[ X ]
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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[ ]
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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Delaware
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76-0146568
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(State or other jurisdiction of incorporation or organization)
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(I.R.S. Employer Identification No.)
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1201 Lake Robbins Drive, The Woodlands, Texas
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77380-1046
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(Address of principal executive offices)
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(Zip Code)
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Title of each class
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Name of each exchange on which registered
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Common Stock, par value $0.10 per share
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New York Stock Exchange
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Title of Class
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Number of Shares Outstanding
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Common Stock, par value $0.10 per share
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499,575,992
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TABLE OF CONTENTS
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Page
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PART I
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Items 1 and 2.
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Regulatory and Environmental
Matters
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Item 1A.
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Item 1B.
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Item 3.
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Item 4.
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PART II
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Item 5.
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Item 6.
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Item 7.
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Item 7A.
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Item 8.
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Item 9.
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Item 9A.
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Item 9B.
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PART III
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Item 10.
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Item 11.
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Item 12.
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Item 13.
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Item 14.
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PART IV
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Item 15.
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Item 16.
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CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS
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–
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the Company’s assumptions about energy markets
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–
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production and sales volume levels
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levels of oil, natural-gas, and NGL reserves
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operating results
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competitive conditions
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technology
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availability of capital resources, levels of capital expenditures, and other contractual obligations
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supply and demand for, the price of, and the commercialization and transporting of oil, natural gas, NGLs, and other products or services
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volatility in the commodity-futures market
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–
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weather
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inflation
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availability of goods and services, including unexpected changes in costs
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drilling and other operational risks
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processing volume, pipeline throughput, and produced water disposal
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general economic conditions, nationally, internationally, or in the jurisdictions in which the Company is, or in the future may be, doing business
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–
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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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–
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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
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the creditworthiness and performance of the Company’s counterparties, including financial institutions, operating partners, and other parties
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volatility in the securities, capital, or credit markets and related risks such as general credit, liquidity, and interest-rate risk
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the Company’s ability to successfully monetize select assets, repay or refinance its debt, successfully complete its debt-reduction program, and the impact of changes in the Company’s credit ratings
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the Company’s ability to successfully complete its Share-Repurchase Program
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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
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uncertainties and liabilities associated with acquired and divested properties and businesses
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disruptions in international oil and NGL cargo shipping activities
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physical, digital, internal, and external security breaches
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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
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–
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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
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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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BUSINESS AND PROPERTIES
GENERAL
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PART I
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GENERAL
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BUSINESS AND PROPERTIES
EXPLORATION AND PRODUCTION PROPERTIES AND ACTIVITES
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EXPLORATION AND PRODUCTION PROPERTIES AND ACTIVITIES
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BUSINESS AND PROPERTIES
EXPLORATION AND PRODUCTION PROPERTIES AND ACTIVITES
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ANADARKO’S EXPLORATION AND PRODUCTION PROPERTIES AND ACTIVITIES
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BUSINESS AND PROPERTIES
EXPLORATION AND PRODUCTION PROPERTIES AND ACTIVITES
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United States
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2018 U.S. OPERATIONS
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U.S. ONSHORE OIL AND NATURAL-GAS EXPLORATION AND PRODUCTION OPERATIONS
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BUSINESS AND PROPERTIES
EXPLORATION AND PRODUCTION PROPERTIES AND ACTIVITES
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Delaware Basin
Anadarko operates approximately 750 wells and owns interests in approximately 450 nonoperated wells in the Delaware basin. The Company’s 2018 drilling activity primarily targeted the Wolfcamp shale play, while also testing the liquids-rich Bone Spring tight sands. Having secured operatorship on a majority of its legacy joint venture acreage, the Company continued to build out one of the most expansive and integrated infrastructure positions in the region, primarily in Reeves and Loving counties. In 2018, the Company focused on securing sufficient oil takeaway capacity, ending the year with approximately 46% of its Delaware basin operated oil volume being sold at Gulf Coast markets via the Enterprise pipeline. This capacity is expected to increase to 100% when the Cactus II pipeline is in full service. Anadarko ended 2018 with eight operated drilling rigs and five completion crews.
The successful Wolfcamp shale delineation program continues to deliver encouraging results across the majority of Anadarko’s acreage position. Anadarko is testing multiple zones within the Wolfcamp shale and several development concepts for increased efficiency. Included in these development concepts are multi-well pads, extended laterals, enhanced completion designs, and optimized horizontal-well spacing. The Company expects the Wolfcamp shale play to provide substantial opportunity for Anadarko’s future activity in the basin.
The Reeves and Loving ROTFs and the first train at the Mentone natural-gas processing plant were placed into service in 2018, adding 120 MBbls/d and 200 MMcf/d of nameplate oil and gas processing capacity to the area. See
Midstream Properties and Activities
for additional discussion on the significant infrastructure added during 2018 to facilitate growth from this asset.
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BUSINESS AND PROPERTIES
EXPLORATION AND PRODUCTION PROPERTIES AND ACTIVITES
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DJ Basin
Anadarko operates approximately 3,400 vertical wells and 1,700 horizontal wells in the Niobrara and Codell formations in the DJ basin. Horizontal drilling results in the field continue to be strong, with enhanced economics realized through the Company’s ownership of the Land Grant and operational efficiencies in drilling and completions.
Anadarko continues to drive drilling efficiencies in its DJ basin operations. In 2018, the Company increased its horizontal lateral length by approximately 16% and improved its footage drilled per rig-day by approximately 30% from 2017. The Company ended 2018 with four operated drilling rigs and two completion crews.
The sixth COSF train was placed in service during the third quarter of 2018, adding 30 MBbls/d of oil-stabilization capacity. Construction activities have commenced at the Latham plant, which will deliver 400 MMcf/d of increased natural-gas processing capacity. See
Midstream Properties and Activities
for additional discussion.
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Powder River Basin
In the southern Powder River basin, Anadarko’s acreage is mainly located in Converse County, Wyoming. The field contains the Turner, Niobrara, and Mowry formations that hold both liquids and natural gas. In 2018, the Company invested $181 million on lease acquisitions, accumulating a 300,000 gross-acre position in the southern Powder River basin area, with significant stacked-oil potential.
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BUSINESS AND PROPERTIES
EXPLORATION AND PRODUCTION PROPERTIES AND ACTIVITES
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Greater Natural Buttes
The Greater Natural Buttes area in eastern Utah is a tight-gas asset. The Company uses cryogenic and refrigeration processing facilities in this area to extract NGLs from the natural-gas stream. There was minimal activity in this field during 2018 due to capital being allocated to higher-margin projects.
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BUSINESS AND PROPERTIES
EXPLORATION AND PRODUCTION PROPERTIES AND ACTIVITES
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GULF OF MEXICO OIL AND NATURAL-GAS EXPLORATION AND PRODUCTION OPERATIONS
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Horn Mountain (100% working interest)
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BUSINESS AND PROPERTIES
EXPLORATION AND PRODUCTION PROPERTIES AND ACTIVITES
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Marlin (100% working interest)
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Holstein (100% working interest)
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Caesar Tonga (33.75% working interest)
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Constellation (33.33% working interest)
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Lucius (48.9% working interest)
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K2 Complex (41.8% working interest)
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BUSINESS AND PROPERTIES
EXPLORATION AND PRODUCTION PROPERTIES AND ACTIVITES
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International
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2018 INTERNATIONAL OPERATIONS
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Algeria
Anadarko is engaged in production and development operations in Algeria’s Sahara Desert in Blocks 404A and 208, which are governed by a Production Sharing Agreement (PSA) between Anadarko, Sonatrach, and other partners. Under this PSA, the Company is responsible for 24.5% of the development and production costs. The Company produces oil and NGLs through the El Merk central processing facility (CPF) in Block 208 and oil through the Hassi Berkine South and Ourhoud CPFs in Block 404A. Gross production through these facilities averaged more than 320 MBbls/d in 2018, inclusive of 29 days of planned downtime for statutory maintenance at the Hassi Berkine South CPF. The Company drilled seven development wells in 2018 and plans to continue drilling operations throughout 2019.
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BUSINESS AND PROPERTIES
EXPLORATION AND PRODUCTION PROPERTIES AND ACTIVITES
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Ghana
Anadarko’s production and development activities in Ghana are located offshore in the West Cape Three Points Block and the Deepwater Tano Block.
The Jubilee field (27% nonoperated participating interest), which spans both the West Cape Three Points Block and the Deepwater Tano Block, utilizes a 120 MBbls/d-capacity FPSO to produce from subsea wells. Gross production averaged 78 MBbls/d of oil in 2018. An average of 75 MMcf/d of natural gas was exported to an onshore natural-gas processing plant in satisfaction of a commitment established in conjunction with the Jubilee development plan. The partnership received Ghanaian government approval for the full-field plan of development in October 2017 and drilling operations commenced in 2018. The operator drilled, completed, and brought online a production well in each of the third and fourth quarters of 2018. Additionally, a previously drilled water injector well was completed and put into service at the end of 2018.
In 2016, the operator of the Jubilee field announced that damage to the FPSO turret bearing had occurred. As a result, new production and offtake procedures were implemented, and the partners agreed to a long-term solution to convert the FPSO to a permanently spread-moored facility. Interim spread mooring of the FPSO commenced in the fourth quarter of 2016 and was completed in 2017. In 2018, the operator completed the necessary work, including two shutdown periods, to effectively stabilize the turret and rotate the FPSO to its permanent heading. Completion of the permanent spread-mooring anchoring system is expected in early 2019, with no further shutdowns anticipated.
The TEN project (19% nonoperated participating interest), located in the Deepwater Tano Block, utilizes an 80 MBbls/d-capacity FPSO to produce from subsea wells. The project achieved first oil in the third quarter of 2016. However additional field development was delayed due to a border dispute between Ghana and Côte d’Ivoire. In September 2017, the International Tribunal for the Law of the Sea issued a ruling 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, did not affect the TEN fields, and the operator resumed development drilling in the first quarter of 2018. The first well was completed and brought online in the third quarter of 2018. Drilling on two additional wells was completed in the fourth quarter of 2018, with completion activities ongoing at year end. The project averaged gross production of 65 MBbls/d of oil in 2018.
In 2019, the operator plans to drill and complete seven new wells to optimize the deliverability from the Jubilee and TEN fields.
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BUSINESS AND PROPERTIES
EXPLORATION AND PRODUCTION PROPERTIES AND ACTIVITES
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Mozambique
Anadarko operates Offshore Area 1 (26.5% working interest).
Development
In February 2018, the Government of Mozambique approved the Development Plan for the Anadarko-operated, initial two-train Golfinho/Atum onshore LNG project, marking a major milestone required for an FID. Major infrastructure projects, including roads, camps, an airstrip, and resettlement, are underway and proceeding as planned, preparing the area for onshore LNG facility construction. 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 preferred offshore construction and installation contractor was selected in the fourth quarter of 2018, and the contracts with the onshore and offshore construction, installation, and equipment contractors are being finalized. Subsequent to year end, LNG sales and purchase agreements (SPAs) were executed with Tokyo Gas Co., Ltd; Centrica LNG Company Ltd., a subsidiary of Centrica plc; Shell International Trading Middle East Ltd; and CNOOC Gas and Power Singapore Trading & Marketing Pte. Ltd, increasing the contracted volume to more than 7.5 MTPA, inclusive of previously announced SPAs executed with Tohoku Electric Power Company, Inc. and Électricité de France, S.A. Execution of SPAs representing 2.0 MTPA of additional contracted volume is anticipated prior to FID.
With progress on major contracts and marketing SPAs, the Company formally launched project financing in December 2018 with the aim of securing funding for up to two-thirds of the required construction capital. The Company is working to finalize project finance arrangements with lenders and secure all partner and government-related approvals required to position the Company to make a final investment decision in the first half of 2019.
Appraisal
In Offshore Area 1, the Company completed the interpretations of the re-processed 3D seismic data covering the Orca, Tubarao, and Tubarao-Tigre discovery areas, and continues to assess these areas in accordance with the appraisal program submitted to the Government of Mozambique.
