ANADARKO PETROLEUM CORP
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 be realized. 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 energy markets
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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, levels of 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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the Company’s inability to timely obtain or maintain permits, including those necessary for drilling and/or development projects
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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 Deepwater Horizon events, including, 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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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 liabilities in connection with those proceedings, which could have a material adverse effect on our business, prospects, results of operations, cash flows, financial condition, and liquidity.
In January 2009, Tronox, a former subsidiary of Kerr-McGee Corporation, 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 (Bankruptcy Court). Subsequently, in May 2009, Tronox and certain of its affiliates filed a lawsuit against Anadarko and Kerr-McGee Corporation and certain of its subsidiaries (collectively, Kerr-McGee) asserting a number of claims, including claims for actual and constructive fraudulent conveyance (Adversary Proceeding). Tronox alleged, among other things, that it was insolvent or undercapitalized at the date of its initial public offering and sought, among other things, to recover damages from Kerr-McGee and Anadarko, as well as interest, appreciation, and attorneys’ fees and costs. See Note 17-Contingencies-Tronox Litigation in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K for the nature and status of this litigation and the Company’s liability accrual.
As a result of the Bankruptcy Court’s finding of liability in its Memorandum of Opinion, After Trial (Opinion) issued in December 2013, the Company believes that a loss in the Adversary Proceeding is probable and has recorded a liability of $850 million at December 31, 2013. The Company’s liability is based on the application of relevant accounting guidance and law to the information known to the Company at this time. The Bankruptcy Court has not entered a judgment against Kerr-McGee because the Bankruptcy Court has not resolved questions it raised concerning the appropriate application of bankruptcy law to Kerr-McGee’s right to an offset claim that would reduce the amount of damages to be awarded to the plaintiffs. As the post-trial proceedings continue, the Bankruptcy Court issues a judgment and the parties consider appeal, it is possible that the Company may be required to increase the accrued liability related to the Adversary Proceeding.
While we currently expect to fully pursue all rights available through the appellate process, the Company cannot guarantee success on appeal. If the Company is ultimately required to pay a judgment, the Company may be required to access its $5.0 billion Facility, enter into new or amended financing arrangements, identify and divest assets and/or use cash flows from operations to secure sufficient funds. The Company’s liabilities relating to Tronox could exceed current estimates, and we could incur additional liabilities that we are unable to estimate or predict at this time. These events could have a material adverse effect on our business, prospects, consolidated financial position, results of operations, cash flows, financial condition, and liquidity.
During the appeals process, the Company may be required to post a bond or provide sufficient security within 14 days of a judgment to stay execution of the judgment by the plaintiffs pending the outcome of the appellate process. Depending on the amount of a judgment, there is no guarantee that the Company will be able to post a bond in a timely manner or provide security at levels acceptable to the Bankruptcy Court.
The Company’s ability to post a bond or provide sufficient security to stay a judgment depends on a variety of factors, including, but not limited to, the amount of the judgment, the willingness of the Bankruptcy Court to accept alternative forms of security, the willingness of bond providers to issue bonds in the required amount or at all, and the proposed terms of such bonds. The Company may be required to access existing or new financing arrangements and monetize or pledge assets in order to post a bond or provide any such required security. There is no assurance that the Company would be able to take such actions on acceptable terms or at all. In addition, any such financing arrangements could subject the Company to covenants imposing additional or more burdensome restrictions on the Company’s business, relative to the covenants currently contained in the $5.0 billion Facility and other existing debt agreements. Moreover, the Company could incur significant fees or costs to obtain and maintain a bond or additional financing arrangements.
A downgrade or other negative rating action with respect to our credit rating could negatively impact our cost of and ability to access capital.
In December 2013, following the Bankruptcy Court’s issuance of the Opinion relating to Tronox, Standard and Poor’s (S&P) affirmed its “BBB-” rating of the Company’s debt but revised its outlook from “positive” to “negative” and Moody’s Investors Service (Moody’s) affirmed its “Baa3” rating but revised its outlook from “positive” to “developing.” At that time, Fitch Ratings (Fitch) announced no change to its “BBB-” rating with a stable outlook. As of the date of this Form 10-K, no changes in the Company’s credit ratings have occurred and we are not aware of any current plans of S&P, Moody’s, or Fitch to lower their respective ratings on our debt. However, we cannot provide assurance that our credit ratings will not be downgraded or otherwise negatively affected, especially at the time the Bankruptcy Court issues a judgment, depending on the amount of the judgment. A downgrade of our credit ratings could negatively impact our cost of capital and our ability to access capital markets, increase our costs under our $5.0 billion Facility, and limit our ability to effectively execute aspects of our strategy.
In addition, a downgrade or other negative rating action could affect the Company’s requirements to post collateral as financial assurance of its performance under certain contractual arrangements, such as pipeline transportation contracts, oil and gas sales contracts, and work commitments. Following the December 2013 outlook revisions by S&P and Moody’s, $17 million of letters of credit were provided as assurance of the Company’s performance under these types of arrangements. A downgrade or other negative rating action could also prompt requests by some of Anadarko’s business partners for the Company to post additional collateral in the form of letters of credit or cash.
A downgrade could also trigger provisions in certain of the Company’s derivative instruments that can require full or partial collateralization or immediate settlement of the Company’s obligations. 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 Facility, and if such facility terminates, the Company may be required to post collateral pursuant to existing credit support arrangements. A downgrade could also cause the Company’s credit thresholds with such derivative counterparties to be reduced or eliminated, increasing the amount of collateral required. The aggregate fair value of all derivative instruments with credit-risk-related contingent features for which a net liability position existed at December 31, 2013, was $42 million (net of collateral). See Note 11-Derivative Instruments in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.
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.
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. 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 or crude oil
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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
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, provincial, 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. To conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals, and certificates from various federal, provincial, regional, state, tribal, and local governmental authorities. Government disruptions, such as an extended federal government shutdown resulting from the failure to pass budget appropriations, adopt continuing funding resolutions or raise the debt ceiling, could delay or halt the granting and renewal of such permits, approvals, and certificates required to conduct our operations. As a result, activity in the affected regions, such as the Gulf of Mexico and on federal and Indian lands in the United States, could be adversely affected or delayed. In addition, the adoption of government payment transparency regulations could harm our competitiveness or relations with other governments or third parties. We may also incur substantial costs to maintain compliance with these existing laws and regulations. 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. In addition, certain operations are subject to EPA rules requiring the monitoring and reporting of GHG emissions from specified onshore and offshore production sources in the United States on an annual basis.
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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 accelerated depreciation for tangible property.
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. 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 in its semi-annual regulatory agenda published in July 2013, the agency continues to project the issuance of an Advance Notice of Proposed Rulemaking, but it does not state a deadline for such issuance. In May 2013, the BLM published a supplemental notice of proposed rulemaking governing hydraulic fracturing on federal and Indian lands, replacing a prior proposed rulemaking issued in May 2012, that would require public disclosure of chemicals used in hydraulic fracturing on federal and Indian lands, confirmation that wells used in fracturing operations meet appropriate construction standards, and development of appropriate plans for managing flowback water that returns to the surface. 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; for example, local ballot initiatives in the Colorado cities of Boulder, Broomfield, Fort Collins, and Lafayette to restrict oil and gas development, including the use of hydraulic fracturing, either temporarily or permanently, within their respective cities’ limits were approved by voters in November 2013. 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 or prohibitions are adopted in areas where we currently conduct operations, or in the future plan to conduct operations, we may incur significant costs to comply with such requirements or 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. Depending on the state or area in which they are adopted, such restrictions or prohibitions could have a material adverse effect on our business, prospects, results of operations, financial condition, and liquidity.
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 BLM 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 and the Bureau of Safety and Environmental Enforcement, each agencies of the U.S. Department of the Interior, 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 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. If similar events were to occur in the future, the United States or other countries could elect to again issue directives to temporarily cease drilling activities and, in any event, may from time to time issue further safety and environmental laws and regulations regarding offshore oil and gas exploration and development.
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. 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, 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 or on the cost or availability of insurance to cover the risks associated with such operations.
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.
Our debt and other financial commitments may limit our financial and operating flexibility.
Our total debt was $13.6 billion at December 31, 2013. 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.
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.
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, potential default on U.S. debt, 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, 2013. 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, difficulty or potential delays in obtaining drilling permits, 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, provincial, 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, including the assessment of administrative, civil, and criminal penalties; the imposition of investigatory, remedial, and corrective action obligations or the incurrence of capital expenditures; the occurrence of delays in the development of projects; and the issuance of injunctions restricting or prohibiting some or all of the Company’s activities in a particular area. 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.
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, Mozambique, Ghana, China, Brazil, Kenya, Côte d’Ivoire, Liberia, Sierra Leone, New Zealand, Colombia, South Africa, 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, Colombia, Côte d’Ivoire, Ghana, Kenya, Liberia, Mozambique, New Zealand, Sierra Leone, and South Africa. 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 or delays in operations as a result of hazards such as expropriation, war, piracy, acts of terrorism, insurrection, civil unrest, and other political risks, including tension and confrontations among political parties
•
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
•
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 developing the TEN complex. In the event Côte d’Ivoire is successful in its maritime border claims, this development could be materially impacted. More recently, Venezuela has engaged Guyana in a dispute with regard to their maritime and land borders. Anadarko was forced to stop a seabed study undertaken within Guyana’s Exclusive Economic Zone pursuant to contractual rights granted by Guyana when a Venezuelan naval vessel escorted the vessel to a Venezuelan port because it claims the area as being within its national maritime territory. The two countries have initiated a dialogue. At this time we are unable to ascertain the full impact of this maritime border dispute on future operations in Guyana.
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 notional volumes
•
a widening of price basis differentials occurs between delivery points for our production and the delivery point assumed in the derivative 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
The enactment of derivatives legislation, and the promulgation of regulations pursuant thereto, 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. Although the CFTC has finalized certain regulations, others remain to be finalized or implemented, and it is not possible at this time to predict when this will be accomplished.
The Dodd-Frank Act authorized the CFTC to establish rules and regulations setting position limits for certain futures contracts in designated physical commodities and for options and swaps that are their economic equivalents. The CFTC’s initial position-limits rules were vacated by the U.S. District Court for the District of Columbia in September 2012. However, in November 2013, the CFTC proposed new rules that would place limits on positions in certain core futures and equivalent swaps contracts for or linked to certain physical commodities, subject to exceptions for certain bona fide hedging transactions. It is not possible at this time to predict when the CFTC will finalize these regulations; therefore, the impact of those provisions on us is uncertain at this time.
The CFTC has designated certain interest-rate swaps and credit-default swaps for mandatory clearing and exchange trading. The CFTC has not yet proposed rules designating any other classes of swaps, including physical commodity swaps, for mandatory clearing. Although the Company believes that it qualifies for the end-user exception from the mandatory clearing and trade execution requirements for swaps entered to manage its commercial risks, the application of the mandatory clearing and trade execution requirements to other market participants, such as swap dealers, may change the cost and availability of the swaps that the Company uses for hedging. In addition, the Dodd-Frank Act requires that regulators establish margin rules for uncleared swaps. Rules that require end-users to post initial or variation margin could impact liquidity and reduce our cash available for capital expenditures, therefore reducing our ability to enter into derivatives to reduce risk and protect cash flows. The proposed margin rules are not yet final, and therefore, the impact of those provisions to us is uncertain at this time.
The Dodd-Frank Act and regulations may also result in 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. In addition, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and gas prices. The Company’s revenues could be adversely affected if a consequence of the Dodd-Frank Act and implementing regulations is to lower commodity prices.
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.
In addition, the European Union and other non-U.S. jurisdictions are implementing regulations with respect to the derivatives market. To the extent the Company transacts with counterparties in foreign jurisdictions, it may become subject to such regulations. At this time, the impact of such regulations is not clear.
Any of these consequences could have a material adverse effect on the Company’s consolidated financial position, results of operations, or cash flows.
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; environmental hazards, such as gas leaks, oil spills, pipeline and vessel ruptures, and releases of chemicals or other hazardous substances, any of which could result in damage to, or destruction of, oil and natural-gas wells or formations, production facilities, and other property; pollution or other environmental damage; and 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 and the completion of those projects may be delayed beyond our anticipated completion dates. 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 or legislative and other governmental approvals
•
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.
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.
We have limited influence 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 the operation or future development of these nonoperated 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 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 oil and gas 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 oil and natural gas, which could increase our costs and/or reduce the revenues we might obtain from the sale of the oil and gas.
