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–	the Company’s assumptions about energy markets

–	production and sales volume levels

–	levels of oil, natural-gas, and NGL 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 volume, 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

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legislative or regulatory changes, including changes relating to hydraulic fracturing or other oil and natural-gas operations; retroactive royalty or production tax regimes; deepwater and onshore 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, successfully complete its debt-reduction program, and the impact of changes in the Company’s credit ratings

–	the Company’s ability to successfully complete its Share-Repurchase Program

–	the Company’s ability to successfully plan, secure additional government and partner approvals, enter into additional long-term sales contracts, make a final investment decision and the timing thereof, finance, build, and operate the necessary infrastructure and LNG park in Mozambique

–	uncertainties and liabilities associated with acquired and divested properties and businesses

–	disruptions in international oil and NGL cargo shipping activities

–	physical, digital, 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

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the outcome of pending and future regulatory, legislative, or other proceedings or investigations, including the investigation by the National Transportation Safety Board 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

–	the completion of the simplification transaction between WES and WGP and the corresponding sale of substantially all of the Company’s Other Midstream assets to WES

–	other factors discussed below and elsewhere in this Form 10-K, the Company’s subsequent Quarterly Reports on Form 10-Q, and in the Company’s other public filings, press releases, and discussions with Company management

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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 18 MMBOE due to performance improvements. Upward revisions of 26 MMBOE were driven primarily by performance improvements in the DJ basin. Downward revisions of 8 MMBOE were primarily due to minor performance reductions in various areas in the Gulf of Mexico and Ghana.

–	Infill-drilling activities  The Company added 158 MMBOE of PUDs associated with infill-drilling activities, with 151 MMBOE in the DJ basin, 5 MMBOE in the Lucius area in the Gulf of Mexico, and the remaining in the Ghana TEN field.

–	Development plan updates  The majority of revisions associated with updates to development plans occurred in the DJ basin due to municipal permit delays in certain areas of the field and ongoing optimization of development activity.

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(1)	Excludes the impact of commodity derivatives.

(2)	Includes oil and gas operating expenses and other taxes and excludes ad valorem and severance taxes. Volume represents produced volume sold during the period.

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(1)	Volume committed to various customers through 2033.

(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 114 MMBOE of PUDs primarily assigned to U.S. onshore development wells suspended or waiting on completion at December 31, 2018. The Company expects to convert 113 MMBOE of these PUDs reserves to developed status within five years of their initial disclosure. The remaining 1 MMBOE is associated with an international well that was spud late in the year and will be converted to developed status in the near future.

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(1)	Excludes horsepower associated with transportation assets.

(1)	Excludes horsepower associated with transportation assets.

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

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U.S. Department of the Interior (which includes Bureau of Land Management (BLM), Bureau of Indian Affairs (BIA), Bureau of Ocean Energy Management (BOEM) and Bureau of Safety and Environmental Enforcement (BSEE) regulations), which govern operations on federal lands and 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 U.S. 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 (SDWA), 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 U.S. 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 U.S. 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

–	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 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, ability to repurchase shares, reduce debt and pay dividends, 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 NGL 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 NGL 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 upstream and 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 (NAAQS) 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. In 2017 and 2018, the EPA issued area designations with respect to ground-level ozone as either “attainment/unclassifiable,” unclassifiable” or “non-attainment.” Additionally, in November 2018, the EPA issued final requirements that apply to state, local, and tribal air agencies for implementing the 2015 NAAQS for ground-level ozone. State implementation of the revised NAAQS 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

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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 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. Texas has also issued rules for wastewater disposal wells that imposed certain permitting and operating restrictions and reporting requirements on 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 regulations 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 U.S. 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 a large volume 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. Additionally, the United States is one of almost 200 nations that, in December 2015, agreed to the Paris Climate Agreement, an international climate change agreement in Paris, France, that calls for countries to set their own GHG emissions targets and be transparent about the measures that each country will use to achieve its GHG emissions targets. The Paris Climate Agreement entered into force in November 2016. However, 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 NGL 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

–	difficulties enforcing our rights against a governmental agency in the absence of an appropriate and adequate dispute resolution mechanism to address contractual disputes, such as international arbitration

–	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 volume

–	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 NGL prices

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–	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