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BUSINESS AND PROPERTIES
EXPLORATION AND PRODUCTION PROPERTIES AND ACTIVITES
|
Proved Reserves
|
|
Oil
(MMBbls)
|
|
Natural Gas
(Bcf)
|
|
NGLs
(MMBbls)
|
|
Total
(MMBOE)
|
|
December 31, 2018
|
|
|
|
|
||||
Developed
|
|
|
|
|
||||
United States
|
392
|
|
2,564
|
|
192
|
|
1,011
|
|
International
|
123
|
|
24
|
|
10
|
|
137
|
|
Undeveloped
|
|
|
|
|
||||
United States
|
137
|
|
634
|
|
66
|
|
309
|
|
International
|
15
|
|
8
|
|
—
|
|
16
|
|
Total proved reserves
|
667
|
|
3,230
|
|
268
|
|
1,473
|
|
December 31, 2017
|
|
|
|
|
||||
Developed
|
|
|
|
|
||||
United States
|
361
|
|
2,640
|
|
176
|
|
977
|
|
International
|
136
|
|
24
|
|
10
|
|
150
|
|
Undeveloped
|
|
|
|
|
||||
United States
|
140
|
|
553
|
|
56
|
|
288
|
|
International
|
21
|
|
13
|
|
1
|
|
24
|
|
Total proved reserves
|
658
|
|
3,230
|
|
243
|
|
1,439
|
|
December 31, 2016
|
|
|
|
|
||||
Developed
|
|
|
|
|
||||
United States
|
360
|
|
3,637
|
|
193
|
|
1,159
|
|
International
|
147
|
|
25
|
|
15
|
|
166
|
|
Undeveloped
|
|
|
|
|
||||
United States
|
181
|
|
762
|
|
75
|
|
383
|
|
International
|
14
|
|
—
|
|
—
|
|
14
|
|
Total proved reserves
|
702
|
|
4,424
|
|
283
|
|
1,722
|
|
|
BUSINESS AND PROPERTIES
EXPLORATION AND PRODUCTION PROPERTIES AND ACTIVITES
|
MMBOE
|
2018
|
|
2017
|
|
2016
|
|
Proved Reserves
|
|
|
|
|||
January 1
|
1,439
|
|
1,722
|
|
2,057
|
|
Reserves additions and revisions
|
|
|
|
|||
Discoveries and extensions
|
164
|
|
114
|
|
40
|
|
Infill-drilling additions
(1)
|
181
|
|
71
|
|
69
|
|
Drilling-related reserves additions and revisions
|
345
|
|
185
|
|
109
|
|
Other non-price-related revisions
(1)
|
(61
|
)
|
59
|
|
191
|
|
Net organic reserves additions
|
284
|
|
244
|
|
300
|
|
Acquisition of proved reserves in place
|
—
|
|
3
|
|
97
|
|
Price-related revisions
(1)
|
29
|
|
92
|
|
(147
|
)
|
Total reserves additions and revisions
|
313
|
|
339
|
|
250
|
|
Sales in place
|
(37
|
)
|
(379
|
)
|
(294
|
)
|
Production
|
(242
|
)
|
(243
|
)
|
(291
|
)
|
December 31
|
1,473
|
|
1,439
|
|
1,722
|
|
Proved Developed Reserves
|
|
|
|
|||
January 1
|
1,127
|
|
1,325
|
|
1,632
|
|
December 31
|
1,148
|
|
1,127
|
|
1,325
|
|
(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.
|
|
BUSINESS AND PROPERTIES
EXPLORATION AND PRODUCTION PROPERTIES AND ACTIVITES
|
MMBOE
|
|
|
PUDs at January 1, 2018
|
312
|
|
Revisions of prior estimates
|
117
|
|
Extensions, discoveries, and other additions
|
47
|
|
Conversions to developed
|
(144
|
)
|
Sales in place
|
(7
|
)
|
PUDs at December 31, 2018
|
325
|
|
MMBOE
|
December 31, 2018
|
|
Revisions due to changes in year-end prices (price impact to opening balance)
|
—
|
|
Other revisions of prior estimates
|
|
|
Revisions due to performance
|
18
|
|
Revisions due to cost updates
|
2
|
|
Revisions due to successful infill drilling
|
158
|
|
Revisions due to development plan updates
|
(61
|
)
|
Total other revisions of prior estimates
|
117
|
|
Revisions of prior estimates
|
117
|
|
–
|
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.
|
|
BUSINESS AND PROPERTIES
EXPLORATION AND PRODUCTION PROPERTIES AND ACTIVITES
|
|
BUSINESS AND PROPERTIES
EXPLORATION AND PRODUCTION PROPERTIES AND ACTIVITES
|
|
BUSINESS AND PROPERTIES
EXPLORATION AND PRODUCTION PROPERTIES AND ACTIVITES
|
Sales Volume, Prices, and Production Costs
|
|
Sales Volume
|
|
|
Average Sales Prices
(1)
|
Average
Production Costs
(2)
(Per BOE)
|
|
|||||||||||||||||||
|
Oil
(MMBbls)
|
|
Natural Gas
(Bcf)
|
|
NGLs
(MMBbls)
|
|
Barrels of Oil
Equivalent
(MMBOE)
|
|
|
Oil
(Per Bbl)
|
|
Natural Gas
(Per Mcf)
|
|
NGLs
(Per Bbl)
|
|
||||||||||
2018
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
United States
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
DJ basin
|
36
|
|
225
|
|
22
|
|
95
|
|
|
|
$
|
63.17
|
|
|
$
|
2.44
|
|
|
$
|
32.80
|
|
|
$
|
1.90
|
|
Other United States
|
71
|
|
165
|
|
14
|
|
113
|
|
|
|
64.44
|
|
|
2.76
|
|
|
34.52
|
|
|
6.43
|
|
||||
Total United States
|
107
|
|
390
|
|
36
|
|
208
|
|
|
|
64.01
|
|
|
2.57
|
|
|
33.46
|
|
|
4.35
|
|
||||
International
|
33
|
|
—
|
|
2
|
|
35
|
|
|
|
70.38
|
|
|
0.66
|
|
|
43.25
|
|
|
7.09
|
|
||||
Total
|
140
|
|
390
|
|
38
|
|
243
|
|
|
|
65.51
|
|
|
2.57
|
|
|
33.93
|
|
|
4.73
|
|
||||
2017
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
United States
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
DJ basin
|
31
|
|
212
|
|
21
|
|
88
|
|
|
|
$
|
49.73
|
|
|
$
|
2.55
|
|
|
$
|
27.46
|
|
|
$
|
1.67
|
|
Other United States
|
66
|
|
266
|
|
13
|
|
123
|
|
|
|
49.57
|
|
|
3.03
|
|
|
32.24
|
|
|
5.22
|
|
||||
Total United States
|
97
|
|
478
|
|
34
|
|
211
|
|
|
|
49.62
|
|
|
2.82
|
|
|
29.24
|
|
|
3.75
|
|
||||
International
|
32
|
|
—
|
|
2
|
|
34
|
|
|
|
53.77
|
|
|
—
|
|
|
35.64
|
|
|
5.84
|
|
||||
Total
|
129
|
|
478
|
|
36
|
|
245
|
|
|
|
50.66
|
|
|
2.82
|
|
|
29.54
|
|
|
4.04
|
|
||||
2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
United States
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
DJ basin
|
33
|
|
214
|
|
20
|
|
89
|
|
|
|
$
|
40.27
|
|
|
$
|
2.00
|
|
|
$
|
18.26
|
|
|
$
|
1.26
|
|
Other United States
|
52
|
|
552
|
|
24
|
|
168
|
|
|
|
38.29
|
|
|
2.06
|
|
|
20.21
|
|
|
2.97
|
|
||||
Total United States
|
85
|
|
766
|
|
44
|
|
257
|
|
|
|
39.06
|
|
|
2.04
|
|
|
19.32
|
|
|
2.37
|
|
||||
International
|
31
|
|
—
|
|
2
|
|
33
|
|
|
|
43.93
|
|
|
—
|
|
|
25.63
|
|
|
6.28
|
|
||||
Total
|
116
|
|
766
|
|
46
|
|
290
|
|
|
|
40.34
|
|
|
2.04
|
|
|
19.64
|
|
|
2.81
|
|
(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.
|
|
BUSINESS AND PROPERTIES
EXPLORATION AND PRODUCTION PROPERTIES AND ACTIVITES
|
Delivery Commitments
|
|
Delivery Commitments
|
|||||||||
|
2019
|
|
2020
|
|
2021
|
|
Thereafter
|
|
Total
|
|
Oil (MMBbls)
|
|
|
|
|
|
|||||
United States
|
19
|
|
9
|
|
—
|
|
—
|
|
28
|
|
International
|
9
|
|
—
|
|
—
|
|
—
|
|
9
|
|
Natural-Gas (Bcf)
|
|
|
|
|
|
|||||
United States
(1)
|
470
|
|
264
|
|
224
|
|
515
|
|
1,473
|
|
NGLs (MMBbls)
|
|
|
|
|
|
|||||
United States
|
4
|
|
—
|
|
—
|
|
—
|
|
4
|
|
(1)
|
Volume committed to various customers through
2033
.
|
Properties and Leases
|
|
Developed
Lease
|
|
Undeveloped
Lease
|
|
Fee
Mineral
(1)
|
|
Total
|
||||||||||||
thousands
|
Gross
|
|
Net
|
|
|
Gross
|
|
Net
|
|
|
Gross
|
|
Net
|
|
|
Gross
|
|
Net
|
|
United States
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
Onshore
|
2,272
|
|
1,445
|
|
|
545
|
|
313
|
|
|
9,868
|
|
8,154
|
|
|
12,685
|
|
9,912
|
|
Offshore
|
315
|
|
183
|
|
|
1,017
|
|
822
|
|
|
—
|
|
—
|
|
|
1,332
|
|
1,005
|
|
Total United States
|
2,587
|
|
1,628
|
|
|
1,562
|
|
1,135
|
|
|
9,868
|
|
8,154
|
|
|
14,017
|
|
10,917
|
|
International
|
635
|
|
138
|
|
|
36,439
|
|
30,536
|
|
|
—
|
|
—
|
|
|
37,074
|
|
30,674
|
|
Total
|
3,222
|
|
1,766
|
|
|
38,001
|
|
31,671
|
|
|
9,868
|
|
8,154
|
|
|
51,091
|
|
41,591
|
|
(1)
|
The Company’s fee mineral acreage is primarily undeveloped.
|
|
BUSINESS AND PROPERTIES
EXPLORATION AND PRODUCTION PROPERTIES AND ACTIVITES
|
Drilling Program
|
Drilling Statistics
|
|
Net Exploratory
|
|
Net Development
|
Total
|
|
||||||||||
|
Productive
|
|
Dry Holes
|
|
Total
|
|
|
Productive
|
|
Dry Holes
|
|
Total
|
|
||
2018
|
|
|
|
|
|
|
|
|
|||||||
United States
|
17.0
|
|
2.0
|
|
19.0
|
|
|
393.7
|
|
5.4
|
|
399.1
|
|
418.1
|
|
International
|
—
|
|
—
|
|
—
|
|
|
2.6
|
|
—
|
|
2.6
|
|
2.6
|
|
Total
|
17.0
|
|
2.0
|
|
19.0
|
|
|
396.3
|
|
5.4
|
|
401.7
|
|
420.7
|
|
2017
|
|
|
|
|
|
|
|
|
|||||||
United States
|
6.6
|
|
3.6
|
|
10.2
|
|
|
359.1
|
|
2.4
|
|
361.5
|
|
371.7
|
|
International
|
—
|
|
7.3
|
|
7.3
|
|
|
—
|
|
—
|
|
—
|
|
7.3
|
|
Total
|
6.6
|
|
10.9
|
|
17.5
|
|
|
359.1
|
|
2.4
|
|
361.5
|
|
379.0
|
|
2016
|
|
|
|
|
|
|
|
|
|||||||
United States
|
3.7
|
|
1.2
|
|
4.9
|
|
|
322.1
|
|
—
|
|
322.1
|
|
327.0
|
|
International
|
—
|
|
1.8
|
|
1.8
|
|
|
2.9
|
|
—
|
|
2.9
|
|
4.7
|
|
Total
|
3.7
|
|
3.0
|
|
6.7
|
|
|
325.0
|
|
—
|
|
325.0
|
|
331.7
|
|
|
Wells in the process of drilling or in active completion
|
|
Wells suspended or waiting on completion
(1)
|
||||||
|
Exploration
|
|
Development
|
|
|
Exploration
|
|
Development
(2)
|
|
United States
|
|
|
|
|
|
||||
Gross
|
3
|
|
45
|
|
|
8
|
|
489
|
|
Net
|
0.2
|
|
35.2
|
|
|
4.6
|
|
370.5
|
|
International
|
|
|
|
|
|
||||
Gross
|
—
|
|
1
|
|
|
25
|
|
8
|
|
Net
|
—
|
|
0.3
|
|
|
7.1
|
|
1.8
|
|
Total
|
|
|
|
|
|
||||
Gross
|
3
|
|
46
|
|
|
33
|
|
497
|
|
Net
|
0.2
|
|
35.5
|
|
|
11.7
|
|
372.3
|
|
(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.
