurred by BP related to the Deepwater Horizon events, including costs under the Operating Agreement (OA). In addition, BP fully indemnified Anadarko against all claims, causes of action, losses, costs, expenses, liabilities, damages, or judgments of any kind arising out of the Deepwater Horizon events, related damage claims arising under the Oil Pollution Act of 1990 (OPA), claims for natural resource damages (NRD) and assessment costs, and any claims arising under the OA. This indemnification is guaranteed by BP Corporation North America Inc. (BPCNA) and, in the event that the net worth of BPCNA declines below an agreed-on amount, BP p.l.c. has agreed to become the sole guarantor. Under the Settlement Agreement, BP does not indemnify the Company against fines and penalties, punitive damages, shareholder derivative, or security laws claims, or certain other claims. The Company believes that costs associated with any non-indemnified items, individually or in the aggregate, will not materially impact the Company’s consolidated financial position, results of operations, or cash flows. Refer to Note 17-Contingencies-Deepwater Horizon Events in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K for discussion and analysis of these events.
Index to Financial Statements For the year ended December 31, 2012, Deepwater Horizon settlement and related costs included $18 million of legal expenses and related costs associated with the Deepwater Horizon events. For the year ended December 31, 2011, Deepwater Horizon settlement and related costs included a $4.0 billion expense for the Company’s cash payment made to BP pursuant to the Settlement Agreement discussed above, as well as $93 million of legal expenses and other related costs associated with the Deepwater Horizon events. These amounts were partially offset by a $163 million gain recognized in the fourth quarter of 2011 for insurance recoveries associated with the Deepwater Horizon events. Although Anadarko has been indemnified by BP for certain costs, the Company may be required to recognize a liability for amounts in advance of or in connection with recognizing a receivable from BP for the related indemnity payment. In all circumstances, however, the Company expects that any additional indemnified liability that may be recognized by the Company will be subsequently recovered from BP itself or through the guarantees of BPCNA or BP p.l.c. Additionally, as part of the Settlement Agreement, BP has agreed that, to the extent it receives value in the future from claims that it has asserted or could assert against third parties arising from or relating to the Deepwater Horizon events, it will make cash payments (not to exceed $1.0 billion in the aggregate) to Anadarko, on a current and continuing basis, equal to 12.5% of the aggregate value received by BP in excess of $1.5 billion. Any payments received by the Company pursuant to this arrangement will be accounted for as a reimbursement of the $4.0 billion 2011 payment made to BP as part of the Settlement Agreement.
Other (Income) Expense
Anadarko’s interest expense decreased $97 million for the year ended December 31, 2012, primarily due to an increase in capitalized interest of $74 million related to higher construction-in-progress balances for long-term capital projects. Additionally, interest expense for the year ended December 31, 2012, decreased $32 million as a result of interest incurred during 2011 related to the Company’s capital lease obligations for a floating production, storage, and offloading vessel (FPSO) for the Company’s Jubilee field operations in Ghana. In December 2011, the Company and its partners in the Jubilee project purchased the vessel, resulting in cancellation of the capital lease obligation.
Anadarko’s interest expense decreased for the year ended December 31, 2011, due to $19 million of increased capitalized interest related to higher construction-in-progress balances for long-term capital projects. Additionally, 2011 interest expense was lower due to items that occurred in 2010 with no similar expense in 2011, including $86 million associated with losses on early debt retirements, $17 million of commitment and structuring costs associated with a contemplated term-loan facility, and $9 million related to unamortized debt issuance costs recognized with the retirement of the Midstream Subsidiary Note Payable to a Related Party. These items were partially offset by $48 million from a higher average outstanding debt balance and weighted-average interest rate on outstanding debt, $29 million related to interest on capital lease obligations incurred in 2011, $24 million attributable to increased amortization of debt-issuance and credit-facility origination costs, and $20 million of higher fees on issued letters of credit and commitment fees related to the $5.0 billion Facility. For additional information, see Liquidity and Capital Resources-Uses of Cash-Debt Retirements and Repayments, and Interest-Rate Risk under

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
The Company’s primary market risks are attributable to fluctuations in energy prices and interest rates. In addition, foreign-currency exchange-rate risk exists due to anticipated foreign-currency denominated payments and receipts. These risks can affect revenues and cash flows from operating, investing, and financing activities. The Company’s risk-management policies provide for the use of derivative instruments to manage these risks. The types of commodity derivative instruments utilized by the Company include futures, swaps, options, and fixed-price physical-delivery contracts. The volume of commodity derivatives entered into by the Company is governed by risk-management policies and may vary from year to year. 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 counterparties in order to satisfy these margin requirements. For additional information relating to the Company’s derivative and financial instruments, see Note 12-Derivative Instruments in the Notes to Consolidated Financial Statements under