–	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

–	possible delays in closing

–	lower-than-expected sales proceeds for the disposed assets

–	potential post-closing claims for indemnification

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(1)	During the fourth quarter of 2018, 109 thousand shares were repurchased 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 23—Share-Based Compensation in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

(2)	During the fourth quarter of 2018, under the Share Repurchase Program, the Company repurchased 4.8 million shares of common stock in the open market for $250 million. For additional information, see Note 21—Stockholders’ Equity in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

(3)

The Company announced a $2.5 billion Share-Repurchase Program in September 2017, which was expanded to $3.0 billion in February 2018 and $4.0 billion in July 2018. In November 2018, the program was further expanded to $5.0 billion and extended through June 30, 2020. For additional information, see Note 21—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 a $1.2 billion one-time deferred tax benefit in 2017 related to Tax Reform Legislation and a $4.4 billion Tronox-related contingent loss in 2014.

(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.

(6)	2018 includes impact of adopting ASU 2014-09. See Note 2—Revenue from Contracts with Customers.

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–	Delaware Basin  Anadarko plans to allocate approximately $1.4 billion toward upstream activities. The successful expansion of the Company’s infrastructure footprint, including oil gathering and treating facilities throughout West Texas, is paving the way to transition to multi-well pad development. This phased development approach is expected to deliver incremental oil sales volume in 2019.

–	DJ Basin  Anadarko expects to invest approximately $1.3 billion on upstream activities, with continued development of its minerals-interest ownership and infrastructure-advantaged position in the Wattenberg field. Anadarko expects to deliver incremental oil sales volume from the DJ basin in 2019.

–	Powder River Basin Anadarko expects to invest approximately $250 million toward upstream activities, including appraisal and delineation of its 300,000 gross acre position in the southern Powder River basin primarily targeting the Turner formation.

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Gulf of Mexico  Anadarko expects to allocate approximately $500 million toward its deepwater Gulf of Mexico operations. Although the capital allocation is lower than in 2018, the Company plans to deliver a similar number of wells in 2019 and maintain production levels around 140 MBOE/d. The majority of these investments are expected to be directed toward high-return oil development opportunities near operated infrastructure at Constellation, Holstein, Horn Mountain, K2, Lucius, and North Hadrian.

–	International  Anadarko plans to allocate approximately $200 million toward its international operations in Algeria and Ghana. The investment in Ghana will be focused on adding incremental wells to optimize capacity at the Jubilee and TEN FPSO vessels.

–	Exploration  The Company's exploration investments in 2019 are expected to total approximately $250 million. Exploration spending will primarily be focused on identifying material and scalable opportunities in the U.S. onshore and tie-back opportunities near existing operated facilities in the deepwater Gulf of Mexico.

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LNG  The Company expects to invest approximately $200 million in the Mozambique LNG project in 2019 on pre-FID activities. This includes Anadarko’s portion of the cost associated with ongoing site preparation for the shared onshore facilities. The Company remains on track for making a final investment decision in the first half of 2019, and anticipates adjusting its capital investment expectations associated with the Mozambique LNG project if the project is sanctioned.

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–	The Company’s oil sales volume averaged 385 MBbls/d, representing a 9% increase from 2017, primarily due to increased volume from the DJ and Delaware basins, partially offset by the divestiture of certain U.S. onshore assets in 2017.

–	The Company’s overall oil sales-volume product mix increased to 58% in 2018, compared to 53% in 2017. The overall liquids sales-volume product mix increased to 73% in 2018, compared to 67% in 2017.

–	Total sales volume in the Delaware basin averaged 109 MBOE/d, representing a 68% increase from 2017, and oil sales volume in the Delaware basin increased 27 MBbls/d, representing a 71% increase from 2017, primarily due to continued drilling and completion activities.

–	In the Delaware basin, the Reeves and Loving County ROTFs were completed, with 138 total wells flowing into the facilities by the end of 2018. In addition, the first train at the WES-owned Mentone natural-gas processing plant was placed in service during the fourth quarter, adding 200 MMcf/d of natural-gas processing capacity.

–	Oil sales volume in the DJ basin increased 14 MBbls/d, representing a 17% increase from 2017, primarily due to continued drilling and completion activities.

–	In the DJ basin, the sixth COSF train was placed in service, adding 30 MBbls/d of oil-stabilization capacity.

–	The Company received net proceeds of approximately $370 million from the divestiture of its nonoperated interest in Alaska.