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.
Item 1B. Unresolved Staff Comments
None.
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; contamination claims relating to oil and gas production, transportation, and processing; and environmental claims, including claims involving assets owned by acquired companies and claims involving assets previously sold to third parties and no longer a part of the Company’s current operations. 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, with the possible exception of the Tronox Litigation discussed in Note 17-Contingencies-Tronox Litigation in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K, 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.
In July 2013, Kerr-McGee Gathering LLC, one of the Company’s consolidated subsidiaries, entered into a consent order with the Colorado Department of Public Health and Environment relating to the failure to comply with certain terms of permits at its Frederick compression station and agreed to pay a penalty of approximately $125,000.
In September 2013, Anadarko received a Notice of Proposed Penalty Assessment (Notice) from the Bureau of Safety and Environmental Enforcement (BSEE) as the result of an incident that occurred in February 2012 relating to a drilling rig in the Gulf of Mexico. In the Notice, the BSEE alleged several violations of certain offshore operational requirements and proposed a penalty in the amount of $395,000. Anadarko has disputed many of the allegations and is working with the BSEE to resolve this matter.
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.
Item 4. Mine Safety Disclosures
Not applicable.
PART II
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, 2014, there were approximately 12,200 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 2013 and 2012:
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.
SECURITIES AUTHORIZED FOR ISSUANCE UNDER EQUITY COMPENSATION PLANS
The following sets forth information with respect to the equity compensation plans available to directors, officers, and employees of the Company at December 31, 2013:
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 2013:
_______________________________________________________________________________
(1)
During the fourth quarter of 2013, 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.
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 two peer groups. The 11 companies included in the new peer group (New Peer Group) are Apache Corporation; Chevron Corporation; ConocoPhillips; Devon Energy Corporation; EOG Resources, Inc.; Hess Corporation; Marathon Oil Corporation; Murphy Oil Corporation; Noble Energy, Inc.; Occidental Petroleum Corporation; and Pioneer Natural Resources Company. The 10 companies included in the old peer group (Old 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; and Pioneer Natural Resources Company. Plains Exploration and Production Company was excluded from the Old Peer Group since it was acquired in May 2013 and ceased trading. As a result, Murphy Oil Corporation was included in the New Peer Group for 2013.
Comparison of 5-Year Cumulative Total Return Among
Anadarko Petroleum Corporation, the S&P 500 Index,
the New Peer Group, and the Old Peer Group
Copyright© 2014 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 each of the peer groups on December 31, 2008, and its relative performance is tracked through December 31, 2013.
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
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 2013. The Company increased sales volumes per day by approximately 7% over 2012 and added 528 million barrels of oil equivalent (BOE) of proved reserves. Additionally, the Company continued its deepwater exploration and appraisal drilling success with a 67% success rate in 2013. The Company ended 2013 with $3.7 billion of cash on hand, availability of its $5.0 billion senior secured revolving credit facility maturing in September 2015 ($5.0 billion Facility), and access to credit and capital markets as needed. Management believes that the Company is positioned to continue 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 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 and predictable development opportunities that, 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 investment in its businesses to efficiently manage commodity price cycles. Maintaining financial discipline enables the Company to capitalize on the opportunities afforded by its global portfolio, while allowing the Company to pursue new strategic growth opportunities.
Significant 2013 operating and financial activities include the following:
Overall
•
Anadarko’s full-year sales volumes averaged 781 thousand barrels of oil equivalent per day (MBOE/d), representing a 7% increase over 2012.
•
Anadarko’s liquids sales volumes were 339 thousand barrels per day (MBbls/d), representing a 7% increase over 2012, primarily due to increased sales volumes in the Wattenberg field, the Eagleford shale, and the East Texas/North Louisiana horizontal development.
•
The Company achieved a 67% success rate from deepwater exploration and appraisal drilling in 2013.
•
The Company recognized an $850 million contingent loss related to the Adversary Proceeding. See Note 17-Contingencies-Tronox Litigation in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.
U.S. Onshore
•
The Rocky Mountains Region (Rockies) full-year sales volumes averaged 327 MBOE/d, representing a 3% increase over 2012, primarily from the Wattenberg field.
•
The Southern and Appalachia Region full-year sales volumes averaged 257 MBOE/d, representing a 30% increase over 2012, primarily from the Marcellus and Eagleford shales, and the East Texas/North Louisiana horizontal development.
•
Anadarko acquired certain oil and gas properties and related assets in the Moxa area of Wyoming for $310 million.
•
Anadarko exchanged certain oil and gas properties in the Wattenberg field with a third party, which allowed the Company to consolidate its working interest and operated acreage positions in the field.
•
The Company sold its interest in the Pinedale/Jonah assets in the Rockies to a third party for $581 million in January 2014, recognizing a loss of $701 million in 2013.
Gulf of Mexico
•
Gulf of Mexico full-year sales volumes averaged 96 MBOE/d, representing a 17% decrease from 2012, primarily due to natural production declines.
•
The Company entered into a carried-interest arrangement that requires a third-party partner to fund $860 million of Anadarko’s capital costs in exchange for a 12.75% working interest in the Heidelberg development.
•
Anadarko’s 80-MBbls/d Lucius spar was installed on location in the deepwater Gulf of Mexico and well-completion activities were initiated.
•
The Company drilled three successful exploration wells and three appraisal wells.
•
The Company increased its ownership position in the Coronado discovery from 15% to 35% and will assume operatorship following the drilling of an appraisal well, which was spud in the fourth quarter of 2013.
International
•
International full-year sales volumes averaged 90 MBOE/d, representing a 7% increase from 2012, primarily in Ghana.
•
The Company drilled two successful exploration wells in Mozambique.
•
Anadarko and its partners continue to make progress marketing liquefied natural gas (LNG) to be produced from Anadarko-operated Rovuma Offshore Area 1 in Mozambique. The partners have reached non-binding Heads of Agreements for long-term LNG sales to buyers in Asian markets covering approximately two-thirds of the first 5-million-tonne-per-annum train.
•
The Company participated in ten successful appraisal wells: six in Mozambique, two in Ghana, and two in Brazil.
•
Anadarko and its partners achieved initial oil production at the El Merk project and production from the facility increased throughout the year as two oil trains and a natural-gas processing and NGLs extraction train were completed and brought online. Final commissioning of the NGLs extraction train is ongoing and will be completed in the first quarter of 2014.
•
Anadarko and its partners received government approval for the Plan of Development for the Tweneboa/Enyenra/Ntomme (TEN) deepwater oil project offshore Ghana.
•
Anadarko sold a 10% working interest in Rovuma Offshore Area 1 in Mozambique for $2.64 billion in February 2014.
Financial
•
Anadarko’s net income attributable to common stockholders for 2013 totaled $801 million, which included an $850 million contingent loss related to the Adversary Proceeding and $794 million of impairment expense primarily related to certain Gulf of Mexico properties and domestic onshore properties.
•
The Company generated $8.9 billion of cash flow from operations in 2013, including $730 million related to the resolution of the Algeria exceptional profits tax dispute, and ended 2013 with $3.7 billion of cash on hand.
•
Anadarko increased the quarterly dividend paid to its common stockholders from $0.09 per share to $0.18 per share.
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, 2013,” refer to the comparison of the year ended December 31, 2013, to the year ended December 31, 2012. Similarly, 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. 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
_______________________________________________________________________________
MMBOE-million barrels of oil equivalent
(1)
Includes Deepwater Horizon settlement and related costs of $15 million in 2013, $18 million in 2012, and $3.9 billion in 2011, and a credit of $1.8 billion for previously recognized expenses related to the favorable resolution of the Algeria exceptional profits tax dispute in 2012.
(2)
Includes Tronox-related contingent loss of $850 million in 2013, reversal of the 2011 Tronox-related contingent loss $(250) million in 2012, and Tronox-related contingent loss of $250 million in 2011.
(3)
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.
FINANCIAL RESULTS
Sales Revenues and Volumes
Anadarko’s total sales revenues increased for the year ended December 31, 2013, primarily due to higher sales volumes for all products and higher average natural-gas prices, partially offset by lower average crude-oil and NGLs prices. Total sales revenues decreased for the year ended December 31, 2012, primarily due to lower average natural-gas and NGLs prices, partially offset by higher sales volumes for all products.
The following provides Anadarko’s sales volumes for the years ended December 31, 2013, 2012, and 2011:
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 11-Derivative Instruments in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K and Other (Income) Expense-(Gains) Losses on 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 157 MMcf/d for the year ended December 31, 2013. Sales volumes for the Southern and Appalachia Region increased 246 MMcf/d primarily due to horizontal drilling and infrastructure expansions in the Eagleford and Marcellus shales, as well as new wells drilled in the liquids-rich East Texas/North Louisiana horizontal development. These increases were partially offset by lower sales volumes in the Gulf of Mexico of 47 MMcf/d primarily due to natural production declines. Also, sales volumes for the Rockies decreased 42 MMcf/d primarily due to a natural production decline in the Powder River basin, partially offset by higher sales volumes in the Wattenberg field due to increased horizontal drilling.
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 wells drilled in previous years were brought online through 2012 infrastructure expansions in the Eagleford and Marcellus shale and new wells were drilled in the liquids-rich East Texas/North Louisiana horizontal development. Also, the Company had higher sales volumes in the Rockies of 52 MMcf/d associated with drilling in the Greater Natural Buttes 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 average natural-gas price Anadarko received increased for the year ended December 31, 2013, as higher-than-normal residential and commercial demand early in the year reduced overall natural gas storage below the previous year’s record levels. Natural-gas prices were further supported by higher demand in the fourth quarter of 2013, a reduction in natural-gas imports from Canada, and continued strength in exports to Mexico. Anadarko’s average natural-gas price 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.
Crude-Oil and Condensate Sales Volumes, Average Prices, and Revenues
_______________________________________________________________________________
MMBbls-million barrels
MBbls/d-thousand barrels per day
Anadarko’s total crude-oil and condensate sales volumes increased 15 MBbls/d for the year ended December 31, 2013. Sales volumes for the Rockies increased 15 MBbls/d primarily in the Wattenberg field due to increased horizontal drilling. Sales volumes for the Southern and Appalachia Region increased 6 MBbls/d, as a result of horizontal drilling and infrastructure expansions in the Eagleford shale. Internationally, sales volumes increased 6 MBbls/d primarily in Ghana as a result of enhanced production due to successful acid stimulations and additional Phase 1A Jubilee wells brought online, as well as timing of cargo liftings. Sales volumes in the Gulf of Mexico decreased 10 MBbls/d primarily due to natural production declines.
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 average crude-oil price received decreased slightly for the year ended December 31, 2013, due to modestly lower international crude oil prices. 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. Anadarko’s average crude-oil price received increased for the year ended December 31, 2012, primarily due to supply disruption concerns associated with political and civil unrest in the Middle East and North Africa, and steady global demand growth.
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 8 MBbls/d for the year ended December 31, 2013. Sales volumes for the Southern and Appalachia Region increased 12 MBbls/d as a result of continued horizontal drilling and infrastructure expansion in the Eagleford shale and horizontal drilling in the liquids-rich East Texas/North Louisiana horizontal development. This increase was partially offset by lower sales volumes in the Rockies of 2 MBbls/d primarily due to ethane rejection in 2013, and in the Gulf of Mexico of 2 MBbls/d due to natural production declines.
Anadarko’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 Southern and Appalachia Region at the Eagleford shale and the East Texas/North Louisiana horizontal development.
Anadarko’s average NGLs price received decreased for the year ended December 31, 2013, primarily due to lower market prices for ethane and butanes as a result of higher U.S. inventory and production levels. 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.
Gathering, Processing, and Marketing Margin
Marketing margins represent the margin earned by purchasing and selling third-party oil and natural gas. Processing margin represents the margin earned by purchasing third-party natural gas and selling the extracted NGLs and remaining residue gas. The Company also earns gathering revenue and processing fees by providing gathering and processing services to third parties. Operating and transportation expenses relate to the Company’s costs to perform these activities, excluding the purchase of commodities that are included in the margin.
For the year ended December 31, 2013, the gathering, processing, and marketing margin increased $22 million. This increase was primarily due to higher gathering revenue as a result of increased throughput across several of Anadarko’s gathering systems and higher marketing margins, partially offset by increased transportation expenses due to increased third-party volumes and increased demand fees.
