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(1)

Combined and reported as revisions of prior estimates in the Company’s Supplemental Information on Oil and Gas Exploration and Production Activities (Supplemental Information) under Item 8 of this Form 10-K. Reserves related to infill-drilling additions are treated as positive revisions. Price-related revisions reflect the impact of current prices on the reserves balance at the beginning of each year. Other non-price-related revisions reflect the net change of performance and cost updates, updates to development plans, and all other year-end updates.

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•	Performance  The Company experienced an overall increase in PUDs of 32 MMBOE due to performance. Upward revisions of 39 MMBOE were driven primarily by performance improvements in the DJ and Delaware basin areas. Downward revisions of 7 MMBOE were primarily due to performance based reductions in various areas in the Gulf of Mexico.

•	Infill-drilling activities  The Company added 64 MMBOE of PUDs associated with infill-drilling activities, of which 46 MMBOE was in the DJ basin, 13 MMBOE in the Lucius and Holstein areas in the Gulf of Mexico and the remaining in the Ghana Jubilee field.

•	Development plan updates  The majority of revisions associated with updates to development plans occurred in the DJ basin due to ongoing optimization of development activity.

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(1)	Excludes the impact of commodity derivatives.

(2)	Excludes ad valorem and severance taxes.

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(1)	The Company’s fee mineral acreage is primarily undeveloped.

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(1)	Wells suspended or waiting on completion include exploration and development wells where drilling has occurred, but the wells are awaiting the completion of hydraulic fracturing or other completion activities or the resumption of drilling in the future.

(2)	There were 107 MMBOE of PUDs primarily assigned to U.S. onshore development wells suspended or waiting on completion at December 31, 2017. The Company expects to convert these reserves to developed status within five years of their initial disclosure.

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(1)	Includes wells containing multiple completions as follows:

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•	the U.S. Clean Air Act, which restricts the emission of air pollutants from many sources, imposes various pre-construction, monitoring, and reporting requirements, which the EPA has relied upon as authority for adopting climate change regulatory initiatives relating to greenhouse gas (GHG) emissions

•	the U.S. Federal Water Pollution Control Act, also known as the federal Clean Water Act, which regulates discharges of pollutants from facilities to state and federal waters and establishes the extent to which waterways are subject to federal jurisdiction and rulemaking as protected waters of the United States

•	the U.S. Oil Pollution Act of 1990, which subjects owners and operators of vessels, onshore facilities, and pipelines, as well as lessees or permittees of areas in which offshore facilities are located, to liability for removal costs and damages arising from an oil spill in waters of the United States

•	U.S. Department of the Interior regulations, which relate to offshore oil and natural-gas operations in U.S. waters and impose obligations for establishing financial assurances for decommissioning activities, liabilities for pollution cleanup costs resulting from operations, and potential liabilities for pollution damages

•	the Comprehensive Environmental Response, Compensation and Liability Act of 1980, which imposes liability on generators, transporters, and arrangers of hazardous substances at sites where hazardous substance releases have occurred or are threatening to occur

•	the U.S. Resource Conservation and Recovery Act, which governs the generation, treatment, storage, transport, and disposal of solid wastes, including hazardous wastes

•	the U.S. Safe Drinking Water Act, which ensures the quality of the nation’s public drinking water through adoption of drinking water standards and control over the injection of waste fluids into below-ground formations that may adversely affect drinking water sources

•	the U.S. Emergency Planning and Community Right-to-Know Act, which requires facilities to implement a safety hazard communication program and disseminate information to employees, local emergency planning committees, and response departments on toxic chemical uses and inventories

•	the U.S. Occupational Safety and Health Act, which establishes workplace standards for the protection of the health and safety of employees, including the implementation of hazard communications programs designed to inform employees about hazardous substances in the workplace, potential harmful effects of these substances, and appropriate control measures

•	the Endangered Species Act, which restricts activities that may affect federally identified endangered and threatened species or their habitats through the implementation of operating restrictions or a temporary, seasonal, or permanent ban in affected areas

•	the National Environmental Policy Act, which requires federal agencies, including the Department of the Interior, to evaluate major agency actions having the potential to impact the environment and that may require the preparation of environmental assessments and more detailed environmental impact statements that may be made available for public review and comment

•	the U.S. Department of Transportation regulations, which relate to advancing the safe transportation of energy and hazardous materials and emergency response preparedness

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•	the Company’s assumptions about energy markets

•	production and sales volume levels

•	levels of oil, natural-gas, and NGLs reserves

•	operating results

•	competitive conditions

•	technology

•	availability of capital resources, levels of capital expenditures, and other contractual obligations

•	supply and demand for, the price of, and the commercialization and transporting of oil, natural gas, NGLs, and other products or services

•	volatility in the commodity-futures market

•	weather

•	inflation

•	availability of goods and services, including unexpected changes in costs

•	drilling and other operational risks

•	processing volumes, pipeline throughput, and produced water disposal

•	general economic conditions, nationally, internationally, or in the jurisdictions in which the Company is, or in the future may be, doing business

•	the Company’s inability to timely obtain or maintain permits or other governmental approvals, including those necessary for drilling and/or development projects

•

legislative or regulatory changes, including changes relating to hydraulic fracturing; retroactive royalty or production tax regimes; deepwater drilling and permitting regulations; derivatives reform; changes in state, federal, and foreign income taxes; environmental regulation, including regulations related to climate change; environmental risks; and liability under international, provincial, federal, regional, state, tribal, local, and foreign environmental laws and regulations

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•	civil or political unrest or acts of terrorism in a region or country

•	the creditworthiness and performance of the Company’s counterparties, including financial institutions, operating partners, and other parties

•	volatility in the securities, capital, or credit markets and related risks such as general credit, liquidity, and interest-rate risk

•	the Company’s ability to successfully monetize select assets, repay or refinance its debt, and the impact of changes in the Company’s credit ratings