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Item 8. Financial Statements and Supplementary Data
ANADARKO PETROLEUM CORPORATION
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Page
Report of Management
Management’s Assessment of Internal Control Over Financial Reporting
Reports of Independent Registered Public Accounting Firm
Consolidated Statements of Income, Three Years Ended December 31, 2012
Consolidated Statements of Comprehensive Income, Three Years Ended December 31,
Consolidated Balance Sheets, December 31, 2012 and 2011
Consolidated Statements of Equity, Three Years Ended December 31, 2012
Consolidated Statements of Cash Flows, Three Years Ended December 31, 2012
Notes to Consolidated Financial Statements
Supplemental Quarterly Information
Supplemental Information on Oil and Gas Exploration and Production Activities
Index to Financial Statements ANADARKO PETROLEUM CORPORATION
REPORT OF MANAGEMENT
Management prepared, and is responsible for, the Consolidated Financial Statements and the other information appearing in this annual report. The Consolidated Financial Statements present fairly the Company’s financial position, results of operations and cash flows in conformity with accounting principles generally accepted in the United States. In preparing its Consolidated Financial Statements, the Company includes amounts that are based on estimates and judgments that Management believes are reasonable under the circumstances. The Company’s financial statements have been audited by KPMG LLP, an independent registered public accounting firm appointed by the Audit Committee of the Board of Directors. Management has made available to KPMG LLP all of the Company’s financial records and related data, as well as the minutes of the stockholders’ and Directors’ meetings.
MANAGEMENT’S ASSESSMENT OF INTERNAL CONTROL OVER FINANCIAL REPORTING
Management is responsible for establishing and maintaining adequate internal control over financial reporting. Anadarko’s internal control system was designed to provide reasonable assurance to the Company’s Management and Directors regarding the preparation and fair presentation of published financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2012. This assessment was based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on our assessment, we believe that as of December 31, 2012, the Company’s internal control over financial reporting was effective based on those criteria.
KPMG LLP has issued an attestation report on the Company’s internal control over financial reporting as of December 31, 2012.
/s/ R. A. WALKER
R. A. Walker
President and Chief Executive Officer
/s/ ROBERT G. GWIN
Robert G. Gwin
Senior Vice President, Finance and Chief
Financial Officer
February 19, 2013
Index to Financial Statements Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders
Anadarko Petroleum Corporation:
We have audited Anadarko Petroleum Corporation’s internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Anadarko Petroleum Corporation’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Assessment of Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, Anadarko Petroleum Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Anadarko Petroleum Corporation and subsidiaries as of December 31, 2012 and 2011, and the related consolidated statements of income, comprehensive income, equity, and cash flows for each of the years in the three-year period ended December 31, 2012, and our report dated February 19, 2013 expressed an unqualified opinion on those consolidated financial statements.
/s/ KPMG LLP
Houston, Texas
February 19, 2013
Index to Financial Statements 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, 2012 and 2011, and the related consolidated statements of income, comprehensive income, equity, and cash flows for each of the years in the three-year period ended December 31, 2012. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Anadarko Petroleum Corporation and subsidiaries as of December 31, 2012 and 2011, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2012, in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Anadarko Petroleum Corporation’s internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 19, 2013 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.
/s/ KPMG LLP
Houston, Texas
February 19, 2013
Index to Financial Statements ANADARKO PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
See accompanying Notes to Consolidated Financial Statements.
Index to Financial Statements ANADARKO PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(1) Net of income tax benefit (expense) of $(4) million in 2012, $(5) million in 2011, and $(9) million in 2010.
(2) Net of income tax benefit (expense) of $56 million in 2012, $77 million in 2011, and $52 million in 2010.
(3) Net of income tax benefit (expense) of $(5) million in 2011 and $2 million in 2010.
(4) Net of income tax benefit (expense) of $(32) million in 2012, $(31) million in 2011, and $(23) million in 2010.
See accompanying Notes to Consolidated Financial Statements.
Index to Financial Statements ANADARKO PETROLEUM CORPORATION
CONSOLIDATED BALANCE SHEETS
See accompanying Notes to Consolidated Financial Statements.
Index to Financial Statements ANADARKO PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF EQUITY
(1) The $130 million increase to paid-in capital, together with the Company’s net income (loss) attributable to common stockholders, totaled $2,521 million for the year ended December 31, 2012. The $194 million increase to paid-in capital, together with the Company’s net income (loss) attributable to common stockholders, totaled $(2,455) million for the year ended December 31, 2011.
(2) Includes $92 million of tax associated with subsidiary equity transactions that occurred prior to the conversion of subordinated limited partner units to common units.
See accompanying Notes to Consolidated Financial Statements.
Index to Financial Statements ANADARKO PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
See accompanying Notes to Consolidated Financial Statements.
Index to Financial Statements ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010
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). In addition, the Company engages in the gathering, processing, treating, and transporting of natural gas, crude oil, and NGLs. The Company also participates in the hard minerals business through its ownership of non-operated joint ventures and royalty arrangements. Unless the context otherwise requires, 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 interest. All intercompany transactions have been eliminated. Undivided interests in oil and natural-gas exploration and production joint ventures are consolidated on a proportionate basis. Investments in non-controlled entities, over which Anadarko has the ability to exercise significant influence over operating and financial policies, are accounted for using the equity method. In applying the equity method of accounting, the investments are initially recognized at cost, and subsequently adjusted for the Company’s proportionate share of earnings, losses, and distributions. Other investments are carried at original cost. Investments accounted for using the equity method and cost method are reported as a component of other assets. Certain prior-period amounts have been reclassified to conform to the current-year presentation.
Use of Estimates The preparation of financial statements in accordance with accounting principles generally accepted in the United States requires that management make informed judgments and estimates that affect the reported amounts of assets, liabilities, revenues, and expenses. Management evaluates its estimates and related assumptions regularly, including those related to the value of properties and equipment; proved reserves; goodwill; intangible assets; asset retirement obligations; litigation reserves; environmental liabilities; pension assets, 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 the price paid to transfer a liability in an orderly transaction between market participants at the measurement date. Inputs used in determining fair value are characterized according to a hierarchy that prioritizes those inputs based on the degree to which they are observable. The three input levels of the fair-value hierarchy are as follows:
Level 1-Inputs represent quoted prices in active markets for identical assets or liabilities (for example, exchange-traded commodity derivatives).
Level 2-Inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly (for example, quoted market prices for similar assets or liabilities in active markets or quoted market prices for identical assets or liabilities in markets not considered to be active, inputs other than quoted prices that are observable for the asset or liability, or market-corroborated inputs).
Level 3-Inputs that are not observable from objective sources, such as the Company’s internally developed assumptions used in pricing an asset or liability (for example, an estimate of future cash flows used in the Company’s internally developed present value of future cash flows model that underlies the fair-value measurement).
Index to Financial Statements ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010
1. Summary of Significant Accounting Policies (Continued)
In determining fair value, the Company utilizes observable market data when available, or models that incorporate observable market data. In addition to market information, the Company incorporates transaction-specific details that, in management’s judgment, market participants would take into account in measuring fair value.
In arriving at fair-value estimates, the Company utilizes the most observable inputs available for the valuation technique employed. If a fair-value measurement reflects inputs at multiple levels within the hierarchy, the fair-value measurement is characterized based on 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, and investments in trading securities.
The carrying amount of cash and cash equivalents, accounts receivable, and accounts payable reported on the Consolidated Balance Sheets approximates fair value. 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 interest rate at each balance sheet date. Debt fair values, as disclosed in Note 13-Debt and Interest Expense, are based on quoted market prices for identical instruments, if available, or based on valuations of similar debt instruments.
Non-financial assets and liabilities initially measured at fair value include certain assets and liabilities acquired in a business combination or through a non-monetary exchange transaction, intangible assets, goodwill, asset retirement obligations, exit or disposal costs, and capital lease assets where the present value of lease payments is greater than the fair value of the leased asset.
Revenues The Company’s natural gas is sold primarily to interstate and intrastate natural-gas pipelines, direct end-users, industrial users, local distribution companies, and natural-gas marketers. Oil and condensate are sold primarily to marketers, gatherers, and refiners. NGLs are sold primarily to direct end-users, refiners, and marketers.
The Company recognizes sales revenues for natural 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 when a tanker lifting has occurred. The Company follows the sales method of accounting for natural-gas production imbalances. If the Company’s sales volumes for a well exceed the Company’s proportionate share of production from the well, a liability is recognized to the extent that the Company’s share of estimated remaining recoverable reserves from the well is insufficient to satisfy this imbalance. No receivables are recorded for those wells on which the Company has taken less than its proportionate share of production.
Anadarko provides gathering, processing, treating, and transporting 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 in the Consolidated Statements of Income.
Marketing margins related to the Company’s production are included in natural-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 derivatives related to such marketing activities are included in gathering, processing, and marketing sales in the Consolidated Statements of Income.
The Company enters into buy/sell arrangements related to the transportation of a portion of its crude-oil production. Under these arrangements, barrels are sold to a third-party at a location-based contract price and subsequently repurchased by the Company at a downstream location. The difference in value between the sale and purchase price represents the transportation fee from the lease or certain gathering locations to more liquid markets. These arrangements are often required by private transporters. These transactions are reported on a net basis and included in oil and gas transportation in the Consolidated Statements of Income.
Index to Financial Statements ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010
1. Summary of Significant Accounting Policies (Continued)
Cash Equivalents The Company considers all highly liquid investments with a maturity of three months or less when purchased to be cash equivalents.
Accounts Receivable and Allowance for Uncollectible Accounts The Company conducts credit analyses of customers prior to making any sales to new customers or increasing credit for existing customers. Based on these analyses, the Company may require a standby letter of credit or a financial guarantee. The Company charges uncollectible accounts receivable against the allowance for uncollectible accounts when it determines collection will no longer be pursued.
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 expense (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. Exploration costs such as exploratory geological and geophysical costs, delay rentals, and exploration overhead are charged against earnings as incurred. If an exploratory well provides evidence 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 in deepwater and international locations) depending on, 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 government sanctioning of development activities in certain international locations. At the end of each quarter, management reviews the status of all suspended exploratory well 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, associated suspended exploratory well costs are expensed.
Acquisition costs of unproved properties are periodically assessed for impairment and are transferred to proved oil and gas properties to the extent the costs are associated with successful exploration activities. Significant undeveloped leases are assessed individually for impairment, based on the Company’s current exploration plans, and a valuation allowance is provided if impairment is indicated. 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 lease terms, 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 unproved properties, as well as amortization of individually insignificant leases and impairment of unsuccessful leases, are included in exploration expense in the Consolidated Statements of Income.
Index to Financial Statements ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010
1. Summary of Significant Accounting Policies (Continued)
Capitalized Interest For significant projects, interest is capitalized as part of the historical cost of developing and constructing assets. Significant oil and gas investments in unproved properties, significant exploration and development projects that have not commenced production, and significant midstream development activities that are in progress qualify for interest capitalization. Interest is capitalized until the asset is ready for service. Capitalized interest is determined by multiplying the Company’s weighted-average borrowing cost on debt by the average amount of qualifying costs incurred. Once an asset subject to interest capitalization is completed and placed in service, the associated capitalized interest is expensed through depreciation or impairment. See Note 13-Debt and Interest Expense.
Asset Retirement Obligations Asset retirement obligations (AROs) associated with the retirement of tangible long-lived assets are recognized as liabilities with an increase to the carrying amounts of the related long-lived assets in the period incurred. The cost of the tangible asset, including the asset retirement cost, is depreciated over the useful life of the asset. AROs are recorded at estimated fair value, measured by reference to the expected future cash outflows required to satisfy the retirement obligations discounted at the Company’s credit-adjusted risk-free interest rate. Accretion expense is recognized over time as the discounted liabilities are accreted to their expected settlement value. If estimated future costs of AROs change, an adjustment is recorded to both the asset retirement obligation and the long-lived asset. 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. See Note 8-Asset Retirement Obligations.
Impairments Properties and equipment are reviewed for impairment at the lowest level for which identifiable cash flows are independent of cash flows from other assets, and when facts and circumstances indicate that 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 the undiscounted future net cash flows is less than the net book value of the property, an impairment loss is recognized for the excess, if any, of the property’s net book value over its estimated fair value. See Note 6-Impairments.
Depreciation, Depletion, and Amortization Costs of drilling and equipping successful wells, costs to construct or acquire facilities other than offshore platforms, associated asset retirement costs, and capital lease assets used in oil and gas activities are depreciated using the unit-of-production (UOP) method based on total estimated proved developed oil and gas reserves. Costs of acquiring proved properties, including leasehold acquisition costs transferred from unproved properties and costs to construct or acquire offshore platforms and associated asset retirement costs, are depleted using the UOP method based on total estimated proved developed and undeveloped reserves. Mineral properties are also depleted using the UOP method. All other properties are stated at historical acquisition cost, net of impairments, and are 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 is subject to annual impairment testing at October 1 (or more frequent testing as circumstances dictate). Anadarko has allocated goodwill to the following reporting units: oil and gas exploration and production, other gathering and processing, Western Gas Partners, LP (WES) gathering and processing, and transportation. Changes in goodwill may result from, among other things, impairments, future acquisitions, or future divestitures. See Note 9-Goodwill and Other Intangible Assets.
Other intangible assets represent contractual rights obtained in connection with business combinations that had favorable contractual terms relative to market at the acquisition date. Other intangible assets are amortized over their estimated useful lives and are assessed for impairment whenever impairment indicators are present. See Note 9-Goodwill and Other Intangible Assets.
Index to Financial Statements ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010
1. Summary of Significant Accounting Policies (Continued)
Derivative Instruments Anadarko uses derivative instruments to manage its exposure to cash-flow variability from commodity-price and interest-rate risk. Derivatives 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 unless they satisfy the normal purchases and sales exception criteria. Where the Company has the contractual right and intends to net settle, derivative assets and liabilities are reported on a net basis.
Realized and unrealized gains and losses on derivative instruments are recognized on a current basis in the Consolidated Statements of Income. Net derivative losses attributable to derivatives previously subject to hedge accounting reside in accumulated other comprehensive income and will be reclassified to earnings in future periods as the economic transactions to which the derivatives relate affect earnings. See Note 12-Derivative Instruments.
Accounts Payable Accounts payable included liabilities of $339 million at December 31, 2012, and $408 million at December 31, 2011, representing the amount by which checks issued, but not presented to the Company’s banks for collection, exceeded balances in applicable bank accounts. Changes in these liabilities are reflected in cash flows from financing activities.
Legal Contingencies The Company is subject to legal proceedings, claims, and liabilities that arise in the ordinary course of business. Except for legal contingencies acquired in a business combination, which are recorded at fair value, the Company accrues losses associated with legal claims when such losses are probable and reasonably estimable. Estimates are adjusted as additional information becomes available or circumstances change. Legal defense costs associated with loss contingencies are expensed in the period incurred. See Note 17-Contingencies.
Environmental Contingencies The Company is subject to various environmental-remediation and reclamation obligations arising from federal, state, and local laws and regulations. Except for environmental contingencies acquired in a business combination, which are recorded at fair value, the Company accrues losses associated with environmental obligations when such losses are probable and reasonably estimable. Accruals for estimated environmental losses are recognized no later than at the time the remediation feasibility study, or the evaluation of response options, is complete. These accruals are adjusted as additional information becomes available or circumstances change. Future environmental expenditures are not discounted to their present value. Recoveries of environmental costs from other parties are recorded separately as assets at their undiscounted value when receipt of such recoveries is probable. See Note 17-Contingencies.
Pension Plans, Other Postretirement Benefits, and Defined-Contribution Plans The Company measures pension plan assets at fair value. Defined-benefit plan obligations and costs are actuarially determined, incorporating the use of various assumptions. Critical assumptions for pension and other postretirement plans include the discount rate, the expected long-term rate of return on plan assets (for funded pension plans), the rate of future compensation increases, and the health care cost trend rate (for postretirement plans). Other assumptions involve demographic factors such as retirement age, mortality, and turnover. The Company evaluates and updates its actuarial assumptions at least annually.
The Company amortizes prior service costs (credits) on a straight-line basis over the average remaining service period of employees expected to receive benefits under each plan. Actuarial gains and losses that exceed 10% of the greater of the projected benefit obligation and the market-related value of assets are amortized over the average remaining service period of participating employees expected to receive benefits under each plan. See Note 22-Pension Plans, Other Postretirement Benefits, and Defined-Contribution Plans.
Index to Financial Statements ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010
1. Summary of Significant Accounting Policies (Continued)
Noncontrolling Interests Noncontrolling interests represent third-party ownership in the net assets of the Company’s consolidated subsidiaries and are presented as a component of equity. Changes in Anadarko’s ownership interests in subsidiaries that do not result in deconsolidation are recognized in equity. See Note 10-Noncontrolling Interests.
Income Taxes The Company files various U.S. 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 routinely assesses the realizability of its deferred tax assets. If the Company concludes that it is more likely than not that some of the deferred tax assets will not be realized, the tax asset is reduced by a valuation allowance. The Company recognizes a tax benefit from an uncertain tax position when it is more likely than not that the position will be sustained upon examination, based on the technical merits of the position. The tax benefit recorded is equal to the largest amount that is greater than 50% likely to be realized through final settlement with a taxing authority. Interest and penalties related to unrecognized tax benefits are recognized in income tax expense (benefit). See Note 19-Income Taxes.
Share-Based Compensation The Company accounts for share-based compensation at fair value. The Company grants equity-classified awards including stock options and non-vested equity shares (restricted stock awards and units). The Company may also grant equity-classified and liability-classified awards based on a comparison of the Company’s total shareholder return (TSR) to the TSR of a predetermined group of peer companies (performance units).
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. For other share-based compensation awards, fair value is determined using a Monte Carlo simulation or discounted cash flow methodology.
The Company records compensation cost, net of estimated forfeitures, for share-based compensation awards over the requisite service period using the straight-line method. An adjustment is made to compensation cost for any difference between the estimated forfeitures and the actual forfeitures related to the awards. For equity-classified share-based compensation awards, expense is recognized over the requisite performance period based on the grant-date fair value. For liability-classified share-based compensation awards, expense is recognized over the requisite performance period for those awards expected to ultimately be paid. The amount of expense reported is adjusted throughout the performance period for fair-value changes so that the expense recognized for each award is equivalent to the amount to be paid. See Note 15-Share-Based Compensation.
Earnings Per Share The Company’s basic earnings per share (EPS) is computed based on the average number of shares of common stock outstanding for the period and includes the effect of any participating securities as appropriate. Diluted EPS includes the effect of the Company’s outstanding stock options, restricted stock awards, restricted stock units, and performance-based stock awards, if the inclusion of these items is dilutive. See Note 14-Stockholders’ Equity.