For the year ended December 31, 2012, the gathering, processing, and marketing margin decreased $109 million primarily due to lower commodity prices, which led to reduced natural-gas processing margins and decreased marketing margins, and higher transportation expenses primarily due to higher demand fees. This decrease was partially offset by additional revenues earned and expenses incurred for 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.
Gains (Losses) on Divestitures and Other, net
Gains (losses) on divestitures and other, net decreased $390 million primarily due to losses on divestitures in 2013. In the fourth quarter of 2013, the Company recognized losses on assets held for sale of $704 million, primarily associated with the divestiture of the Pinedale/Jonah assets in the Rockies, which closed in January 2014 for sale proceeds of $581 million. This decrease was partially offset by a $140 million gain in 2013 associated with the Company’s divestiture of its interests in a soda ash joint venture. The Company divested its interests in the soda ash joint venture for $310 million and potential additional consideration based on future revenue of the joint venture, while retaining its royalty interest in soda ash mined by the joint venture from the Company’s Land Grant. In 2013, gains on divestitures also included $94 million primarily related to the divestiture of certain oil and gas properties in the United States compared to net losses on similar divestitures of $71 million in 2012 primarily related to the sale of oil and gas properties in Indonesia. See Note 2-Acquisitions, Divestitures, and Assets Held for Sale in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K for additional information on assets held for sale.
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. Gains (losses) on divestitures for 2012 included net losses of $71 million, as discussed above. 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 that occurred in connection with the Company’s purchase of the Wattenberg 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.
Costs and Expenses
For the year ended December 31, 2013, oil and gas operating expenses increased $116 million primarily due to increased workovers in the Gulf of Mexico, Rockies, and Southern and Appalachia Regions; higher expenses in Algeria associated with the start of El Merk production in 2013; and increased costs associated with increased activity in the Rockies and Southern and Appalachia Regions. Oil and gas operating expenses per BOE increased by $0.18 for the year ended December 31, 2013, primarily due to these higher costs, partially offset by increased sales volumes.
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 as a result of 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 production costs remained flat as a result of efficiency gains, and lower workover expenses as discussed above.
Oil and gas transportation and other expenses increased by $67 million for the year ended December 31, 2013, and $64 million for the year ended December 31, 2012, primarily due to higher gas-gathering and transportation costs attributable to higher volumes and increased costs related to growth in the Company’s U.S. onshore asset base. Oil and gas transportation and other expenses per BOE increased by $0.02 for the year ended December 31, 2013, primarily due to the higher costs discussed above, partially offset by increased sales volumes. 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.
Exploration expense decreased $617 million for the year ended December 31, 2013. Impairments of unproved properties decreased $796 million primarily due to $845 million of 2012 impairments, which included $721 million related to Powder River coalbed methane properties primarily due to lower natural-gas prices and $124 million related to a Gulf of Mexico natural-gas property that the Company does not expect to develop under the forecasted natural-gas price environment. In addition, unproved property impairments for the year ended December 31, 2013, decreased by $144 million as a result of a change in the Company’s estimated success rate associated with unproved Gulf of Mexico properties. The decrease was partially offset by unproved oil and gas property impairments in 2013 due to changes to the Company’s drilling plans, which included $89 million for an unproved property in Block 43/11 in the South China Sea, $53 million for an unproved property in the Espírito Santo basin in Brazil, and $53 million for a domestic onshore unproved property. For the year ended December 31, 2013, dry hole expense increased by $116 million primarily due to 2013 dry hole expense for wells in the Gulf of Mexico, Sierra Leone, Kenya, Côte d’Ivoire, and New Zealand, partially offset by 2012 dry hole expense for wells in Brazil, Sierra Leone, the Gulf of Mexico, Ghana, and Côte d’Ivoire. Geological and geophysical expense increased $57 million for the year ended December 31, 2013, primarily due to 2013 seismic purchases in Colombia and the Gulf of Mexico.
Exploration expense increased $870 million for the year ended December 31, 2012. Impairments of unproved properties increased $633 million primarily due to $845 million of 2012 impairments for certain unproved properties in the Rockies and the Gulf of Mexico as discussed above, 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. Dry hole expense increased $286 million for the year ended December 31, 2012, primarily due to wells in Brazil, Sierra Leone, Côte d’Ivoire, Mozambique, and the Gulf of Mexico. Geological and geophysical expense decreased $95 million primarily due to fewer seismic purchases in Kenya, Liberia, New Zealand, and Mozambique. Exploration overhead and other increased $46 million for the year ended December 31, 2012, primarily due to increased exploration activity in U.S. onshore and Mozambique.
For the year ended December 31, 2013, general and administrative (G&A) expense decreased by $156 million due to reduced legal-related expenses of $101 million and lower employee-related expenses of $60 million. The reduced legal-related expenses were primarily related to lower Tronox legal expenses in 2013 and the third-party reimbursement during 2013 of the Company’s legal expenses associated with the Algeria exceptional profits tax settlement. The lower employee-related expenses were primarily related to the 2012 expense associated with Unit Appreciation Rights (UARs), partially offset by higher 2013 employee-related expenses associated with operational expansions. The UARs were awarded in prior years to certain officers of the general partner of Western Gas Partners, LP (WES), a consolidated subsidiary of Anadarko, pursuant to the Western Gas Holdings, LLC (WGH) Equity Incentive Plan. This expense was related to the change in fair value of the UARs upon the initial public offering (IPO) of Western Gas Equity Partners, LP (WGP), a consolidated subsidiary formed to own substantially all of Anadarko’s partnership interests in WES. For the year ended December 31, 2012, G&A expense increased by $186 million due to higher employee-related expenses of $150 million primarily related to expense associated with the UARs discussed above and $41 million due to legal-related expenses primarily related to increased Tronox legal expenses in 2012.
For the year ended December 31, 2013, depreciation, depletion, and amortization (DD&A) expense decreased by $37 million primarily due to accelerated expense in 2012 associated with the depletion of fields in the Gulf of Mexico, partially offset by higher volumes in 2013. For the year ended December 31, 2012, DD&A expense increased by $134 million primarily due to higher sales volumes, accelerated expense in 2012 as discussed above, 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 recognized in the fourth quarter of 2011 and reserves additions in 2012 in the Southern and Appalachia Region.
For the year ended December 31, 2013, other taxes decreased by $147 million primarily related to lower Algerian exceptional profits taxes of $116 million due to a lower Algeria effective tax rate resulting from the resolution of the Algeria exceptional profits tax dispute and lower crude-oil prices. In addition, lower sales volumes and crude-oil prices resulted in a $33 million decrease in U.S. production and severance taxes primarily in Alaska. For the year ended December 31, 2012, other taxes decreased by $268 million 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.
Impairment expense of $794 million for the year ended December 31, 2013, included $562 million due to a reduction in estimated future net cash flows per barrel and downward revisions of reserves for certain Gulf of Mexico properties that the Company no longer plans to develop. In addition, impairment expense included $142 million for certain domestic onshore oil and gas properties due to downward revisions of reserves that the Company no longer plans to develop and $49 million for related midstream assets. Impairment expense also included $30 million for certain midstream properties due to a reduction in estimated future cash flows, and $11 million related to the Company’s Venezuelan cost-method investment due to declines in estimated recoverable value. Declines in commodity prices or negative reserves revisions could result in additional impairments. See Note 5-Impairments in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K for additional information on impairments and Risk Factors under Item 1A of this Form 10-K for further discussion on the risks associated with oil, natural-gas, and NGLs prices.
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.
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 properties.
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 $1.7 billion and the elimination of $62 million of previously recorded and unpaid transportation charges. The Company recognized a $1.8 billion credit in the Costs and Expenses section of the Consolidated Statement of Income for 2012 to reflect the effect of this agreement for previously recorded expenses. During 2013, the Company revised its estimate of income tax expense related to the elimination of previously recorded and unpaid transportation charges and recognized a $33 million unfavorable adjustment to the settlement, which was offset by an equivalent income tax benefit also recognized in 2013. At December 31, 2013, the Company had collected all of the $1.7 billion associated with the Algeria exceptional profits tax receivable.
In October 2011, the Company and BP Exploration & Production Inc (BP) entered into the 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, and BP agreed to accept this consideration in full satisfaction of its claims against Anadarko. 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.
Deepwater Horizon settlement and related costs included legal expenses and related costs associated with the Deepwater Horizon events of $15 million for the year ended December 31, 2013, and $18 million for the year ended December 31, 2012. 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 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 recorded 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 by $56 million for the year ended December 31, 2013, primarily due to an increase in capitalized interest of $42 million related to higher construction-in-progress balances for long-term capital projects. Additionally, interest expense for the year ended December 31, 2013, decreased $31 million as a result of the repayment of outstanding borrowings during 2012 associated with the five-year, $5.0 billion Facility. The decrease for the year ended December 31, 2013, was partially offset by $18 million of interest expense for outstanding borrowings primarily related to WES’s 4.000% Senior Notes due 2022. For additional information, see Liquidity and Capital Resources and Interest-Rate Risk under
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 to satisfy these margin requirements. For additional information relating to the Company’s derivative and financial instruments, see Note 11-Derivative Instruments in the Notes to Consolidated Financial Statements under
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 for the Three Years Ended December 31, 2013
Consolidated Statements of Comprehensive Income for the Three Years Ended December 31, 2013
Consolidated Balance Sheets at December 31, 2013 and 2012
Consolidated Statements of Equity for the Three Years Ended December 31, 2013
Consolidated Statements of Cash Flows for the Three Years Ended December 31, 2013
Notes to Consolidated Financial Statements
Supplemental Quarterly Information
Supplemental Information on Oil and Gas Exploration and Production Activities
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, 2013. This assessment was based on criteria established in Internal Control-Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on our assessment, we believe that as of December 31, 2013, 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, 2013.
/s/ R. A. WALKER
R. A. Walker
Chairman, President and Chief Executive Officer
/s/ ROBERT G. GWIN
Robert G. Gwin
Executive Vice President, Finance and Chief Financial Officer
February 28, 2014
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, 2013, based on criteria established in Internal Control - Integrated Framework (1992) 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, 2013, based on criteria established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
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, 2013 and 2012, 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, 2013, and our report dated February 28, 2014 expressed an unqualified opinion on those consolidated financial statements.
/s/ KPMG LLP
Houston, Texas
February 28, 2014
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, 2013 and 2012, 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, 2013. 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, 2013 and 2012, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2013, 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, 2013, based on criteria established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 28, 2014 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.
/s/ KPMG LLP
Houston, Texas
February 28, 2014
ANADARKO PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
See accompanying Notes to Consolidated Financial Statements.
ANADARKO PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
__________________________________________________________________
(1)
Net of income tax benefit (expense) of $(4) million in 2013, $(4) million in 2012, and $(5) million in 2011.
(2)
Net of income tax benefit (expense) of $(152) million in 2013, $56 million in 2012, and $77 million in 2011.
(3)
Net of income tax benefit (expense) of $(5) million in 2011.
(4)
Net of income tax benefit (expense) of $(49) million in 2013, $(32) million in 2012, and $(31) million in 2011.
See accompanying Notes to Consolidated Financial Statements.
ANADARKO PETROLEUM CORPORATION
CONSOLIDATED BALANCE SHEETS
See accompanying Notes to Consolidated Financial Statements.
ANADARKO PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF EQUITY
__________________________________________________________________
(1)
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.
ANADARKO PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
See accompanying Notes to Consolidated Financial Statements.
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2013, 2012, AND 2011
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, natural gas liquids (NGLs), and anticipated production of liquefied natural gas (LNG). In addition, the Company engages in the gathering, processing, treating, and transporting of natural gas, crude oil, and NGLs. The Company also participates in hard-minerals 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 management to 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 proved reserves; the value of properties and equipment; goodwill; intangible assets; asset retirement obligations; litigation liabilities; 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).
In determining fair value, the Company uses 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.
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2013, 2012, AND 2011
1. Summary of Significant Accounting Policies (Continued)
In arriving at fair-value estimates, the Company uses 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 12-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 and 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.
Cash Equivalents The Company considers all highly liquid investments with a maturity of three months or less when purchased to be cash equivalents.
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2013, 2012, AND 2011
1. Summary of Significant Accounting Policies (Continued)
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 term 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.
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, significant midstream development activities that are in progress, and investments in equity method affiliates that are undergoing the construction of assets that have not commenced principle operations 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 12-Debt and Interest Expense.
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2013, 2012, AND 2011
1. Summary of Significant Accounting Policies (Continued)
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 7-Asset Retirement Obligations.