•	the Company’s ability to successfully complete its share-repurchase program

•	uncertainties associated with acquired properties and businesses

•	disruptions in international oil and NGLs cargo shipping activities

•	physical, digital, cyber, internal, and external security breaches

•	supply and demand, technological, political, governmental, and commercial conditions associated with long-term development and production projects in domestic and international locations

•	the outcome of pending and future regulatory, legislative, or other proceedings or investigations, including the investigation by the NTSB related to the Company’s operations in Colorado, and continued or additional disruptions in operations that may occur as the Company complies with regulatory orders or other state or local changes in laws or regulations in Colorado

•	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

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•	the domestic and worldwide supply of, and demand for, oil, natural gas, and NGLs

•	volatility and trading patterns in the commodity-futures markets

•	the cost of exploring for, developing, producing, transporting, and marketing oil, natural gas, and NGLs

•	the level of global oil and natural-gas inventories

•	weather conditions

•	the level of U.S. exports of oil, LNG, or NGLs

•	the ability of the members of OPEC and other producing nations to agree to and maintain production levels

•	the worldwide military and political environment, civil and political unrest worldwide, including in Africa and the Middle East, uncertainty or instability resulting from the escalation or additional outbreak of armed hostilities, or acts of terrorism in the United States or elsewhere

•	the effect of worldwide energy conservation and environmental protection efforts

•	the price and availability of alternative and competing fuels

•	the level of foreign imports of oil, natural gas, and NGLs

•	domestic and foreign governmental laws, regulations, and taxes

•	shareholder activism or activities by non-governmental organizations to limit certain sources of funding for the energy sector or restrict the exploration, development, and production of oil and natural gas

•	the proximity to, and capacity of, natural-gas pipelines and other transportation facilities

•	general economic conditions worldwide

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•	adversely affect our financial condition, liquidity, ability to finance planned capital expenditures, and results of operations

•	reduce the amount of oil, natural gas, and NGLs that we can produce economically

•	cause us to delay or postpone some of our capital projects

•	reduce our revenues, operating income, or cash flows

•	reduce the amounts of our estimated proved oil, natural-gas, and NGLs reserves

•	reduce the carrying value of our oil, natural-gas, and midstream properties due to recognizing additional impairments of proved properties, unproved properties, exploration assets, and midstream facilities

•	reduce the standardized measure of discounted future net cash flows relating to oil, natural-gas, and NGLs reserves

•	limit our access to, or increasing the cost of, sources of capital such as equity and long-term debt

•	adversely affect the ability of our partners to fund their working interest capital requirements

•	issuance of permits in connection with exploration, drilling, production, produced water disposal, and other midstream activities

•	drilling activities on certain lands lying within wilderness, wetlands, and other protected areas

•	types, quantities, and concentrations of emissions, discharges, and authorized releases

•	generation, management, and disposition of waste materials

•	offshore oil and natural-gas operations and decommissioning of abandoned facilities

•	reclamation and abandonment of wells and facility sites

•	remediation of contaminated sites

•	protection of endangered species

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Ground-Level Ozone Standards. In October 2015, the EPA issued a rule under the Clean Air Act, lowering the National Ambient Air Quality Standard for ground-level ozone from 75 parts per billion to 70 parts per billion under both the primary and secondary standards to provide requisite protection of public health and welfare, respectively. The EPA did not meet the October 1, 2017 deadline for designating non-attainment areas but, on November 6, 2017, issued final designations for areas in the United States that are in attainment with the 70 parts per billion standard, representing approximately 85% of the U.S. counties that became effective on January 18, 2018. For the remaining areas of the United States, the EPA has not yet prepared final designations, but is expected to do so in a separate future action in the first half of 2018. Reclassification of areas or imposition of more stringent standards may make it more difficult to construct new or modified facilities in new designated non-attainment areas. Also, states that are designated as non-attainment are expected to implement more stringent regulations, which could, among other things, require installation of new emission controls on some of our equipment, result in longer permitting timelines, and significantly increase our capital expenditures and operating costs.

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Reduction of Methane Emissions by the Oil and Gas Industry. In June 2016, the EPA published a final rule establishing new emissions standards for methane and additional standards for volatile organic compounds from certain new, modified, and reconstructed oil and natural-gas production and natural-gas processing and transmission facilities. The EPA’s rule is under the New Source Performance Standards, Subpart OOOOa, that requires certain new, modified, or reconstructed facilities in the oil and natural-gas sector to reduce these methane gas and volatile organic compound emissions. These Subpart OOOOa standards would expand previously issued New Source Performance Standards, Subpart OOOO, published by the EPA in 2012 by using certain equipment-specific emissions control practices with respect to, among other things, hydraulically fractured oil and natural-gas well completions, fugitive emissions from well sites and compressors, and pneumatic pumps. However, in June 2017, the EPA published a proposed rule to stay certain portions of the June 2016 standards for two years and re-evaluate the entirety of the 2016 standards but the EPA has not yet published a final rule and, as a result, the June 2016 standards remain in effect, but future implementation of the standards are uncertain at this time. Furthermore, in June 2017, the Bureau of Land Management (BLM) stayed a rule published in November 2016 imposing requirements to reduce methane emissions from venting, flaring, and leaking on public lands. On October 4, 2017, the U.S. District Court for the Northern District of California struck down the June 2017 stay. However, on December 8, 2017, the BLM published a final rule that will temporarily suspend certain requirements contained in the November 2016 final rule until January 17, 2019. The December 2017 compliance extension was challenged by non-governmental organizations and several states on December 19, 2017. Notwithstanding the current uncertainty, we have taken measures to enter into a voluntary regime, together with certain other oil and natural gas exploration and production operators, to reduce methane emissions. At the state level, some states are considering and others have issued requirements, including Colorado where we conduct operations, for the performance of leak-detection programs that identify and repair methane leaks at certain oil and natural-gas sources. Compliance with these rules or future methane regulations will, among other things, require installation of new emission controls on some of our equipment and increase our capital expenditures and operating costs.