|
|
BUSINESS AND PROPERTIES
EXPLORATION AND PRODUCTION PROPERTIES AND ACTIVITES
|
Productive Wells
|
|
Oil Wells
(1)
|
|
Gas Wells
(1)
|
|
United States
|
|
|
||
Gross
|
3,976
|
|
7,852
|
|
Net
|
2,544.3
|
|
6,543.4
|
|
International
|
|
|
||
Gross
|
215
|
|
9
|
|
Net
|
38.9
|
|
2.2
|
|
Total
|
|
|
||
Gross
|
4,191
|
|
7,861
|
|
Net
|
2,583.2
|
|
6,545.6
|
|
(1)
Includes wells containing multiple completions as follows:
|
|
|
||
Gross
|
364
|
|
2,510
|
|
Net
|
311.3
|
|
2,263.4
|
|
|
BUSINESS & PROPERTIES
MIDSTREAM PROPERTIES AND ACTIVITIES
|
MIDSTREAM PROPERTIES AND ACTIVITIES
|
ANADARKO’S MIDSTREAM PROPERTIES AND ACTIVITIES
|
|
BUSINESS & PROPERTIES
MIDSTREAM PROPERTIES AND ACTIVITIES
|
WES Midstream
|
|
BUSINESS & PROPERTIES
MIDSTREAM PROPERTIES AND ACTIVITIES
|
Area
|
Miles of
Pipelines
|
|
Total
Horsepower
(1)
|
|
2018 Average Net
Throughput (MMcf/d)
|
|
2018 Average Net
Throughput (MBbls/d)
|
|
DJ basin
|
4,720
|
|
302,200
|
|
1,110
|
|
55
|
|
Delaware basin
|
2,080
|
|
412,700
|
|
1,040
|
|
160
|
|
Wyoming
|
4,210
|
|
160,800
|
|
840
|
|
—
|
|
Eagleford
|
880
|
|
202,700
|
|
445
|
|
40
|
|
Greater Natural Buttes
|
40
|
|
74,900
|
|
360
|
|
10
|
|
Other
|
930
|
|
9,700
|
|
100
|
|
95
|
|
Total
|
12,860
|
|
1,163,000
|
|
3,895
|
|
360
|
|
(1)
|
Excludes horsepower associated with transportation assets.
|
Other Midstream
|
Area
|
Miles of
Pipelines |
|
Total
Horsepower (1) |
|
2018 Average Net
Throughput (MMcf/d)
|
|
2018 Average Net
Throughput (MBbls/d)
|
|
DJ basin
|
1,070
|
|
23,300
|
|
220
|
|
120
|
|
Delaware basin
|
1,140
|
|
76,900
|
|
150
|
|
285
|
|
Greater Natural Buttes
|
1,130
|
|
146,800
|
|
280
|
|
—
|
|
Other
|
300
|
|
—
|
|
—
|
|
15
|
|
Total
|
3,640
|
|
247,000
|
|
650
|
|
420
|
|
(1)
|
Excludes horsepower associated with transportation assets.
|
|
BUSINESS & PROPERTIES
COMPETITION AND EMPLOYEES |
COMPETITION
|
EMPLOYEES
|
|
BUSINESS & PROPERTIES
REGULATORY AND ENVIRONMENTAL MATTERS
|
REGULATORY AND ENVIRONMENTAL MATTERS
|
Environmental and Occupational Health and Safety Regulations
|
–
|
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
|
–
|
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
|
|
BUSINESS & PROPERTIES
REGULATORY AND ENVIRONMENTAL MATTERS
|
|
BUSINESS & PROPERTIES
REGULATORY AND ENVIRONMENTAL MATTERS
|
Oil Spill-Response Plan
|
TITLE TO PROPERTIES
|
|
BUSINESS & PROPERTIES
EXECUTIVE OFFICERS OF THE REGISTRANT |
EXECUTIVE OFFICERS OF THE REGISTRANT
|
Name
|
Age at
January 31, 2019
|
Position
|
R. A. Walker
|
61
|
Chairman and Chief Executive Officer
|
Robert G. Gwin
|
55
|
President
|
Benjamin M. Fink
|
48
|
Executive Vice President, Finance and Chief Financial Officer
|
Daniel E. Brown
|
43
|
Executive Vice President, U.S. Onshore Operations
|
Mitchell W. Ingram
|
56
|
Executive Vice President, International, Deepwater and Exploration
|
Amanda M. McMillian
|
45
|
Executive Vice President and General Counsel
|
Christopher O. Champion
|
49
|
Senior Vice President, Chief Accounting Officer and Controller
|
|
BUSINESS & PROPERTIES
EXECUTIVE OFFICERS OF THE REGISTRANT |
|
RISK FACTORS
|
RISK FACTORS
|
–
|
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
|
|
RISK FACTORS
|
–
|
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
|
–
|
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.
|
–
|
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
|
|
RISK FACTORS
|
–
|
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.
|
–
|
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.
|
|
RISK FACTORS
|
|
RISK FACTORS
|
–
|
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
|
|
RISK FACTORS
|
–
|
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
|
|
RISK FACTORS
|
|
RISK FACTORS
|
–
|
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
|
|
RISK FACTORS
|
|
RISK FACTORS
|
–
|
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
|
|
RISK FACTORS
|
–
|
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
|
|
RISK FACTORS
|
–
|
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
|
|
RISK FACTORS
|
|
RISK FACTORS
|
–
|
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
|
|
RISK FACTORS
|
|
OTHER INFORMATION
|
|
OTHER INFORMATION
|
PART II
|
MARKET INFORMATION, HOLDERS, AND DIVIDENDS
|
SECURITIES AUTHORIZED FOR ISSUANCE UNDER EQUITY COMPENSATION PLANS
|
Plan Category
|
(a)
Number of securities
to be issued upon
exercise of
outstanding options,
warrants, and rights
|
|
(b)
Weighted-average
exercise price of
outstanding
options, warrants,
and rights
|
|
(c)
Number of securities
remaining available
for future issuance
under equity
compensation plans
(excluding securities
reflected in column(a))
|
|
||
Equity compensation plans approved by security holders
|
6,356,970
|
|
|
$
|
67.00
|
|
20,246,444
|
|
Equity compensation plans not approved by security holders
|
—
|
|
|
—
|
|
—
|
|
|
Total
|
6,356,970
|
|
|
$
|
67.00
|
|
20,246,444
|
|
|
OTHER INFORMATION
|
PURCHASES OF EQUITY SECURITIES BY THE ISSUER AND AFFILIATED PERSONS
|
Period
|
Total
number of
shares
purchased
(1)
|
|
Average
price paid
per share
|
|
Total number of
shares purchased
as part of publicly
announced plans
or programs
(2)
|
|
Approximate dollar
value of shares that
may yet be
purchased under the
plans or programs
(2)(3)
|
|
||||
October 1-31, 2018
|
35,626
|
|
|
$
|
64.55
|
|
—
|
|
|
$
|
500,000,003
|
|
November 1-30, 2018
|
56,912
|
|
|
$
|
55.73
|
|
—
|
|
|
$
|
1,500,000,003
|
|
December 1-31, 2018
|
4,792,707
|
|
|
$
|
52.35
|
|
4,776,318
|
|
|
$
|
1,250,000,064
|
|
Total
|
4,885,245
|
|
|
$
|
52.48
|
|
4,776,318
|
|
|
|
|
(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.
|
|
OTHER INFORMATION
|
PERFORMANCE GRAPH
|
Fiscal Year Ended December 31
|
2013
|
|
|
2014
|
|
|
2015
|
|
|
2016
|
|
|
2017
|
|
|
2018
|
|
||||||
Anadarko Petroleum Corporation
|
$
|
100.00
|
|
|
$
|
105.14
|
|
|
$
|
62.88
|
|
|
$
|
90.58
|
|
|
$
|
69.96
|
|
|
$
|
58.19
|
|
S&P 500
|
100.00
|
|
|
113.69
|
|
|
115.26
|
|
|
129.05
|
|
|
157.22
|
|
|
150.33
|
|
||||||
Peer Group
|
100.00
|
|
|
92.09
|
|
|
69.98
|
|
|
91.31
|
|
|
94.42
|
|
|
82.93
|
|
|
OTHER INFORMATION
|
|
Summary Financial Information
(1)
|
||||||||||||||||||
millions except per-share and employee amounts
|
2018
|
|
|
2017
|
|
|
2016
|
|
|
2015
|
|
|
2014
|
|
|||||
Sales Revenues
(6)
|
$
|
13,070
|
|
|
$
|
10,969
|
|
|
$
|
8,447
|
|
|
$
|
9,486
|
|
|
$
|
16,375
|
|
Gains (Losses) on Divestitures and Other, net
|
312
|
|
|
939
|
|
|
(578
|
)
|
|
(788
|
)
|
|
2,095
|
|
|||||
Total Revenues and Other
|
13,382
|
|
|
11,908
|
|
|
7,869
|
|
|
8,698
|
|
|
18,470
|
|
|||||
Operating Income (Loss)
|
2,619
|
|
|
(565
|
)
|
|
(2,372
|
)
|
|
(8,743
|
)
|
|
5,438
|
|
|||||
Net Income (Loss)
(2)
|
752
|
|
|
(211
|
)
|
|
(2,808
|
)
|
|
(6,812
|
)
|
|
(1,563
|
)
|
|||||
Net Income (Loss) Attributable to Common Stockholders
|
615
|
|
|
(456
|
)
|
|
(3,071
|
)
|
|
(6,692
|
)
|
|
(1,750
|
)
|
|||||
Per Common Share (amounts attributable to common stockholders)
|
|
|
|
|
|
|
|
|
|
||||||||||
Net Income (Loss)—Basic
|
$
|
1.20
|
|
|
$
|
(0.85
|
)
|
|
$
|
(5.90
|
)
|
|
$
|
(13.18
|
)
|
|
$
|
(3.47
|
)
|
Net Income (Loss)—Diluted
|
$
|
1.20
|
|
|
$
|
(0.85
|
)
|
|
$
|
(5.90
|
)
|
|
$
|
(13.18
|
)
|
|
$
|
(3.47
|
)
|
Dividends
|
$
|
1.05
|
|
|
$
|
0.20
|
|
|
$
|
0.20
|
|
|
$
|
1.08
|
|
|
$
|
0.99
|
|
Average Number of Common Shares Outstanding—Basic
|
504
|
|
|
548
|
|
|
522
|
|
|
508
|
|
|
506
|
|
|||||
Average Number of Common Shares Outstanding—Diluted
|
504
|
|
|
548
|
|
|
522
|
|
|
508
|
|
|
506
|
|
|||||
Net Cash Provided by (Used in) Operating Activities
(3)
|
$
|
5,929
|
|
|
$
|
4,009
|
|
|
$
|
3,000
|
|
|
$
|
(1,877
|
)
|
|
$
|
8,466
|
|
Net Cash Provided by (Used in) Investing Activities
|
(5,982
|
)
|
|
(1,030
|
)
|
|
(2,742
|
)
|
|
(4,771
|
)
|
|
(6,472
|
)
|
|||||
Net Cash Provided by (Used in) Financing Activities
|
(3,177
|
)
|
|
(1,613
|
)
|
|
2,008
|
|
|
220
|
|
|
1,675
|
|
|||||
Capital Expenditures
|
$
|
6,185
|
|
|
$
|
5,300
|
|
|
$
|
3,314
|
|
|
$
|
5,888
|
|
|
$
|
9,256
|
|
Long-term debt - Anadarko
(4)
|
$
|
10,683
|
|
|
$
|
12,054
|
|
|
$
|
12,162
|
|
|
$
|
12,945
|
|
|
$
|
12,595
|
|
Long-term debt - WES and WGP
|
4,787
|
|
|
3,493
|
|
|
3,119
|
|
|
2,691
|
|
|
2,409
|
|
|||||
Total Stockholders’ Equity
|
8,496
|
|
|
10,696
|
|
|
12,212
|
|
|
12,819
|
|
|
19,725
|
|
|||||
Total Assets
|
$
|
40,376
|
|
|
$
|
42,086
|
|
|
$
|
45,564
|
|
|
$
|
46,331
|
|
|
$
|
60,879
|
|
Annual Sales Volume
|
|
|
|
|
|
|
|
|
|
||||||||||
Oil (MMBbls)
|
141
|
|
|
129
|
|
|
116
|
|
|
116
|
|
|
106
|
|
|||||
Natural Gas (Bcf)
|
390
|
|
|
478
|
|
|
766
|
|
|
852
|
|
|
945
|
|
|||||
Natural-Gas Liquids (MMBbls)
|
37
|
|
|
36
|
|
|
46
|
|
|
47
|
|
|
44
|
|
|||||
Total (MMBOE)
(5)
|
243
|
|
|
245
|
|
|
290
|
|
|
305
|
|
|
308
|
|
|||||
Average Daily Sales Volume
|
|
|
|
|
|
|
|
|
|
||||||||||
Oil (MBbls/d)
|
385
|
|
|
355
|
|
|
316
|
|
|
317
|
|
|
292
|
|
|||||
Natural Gas (MMcf/d)
|
1,069
|
|
|
1,309
|
|
|
2,093
|
|
|
2,334
|
|
|
2,589
|
|
|||||
Natural-Gas Liquids (MBbls/d)
|
103
|
|
|
99
|
|
|
128
|
|
|
130
|
|
|
119
|
|
|||||
Total (MBOE/d)
(5)
|
666
|
|
|
672
|
|
|
793
|
|
|
836
|
|
|
843
|
|
|||||
Proved Reserves
|
|
|
|
|
|
|
|
|
|
||||||||||
Oil Reserves (MMBbls)
|
667
|
|
|
658
|
|
|
702
|
|
|
713
|
|
|
929
|
|
|||||
Natural-gas Reserves (Tcf)
|
3.2
|
|
|
3.2
|
|
|
4.4
|
|
|
6.0
|
|
|
8.7
|
|
|||||
Natural-gas Liquids Reserves (MMBbls)
|
268
|
|
|
243
|
|
|
283
|
|
|
340
|
|
|
479
|
|
|||||
Total Proved Reserves (MMBOE)
(5)
|
1,473
|
|
|
1,439
|
|
|
1,722
|
|
|
2,057
|
|
|
2,858
|
|
|||||
Number of Employees
|
4,700
|
|
|
4,400
|
|
|
4,500
|
|
|
5,800
|
|
|
6,100
|
|
(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
.