Impairments Properties and equipment are reviewed for impairment when facts and circumstances indicate that net book values may not be recoverable. In performing this review, an undiscounted cash flow test is performed at the lowest level for which identifiable cash flows are independent of cash flows from other assets. 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 5-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 8-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 8-Goodwill and Other Intangible Assets.
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.
Gains and losses on derivative instruments are recognized currently in earnings. Net 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 11-Derivative Instruments.
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2013, 2012, AND 2011
1. Summary of Significant Accounting Policies (Continued)
Accounts Payable Accounts payable included liabilities of $326 million at December 31, 2013, and $339 million at December 31, 2012, 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 at the time of acquisition, the Company accrues losses associated with legal claims when such losses are probable and reasonably estimable. If the Company determines that a loss is probable and cannot estimate a specific amount for that loss, but can estimate a range of loss, the best estimate within the range is accrued. If no amount within the range is a better estimate than any other, the minimum amount of the range is accrued. 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 at the time of acquisition, 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.
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 9-Noncontrolling Interests.
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2013, 2012, AND 2011
1. Summary of Significant Accounting Policies (Continued)
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 basis. 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 based on the grant-date fair value. For liability-classified share-based compensation awards, expense is recognized for those awards expected to ultimately be paid. The amount of expense reported is adjusted 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 13-Stockholders’ Equity.
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2013, 2012, AND 2011
2. Acquisitions, Divestitures, and Assets Held for Sale
Acquisitions The following summarizes acquisitions made during 2013 and 2011. There were no acquisitions made during 2012.
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(1)
Includes $306 million that represents the fair value of the oil and gas properties acquired.
(2)
The Company recognized a $76 million loss on preexisting contracts with the previous Wattenberg Plant owner in addition to the cash paid in the Wattenberg Plant acquisition. Anadarko operates and owns a 100% interest in the Wattenberg Plant.
Divestitures In 2013, sale proceeds of $509 million were primarily related to the Company’s divestiture of its interests in a soda ash joint venture and certain U.S. onshore and Indonesian oil and gas properties. Net gains of $234 million were primarily related to the Company’s divestiture of its interests in the soda ash joint venture and certain U.S. oil and gas properties.
In 2012, sale proceeds of $433 million were primarily related to U.S. oil and gas properties and net losses of $43 million were primarily related to Indonesian oil and gas properties. 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 February 2014, the Company sold a 10% working interest in Rovuma Offshore Area 1 in Mozambique for $2.64 billion. Also in February 2014, the Company entered into an agreement to sell its oil and gas properties in China for $1.075 billion. The transaction is expected to close later in 2014 and is subject to preferential rights, regulatory approvals, and other customary closing conditions.
Property Exchange In 2013, the Company exchanged certain oil and gas properties in the Wattenberg field with a third party. The properties exchanged were measured at the Company’s historical net cost with no gain or loss recognized. Anadarko paid $106 million in cash as part of the exchange, which is included as an addition to properties and equipment on the Company’s Consolidated Statement of Cash Flows.
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2013, 2012, AND 2011
2. Acquisitions, Divestitures, and Assets Held for Sale (Continued)
Assets Held for Sale During the fourth quarter of 2013, the Company began marketing certain domestic properties from the oil and gas exploration and production reporting segment to redirect its operating activities and capital investments to other areas. These assets were remeasured to their fair value using a market approach, resulting in a Level 2 fair-value measurement. Losses of $704 million primarily related to the sale of the Pinedale/Jonah assets in the Rockies, which closed in January 2014 for sale proceeds of $581 million. Gains and losses on 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, 2013, the Company’s Consolidated Balance Sheets included long-term assets of $616 million and long-term liabilities of $27 million associated with assets held for sale.
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. At December 31, 2012, the balances of assets and liabilities associated with assets held for sale were not material.
3. Inventories
The following summarizes the major classes of inventories, included in other current assets, at December 31:
4. Properties and Equipment
The following summarizes the cost of properties and equipment by segment at December 31:
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(1)
Includes costs associated with unproved properties of $6.9 billion at December 31, 2013, and $7.1 billion at December 31, 2012.
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2013, 2012, AND 2011
5. Impairments
The following summarizes impairments by segment for the years ended December 31:
In 2013, certain Gulf of Mexico properties were impaired due to a reduction in estimated future net cash flows per barrel and downward revisions of reserves that the Company no longer plans to develop. Also in 2013, certain U.S. onshore properties and related midstream assets were impaired due to downward revisions of reserves that the Company no longer plans to develop. In addition, a midstream property was impaired during 2013 due to a reduction in estimated future cash flows. In 2012, certain U.S. onshore and midstream properties were impaired primarily due to lower natural-gas prices and 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, certain 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. Impairments of the Company’s Venezuelan cost-method investment were due to declines in estimated recoverable value.
The following summarizes the post-impairment fair value of the above-described assets, all of which were measured using the income approach and Level 3 inputs:
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(1)
This represents the Company’s after-tax net investment.
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 due to 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 expect to develop under the forecasted natural-gas price environment.
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2013, 2012, AND 2011
6. 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.
The following summarizes an aging of suspended exploratory well costs by geographic area and the year the costs were suspended at December 31, 2013:
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(1)
Excludes additions subsequently reclassified to proved properties within the same year.
Suspended exploratory well costs capitalized for a period greater than one year after completion of drilling were associated with 14 projects at December 31, 2013, primarily located in Mozambique, Brazil, the Gulf of Mexico, and Ghana. 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, well-test analysis, additional geological and geophysical data, facilities and infrastructure development options, 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.
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2013, 2012, AND 2011
7. Asset Retirement Obligations
The majority of Anadarko’s AROs relate to the plugging of wells and the related abandonment of oil and gas properties. 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. The following summarizes changes in the Company’s AROs during 2013 and 2012:
8. Goodwill and Other Intangible Assets
Goodwill The Company completed its annual impairment assessment of goodwill during the fourth quarter of 2013, and the test indicated no impairment. At December 31, 2013, the Company had $5.5 billion of goodwill allocated to the following reporting units: $5.3 billion to oil and gas exploration and production, $70 million to other gathering and processing, $100 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 2011 Wattenberg Plant acquisition. The contracts are included in the Company’s midstream reporting segment and are being amortized over 50 years. The estimated aggregate amortization expense for intangible assets for the next five years is not expected to be material.
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2013, 2012, AND 2011
9. Noncontrolling Interests
In December 2012, Western Gas Equity Partners, LP (WGP), a publicly traded consolidated subsidiary formed to own substantially all of 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, 2013, Anadarko’s ownership interest in WGP consisted of a 91.0% limited partner interest and the entire non-economic general partner interest. The remaining limited partner interest in WGP consisted of a 9.0% public ownership interest.
WES, a publicly traded consolidated subsidiary, is a limited partnership formed by Anadarko to own, operate, acquire, and develop midstream assets. WES issued approximately 12 million common units to the public raising net proceeds of $725 million in 2013, approximately 5 million common units to the public raising net proceeds of $212 million in 2012, and approximately 10 million common units to the public raising net proceeds of $328 million in 2011. At December 31, 2013, WGP’s ownership interest in WES consisted of a 41.2% limited partner interest, the entire 2.0% general partner interest, and all WES incentive distribution rights. At December 31, 2013, Anadarko also owned a 0.4% limited partner interest in WES through another subsidiary. The remaining limited partner interest in WES consisted of a 56.4% public ownership interest.
10. 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, 2013. 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 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 1.24% at December 31, 2013, and 1.31% at December 31, 2012. The note payable agreement contains a covenant that provides for a maximum Anadarko debt-to-capital ratio of 67%. Anadarko was in compliance with this covenant at December 31, 2013. Other (income) expense, net includes interest expense on the notes payable of $37 million in 2013, $42 million in 2012, and $38 million in 2011, and equity earnings from Anadarko’s investments in the investee entities of $(42) million in 2013, $(43) million in 2012, and $(41) million in 2011.
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2013, 2012, AND 2011
11. 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, Louisiana for natural gas and Cushing, Oklahoma or Sullom Voe, Scotland for oil. Basis swaps are periodically 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, gains and losses associated with derivative instruments are recognized currently 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. See Note 14-Accumulated Other Comprehensive Income (Loss).
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2013, 2012, AND 2011
11. 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 and IntercontinentalExchange, Inc. (ICE) Brent Blend 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, 2013:
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(1)
The extendable fixed-price contracts have a contract term of January 2014 to June 2014 with an option to extend the contract term to December 2014 at the same price.
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 The Company had financial derivative transactions with notional volumes totaling 16 billion cubic feet (Bcf) of natural gas at December 31, 2013, and 22 Bcf at December 31, 2012, that were entered into to mitigate commodity-price risk related to fixed-price purchase and sales contracts and storage activity.
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2013, 2012, AND 2011
11. 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 future 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 debt refinancing, the Company extended the maturity dates for certain interest-rate swaps. In 2012, the Company extended the 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 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 payment 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 payment of $57 million.
The Company had the following outstanding interest-rate swaps at December 31, 2013:
Effect of Derivative Instruments-Balance Sheet The following summarizes the fair value of the Company’s derivative instruments at December 31:
__________________________________________________________________
(1)
Interest-rate swaps with June 2014 maturity dates were reclassified from other liabilities to accrued expenses during 2013.
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2013, 2012, AND 2011
11. Derivative Instruments (Continued)
Effect of Derivative Instruments-Statement of Income The following summarizes gains and losses related to derivative instruments:
__________________________________________________________________
(1)
Represents the effect of marketing and trading derivative activities.
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 gains and 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, 2013, $76 million of the Company’s $986 million gross derivative liability balance, and at December 31, 2012, $339 million of the Company’s $1.4 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 maturing in September 2015 ($5.0 billion Facility).
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 from major credit rating agencies declining to a level below investment grade. The aggregate fair value of derivative instruments with credit-risk-related contingent features for which a net liability position existed was $42 million (net of collateral) at December 31, 2013, and $94 million (net of collateral) at December 31, 2012. The current portion of these amounts was included in accrued expenses and the long-term portion of these amounts was included in other long-term liabilities-other on the Company’s Consolidated Balance Sheets.
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2013, 2012, AND 2011
11. 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.
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2013, 2012, AND 2011
12. 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 10-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.
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2013, 2012, AND 2011
12. 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 Zero Coupons can be put to the Company in October of each year, which would cause the Company to repay up to the then-accreted value of the outstanding Zero Coupons. The accreted value of the outstanding Zero Coupons was $727 million at December 31, 2013. Anadarko’s $275 million aggregate principal amount of 5.750% Senior Notes due June 2014 and Zero Coupons, which can be put to the Company in 2014, are classified as long-term debt on the Company’s Consolidated Balance Sheets, as the Company has the ability and intent to refinance these obligations using long-term debt.
Fair Value The Company uses a market approach to determine the 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 $15.3 billion at December 31, 2013, and $16.2 billion at December 31, 2012.
Debt Activity The following summarizes the Company’s debt activity during 2013 and 2012:
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2013, 2012, AND 2011
12. 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 11-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, 2013, the Company was in compliance with applicable covenants and there were no restrictions on its ability to utilize the $5.0 billion Facility.
WES Borrowings In March 2011, WES entered into a five-year, $800 million senior unsecured revolving credit facility maturing in March 2016 (RCF). Borrowings under the RCF bear 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. During 2013, WES repaid all outstanding borrowings under its RCF with proceeds from debt and equity offerings. At December 31, 2013, WES was in compliance with all covenants contained in its RCF.
In February 2014, WES entered into a five-year, $1.2 billion senior unsecured revolving credit facility maturing in February 2019 (2014 RCF), which amended and restated the RCF. The 2014 RCF is expandable to a maximum of $1.5 billion. Borrowings under the 2014 RCF bear interest at LIBOR plus an applicable margin ranging from 0.975% to 1.45%, or rates at a margin above the one-month LIBOR, the federal funds rate, or prime rates offered by certain designated banks.
Scheduled Maturities Total principal amount of debt maturities for the five years ending December 31, 2018, 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:
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2013, 2012, AND 2011
13. Stockholders’ Equity
Common Stock The following summarizes the changes in the Company’s outstanding shares of common stock:
The following provides a reconciliation between basic and diluted EPS attributable to common stockholders for the years ended December 31:
__________________________________________________________________
(1)
Inclusion of certain shares would have had an anti-dilutive effect.