–	Oil sales volume averaged 121 MBbls/d, remaining relatively flat compared to 2017, primarily due to natural production declines and planned downtime at various platforms, partially offset by new wells coming online at Horn Mountain, Holstein, Marlin, and Caesar Tonga.

–	In the TEN field, the operator resumed drilling operations in early 2018, with one well brought online in 2018. Two additional wells were drilled in 2018, with completion activities ongoing at year end.

–	In the Jubilee field, the operator drilled two production wells during the second quarter of 2018, with the first of these wells brought online in the third quarter. The second well was brought online in the fourth quarter. Additionally, a previously drilled water injector well was brought online during the fourth quarter of 2018.

–	The operator of the Jubilee FPSO completed two shutdowns to effectively stabilize the turret and rotate the FPSO to its permanent heading. Completion of the spread-mooring anchoring system is expected in early 2019, with no further shutdowns anticipated.

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–	During 2018 and subsequent to year end, additional LNG sales and purchase agreements were executed, increasing contracted volumes to more than 7.5 MTPA, with an additional 2.0 MTPA of contracted volume anticipated prior to FID.

–	The Government of Mozambique approved the Development Plan for the Anadarko-operated, initial two-train Golfinho/Atum project.

–	The preferred offshore construction and installation contractor was selected in the fourth quarter of 2018, and the contracts with the onshore and offshore construction and installation contractors are being finalized ahead of making a final investment decision in the first half of 2019.

–	Site preparation activities are fully underway at the Afungi onshore site, as major infrastructure and resettlement projects are proceeding as planned, positioning the area for construction of the LNG facilities.

–	In the third quarter of 2018, Offshore Area 4, which is owned and operated by third parties, joined the Anadarko-led resettlement and airstrip projects as a 50% participant.

–	The Company generated $5.9 billion of cash flow from operations and ended 2018 with $1.3 billion of cash.

–	The Company completed $2.7 billion of share repurchases and retired more than $600 million of debt.

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–	Sales volume for the Delaware basin increased by 27 MBbls/d, primarily due to continued drilling and completion activities and midstream infrastructure additions in 2018.

–	Sales volume for the DJ basin increased by 14 MBbls/d, primarily due to continued drilling and completion activities in 2018.

–	Divestitures resulted in decreased sales volume of 16 MBbls/d, primarily related to the sale of the Alaska nonoperated assets in the first quarter of 2018 and the Eagleford and West Chalk assets in the first half of 2017.

–	Sales volume for the Gulf of Mexico remained flat, primarily due to natural production declines and planned downtime at various platforms, partially offset by new wells coming online at Horn Mountain, Holstein, Marlin, and Caesar Tonga throughout 2018.

–	Sales volume 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 volume of 29 MBbls/d, primarily related to the sale of the Eagleford assets in the first half of 2017.

–	Sales volume 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.

–	Sales volume for Ghana increased by 9 MBbls/d, primarily due to a full year of liftings from the TEN development, 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.

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(1)	All natural-gas sales volume originates in the United States.

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(1)	Approximately 95% of NGL sales volume was from the United States.

–	Sales volume for the Delaware basin increased by 9 MBbls/d, primarily due to continued drilling and completion activities and midstream infrastructure additions in 2018.

–	Sales volume for other U.S. onshore assets decreased by 5 MBbls/d, primarily due to the sale of the Eagleford and West Chalk assets in the first half of 2017 and the Moxa assets in the second half of 2017.

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(1)

As a result of adopting ASU 2014-09, Revenue from Contracts with Customers (Topic 606), as of January 1, 2018, gathering, processing, and marketing sales decreased by $1.0 billion for the year ended December 31, 2018, and gathering, processing, and marketing expenses decreased by $1.0 billion for the year ended December 31, 2018. Refer to Note 2—Revenue from Contracts with Customers in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K for further information.