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Induced Seismic Activity Associated with Oilfield Disposal Wells. We dispose of wastewater generated from oil and natural-gas production operations directly or through the use of third parties. The legal requirements related to the disposal of wastewater in underground injections wells are subject to change based on concerns of the public or governmental authorities regarding such disposal activities. One such concern relates to recent seismic events near injection wells used for the disposal of produced water resulting from oil and natural-gas activities. In response to concerns regarding induced seismicity, regulators in some states have imposed, or are considering imposing, additional requirements in the permitting of produced water disposal wells or otherwise to assess any relationship between seismicity and the use of such wells. For example, Colorado developed and follows guidance when issuing underground injection control permits to limit the maximum injection pressure, rate, and volume of water. Oklahoma has issued rules for wastewater disposal wells that imposed certain permitting and operating restrictions and reporting requirements on disposal wells in proximity to faults and also, from time to time, is developing and implementing plans directing certain wells where seismic incidents have occurred to restrict or suspend disposal well operations. The Texas Railroad Commission has also adopted similar permitting, operating, and reporting rules for disposal wells. In addition, ongoing class action lawsuits, to which we are not currently a party, allege that disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. These developments could result in additional regulation and restrictions on the use of injection wells by us or by commercial disposal well vendors whom we may use from time to time to dispose of wastewater, which could have a material adverse effect on our capital expenditures and operating costs, financial condition, and results of operations.

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Reduction of Greenhouse Gas Emissions. The U.S. Congress and the EPA, in addition to some state and regional authorities, have in recent years considered legislation or regulations to reduce emissions of GHGs. These efforts have included consideration of cap-and-trade programs, carbon taxes, GHG reporting and tracking programs, and regulations that directly limit GHG emissions from certain sources. In the absence of federal GHG-limiting legislation, the EPA has determined that GHG emissions present a danger to public health and the environment and has adopted regulations that, among other things, restrict emissions of GHGs under existing provisions of the Clean Air Act and may require the installation of “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 together with other criteria pollutants. Also, certain of our operations are subject to EPA rules requiring the monitoring and annual reporting of GHG emissions from specified onshore and offshore production sources. In December 2015, the United States joined the international community at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France that prepared an agreement requiring member countries to review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals every five years beginning in 2020. Although this international agreement does not create any binding obligations for nations to limit their GHG emissions, it does include pledges to voluntarily limit or reduce future emissions. In August 2017, the U.S. State Department informed the United Nations of the intent of the United States to withdraw from the Paris Climate Agreement, which would result in an effective exit date of November 2020. Notwithstanding any withdrawal from this agreement, the implementation of substantial limitations on GHG emissions in areas where we conduct operations could adversely affect demand for the oil and natural gas we produce and lower the value of our reserves.

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•	increasing our vulnerability to general adverse economic and industry conditions

•	limiting our ability to fund future working capital and capital expenditures, to engage in future acquisitions or development activities, or to otherwise fully realize the value of our assets and opportunities 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

•	limiting our flexibility in planning for, or reacting to, changes in the industry in which we operate

•	placing us at a competitive disadvantage compared to our competitors that have less debt and/or fewer financial commitments

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•	estimated future production from an area is consistent with historical production from similar producing areas

•	assumed effects of regulation by governmental agencies and court rulings

•	assumptions concerning future oil, natural-gas, and NGLs prices, future operating costs, and capital expenditures

•	estimates of future severance and excise taxes, workover costs, and remedial costs

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•	hurricanes and other adverse weather conditions

•	geological complexities and water depths associated with such operations

•	limited number of partners available to participate in projects

•	oilfield service costs and availability

•	compliance with environmental, safety, and other laws and regulations

•	terrorist attacks or piracy

•	remediation and other costs and regulatory changes resulting from oil spills or releases of hazardous materials

•	failure of equipment or facilities

•	response capabilities for personnel, equipment, or environmental incidents

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•	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

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•	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, natural-gas, or NGLs prices

•	project approvals and funding by joint-venture partners

•	timely issuance of permits and licenses by governmental agencies or legislative and other governmental approvals

•	weather conditions

•	availability of qualified personnel

•	civil and political environment of, and existing infrastructure in, the country or region in which the project is located

•	manufacturing and delivery schedules of critical equipment

•	commercial arrangements for pipelines, tankers, and related equipment to transport and market hydrocarbons

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•	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

•	lack of availability or delays in the delivery of technology, equipment, or resources for operations

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•	the validity of our assumptions about, among other things, reserves, estimated production, revenues, capital expenditures, operating expenses, and costs

•	the assumption of environmental, decommissioning, and other liabilities, and losses or costs for which we are not indemnified or for which our indemnity is inadequate

•	a failure to attain or maintain compliance with environmental, safety, and other governmental regulations

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Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

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(1)

During the fourth quarter of 2017, (i) 21.9 million shares were purchased under the $3.0 Billion Share-Repurchase Program and (ii) 67 thousand shares were purchased related to stock received by the Company for the payment of withholding taxes due on employee share issuances under share-based compensation plans. For additional information, see Note 22—Share-Based Compensation in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

(2)

At December 31, 2017, the Company had repurchased, through open-market and private transactions, approximately $1.1 billion of common stock under its share-repurchase program in place at year end, which was expanded by $500 million in February 2018 under the $3.0 Billion Share-Repurchase Program. In February 2018, the Company completed the repurchase of an additional 8.5 million shares as part of an ASR Agreement. For additional information, see Note 20—Stockholders’ Equity in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

(3)

In October 2017, the Company entered into an ASR Agreement to complete $1.0 billion of the $3.0 Billion Share-Repurchase Program and received an initial delivery of 15.7 million shares. The transaction was completed in December 2017, at which time the Company received an additional 5.1 million shares to settle the agreement. The settlement price was determined by the volume-weighted average price of the shares during the term less a negotiated settlement price adjustment. During the fourth quarter of 2017, the Company repurchased an additional 1.1 million shares for $59 million through open-market purchases. For additional information, see Note 20—Stockholders’ Equity in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

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(1)	Consolidated for Anadarko and its subsidiaries. Certain amounts for prior years have been reclassified to conform to the current presentation.