|
|
MANAGEMENT’S DISCUSSION AND ANALYSIS
MANAGEMENT OVERVIEW
|
MANAGEMENT OVERVIEW
|
2019 Outlook
|
|
MANAGEMENT’S DISCUSSION AND ANALYSIS
MANAGEMENT OVERVIEW
|
–
|
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.
|
–
|
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.
|
–
|
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.
|
|
MANAGEMENT’S DISCUSSION AND ANALYSIS
MANAGEMENT OVERVIEW
|
Significant 2018 Operating and Financial Activities
|
–
|
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.
|
|
MANAGEMENT’S DISCUSSION AND ANALYSIS
MANAGEMENT OVERVIEW
|
–
|
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.
|
|
MANAGEMENT’S DISCUSSION AND ANALYSIS
RESULTS OF OPERATIONS
|
FINANCIAL RESULTS
|
millions except per-share amounts
|
2018
|
|
|
2017
|
|
|
2016
|
|
|||
Oil, natural-gas, and NGL sales
|
$
|
11,482
|
|
|
$
|
8,969
|
|
|
$
|
7,153
|
|
Gathering, processing, and marketing sales
|
1,588
|
|
|
2,000
|
|
|
1,294
|
|
|||
Gains (losses) on divestitures and other, net
|
312
|
|
|
939
|
|
|
(578
|
)
|
|||
Revenues and other
|
$
|
13,382
|
|
|
$
|
11,908
|
|
|
$
|
7,869
|
|
Costs and expenses
|
10,763
|
|
|
12,473
|
|
|
10,241
|
|
|||
Other (income) expense
|
1,134
|
|
|
1,123
|
|
|
1,457
|
|
|||
Income tax expense (benefit)
|
733
|
|
|
(1,477
|
)
|
|
(1,021
|
)
|
|||
Net income (loss) attributable to common stockholders
|
$
|
615
|
|
|
$
|
(456
|
)
|
|
$
|
(3,071
|
)
|
Net income (loss) per common share attributable to common stockholders—diluted
|
$
|
1.20
|
|
|
$
|
(0.85
|
)
|
|
$
|
(5.90
|
)
|
Average number of common shares outstanding—diluted
|
504
|
|
|
548
|
|
|
522
|
|
|
MANAGEMENT’S DISCUSSION AND ANALYSIS
RESULTS OF OPERATIONS
|
|
Barrels of Oil Equivalent
(MMBOE)
|
|
Barrels of Oil Equivalent
per Day (MBOE/d)
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
|
|
2018
|
|
2017
|
|
2016
|
|
United States
|
208
|
|
211
|
|
257
|
|
|
570
|
|
579
|
|
704
|
|
International
|
35
|
|
34
|
|
33
|
|
|
96
|
|
93
|
|
89
|
|
Total
|
243
|
|
245
|
|
290
|
|
|
666
|
|
672
|
|
793
|
|
|
MANAGEMENT’S DISCUSSION AND ANALYSIS
RESULTS OF OPERATIONS
|
Oil Sales Revenues, Average Prices, and Volume
|
|
2018
|
|
|
2017
|
|
|
2016
|
|
|||
Oil sales revenues (millions)
|
$
|
9,206
|
|
|
$
|
6,552
|
|
|
$
|
4,668
|
|
|
|
|
|
|
|
||||||
Price per barrel
|
|
|
|
|
|
||||||
United States
|
$
|
64.01
|
|
|
$
|
49.62
|
|
|
$
|
39.06
|
|
International
|
70.38
|
|
|
53.77
|
|
|
43.93
|
|
|||
Total
|
$
|
65.51
|
|
|
$
|
50.66
|
|
|
$
|
40.34
|
|
|
|
|
|
|
|
||||||
Sales volume (MMBbls)
|
|
|
|
|
|
||||||
United States
|
108
|
|
|
97
|
|
|
85
|
|
|||
International
|
33
|
|
|
32
|
|
|
31
|
|
|||
Total
|
141
|
|
|
129
|
|
|
116
|
|
|||
|
|
|
|
|
|
||||||
Sales volume per day (MBbls/d)
|
|
|
|
|
|
||||||
United States
|
294
|
|
|
266
|
|
|
233
|
|
|||
International
|
91
|
|
|
89
|
|
|
83
|
|
|||
Total
|
385
|
|
|
355
|
|
|
316
|
|
|
MANAGEMENT’S DISCUSSION AND ANALYSIS
RESULTS OF OPERATIONS
|
–
|
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.
|
|
MANAGEMENT’S DISCUSSION AND ANALYSIS
RESULTS OF OPERATIONS
|
Natural-Gas Sales Revenues, Volume, and Average Prices
|
|
2018
|
|
|
2017
|
|
|
2016
|
|
|||
Natural-gas sales revenues (millions)
|
$
|
1,005
|
|
|
$
|
1,348
|
|
|
$
|
1,564
|
|
|
|
|
|
|
|
||||||
Price per Mcf
|
$
|
2.57
|
|
|
$
|
2.82
|
|
|
$
|
2.04
|
|
|
|
|
|
|
|
||||||
Sales volume (Bcf)
(1)
|
390
|
|
|
478
|
|
|
766
|
|
|||
Sales volume per day (MMcf/d)
(1)
|
1,069
|
|
|
1,309
|
|
|
2,093
|
|
(1)
|
All natural-gas sales volume originates in the United States.
|
|
MANAGEMENT’S DISCUSSION AND ANALYSIS
RESULTS OF OPERATIONS
|
Natural-Gas Liquids Sales Revenues, Volume, and Average Prices
|
|
2018
|
|
|
2017
|
|
|
2016
|
|
|||
Natural-gas liquids sales revenues (millions)
|
$
|
1,271
|
|
|
$
|
1,069
|
|
|
$
|
921
|
|
|
|
|
|
|
|
||||||
Price per barrel
|
$
|
33.93
|
|
|
$
|
29.54
|
|
|
$
|
19.64
|
|
|
|
|
|
|
|
||||||
Sales volume (MMBbls)
(1)
|
37
|
|
|
36
|
|
|
46
|
|
|||
Sales volume per day (MBbls/d)
(1)
|
103
|
|
|
99
|
|
|
128
|
|
(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.
|
|
MANAGEMENT’S DISCUSSION AND ANALYSIS
RESULTS OF OPERATIONS
|
Gathering, Processing, and Marketing
|
millions
|
2018
|
|
|
2017
|
|
|
2016
|
|
|||
Gathering, processing, and marketing sales
(1)
|
$
|
1,588
|
|
|
$
|
2,000
|
|
|
$
|
1,294
|
|
Gathering, processing, and marketing expense
(1)
|
1,047
|
|
|
1,552
|
|
|
1,083
|
|
|||
Gathering, processing, and marketing, net
|
$
|
541
|
|
|
$
|
448
|
|
|
$
|
211
|
|
(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.
|
Gains (Losses) on Divestitures and Other, net
|
millions
|
2018
|
|
|
2017
|
|
|
2016
|
|
|||
Gains (losses) on divestitures, net
|
$
|
20
|
|
|
$
|
674
|
|
|
$
|
(757
|
)
|
Other
|
292
|
|
|
265
|
|
|
179
|
|
|||
Total gains (losses) on divestitures and other, net
|
$
|
312
|
|
|
$
|
939
|
|
|
$
|
(578
|
)
|
|
MANAGEMENT’S DISCUSSION AND ANALYSIS
RESULTS OF OPERATIONS
|
millions
|
2018
|
|
|
2017
|
|
|
2016
|
|
|||
Oil and gas operating
|
$
|
1,153
|
|
|
$
|
988
|
|
|
$
|
807
|
|
Oil and gas transportation
|
878
|
|
|
914
|
|
|
1,002
|
|
|||
Exploration
|
459
|
|
|
2,535
|
|
|
944
|
|
|||
Gathering, processing, and marketing
|
1,047
|
|
|
1,552
|
|
|
1,083
|
|
|||
G&A
|
1,084
|
|
|
994
|
|
|
1,223
|
|
|||
DD&A
|
4,254
|
|
|
4,279
|
|
|
4,301
|
|
|||
Production, property, and other taxes
|
826
|
|
|
582
|
|
|
536
|
|
|||
Impairments
|
800
|
|
|
408
|
|
|
227
|
|
|||
Other operating expense
|
262
|
|
|
221
|
|
|
118
|
|
|||
Total
|
$
|
10,763
|
|
|
$
|
12,473
|
|
|
$
|
10,241
|
|
Oil and Gas Operating Expenses
|
|
2018
|
|
|
2017
|
|
|
2016
|
|
|||
Oil and gas operating (millions)
|
$
|
1,153
|
|
|
$
|
988
|
|
|
$
|
807
|
|
Oil and gas operating—per BOE
|
4.74
|
|
|
4.03
|
|
|
2.78
|
|
–
|
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
|
|
MANAGEMENT’S DISCUSSION AND ANALYSIS
RESULTS OF OPERATIONS
|
Oil and Gas Transportation Expenses
|
|
2018
|
|
|
2017
|
|
|
2016
|
|
|||
Oil and gas transportation (millions)
|
$
|
878
|
|
|
$
|
914
|
|
|
$
|
1,002
|
|
Oil and gas transportation—per BOE
|
3.61
|
|
|
3.73
|
|
|
3.46
|
|
Exploration Expense
|
millions
|
2018
|
|
|
2017
|
|
|
2016
|
|
|||
Dry hole expense
|
$
|
87
|
|
|
$
|
1,433
|
|
|
$
|
397
|
|
Impairments of unproved properties
|
159
|
|
|
788
|
|
|
216
|
|
|||
Geological and geophysical, exploration overhead, and other expense
|
213
|
|
|
314
|
|
|
331
|
|
|||
Total exploration expense
|
$
|
459
|
|
|
$
|
2,535
|
|
|
$
|
944
|
|
–
|
$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
|
|
MANAGEMENT’S DISCUSSION AND ANALYSIS
RESULTS OF OPERATIONS
|
G&A
|
millions
|
2018
|
|
|
2017
|
|
|
2016
|
|
|||
G&A
|
$
|
1,084
|
|
|
$
|
994
|
|
|
$
|
1,223
|
|
DD&A
|
millions
|
2018
|
|
|
2017
|
|
|
2016
|
|
|||
DD&A
|
$
|
4,254
|
|
|
$
|
4,279
|
|
|
$
|
4,301
|
|
–
|
$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
|
Production, Property, and Other Taxes
|
millions
|
2018
|
|
|
2017
|
|
|
2016
|
|
|||
U.S. production and severance taxes
|
$
|
164
|
|
|
$
|
90
|
|
|
$
|
80
|
|
Algeria exceptional profits taxes
|
405
|
|
|
289
|
|
|
280
|
|
|||
Ad valorem taxes
|
254
|
|
|
196
|
|
|
163
|
|
|||
Other
|
3
|
|
|
7
|
|
|
13
|
|
|||
Total production, property, and other taxes
|
$
|
826
|
|
|
$
|
582
|
|
|
$
|
536
|
|
|
MANAGEMENT’S DISCUSSION AND ANALYSIS
RESULTS OF OPERATIONS
|
Impairments
|
millions
|
2018
|
|
|
2017
|
|
|
2016
|
|
|||
Exploration and Production
|
|
|
|
|
|
||||||
U.S. onshore properties
|
$
|
347
|
|
|
$
|
2
|
|
|
$
|
28
|
|
Gulf of Mexico properties
|
27
|
|
|
227
|
|
|
27
|
|
|||
Cost-method investment
|
—
|
|
|
—
|
|
|
59
|
|
|||
WES Midstream
|
228
|
|
|
176
|
|
|
16
|
|
|||
Other Midstream
|
53
|
|
|
2
|
|
|
57
|
|
|||
Other
|
145
|
|
|
1
|
|
|
40
|
|
|||
Total impairments
|
$
|
800
|
|
|
$
|
408
|
|
|
$
|
227
|
|
Other (Income) Expense
|
millions
|
2018
|
|
|
2017
|
|
|
2016
|
|
|||
Interest expense
(1)
|
$
|
947
|
|
|
$
|
932
|
|
|
$
|
890
|
|
(Gains) losses on early extinguishment of debt
(2)
|
(2
|
)
|
|
2
|
|
|
155
|
|
|||
(Gains) losses on derivatives, net
(3)
|
130
|
|
|
135
|
|
|
286
|
|
|||
Other (income) expense, net
|
59
|
|
|
54
|
|
|
126
|
|
|||
Total
|
$
|
1,134
|
|
|
$
|
1,123
|
|
|
$
|
1,457
|
|
(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.