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2013, 2012, AND 2011
14. Accumulated Other Comprehensive Income (Loss)
The following summarizes the after-tax changes in the balances of each component of accumulated other comprehensive income (loss):
15. Share-Based Compensation
At December 31, 2013, 26 million shares of the 31 million shares of Anadarko common stock originally 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 $11 million in 2013, $51 million in 2012, and $(15) million in 2011. Cash received from stock option exercises was $135 million in 2013, $52 million in 2012, and $45 million in 2011.
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2013, 2012, AND 2011
15. Share-Based Compensation (Continued)
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, which are also considered restricted stock, 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.
The following summarizes the Company’s restricted stock activity:
The weighted-average grant-date fair value per share of restricted stock granted was $79.97 during 2012 and $81.19 during 2011. The total fair value of restricted shares vested was $110 million during 2013, $105 million during 2012, and $124 million during 2011, based on the market price at the vesting date. At December 31, 2013, total unrecognized compensation cost related to restricted stock of $175 million is expected to be recognized over a weighted-average remaining service period of 1.9 years.
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2013, 2012, AND 2011
15. Share-Based Compensation (Continued)
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.
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 2013, 2012, and 2011:
The following summarizes the Company’s stock option activity:
The per-option weighted-average grant-date fair value of stock options granted was $26.27 during 2013, $25.84 during 2012, and $29.77 during 2011. The total intrinsic value of stock options exercised was $80 million during 2013, $49 million during 2012, and $45 million during 2011, based on the difference between the market price at the exercise date and the exercise price. At December 31, 2013, total unrecognized compensation cost related to stock options of $41 million is expected to be recognized over a weighted-average remaining service period of 2.2 years.
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2013, 2012, AND 2011
15. Share-Based Compensation (Continued)
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, 2013, 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, 506,449 shares have been issued and 14,809 shares have been deferred pursuant to the agreements. The fair value of the performance-based share awards issued was $11 million during 2013, zero during 2012, and $6 million during 2011, based on the market price on the date of issuance. At December 31, 2013, the Company had no unrecognized compensation cost related to these awards.
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 zero during 2013 related to the plan, $24 million during 2012, and zero during 2011. At December 31, 2013, the Company had no outstanding liability attributable to the 2013 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 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 $15 million related to vested performance units in 2013, $37 million in 2012, and $25 million in 2011. At December 31, 2013, the Company’s liability under Performance Unit Award Agreements was $15 million, with total unrecognized compensation cost related to these awards of $20 million expected to be recognized over a weighted-average remaining performance period of 1.9 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 in settlement of obligations related to all awards then outstanding.
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2013, 2012, AND 2011
16. Commitments
Operating Leases At December 31, 2013, the Company had $3.3 billion in long-term drilling rig commitments that satisfy operating lease criteria. The Company also had $388 million of various commitments under non-cancelable operating lease agreements 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 $53 million at December 31, 2013. No liability has been accrued for residual value guarantees. In addition, these operating leases include options to purchase the leased property during or at the end of the lease term for the fair market value or other specified amount at that time. The following summarizes future minimum lease payments under operating leases at December 31, 2013:
Total rent expense, net of sublease income, amounted to $119 million in 2013, $136 million in 2012, and $143 million in 2011. Total rent expense includes contingent rent expense related to processing fees of $17 million in 2013, $18 million in 2012, and $21 million in 2011.
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 $3.1 billion related to eight offshore drilling vessels and $155 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 or impaired 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 $206 million for these agreements.
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 oil and gas activities. These agreements expire at various dates through 2030. At December 31, 2013, aggregate future payments under these contracts totaled $11.5 billion, of which $2.3 billion is expected to be paid in 2014, $1.8 billion in 2015, $1.4 billion in 2016, $1.2 billion in 2017, $1.1 billion in 2018, and $3.7 billion thereafter.
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2013, 2012, AND 2011
17. Contingencies
Litigation 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; contamination claims relating to oil and gas production, transportation, and processing; and environmental claims, including claims involving assets owned by acquired companies and claims involving assets previously sold to third parties and no longer a part of the Company’s current operations. The Company’s Consolidated Balance Sheets include liabilities of $854 million at December 31, 2013, and $49 million at December 31, 2012, for litigation-related contingencies. 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, with the possible exception of the Tronox Litigation discussed below, 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.
Tronox Litigation On November 28, 2005, Tronox Incorporated (Tronox), at the time a subsidiary of Kerr-McGee Corporation, completed an IPO and was subsequently spun-off from Kerr-McGee Corporation. In August 2006, Anadarko acquired all of the stock of Kerr-McGee Corporation. In January 2009, Tronox 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 (Bankruptcy Court), which is the court that is also hearing the Adversary Proceeding (defined below). Subsequently, in May 2009, Tronox and certain of its affiliates filed a lawsuit against Anadarko and Kerr-McGee Corporation and certain of its subsidiaries (collectively, Kerr-McGee) asserting several claims, including claims for actual and constructive fraudulent conveyance (Adversary Proceeding). Tronox alleged, among other things, that it was insolvent or undercapitalized at the date of its IPO and sought, among other things, to recover damages from Kerr-McGee and Anadarko, as well as interest, appreciation, and attorneys’ fees and costs. In accordance with Tronox’s Bankruptcy Court-approved Plan of Reorganization (Plan), the Adversary Proceeding is being pursued by a litigation trust (Litigation Trust). Pursuant to the Plan, the Litigation Trust was “deemed substituted” for the Tronox plaintiffs in the Adversary Proceeding. For purposes of this Form 10-K, references to “Tronox” after February 2011 refer to the Litigation Trust.
The U.S. government intervened 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). The Litigation Trust and the U.S. government have agreed that the recovery of damages under the Adversary Proceeding, if any, would cover both the Adversary Proceeding and the FDCPA Complaint.
In February 2011, Tronox emerged from bankruptcy pursuant to the Plan. The terms of the Plan, which were confirmed by the Bankruptcy Court in the fourth quarter of 2010, contemplate that the claims of the U.S. government (together with other federal, state, local, and tribal governmental entities having regulatory authority or responsibilities for environmental laws, collectively, the Governmental Entities) related to Tronox’s environmental liabilities and tort claims asserted against Tronox by other creditors will be settled through certain environmental response trusts and the Litigation Trust. The Plan provides for an allocation of any proceeds from the Adversary Proceeding between the Governmental Entities and the other creditors.
In January 2012, the Bankruptcy Court held that Section 550(a) of the Bankruptcy Code does not impose a cap on potential damages Tronox may recover, stating that the appropriate measure of damages should only be determined after trial in the Adversary Proceeding.
The Adversary Proceeding trial was held from May 2012 through September 2012. In November 2012, the parties filed post-trial briefs, and closing arguments were presented in December 2012. In December 2013, the Bankruptcy Court issued a Memorandum of Opinion, After Trial (discussed below).
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2013, 2012, AND 2011
17. Contingencies (Continued)
Historical Accounting The Company recognized losses of $250 million in the fourth quarter of 2011 and $275 million in the first quarter of 2012, for a total estimated contingent liability related to the Adversary Proceeding of $525 million at March 31, 2012. At that time, the Company’s assessment was that it was probable the parties would reach a settlement and thus the Company considered a loss, via settlement, to be probable. The Company’s attempts during the second quarter of 2012 to resolve the Adversary Proceeding through mediation and settlement discussions reached an impasse. Accordingly, based on information available at that time, the Company’s assessment was that the likelihood of resolving the Adversary Proceeding through settlement was remote, that the likely form of final resolution of this matter was through litigation and the appellate process, and that a loss was not probable. Therefore, the Company reversed the settlement-based $525 million contingent liability in the second quarter of 2012 resulting in no accrued liability for this matter at June 30, 2012. There were no events or developments that changed the Company’s assessment until December 2013.
Memorandum of Opinion In December 2013, the Bankruptcy Court issued a Memorandum of Opinion, After Trial (Opinion) in which the Bankruptcy Court found Kerr-McGee liable for fraudulent transfers in connection with Kerr-McGee’s 2002 internal corporate restructuring and the subsequent IPO of Tronox. In its Opinion, the Bankruptcy Court concluded that damages from the fraudulent conveyance were equal to the value of the transferred assets as of the IPO date of $14.459 billion, but that Kerr-McGee may file a claim under Section 502(h) of the U.S. Bankruptcy Code (502(h) Claim). The Opinion provisionally outlined a framework for determining the amount of Kerr-McGee’s 502(h) Claim, resulting in a 502(h) Claim amount of $10.459 billion. The Bankruptcy Court noted that a portion of the 502(h) Claim, if allowed, would be offset against an award of damages. The Bankruptcy Court expressed its opinion that it has the authority to enter a judgment against Kerr-McGee, but did not enter a judgment against Kerr-McGee at the time of the issuance of its Opinion because it had not resolved questions it raised concerning Kerr-McGee’s 502(h) Claim and the portion of the 502(h) Claim that could be recovered (Recovery Percentage). The Bankruptcy Court also noted that attorneys’ fees and costs could be added to an award to the extent appropriate. The Bankruptcy Court ordered the parties to submit further briefing regarding Kerr-McGee’s 502(h) Claim.
Briefing on 502(h) Claim In accordance with the Bankruptcy Court’s order, Kerr-McGee submitted its brief and filed its 502(h) Claim in January 2014 and the plaintiffs’ response was submitted in February 2014. Kerr-McGee argued in its brief, among other things, that the Bankruptcy Court should not dilute Kerr-McGee’s 502(h) Claim and that the Bankruptcy Court, in its provisional findings, has not properly considered the amount of Kerr-McGee’s 502(h) Claim or the Recovery Percentage. Kerr-McGee argued that the proper application of the Bankruptcy Court’s findings of fact and conclusions of law would result in net damages of $850 million. Alternatively, the Company argued that using the Bankruptcy Court’s framework, damages should be limited to the net present value of the legacy environmental and tort liabilities at the IPO date, which the Bankruptcy Court determined to be $1.757 billion.
In their responsive pleadings, the plaintiffs argued, among other things, that Kerr-McGee’s 502(h) Claim should be disallowed or, in the alternative, diluted to either 68% or 2.8% of its value. Furthermore, the plaintiffs argued that in addition to the value of the transferred assets as of the IPO date, they are entitled to recover appreciation in the value of those assets from the IPO date through June 2012, the date testimony was provided by a plaintiffs’ expert. If combined with a disallowed 502(h) Claim as argued by the plaintiffs, this would yield net damages to the plaintiffs in the amount of $18.85 billion, excluding interest and attorneys’ fees and costs. Further, the plaintiffs are seeking pre-judgment interest applied at a rate of 6% compounded annually from June 2012 through the date of judgment, which combined with the net damages amount above would total $20.77 billion as of February 2014. The plaintiffs also submitted a request to be reimbursed for $61 million in attorneys’ fees and costs.
Kerr-McGee has until March 14, 2014, to submit a reply to the plaintiffs’ brief. The Opinion indicated that either party may request a hearing on the matters being briefed, and a hearing has been scheduled for April 2014. After this process, the Bankruptcy Court is expected to issue a judgment, which will then be subject to appeal.
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2013, 2012, AND 2011
17. Contingencies (Continued)
Liability Accrual Analysis Applicable accounting guidance requires the Company to accrue a liability if (a) it is probable that a liability has been incurred and (b) the amount of that liability can be reasonably estimated. That guidance also requires a liability accrual at the low end of an estimated range of probable loss when no amount within the range is a better estimate than any other amount. The Company believes that a loss in the Adversary Proceeding is probable, based on the Bankruptcy Court’s finding of liability in its Opinion. The Company considers a reasonable estimate of the range of probable loss, after all appellate processes have concluded, to be $850 million to $5.15 billion, and recorded a liability of $850 million, equal to the low end of that range. Although the Company does not believe a loss in excess of $5.15 billion to be probable, it is reasonably possible that the loss could be as high as $14.52 billion, including $61 million for attorneys’ fees and costs, but excluding any potential interest and appreciation.
The Company’s $850 million contingent liability accrual is based on the application of accounting guidance to currently available information and the Company’s judgment concerning the application of law to that information. Furthermore, the Company’s liability accrual and estimated range of probable loss do not include any amounts for interest, appreciation, or attorneys’ fees and costs, and reflects its assessment that resolution through settlement is not probable at this time. The ultimate outcome of the Adversary Proceeding is subject to significant uncertainty; accordingly, the Company’s liability accrual could change materially in the near term as events unfold and more information becomes available. In quantifying an estimated range of probable loss, the Company considered the following components of a possible award for which it could ultimately be responsible: damages, pre-judgment interest and appreciation, post-judgment interest, and attorneys’ fees and costs.