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–	higher U.S. onshore costs of $140 million, primarily related to increased operating and nonoperating activity in the DJ and Delaware basins, partially offset by lower expenses of $74 million as a result of U.S. onshore asset divestitures

–	higher non-operating costs of $54 million in Ghana, primarily due to the Jubilee FPSO turret repair and additional wells coming online in 2018

–	higher operating costs of $32 million, primarily related to maintenance at various platforms in GOM

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

–	higher operating costs of $84 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

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–	$87 million related to unsuccessful drilling activities, primarily in the Gulf of Mexico

–	$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 all of its exploration 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

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–	$140 million decrease, primarily related to divestitures associated with U.S. onshore properties in 2018 and 2017 and a lower DD&A rate in 2018 driven by increased proved developed reserves in Ghana

–	$62 million increase in ARO accretion expense due to increased ARO estimates in the Gulf of Mexico

–	$53 million increase in straight line depreciation related to newly constructed pipelines and salt water disposal facilities in the Delaware basin

–	$717 million related to lower 2017 sales volume 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 volume in the Gulf of Mexico, primarily due to the GOM Acquisition

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

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(1)	Interest expense increased from 2016 to 2017 primarily due to lower capitalized interest in 2017. See Note 13—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

(2)	See Financing Activities in Liquidity and Capital Resources for additional information.

(3)	See Note 11—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)	Proceeds were used to purchase and retire $1.250 billion of its $2.0 billion 6.375% Senior Notes due September 2017 pursuant to a tender offer and to redeem its $1.750 billion 5.950% Senior Notes due September 2016.

(2)	Proceeds were used to repay amounts outstanding under the WES RCF, with remaining proceeds used for general partnership purposes, including capital expenditures.

(3)	Proceeds were used to repay the maturing $350 million 2.600% Senior Notes due August 2018 and amounts outstanding under the WES RCF, with remaining proceeds used for general partnership purposes, including capital expenditures.

(4)	Proceeds were used to repay a portion of the amount outstanding under the WES RCF.

(5)	Proceeds were primarily used for general short-term working capital needs.

(6)	Borrowings in 2018 and 2017 were used for general partnership purposes, including capital expenditures. In 2016, borrowings were used to fund a portion of an acquisition and for general partnership purposes, including capital expenditures.

(7)	The Company purchased and retired $377 million of its $625 million 3.450% Senior Notes due 2024 and $123 million of its $800 million 4.850% Senior Notes due 2021 pursuant to a tender offer.

(8)	The Company recognized losses of $155 million for the early retirement and redemption of these senior notes, which included $144 million of premiums paid.

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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 $0.98 per common unit for the fourth quarter of 2018 (paid in February 2019).

(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 24—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 $0.6025 per unit for the fourth quarter of 2018 (to be paid in February 2019).

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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 $2.3 billion as coming due after 2023. 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 for $942 million, if put in whole, in October 2019 (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 $802 million, comprised of approximately $670 million related to the United States and $132 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)

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 18—Contingencies, Note 20—Pension Plans, Other Postretirement Benefits, and Defined-Contribution Plans, and Note 16—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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(1)	Beginning January 1, 2018, the Company adopted ASU 2018-02, Income Statement - Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income. See Note 1—Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements for further information.

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(1)	Excludes WES and WGP.

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(1)

Beginning January 1, 2018, the Company adopted ASU 2014-09, Revenue from Contracts with Customers (Topic 606), and ASU 2018-02, Income Statement - Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income. See Note 1—Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements for further information.

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(1)	The amount in Other and Intersegment Eliminations primarily represents sales of third-party natural gas and NGLs of $957 million and intersegment eliminations of $(876) million for the year ended December 31, 2018.

(2)	The amount in Other and Intersegment Eliminations primarily represents purchases of third-party natural gas and NGLs. Although these purchases are reported net in gathering, processing, and marketing sales in the Company’s Consolidated Statements of Income, they are shown separately on this table as the purchases are not considered revenue from customers.

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

(2)	Includes gain of $126 million related to the 2017 property exchange discussed below.

–	Alaska nonoperated assets, included in the Exploration and Production and Other Midstream reporting segments, for net proceeds of $370 million and net losses of $33 million in 2018 and $154 million in the fourth quarter of 2017

–	Ram Powell nonoperated assets in the Gulf of Mexico, included in the Exploration and Production reporting segment, resulting in a net gain of $67 million

–	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

–	Utah CBM assets, 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

(1)	Includes costs associated with unproved properties of $1.7 billion at December 31, 2018, and $2.4 billion at December 31, 2017.

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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.

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(1)	Excludes amounts capitalized and subsequently charged to expense within the same year.

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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 at the time, the Company suspended further appraisal activities. In 2018, the Company relinquished its ownership interest in Shenandoah.