|
|
MANAGEMENT’S DISCUSSION AND ANALYSIS
RESULTS OF OPERATIONS
|
Income Tax Expense (Benefit)
|
millions except percentages
|
2018
|
|
|
2017
|
|
|
2016
|
|
|||
Income tax expense (benefit)
|
$
|
733
|
|
|
$
|
(1,477
|
)
|
|
$
|
(1,021
|
)
|
Income (loss) before income taxes
|
$
|
1,485
|
|
|
$
|
(1,688
|
)
|
|
$
|
(3,829
|
)
|
Effective tax rate
|
49
|
%
|
|
88
|
%
|
|
27
|
%
|
|
MANAGEMENT’S DISCUSSION AND ANALYSIS
LIQUIDITY AND CAPITAL RESOURCES
|
LIQUIDITY AND CAPITAL RESOURCES
|
millions
|
2018
|
|
|
2017
|
|
|
2016
|
|
|||
Net cash provided by (used in) operating activities
|
$
|
5,929
|
|
|
$
|
4,009
|
|
|
$
|
3,000
|
|
Net cash provided by (used in) investing activities
|
(5,982
|
)
|
|
(1,030
|
)
|
|
(2,742
|
)
|
|||
Net cash provided by (used in) financing activities
|
(3,177
|
)
|
|
(1,613
|
)
|
|
2,008
|
|
Overview
|
Credit Rating
|
|
MANAGEMENT’S DISCUSSION AND ANALYSIS
LIQUIDITY AND CAPITAL RESOURCES
|
Operating Activities
|
|
MANAGEMENT’S DISCUSSION AND ANALYSIS
LIQUIDITY AND CAPITAL RESOURCES
|
Investing Activities
|
millions
|
2018
|
|
|
2017
|
|
|
2016
|
|
|||
Cash Flows from Investing Activities
|
|
|
|
|
|
||||||
Additions to properties and equipment
(1)
|
$
|
6,183
|
|
|
$
|
5,031
|
|
|
$
|
3,505
|
|
Adjustments for capital expenditures
|
|
|
|
|
|
||||||
Changes in capital accruals
|
(3
|
)
|
|
275
|
|
|
(205
|
)
|
|||
Other
|
5
|
|
|
(6
|
)
|
|
14
|
|
|||
Total capital expenditures
(2)
|
$
|
6,185
|
|
|
$
|
5,300
|
|
|
$
|
3,314
|
|
|
|
|
|
|
|
||||||
Exploration and Production and other capital expenditures
|
$
|
4,264
|
|
|
$
|
3,884
|
|
|
$
|
2,763
|
|
WES Midstream capital expenditures
|
1,178
|
|
|
956
|
|
|
491
|
|
|||
Other Midstream capital expenditures
|
743
|
|
|
460
|
|
|
60
|
|
(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.
|
|
MANAGEMENT’S DISCUSSION AND ANALYSIS
LIQUIDITY AND CAPITAL RESOURCES
|
Financing Activities
|
|
December 31,
|
||||||
millions except percentages
|
2018
|
|
|
2017
|
|
||
Anadarko
|
$
|
11,602
|
|
|
$
|
12,196
|
|
WES
|
4,787
|
|
|
3,465
|
|
||
WGP
|
28
|
|
|
28
|
|
||
Total debt
|
$
|
16,417
|
|
|
$
|
15,689
|
|
Total equity
|
10,943
|
|
|
13,790
|
|
||
Consolidated debt to total capitalization ratio
|
60.0
|
%
|
|
53.2
|
%
|
|
MANAGEMENT’S DISCUSSION AND ANALYSIS
LIQUIDITY AND CAPITAL RESOURCES
|
millions
|
Company
|
2018
|
|
|
2017
|
|
|
2016
|
|
Description
|
|||
Issuances
|
Anadarko
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
800
|
|
4.850% Senior Notes due 2021
(1)
|
|
Anadarko
|
—
|
|
|
—
|
|
|
1,100
|
|
5.550% Senior Notes due 2026
(1)
|
|||
|
Anadarko
|
—
|
|
|
—
|
|
|
1,100
|
|
6.600% Senior Notes due 2046
(1)
|
|||
|
WES
|
400
|
|
|
—
|
|
|
—
|
|
WES 4.500% Senior Notes due 2028
(2)
|
|||
|
WES
|
700
|
|
|
—
|
|
|
—
|
|
WES 5.300% Senior Notes due 2048
(2)
|
|||
|
WES
|
400
|
|
|
—
|
|
|
—
|
|
WES 4.750% Senior Notes due 2028
(3)
|
|||
|
WES
|
350
|
|
|
—
|
|
|
—
|
|
WES 5.500% Senior Notes due 2048
(3)
|
|||
|
WES
|
—
|
|
|
—
|
|
|
500
|
|
WES 4.650% Senior Notes due 2026
(4)
|
|||
|
WES
|
—
|
|
|
—
|
|
|
200
|
|
WES 5.450% Senior Notes due 2044
(2)
|
|||
Borrowings
|
Anadarko
|
—
|
|
|
—
|
|
|
1,750
|
|
364-Day Facility
(5)
|
|||
|
WES
|
540
|
|
|
370
|
|
|
600
|
|
WES RCF
(6)
|
|||
|
WGP
|
—
|
|
|
—
|
|
|
28
|
|
WGP RCF
|
|||
Repayments
|
Anadarko
|
(114
|
)
|
|
—
|
|
|
—
|
|
7.050% Debentures due 2018
|
|||
|
Anadarko
|
(123
|
)
|
|
—
|
|
|
—
|
|
4.850% Senior Notes due 2021
(7)
|
|||
|
Anadarko
|
(377
|
)
|
|
—
|
|
|
—
|
|
3.450% Senior Notes due 2024
(7)
|
|||
|
Anadarko
|
(90
|
)
|
|
—
|
|
|
—
|
|
Zero Coupon Notes due 2036
|
|||
|
Anadarko
|
—
|
|
|
(6
|
)
|
|
—
|
|
7.000% Debentures due 2027
|
|||
|
Anadarko
|
—
|
|
|
(3
|
)
|
|
—
|
|
6.625% Debentures due 2028
|
|||
|
Anadarko
|
—
|
|
|
(1
|
)
|
|
—
|
|
7.950% Debentures due 2029
|
|||
|
Anadarko
|
—
|
|
|
—
|
|
|
(1,750
|
)
|
5.950% Senior Notes due 2016
(8)
|
|||
|
Anadarko
|
—
|
|
|
—
|
|
|
(2,000
|
)
|
6.375% Senior Notes due 2017
(8)
|
|||
|
Anadarko
|
—
|
|
|
—
|
|
|
(1,750
|
)
|
364-Day Facility
|
|||
|
Anadarko
|
—
|
|
|
—
|
|
|
(250
|
)
|
Commercial paper notes, net
|
|||
|
Anadarko
|
(17
|
)
|
|
(34
|
)
|
|
(34
|
)
|
TEUs - senior amortizing notes
|
|||
|
WES
|
(350
|
)
|
|
—
|
|
|
—
|
|
WES 2.600% Senior Notes due 2018
|
|||
|
WES
|
(690
|
)
|
|
—
|
|
|
(900
|
)
|
WES RCF
|
(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.
|
|
MANAGEMENT’S DISCUSSION AND ANALYSIS
LIQUIDITY AND CAPITAL RESOURCES
|
|
MANAGEMENT’S DISCUSSION AND ANALYSIS
LIQUIDITY AND CAPITAL RESOURCES
|
millions
|
2018
|
|
|
2017
|
|
|
2016
|
|
|||
WES distributions to unitholders (excluding Anadarko and WGP)
(1)
|
$
|
379
|
|
|
$
|
326
|
|
|
$
|
258
|
|
WES distributions to Series A Preferred unitholders
(2)
|
—
|
|
|
22
|
|
|
31
|
|
|||
WES distributions to Chipeta noncontrolling interest owners
|
14
|
|
|
14
|
|
|
14
|
|
|||
WGP distributions to unitholders (excluding Anadarko)
(3)
|
102
|
|
|
81
|
|
|
59
|
|
(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
).
|
|
MANAGEMENT’S DISCUSSION AND ANALYSIS
LIQUIDITY AND CAPITAL RESOURCES
|
Insurance Coverage and Other Indemnities
|
|
MANAGEMENT’S DISCUSSION AND ANALYSIS
LIQUIDITY AND CAPITAL RESOURCES
|
Off-Balance-Sheet Arrangements
|
Obligations
|
|
|
|
Obligations by Period
|
||||||||||||||||||
millions
|
Note Reference
(1)
|
2019
|
|
2020-2021
|
|
2022-2023
|
|
Thereafter
|
|
Total
|
|
||||||||||
Total debt
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Principal—total borrowings
(2)
|
|
$
|
928
|
|
|
$
|
1,177
|
|
|
$
|
890
|
|
|
$
|
14,666
|
|
|
$
|
17,661
|
|
|
Interest on borrowings
|
|
834
|
|
|
1,655
|
|
|
1,530
|
|
|
9,515
|
|
|
13,534
|
|
||||||
Capital lease obligation and interest
|
|
58
|
|
|
98
|
|
|
88
|
|
|
323
|
|
|
567
|
|
||||||
Investee entities’ debt and interest
(3)
|
|
108
|
|
|
206
|
|
|
204
|
|
|
2,115
|
|
|
2,633
|
|
||||||
Operating leases
|
|
264
|
|
|
196
|
|
|
59
|
|
|
135
|
|
|
654
|
|
||||||
Oil and gas activities
(4)
|
|
272
|
|
|
332
|
|
|
109
|
|
|
89
|
|
|
802
|
|
||||||
Midstream and marketing activities
|
|
875
|
|
|
1,816
|
|
|
1,323
|
|
|
1,409
|
|
|
5,423
|
|
||||||
AROs
|
|
254
|
|
|
345
|
|
|
699
|
|
|
1,801
|
|
|
3,099
|
|
||||||
Derivative liabilities
(5)
|
|
72
|
|
|
655
|
|
|
448
|
|
|
—
|
|
|
1,175
|
|
||||||
Uncertain tax positions
(6)
|
|
70
|
|
|
74
|
|
|
1,143
|
|
|
—
|
|
|
1,287
|
|
||||||
Environmental liabilities
|
|
22
|
|
|
35
|
|
|
10
|
|
|
42
|
|
|
109
|
|
||||||
Other
|
|
|
20
|
|
|
200
|
|
|
31
|
|
|
57
|
|
|
308
|
|
|||||
Total
(7)
|
|
|
$
|
3,777
|
|
|
$
|
6,789
|
|
|
$
|
6,534
|
|
|
$
|
30,152
|
|
|
$
|
47,252
|
|
(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.
|
|
MANAGEMENT’S DISCUSSION AND ANALYSIS
CRITICAL ACCOUNTING ESTIMATES
|
CRITICAL ACCOUNTING ESTIMATES
|
Proved Reserves
|
|
MANAGEMENT’S DISCUSSION AND ANALYSIS
CRITICAL ACCOUNTING ESTIMATES
|
Exploratory Costs
|
Fair Value
|
|
MANAGEMENT’S DISCUSSION AND ANALYSIS
CRITICAL ACCOUNTING ESTIMATES
|
Impairments of Proved Oil and Natural-Gas Properties
|
Impairments of Unproved Oil and Natural-Gas Properties
|
|
MANAGEMENT’S DISCUSSION AND ANALYSIS
CRITICAL ACCOUNTING ESTIMATES
|
Income Taxes
|
Contingencies
|
RECENT ACCOUNTING DEVELOPMENTS
|
|
MARKET RISK
QUANTITATIVE AND QUALITATIVE DISCLOSURES
|
COMMODITY-PRICE RISK
|
INTEREST-RATE RISK
|
|
FINANCIAL STATEMENTS
INDEX
|
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
|
Page
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FINANCIAL STATEMENTS
REPORTS
|
REPORT OF MANAGEMENT
|
MANAGEMENT’S ASSESSMENT OF INTERNAL CONTROL OVER FINANCIAL REPORTING
|
/s/ R. A. WALKER
|
R. A. Walker
Chairman and Chief Executive Officer
|
/s/ BENJAMIN M. FINK
|
Benjamin M. Fink
Executive Vice President, Finance and Chief Financial Officer
|
|
February 14, 2019
|
|
FINANCIAL STATEMENTS
REPORTS
|
/s/ KPMG LLP
|
|
Houston, Texas
|
February 14, 2019
|
|
FINANCIAL STATEMENTS
REPORTS
|
/s/ KPMG LLP
|
|
We have served as the Company’s auditor since 1981.