Damages The Company estimates a range of probable damages ultimately awarded to the plaintiffs to be $850 million to $5.15 billion. This estimate is based on currently available information and the Company’s opinion regarding the ultimate outcome of the Adversary Proceeding. As described below, the degree of uncertainty regarding the determination of Kerr-McGee’s allowable 502(h) Claim and the Recovery Percentage prevents the Company from determining any one amount within the estimated range of probable loss to be a better estimate than any other amount.
Critical factors in assessing the estimated range of probable loss with respect to damages are the as-yet unresolved issues of the amount of Kerr-McGee’s 502(h) Claim, and the extent to which such an offset amount would reduce damages. The Bankruptcy Court provisionally stated that the 502(h) Claim could be $10.459 billion. This 502(h) Claim amount represents the difference between (i) $14.459 billion, which is the Bankruptcy Court’s finding as to damages based on the net value of the transferred assets as of the date of IPO, and (ii) $4.0 billion, which is the mid-point in the plaintiffs’ post-petition estimate of potential legacy environmental and tort liabilities as of 2010. To calculate the offset amount that could reduce damages, the Bankruptcy Court indicated that the Recovery Percentage to be applied to Kerr-McGee’s 502(h) Claim could be either 89% or 2.8%. The Bankruptcy Court noted in its Opinion that the Plan provides that Kerr-McGee’s 502(h) Claim must be multiplied by “the percentage recovery to Allowed Class 3 General Unsecured Creditors” (Class 3 Recovery). Additionally, the Bankruptcy Court noted that 89% represents the estimated average Class 3 Recovery as stated in the Disclosure Statement filed by Tronox in its bankruptcy case. Under this scenario, the damages paid to the plaintiffs would be reduced by approximately $9.3 billion, resulting in a net damage award to plaintiffs of $5.15 billion.
The Bankruptcy Court also suggested that the Recovery Percentage might be determined after including Kerr-McGee’s 502(h) Claim with the Class 3 claims allowed under the Plan, which would have the effect of diluting Kerr-McGee’s Recovery Percentage. Under this scenario, the Recovery Percentage to be applied to Kerr-McGee’s 502(h) Claim would be 2.8%, resulting in an allowed 502(h) Claim of $293 million and a net damages award to plaintiffs of approximately $14.16 billion.
The Company believes that Kerr-McGee’s 502(h) Claim should be computed by reference to the Bankruptcy Court’s own findings in the Opinion and the language of the Plan, as opposed to being computed by reference to the plaintiffs’ post-petition estimate of the amount of legacy environmental and tort liabilities as of 2010. Accordingly, the Company believes that Kerr-McGee’s 502(h) Claim should be computed by reference to $850 million, which represents the Bankruptcy Court’s finding as to the amount of the net creditor shortfall at the IPO date, which considers the fair value of all of Tronox’s assets and liabilities including the legacy environmental and tort liabilities.
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2013, 2012, AND 2011
17. Contingencies (Continued)
Using the Bankruptcy Court’s framework for calculating the amount of Kerr-McGee’s 502(h) Claim that may be allowed, but applying the Bankruptcy Court’s finding of the $850 million net creditor shortfall instead of the plaintiffs’ post-petition estimate of legacy environmental and tort liabilities used in the Bankruptcy Court’s calculation, results in a 502(h) Claim of $13.609 billion. Furthermore, it is Kerr-McGee’s position that the applicable Recovery Percentage should be determined by the Plan, which states that Kerr-McGee is entitled to the same Class 3 Recovery actually received in the bankruptcy, which exceeded 100%. In accordance with the principles of law and equity outlined in the Opinion, the Company believes that Kerr-McGee is entitled to a Recovery Percentage of 100%, resulting in a net damage award to plaintiffs of $850 million. While it is possible that damages could be determined using a Recovery Percentage of less than 89%, the Company does not believe that this outcome is probable, and therefore a lower Recovery Percentage is not included in the Company’s estimated range of probable loss.
The following summarizes the Company’s estimated range of probable loss:
__________________________________________________________________
(1)
As determined by the Bankruptcy Court.
The Company’s estimate of the range of probable loss requires significant assumptions. As summarized above, the Company’s estimated range of probable loss uses the net creditor shortfall of $850 million on the low end and plaintiffs’ estimated legacy environmental and tort liabilities of $4.0 billion on the high end. Alternatively, the Bankruptcy Court could use $1.757 billion, which represents the Bankruptcy Court’s findings of fact related to the net present value of the environmental and tort liabilities at the IPO date. Further, the Company’s estimated range of probable loss uses a Recovery Percentage of 100% for the low end and 89% for the high end. Combinations of the above factors would result in damage estimates that are within the Company’s estimated range of probable loss.
If no 502(h) Claim is allowed, the Company could incur a liability for damages of $14.459 billion, which is materially higher than the Company’s estimated range of probable loss.
Pre-Judgment Interest and Appreciation The Bankruptcy Court did not address pre-judgment interest or appreciation in its Opinion. The Bankruptcy Court has discretion in deciding whether to award pre-judgment interest and how such interest may be calculated. The interest rate that may be charged, the date from which such interest is calculated, and whether any such interest is compounded or computed as simple interest may vary. If the Bankruptcy Court chooses to award pre-judgment interest, the amount could be material depending on the amount of net damages awarded in a judgment and the interest rates, dates, and compounding method applied for purposes of calculating the amount of pre-judgment interest.
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2013, 2012, AND 2011
17. Contingencies (Continued)
As noted above, the plaintiffs argued that, in addition to the value of the transferred assets as of 2005, the plaintiffs should recover appreciation in the value of those assets from November 2005 until June 2012. In connection with their appreciation argument, the plaintiffs also are seeking pre-judgment interest applied at a rate of 6% compounded annually from June 2012 until the date of judgment. Appreciation was not addressed by the Bankruptcy Court in its Opinion and it is unclear how any such argument by the plaintiffs will be addressed by the Bankruptcy Court, if at all.
The inherent uncertainty and lack of information, including the lack of a court-provided framework for whether or how the Bankruptcy Court would consider pre-judgment interest or appreciation, prevent the Company from formulating a reasonable estimate of the amount of pre-judgment interest or appreciation that could be included as part of a judgment. Accordingly, the Company is unable to estimate a range of probable or reasonably possible loss from pre-judgment interest or appreciation at this time, and the Company’s liability accrual does not include any such amounts. The Company will continue to evaluate the extent to which a reasonable estimate of such amounts can be made as additional information regarding the above factors becomes available. Developments that could assist the Company in estimating interest or appreciation include a judgment by the Bankruptcy Court or matters raised in potential hearings regarding the remaining issues being briefed.
Post-Judgment Interest Post-judgment interest is mandated by federal law. Post-judgment interest would not begin to accrue until the date a judgment is entered, and would continue until that judgment is paid in full. Because no judgment had been issued as of December 31, 2013, a liability for post-judgment interest has not been incurred. Accordingly, no amount for post-judgment interest has been included in the Company’s accrual or estimated range of probable loss. Further, the Company cannot estimate a range of future liability related to post-judgment interest at this time. At December 31, 2013, the annual interest rate for post-judgment interest was 0.13%.
Attorneys’ Fees and Costs In its Opinion, the Bankruptcy Court stated that the plaintiffs could request reimbursement of attorneys’ fees and costs. Based on the Company’s review of relevant law, aside from certain de minimis costs the Company believes there is no basis in law or contract that would permit the plaintiffs to recover attorneys’ fees and costs. Accordingly, the Company has not included any amount related to attorneys’ fees and costs in its estimated range of probable loss. However, it is reasonably possible that a loss related to attorneys’ fees and costs could be as high as the $61 million requested by the plaintiffs.
Tax Deductibility The Company has concluded that it is more likely than not that 88% of the $850 million loss recognized in 2013 will be deductible for U.S. tax purposes. Accordingly, the Company recognized a deferred tax benefit of $274 million in its 2013 financial statements. If additional losses are accrued in the future, the Company will evaluate the tax deductibility of any such accrual based on the facts and circumstances related to that accrual.
Liability Outlook A separate action pending before the U.S. Supreme Court to which Anadarko is not a party, Executive Benefits Insurance Agency v. Arkison, raises certain legal issues including, but not limited to, whether a bankruptcy court has authority to enter a judgment or to make a report and recommendation in a fraudulent transfer case. The Company is uncertain, at this time, what impact any ruling in that case would have on the Adversary Proceeding.
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2013, 2012, AND 2011
17. Contingencies (Continued)
As discussed above, the Company’s $850 million accrued contingent liability as of December 31, 2013, has been established based on the application of accounting guidance to currently available information and the Company’s judgment concerning the application of law to that information. A wide range of possible ultimate outcomes currently exists, and the Company may ultimately incur a liability related to the Adversary Proceeding materially in excess of the current accrued liability. The Company’s liability accrual could also change materially in the near term as events unfold and more information becomes available. Further, it is possible that the Company’s ultimate liability could exceed the currently estimated range of probable loss of $850 million to $5.15 billion. A judgment could also include an award of pre-judgment interest and appreciation, which could be material, as well as attorneys’ fees and costs. In addition, the Company does not believe that the current contingent liability of $850 million accrued at December 31, 2013, is representative of the amount it could be required to pay to reach final resolution of the Adversary Proceeding through settlement. Although the Company does not believe final resolution through settlement to be probable at this time, it expects that any such settlement would require payment of an amount substantially greater than the current accrued liability.
Following a judgment, the Company would be required either to pay the damage award or appeal the judgment. If the Company pursues its rights through the appellate process, the Company may be required to post a bond or provide sufficient security to stay execution of the judgment by the plaintiffs pending the outcome of the appellate process. As the Bankruptcy Court has not yet issued a judgment, the Company is unable to estimate whether the Company would be required to provide a bond or other security or the potential form or amount of any such bond or other security. However, depending on the amount of the judgment and other factors relating to the appellate process, satisfying any security requirements could have a potentially material negative impact on the Company’s consolidated financial position in the short term.
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, resulting in an oil spill. The well was operated by BP Exploration and Production Inc. (BP) and Anadarko held a 25% nonoperated 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-upon 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. Applicable accounting guidance requires the Company to accrue a liability if both (a) it is probable that a liability has been incurred and (b) the amount of that liability 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.
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2013, 2012, AND 2011
17. Contingencies (Continued)
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.
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.
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 through the fourth quarter of 2011, 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 4, 2014, gross OPA-related environmental costs are estimated to be $10.9 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.
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2013, 2012, AND 2011
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 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 the Company, seeking an assessment of civil penalties under the 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. The declaratory judgment addresses liability only, and does not address the amount of any civil penalty. The assessment of a civil penalty against Anadarko has been reserved until a later proceeding to be scheduled by the Louisiana District Court. 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. The appeal is pending and oral arguments were heard in December 2013. The Louisiana District Court has not yet issued a ruling.
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. For example, eleven Louisiana Parish District Attorneys appealed that decision to the U.S. Court of Appeals for the Fifth Circuit. In February 2014, the Fifth Circuit denied the appeal. If any such appeal is successful, state and/or local laws and regulations could become sources of penalties or fines against the Company.
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2013, 2012, AND 2011
17. Contingencies (Continued)
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 nonoperating partner with the United States and five affected Gulf states (Texas, Louisiana, Mississippi, Alabama, and Florida) nor the January 2013 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 was reconfirmed by the Louisiana District Court in September 2013 by excluding any evidence of Anadarko’s alleged culpability or fault in the Phase II trial, 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 Louisiana District Court dismissed all the NRD-related state law claims asserted against the Company by the states of Alabama and Louisiana. In April 2013, the states of Texas and Mississippi filed NRD-related state law claims against the Company, which were consolidated in the federal Multidistrict Litigation (MDL) action before the Louisiana District Court discussed below and are stayed until further order of the Louisiana District Court.
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.).