Index to Financial Statements ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010
2. Acquisitions
In May 2011, Anadarko increased its ownership interest in a natural-gas processing plant (Wattenberg Plant), located in northeast Colorado, by acquiring an additional 93% interest for $576 million. Anadarko operates and owns a 100% interest in the Wattenberg Plant. In February 2011, WES, a consolidated subsidiary of the Company, acquired a natural-gas processing plant and related gathering systems (Platte Valley), located in northeast Colorado, for $302 million.
These acquisitions, along with future expansion plans, align Anadarko’s natural-gas processing capacity with the Company’s anticipated production growth in the Rocky Mountains Region (Rockies). In addition, these acquisitions position the Company to improve field recoveries and realize operational cost efficiencies.
The Wattenberg Plant and Platte Valley acquisitions constitute business combinations and were accounted for using the acquisition method. Preliminary fair-value measurements of assets acquired and liabilities assumed were finalized in the first quarter of 2012, and were equal to the amounts included on the Company’s Consolidated Balance Sheet at December 31, 2011. The following summarizes the fair value of assets acquired and liabilities assumed at the acquisition dates:
Fair-value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and thus represent Level 3 inputs. The fair value of acquired properties and equipment is based on market and cost approaches. Intangible assets consist of customer contracts, the fair value of which was determined using an income approach. Deferred tax assets represent the tax effects of differences in the tax basis and acquisition-date fair values of assets acquired and liabilities assumed. Liabilities assumed include asset retirement obligations existing at the date of acquisition, and are valued consistent with the Company’s policy for estimating such obligations.
Assets acquired and liabilities assumed are included within the midstream reporting segment, except for $335 million of goodwill and a portion of the related deferred tax asset recognized in connection with the Wattenberg Plant acquisition, which are included in the oil and gas exploration and production reporting segment. Goodwill of $469 million related to the Wattenberg Plant acquisition is amortizable for tax purposes.
Goodwill from these acquisitions is included in the oil and gas exploration and production reporting segment and the midstream reporting segment based on the increase in fair value to each of the respective reporting segments. The increase in fair value to these reporting segments is derived from improved NGLs volume retention from equity production and the alignment of Company-controlled natural-gas processing capacity with future production growth plans in the Rockies. See Note 9-Goodwill and Other Intangible Assets.
Index to Financial Statements ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010
2. Acquisitions (Continued)
Prior to the Wattenberg Plant acquisition, the Company was party to natural-gas processing contracts with the previous Wattenberg Plant owner. As a result of the acquisition, these preexisting contracts were effectively eliminated, for purposes of consolidated financial reporting, causing the Company to recognize a $76 million loss, which is included in gains (losses) on divestitures and other, net in the Company’s Consolidated Statement of Income for the year ended December 31, 2011. This loss represents the aggregate amount by which the contracts were unfavorable as compared to market transactions for the same or similar services at the date the Company acquired the Wattenberg Plant.
The Company also recognized a gain of $21 million from the acquisition-date fair-value remeasurement of its pre-acquisition 7% equity interest in the Wattenberg Plant. The gain is included in gains (losses) on divestitures and other, net in the Company’s Consolidated Statement of Income for the year ended December 31, 2011.
Results of operations attributable to the Wattenberg Plant and Platte Valley acquisitions are included in the Company’s Consolidated Statements of Income from the dates acquired. The amounts of revenue and earnings included in the Company’s Consolidated Statement of Income for the year ended December 31, 2011, and the amounts of revenue and earnings that would have been recognized had the acquisitions occurred on January 1, 2010, are not material to the Company’s Consolidated Statements of Income.
3. Divestitures and Assets Held for Sale
Divestitures In 2012, proceeds from divestitures of $433 million were primarily related to U.S. oil and gas properties and net losses on divestitures of $43 million were primarily related to oil and gas properties in Indonesia. In 2011, the Company received $419 million related to contingent consideration received for the 2008 divestiture of its interest in the Peregrino field offshore Brazil. In 2010, proceeds from divestitures of $70 million and net gains on divestitures of $29 million were primarily related to U.S. onshore oil and gas properties.
Assets Held for Sale In 2011, the Company began marketing certain domestic properties from the oil and gas exploration and production reporting segment and the midstream reporting segment in order to redirect operating activities and capital investment to other areas. These assets were remeasured to their fair value, estimated using Level 3 fair-value inputs, with resulting losses of $390 million related to oil and gas exploration and production reporting segment properties and $32 million related to midstream reporting segment properties. On the Company’s Consolidated Balance Sheet at December 31, 2011, amounts associated with assets held for sale included $320 million in net properties and equipment, $38 million in goodwill and other intangible assets, and $75 million in other long-term liabilities.
In 2012, the Company recognized losses on assets held for sale of $28 million primarily related to certain oil and gas exploration and production reporting segment properties. Gains and losses related to assets held for sale are included in gains (losses) on divestitures and other, net in the Company’s Consolidated Statements of Income. At December 31, 2012, the remaining balances of assets and liabilities associated with assets held for sale were not material.
Index to Financial Statements ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010
4. Inventories
The following summarizes the major classes of inventories, included in other current assets, at December 31:
5. Properties and Equipment
The following summarizes the cost of properties and equipment by segment at December 31:
(1) Includes costs associated with unproved properties of $7.1 billion at December 31, 2012, and $8.3 billion at December 31, 2011.
6. Impairments
The following summarizes impairments by segment for the years ended December 31:
Index to Financial Statements ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010
6. Impairments (Continued)
In 2012, U.S. onshore and midstream properties were impaired primarily due to lower natural-gas prices. The Gulf of Mexico properties were impaired primarily as a result of downward reserves revisions for a property that was near the end of its economic life. In 2011, U.S. onshore and midstream properties were impaired primarily due to decreases in natural-gas prices, and Gulf of Mexico properties were impaired due to declines in estimated recoverable reserves. In 2010, the impairment of Gulf of Mexico properties related to a production platform that remains idle with no immediate plan for use, and for which a limited market exists. Impairments of the Company’s Venezuelan cost-method investment were due to declines in estimated recoverable reserves in 2012, 2011, and 2010, and lower crude-oil prices in 2012.
The following summarizes the aggregate fair values of the above-described assets, by major category and input level within the fair-value hierarchy, at the respective dates of impairment:
(1) The income approach was used to measure fair value.
Impairments of Unproved Properties Impairments of unproved properties are included in exploration expense in the Company’s Consolidated Statements of Income. In 2012, the Company recognized a $721 million impairment of unproved Powder River coalbed methane properties primarily resulting from lower natural-gas prices. Also in 2012, the Company recognized a $124 million impairment of an unproved Gulf of Mexico natural-gas property that the Company does not plan to pursue under the forecasted natural-gas price environment.
7. Suspended Exploratory Well Costs
The following summarizes the changes in suspended exploratory well costs at December 31 for each of the last three years. Additions pending the determination of proved reserves excludes amounts capitalized and subsequently charged to expense within the same year.
Index to Financial Statements ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010
7. Suspended Exploratory Well Costs (Continued)
The following summarizes an aging of suspended exploratory well costs by geographic area and the year the costs were suspended at December 31, 2012:
(1) Excludes additions subsequently reclassified to proved properties within the same year.
Suspended exploratory well costs capitalized for a period greater than one year at December 31, 2012, after completion of drilling were associated with 22 projects, primarily located in Ghana, Brazil, the Gulf of Mexico, and Mozambique. Project costs suspended for longer than one year were primarily suspended pending the completion of economic evaluations including, but not limited to, results of additional appraisal drilling, facilities, infrastructure, well-test analysis, additional geological and geophysical data, development plan approval, and permitting. Management believes projects with suspended exploratory well costs exhibit sufficient quantities of hydrocarbons to justify potential development and is actively pursuing efforts to assess whether reserves can be attributed to these projects. 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.
8. Asset Retirement Obligations
The majority of Anadarko’s AROs relate to the plugging of wells and the related abandonment of oil and gas properties. The following provides a rollforward of the Company’s combined short- and long-term AROs. Revisions in 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 settlement.
(1) Short-term AROs of $298 million at December 31, 2012, and $31 million at December 31, 2011, were included in accrued expenses on the Company’s Consolidated Balance Sheets.
Index to Financial Statements ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010
9. Goodwill and Other Intangible Assets
Goodwill The Company completed its annual impairment assessment of goodwill during the fourth quarter of 2012, and the test indicated no impairment. At December 31, 2012, the Company had $5.5 billion of goodwill allocated to the following reporting units: $5.3 billion to oil and gas exploration and production, $87 million to other gathering and processing, $83 million to WES gathering and processing, and $5 million to transportation.
Significant declines in commodity prices, difficulty or potential delays in obtaining drilling permits, or other unanticipated events could result in further goodwill impairment tests in the near term, the results of which may have a material adverse impact on the Company’s results of operations.
Other Intangible Assets Intangible assets and associated amortization expense were as follows:
Customer contract intangible assets are primarily related to the Wattenberg Plant acquisition. The contracts are included in the Company’s midstream reporting segment and are being amortized over 50 years. See Note 2-Acquisitions. The estimated aggregate amortization expense for intangible assets for the next five years is not expected to be material.
10. Noncontrolling Interests
In December 2012, Western Gas Equity Partners, LP (WGP), a consolidated subsidiary formed to own Anadarko’s partnership interests in WES, completed its initial public offering (IPO) of approximately 20 million common units representing limited partner interests in WGP at a price of $22.00 per common unit, for net proceeds of $411 million. At December 31, 2012, Anadarko’s ownership interest in WGP consisted of a 91.0% limited partner interest and the entire general partner interest.
WES, a consolidated subsidiary, is a limited partnership formed by Anadarko to own, operate, acquire, and develop midstream assets. WES issued approximately 5 million common units to the public raising net proceeds of $212 million in 2012, approximately 10 million common units were issued to the public raising net proceeds of $328 million in 2011, and approximately 13 million common units were issued to the public raising net proceeds of $338 million in 2010. At December 31, 2012, WGP’s ownership interest in WES consisted of a 46.2% limited partner interest, the entire 2.0% general partner interest, and all of the WES incentive distribution rights.
Index to Financial Statements ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010
11. Equity-Method Investments
In 2007, Anadarko contributed certain of its oil and gas properties and gathering and processing assets, with an aggregate fair value of $2.9 billion at the time of the contribution, to newly formed unconsolidated entities in exchange for noncontrolling mandatorily redeemable London Interbank Offered Rate (LIBOR) based preferred interests in those entities. The common equity of the investee entities is 95% owned by third parties that also maintain control over the assets. Subsequent to their formation, the investee entities loaned Anadarko an aggregate of $2.9 billion. The Company accounts for its investment in these entities using the equity method of accounting. The carrying amount of these investments was $2.8 billion and the carrying amount of notes payable to affiliates was $2.9 billion at December 31, 2012. 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 value of its interest in the corresponding investee. Accordingly, the investments and the obligations are presented net on the Consolidated Balance Sheets with the excess of the notes payable to affiliates over the aggregate investment carrying amounts reported in other long-term liabilities-other for all periods presented.
Interest on the notes issued by Anadarko is variable, based on LIBOR, plus a spread that fluctuates with Anadarko’s credit rating. The applicable interest rate was 1.31% at December 31, 2012, and 1.55% at December 31, 2011. The note payable agreement contains a covenant that provides for a maximum debt-to-capital ratio of 67%. Anadarko was in compliance with this covenant at December 31, 2012. Other (income) expense, net includes interest expense on the notes payable of $42 million in 2012, $38 million in 2011, and $39 million in 2010, and equity earnings from Anadarko’s investments in the investee entities of $(43) million in 2012, $(41) million in 2011, and $(37) million in 2010.
12. Derivative Instruments
Objective and Strategy The Company uses derivative instruments to manage its exposure to cash-flow variability from commodity-price and interest-rate risks. Futures, swaps, and options are used to manage exposure to commodity-price risk inherent in the Company’s oil and natural-gas production and natural-gas processing operations (Oil and Natural-Gas Production/Processing Derivative Activities). Futures contracts and commodity-price swap agreements are used to fix the price of expected future oil and natural-gas sales at major industry trading locations, such as Henry Hub for natural gas and Cushing for oil. Basis swaps are used to fix or float the price differential between product prices at one market location versus another. Options are used to establish a floor price, a ceiling price, or a floor and a ceiling price (collar) for expected future oil and natural-gas sales. Derivative instruments are also used to manage commodity-price risk inherent in customer price requirements and to fix margins on the future sale of natural gas and NGLs from the Company’s leased storage facilities (Marketing and Trading Derivative Activities).
Interest-rate swaps are used to fix or float interest rates on existing or anticipated indebtedness. The purpose of these instruments is to manage the Company’s existing or anticipated exposure to unfavorable interest-rate changes. The fair value of the Company’s interest-rate swap portfolio increases (decreases) when interest rates increase (decrease).
The Company does not apply hedge accounting to any of its derivative instruments. 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 as the transactions to which the derivatives relate are recognized in earnings. Accumulated other comprehensive loss balances related to interest-rate derivatives that were previously subject to hedge accounting were $96 million ($61 million after tax) at December 31, 2012, and $109 million ($70 million after tax) at December 31, 2011.
Index to Financial Statements ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010
12. Derivative Instruments (Continued)
Oil and Natural-Gas Production/Processing Derivative Activities The natural-gas prices listed below are New York Mercantile Exchange (NYMEX) Henry Hub prices. The crude-oil prices listed below are a combination of NYMEX West Texas Intermediate (WTI) and IntercontinentalExchange, Inc. (ICE) Brent prices. The following is a summary of the Company’s derivative instruments related to its Oil and Natural-Gas Production/Processing Activities at December 31, 2012:
(1) The Company entered into offsetting purchased and sold natural-gas three-way collars of 450,000 MMBtu/d for 2013 settlement.
MMBtu-million British thermal units
MMBtu/d-million British thermal units per day
MBbls/d-thousand barrels per day
A three-way collar is a combination of three options: a sold call, a purchased put, and a sold put. The sold call establishes the maximum price that the Company will receive for the contracted commodity volumes. The purchased put establishes the minimum price that the Company will receive for the contracted volumes unless the market price for the commodity falls below the sold put strike price, at which point the minimum price equals the reference price (e.g., 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. These activities include physical product sales and related derivative transactions used to manage commodity-price risk. At December 31, 2012, the Company had fixed-price physical transactions related to natural gas totaling 10 billion cubic feet (Bcf), offset by derivative transactions totaling 10 Bcf. At December 31, 2011, the Company had fixed-price physical transactions related to natural gas totaling 22 Bcf, offset by derivative transactions totaling 21 Bcf.
Index to Financial Statements ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010
12. Derivative Instruments (Continued)
Interest-Rate Derivatives In December 2008 and January 2009, Anadarko entered into interest-rate swap contracts as a fixed-rate payer to mitigate the interest-rate risk associated with anticipated 2011 and 2012 debt issuances. The Company locked in a fixed interest rate in exchange for a floating interest rate indexed to the three-month LIBOR. 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.
To align the swap portfolio with the anticipated timing of future debt refinancing, the Company extended the swap maturity dates for certain interest-rate swaps. In 2012, the Company extended the swap maturity dates from October 2012 to September 2016 for interest-rate swaps with an aggregate notional principal amount of $800 million. In 2011, the Company extended the swap maturity dates from October 2011 to June 2014 for interest-rate swaps with an aggregate notional principal amount of $1.85 billion. In connection with these extensions, the swap interest rates were also adjusted. Interest-rate swap agreements with an aggregate notional principal amount of $200 million were settled in October 2012, resulting in a realized loss of $64 million, and interest-rate swap agreements with an aggregate notional principal amount of $150 million were settled in October 2011, resulting in a realized loss of $57 million.
The Company had the following outstanding interest-rate swaps at December 31, 2012:
Effect of Derivative Instruments-Balance Sheet The following summarizes the fair value of the Company’s derivative instruments at December 31:
Index to Financial Statements ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010
12. Derivative Instruments (Continued)
Effect of Derivative Instruments-Statement of Income The following summarizes realized and unrealized gains or losses related to derivative instruments:
(1) Represents the effect of marketing and trading derivative activities.
Index to Financial Statements ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010
12. Derivative Instruments (Continued)
Credit-Risk Considerations The financial integrity of exchange-traded contracts, which are subject to nominal credit risk, is assured by NYMEX or ICE through systems of financial safeguards and transaction guarantees. Over-the-counter traded swaps, options, and futures contracts expose the Company to counterparty credit risk. The Company monitors the creditworthiness of its counterparties, establishes credit limits according to the Company’s credit policies and guidelines, and assesses the impact on fair value of its counterparties’ creditworthiness. The Company has the ability to require cash collateral or letters of credit to mitigate its credit-risk exposure. The Company has netting agreements with financial institutions that permit net settlement of gross commodity derivative assets against gross commodity derivative liabilities, and routinely exercises its contractual right to offset realized gains against realized losses when settling with derivative counterparties.
In addition, the Company has setoff agreements with certain financial institutions that may be exercised in the event of default and that provide for contract termination and net settlement across derivative types. At December 31, 2012, $339 million of the Company’s $1.4 billion gross derivative liability balance, and at December 31, 2011, $749 million of the Company’s $1.6 billion gross derivative liability balance, would have been eligible for setoff against the Company’s gross derivative asset balance in the event of default. Other than in the event of default, the Company does not net settle across derivative types.
Some of the Company’s derivative instruments are subject to provisions that can require full or partial collateralization or immediate settlement of the Company’s obligations if certain credit-risk-related provisions are triggered. However, most of the Company’s derivative counterparties maintain secured positions with respect to the Company’s derivative liabilities under the Company’s $5.0 billion senior secured revolving credit facility ($5.0 billion Facility), the available capacity of which is sufficient to secure potential obligations to such counterparties.
Unsecured derivative obligations may require immediate settlement or full collateralization if certain credit-risk-related provisions are triggered, such as the Company’s credit rating declining to a level below investment grade by major credit rating agencies. The aggregate fair value of derivative instruments with credit-risk-related contingent features for which a net liability position existed was $94 million (net of collateral) at December 31, 2012, and $2 million (net of collateral) at December 31, 2011. These amounts were included in accrued expenses on the Company’s Consolidated Balance Sheets.
Index to Financial Statements ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010
12. Derivative Instruments (Continued)
Fair Value Fair value of futures contracts is based on quoted prices in active markets for identical assets or liabilities, which represent Level 1 inputs. Valuations of physical-delivery purchase and sale agreements, over-the-counter financial swaps, and commodity-option collars are based on similar transactions observable in active markets and industry-standard models that primarily rely on market-observable inputs. Inputs used to estimate the fair value of swaps and options include market-price curves; contract terms and prices; credit-risk adjustments; and, for Black-Scholes option valuations, implied market volatility and discount factors. Inputs used to estimate fair value in industry-standard models are categorized as Level 2 inputs because substantially all assumptions and inputs are observable in active markets throughout the full term of the instruments.
The following summarizes the fair value of the Company’s derivative assets and liabilities, by input level within the fair-value hierarchy:
(1) Represents the impact of netting commodity derivative assets and liabilities with counterparties where the Company has the contractual right and intends to net settle.
Index to Financial Statements ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010
13. Debt and Interest Expense
Debt The Company’s outstanding debt is senior unsecured, except for borrowings, if any, under the $5.0 billion Facility. See Note 11-Equity-Method Investments for disclosure regarding Anadarko’s notes payable related to its ownership of certain noncontrolling mandatorily redeemable interests that are not included in the Company’s reported debt balance and do not affect consolidated interest expense. The following summarizes the Company’s outstanding debt:
(1) Unamortized discounts and premiums are amortized over the term of the related debt.
Index to Financial Statements ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010
13. Debt and Interest Expense (Continued)
In a 2006 private offering, Anadarko received $500 million of loan proceeds upon issuing the Zero-Coupon Senior Notes due 2036 (Zero Coupons). The Zero Coupons mature in 2036 and have an aggregate principal amount due at maturity of $2.4 billion, reflecting a yield to maturity of 5.24%. The holder has the right to cause the Company to repay an amount up to the then-accreted value of the outstanding Zero Coupons in October of each year. The holder did not elect to put any of the accreted balance of the Zero Coupons to the Company in October 2012. The Zero Coupons are classified as long-term debt on the Consolidated Balance Sheets based on the Company’s ability and intent to refinance the obligations, if the holder requests repayment in 2013.