|
|
Houston, Texas
|
February 14, 2019
|
|
FINANCIAL STATEMENTS
|
|
Years Ended December 31,
|
||||||||||
millions except per-share amounts
|
2018
|
|
|
2017
|
|
|
2016
|
|
|||
Revenues and Other
|
|
|
|
|
|
||||||
Oil sales
|
$
|
9,206
|
|
|
$
|
6,552
|
|
|
$
|
4,668
|
|
Natural-gas sales
|
1,005
|
|
|
1,348
|
|
|
1,564
|
|
|||
Natural-gas liquids sales
|
1,271
|
|
|
1,069
|
|
|
921
|
|
|||
Gathering, processing, and marketing sales
|
1,588
|
|
|
2,000
|
|
|
1,294
|
|
|||
Gains (losses) on divestitures and other, net
|
312
|
|
|
939
|
|
|
(578
|
)
|
|||
Total
|
13,382
|
|
|
11,908
|
|
|
7,869
|
|
|||
Costs and Expenses
|
|
|
|
|
|
||||||
Oil and gas operating
|
1,153
|
|
|
988
|
|
|
807
|
|
|||
Oil and gas transportation
|
878
|
|
|
914
|
|
|
1,002
|
|
|||
Exploration
|
459
|
|
|
2,535
|
|
|
944
|
|
|||
Gathering, processing, and marketing
|
1,047
|
|
|
1,552
|
|
|
1,083
|
|
|||
General and administrative
|
1,084
|
|
|
994
|
|
|
1,223
|
|
|||
Depreciation, depletion, and amortization
|
4,254
|
|
|
4,279
|
|
|
4,301
|
|
|||
Production, property, and other taxes
|
826
|
|
|
582
|
|
|
536
|
|
|||
Impairments
|
800
|
|
|
408
|
|
|
227
|
|
|||
Other operating expense
|
262
|
|
|
221
|
|
|
118
|
|
|||
Total
|
10,763
|
|
|
12,473
|
|
|
10,241
|
|
|||
Operating Income (Loss)
|
2,619
|
|
|
(565
|
)
|
|
(2,372
|
)
|
|||
Other (Income) Expense
|
|
|
|
|
|
||||||
Interest expense
|
947
|
|
|
932
|
|
|
890
|
|
|||
(Gains) losses on early extinguishment of debt
|
(2
|
)
|
|
2
|
|
|
155
|
|
|||
(Gains) losses on derivatives, net
|
130
|
|
|
135
|
|
|
286
|
|
|||
Other (income) expense, net
|
59
|
|
|
54
|
|
|
126
|
|
|||
Total
|
1,134
|
|
|
1,123
|
|
|
1,457
|
|
|||
Income (Loss) Before Income Taxes
|
1,485
|
|
|
(1,688
|
)
|
|
(3,829
|
)
|
|||
Income tax expense (benefit)
|
733
|
|
|
(1,477
|
)
|
|
(1,021
|
)
|
|||
Net Income (Loss)
|
752
|
|
|
(211
|
)
|
|
(2,808
|
)
|
|||
Net income (loss) attributable to noncontrolling interests
|
137
|
|
|
245
|
|
|
263
|
|
|||
Net Income (Loss) Attributable to Common Stockholders
|
$
|
615
|
|
|
$
|
(456
|
)
|
|
$
|
(3,071
|
)
|
|
|
|
|
|
|
||||||
Per Common Share
|
|
|
|
|
|
||||||
Net income (loss) attributable to common stockholders—basic
|
$
|
1.20
|
|
|
$
|
(0.85
|
)
|
|
$
|
(5.90
|
)
|
Net income (loss) attributable to common stockholders—diluted
|
$
|
1.20
|
|
|
$
|
(0.85
|
)
|
|
$
|
(5.90
|
)
|
Average Number of Common Shares Outstanding—Basic
|
504
|
|
|
548
|
|
|
522
|
|
|||
Average Number of Common Shares Outstanding—Diluted
|
504
|
|
|
548
|
|
|
522
|
|
|
FINANCIAL STATEMENTS
|
|
Years Ended December 31,
|
||||||||||
millions
|
2018
|
|
|
2017
|
|
|
2016
|
|
|||
Net Income (Loss)
|
$
|
752
|
|
|
$
|
(211
|
)
|
|
$
|
(2,808
|
)
|
Other Comprehensive Income (Loss)
|
|
|
|
|
|
||||||
Adjustments for derivative instruments
|
|
|
|
|
|
||||||
Cumulative effect of accounting change
(1)
|
(7
|
)
|
|
—
|
|
|
—
|
|
|||
Reclassification of previously deferred derivative losses to (gains) losses on derivatives, net
|
3
|
|
|
3
|
|
|
8
|
|
|||
Income taxes on reclassification of previously deferred derivative losses to (gains) losses on derivatives, net
|
(1
|
)
|
|
(1
|
)
|
|
(3
|
)
|
|||
Total adjustments for derivative instruments, net of taxes
|
(5
|
)
|
|
2
|
|
|
5
|
|
|||
Adjustments for pension and other postretirement plans
|
|
|
|
|
|
||||||
Cumulative effect of accounting change
(1)
|
(66
|
)
|
|
—
|
|
|
—
|
|
|||
Net gain (loss) incurred during period
|
50
|
|
|
(14
|
)
|
|
(175
|
)
|
|||
Income taxes on net gain (loss) incurred during period
|
(11
|
)
|
|
4
|
|
|
68
|
|
|||
Amortization of net actuarial (gain) loss to other (income) expense, net
|
74
|
|
|
116
|
|
|
188
|
|
|||
Income taxes on amortization of net actuarial (gain) loss
|
(20
|
)
|
|
(40
|
)
|
|
(73
|
)
|
|||
Amortization of net prior service (credit) cost to other (income) expense, net
|
(24
|
)
|
|
(25
|
)
|
|
(34
|
)
|
|||
Income taxes on amortization of net prior service (credit) cost
|
5
|
|
|
10
|
|
|
13
|
|
|||
Total adjustments for pension and other postretirement plans, net of taxes
|
8
|
|
|
51
|
|
|
(13
|
)
|
|||
Total
|
3
|
|
|
53
|
|
|
(8
|
)
|
|||
Comprehensive Income (Loss)
|
755
|
|
|
(158
|
)
|
|
(2,816
|
)
|
|||
Comprehensive income (loss) attributable to noncontrolling interests
|
137
|
|
|
245
|
|
|
263
|
|
|||
Comprehensive Income (Loss) Attributable to Common Stockholders
|
$
|
618
|
|
|
$
|
(403
|
)
|
|
$
|
(3,079
|
)
|
(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.
|
|
FINANCIAL STATEMENTS
|
|
December 31,
|
||||||
millions except per-share amounts
|
2018
|
|
|
2017
|
|
||
ASSETS
|
|
|
|
||||
Current Assets
|
|
|
|
||||
Cash and cash equivalents ($92 and $80 related to VIEs)
|
$
|
1,295
|
|
|
$
|
4,553
|
|
Accounts receivable (net of allowance of $13 and $14)
|
|
|
|
||||
Customers ($138 and $106 related to VIEs)
|
1,491
|
|
|
1,222
|
|
||
Others ($15 and $19 related to VIEs)
|
535
|
|
|
607
|
|
||
Other current assets
|
474
|
|
|
380
|
|
||
Total
|
3,795
|
|
|
6,762
|
|
||
Net properties and equipment
(net of accumulated depreciation, depletion, and amortization of $37,905 and $34,107) ($6,612 and $5,731 related to VIEs)
|
28,615
|
|
|
27,451
|
|
||
Other Assets
($868 and $579 related to VIEs)
|
2,336
|
|
|
2,211
|
|
||
Goodwill and Other Intangible Assets
($1,163 and $1,191 related to VIEs)
|
5,630
|
|
|
5,662
|
|
||
Total Assets
|
$
|
40,376
|
|
|
$
|
42,086
|
|
|
|
|
|
||||
LIABILITIES AND EQUITY
|
|
|
|
||||
Current Liabilities
|
|
|
|
||||
Accounts payable
|
|
|
|
||||
Trade ($263 and $305 related to VIEs)
|
$
|
2,003
|
|
|
$
|
1,894
|
|
Other ($15 and $1 related to VIEs)
|
161
|
|
|
266
|
|
||
Short-term debt - Anadarko
(1)
|
919
|
|
|
142
|
|
||
Short-term debt - WES and WGP
|
28
|
|
|
—
|
|
||
Current asset retirement obligations
|
252
|
|
|
294
|
|
||
Other current liabilities
|
1,295
|
|
|
1,310
|
|
||
Total
|
4,658
|
|
|
3,906
|
|
||
Long-term Debt
|
|
|
|
||||
Long-term debt - Anadarko
(1)
|
10,683
|
|
|
12,054
|
|
||
Long-term debt - WES and WGP
|
4,787
|
|
|
3,493
|
|
||
Total
|
15,470
|
|
|
15,547
|
|
||
Other Long-term Liabilities
|
|
|
|
||||
Deferred income taxes
|
2,437
|
|
|
2,234
|
|
||
Asset retirement obligations ($260 and $143 related to VIEs)
|
2,847
|
|
|
2,500
|
|
||
Other
|
4,021
|
|
|
4,109
|
|
||
Total
|
9,305
|
|
|
8,843
|
|
||
|
|
|
|
||||
Equity
|
|
|
|
||||
Stockholders’ equity
|
|
|
|
||||
Common stock, par value $0.10 per share (1.0 billion shares authorized, 576.6 million and 574.2 million shares issued)
|
57
|
|
|
57
|
|
||
Paid-in capital
|
12,393
|
|
|
12,000
|
|
||
Retained earnings
|
1,245
|
|
|
1,109
|
|
||
Treasury stock (87.2 million and 43.4 million shares)
|
(4,864
|
)
|
|
(2,132
|
)
|
||
Accumulated other comprehensive income (loss)
|
(335
|
)
|
|
(338
|
)
|
||
Total Stockholders’ Equity
|
8,496
|
|
|
10,696
|
|
||
Noncontrolling interests
|
2,447
|
|
|
3,094
|
|
||
Total Equity
|
10,943
|
|
|
13,790
|
|
||
Total Liabilities and Equity
|
$
|
40,376
|
|
|
$
|
42,086
|
|
(1)
|
Excludes WES and WGP.