–	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.

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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 $109 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.

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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 exploration blocks in Côte d’Ivoire. The Company expects to complete the withdrawal from its remaining appraisal block in 2019.

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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.

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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)	Excludes amounts related to WES interest-rate swap agreements.

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(1)	Excludes amounts related to WES interest-rate swap agreements.

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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.

(2)	Excludes amounts related to WES interest-rate swap agreements.

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(1)	Excludes WES.

(2)	Excludes WES and WGP.

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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)	Net deferred tax assets related to Algeria of $34 million in 2018 and $21 million in 2017 are presented in other assets on the Company’s Consolidated Balance Sheet.

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(1)	Net of $711 million uncertain tax position at December 31, 2018.

(2)	Net of $378 million uncertain tax position at December 31, 2018.

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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)	The accumulated benefit obligation for all defined-benefit pension plans was $1.6 billion at December 31, 2018 and $1.9 billion at December 31, 2017.

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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 19—Restructuring Charges.

(2)	The service cost component of net periodic benefit cost is included in G&A; oil and gas operating expense; gathering, processing, and marketing expense; and exploration expense, and all other components of net periodic benefit cost are included in other (income) expense on the Company’s Consolidated Statements of Income.

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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)	There were no changes in Level 3 investments for the year ended December 31, 2018. The changes in Level 3 investments of $3 million for the year ended December 31, 2017, were attributable to the actual return on plan assets still held at the reporting date.

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(1)	Beginning January 1, 2018, the Company adopted ASU 2018-02, Income Statement - Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income. See Note 1—Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements for further information.

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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 19—Restructuring Charges for additional information.

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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.

(1)	The total intrinsic value of stock options exercised was $1 million during 2018, zero during 2017, and $7 million during 2016, based on the difference between the market price at the exercise date and the exercise price.

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(1)	WGP distributions to Anadarko are eliminated upon consolidation.

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(1)	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.

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(1)	Includes reorganization-related charges of $20 million for the year ended December 31, 2018.

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

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

(3)	Other (income) expense, net excludes reorganization-related charges since these expenses are excluded from Adjusted EBITDAX.

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

(2)	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.

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

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(1)	Includes $519 million of capitalized costs related to the Mozambique LNG project at December 31, 2018.

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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 181 MMBOE for 2018, 71 MMBOE for 2017, and 69 MMBOE for 2016.

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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 181 MMBOE for 2018, 71 MMBOE for 2017, and 69 MMBOE for 2016.

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Performance The Company experienced an overall increase of 4 MMBOE in proved reserves due to performance improvements. Numerous areas of the Company contributed to a total upward revision of 48 MMBOE with assets in the Gulf of Mexico primarily responsible for the positive changes. Downward revisions of 44 MMBOE were primarily due to vertical well performance reductions in the DJ basin and performance reductions in the Lucius, K2, and Nansen areas in the Gulf of Mexico.

–	Cost updates Annual updates to cost forecasts resulted in a minor reduction in proved reserves primarily associated with the Greater Natural Buttes area in the Rockies.

–	Infill-drilling activities The Company added 181 MMBOE of proved reserves associated with infill-drilling activities, with 168 MMBOE in the DJ basin, 5 MMBOE in the Gulf of Mexico K2 area, 5 MMBOE in the Gulf of Mexico Lucius area, and the remaining in the Ghana TEN field.

–	Development plan updates The majority of revisions associated with updates to development plans occurred in the DJ basin due to municipal permit delays in certain areas of the field.

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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 basins. 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, with 53 MMBOE 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.

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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, with the majority 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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(1)	Represents administrative costs that are related to oil and gas operations.

(2)	Income tax expense is calculated by applying the current statutory tax rates to revenues after deducting costs, which include DD&A allowances, after giving effect to permanent differences.

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(1)	Represents administrative costs that are related to oil and gas operations.

(2)	Income tax expense is calculated by applying the current statutory tax rates to revenues after deducting costs, which include DD&A allowances, after giving effect to permanent differences.

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(1)	The consolidated financial statements of Anadarko Petroleum Corporation are listed on the Index to this Form 10-K, 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 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.

#	Pursuant to Item 601(b)(2) of Regulation S-K, the registrant agrees to furnish supplementally a copy of any omitted schedule to the Securities and Exchange Commission upon request.

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