Fair Value The Company uses a market approach to determine fair value of its fixed-rate debt using observable market data, which results in a Level 2 fair-value measurement. The carrying amount of floating-rate debt approximates fair value as the interest rates are variable and reflective of market rates. The estimated fair value of the Company’s total borrowings was $16.2 billion at December 31, 2012, and $17.3 billion at December 31, 2011.
Debt Activity The following summarizes the Company’s debt activity during 2012 and 2011:
Capital Lease Obligation In the fourth quarter of 2010, a lease commenced for a floating production, storage, and offloading vessel (FPSO) for the Company’s Jubilee field operations in Ghana. In December 2011, the Company and its partners in the Jubilee project purchased the FPSO, resulting in the cancellation of the capital lease obligation.
Index to Financial Statements ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010
13. Debt and Interest Expense (Continued)
Anadarko Revolving Credit Facility and Letter of Credit Facility In September 2010, the Company entered into the $5.0 billion Facility maturing in September 2015. Borrowings under the $5.0 billion Facility bear interest at LIBOR plus an applicable margin ranging from 1.25% to 2.50%, depending on the Company’s credit rating, or rates at a margin above the one-month LIBOR, the federal funds rate, or prime rates offered by certain designated banks. During 2012, the Company repaid all outstanding borrowings under the $5.0 billion Facility with cash on hand and cash realized from the resolution of the Algeria exceptional profits tax dispute.
Obligations incurred under the $5.0 billion Facility, as well as obligations Anadarko has to lenders or their affiliates pursuant to certain derivative instruments that are supported by the $5.0 billion Facility (as discussed in Note 12-Derivative Instruments), are guaranteed by certain of the Company’s wholly owned domestic subsidiaries, and are secured by a perfected first-priority security interest in certain exploration and production assets located in the United States and 65% of the capital stock of certain wholly owned foreign subsidiaries. At December 31, 2012, the Company was in compliance with applicable covenants and there were no restrictions on its ability to utilize the $5.0 billion Facility.
In 2011, the Company entered into an agreement with a financial institution to provide up to $400 million of letters of credit (LOC Facility). In the third quarter of 2012, the Company terminated the LOC Facility.
WES Borrowings In March 2011, WES entered into a five-year, $800 million senior unsecured revolving credit facility (RCF). The $800 million RCF matures in March 2016 and bears interest at LIBOR plus an applicable margin ranging from 1.30% to 1.90%, or rates at a margin above the one-month LIBOR, the federal funds rate, or prime rates offered by certain designated banks. In 2012, WES repaid all outstanding borrowings under its RCF with net proceeds from its public offering of $670 million aggregate principal amount of 4.000% Senior Notes due 2022. At December 31, 2012, WES was in compliance with all of the covenants contained in the RCF.
Scheduled Maturities Total principal amount of debt maturities for the five years ending December 31, 2017, excluding the potential repayment of the outstanding Zero Coupons that may be put by the holder to the Company annually, were as follows:
Interest Expense The following summarizes interest expense for the years ended December 31:
(1) Loss on early debt retirements in 2010 is the result of repurchasing $1.4 billion aggregate principal amount of debt due 2011 and 2012.
Index to Financial Statements ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010
14. Stockholders’ Equity
Common Stock In August 2011, the Company terminated its $5.0 billion share-repurchase program under which shares could be repurchased either in the open market or through privately negotiated transactions. The following summarizes the changes in the Company’s outstanding shares of common stock:
The reconciliation between basic and diluted EPS attributable to common stockholders is as follows:
(1) Inclusion of certain shares would have had an anti-dilutive effect.
Index to Financial Statements ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010
15. Share-Based Compensation
At December 31, 2012, 30 million shares of the 31 million shares of Anadarko common stock authorized for awards under active share-based compensation plans remained available for future issuance. The Company generally issues new shares to satisfy awards under employee share-based payment plans. The number of shares available is reduced by awards granted. The following summarizes share-based compensation expense for the years ended December 31:
Cash flows from financing activities included excess tax benefits related to share-based compensation of $51 million in 2012, $(15) million in 2011, and $26 million in 2010. Cash received from stock option exercises was $52 million in 2012, $45 million in 2011, and $78 million in 2010.
Equity-Classified Awards
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 do not have the right to vote. Restricted stock vests over service periods ranging from the date of grant up to three years and is not considered issued and outstanding until vested.
Non-employee directors are granted deferred shares that are held in a grantor trust by the Company until payable. Non-employee directors may receive these shares in a lump-sum payment or in annual installments.
Index to Financial Statements ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010
15. Share-Based Compensation (Continued)
The following summarizes the Company’s restricted stock activity:
The weighted-average grant-date fair value per share of restricted stock granted was $81.19 during 2011 and $68.51 during 2010. The total fair value of restricted shares vested was $105 million during 2012, $124 million during 2011, and $122 million during 2010, based on the market price at the vesting date. At December 31, 2012, total unrecognized compensation cost related to restricted stock of $148 million is expected to be recognized over a weighted-average remaining service period of 1.9 years.
Stock Options Certain employees may be granted nonqualified 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 three years from the date of grant and terminate at the earlier of the date of exercise or seven years from the date of grant.
Non-employee directors may be granted nonqualified stock options 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 a one-year service period from the date of grant and terminate at the earlier of the date of exercise or ten years from the date of grant.
The fair value of stock option awards is determined using the Black-Scholes option-pricing model. The expected life of an option is estimated based on historical exercise behavior. Volatility assumptions are estimated based on an average of historical volatility over the expected life of an option and the 12-month average implied volatility. Risk-free interest rates are based on the U.S. Treasury rate over the expected life of an option. The dividend yield is based on a 12-month average dividend yield, taking into account the Company’s expected dividend policy over the expected life of an option. Expected forfeiture rates are estimated based on historical forfeiture experience. The Company used the following weighted-average assumptions to estimate the fair value of stock options granted during 2012, 2011, and 2010:
Index to Financial Statements ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010
15. Share-Based Compensation (Continued)
The following summarizes the Company’s stock option activity:
The per-option weighted-average grant-date fair value of stock options granted was $25.84 during 2012, $29.77 during 2011, and $26.44 during 2010. The total intrinsic value of stock options exercised was $49 million during 2012, $45 million during 2011, and $62 million during 2010, based on the difference between the market price at the exercise date and the exercise price. At December 31, 2012, total unrecognized compensation cost related to stock options of $46 million is expected to be recognized over a weighted-average remaining period of 2.0 years.
Performance-Based Share Awards In 2007, certain officers of the Company were provided Performance Unit Award Agreements with performance periods ranging from one to three years. The number of shares of common stock earned under these agreements was based on a comparison of the Company’s TSR to the TSR of a predetermined group of peer companies over the specified performance periods. The maximum number of shares of Anadarko common stock available to be earned was 934,424 shares based on predefined payout percentages. At December 31, 2012, all performance periods have ended and a total of 521,258 shares were earned, with no additional shares available to be earned in the future. Of the total shares earned, 386,574 shares have been issued and 134,684 shares have been deferred pursuant to the agreements. There were no performance-based shares issued during 2012. The fair value of the performance-based share awards issued was $6 million during 2011 and $17 million during 2010, based on the market price on the date of issuance. At December 31, 2012, the Company had no unrecognized compensation cost related to these awards.
Index to Financial Statements ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010
15. Share-Based Compensation (Continued)
Liability-Classified Awards
Value Creation Plan As a part of its employee compensation program, the Company offers an incentive compensation program that provides non-officer employees the opportunity to earn cash bonus awards based on the Company’s TSR for the year, compared to the TSR of a predetermined group of peer companies. The Company paid $24 million during 2012 related to the plan, and zero during 2011 and 2010. At December 31, 2012, the Company had no outstanding liability attributable to the 2012 performance period.
Performance-Based Unit Awards Certain officers of the Company were provided Performance Unit Award Agreements with two- and three-year performance periods. The vesting of these units is based solely on comparing the Company’s TSR to the TSR of a predetermined group of peer companies over the specified performance period. Each performance unit represents the value of one share of the Company’s common stock. At the end of each performance period, the value of the vested performance units, if any, is paid in cash. The Company paid $37 million related to vested performance units in 2012, $25 million in 2011, and zero in 2010. At December 31, 2012, the Company’s liability under Performance Unit Award Agreements was $26 million, with total estimated unrecognized compensation cost related to these awards of $19 million expected to be recognized over a weighted-average remaining performance period of 1.8 years.
Other Performance-Based Awards Prior to 2011, certain officers of the general partner of WES were awarded general partner Unit Appreciation Rights (UARs) pursuant to the Western Gas Holdings, LLC Equity Incentive Plan. The fair value of the UARs was determined based on the fair value of WES’s general partner, as determined by the WGP IPO price. The Company paid $203 million related to the UARs upon the WGP IPO in 2012, and zero in 2011 and 2010. At December 31, 2012, the Company had no outstanding liability and no unrecognized compensation cost attributable to these awards.
Index to Financial Statements ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010
16. Commitments
Operating Leases The Company had $3.4 billion in long-term drilling rig commitments that satisfy operating lease criteria. The Company also has various commitments under non-cancelable operating lease agreements of $614 million for production platforms and equipment, buildings, facilities, compressors, and aircraft. These operating leases expire at various dates through 2026. Certain of these operating leases contain residual value guarantees at the end of the lease term, totaling $96 million at December 31, 2012; however, no liability has been accrued for residual value guarantees. Future minimum lease payments under operating leases at December 31, 2012, were as follows:
Total rent expense, net of sublease income, amounted to $136 million in 2012, $143 million in 2011, and $154 million in 2010. Total rent expense includes contingent rent expense related to processing fees of $18 million in 2012, $21 million in 2011, and $20 million in 2010.
Drilling Rig Commitments Anadarko has entered into various agreements to secure drilling rigs necessary to execute its drilling plans over the next several years. The table of future minimum lease payments above includes approximately $3.2 billion related to 12 offshore drilling vessels and $183 million related to certain contracts for U.S. onshore drilling rigs. Lease payments associated with the drilling of 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.
Spar Platform and Production Vessel Leases Anadarko has operating leases related to certain spar platforms in the Gulf of Mexico. The table of future minimum lease payments above includes approximately $354 million for these agreements. These agreements also contain unrecorded residual value guarantees totaling $37 million at the end of the lease periods.
Other Commitments In the normal course of business, the Company enters into other contractual agreements for processing, treating, transportation, and storage of natural gas, crude oil, and NGLs, as well as for other services. These agreements expire at various dates through 2028. At December 31, 2012, aggregate future payments under these contracts totaled $8.8 billion, of which $1.7 billion is expected to be paid in 2013, $1.4 billion in 2014, $1.1 billion in 2015, $881 million in 2016, $772 million in 2017, and $2.9 billion thereafter.
Index to Financial Statements ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010
17. Contingencies
General The Company is a defendant in a number of lawsuits and is involved in governmental proceedings and regulatory controls arising in the ordinary course of business, including, but not limited to, personal injury claims, title disputes, tax disputes, royalty claims, contract claims, oil-field contamination claims, and environmental claims, including claims involving assets owned by acquired companies. The Company had accrued $49 million at December 31, 2012, and $342 million at December 31, 2011, related to litigation contingencies. Anadarko is also subject to various environmental-remediation and reclamation obligations arising from federal, state, and local laws and regulations. The Company’s Consolidated Balance Sheets include liabilities of $81 million at December 31, 2012, and $92 million at December 31, 2011, for remediation and reclamation obligations. While the ultimate outcome and impact on the Company cannot be predicted with certainty, after consideration of recorded expense and liability accruals, management believes that the resolution of pending proceedings will not have a material adverse effect on the Company’s consolidated financial position, results of operations, or cash flows.
Deepwater Horizon Events In April 2010, the Macondo well in the Gulf of Mexico blew out and an explosion occurred on the Deepwater Horizon drilling rig. The well was operated by BP Exploration and Production Inc. (BP) and Anadarko held a 25% non-operated interest. In October 2011, the Company and BP entered into a settlement agreement, mutual releases, and agreement to indemnify relating to the Deepwater Horizon events (Settlement Agreement), under which the Company paid $4.0 billion in cash and transferred its interest in the Macondo well and the Mississippi Canyon Block 252 (Lease) to BP. Pursuant to the Settlement Agreement, the Company is fully indemnified by BP against all claims, causes of action, losses, costs, expenses, liabilities, damages, or judgments of any kind arising out of the Deepwater Horizon events, related damage claims arising under the Oil Pollution Act of 1990 (OPA), claims for natural resource damages (NRD) and assessment costs, and any claims arising under the Operating Agreement with BP (OA). This indemnification is guaranteed by BP Corporation North America Inc. (BPCNA) and, in the event that the net worth of BPCNA declines below an agreed-on amount, BP p.l.c. has agreed to become the sole guarantor. Under the Settlement Agreement, BP does not indemnify the Company against fines and penalties, punitive damages, shareholder derivative or securities laws claims, or certain other claims.
Liability Accrual Below is a discussion of the Company’s current analysis, under applicable accounting guidance, of its potential liability for (i) amounts invoiced by BP under the OA (OA Liabilities), (ii) OPA-related environmental costs, and (iii) other contingent liabilities. Accounting rules require loss recognition where a potential loss is considered probable and can be reasonably estimated.
The Company is fully indemnified by BP against OPA damage claims, NRD claims and assessment costs, and other potential liabilities. The Company may be required to recognize a liability for these amounts in advance of or in connection with recognizing a receivable from BP for the related indemnity payment. In all circumstances, however, the Company expects that any additional indemnified liability that may be recognized by the Company will be subsequently recovered from BP itself or through the guarantees of BPCNA or BP p.l.c. The Company has not recorded a liability for any costs that are subject to indemnification by BP.
OA Liabilities Pursuant to the Settlement Agreement, all amounts deemed by BP to have been due under the OA, as well as all future amounts that otherwise would be invoiced to Anadarko under the OA, have been satisfied.
Index to Financial Statements ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010
17. Contingencies (Continued)
OPA-Related Environmental Costs BP, Anadarko, and other parties, including parties that do not own an interest in the Lease, such as the drilling contractor, have received correspondence from the U.S. Coast Guard (USCG) referencing their identification as a “responsible party or guarantor” (RP) under OPA. Under OPA, RPs, including Anadarko, may be jointly and severally liable for costs of well control, spill response, and containment and removal of hydrocarbons, as well as other costs and damage claims related to the spill and spill cleanup. The USCG’s identification of Anadarko as an RP arises as a result of Anadarko’s status as a co-lessee in the Lease.
Applicable accounting guidance requires the Company to accrue an environmental liability if it is both probable that a liability is incurred and the amount of the liability can be reasonably estimated. Under accounting guidance applicable to environmental liabilities, a liability is presumed probable if the entity is both identified as an RP and associated with the environmental event. The Company’s co-lessee status in the Lease at the time of the event and the subsequent identification and treatment of the Company as an RP satisfies these standards and therefore establishes the presumption that the Company’s potential environmental liabilities related to the Deepwater Horizon events are probable.
As BP funds OPA-related environmental costs, any potential joint and several liability for these costs is satisfied for all RPs, including Anadarko. This bears significance in that once these costs are funded by BP, such costs are no longer analyzed as OPA-related environmental costs, but instead are analyzed as OA Liabilities. As discussed above, Anadarko has settled its OA Liabilities with BP. Thus, potential liability to the Company for OPA-related environmental costs can arise only where BP does not, or otherwise is unable to, fund all of the OPA-related environmental costs. Under this scenario, the joint and several nature of the liability for these costs could cause the Company to recognize a liability for OPA-related environmental costs. However, the Company is fully indemnified by BP against these costs (including guarantees by BPCNA or BP p.l.c.).
Gross OPA-Related Environmental Cost Estimate In prior periods, the Company provided an estimated range of gross OPA-related environmental costs for all identified RPs. This estimate was comprised of spill-response costs and OPA damage claims and was derived from cost information received by the Company from BP. The Company no longer receives Deepwater Horizon-related cost and claims data from BP. Accordingly, the OPA-related environmental cost estimate included in BP’s public releases is the best data available to the Company.
Based on information included in BP p.l.c.’s public release on February 5, 2013, gross OPA-related environmental costs are estimated to be $10.7 billion, excluding (i) amounts BP has already funded, which constitute settled OA Liabilities; (ii) amounts that in BP’s view cannot reasonably be estimated, which include NRD claims and other litigation damages; (iii) non-OPA-related fines and penalties that may be assessed against Anadarko, including assessments under the Clean Water Act (CWA); and (iv) estimated state and local governmental claims, which BP no longer publicly discloses and, as a result, Anadarko cannot estimate. Actual gross OPA-related environmental costs may vary from those estimated by BP p.l.c. in its public releases, perhaps materially from the above estimate.
Index to Financial Statements ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010
17. Contingencies (Continued)
Allocable Share of Gross OPA-Related Environmental Costs Under applicable accounting guidance, the Company is required to estimate its allocable share of gross OPA-related environmental costs. To date, BP has paid all Deepwater Horizon event-related costs, which satisfies the Company’s potential liability for these costs. Additionally, BP has repeatedly stated publicly and in prior congressional testimony that it will continue to pay these costs. BP’s funding and public commentary has continued subsequent to the release of BP’s own investigation report, the National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling’s final report, and the Deepwater Horizon Joint Investigation Team final report, which the Company considers to be significant positive indications in assessing the likelihood of BP continuing to fund all of these costs. Based on BP’s stated intent to continue funding these costs, the Company’s assessment of BP’s financial ability to continue funding these costs, and the impact of BP’s settlements with both of its OA partners, the Company believes the likelihood of BP not continuing to satisfy these claims to be remote. Accordingly, the Company considers zero to be its allocable share of gross OPA-related environmental costs and, consistent with applicable accounting guidance, has not recorded a liability for these amounts.
Penalties and Fines These costs include amounts that may be assessed as a result of potential civil and/or criminal penalties under various federal, state, and/or local statutes and/or regulations as a result of the Deepwater Horizon events, including, for example, the CWA, the Outer Continental Shelf Lands Act, the Migratory Bird Treaty Act, and possibly other federal, state, and local laws. The foregoing does not represent an exhaustive list of statutes and regulations that potentially could trigger a penalty or fine assessment against the Company. To date, no penalties or fines have been assessed against the Company. However, in December 2010, the U.S. Department of Justice (DOJ), on behalf of the United States, filed a civil lawsuit in the U.S. District Court in New Orleans, Louisiana (Louisiana District Court) against several parties, including Anadarko Petroleum Corporation and Anadarko E&P Company LP (AE&P), a subsidiary of Anadarko, seeking an assessment of civil penalties under the Clean Water Act (CWA) in an amount to be determined by the Louisiana District Court. In February 2012, the Louisiana District Court entered a declaratory judgment that, as a partial owner of the Macondo well, Anadarko is liable for civil penalties under Section 311 of the CWA and denied both the Company’s and the United States’ motions for summary judgment with respect to the liability of AE&P. The declaratory judgment addresses liability only, and does not address the amount of any civil penalty. Also, in February 2012, the Louisiana District Court entered a stipulated order (Stipulated Order), agreed to by the Company and the United States, that the United States will not assert any claim for a CWA penalty against AE&P, and that the United States will not assert any other theories of liability under the CWA (e.g., operator or person-in-charge liability) against either Anadarko or AE&P. Further, the Stipulated Order reserved the issue of an assessment of a civil penalty against Anadarko until a later proceeding, to be scheduled by the Louisiana District Court. The Company believes that the Stipulated Order does not have a material impact on Anadarko’s potential liability. In August 2012, Anadarko filed a notice of appeal in the U.S. Court of Appeals for the Fifth Circuit concerning that portion of the February 2012 declaratory judgment finding Anadarko liable for civil penalties under the CWA.
As discussed below, numerous Deepwater Horizon event-related civil lawsuits have been filed against BP and other parties, including the Company. Certain state and local governments have appealed, or have provided indication of a likely appeal of, the Louisiana District Court’s decision that only federal law, and not state law, applies to Deepwater Horizon event-related claims. If such an appeal is successful, state and/or local laws and regulations could become sources of penalties or fines against the Company.
Index to Financial Statements ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010
17. Contingencies (Continued)