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2013, 2012, AND 2011
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 States of Alabama, Louisiana, Texas, and Mississippi, and several of their political subdivisions; the DOJ; environmental non-governmental organizations; 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 MDL action pending before Judge Carl Barbier in the Louisiana District Court. In March 2012, BP and the Plaintiffs’ Steering Committee 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 Louisiana District Court’s decision that only federal law, and not state law, applies to Deepwater Horizon event-related claims. Certain Mexican states also have appealed the dismissal of their claims against BP, the Company, and others. 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 first phase of the trial in the MDL commenced in February 2013 (Phase I). In April 2013, all parties rested their Phase I cases. Findings of fact, post-trial briefs, and responsive briefs were submitted in July 2013. BP, BP p.l.c., the United States, state and local governments, Halliburton Energy Services, Inc. (Halliburton), and Transocean Ltd. (Transocean) participated in Phase I. Anadarko was excused from participation in Phase I. The issues tried in Phase I included 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 each wishes to prove to the Louisiana District Court that their respective company was not at fault. The second phase of trial began in September 2013 (Phase II) and in November 2013 the parties rested their Phase II cases. The issues tried in Phase II included spill-source control and quantification of the spill for the period from April 20, 2010, until the well was capped. The Company, BP, BP p.l.c., the United States, state and local governments, Halliburton, and Transocean participated in Phase II of the trial. Prior to commencement of Phase II, the judge entered an order excluding any evidence of Anadarko’s alleged culpability or fault during Phase II.
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 for purported misstatements and omissions regarding, among other things, the Company’s liability related to the Deepwater Horizon events. The plaintiffs seek an unspecified amount of compensatory damages, including interest thereon, as well as litigation fees and costs. In November 2010, the New York District Court consolidated the two cases. In March 2012, the New York District Court granted the plaintiffs’ 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. Ellison. In July 2012, the plaintiffs filed their First Amended Consolidated Class Action Complaint. The defendants filed a renewed motion to dismiss in the Texas District Court in September 2012. In July 2013, the Texas District Court dismissed the claims relating to all but one of the alleged misstatements asserted in the plaintiffs’ complaint. The Texas District Court gave the plaintiffs 30 days to amend the complaint to attempt to rehabilitate the claims that were dismissed. The plaintiffs declined to amend the complaint. The Company filed its answer to the complaint in September 2013. The parties have not commenced discovery.
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2013, 2012, AND 2011
17. Contingencies (Continued)
In September 2010, a purported shareholder made a demand on the Company’s Board of Directors (the Board) to investigate allegations of breaches of duty by members of management related to the Deepwater Horizon events. The Board received a supplemental demand letter from the shareholder in March 2012. The Board considered each of the demand letters in January 2011 and April 2012 and determined that it would not be in the best interest of the Company to pursue the issues alleged in the demand letters. In May 2013, a shareholder derivative petition was filed in the 215th District Court of Harris County, Texas by the shareholder against Anadarko (as a nominal defendant) and certain current and former directors and officers. The petition alleges breach of fiduciary duties, unjust enrichment, abuse of control, and gross mismanagement in connection with the Deepwater Horizon events. The plaintiff seeks an unspecified amount of damages, certain changes to the Company’s governance and internal procedures, disgorgement of profits, and reimbursement of litigation fees and costs. By agreement of the parties, this case has been stayed.
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 the indemnities provided by BP against civil damages.
Remaining Liability Outlook It is 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.
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2013, 2012, AND 2011
17. Contingencies (Continued)
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, $144 million, the amount of tax originally 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, 2013.
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. In August 2013, following a determination by an administrative court in a related matter that the amount of tax in dispute was not calculated properly, the Company filed a petition requesting the withdrawal of a portion of the judicial deposit to the extent it exceeds $47 million, the amount of tax currently in dispute, and any interest on such amount.
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, 2013. The Company continues to vigorously defend itself in Brazilian courts.
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 and the resolution provided for the transfer of $1.7 billion of crude oil to the Company over a 12-month period ending in mid-2013.
Guarantees and Indemnifications The Company provides certain indemnifications in relation to asset dispositions. These indemnifications typically relate to disputes, litigation, or tax matters existing at the date of disposition. In 2013, as a result of a bankruptcy declaration by a third party, the DOI ordered Anadarko to decommission offshore wells and production facilities previously sold to the third party and not related to the Company’s current operations. During 2013, the Company recognized a decommissioning charge of $117 million, reported in other (income) expense, net in the Consolidated Statement of Income. Anadarko expects to complete decommissioning of the production facilities in 2014 and the wells in 2015. Decommissioning obligations of $21 million were included in accrued expenses and $85 million were included in other long-term liabilities on the Consolidated Balance Sheet at December 31, 2013. Actual costs may vary from this estimate; however, the Company does not believe that any such change will materially impact its consolidated financial position, results of operations, or cash flows.
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2013, 2012, AND 2011
17. Contingencies (Continued)
Environmental Matters 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 $126 million at December 31, 2013, and $81 million at December 31, 2012, for remediation and reclamation obligations. The current portion of these amounts was included in accounts payable and the long-term portion of these amounts was included in other long-term liabilities-other on the Company’s Consolidated Balance Sheets. The Company continually monitors remediation and reclamation processes and adjusts its liability for these obligations as necessary.
The Company was previously notified by the California Department of Toxic Substances Control (DTSC) that, as a result of a prior acquisition, it is one of 27 potentially responsible parties with respect to a landfill located in West Covina, California. While no agreement is in place with the DTSC, the Company has recorded a $50 million restoration liability with respect to the site, representing the current estimated obligation, which is included in the Company’s liability balance at December 31, 2013. The Company could incur additional obligations if any of the potentially responsible parties are ultimately not able to fund their allocated share of the costs or if the DTSC requires a more costly remedial approach. It is possible that the Company’s current estimate of probable loss related to this matter could change, perhaps materially, in the future.
18. Other Taxes
Taxes incurred, other than income taxes, for the years ended December 31 were as follows:
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2013, 2012, AND 2011
19. Income Taxes
The following summarizes components of income tax expense (benefit) for the years ended December 31:
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 following summarizes the sources of these differences for the years ended December 31:
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2013, 2012, AND 2011
19. Income Taxes (Continued)
The following summarizes components of total deferred taxes at December 31:
The following summarizes tax effects of temporary differences that give rise to significant portions of the deferred tax assets (liabilities) at December 31:
Changes to valuation allowances, due to changes in judgment regarding the future realizability of deferred tax assets, were an increase of $2 million in 2013, an increase of $23 million in 2012, and a decrease of $17 million in 2011. The following summarizes changes in the balance of valuation allowances on deferred tax assets:
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2013, 2012, AND 2011
19. Income Taxes (Continued)
The following summarizes taxes receivable (payable) related to income tax expense (benefit) at December 31:
Tax carryforwards available for use on future income tax returns at December 31, 2013, 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 2013 ending balance of unrecognized tax benefits presented above are potential benefits of $(129) million that would affect the effective tax rate on income if recognized. Based on the Company’s existing activities, a $99 million increase in valuation allowance would be expected to offset a portion of the potential benefit of $(129) million. Also included in the 2013 ending balance are benefits of $(18) 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 $(4) million to $(10) 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 accrued approximately $8 million of interest related to uncertain tax positions at December 31, 2013, and $28 million at December 31, 2012. The Company recognized interest and penalties in income tax expense (benefit) of $(20) million during 2013 and $9 million during 2012.
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2013, 2012, AND 2011
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 through 2013.
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 for the years ended December 31:
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, and plans for the development and operation of the Company’s LNG project in Mozambique. 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, 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.
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2013, 2012, AND 2011
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; exploration expense; depreciation, depletion, and amortization (DD&A); impairments; interest expense; total (gains) losses on derivatives, net, less net cash received in settlement of commodity derivatives; and certain items not related to the Company’s normal operations, less net income attributable to noncontrolling interests. During the periods presented, certain items not related to the Company’s normal operations included Deepwater Horizon settlement and related costs, Algeria exceptional profits tax settlement, Tronox-related contingent loss, and certain other nonoperating items included in other (income) expense, net. The Company’s definition of Adjusted EBITDAX 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. Adjusted EBITDAX also excludes interest expense to allow for assessment of segment operating results without regard to Anadarko’s financing methods or capital structure. Total (gains) losses on derivatives, net, less net cash received in settlement of commodity derivatives, are excluded from Adjusted EBITDAX because these (gains) losses are not considered a measure of asset operating performance. Finally, net income attributable to noncontrolling interests is excluded from the Company’s measure of Adjusted EBITDAX because it represents earnings that are not attributable to the Company’s common stockholders.
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 for the years ended December 31:
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2013, 2012, AND 2011
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 royalty arrangements and corporate, financing, and certain derivative activities. The following summarizes selected financial information for Anadarko’s reporting segments:
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2013, 2012, AND 2011
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.
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2013, 2012, AND 2011
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:
Major Customers Sales to Total S.A. were $2.0 billion in 2013 and $1.9 billion in 2012. These amounts are included in the oil and gas exploration and production reporting segment. In 2011, there were no sales to individual customers that exceeded 10% of the Company’s total sales revenues.
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.
While reported benefit obligations exceed the fair value of pension and other postretirement plan assets at December 31, 2013, the Company monitors the funded status of its funded pension plans to ensure that plan funds are sufficient to continue paying benefits. During 2013, the Company made contributions of $123 million to its funded pension plans, $37 million to its unfunded pension plans, and $14 million to its unfunded other postretirement benefit plans. Contributions to funded plans increase plan assets while contributions to unfunded plans are used to fund current benefit payments. The Company expects to contribute $103 million to its funded pension plans, $19 million to its unfunded pension plans, and $15 million to its unfunded other postretirement benefit plans in 2014.
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2013, 2012, AND 2011
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, 2013 and 2012, as well as the funded status of the plans and amounts recognized in the financial statements at December 31, 2013 and 2012:
__________________________________________________________________
(1)
The accumulated benefit obligation for all defined-benefit pension plans was $1.8 billion at December 31, 2013, and $2.1 billion at December 31, 2012.
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2013, 2012, AND 2011
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 2014, an estimated $26 million of net actuarial loss for the pension and other postretirement plans will be amortized from accumulated other comprehensive income into net periodic benefit cost.
The following summarizes the weighted-average assumptions used by the Company in determining the pension and other postretirement benefit obligations at December 31:
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2013, 2012, AND 2011
22. Pension Plans, Other Postretirement Benefits, and Defined-Contribution Plans (Continued)
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. The discount-rate assumption used by the Company represents an estimate of the interest rate at which the pension and other postretirement benefit obligations could effectively be settled on the measurement date. 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, 2013, an 8.00% annual rate of increase in the per-capita cost of covered health care benefits for 2014 was assumed for purposes of measuring other postretirement benefit obligations. 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. This rate is expected to gradually decrease to 5.00% in 2019 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:
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2013, 2012, AND 2011
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 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 2013 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.
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2013, 2012, AND 2011
22. Pension Plans, Other Postretirement Benefits, and Defined-Contribution Plans (Continued)
The fair value of the Company’s pension plan assets by asset class 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 $2 million for 2013 and $4 million for 2012, primarily related to Level 1 investments.
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2013, 2012, AND 2011
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 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.
ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2013, 2012, AND 2011
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, the most significant of which is 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 $78 million for 2013, $55 million for 2012, and $41 million for 2011, related to these plans.
ANADARKO PETROLEUM CORPORATION
SUPPLEMENTAL QUARTERLY INFORMATION
(Unaudited)
Quarterly Financial Data
The following summarizes quarterly financial data for 2013 and 2012:
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 2013, 2012, and 2011 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 natural-gas liquids (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 2013, Anadarko added 145 MMBOE of proved reserves through extensions and discoveries as the result of successful drilling primarily in the United States. Reserves revisions for 2013 include an increase of 370 MMBOE primarily related to successful infill drilling in large onshore areas, such as Wattenberg, Greater Natural Buttes, and the Eagleford shale, and a decrease of 23 MMBOE primarily due to lower ethane prices. Sales of proved reserves in place were 12 MMBOE, related to domestic assets. Acquisitions of proved reserves were 36 MMBOE, also related to domestic assets.
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 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 onshore 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 large onshore areas, such as the Greater Natural Buttes, Wattenberg, and Pinedale fields, and an increase of 8 MMBOE primarily due to higher oil prices. Sales of proved reserves in place were 29 MMBOE, related to onshore domestic assets.
Prices used to compute the information presented in the following tables are adjusted only for fixed and determinable amounts under provisions in existing contracts. These prices, before adjustments, were $3.67, $2.76, and $4.12 per MMBtu of natural gas and $96.78, $94.71, and $96.19 per barrel of oil for 2013, 2012, and 2011.
ANADARKO PETROLEUM CORPORATION
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION
AND PRODUCTION ACTIVITIES
(Unaudited)
Oil and Gas Reserves (Continued)
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 410 MMBOE for 2013, 383 MMBOE for 2012, and 203 MMBOE for 2011.