|
|
FINANCIAL STATEMENTS
|
|
Total Stockholders’ Equity
|
|
|
|
|||||||||||||||||||
millions
|
Common
Stock
|
|
Paid-in
Capital
|
|
Retained
Earnings
|
|
Treasury
Stock
|
|
Accumulated Other
Comprehensive
Income (Loss)
|
|
Non-
controlling
Interests
|
|
Total
Equity
|
|
|||||||||
Balance at December 31, 2015
|
$
|
52
|
|
$
|
9,265
|
|
$
|
4,880
|
|
$
|
(995
|
)
|
|
$
|
(383
|
)
|
|
$
|
2,638
|
|
$
|
15,457
|
|
Net income (loss)
|
—
|
|
—
|
|
(3,071
|
)
|
—
|
|
|
—
|
|
|
263
|
|
(2,808
|
)
|
|||||||
Common stock issued
|
5
|
|
2,150
|
|
—
|
|
—
|
|
|
—
|
|
|
—
|
|
2,155
|
|
|||||||
Share-based compensation expense
|
—
|
|
197
|
|
—
|
|
—
|
|
|
—
|
|
|
—
|
|
197
|
|
|||||||
Dividends—common stock
|
—
|
|
—
|
|
(105
|
)
|
—
|
|
|
—
|
|
|
—
|
|
(105
|
)
|
|||||||
Repurchases of common stock
|
—
|
|
—
|
|
—
|
|
(38
|
)
|
|
—
|
|
|
—
|
|
(38
|
)
|
|||||||
Subsidiary equity transactions
|
—
|
|
263
|
|
—
|
|
—
|
|
|
—
|
|
|
746
|
|
1,009
|
|
|||||||
Distributions to noncontrolling interest owners
|
—
|
|
—
|
|
—
|
|
—
|
|
|
—
|
|
|
(362
|
)
|
(362
|
)
|
|||||||
Reclassification of previously deferred derivative losses to (gains) losses on derivatives, net
|
—
|
|
—
|
|
—
|
|
—
|
|
|
5
|
|
|
—
|
|
5
|
|
|||||||
Adjustments for pension and other postretirement plans
|
—
|
|
—
|
|
—
|
|
—
|
|
|
(13
|
)
|
|
—
|
|
(13
|
)
|
|||||||
Balance at December 31, 2016
|
57
|
|
11,875
|
|
1,704
|
|
(1,033
|
)
|
|
(391
|
)
|
|
3,285
|
|
15,497
|
|
|||||||
Net income (loss)
|
—
|
|
—
|
|
(456
|
)
|
—
|
|
|
—
|
|
|
245
|
|
(211
|
)
|
|||||||
Share-based compensation expense
|
—
|
|
163
|
|
—
|
|
—
|
|
|
—
|
|
|
—
|
|
163
|
|
|||||||
Dividends—common stock
|
—
|
|
—
|
|
(111
|
)
|
—
|
|
|
—
|
|
|
—
|
|
(111
|
)
|
|||||||
Repurchases of common stock
|
—
|
|
—
|
|
—
|
|
(1,099
|
)
|
|
—
|
|
|
—
|
|
(1,099
|
)
|
|||||||
Subsidiary equity transactions
|
—
|
|
(35
|
)
|
—
|
|
—
|
|
|
—
|
|
|
9
|
|
(26
|
)
|
|||||||
Distributions to noncontrolling interest owners
|
—
|
|
—
|
|
—
|
|
—
|
|
|
—
|
|
|
(445
|
)
|
(445
|
)
|
|||||||
Reclassification of previously deferred derivative losses to (gains) losses on derivatives, net
|
—
|
|
—
|
|
—
|
|
—
|
|
|
2
|
|
|
—
|
|
2
|
|
|||||||
Adjustments for pension and other postretirement plans
|
—
|
|
—
|
|
—
|
|
—
|
|
|
51
|
|
|
—
|
|
51
|
|
|||||||
Cumulative effect of accounting change
|
—
|
|
(3
|
)
|
(28
|
)
|
—
|
|
|
—
|
|
|
—
|
|
(31
|
)
|
|||||||
Balance at December 31, 2017
|
57
|
|
12,000
|
|
1,109
|
|
(2,132
|
)
|
|
(338
|
)
|
|
3,094
|
|
13,790
|
|
|||||||
Net income (loss)
|
—
|
|
—
|
|
615
|
|
—
|
|
|
—
|
|
|
137
|
|
752
|
|
|||||||
Common stock issued
|
—
|
|
7
|
|
—
|
|
—
|
|
|
—
|
|
|
—
|
|
7
|
|
|||||||
Share-based compensation expense
|
—
|
|
169
|
|
—
|
|
—
|
|
|
—
|
|
|
—
|
|
169
|
|
|||||||
Dividends—common stock
|
—
|
|
—
|
|
(528
|
)
|
—
|
|
|
—
|
|
|
—
|
|
(528
|
)
|
|||||||
Repurchases of common stock
|
—
|
|
—
|
|
—
|
|
(2,732
|
)
|
|
—
|
|
|
—
|
|
(2,732
|
)
|
|||||||
Subsidiary equity transactions
|
—
|
|
(15
|
)
|
—
|
|
—
|
|
|
—
|
|
|
34
|
|
19
|
|
|||||||
Settlement of tangible equity units
|
—
|
|
232
|
|
—
|
|
—
|
|
|
—
|
|
|
(300
|
)
|
(68
|
)
|
|||||||
Distributions to noncontrolling interest owners
|
—
|
|
—
|
|
—
|
|
—
|
|
|
—
|
|
|
(495
|
)
|
(495
|
)
|
|||||||
Reclassification of previously deferred derivative losses to (gains) losses on derivatives, net
|
—
|
|
—
|
|
—
|
|
—
|
|
|
2
|
|
|
—
|
|
2
|
|
|||||||
Adjustments for pension and other postretirement plans
|
—
|
|
—
|
|
—
|
|
—
|
|
|
74
|
|
|
—
|
|
74
|
|
|||||||
Cumulative effect of accounting change
(1)
|
—
|
|
—
|
|
49
|
|
—
|
|
|
(73
|
)
|
|
(23
|
)
|
(47
|
)
|
|||||||
Balance at December 31, 2018
|
$
|
57
|
|
$
|
12,393
|
|
$
|
1,245
|
|
$
|
(4,864
|
)
|
|
$
|
(335
|
)
|
|
$
|
2,447
|
|
$
|
10,943
|
|
(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.
|
|
FINANCIAL STATEMENTS
|
|
Years Ended December 31,
|
||||||||||
millions
|
2018
|
|
|
2017
|
|
|
2016
|
|
|||
Cash Flows from Operating Activities
|
|
|
|
|
|
||||||
Net income (loss)
|
$
|
752
|
|
|
$
|
(211
|
)
|
|
$
|
(2,808
|
)
|
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities
|
|
|
|
|
|
||||||
Depreciation, depletion, and amortization
|
4,254
|
|
|
4,279
|
|
|
4,301
|
|
|||
Deferred income taxes
|
139
|
|
|
(2,169
|
)
|
|
(1,238
|
)
|
|||
Dry hole expense and impairments of unproved properties
|
246
|
|
|
2,221
|
|
|
613
|
|
|||
Impairments
|
800
|
|
|
408
|
|
|
227
|
|
|||
(Gains) losses on divestitures, net
|
(20
|
)
|
|
(674
|
)
|
|
757
|
|
|||
(Gains) losses on early extinguishment of debt
|
(2
|
)
|
|
2
|
|
|
155
|
|
|||
Total (gains) losses on derivatives, net
|
138
|
|
|
131
|
|
|
292
|
|
|||
Operating portion of net cash received (paid) in settlement of derivative instruments
|
(545
|
)
|
|
25
|
|
|
267
|
|
|||
Other
|
294
|
|
|
303
|
|
|
342
|
|
|||
Changes in assets and liabilities
|
|
|
|
|
|
||||||
(Increase) decrease in accounts receivable
|
(211
|
)
|
|
(147
|
)
|
|
677
|
|
|||
Increase (decrease) in accounts payable and other current liabilities
|
348
|
|
|
(32
|
)
|
|
(443
|
)
|
|||
Other items, net
|
(264
|
)
|
|
(127
|
)
|
|
(142
|
)
|
|||
Net cash provided by (used in) operating activities
|
5,929
|
|
|
4,009
|
|
|
3,000
|
|
|||
Cash Flows from Investing Activities
|
|
|
|
|
|
||||||
Additions to properties and equipment
|
(6,183
|
)
|
|
(5,031
|
)
|
|
(3,505
|
)
|
|||
Acquisition of businesses
|
—
|
|
|
25
|
|
|
(1,740
|
)
|
|||
Divestitures of properties and equipment and other assets
|
417
|
|
|
4,008
|
|
|
2,356
|
|
|||
Other, net
|
(216
|
)
|
|
(32
|
)
|
|
147
|
|
|||
Net cash provided by (used in) investing activities
|
(5,982
|
)
|
|
(1,030
|
)
|
|
(2,742
|
)
|
|||
Cash Flows from Financing Activities
|
|
|
|
|
|
||||||
Borrowings, net of issuance costs
|
2,343
|
|
|
369
|
|
|
6,042
|
|
|||
Repayments of debt
|
(1,689
|
)
|
|
(58
|
)
|
|
(6,832
|
)
|
|||
Financing portion of net cash received (paid) for derivative instruments
|
12
|
|
|
(165
|
)
|
|
(333
|
)
|
|||
Increase (decrease) in outstanding checks
|
(39
|
)
|
|
(43
|
)
|
|
(103
|
)
|
|||
Dividends paid
|
(528
|
)
|
|
(111
|
)
|
|
(105
|
)
|
|||
Repurchases of common stock
|
(2,732
|
)
|
|
(1,092
|
)
|
|
(38
|
)
|
|||
Issuances of common stock
|
7
|
|
|
—
|
|
|
2,188
|
|
|||
Sales of subsidiary units
|
—
|
|
|
—
|
|
|
1,163
|
|
|||
Distributions to noncontrolling interest owners
|
(495
|
)
|
|
(445
|
)
|
|
(362
|
)
|
|||
Proceeds from conveyance of future hard-minerals royalty revenues, net of transaction costs
|
—
|
|
|
—
|
|
|
413
|
|
|||
Payments of future hard-minerals royalty revenues conveyed
|
(50
|
)
|
|
(50
|
)
|
|
(25
|
)
|
|||
Other financing activities
|
(6
|
)
|
|
(18
|
)
|
|
—
|
|
|||
Net cash provided by (used in) financing activities
|
(3,177
|
)
|
|
(1,613
|
)
|
|
2,008
|
|
|||
Effect of exchange rate changes on cash, cash equivalents, restricted cash, and restricted cash equivalents
|
(15
|
)
|
|
—
|
|
|
17
|
|
|||
Net Increase (Decrease) in Cash, Cash Equivalents, Restricted Cash, and Restricted Cash Equivalents
|
(3,245
|
)
|
|
1,366
|
|
|
2,283
|
|
|||
Cash, Cash Equivalents, Restricted Cash, and Restricted Cash Equivalents at Beginning of Period
|
4,674
|
|
|
3,308
|
|
|
1,025
|
|
|||
Cash, Cash Equivalents, Restricted Cash, and Restricted Cash Equivalents at End of Period
|
$
|
1,429
|
|
|
$
|
4,674
|
|
|
$
|
3,308
|
|
|
FINANCIAL STATEMENTS
FOOTNOTES
|
1. Summary of Significant Accounting Policies
|
|
FINANCIAL STATEMENTS
FOOTNOTES
|
1. Summary of Significant Accounting Policies (Continued)
|
|
FINANCIAL STATEMENTS
FOOTNOTES
|
1. Summary of Significant Accounting Policies (Continued)
|
|
FINANCIAL STATEMENTS
FOOTNOTES
|
1. Summary of Significant Accounting Policies (Continued)
|
|
FINANCIAL STATEMENTS
FOOTNOTES
|
1. Summary of Significant Accounting Policies (Continued)
|
|
FINANCIAL STATEMENTS
FOOTNOTES
|
1. Summary of Significant Accounting Policies (Continued)
|
|
FINANCIAL STATEMENTS
FOOTNOTES
|
1. Summary of Significant Accounting Policies (Continued)
|
|
FINANCIAL STATEMENTS
FOOTNOTES
|
1. Summary of Significant Accounting Policies (Continued)
|
|
FINANCIAL STATEMENTS
FOOTNOTES
|
1. Summary of Significant Accounting Policies (Continued)
|
|
FINANCIAL STATEMENTS
FOOTNOTES
|
2. Revenue from Contracts with Customers
|
CONSOLIDATED BALANCE SHEET
|
Impact of Change in Accounting Policy
|
||||||||||
millions
|
As Reported
|
|
Without Adoption of Topic 606
|
|
Effect of Change
Increase/(Decrease)
|
|
|||||
December 31, 2018
|
|
|
|
|
|
||||||
Assets
|
|
|
|
|
|
||||||
Other current assets
|
$
|
474
|
|
|
$
|
472
|
|
|
$
|
2
|
|
Net properties and equipment
|
28,615
|
|
|
28,548
|
|
|
67
|
|
|||
Other assets
|
2,336
|
|
|
2,326
|
|
|
10
|
|
|||
Liabilities
|
|
|
|
|
|
||||||
Other current liabilities
|
1,295
|
|
|
1,290
|
|
|
5
|
|
|||
Deferred income taxes
|
2,437
|
|
|
2,441
|
|
|
(4
|
)
|
|||
Other
|
4,021
|
|
|
3,914
|
|
|
107
|
|
|||
Equity
|
|
|
|
|
|
||||||
Total equity
|
10,943
|
|
|
10,972
|
|
|
(29
|
)
|
|
FINANCIAL STATEMENTS
FOOTNOTES
|
2. Revenue from Contracts with Customers (Continued)
|
CONSOLIDATED STATEMENT OF INCOME
|
Impact of Change in Accounting Policy
|
||||||||||
millions
|
As Reported
|
|
Without Adoption of Topic 606
|
|
Effect of Change
Increase/(Decrease)
|
|
|||||
Year Ended December 31, 2018
|
|
|
|
|
|
||||||
Revenues
|
|
|
|
|
|
||||||
Gathering, processing, and marketing sales
|
$
|
1,588
|
|
|
$
|
2,592
|
|
|
$
|
(1,004
|
)
|
Gains (losses) on divestitures and other, net
|
312
|
|
|
316
|
|
|
(4
|
)
|
|||
Expenses
|
|
|
|
|
|
||||||
Gathering, processing, and marketing
|
1,047
|
|
|
2,075
|
|
|
(1,028
|
)
|
|||
Income tax expense (benefit)
|
733
|
|
|
731
|
|
|
2
|
|
|||
Net income (loss) attributable to noncontrolling interests
|
137
|
|
|
127
|
|
|
10
|
|
|||
Net Income (Loss) Attributable to Common Stockholders
|
$
|
615
|
|
|
$
|
607
|
|
|
$
|
8
|
|
millions
|
Exploration
& Production |
|
WES Midstream
|
|
Other Midstream
|
|
Other and
Intersegment Eliminations |
|
|
Total
|
|
|||||||||
Year Ended December 31, 2018
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Oil sales
|
|
$
|
9,206
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
9,206
|
|
Natural-gas sales
|
|
1,005
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,005
|
|
|||||
Natural-gas liquids sales
|
|
1,271
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,271
|
|
|||||
Gathering, processing, and marketing sales
(1)
|
|
—
|
|
|
1,997
|
|
|
416
|
|
|
21
|
|
|
2,434
|
|
|||||
Other, net
|
|
30
|
|
|
—
|
|
|
1
|
|
|
97
|
|
|
128
|
|
|||||
Total Revenue from Customers
|
|
$
|
11,512
|
|
|
$
|
1,997
|
|
|
$
|
417
|
|
|
$
|
118
|
|
|
$
|
14,044
|
|
Gathering, processing, and marketing sales
(2)
|
|
—
|
|
|
(8
|
)
|
|
8
|
|
|
(846
|
)
|
|
(846
|
)
|
|||||
Gains (losses) on divestitures, net
|
|
20
|
|
|
1
|
|
|
10
|
|
|
(11
|
)
|
|
20
|
|
|||||
Other, net
|
|
(34
|
)
|
|
173
|
|
|
40
|
|
|
(15
|
)
|
|
164
|
|
|||||
Total Revenue from Other than Customers
|
|
$
|
(14
|
)
|
|
$
|
166
|
|
|
$
|
58
|
|
|
$
|
(872
|
)
|
|
$
|
(662
|
)
|
Total Revenue and Other
|
|
$
|
11,498
|
|
|
$
|
2,163
|
|
|
$
|
475
|
|
|
$
|
(754
|
)
|
|
$
|
13,382
|
|
(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.