Applicable accounting guidance requires the Company to accrue a liability if it is probable that a liability is incurred and the amount of the liability can be reasonably estimated. The Louisiana District Court’s declaratory judgment in February 2012 satisfies the requirement that a loss, arising from the future assessment of a civil penalty against Anadarko, is probable. Notwithstanding the declaratory judgment, the Company currently cannot estimate the amount of any potential civil penalty. The CWA sets forth subjective criteria, including degree of fault and history of prior violations, which significantly influence the magnitude of CWA penalty assessments. As a result of the subjective nature of CWA penalty assessments, the Company currently cannot estimate the amount of any such penalty nor determine a range of potential loss. Furthermore, neither the February 2012 settlement of Deepwater Horizon-related civil penalties (including those under the CWA) by the other non-operating partner with the United States and five affected Gulf states (Texas, Louisiana, Mississippi, Alabama, and Florida) nor the January 2013 proposed settlement of CWA civil and criminal penalties by the drilling contractor with the United States affects the Company’s current conclusion regarding its ability to estimate potential fines and penalties. The Company lacks insight into those settlements, retains legal counsel separate from the other parties, and was not involved in any manner with respect to those settlements. Events or factors that could assist the Company in estimating the amount of any potential civil penalty or a range of potential loss related to such penalties include (i) an assessment by the DOJ, (ii) a ruling by a court of competent jurisdiction, or (iii) the initiation of substantive settlement negotiations between the Company and the DOJ.
Given the Company’s lack of direct operational involvement in the event, as confirmed by the Louisiana District Court, and the subjective criteria of the CWA, the Company believes that its exposure to CWA penalties will not materially impact the Company’s consolidated financial position, results of operations, or cash flows.
Natural Resource Damages This category includes future damage claims that may be made by federal and/or state natural resource trustee agencies at the completion of injury assessments and restoration planning. Natural resources generally include land, fish, water, air, wildlife, and other such resources belonging to, managed by, held in trust by, or otherwise controlled by, the federal, state, or local government.
The NRD-assessment process is led by government agencies that act as trustees of natural resources on behalf of the public. Government agencies involved in the process include the Department of Commerce, the Department of the Interior (DOI), and the Department of Defense. These governmental departments, along with the five affected states - Alabama, Florida, Louisiana, Mississippi, and Texas - are referred to as the “Co-Trustees.” The Co-Trustees continue to conduct injury assessment and restoration planning.
The DOJ civil lawsuit filed against BP, the Company, and others seeks unspecified damages for injury to federal natural resources. Not all of the Co-Trustees were a party to this lawsuit; however, during the second quarter of 2011, the states of Alabama and Louisiana each filed NRD-related state law claims against the Company in the Louisiana District Court. In November 2011, the Court dismissed all the NRD-related state law claims asserted against the Company by the states of Alabama and Louisiana.
NRD claims are generally sought after the damage assessment and restoration planning is completed, which may take several years. Thus, the Company remains unable to reasonably estimate the magnitude of any NRD claim. The Company anticipates that BP will satisfy any NRD claim, which eliminates any potential liability to Anadarko for such costs. In the event any NRD damage claim is made directly against Anadarko, the Company is fully indemnified by BP against such claims (including guarantees by BPCNA or BP p.l.c.).
Index to Financial Statements ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010
17. Contingencies (Continued)
Civil Litigation Damage Claims Numerous Deepwater Horizon event-related civil lawsuits have been filed against BP and other parties, including the Company by, among others, fishing, boating, and shrimping enterprises and industry groups; restaurants; commercial and residential property owners; certain rig workers or their families; the State of Alabama and several of its political subdivisions; the DOJ; environmental non-governmental organizations; the State of Louisiana and certain of its political subdivisions; and certain Mexican states. Many of the lawsuits filed assert various claims of negligence, gross negligence, and violations of several federal and state laws and regulations, including, among others, OPA; the Comprehensive Environmental Response, Compensation, and Liability Act; the Clean Air Act; the CWA; and the Endangered Species Act; or challenge existing permits for operations in the Gulf of Mexico. Generally, the plaintiffs are seeking actual damages, punitive damages, declaratory judgment, and/or injunctive relief.
This litigation has been consolidated into a federal Multidistrict Litigation (MDL) action pending before Judge Carl Barbier in the Louisiana District Court. In March 2012, BP and the Plaintiffs’ Steering Committee (PSC) entered into a tentative settlement agreement to resolve the substantial majority of economic loss and medical claims stemming from the Deepwater Horizon events, which the Louisiana District Court approved in orders issued in December 2012 and January 2013. Only OPA claims seeking economic loss damages against the Company remain. In addition, certain state and local governments have appealed, or have provided indication of a likely appeal of, the MDL court’s decision that only federal law, and not state law, applies to Deepwater Horizon event-related claims. The Company, pursuant to the Settlement Agreement, is fully indemnified by BP against losses arising as a result of claims for damages, irrespective of whether such claims are based on federal (including OPA) or state law.
The Louisiana District Court plans to hold a trial in Transocean’s Limitation of Liability case in the MDL commencing in 2013. In May 2012, the Louisiana District Court issued its revised case management order (CMO) ruling that the first phase of the trial will commence in February 2013 (Phase I). Phase I is expected to last for six to twelve weeks. BP, BP p.l.c., the United States, state and local governments, Halliburton, and Transocean will participate in Phase I of the trial. The CMO provides that the Stipulated Order excusing Anadarko from participation in Phase I of the trial remains in effect. The issues to be tried in Phase I include the cause of the blow-out and all related events leading up to April 22, 2010, the date the Deepwater Horizon sank, as well as allocation of fault. The allocation of fault remains in the Phase I trial because Halliburton and Transocean have not settled with any of the parties and wish to prove to the court that their respective company was not at fault. The second phase of trial is estimated to start in July 2013 (Phase II) and may take six to eight weeks to complete. The issues to be tried in Phase II will include spill-source control and quantification of the spill for the period from April 22, 2010, until the well was capped. The Company, BP, BP p.l.c., the United States, state and local governments, Halliburton, and Transocean will participate in Phase II of the trial.
Index to Financial Statements ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010
17. Contingencies (Continued)
Two separate class action complaints were filed in June and August 2010, in the U.S. District Court for the Southern District of New York (New York District Court) on behalf of purported purchasers of the Company’s stock between June 9, 2009, and June 12, 2010, against Anadarko and certain of its officers. The complaints allege causes of action arising pursuant to the Securities Exchange Act of 1934 (Exchange Act) for purported misstatements and omissions regarding, among other things, the Company’s liability related to the Deepwater Horizon events. In March 2012, the New York District Court granted the Lead Plaintiff’s motion to transfer venue to the U.S. District Court for the Southern District of Texas - Houston Division (Texas District Court). In May 2012, the Texas District Court granted the defendants’ motion to transfer the consolidated action within the district to Judge Keith P. Ellis. In July 2012, the plaintiffs filed their First Amended Consolidated Class Action Complaint. The defendants filed a renewed motion to dismiss in the Southern District Court of Texas in September 2012. The motion is fully briefed and is pending before the court.
In November 2011, the Company’s Board of Directors (Board) received a letter from a purported shareholder demanding that the Board investigate, address, remedy, and commence derivative proceedings against certain officers and directors for their alleged breach of fiduciary duty related to the Deepwater Horizon events. The Board has considered this demand and in February 2012 determined that it would not be in the best interest of the Company to pursue the issues alleged in the demand letter. In March 2012, the Company’s Board received a similar demand letter from a purported shareholder supplementing an original demand that had been made by the shareholder in September 2010 related to the Deepwater Horizon events. The Board has considered this demand and in April 2012 determined that it would not be in the best interest of the Company to pursue the issues alleged in the demand letter.
Given the various stages of these matters, the Company currently cannot assess the probability of losses, or reasonably estimate a range of any potential losses, related to ongoing proceedings. The Company intends to vigorously defend itself, its officers, and its directors in each of these matters, and will avail itself of any and all indemnities provided by BP against civil damages.
Remaining Liability Outlook It is reasonably possible that the Company may recognize additional Deepwater Horizon event-related liabilities for potential fines and penalties, shareholder claims, and certain other claims not covered by the indemnification provisions of the Settlement Agreement; however, the Company does not believe that any potential liability attributable to the foregoing items, individually or in the aggregate, will have a material impact on the Company’s consolidated financial position, results of operations, or cash flows. This assessment takes into account certain qualitative factors, including the subjective and fault-based nature of CWA penalties, the Company’s indemnification by BP against certain damage claims as discussed above, BP’s creditworthiness, the merits of the shareholder claims, and directors and officers insurance coverage related to outstanding shareholder claims.
The Company will continue to monitor the MDL and other legal proceedings discussed above as well as federal investigations related to the Deepwater Horizon events. The Company cannot predict the nature of evidence that may be discovered during the course of legal proceedings or the timing of completion of any legal proceedings.
Although the Company is fully indemnified by BP against OPA damage claims, NRD claims and assessment costs, and certain other potential liabilities, the Company may be required to recognize a liability for these amounts in advance of or in connection with recognizing a receivable from BP for the related indemnity payment. In all circumstances, however, the Company expects that any additional indemnified liability that may be recognized by the Company will be subsequently recovered from BP itself or through the guarantees of BPCNA or BP p.l.c.
Index to Financial Statements ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010
17. Contingencies (Continued)
Tronox Litigation In January 2009, Tronox Incorporated (Tronox), a former subsidiary of Kerr-McGee Corporation (Kerr-McGee), which is a current subsidiary of Anadarko, and certain of Tronox’s subsidiaries filed voluntary petitions for relief under Chapter 11 of the U.S. Bankruptcy Code (Bankruptcy) in the U.S. Bankruptcy Court for the Southern District of New York (Bankruptcy Court). Subsequently, in May 2009, Tronox and certain of its affiliates filed a lawsuit against Anadarko and Kerr-McGee asserting a number of claims, including claims for actual and constructive fraudulent conveyance (Adversary Proceeding). Tronox alleges, among other things, that it was insolvent or undercapitalized at the time it was spun off from Kerr-McGee and seeks, among other things, to recover damages, including interest, in excess of $18.9 billion from Kerr-McGee and Anadarko, as well as litigation fees and costs. In February 2011, in accordance with Chapter 11 of the Bankruptcy Code, Tronox emerged from bankruptcy pursuant to an August 2010 Bankruptcy Court approved Plan of Reorganization (Plan). The terms of the Plan, which were confirmed by the Bankruptcy Court in the third quarter of 2010, contemplate that the claims of the U.S. government (together with other federal, state, local, or tribal governmental entities having regulatory authority or responsibilities for environmental laws, the Governmental Entities) related to Tronox’s environmental liabilities will be settled through certain environmental response trusts and a litigation trust (Anadarko Litigation Trust). The Plan provides that the Governmental Entities will receive, among other things, 88% of the proceeds from the Adversary Proceeding. Additionally, certain creditors asserting tort claims against Tronox may receive, among other things, 12% of the proceeds from the Adversary Proceeding. In accordance with the Plan, the Adversary Proceeding was prosecuted by the Anadarko Litigation Trust. Pursuant to the Plan, the Anadarko Litigation Trust was “deemed substituted” for Tronox in the Adversary Proceeding as the party in such litigation. For purposes of this Form 10-K, references to “Tronox” after February 2011 refer to the Anadarko Litigation Trust. In May 2011, the Bankruptcy Court dismissed two claims against Anadarko for conspiracy and aiding and abetting. In January 2012, the Court granted partial summary judgment in favor of Tronox on the issue of whether damages in the Adversary Proceeding are limited to the amount of allowed creditor claims filed in the Bankruptcy. The Court held that Section of 550(a) of the Bankruptcy Code does not impose a cap on Tronox’s potential damages, but stated that the appropriate measure of damages should only be determined after trial.
The U.S. government was granted authority to intervene in the Adversary Proceeding, and in May 2009 asserted separate claims against Anadarko and Kerr-McGee under the Federal Debt Collection Procedures Act (FDCPA Complaint). Anadarko and Kerr-McGee moved to dismiss the claims of the U.S. government, but that motion has been stayed by the Bankruptcy Court. In April 2012, Anadarko and Kerr-McGee filed an answer to the FDCPA Complaint.
In February 2012, the Company filed a motion for partial summary judgment seeking dismissal of several claims, including all actual and constructive fraudulent transfer claims protected by Section 546(e) of the Bankruptcy Code. The court has not yet ruled on that issue. Trial began in May 2012 and in September 2012, the evidence closed and both sides rested. In November 2012, the parties filed post-trial briefs and closing arguments were presented in December 2012. The parties filed final post-trial briefs in January 2013. The matter is pending before the court.
In the first quarter of 2012, the Company believed it probable that the parties would reach a settlement on reasonable terms and thus the Company considered a loss, via settlement, related to the Adversary Proceeding probable. Based on this assumption, a $275 million loss contingency was accrued in the first quarter of 2012, which increased the Company’s total estimated contingent loss accrual related to the Adversary Proceeding to $525 million at March 31, 2012. The Company’s attempts during the second quarter of 2012 to resolve the Adversary Proceeding through mediation and settlement discussions reached an impasse, resulting in the Company’s assessment that the likelihood of settlement is remote and that litigation would be the probable form of final resolution of the Adversary Proceeding. Due to the change in the Company’s opinion as to the probable form of resolution of this matter, the Company reversed the settlement-based $525 million contingent loss accrual related to this matter in the second quarter of 2012.
Index to Financial Statements ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010
17. Contingencies (Continued)
The Company remains confident in the merits of its position, and will continue to vigorously defend the claims asserted in the Adversary Proceeding. The Company does not believe a loss resulting from litigating the Adversary Proceeding is probable. Accounting guidance requires that contingent losses be probable in nature for loss recognition to be appropriate. Accordingly, the Company’s Consolidated Balance Sheet at December 31, 2012, does not include a loss-contingency liability related to the litigation of the Adversary Proceeding.
Although the Company does not consider a loss related to the litigation of the Adversary Proceeding to be probable, it is reasonably possible that the Company could incur a loss as a result of litigating this matter. Despite the plaintiffs’ damage claims in excess of $18.9 billion, the Company currently believes a reasonable range of potential loss is zero to $1.4 billion. The low end of the Company’s estimated range of potential loss is based on the Company’s current belief that it will more likely than not prevail in defending against the claims asserted in the Adversary Proceeding. The high end of the Company’s estimated range of potential loss represents the amount of consideration received by Kerr-McGee at the time of the Tronox spin-off, approximately $985 million, plus interest thereon.
The Company’s estimated range of potential loss is based on the Company’s opinion regarding the current status of and likelihood of final resolution through litigation and could change as a result of developments in the Adversary Proceeding, or if the likelihood of settlement ceases to be remote. The Company’s ultimate financial obligation resulting from resolution of the Adversary Proceeding could vary, perhaps materially, from the Company’s above-stated estimated range of potential loss.
Separately, in July 2009, a consolidated class action complaint was filed in the New York District Court on behalf of purported purchasers of Tronox’s equity and debt securities between November 21, 2005, and January 12, 2009, against Anadarko, Kerr-McGee, several former Kerr-McGee officers and directors, several former Tronox officers and directors, and Ernst & Young LLP (Securities Case). The complaint alleges causes of action arising under Sections 10(b) and 20(a) of the Exchange Act for purported misstatements and omissions regarding, among other things, Tronox’s environmental-remediation and tort-claim liabilities. The plaintiffs allege, among other things, that these purported misstatements and omissions are contained in certain of Tronox’s public filings, including filings made in connection with Tronox’s initial public offering. The plaintiffs seek an unspecified amount of compensatory damages, including interest thereon, as well as litigation fees and costs. In April 2012, certain parties, including Anadarko, Kerr-McGee, and the former Kerr-McGee officers and directors, reached a settlement, which was approved by the court in November 2012. The settlement was directly funded by the insurers for Tronox, Anadarko, and Kerr-McGee.
Other Litigation In December 2008, Anadarko sold its interest in the Peregrino heavy-oil field offshore Brazil. The Company is currently litigating a dispute with the Brazilian tax authorities regarding the tax rate applicable to the transaction. Currently, $166 million, the amount of tax in dispute, resides in a judicially controlled Brazilian bank account, pending final resolution of the matter and is included in other assets on the Company’s Consolidated Balance Sheet at December 31, 2012.
In July 2009, the lower judicial court ruled in favor of the Brazilian tax authorities. The Company appealed this decision to the Brazilian Regional courts, which upheld the lower court’s ruling in favor of the Brazilian tax authorities in December 2011. In April 2012, the Company filed simultaneous appeals to the Brazilian Superior Court and the Brazilian Supreme Court. The Brazilian Superior Court and the Brazilian Supreme Court have agreed to hear the case and the Company currently is awaiting the setting of initial hearing dates.
The Company believes that it will more likely than not prevail in Brazilian courts. Therefore, no tax liability has been recorded for Peregrino divestiture-related litigation at December 31, 2012. The Company continues to vigorously defend itself in Brazilian courts.
Index to Financial Statements ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010
17. Contingencies (Continued)
Deepwater Drilling Moratorium and Other Related Matters In June 2010, as a result of the moratorium on drilling in the Gulf of Mexico between mid-May 2010 and mid-October 2010 (Moratorium), the Company gave written notice of termination to a drilling contractor of a rig placed in force majeure in May 2010, and filed a lawsuit in the Texas District Court against the drilling contractor seeking a judicial declaration that the Company’s interpretation of the drilling contract was correct and that the contract terminated on June 19, 2010. The drilling contractor filed an Original Answer in July 2010 denying the Moratorium constituted a force majeure event and asserting that Anadarko had breached the drilling contract. In the second quarter of 2012, the Company and the drilling contractor mutually agreed to dismiss all claims related to this dispute. The resolution of this dispute did not have a material impact on Anadarko’s consolidated financial position, results of operations, or cash flows.
Algeria Exceptional Profits Tax Settlement In 2006, the Algerian parliament approved legislation establishing an exceptional profits tax on foreign companies’ Algerian oil production and issued regulations implementing this legislation. The Company disagreed with Sonatrach’s collection of the exceptional profits tax and initiated arbitration against Sonatrach in 2009. In March 2012, the Company and Sonatrach resolved this dispute. The resolution provided for delivery to the Company of crude oil valued at approximately $1.7 billion and the elimination of $62 million of the Company’s previously recorded and unpaid transportation charges. The crude oil is to be delivered to the Company over a 12-month period that began in June 2012. At December 31, 2012, a receivable of $730 million was included on the Company’s Consolidated Balance Sheet and is in the oil and gas exploration and production reporting segment. The Company recognized a $1.8 billion credit in the Costs and Expenses section of the Consolidated Statement of Income for the year ended December 31, 2012, to reflect the effect of this agreement for previously recorded expenses. Additionally, the parties amended the existing Production Sharing Agreement (PSA) to increase the Company’s sales volumes and to lower the effective exceptional profits tax rate. The amendment confirmed the length of each exploitation license to be 25 years from the date the license was granted under the PSA with expiration dates ranging from December 2022 to December 2036.
Guarantees and Indemnifications Under the terms of the MSA entered into between Kerr-McGee and Tronox, Kerr-McGee agreed to reimburse Tronox for 50% of certain qualifying environmental-remediation costs incurred and paid by Tronox and its subsidiaries, subject to certain limitations and conditions. The reimbursement obligation under the MSA was limited to a maximum aggregate reimbursement of $100 million. During 2010, the Company reversed to non-operating income a $95 million liability recorded for this reimbursement obligation as a result of a court-authorized rejection of the MSA. See Tronox Litigation section of this note.
The Company also provides certain indemnifications in relation to asset dispositions. These indemnifications typically relate to disputes, litigation, or tax matters existing at the date of disposition. No material liabilities were recorded for any such indemnifications at December 31, 2012.
18. Other Taxes
Taxes incurred, other than income taxes, were as follows:
Index to Financial Statements ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010
19. Income Taxes
Components of income tax expense (benefit) were as follows:
Total income taxes differed from the amounts computed by applying the U.S. federal statutory income tax rate to income (loss) before income taxes. The sources of these differences were as follows:
Index to Financial Statements ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010
19. Income Taxes (Continued)
Components of total deferred taxes were as follows:
The tax effects of temporary differences that give rise to significant portions of the deferred tax assets (liabilities) were as follows:
Changes to valuation allowances, due to changes in judgment regarding the future realizability of deferred tax assets, were an increase of $23 million for 2012 and a decrease of $17 million for 2011. The following summarizes changes in the balance of valuation allowances on deferred tax assets:
Index to Financial Statements ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010
19. Income Taxes (Continued)
Taxes receivable (payable) related to income tax expense (benefit) were as follows:
Tax carryforwards available for use on future income tax returns at December 31, 2012, were as follows:
Changes in the balance of unrecognized tax benefits excluding interest and penalties on uncertain tax positions were as follows:
Included in the 2012 ending balance of unrecognized tax benefits presented above are potential benefits of $(40) million that would affect the effective tax rate on income if recognized. Also included in the 2012 ending balance are benefits of $(6) 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 $(5) million to $(29) million of unrecognized tax benefits related to adjustments to taxable income and credits previously recorded pursuant to the accounting standard for accounting for tax uncertainties will reverse within the next 12 months due to expiration of statutes of limitation and audit settlements.
The Company had approximately $28 million of accrued interest related to uncertain tax positions at December 31, 2012, and $18 million at December 31, 2011. The Company recognized interest and penalties in income tax expense (benefit) of $9 million during 2012 and $(8) million during 2011.