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, liquefied natural gas (LNG) facilities costs, and other corporate activities are not included.
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, LNG facilities costs, and other corporate activities are not included.
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 provided for the transfer of $1.7 billion of crude oil to the Company over a 12-month period ending in mid-2013. 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.
ANADARKO PETROLEUM CORPORATION
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION
AND PRODUCTION ACTIVITIES
(Unaudited)
Results of Operations (Continued)
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 2013, 2012, and 2011 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 $3.67, $2.76, and $4.12 per MMBtu of natural gas and $96.78, $94.71, and $96.19 per barrel of oil, for 2013, 2012, and 2011. 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.
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
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
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)
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
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, 2013.
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 2013 that materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
Item 9B. Other Information
None.
PART III
Item 10. Directors, Executive Officers, and Corporate Governance
See Anadarko Board of Directors, Corporate Governance-Board of Directors, Corporate Governance-Committees of the Board and Section 16(a) Beneficial Ownership Reporting Compliance in the Anadarko Petroleum Corporation Proxy Statement (Proxy Statement), for the Annual Meeting of Stockholders of Anadarko Petroleum Corporation to be held May 13, 2014 (to be filed with the Securities and Exchange Commission prior to April 3, 2014), 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
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 2013, Compensation and Benefits Committee Report on 2013 Executive Compensation, Compensation Discussion and Analysis and Executive Compensation in the Proxy Statement, each of which is incorporated herein by reference. The Compensation and Benefits Committee Report and related information incorporated by reference herein shall not be deemed “soliciting material” or to be “filed” with the Securities and Exchange Commission, nor shall such information be incorporated by reference into any future filing under the Securities Act of 1933 or Securities Exchange Act of 1934, each as amended, except to the extent that the Company specifically incorporates it by reference into such filing.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
See Security Ownership of Certain Beneficial Owners and Management in the Proxy Statement and Securities Authorized for Issuance under Equity Compensation Plans under Item 5 of this Form 10-K, which are incorporated herein by reference.
Item 13. Certain Relationships and Related Transactions, and Director Independence
See Corporate Governance-Board of Directors and Transactions with Related Persons in the Proxy Statement, each of which is incorporated herein by reference.
Item 14. Principal Accounting Fees and Services
See Independent Auditor in the Proxy Statement, which is incorporated herein by reference.
PART IV
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 87.
(2)
Exhibits not incorporated by reference to a prior filing are designated by an asterisk (*) and are filed herewith or double asterisk (**) and are furnished herewith; all exhibits not so designated are incorporated herein by reference to a prior filing as indicated.
Exhibit
Number
Description
File
Number
(i)
Agreement and Plan of Merger dated as of June 22, 2006, among Anadarko Petroleum Corporation, APC Acquisition Sub, Inc. and Kerr-McGee Corporation, filed as Exhibit 2.2 to Form 8-K filed on June 26, 2006
1-8968
(i)
Restated Certificate of Incorporation of Anadarko Petroleum Corporation, dated May 21, 2009, filed as Exhibit 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, filed as Exhibit 3.1 to Form 8-K filed on May 15, 2012
1-8968
(i)
Trustee Indenture dated as of September 19, 2006, Anadarko Petroleum Corporation to The Bank of New York Trust Company, N.A., filed as Exhibit 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., filed as Exhibit 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., filed as Exhibit 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, filed as Exhibit 4.1 to Form 8-K filed on March 6, 2009
1-8968
(v)
Form of 7.625% Senior Notes due 2014, filed as Exhibit 4.2 to Form 8-K filed on March 6, 2009
1-8968
(vi)
Form of 8.700% Senior Notes due 2019, filed as Exhibit 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, filed as Exhibit 4.1 to Form 8-K filed on June 12, 2009
1-8968
(viii)
Form of 5.75% Senior Notes due 2014, filed as Exhibit 4.2 to Form 8-K filed on June 12, 2009
1-8968
(ix)
Form of 6.95% Senior Notes due 2019, filed as Exhibit 4.3 to Form 8-K filed on June 12, 2009
1-8968
(x)
Form of 7.95% Senior Notes due 2039, filed as Exhibit 4.4 to Form 8-K filed on June 12, 2009
1-8968
Exhibit
Number
Description
File
Number
(xi)
Officers’ Certificate of Anadarko Petroleum Corporation dated March 9, 2010, establishing the 6.200% Senior Notes due 2040, filed as Exhibit 4.1 to Form 8-K filed on March 16, 2010
1-8968
(xii)
Form of 6.200% Senior Notes due 2040, filed as Exhibit 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, filed as Exhibit 4.1 to Form 8-K filed on August 12, 2010
1-8968
(xiv)
Form of 6.375% Senior Notes due 2017, filed as Exhibit 4.2 to Form 8-K filed on August 12, 2010
1-8968
†
(i)
1998 Director Stock Plan of Anadarko Petroleum Corporation, effective January 30, 1998, filed as 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, filed as Exhibit 10.1 to Form 8-K filed on November 17, 2005
1-8968
†
(iii)
Anadarko Petroleum Corporation Amended and Restated 1999 Stock Incentive Plan, filed as 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, filed as Exhibit 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, filed as Exhibit 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), filed as Exhibit 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, filed as Exhibit 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), filed as Exhibit 10.3 to Form 8-K filed on November 13, 2007
1-8968
†
(ix)
Form of Anadarko Petroleum Corporation 1999 Stock Incentive Plan Restricted Stock Agreement, filed as Exhibit 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, filed as Exhibit 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, filed as Exhibit 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, filed as Exhibit 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, filed as Exhibit 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, filed as Exhibit 10(b)(ii) to Form 10-Q for quarter ended June 30, 2003, filed on August 11, 2003
1-8968
Exhibit
Number
Description
File
Number
†
(xv)
Form of Key Employee Change of Control Contract (2011), filed as Exhibit 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., filed as Exhibit 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), filed as Exhibit 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), filed as Exhibit 10.2 to Form 8-K filed on November 13, 2007
1-8968
†
(xix)
Anadarko Petroleum Corporation Estate Enhancement Program, filed as Exhibit
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, filed as Exhibit 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, filed as Exhibit 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, filed as Exhibit 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, filed as Exhibit 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, filed as Exhibit 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, filed as Exhibit 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, filed as Exhibit 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, filed as Exhibit 10 to Form 8-K filed on September 3, 2004
1-8968
(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, filed as Exhibit 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, filed as Exhibit 10(i) to Form 10-Q for quarter ended September 30, 2011, filed on October 31, 2011
1-8968
Exhibit
Number
Description
File
Number
†
(xxx)
Anadarko Petroleum Corporation 2008 Omnibus Incentive Compensation Plan, effective as of May 20, 2008, filed as Exhibit 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, filed as Exhibit 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, filed as Exhibit 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, filed as Exhibit 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, filed as Exhibit 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, filed as Exhibit 10.3 to Form 8-K filed on May 27, 2008
1-8968
†
(xxxvi)
Form of Award Letter for Anadarko Petroleum Corporation 2008 Director Compensation Plan (2013), filed as Exhibit 10(i) to Form 10-Q for quarter ended June 30, 2013, filed on July 29, 2013
1-8968
†
(xxxvii)
Anadarko Petroleum Corporation Benefits Trust Agreement, amended and restated effective as of November 5, 2008, filed as Exhibit 10(lvi) to Form 10-K for year ended December 31, 2008, filed on February 25, 2009
1-8968
†
(xxxviii)
Anadarko Petroleum Corporation Deferred Compensation Plan (as amended and restated effective as of January 1, 2010), filed as Exhibit 10(xlvi) to Form 10-K for year ended December 31, 2009, filed on February 23, 2010
1-8968
†
(xxxvix)
Amended and Restated Employment Agreement between James T. Hackett and Anadarko Petroleum Corporation, dated November 11, 2009, filed as Exhibit 10.4 to Form 8-K filed on November 13, 2009
1-8968
(xl)
Letter Agreement between James T. Hackett and Anadarko Petroleum Corporation, dated February 16, 2012, filed as Exhibit 10.1 to Form 8-K filed on February 21, 2012
1-8968
†
(xli)
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, filed as Exhibit 10 to Form 10-Q for quarter ended June 30, 2010, filed on August 3, 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., filed as Exhibit 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, filed as Exhibit 10.2 to Form 8-K filed on February 21, 2012
1-8968
†
(xliv)
Time Sharing Agreement between R. A. Walker and Anadarko Petroleum Corporation, dated May 15, 2012, filed as Exhibit 10(ii) to Form 10-Q for quarter ended June 30, 2012, filed on August 8, 2012
1-8968
Exhibit
Number
Description
File
Number
†
(xlv)
Anadarko Petroleum Corporation 2012 Omnibus Incentive Compensation Plan, effective as of May 15, 2012, filed as Exhibit 10.1 to Form 8-K filed on May 15, 2012
1-8968
†
(xlvi)
Form of Anadarko Petroleum Corporation 2012 Omnibus Incentive Compensation Plan Stock Option Award Agreement, filed as Exhibit 10.2 to Form 8-K filed on May 15, 2012
1-8968
†
(xlvii)
Form of Anadarko Petroleum Corporation 2012 Omnibus Incentive Compensation Plan Restricted Stock Unit Award Agreement, filed as Exhibit 10.3 to Form 8-K filed on May 15, 2012
1-8968
†
(xlviii)
Form of Anadarko Petroleum Corporation 2012 Omnibus Incentive Compensation Plan Performance Unit Award Agreement, filed as Exhibit 10.4 to Form 8-K filed on May 15, 2012
1-8968
†
(xlix)
Form of Anadarko Petroleum Corporation 2012 Omnibus Incentive Compensation Plan Restricted Stock Unit Award Agreement, filed as Exhibit 10.1 to Form 8-K filed on November 9, 2012
1-8968
†
(l)
Form of Anadarko Petroleum Corporation 2012 Omnibus Incentive Compensation Plan Performance Unit Award Agreement, filed as Exhibit 10.2 to Form 8-K filed on November 9, 2012
1-8968
†
(li)
Form of U.K. Award Letter for Anadarko Petroleum Corporation 2008 Director Compensation Plan, filed as Exhibit 10.5 to Form 8-K filed on May 15, 2012
1-8968
†
(lii)
Amended and Restated Performance Unit Award Agreement, effective November 5, 2012, for Mr. R. A. Walker, filed as Exhibit 10.3 to Form 8-K filed on November 9, 2012
1-8968
*
Computation of Ratios of Earnings to Fixed Charges and Earnings to Combined Fixed Charges and Preferred Stock Dividends
*
List of Subsidiaries
*
(i)
Consent of KPMG LLP
*
(ii)
Consent of Miller and Lents, Ltd.
*
Power of Attorney
*
(i)
Rule 13a-14(a)/15d-14(a) Certification-Chief Executive Officer
*
(ii)
Rule 13a-14(a)/15d-14(a) Certification-Chief Financial Officer
**
Section 1350 Certifications
*
Report of Miller and Lents, Ltd.
Exhibit
Number
Description
File
Number
*
.INS
XBRL Instance Document
*
.SCH
XBRL Schema Document
*
.CAL
XBRL Calculation Linkbase Document
*
.DEF
XBRL Definition Linkbase Document
*
.LAB
XBRL Label Linkbase Document
*
.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.
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.
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 28, 2014
By:
/s/ ROBERT G. GWIN
Robert G. Gwin
Executive 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 28, 2014.
Name and Signature
Title
(i) Principal executive officer and director:
/s/ R. A. WALKER
Chairman, President and Chief Executive Officer
R. A. Walker
(ii) Principal financial officer:
/s/ ROBERT G. GWIN
Executive Vice President, Finance and Chief Financial Officer
Robert G. Gwin
(iii) Principal accounting officer:
/s/ M. CATHY DOUGLAS
Senior Vice President, Chief Accounting Officer and Controller
M. Cathy Douglas
(iv) Directors:*
ANTHONY R. CHASE
KEVIN P. CHILTON
H. PAULETT EBERHART
PETER J. FLUOR
RICHARD L. GEORGE
PRESTON M. GEREN III
CHARLES W. GOODYEAR
JOHN R. GORDON
ERIC D. MULLINS
PAULA ROSPUT REYNOLDS
* Signed on behalf of each of these persons and on his own behalf:
By:
/s/ ROBERT G. GWIN
Robert G. Gwin, Attorney-in-Fact