(2)	Includes one-time deferred tax benefit of $1.2 billion in 2017 related to Tax Reform Legislation.

(3)	Includes Tronox settlement payment of $5.2 billion in 2015.

(4)	Excludes WES and WGP.

(5)	Natural gas is converted to equivalent barrels at the rate of 6,000 cubic feet of gas per barrel.

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Delaware Basin  Anadarko plans to allocate approximately $1.0 billion toward upstream and an additional $500 million toward Anadarko midstream investments. This program supports the continuation of the Company's efforts to build out one of the most expansive and integrated infrastructure positions in the region. The Company also is advancing its efforts to capture operatorship on 70% of its acreage position, primarily in Reeves and Loving counties. Additionally, Anadarko continues to progress the construction of three ROTFs to support its more cost-effective and environmentally beneficial tankless battery design field-wide, while also securing necessary gathering, processing, and takeaway capacity. This comprehensive build-out plan and phased development approach in the basin is expected to deliver incremental oil sales volumes during the second half of 2018, with total-year Delaware basin oil sales volumes expected to increase more than 50% relative to 2017. During 2018, the Company plans to average seven operated rigs and six completion crews.

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DJ Basin  Anadarko expects to invest approximately $950 million on upstream activities and an additional $50 million toward Anadarko midstream investments. The Company has implemented a new completion design in the field, which has resulted in a 20% improvement in average well recovery. Anadarko expects to increase year-over-year oil sales volumes from the DJ basin by more than 30% and plans to average five operated rigs and three completions crews in the basin during the year.

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Deepwater Gulf of Mexico  Anadarko expects to allocate approximately $1.0 billion toward its deepwater Gulf of Mexico operations. The majority of these investments are expected to be directed toward high-return oil development opportunities near operated infrastructure at Lucius, Horn Mountain, Marlin, Holstein, and Marco Polo. The Company plans to operate two floating drillships and one platform rig and spud approximately nine development wells in the Gulf of Mexico during the year.

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International  Anadarko plans to allocate approximately $150 million toward its international cash-generating operations in Algeria and Ghana. These investments will support further drilling in the TEN development area, which is expected to commence in early 2018, as well as additional drilling operations in the Jubilee field following the Ghanaian government's recent approval of the full-field plan of development.

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Exploration  The Company's exploration investments in 2018 are expected to total approximately $200 million. Exploration spending will primarily be focused on the Gulf of Mexico, where the Company plans to drill identified prospects near existing operated infrastructure with one floating drillship. The Company plans to allocate additional exploration investment to the U.S. onshore as it continues to identify future areas that could make a material and scalable addition to its portfolio.

•	LNG  The Company expects to invest approximately $150 million to advance the Mozambique LNG project toward FID. This includes funding Anadarko's portion of the costs associated with preparing the site of the future onshore LNG park.

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•	The Company’s oil sales volumes averaged 355 MBbls/d, representing a 12% increase from 2016, primarily due to increased volumes from the Gulf of Mexico, partially offset by the divestiture of certain U.S. onshore assets in 2017 and 2016.

•	The Company’s overall sales-volume product mix increased to 53% oil in 2017, compared to 40% in 2016, which significantly improved margins and returns.

•	Total sales volumes in the Delaware basin averaged 63 MBOE/d, representing a 41% increase from 2016, and oil sales volumes in the Delaware basin increased 13 MBbls/d, representing a 52% increase from 2016, primarily due to continued drilling and completion activities.

•	WES acquired a third party’s 50% nonoperated interest in the DBJV System in exchange for WES’s 33.75% interest in nonoperated Marcellus midstream assets and $155 million in cash.

•	The Company received net proceeds of approximately $4.0 billion from divestitures of certain U.S. onshore assets during 2017.

•	Oil sales volumes averaged 121 MBbls/d, representing an 85% increase from 2016, primarily due to the GOM Acquisition and continued tie-back activity at several facilities, partially offset by deferred production as a result of Hurricanes Harvey, Irma, and Nate and nonoperated field downtime during the second half of 2017.

•	The International Tribunal for the Law of the Sea issued a ruling in September 2017 regarding the delimitation of the maritime boundary between Ghana and Côte d’Ivoire in the Atlantic Ocean. The new maritime boundary as determined by the tribunal does not affect the TEN fields, and the operator now plans to resume development drilling in early 2018.

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Interim spread mooring of the FPSO at the Jubilee field in Ghana commenced in the fourth quarter of 2016 and was completed during the first quarter of 2017. In early 2018, the operator will start the first of three shutdown periods that are expected to occur in 2018 to effectively stabilize the turret and rotate the FPSO to its permanent heading. In October, the partnership received Ghanaian Government approval for the full-field plan of development, with drilling operations expected to commence in 2018.

•	During the third quarter of 2017, the foundational legal and contractual framework was completed for the Company’s onshore LNG project in Mozambique. Anadarko commenced resettlement and site preparation activities, which will position the onshore area for construction of the LNG facilities.

•	Anadarko and its co-venturers in Offshore Area 1 in Mozambique reached agreement on the project’s first long-term sale and purchase agreement for 2.6 MTPA with Thailand’s national oil and gas company, subject to the approval of the Government of Thailand.

•	The Company generated $4.0 billion of cash flow from operations and ended 2017 with $4.6 billion of cash.

•	Prior to the end of 2017, the Company completed $1.1 billion of the share repurchases. In February 2018, the Company completed an additional $500 million of share repurchases.

•	The Company recognized a one-time deferred tax benefit of $1.2 billion as a result of the Tax Reform Legislation.

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•	Sales volumes for the Delaware basin increased by 13 MBbls/d, primarily due to continued drilling and completion activities in 2017.