Index to Financial Statements ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010
19. Income Taxes (Continued)
Anadarko is subject to audit by tax authorities in the U.S. federal, state, and local tax jurisdictions as well as in various foreign jurisdictions. The Company is currently under routine examination by the U.S. Internal Revenue Service for the tax years 2007, 2008, 2010, 2011, and 2012.
Income tax audits and the Company’s acquisition and divestiture activity have given rise to tax disputes in U.S. and foreign jurisdictions. See Note 17-Contingencies-Other Litigation. Management does not believe that the final resolution of outstanding tax audits and litigation will have a material adverse effect on the Company’s consolidated financial position, results of operations, or cash flows.
The following lists the tax years subject to examination by major tax jurisdiction:
20. Supplemental Cash Flow Information
The following summarizes cash paid (received) for interest (net of amounts capitalized) and income taxes, as well as non-cash investing and financing transactions:
21. Segment Information
Anadarko’s business segments are separately managed due to distinct operational differences and unique technology, distribution, and marketing requirements. The Company’s three reporting segments are oil and gas exploration and production, midstream, and marketing. The oil and gas 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, natural-gas, and NGLs production. The midstream reporting segment consists of two operating segments, WES and other midstream activities, which are aggregated into one reporting segment due to similar financial and operating characteristics. The marketing segment sells much of Anadarko’s production, as well as third-party purchased volumes.
Index to Financial Statements ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010
21. Segment Information (Continued)
To assess the performance of Anadarko’s operating segments, the chief operating decision maker analyzes Adjusted EBITDAX. The Company defines Adjusted EBITDAX as income (loss) before income taxes; interest expense; exploration expense; depreciation, depletion, and amortization (DD&A); impairments; Deepwater Horizon settlement and related costs; Algeria exceptional profits tax settlement; Tronox-related contingent loss; unrealized (gains) losses on derivatives, net; and realized (gains) losses on other derivatives, net, less net income attributable to noncontrolling interests. The Company’s definition of Adjusted EBITDAX excludes interest expense to allow for assessment of segment operating results without regard to Anadarko’s financing methods or capital structure. Adjusted EBITDAX also excludes exploration expense, as it 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 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. Anadarko’s definition of Adjusted EBITDAX excludes Deepwater Horizon settlement and related costs, Algeria exceptional profits tax settlement, and Tronox-related contingent loss, as these costs are outside the normal operations of the Company. See Note 17-Contingencies. Finally, unrealized (gains) losses on derivatives, net and realized (gains) losses on other derivatives, net are excluded from Adjusted EBITDAX because these (gains) losses are not considered a measure of asset operating performance. Management believes that the presentation of Adjusted EBITDAX provides information useful in assessing the Company’s financial condition and results of operations and that Adjusted EBITDAX is a widely accepted financial indicator of a company’s ability to incur and service debt, fund capital expenditures, and make distributions to stockholders.
Adjusted EBITDAX, as defined by Anadarko, may not be comparable to similarly titled measures used by other companies and should be considered in conjunction with net income (loss) attributable to common stockholders and other performance measures, such as operating income or cash flows from operating activities. Below is a reconciliation of consolidated Adjusted EBITDAX to income (loss) before income taxes:
(1) In the first quarter of 2012, the Company revised the definition of Adjusted EBITDAX to exclude Algeria exceptional profits tax settlement, Tronox-related contingent loss, and realized (gains) losses on other derivatives, net. Prior periods have been adjusted to reflect this change.
Index to Financial Statements ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010
21. Segment Information (Continued)
The Company’s accounting policies for individual segments are the same as those described in the summary of significant accounting policies, with the following exception: certain intersegment commodity contracts may meet the U.S. Generally Accepted Accounting Principles (GAAP) definition of a derivative instrument, which would be accounted for at fair value under GAAP. However, Anadarko does not recognize any mark-to-market adjustments on such intersegment arrangements. Additionally, intersegment asset transfers are accounted for at historical cost basis, and do not give rise to gain or loss recognition.
Information presented below as “Other and Intersegment Eliminations” includes results from hard-minerals non-operated joint ventures and royalty arrangements; and corporate, financing, and certain hedging activities. The following summarizes selected financial information for Anadarko’s reporting segments:
Index to Financial Statements ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010
21. Segment Information (Continued)
(1) Operating costs and expenses exclude exploration expense, DD&A, impairments, Deepwater Horizon settlement and related costs, and Algeria exceptional profits tax settlement since these expenses are excluded from Adjusted EBITDAX.
(2) Other (income) expense, net excludes Tronox-related contingent loss since this expense is excluded from Adjusted EBITDAX.
In 2012, sales to Total SA were $1.9 billion, including $532 million that was reported as a reduction to the Algeria exceptional profits tax settlement included on the Company’s Consolidated Balance Sheet. These amounts are included in the oil and gas exploration and production reporting segment. In 2011 and 2010, there were no sales to individual customers that exceeded 10% of the Company’s total sales revenues.
Index to Financial Statements ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010
21. Segment Information (Continued)
The following represents Anadarko’s sales revenues (based on the origin of the sales) and net properties and equipment by geographic area:
22. Pension Plans, Other Postretirement Benefits, and Defined-Contribution Plans
The Company has contributory and non-contributory defined-benefit pension plans, which include both qualified and supplemental plans. The Company also provides certain health care and life insurance benefits for certain retired employees. Retiree health care benefits are funded by contributions from the retiree, and in certain circumstances, contributions from the Company. The Company’s retiree life insurance plan is non-contributory.
In 2012, the Company made contributions of $101 million to its funded pension plans, $6 million to its unfunded pension plans, and $19 million to its unfunded other postretirement benefit plans. While reported benefit obligations exceed the fair value of pension and other postretirement plan assets at December 31, 2012, the Company monitors the funded status of its funded pension plans to ensure that plan funds are sufficient to continue paying benefits. Contributions to funded plans increase plan assets while contributions to unfunded plans are used to fund current benefit payments. The Company expects to contribute approximately $81 million to its funded pension plans, approximately $45 million to its unfunded pension plans, and approximately $16 million to its unfunded other postretirement benefit plans in 2013.
Index to Financial Statements ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010
22. Pension Plans, Other Postretirement Benefits, and Defined-Contribution Plans (Continued)
The following sets forth changes in the benefit obligations and fair value of plan assets for the Company’s pension and other postretirement benefit plans for the years ended December 31, 2012 and 2011, as well as the funded status of the plans and amounts recognized in the financial statements at December 31, 2012 and 2011:
(1) The accumulated benefit obligation for all defined-benefit pension plans was $2.1 billion at December 31, 2012, and $1.9 billion at December 31, 2011.
Index to Financial Statements ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010
22. Pension Plans, Other Postretirement Benefits, and Defined-Contribution Plans (Continued)
The following summarizes the Company’s defined-benefit pension plans with accumulated benefit obligations in excess of plan assets for the years ended December 31:
The following summarizes the Company’s pension and other postretirement benefit cost and amounts recognized in other comprehensive income (before tax benefit) for the years ended December 31:
In 2013, an estimated $116 million of net actuarial loss and $1 million of net prior service cost for the pension and other postretirement plans will be amortized from accumulated other comprehensive income into net periodic benefit cost.
Index to Financial Statements ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010
22. Pension Plans, Other Postretirement Benefits, and Defined-Contribution Plans (Continued)
The following summarizes the weighted-average assumptions used by the Company in determining the pension and other postretirement benefit obligations at December 31:
Accumulated and projected benefit obligations are measured as the present value of future cash payments. The Company discounts those cash payments using a discount rate that reflects the weighted average of market-observed yields for select high-quality (AA-rated) fixed-income securities with cash flows that correspond to the expected amounts and timing of benefit payments. Discount-rate selection for measurements prior to December 31, 2011, was based on a similar cash-flow-matching analysis, although, instead of using a portfolio of select high-quality fixed-income securities to determine the effective settlement rate for a given plan obligation, the Company relied primarily on a published yield curve derived from market-observed yields for a universe of high-quality bonds. Both methods are acceptable and result in a discount-rate assumption that represents an estimate of the interest rate at which the pension and other postretirement benefit obligations could effectively be settled on the measurement date. However, the Company believes a discount rate reflecting yields for high-quality fixed-income securities better corresponds to the Company’s expectations as to the amount and timing of its benefit payments. Assumed rates of compensation increases for active participants vary by age group, with the resulting weighted-average assumed rate (weighted by the plan-level benefit obligation) provided in the preceding table.
The following summarizes the weighted-average assumptions used by the Company in determining the net periodic pension and other postretirement benefit cost:
At December 31, 2012, an 8.00% annual rate of increase in the per-capita cost of covered health care benefits for 2013 was assumed for purposes of measuring other postretirement benefit obligations. At December 31, 2011, a 9.00% annual rate of increase in the per-capita cost of covered health care benefits for 2012 was assumed for purposes of measuring other postretirement benefit obligations. This rate is expected to gradually decrease to 5.00% in 2018 and beyond. The assumed health care cost trend rate can have 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:
Index to Financial Statements ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010
22. Pension Plans, Other Postretirement Benefits, and Defined-Contribution Plans (Continued)
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-capitalization equity securities, international equity securities, fixed-income securities, 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 funds under their management to the extent permitted within investment guidelines.
Although investment managers may, at their discretion and within investment guidelines, invest in Anadarko securities, there are no direct investments in Anadarko securities included in plan assets. There may be, however, indirect investments in Anadarko securities through the plans’ collective fund investments. The expected long-term rate of return on plan assets assumption was determined using the year-end 2012 pension investment balances by asset class and expected long-term asset allocation. The expected return for each asset class reflects capital-market projections formulated using a forward-looking building-block approach, while also taking into account historical return trends and current market conditions. Equity returns generally reflect long-term expectations of real earnings growth, dividend yield, and inflation. Returns on fixed-income securities are generally developed based on expected inflation, real bond yield, and risk spread (as appropriate), adjusted for the expected effect that changing yields have on the rate of return. Other asset-class returns are derived from their relationship to the equity and fixed-income markets.
Index to Financial Statements ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010
22. Pension Plans, Other Postretirement Benefits, and Defined-Contribution Plans (Continued)
The fair value of the Company’s pension plan assets by asset category and input level within the fair-value hierarchy were as follows:
(1) Amounts include investments in diversified fixed-income collective investment funds with exposure to mortgage-backed securities, government-issued securities, corporate debt, and other fixed-income securities.
(2) Amount excludes net receivables of $4 million, primarily related to Level 1 investments.
(3) Amount excludes net payables of $1 million, primarily related to Level 1 investments.
Index to Financial Statements ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010
22. Pension Plans, Other Postretirement Benefits, and Defined-Contribution Plans (Continued)
Investments in securities traded in active markets are measured based on quoted prices, which represent Level 1 inputs. Investments based on Level 2 inputs include direct investments in corporate debt and other fixed-income securities, as well as shares of open-end mutual funds or similar investment vehicles that do not have a readily determinable fair value, but are valued at the net asset value per share (NAV). For such funds, the NAV is the value at which investors transact with the fund, and is determined by the fund based on the estimated fair values of the underlying fund assets. Fair value of investments included as Level 3 inputs generally also reflect investments valued at fund NAVs, but, unlike investments characteristic of Level 2 fair-value measurements, such plan assets have significant liquidity restrictions or other features that are not reflected in NAV.
The following summarizes changes in the fair value of investments based on Level 3 inputs:
Risks and Uncertainties The plan assets include various investment securities that are exposed to various risks, such as interest-rate, credit, and market risks. Due to the level of risk associated with certain investment securities, it is reasonably possible that changes in the values of investment securities could significantly impact the plan assets.
The plan assets may include securities with contractual cash flows, such as asset-backed securities, collateralized mortgage obligations, and commercial mortgage-backed securities, including securities backed by subprime mortgage loans. The value, liquidity, and related income of those securities are sensitive to changes in economic conditions, including real estate value, delinquencies, or defaults, or both, and may be adversely affected by shifts in the market’s perception of the issuers and changes in interest rates.
Index to Financial Statements ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010
22. Pension Plans, Other Postretirement Benefits, and Defined-Contribution Plans (Continued)
Expected Benefit Payments
The following summarizes estimated benefit payments for the next ten years, including benefit increases due to continuing employee service:
Defined-Contribution Plans The Company maintains several defined-contribution benefit plans, including the Anadarko Employee Savings Plan (ESP). All regular employees of the Company on its U.S. payroll are eligible to participate in the ESP by making elective contributions that are matched by the Company, subject to certain limitations. The Company recognized expense of $55 million for 2012, $41 million for 2011, and $40 million for 2010, related to these plans.
Index to Financial Statements ANADARKO PETROLEUM CORPORATION
SUPPLEMENTAL QUARTERLY INFORMATION
(Unaudited)
Quarterly Financial Data
The following summarizes quarterly financial data for 2012 and 2011:
Index to Financial Statements ANADARKO PETROLEUM CORPORATION
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION
AND PRODUCTION ACTIVITIES
(Unaudited)
The unaudited supplemental information on oil and gas exploration and production activities for 2012, 2011, and 2010 has been presented in accordance with Financial Accounting Standards Board Accounting Standards Codification Topic 932, Extractive Activities-Oil and Gas and the Securities and Exchange Commission’s final rule, Modernization of Oil and Gas Reporting. Disclosures by geographic area include the United States and International. The International geographic area consists of proved reserves located in Algeria, Ghana, and China.
Oil and Gas Reserves
The following reserves disclosures reflect estimates of proved reserves, proved developed reserves, and proved undeveloped reserves, net of third-party royalty interests, of natural gas, oil, condensate, and NGLs owned at each year end and changes in proved reserves during each of the last three years. Natural-gas volumes are presented in billion cubic feet (Bcf) at a pressure base of 14.73 pounds per square inch and volumes for oil, condensate, and NGLs are presented in millions of barrels (MMBbls). 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 natural gas. Shrinkage associated with NGLs has been deducted from the natural-gas reserves volumes.
Reserves for international locations are calculated in accordance with the terms of governing agreements. The international reserves include estimated quantities allocated to Anadarko for recovery of costs and income taxes and Anadarko’s net equity share after recovery of such costs.
The Company’s estimates of proved reserves are 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. The results of infill drilling are treated as positive revisions due to increases to expected recovery. Other revisions are due to changes in, among other things, development plans, reservoir performance, prices, economic conditions, and governmental restrictions.
In 2012, Anadarko added 82 MMBOE of proved reserves through extensions and discoveries as the result of successful drilling in the United States. Reserves revisions for 2012 include an increase of 352 MMBOE primarily related to successful infill drilling in the large onshore areas, such as the Greater Natural Buttes, Wattenberg, and Carthage, and a decrease of 68 MMBOE associated with lower commodity prices. Sales of proved reserves in place were 81 MMBOE, related to domestic assets.
In 2011, Anadarko added 174 MMBOE of proved reserves primarily as the result of successful drilling in the United States. Reserves revisions for 2011 include an increase of 210 MMBOE primarily related to successful infill drilling in the large onshore areas, such as the Greater Natural Buttes, Wattenberg, and Pinedale fields, and an increase of 8 MMBOE driven by higher oil prices. Sales of proved reserves in place were 29 MMBOE, related to onshore domestic assets.
In 2010, Anadarko added 83 MMBOE of proved reserves primarily as the result of successful drilling in the United States. Reserves revisions for 2010 include an increase of 246 MMBOE primarily related to successful infill drilling in the large onshore natural-gas plays, such as the Greater Natural Buttes, Wattenberg, and Pinedale fields, and an increase of 29 MMBOE driven by higher oil and gas prices. Sales of proved reserves in place were 6 MMBOE, related to onshore domestic and international assets.
Prices used to compute the information presented in the tables below are adjusted only for fixed and determinable amounts under provisions in existing contracts. These prices, before adjustments, were $2.76, $4.12, and $4.38 per MMBtu of natural gas and $94.71, $96.19, and $79.43 per barrel of oil for 2012, 2011, and 2010.
Index to Financial Statements ANADARKO PETROLEUM CORPORATION
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION
AND PRODUCTION ACTIVITIES
(Unaudited)
Oil and Gas Reserves (Continued)
Index to Financial Statements ANADARKO PETROLEUM CORPORATION
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION
AND PRODUCTION ACTIVITIES
(Unaudited)
Oil and Gas Reserves (Continued)
(1) Revisions of prior estimates include additions generated by Anadarko’s infill drilling programs of 383 MMBOE for 2012, 203 MMBOE for 2011, and 312 MMBOE for 2010.
Index to Financial Statements 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 natural-gas producing activities. Capitalized costs for proved properties include costs for oil and natural-gas leaseholds where proved reserves have been identified, development wells, and related equipment and facilities, including development wells in progress. Capitalized costs for unproved properties include costs for acquiring oil and gas leaseholds where no proved reserves have been identified, including costs of exploratory wells that are in the process of drilling or in active completion, and costs of exploratory wells suspended or waiting on completion. Capitalized costs associated with activities of the Company’s midstream and marketing reporting segments, and other corporate activities are not included.
Index to Financial Statements 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 when incurred 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 presented below include the costs of drilling and equipping successful and unsuccessful exploration wells during the year, geological and geophysical expenses, and the costs of retaining undeveloped leaseholds. Development costs include the costs of drilling and equipping development wells, and construction of related production facilities. Costs associated with activities of the Company’s midstream and marketing reporting segments, and other corporate activities are not included.
Index to Financial Statements ANADARKO PETROLEUM CORPORATION
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION
AND PRODUCTION ACTIVITIES
(Unaudited)
Results of Operations
Results of operations for producing activities consist of all activities within the oil and gas exploration and production reporting segment. Net revenues from production include only the revenues from the production and sale of natural gas, oil, condensate, and NGLs. Gains (losses) on property dispositions represent net gains or losses on sales of oil and gas properties. 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 unproved leaseholds. Algeria exceptional profits tax settlement represents the Company’s resolution of the Algeria exceptional profits tax dispute with Sonatrach, which provides for delivery to the Company of crude oil valued at approximately $1.7 billion and the elimination of $62 million of the Company’s previously recorded and unpaid transportation charges. Deepwater Horizon settlement and related costs represents the Company’s $4.0 billion settlement with BP, and associated legal and other costs, net of related insurance recoveries. Income tax expense is calculated by applying the current statutory tax rates to the revenues after deducting costs, which include depreciation, depletion, and amortization allowances, after giving effect to permanent differences. The results of operations exclude general office overhead and interest expense attributable to oil and gas activities.
Index to Financial Statements ANADARKO PETROLEUM CORPORATION
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION
AND PRODUCTION ACTIVITIES
(Unaudited)
Results of Operations (Continued)
Index to Financial Statements ANADARKO PETROLEUM CORPORATION
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION
AND PRODUCTION ACTIVITIES
(Unaudited)
Standardized Measure of Discounted Future Net Cash Flows
Estimates of future net cash flows from proved reserves of natural gas, oil, condensate, and NGLs for 2012, 2011, and 2010 are computed using the average first-day-of-the-month price during the 12-month period for the respective year. Prices used to compute the information presented in the tables below are adjusted only for fixed and determinable amounts under provisions in existing contracts. These prices, before adjustments, were $2.76, $4.12, and $4.38 per MMBtu of natural gas and $94.71, $96.19, and $79.43 per barrel of oil, for 2012, 2011, and 2010. Estimated future net cash flows for all periods presented are reduced by estimated future development, production, and 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% discount factor is prescribed by U.S. Generally Accepted Accounting Principles.
The present value of future net cash flows is not an estimate of the fair value of Anadarko’s proved reserves. An estimate of fair value would also take into account, among other things, anticipated changes in future prices and costs, the expected recovery of reserves in excess of proved reserves, and a discount factor more representative of the time value of money and the risks inherent in producing oil and natural gas. Significant changes in estimated reserves volumes or commodity prices could have a material effect on the Company’s Consolidated Financial Statements.
Index to Financial Statements 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
Index to Financial Statements 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
Index to Financial Statements 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 (Continued)
Index to Financial Statements