•	Divestitures resulted in a decrease in sales volumes of 29 MBbls/d, primarily related to the sale of the Eagleford assets in the first half of 2017.

•	Sales volumes increased by 56 MBbls/d, primarily due to the GOM Acquisition in December 2016 and continued tie-back activity at several facilities, partially offset by deferred production as a result of Hurricanes Harvey, Irma, and Nate and nonoperated field downtime during the second half of 2017.

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Sales volumes for Ghana increased by 9 MBbls/d, primarily due to a full year of liftings from the TEN development project, which came online late in the third quarter of 2016, and downtime in 2016 to address new production and offtake procedures resulting from issues associated with the Jubilee field FPSO turret bearing. Shuttle tankers are conducting offtakes until the facility is permanently moored.

•	Sales volumes for the Delaware basin increased by 8 MBbls/d, primarily due to continued field development.

•	Sales volumes for the DJ basin decreased by 6 MBbls/d, primarily due to reduced capital activity.

•	Sales volumes decreased by 7 MBbls/d, primarily due to the sale of EOR assets in the first half of 2015 and the East Chalk and Wamsutter assets in the first half of 2016.

•	Sales volumes increased by 12 MBbls/d, primarily due to new wells coming online at K2 Complex and Caesar/Tonga in the first half of 2016, an increased flow rate at Lucius, and the achievement of first oil at Heidelberg in January 2016.

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Sales volumes for Ghana decreased by 7 MBbls/d, primarily due to downtime during 2016 to address new production and offtake procedures resulting from issues associated with the Jubilee field FPSO turret bearing. Shuttle tankers are conducting offtakes until the facility is permanently moored. The decrease in volumes at Jubilee were partially offset by TEN coming online late in the third quarter of 2016.

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•	Sales volumes for the DJ basin increased by 98 MMcf/d, primarily due to improved performance.

•	Sales volumes for the Delaware basin increased by 18 MMcf/d, primarily due to continued field development.

•	Sales volumes decreased by 290 MMcf/d, primarily due to the sale of the Powder River Basin CBM assets and the Freestone assets in the second half of 2015, the Carthage assets in the second half of 2016, and the Wamsutter assets in the first half of 2016.

•	Sales volumes decreased by 61 MMcf/d, primarily as a result of the last producing well at Independence Hub going off line in December 2015.

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(1)	The percentage of NGLs sales volumes from the U.S. was 94% in 2017 and 96% in 2016 and 2015.

(2)	The percentage of daily NGLs sales volumes from the U.S. was 96% in 2017 and 95% in 2016 and 2015.

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•	higher operating costs of $212 million primarily related to the GOM Acquisition

•	higher operating costs of $88 million related to increased activity in the DJ and Delaware basins and costs related to the Company’s response efforts in Colorado in 2017

•	lower nonoperating costs of $12 million in Ghana primarily related to FPSO maintenance costs in 2016, partially offset by higher costs in 2017 due to increased production from the TEN development, which came online late in the third quarter of 2016

•	lower expenses of $89 million as a result of U.S. onshore asset divestitures

•	lower workover costs of $28 million in the Gulf of Mexico and the U.S. onshore

•	lower surface maintenance costs of $16 million in the U.S. onshore and the Gulf of Mexico

•	lower expenses of $112 million as a result of divestitures

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•	$437 million related to the Shenandoah project, $215 million related to the Phobos project, and $108 million related to the Warrior project in the Gulf of Mexico due to insufficient quantities of oil pay to justify development

•	$329 million related to all remaining wells in Côte d’Ivoire, where the Company relinquished its interest in its Cote d'Ivoire blocks

•	$243 million related to certain wells in the Grand Fuerte area in Colombia due to insufficient progress on contractual and fiscal reforms needed for deepwater natural-gas development

•	$231 million related to certain wells in the Gulf of Mexico and $92 million related to certain wells in Mozambique

•	$39 million for a well in Côte d’Ivoire that finished drilling in the third quarter of 2016 and encountered noncommercial quantities of hydrocarbons

•	$746 million primarily related to Brazil where the Company did not expect to have substantive exploration and development activities for the foreseeable future given the current oil-price environment

•	$306 million due to unsuccessful drilling activities in 2015 primarily in Colombia and the Gulf of Mexico

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The Company recognized a $610 million impairment of unproved Gulf of Mexico properties, of which $463 million related to the Shenandoah project. The unproved property balance related to the Shenandoah project originated from the purchase price allocated to the Gulf of Mexico exploration projects from the acquisition of Kerr McGee Corporation in 2006. For additional details on the Shenandoah project, see Note 6—Suspended Exploratory Well Costs in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

•	The Company recognized $88 million of impairments of unproved international properties.

•	The Company recognized a $72 million impairment of unproved properties in the Gulf of Mexico and $92 million for unproved international properties, primarily in Brazil and Tunisia, due to the Company’s current intentions to not pursue future exploration activities.

•	The Company recognized a $935 million impairment of unproved Greater Natural Buttes properties and a $66 million impairment of an unproved Gulf of Mexico property as a result of lower commodity prices.

•	The Company recognized a $109 million impairment of unproved Utica properties resulting from an assignment of mineral interests in settlement of a legal matter.

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•	$717 million related to lower 2017 sales volumes and asset property balances associated with U.S. onshore properties as a result of divestitures in 2016 and 2017

•	$457 million related to higher sales volumes in the Gulf of Mexico primarily due to the GOM Acquisition

•	$240 million related to international production DD&A primarily due to higher sales volumes from the Ghana TEN project, which came online late in the third quarter of 2016

•	lower carrying value for U.S. onshore and midstream properties as a result of 2015 asset impairments and divestitures in 2015 and 2016

•	lower 2016 sales volumes associated with U.S. onshore properties

(1)	In 2015, $3.0 billion of Exploration and Production impairments and $482 million of Other Midstream impairments related to Greater Natural Buttes.

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(1)	The increase in interest expense from 2016 to 2017 is primarily due to lower capitalized interest in 2017. See Note 12—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

(2)	See Note 12—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K for information on early extinguishment of debt.

(3)	See Note 10—Derivative Instruments in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

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(1)	Additions to properties and equipment as presented within Anadarko’s cash flows from investing activities include cash payments for cost of properties, equipment, and facilities. The cost of properties includes the initial capitalization of drilling costs associated with all exploratory wells, whether or not they were deemed to have a commercially sufficient quantity of proved reserves.

(2)	Capital expenditures exclude the FPSO capital lease asset; see Financing Activities—Capital Lease Obligations below.

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(1)	Represent senior notes issued in March 2016.

(2)	Includes repayments of $(106) million related to commercial paper notes with maturities greater than 90 days.

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(1)	WES has made quarterly distributions to its unitholders since its IPO in the second quarter of 2008 and has increased its distribution from $0.30 per common unit for the third quarter of 2008 to $0.92 per common unit for the fourth quarter of 2017 (paid in February 2018).

(2)	WES made distributions of $0.68 per unit, prorated based on issuance date, to its Series A Preferred unitholders since the unit issuances in March and April 2016. As of June 30, 2017, all Series A Preferred units had converted into WES common units. See Note 23—Noncontrolling Interests in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

(3)	WGP has made quarterly distributions to its unitholders since its IPO in December 2012 and has increased its distribution from $0.17875 per common unit for the first quarter of 2013 to $0.54875 per unit for the fourth quarter of 2017 (to be paid in February 2018).

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(1)	For additional information, see the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

(2)

Includes the fully accreted principal amount of the Zero Coupons of approximately $2.4 billion as coming due after 2022. While the Zero Coupons do not mature until 2036, the outstanding Zero Coupons can be put to the Company each October, in whole or in part, for the then-accreted value. The Company could be required to repurchase the outstanding Zero Coupons at $930 million in October 2018 (the next potential put date).

(3)	The obligations and related investments are presented net on the Company’s Consolidated Balance Sheets in other assets or other long-term liabilities-other. Future interest payments are estimated using the relevant forward LIBOR rate curve. The preferred return that Anadarko receives on its investment in these entities is not included.

(4)	Includes long-term drilling and work-related commitments of $916 million, comprised of approximately $815 million related to the United States and $101 million related to international locations. Amounts are undiscounted and do not include purchase commitments for jointly owned fields and facilities where the Company is not the operator.

(5)	Represents Anadarko’s gross derivative liability after taking into account the impacts of netting margin and collateral balances deposited with counterparties.

(6)	Timing of conclusion of the uncertain tax positions cannot be determined with certainty.

(7)	Includes environmental liabilities; for additional information, see Note 17—Contingencies in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

(8)

Excludes litigation-related contingent liabilities, the Company’s pension and postretirement benefit obligations, or payments related to the conveyance of future hard-minerals royalty revenues. See Note 17—Contingencies, Note 19—Pension Plans, Other Postretirement Benefits, and Defined-Contribution Plans, and Note 15—Conveyance of Future Hard-Minerals Royalty Revenues in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

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•	significant changes in the stock price of Anadarko, WES, and WGP

•	significant declines in commodity prices

•	significant increases in cost factors such as costs of drilling, production costs, and gathering, processing, and other transportation costs

•	impairments recognized by the Company

•	acquisitions and disposals of assets

•	changes to the Company’s reserves, including changes due to fluctuations in commodity prices and updates to the Company’s plans or forecasts

•	significant declines in trading multiples for midstream peers

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(1)	Excludes WES and WGP.

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•	Exploration and Production—No significant impact is expected for the recognition, measurement, or presentation of oil, natural-gas, or NGLs sales revenues.

•

WES Midstream and Other Midstream—Gathering and processing revenues will decrease for contracts where the Company is acting as an agent for its processing customer in the sale of processed volumes and increase for contracts with noncash consideration that will generally be valued at current market prices of the commodity received, with an offset in gathering and processing expense. The magnitude of these changes is dependent on future customer volumes subject to the impacted contracts and commodity prices for those volumes. While reported gathering and processing revenues and expenses will be materially reduced, these presentation changes will not impact net earnings.

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(1)	Includes goodwill allocated to divestitures of $209 million in 2017, $397 million in 2016, and $184 million in 2015.

(2)	Includes the $126 million gain related to the property exchange discussed above.

•	Eagleford assets in South Texas, included in the Exploration and Production reporting segment, for net proceeds of $2.1 billion and a net gain of $729 million

•	Eaglebine assets in Southeast Texas, included in the Exploration and Production reporting segment, for net proceeds of $533 million and a net gain of $282 million

•	CBM assets in Utah, included in the Exploration and Production and WES Midstream reporting segments, for net proceeds of $69 million and a net loss of $52 million

•	Marcellus assets in Pennsylvania, included in the Exploration and Production and Other Midstream reporting segments, for net proceeds of $951 million and net losses of $55 million in 2017 and $129 million in 2016

•	Moxa assets in Wyoming, included in the Exploration and Production reporting segment, for net proceeds of $313 million and a net loss of $204 million

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•	Hugoton assets in Kansas, included in the Exploration and Production and WES Midstream reporting segments, for net proceeds of $159 million and a loss of $4 million

•	Ozona and Steward assets in West Texas, included in the Exploration and Production and Other Midstream reporting segments, for net proceeds of $221 million and a loss of $52 million

•	Wamsutter assets in Wyoming, included in the Exploration and Production reporting segment, for net proceeds of $588 million and a loss of $58 million

•	Elm Grove assets in East Texas, included in the Exploration and Production reporting segment, for net proceeds of $89 million and a loss of $64 million

•	East Chalk and Carthage assets in East Texas/Louisiana, included in the Exploration and Production and Other Midstream reporting segments, for net proceeds of $1.0 billion and a net loss of $439 million

•	Freestone and Dew Pinnacle assets in East Texas, included in the Exploration and Production and WES Midstream reporting segments, for net proceeds of $425 million and a loss of $110 million

•	EOR assets in Wyoming, included in the Exploration and Production reporting segment, for net proceeds of $675 million and a loss of $350 million

•	Powder River Basin CBM assets in Wyoming, included in the Exploration and Production and Other Midstream reporting segments, for net proceeds of $154 million and a loss of $538 million

(1)	Includes costs associated with unproved properties of $2.4 billion at December 31, 2017, and $4.1 billion at December 31, 2016.