---

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.

---

ITEM 9A. CONTROLS AND PROCEDURES
Item 9A. Controls and Procedures
EVALUATION AND DISCLOSURE CONTROLS AND PROCEDURES
Anadarko’s Chief Executive Officer and Chief Financial Officer performed an evaluation of the Company’s disclosure controls and procedures as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934. The Company’s disclosure controls and procedures are designed to ensure that information required to be disclosed by the Company in reports it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized, and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission, and to ensure that the information required to be disclosed by us in reports that we file under the Securities Exchange Act of 1934 is accumulated and communicated to the Company’s management, including the principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure. Based on this evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that the Company’s disclosure controls and procedures are effective as of December 31, 2012.
MANAGEMENT’S ANNUAL REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
See Management’s Assessment of Internal Control Over Financial Reporting under Item 8 of this Form 10-K.
ATTESTATION REPORT OF THE REGISTERED PUBLIC ACCOUNTING FIRM
See Report of Independent Registered Public Accounting Firm under Item 8 of this Form 10-K.
CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING
There were no changes in Anadarko’s internal control over financial reporting during the fourth quarter of 2012 that materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

---

ITEM 9B. OTHER INFORMATION
Item 9B. Other Information
None.
Index to Financial Statements PART III

---

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS
Item 10. Directors, Executive Officers, and Corporate Governance
See Anadarko Board of Directors, Corporate Governance-Board of Directors, Corporate Governance-Committees of the Board and Section 16(a) Beneficial Ownership Reporting Compliance in the Anadarko Petroleum Corporation Proxy Statement (Proxy Statement), for the Annual Meeting of Stockholders of Anadarko Petroleum Corporation to be held May 14, 2013 (to be filed with the Securities and Exchange Commission prior to April 4, 2013), each of which is incorporated herein by reference.
See list of Executive Officers of the Registrant under Items 1 and 2 of this Form 10-K, which is incorporated herein by reference.
The Company’s Code of Business Conduct and Ethics and the Code of Ethics for the Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer (Code of Ethics) can be found on the Company’s website located at www.anadarko.com/About/Pages/Governance.aspx. Any stockholder may request a printed copy of the Code of Ethics by submitting a written request to the Company’s Corporate Secretary. If the Company amends the Code of Ethics or grants a waiver, including an implicit waiver, from the Code of Ethics, the Company will disclose the information on its website. The waiver information will remain on the website for at least 12 months after the initial disclosure of such waiver.

---

ITEM 11. EXECUTIVE COMPENSATION
Item 11. Executive Compensation
See Corporate Governance-Board of Directors-Compensation and Benefits Committee Interlocks and Insider Participation, Corporate Governance-Board of Directors-Director Compensation, Corporate Governance-Director Compensation Table for 2012, Compensation and Benefits Committee Report on 2012 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
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.
See Securities Authorized for Issuance under Equity Compensation Plans under Item 5 of this Form 10-K, which is incorporated herein by reference.