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(1)	Measured as of the impairment date using the income approach and Level 3 inputs. The primary assumptions used to estimate undiscounted future net cash flows include anticipated future production, commodity prices, and capital and operating costs.

(2)	The after-tax net investment fair value was $32 million at December 31, 2015.

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Shenandoah The Company expensed $437 million of exploratory well costs, including $326 million of costs that were suspended as of December 31, 2016. The Shenandoah-6 appraisal well and subsequent sidetrack, which completed appraisal activities in April 2017 and did not encounter oil in the eastern portion of the field. Given the results of this well and the commodity-price environment, the Company suspended further appraisal activities.

•	Phobos The Company expensed $215 million of exploratory well costs, including $99 million of costs that were suspended as of December 31, 2016, in the third quarter of 2017 related to wells at the Phobos project. These wells found insufficient quantities of oil pay to justify development in the current price environment.

•

Warrior The Company expensed $108 million of exploratory well costs in the third quarter of 2017 related to the northern appraisal well and sidetrack at the Warrior project. These wells found insufficient quantities of oil pay to justify development of the northern portion of the field in the current price environment. Evaluation of tie-back opportunities in the southern portion of the field is ongoing.

•	The Company expensed $243 million of exploratory well costs, including $102 million of costs that were suspended as of December 31, 2016, related to wells in the Grand Fuerte area in Colombia due to insufficient progress on contractual and fiscal reforms needed for deepwater gas development. All remaining leases are contractually in good standing.

•	The Company expensed $329 million of exploratory well costs, including $237 million of costs that were suspended as of December 31, 2016, in Côte d’Ivoire. During 2017, the Company had unsuccessful drilling activities in the south channel of the Paon prospect and in Block CI-527 and after further evaluation of the well results, Anadarko withdrew from all Côte d’Ivoire blocks.

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•	The Company expensed $231 million of suspended exploratory well costs in the Gulf of Mexico primarily related to the Yeti project, as the Company did not expect to have exploration activities on this prospect in the foreseeable future, and a Shenandoah well that was expensed, as it was no longer reasonably possible that the wellbore could be used in the development of the project.

•

The Company expensed $92 million of suspended exploratory well costs in Mozambique. The Tubarão-Tigre discovery wells were expensed based on the outlook for development viability, the commodity market conditions, and the complexity introduced by the depth and characteristics of the reservoir. The Orca-4 well was expensed after additional reservoir analysis and the determination that the well was not associated with the first three Orca wells.

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(1)	Represents the effect of Marketing and Trading Derivative Activities.

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(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.

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(1)	The applicable market value is the average of the daily volume-weighted average prices of WGP common units (or APC Shares) for the 20 consecutive trading days beginning on, and including, the 23rd scheduled trading day immediately preceding June 7, 2018.

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(1)	Excludes WES.

(2)	Excludes WES and WGP

(3)	Represent senior notes issued in March 2016.

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(1)	Excludes WES.

(2)	Excludes WES and WGP.

(3)	Unamortized discounts, premiums, and debt issuance costs are amortized over the term of the related debt. Debt issuance costs related to RCFs are included in other current assets and other assets on the Company’s Consolidated Balance Sheets.

(4)	The Company’s outstanding borrowings, except for borrowings under the WGP RCF, are senior unsecured.

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(1)	Excludes WES.

(2)	Excludes WES and WGP.

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(1)	In December 2016, the Company closed the GOM Acquisition. See Note 3—Acquisitions, Divestitures, and Assets Held for Sale for additional information.

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(1)	Excludes purchase commitments for jointly owned fields and facilities for which the Company is not the operator.

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(1)	Includes $19 million of settlement losses for pension benefits at December 31, 2017, and $44 million of termination benefits at December 31, 2016, associated with the Company’s workforce reduction program initiated in the first quarter of 2016. See Note 18—Restructuring Charges.

(2)	The accumulated benefit obligation for all defined-benefit pension plans was $1.9 billion at December 31, 2017 and $2.0 billion at December 31, 2016.

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(1)	Settlement expense, termination benefits expense, and curtailment expense for 2016 relate to the workforce reduction program initiated in the first quarter of 2016. See Note 18—Restructuring Charges.

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(1)	Certain investments measured at fair value using the net asset value per share (or its equivalent) have not been categorized in the fair value hierarchy. Amounts presented in this table are intended to reconcile the fair value hierarchy to the pension plan assets.

(2)	Amount excludes receivables and payables, primarily related to Level 1 investments.

(3)	The changes in level 3 investments of $3 million for the year ended December 31, 2017, and $(3) million for the year ended December 31, 2016, were attributable to the actual return on plan assets still held at the reporting date.

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(1)	Includes restructuring charges of $(7) million for performance-based unit awards in 2017 and $31 million for restricted stock, $1 million for stock options, and $7 million for performance-based unit awards in 2016. See Note 18—Restructuring Charges for further discussion.

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•	Expected life—Based on historical exercise behavior.

•	Volatility—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—Based on the U.S. Treasury rate over the expected life of an option.

•	Dividend yield—Based on a 12-month average dividend yield, taking into account the Company’s expected dividend policy over the expected life of an option.

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(1)	The total intrinsic value of stock options exercised was zero during 2017, $7 million during 2016, and $23 million during 2015, based on the difference between the market price at the exercise date and the exercise price.

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(1)	Includes $1.2 billion of interest related to the Tronox settlement payment in 2015.

(2)	Includes $881 million from a tax refund in 2016 related to the income tax benefit associated with the Company’s 2015 tax net operating loss carryback.

(3)	Upon completion of the FPSO in the third quarter of 2016, the Company reported the construction period obligation as a capital lease obligation based on the fair value of the FPSO. See Note 12—Debt and Interest Expense.

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(1)	Presentation has been adjusted to align with the current analysis of segment performance. Net income (loss) attributable to noncontrolling interests, previously reported within the Midstream segment, is now presented within Other and Intersegment Eliminations. Other revenues, previously reported within Other and Intersegment Eliminations, is now presented within the applicable segments.

(2)	Total revenues and other excludes gains (losses) on divestitures, net since these gains and losses are excluded from Adjusted EBITDAX.

(3)	Operating costs and expenses excludes exploration expense, DD&A, impairments, restructuring charges, and certain other operating expenses since these expenses are excluded from Adjusted EBITDAX.

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(1)	Presentation has been adjusted to align with the current analysis of segment performance. Net income (loss) attributable to noncontrolling interests, previously reported within the Midstream segment, is now presented within Other and Intersegment Eliminations. Other revenues, previously reported within Other and Intersegment Eliminations, is now presented within the applicable segments.

(2)	Total revenues and other excludes gains (losses) on divestitures, net since these gains and losses are excluded from Adjusted EBITDAX.

(3)	Operating costs and expenses excludes exploration expense, DD&A, impairments, restructuring charges, and certain other operating expenses since these expenses are excluded from Adjusted EBITDAX.

(4)	Other (income) expense, net excludes certain other nonoperating items since these items are excluded from Adjusted EBITDAX.

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(1)	Includes $413 million of capitalized costs related to the Mozambique LNG project at December 31, 2017.

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(1)	Includes a one-time deferred tax benefit of $1.2 billion in the fourth quarter of 2017 related to the Tax Reform Legislation.

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(1)	Revisions of prior estimates include the effects of new infill drilling, changes in commodity prices, and other updates, including changes in economic conditions, changes in reservoir performance, and changes to development plans. Additions generated by Anadarko’s infill drilling programs were 71 MMBOE for 2017, 69 MMBOE for 2016, and 89 MMBOE for 2015.

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Performance The Company experienced an overall increase of 60 MMBOE in proved reserves due to performance improvements. Numerous areas of the Company contributed to a total upward revision of 91 MMBOE with the largest increases occurring in the DJ and Delaware basin areas. Downward revisions of 31 MMBOE were primarily due to performance reductions in the Lucius area in the Gulf of Mexico and in the Greater Natural Buttes area of the Rockies.

•	Cost updates Annual updates reflected cost increases in certain U.S. onshore areas resulting in a minor reduction in proved reserves.

•	Infill-drilling activities The Company added 71 MMBOE of proved reserves associated with infill drilling activities, of which 53 MMBOE was in the DJ basin, 13 MMBOE in the Lucius and Holstein areas in the Gulf of Mexico, and the remaining in the Ghana Jubilee field.

•	Development plan updates The majority of revisions associated with updates to development plans occurred in the DJ basin due to ongoing optimization of development activity.

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•	Performance  The Company experienced an overall increase of 74 MMBOE in proved reserves. Upward revisions of 102 MMBOE were primarily due to improved well performance in the DJ basin, certain U.S. shale plays, and select wells in the Gulf of Mexico. Downward revisions of 28 MMBOE were primarily due to performance updates associated with select wells in the Gulf of Mexico.

•

Cost reductions  Ongoing cost-optimization efforts and a reduced cost structure associated with the lower commodity-price environment resulted in an increase in proved reserves. The Eagleford and the DJ basin areas experienced an increase of 94 MMBOE of proved reserves associated with certain wells, included in the negative price-related revisions, which experienced restored economic producibility upon reduction of the cost structure. The remaining increase in proved reserves due to the improved cost structure is attributable to numerous areas across the Company.

•	Infill-drilling activities  The Company added 69 MMBOE of proved reserves associated with infill drilling activities, the majority of which were in the DJ basin and the K2 and Caesar/Tonga areas of the Gulf of Mexico.

•	Other revisions  Other revisions resulted from the Company’s multi-step reserves reconciliation process and the elimination of duplicative adjustments to the opening reserves balance.

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Performance  The Company experienced an increase of 169 MMBOE in proved reserves primarily due to increases to planned lateral lengths in the Eagleford area of South Texas combined with improved well performance in the Eagleford area, the DJ basin, and the Marcellus area of the Appalachian basin. All other performance increases were a result of minor improvements from numerous areas throughout the Company.

•

Cost reductions  Capital spent in 2015 associated with ongoing drilling and completion activities, ongoing cost-optimization efforts, and a reduced cost structure associated with the lower commodity-price environment resulted in an increase in proved reserves. The DJ basin and Greater Natural Buttes areas and the Eagleford area experienced an increase of 81 MMBOE of proved reserves due to drilling activity associated with certain wells, included in the negative price-related revisions, which experienced restored economic producibility upon reduction of the capital cost structure. An increase of 14 MMBOE in proved reserves was associated with the Marcellus area where certain wells, included in the negative price-related revisions, experienced extended economic limits as a result of reductions to operating expenses during 2015. The remaining increase in proved reserves due to the improved cost structure was attributable to numerous areas across the Company.

•	Infill-drilling activities  The Company added 89 MMBOE of proved reserves associated with infill drilling activities during 2015, the majority of which were in the DJ basin.

•	Development plan updates  The majority of revisions associated with updates to development plans occurred in the DJ basin due to a significantly reduced development pace related to the decrease in commodity prices.

•	Other revisions  Other revisions resulted from the Company’s multi-step reserves reconciliation process and the elimination of duplicative adjustments to the opening reserves balance.

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(1)	The Consolidated Financial Statements of Anadarko Petroleum Corporation are listed on the Index to this Form 10-K, page 85.

(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 under File Number 1-8968 as indicated.

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†	Management contracts or compensatory plans or arrangements required to be filed pursuant to Item 15.

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