---

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
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 ACCOUNTANT FEES AND SERVICES
Item 14. Principal Accountant Fees and Services
See Independent Auditor in the Proxy Statement, which is incorporated herein by reference.
Index to Financial Statements PART IV

---

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
Item 15. Exhibits, Financial Statement Schedules
a) EXHIBITS
The following documents are filed as 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 88.
(2) Exhibits not incorporated by reference to a prior filing are designated by an asterisk (*) and are filed herewith; all exhibits not so designated are incorporated herein by reference to a prior filing as indicated.
Exhibit
Number
Description
Original Filed
Exhibit
File
Number
2(i)
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 filed on 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 filed on May 22, 2009
1-8968
(ii)
By-Laws of Anadarko Petroleum Corporation, amended and restated as of May 15, 2012
3.1 to Form 8-K filed on May 15, 2012
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 filed on 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 filed on October 6, 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 filed on October 6, 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 filed on March 6, 2009
1-8968
(v)
Form of 7.625% Senior Notes due 2014
4.2 to Form 8-K filed on March 6, 2009
1-8968
(vi)
Form of 8.700% Senior Notes due 2019
4.3 to Form 8-K filed on March 6, 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 filed on June 12, 2009
1-8968
Index to Financial Statements
Exhibit
Number
Description
Original Filed
Exhibit
File
Number
4(viii)
Form of 5.75% Senior Notes due 2014
4.2 to Form 8-K filed on June 12, 2009
1-8968
(ix)
Form of 6.95% Senior Notes due 2019
4.3 to Form 8-K filed on June 12, 2009
1-8968
(x)
Form of 7.95% Senior Notes due 2039
4.4 to Form 8-K filed on June 12, 2009
1-8968
(xi)
Officers’ Certificate of Anadarko Petroleum Corporation dated March 9, 2010, establishing the 6.200% Senior Notes due 2040
4.1 to Form 8-K filed on March 16, 2010
1-8968
(xii)
Form of 6.200% Senior Notes due 2040
4.2 to Form 8-K filed on March 16, 2010
1-8968
(xiii)
Officers’ Certificate of Anadarko Petroleum Corporation dated August 9, 2010, establishing the 6.375% Senior Notes due 2017
4.1 to Form 8-K filed on August 12, 2010
1-8968
(xiv)
Form of 6.375% Senior Notes due 2017
4.2 to Form 8-K filed on August 12, 2010
1-8968
 10(i)
1998 Director Stock Plan of Anadarko Petroleum Corporation, effective January 30, 1998
Appendix A to DEF 14A filed on March 16, 1998
1-8968
 (ii)
Form of Anadarko Petroleum Corporation 1998 Director Stock Plan Stock Option Agreement
10.1 to Form 8-K filed on November 17, 2005
1-8968
 (iii)
Anadarko Petroleum Corporation Amended and Restated 1999 Stock Incentive Plan
Appendix A to DEF 14A filed on 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 filed on 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 filed on November 17, 2005
1-8968
 (vi)
Form of Stock Option Agreement-1999 Stock Incentive Plan (UK Nationals)
10.4 to Form 8-K filed on 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 filed on January 23, 2007
1-8968
 (viii)
Anadarko Petroleum Corporation 1999 Stock Incentive Plan (Amendment to Performance Unit Agreement)
10.3 to Form 8-K filed on November 13, 2007
1-8968
Index to Financial Statements
Exhibit
Number
Description
Original Filed
Exhibit
File
Number
 10(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, filed on March 16, 2000
1-8968
 (x)
Form of Anadarko Petroleum Corporation 1999 Stock Incentive Plan Restricted Stock Unit Award Letter
10.1 to Form 8-K filed on November 13, 2007
1-8968
 (xi)
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, filed on March 4, 2004
1-8968
 (xii)
Key Employee Change of Control Contract
10(b)(xxii) to Form 10-K for year ended December 31, 1997, filed on March 18, 1998
1-8968
 (xiii)
First Amendment to Anadarko Petroleum Corporation Key Employee Change of Control Contract
10(b) to Form 10-Q for quarter ended September 30, 2000, filed on November 13, 2000
1-8968
 (xiv)
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, filed on August 11, 2003
1-8968
 (xv)
Form of Key Employee Change of Control Contract (2011)
10(i) to Form 10-Q for quarter ended June 30, 2011, filed on July 27, 2011
1-8968
 (xvi)
Letter Agreement regarding Post-Retirement Benefits, dated February 16, 2004-Robert J. Allison, Jr.
10(b)(xxxiv) to Form 10-K for year ended December 31, 2003, filed on March 4, 2004
1-8968
 (xvii)
Anadarko Petroleum Corporation Savings Restoration Plan (As Amended and Restated Effective January 1, 2007)
10(xxii) to Form 10-K for year ended December 31, 2009, filed on February 23, 2010
1-8968
 (xviii)
Anadarko Retirement Restoration Plan (As Amended and Restated Effective as of November 7, 2007)
10.2 to Form 8-K filed on November 13, 2007
1-8968
Index to Financial Statements
Exhibit
Number
Description
Original Filed
Exhibit
File
Number
 10(xix)
Anadarko Petroleum Corporation Estate Enhancement Program
10(b)(xxxiv) to Form 10-K for year ended December 31, 1998, filed on March 15, 1999
1-8968
 (xx)
Estate Enhancement Program Agreement between Anadarko Petroleum Corporation and Eligible Executives
10(b)(xxxv) to Form 10-K for year ended December 31, 1998, filed on March 15, 1999
1-8968
 (xxi)
Estate Enhancement Program Agreements effective November 29, 2000
10(b)(xxxxii) to Form 10-K for year ended December 31, 2000, filed on March 15, 2001
1-8968
 (xxii)
Anadarko Petroleum Corporation Management Life Insurance Plan, restated November 1, 2002
10(b)(xxxii) to Form 10-K for year ended December 31, 2002, filed on
March 14, 2003
1-8968
 (xxiii)
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, filed on
March 4, 2004
1-8968
 (xxiv)
Second Amendment to Anadarko Petroleum Corporation Management Life Insurance Plan, effective January 1, 2008
10(xxix) to Form 10-K for year ended December 31, 2009, filed on February 23, 2010
1-8968
 (xxv)
Anadarko Petroleum Corporation Officer Severance Plan
10(b)(iv) to Form 10-Q for quarter ended September 30, 2003, filed on November 12, 2003
1-8968
 (xxvi)
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, filed on November 12, 2003
1-8968
 (xxvii)
Form of Director and Officer Indemnification Agreement
10 to Form 8-K filed on September 3, 2004
1-8968
Index to Financial Statements
Exhibit
Number
Description
Original Filed
Exhibit
File
Number
10(xxviii)
$5,000,000,000 Revolving Credit Agreement, dated as of September 2, 2010, among Anadarko Petroleum Corporation, as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent, Bank of America, N.A., DnB NorBank ASA, The Royal Bank of Scotland plc, Société Général, and Wells Fargo Bank, N.A., as Syndication Agents, and the several lenders named therein.
10.1 to Form 8-K filed on September 8, 2010
1-8968
(xxix)
First Amendment to Revolving Credit Agreement, dated as of August 3, 2011, to the Revolving Credit Agreement dated as of September 2, 2010, among Anadarko Petroleum Corporation, as Borrower, JPMorgan Chase Bank, N.A. as Administrative Agent, Bank of America, N.A., DnB Nor Bank ASA, The Royal Bank of Scotland plc, Société Générale, and Wells Fargo Bank, N.A., as co-syndication agents, and each of the Lenders from time to time party thereto.
10(i) to Form 10-Q for quarter ended September 30, 2011, filed on October 31, 2011
1-8968
 (xxx)
Anadarko Petroleum Corporation 2008 Omnibus Incentive Compensation Plan, effective as of May 20, 2008
10.1 to Form 8-K filed on May 27, 2008
1-8968
 (xxxi)
Form of Anadarko Petroleum Corporation 2008 Omnibus Incentive Compensation Plan Stock Option Award Agreement
10.3 to Form 8-K filed on November 13, 2009
1-8968
 (xxxii)
Form of Anadarko Petroleum Corporation 2008 Omnibus Incentive Compensation Plan Restricted Stock Unit Award Agreement
10.1 to Form 8-K filed on November 13, 2009
1-8968
 (xxxiii)
Form of Anadarko Petroleum Corporation 2008 Omnibus Incentive Compensation Plan Performance Unit Award Agreement
10.2 to Form 8-K filed on November 13, 2009
1-8968
 (xxxiv)
Anadarko Petroleum Corporation 2008 Director Compensation Plan, effective as of May 20, 2008
10.2 to Form 8-K filed on May 27, 2008
1-8968
 (xxxv)
Form of Award Letter for Anadarko Petroleum Corporation 2008 Director Compensation Plan
10.3 to Form 8-K filed on May 27, 2008
1-8968
 (xxxvi)
Anadarko Petroleum Corporation Benefits Trust Agreement, amended and restated effective as of November 5, 2008
10(lvi) to Form 10-K for year ended December 31, 2008, filed on February 25, 2009
1-8968
 (xxxvii)
Anadarko Petroleum Corporation Deferred Compensation Plan (as amended and restated effective as of January 1, 2010)
10(xlvi) to Form 10-K for year ended December 31, 2009, filed on February 23, 2010
1-8968
Index to Financial Statements
Exhibit
Number
Description
Original Filed
Exhibit
File
Number
 10(xxxviii)
Amended and Restated Employment Agreement between James T. Hackett and Anadarko Petroleum Corporation, dated November 11, 2009
10.4 to Form 8-K filed on November 13, 2009
1-8968
 (xxxix)
Letter Agreement between James T. Hackett and Anadarko Petroleum Corporation, dated February 16, 2012
10.1 to Form 8-K filed on February 21, 2012
1-8968
(xl)
Operating Agreement, dated October 1, 2009, between BP Exploration & Production Inc., as Operator, and MOEX Offshore 2007 LLC, as Non-Operator, as ratified by that certain Ratification and Joinder of Operating Agreement, dated December 17, 2009, by and among BP Exploration & Production Inc., Anadarko Petroleum Corporation (as Non-Operator), Anadarko E&P Company LP (as predecessor in interest to Anadarko Petroleum Corporation), and MOEX Offshore 2007 LLC, together with material exhibits.
10 to Form 10-Q for quarter ended June 30, 2010, filed on August 3, 2010
1-8968
 (xli)
Retention Agreement, dated August 2, 2010
10.1 to Form 8-K filed on August 6, 2010
1-8968
 (xlii)
Confidential Settlement Agreement, Mutual Releases and Agreement to Indemnify, dated October 16, 2011, by and among BP Exploration & Production Inc., Anadarko Petroleum Corporation, Anadarko E&P Company LP, BP Corporation North America Inc. and BP p.l.c.
10(xlii) to Form 10-K for year ended December 31, 2011, filed on February 21, 2012
1-8968
 (xliii)
Severance Agreement between R. A. Walker and Anadarko Petroleum Corporation, dated February 16, 2012
10.2 to Form 8-K filed on February 21, 2012
1-8968
 (xliv)
Time Sharing Agreement between James T. Hackett and Anadarko Petroleum Corporation, dated May 15, 2012
10(i) to Form 10-Q filed on August 8, 2012
1-8968
 (xlv)
Time Sharing Agreement between R. A. Walker and Anadarko Petroleum Corporation, dated May 15, 2012
10(ii) to Form 10-Q filed on August 8, 2012
1-8968
 (xlvi)
Anadarko Petroleum Corporation 2012 Omnibus Incentive Compensation Plan, effective as of May 15, 2012
10.1 to Form 8-K filed on May 15, 2012
1-8968
 (xlvii)
Form of Anadarko Petroleum Corporation 2012 Omnibus Incentive Compensation Plan Stock Option Award Agreement
10.2 to Form 8-K filed on May 15, 2012
1-8968
 (xlviii)
Form of Anadarko Petroleum Corporation 2012 Omnibus Incentive Compensation Plan Restricted Stock Unit Award Agreement
10.3 to Form 8-K filed on May 15, 2012
1-8968
Index to Financial Statements
Exhibit
Number
Description
Original Filed
Exhibit
File
Number
 10(xlix)
Form of Anadarko Petroleum Corporation 2012 Omnibus Incentive Compensation Plan Performance Unit Award Agreement
10.4 to Form 8-K filed on May 15, 2012
1-8968
 (l)
Form of Anadarko Petroleum Corporation 2012 Omnibus Incentive Compensation Plan Restricted Stock Unit Award Agreement
10.1 to Form 8-K filed on November 9, 2012
1-8968
 (li)
Form of Anadarko Petroleum Corporation 2012 Omnibus Incentive Compensation Plan Performance Unit Award Agreement
10.2 to Form 8-K filed on November 9, 2012
1-8968
 (lii)
Form of U.K. Award Letter for Anadarko Petroleum Corporation 2008 Director Compensation Plan
10.5 to Form 8-K filed on May 15, 2012
1-8968
 (liii)
Amended and Restated Performance Unit Award Agreement, effective November 5, 2012, for
Mr. R. A. Walker
10.3 to Form 8-K filed on November 9, 2012
1-8968
* 12
Computation of Ratios of Earnings to Fixed Charges and Earnings to Combined Fixed Charges and Preferred Stock Dividends
* 21
List of Subsidiaries
* 23(i)
Consent of KPMG LLP
* 23(ii)
Consent of Miller and Lents, Ltd.
* 24
Power of Attorney
* 31(i)
Rule 13a-14(a)/15d-14(a) Certification-Chief Executive Officer
* 31(ii)
Rule 13a-14(a)/15d-14(a) Certification-Chief Financial Officer
* 32
Section 1350 Certifications
* 99
Report of Miller and Lents, Ltd.
* 101.INS
XBRL Instance Document
* 101.SCH
XBRL Schema Document
* 101.CAL
XBRL Calculation Linkbase Document
* 101.DEF
XBRL Definition Linkbase Document
* 101.LAB
XBRL Label Linkbase Document
* 101.PRE
XBRL Presentation Linkbase Document
 Management contracts or compensatory plans or arrangements required to be filed pursuant to Item 15.
 Application has been made to the Securities and Exchange Commission (SEC) for confidential treatment of certain provisions of the exhibit. Omitted material for which confidential treatment has been requested has been filed separately with the SEC.
Index to Financial Statements 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 registrants and its subsidiaries on a consolidated basis. The registrant agrees, upon request of the SEC, to furnish copies of any or all of such instruments to the SEC.
b) FINANCIAL STATEMENT SCHEDULES
Financial statement schedules have been omitted because they are not required, not applicable, or the information is included in the Company’s Consolidated Financial Statements.
Index to Financial Statements 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 19, 2013
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 19, 2013.
Name and Signature
Title
(i) Principal executive officer:*
R. A. WALKER
President and Chief Executive Officer
R. A. Walker
(ii) Principal financial officer:
Senior Vice President, Finance and Chief
Financial Officer
/s/ ROBERT G. GWIN
Robert G. Gwin
(iii) Principal accounting officer:
/s/ M. CATHY DOUGLAS
Vice President and Chief Accounting Officer
M. Cathy Douglas
(iv) Directors:*
KEVIN P. CHILTON
LUKE R. CORBETT
H. PAULETT EBERHART
PETER J. FLUOR
RICHARD L. GEORGE
PRESTON M. GEREN III
CHARLES W. GOODYEAR
JOHN R. GORDON
JAMES T. HACKETT
ERIC D. MULLINS
PAULA ROSPUT REYNOLDS
R. A. WALKER
* Signed on behalf of each of these persons and on his own behalf:
By:
/s/ ROBERT G. GWIN
Robert G. Gwin, Attorney-in-Fact

---

Stock Performance Metrics:
Return: 0.02497557736933231
1-Day Return: $1_day_return
3-Day Return: $3_day_return
5-Day Return: $5_day_return
10-Day Return: $10_day_return
20-Day Return: $20_day_return
40-Day Return: $40_day_return
60-Day Return: $60_day_return
80-Day Return: $80_day_return
100-Day Return: $100_day_return
150-Day Return: $150_day_return
252-Day Return: $252_day_return