|
|
FINANCIAL STATEMENTS
FOOTNOTES
|
2. Revenue from Contracts with Customers (Continued)
|
millions
|
|
||
Balance at December 31, 2017
|
$
|
37
|
|
Increase due to cumulative effect of adopting Topic 606
|
98
|
|
|
Increase due to cash received, excluding revenues recognized in the period
|
66
|
|
|
Increase due to assets received from customer
|
13
|
|
|
Decrease due to revenue recognized
|
(42
|
)
|
|
Decrease due to change in estimated consideration
|
(22
|
)
|
|
Balance at December 31, 2018
|
$
|
150
|
|
|
|
||
Contract liabilities at December 31, 2018
|
|
||
Other current liabilities
|
$
|
31
|
|
Other long-term liabilities - other
|
119
|
|
|
Total contract liabilities from contracts with customers
|
$
|
150
|
|
millions
|
Exploration
& Production |
|
WES Midstream
|
|
Other Midstream
|
|
Other and
Intersegment Eliminations |
|
Total
|
|
||||||||||
2019
|
|
$
|
104
|
|
|
$
|
470
|
|
|
$
|
204
|
|
|
$
|
(432
|
)
|
|
$
|
346
|
|
2020
|
|
103
|
|
|
554
|
|
|
293
|
|
|
(614
|
)
|
|
336
|
|
|||||
2021
|
|
103
|
|
|
534
|
|
|
361
|
|
|
(681
|
)
|
|
317
|
|
|||||
2022
|
|
7
|
|
|
530
|
|
|
417
|
|
|
(740
|
)
|
|
214
|
|
|||||
2023
|
|
7
|
|
|
489
|
|
|
424
|
|
|
(750
|
)
|
|
170
|
|
|||||
Thereafter
|
|
58
|
|
|
1,802
|
|
|
2,763
|
|
|
(4,077
|
)
|
|
546
|
|
|||||
Total
|
|
$
|
382
|
|
|
$
|
4,379
|
|
|
$
|
4,462
|
|
|
$
|
(7,294
|
)
|
|
$
|
1,929
|
|
|
FINANCIAL STATEMENTS
FOOTNOTES
|
3. Commodity Inventories
|
millions
|
2018
|
|
|
2017
|
|
||
Oil
|
$
|
139
|
|
|
$
|
165
|
|
Natural gas
|
18
|
|
|
29
|
|
||
NGLs
|
78
|
|
|
122
|
|
||
Total commodity inventories
|
$
|
235
|
|
|
$
|
316
|
|
4. Divestitures and Assets Held for Sale
|
millions
|
2018
|
|
|
2017
|
|
|
2016
|
|
|||
Proceeds received, net of closing adjustments
|
$
|
417
|
|
|
$
|
4,008
|
|
|
$
|
2,356
|
|
Gains (losses) on divestitures, net
(1) (2)
|
20
|
|
|
674
|
|
|
(757
|
)
|
(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
|
|
FINANCIAL STATEMENTS
FOOTNOTES
|
4. Divestitures and Assets Held for Sale (Continued)
|
–
|
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
|
5. Properties and Equipment
|
millions
|
2018
|
|
|
2017
|
|
||
Exploration and Production
(1)
|
$
|
51,941
|
|
|
$
|
49,388
|
|
WES Midstream
|
9,250
|
|
|
7,865
|
|
||
Other Midstream
|
2,908
|
|
|
2,012
|
|
||
Other
|
2,421
|
|
|
2,293
|
|
||
Gross properties and equipment
|
$
|
66,520
|
|
|
$
|
61,558
|
|
Less accumulated DD&A
|
37,905
|
|
|
34,107
|
|
||
Net properties and equipment
|
$
|
28,615
|
|
|
$
|
27,451
|
|
(1)
|
Includes costs associated with unproved properties of
$1.7 billion
at
December 31, 2018
, and
$2.4 billion
at
December 31, 2017
.
|
|
FINANCIAL STATEMENTS
FOOTNOTES
|
6. Impairments
|
|
2018
|
|
2017
|
|
2016
|
|||||||||||||||||||||
millions
|
Impairment
|
|
Fair Value
(1)
|
|
|
Impairment
|
|
Fair Value
(1)
|
|
|
Impairment
|
|
Fair Value
(1)
|
|
||||||||||||
Exploration and Production
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
U.S. onshore properties
|
|
$
|
347
|
|
|
$
|
100
|
|
|
|
$
|
2
|
|
|
$
|
3
|
|
|
|
$
|
28
|
|
|
$
|
617
|
|
Gulf of Mexico properties
|
|
27
|
|
|
—
|
|
|
|
227
|
|
|
216
|
|
|
|
27
|
|
|
61
|
|
||||||
Cost-method investment
|
|
—
|
|
|
—
|
|
|
|
—
|
|
|
—
|
|
|
|
59
|
|
|
—
|
|
||||||
WES Midstream
|
|
228
|
|
|
30
|
|
|
|
176
|
|
|
58
|
|
|
|
16
|
|
|
3
|
|
||||||
Other Midstream
|
|
53
|
|
|
72
|
|
|
|
2
|
|
|
—
|
|
|
|
57
|
|
|
29
|
|
||||||
Other
|
|
145
|
|
|
15
|
|
|
|
1
|
|
|
—
|
|
|
|
40
|
|
|
—
|
|
||||||
Total impairments
|
|
$
|
800
|
|
|
$
|
217
|
|
|
|
$
|
408
|
|
|
$
|
277
|
|
|
|
$
|
227
|
|
|
$
|
710
|
|
(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.
|
|
FINANCIAL STATEMENTS
FOOTNOTES
|
6. Impairments (Continued)
|
|
FINANCIAL STATEMENTS
FOOTNOTES
|
7. Suspended Exploratory Well Costs
|
millions
|
2018
|
|
|
2017
|
|
|
2016
|
|
|||
Balance at January 1
|
$
|
525
|
|
|
$
|
1,230
|
|
|
$
|
1,124
|
|
Additions pending the determination of proved reserves
(1)
|
90
|
|
|
349
|
|
|
490
|
|
|||
Divestitures and other
|
(38
|
)
|
|
(36
|
)
|
|
(11
|
)
|
|||
Reclassifications to proved properties
|
(132
|
)
|
|
(41
|
)
|
|
(50
|
)
|
|||
Charges to exploration expense
|
(1
|
)
|
|
(977
|
)
|
|
(323
|
)
|
|||
Balance at December 31
|
$
|
444
|
|
|
$
|
525
|
|
|
$
|
1,230
|
|
(1)
|
Excludes amounts capitalized and subsequently charged to expense within the same year.
|
–
|
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.
|
–
|
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.
|
–
|
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.
|
|
FINANCIAL STATEMENTS
FOOTNOTES
|
7. Suspended Exploratory Well Costs (Continued)
|
–
|
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.
|
millions
|
2018
|
|
|
2017
|
|
|
2016
|
|
|||
Exploratory well costs capitalized for a period of one year or less
|
$
|
152
|
|
|
$
|
201
|
|
|
$
|
460
|
|
Exploratory well costs capitalized for a period greater than one year
|
292
|
|
|
324
|
|
|
770
|
|
|||
Balance at December 31
|
$
|
444
|
|
|
$
|
525
|
|
|
$
|
1,230
|
|
|
FINANCIAL STATEMENTS
FOOTNOTES
|
7. Suspended Exploratory Well Costs (Continued)
|
millions except projects
|
Number of Projects
|
|
Total
|
|
|
2017
|
|
|
2016
|
|
|
2015 and
prior |
|
||||
U.S. onshore
|
1
|
|
$
|
2
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
2
|
|
U.S. offshore
|
1
|
|
73
|
|
|
(1
|
)
|
|
74
|
|
|
—
|
|
||||
International
|
3
|
|
217
|
|
|
11
|
|
|
14
|
|
|
192
|
|
||||
|
5
|
|
$
|
292
|
|
|
$
|
10
|
|
|
$
|
88
|
|
|
$
|
194
|
|
|
FINANCIAL STATEMENTS
FOOTNOTES
|
8. Goodwill and Other Intangible Assets
|
millions
|
2018
|
|
|
2017
|
|
||
Gross carrying amount
|
$
|
980
|
|
|
$
|
1,013
|
|
Accumulated amortization
|
(139
|
)
|
|
(140
|
)
|
||
Net carrying amount
|
$
|
841
|
|
|
$
|
873
|
|
Amortization expense
|
$
|
32
|
|
|
$
|
31
|
|
9. Equity-Method Investments
|
|
FINANCIAL STATEMENTS
FOOTNOTES
|
10. Current Liabilities
|
millions
|
2018
|
|
|
2017
|
|
||
Accrued income taxes
|
$
|
167
|
|
|
$
|
71
|
|
Interest payable
|
267
|
|
|
246
|
|
||
Production, property, and other taxes payable
|
309
|
|
|
216
|
|
||
Accrued employee benefits
|
319
|
|
|
210
|
|
||
Derivatives
|
89
|
|
|
384
|
|
||
Other
|
144
|
|
|
183
|
|
||
Total other current liabilities
|
$
|
1,295
|
|
|
$
|
1,310
|
|
11. Derivative Instruments
|
|
FINANCIAL STATEMENTS
FOOTNOTES
|
11. Derivative Instruments (Continued)
|
|
2019 Settlement
|
|
||
Oil
|
|
|
||
Three-Way Collars (MBbls/d)
|
|
87
|
|
|
Average price per barrel
|
|
|
||
Ceiling sold price (call)
|
|
$
|
72.98
|
|
Floor purchased price (put)
|
|
$
|
56.72
|
|
Floor sold price (put)
|
|
$
|
46.72
|
|
millions except percentages
|
|
Mandatory
|
Weighted-Average
|
|
|||
Notional Principal Amount
|
Reference Period
|
Termination Date
|
Interest Rate
|
|
|||
$
|
550
|
|
|
September 2016 - 2046
|
September 2020
|
6.418
|
%
|
$
|
250
|
|
|
September 2016 - 2046
|
September 2022
|
6.809
|
%
|
$
|
100
|
|
|
September 2017 - 2047
|
September 2020
|
6.891
|
%
|
$
|
250
|
|
|
September 2017 - 2047
|
September 2021
|
6.570
|
%
|
$
|
450
|
|
|
September 2017 - 2047
|
September 2023
|
6.445
|
%
|
|
FINANCIAL STATEMENTS
FOOTNOTES
|
11. Derivative Instruments (Continued)
|
millions except percentages
|
|
Mandatory
|
Fixed
|
|
|||
Notional Principal Amount
|
Reference Period
|
Termination Date
|
Interest Rate
|
|
|||
$
|
250
|
|
|
December 2019 - 2024
|
December 2019
|
2.730
|
%
|
$
|
250
|
|
|
December 2019 - 2029
|
December 2019
|
2.856
|
%
|
$
|
250
|
|
|
December 2019 - 2049
|
December 2019
|
2.905
|
%
|
millions
|
Gross
Derivative Assets
|
|
Gross
Derivative Liabilities
|
||||||||||||||
Balance Sheet Classification
|
|
2018
|
|
|
2017
|
|
|
|
2018
|
|
|
2017
|
|
||||
Commodity derivatives - Anadarko
(1)
|
|
|
|
|
|
|
|
|
|
||||||||
Other current assets
|
|
$
|
300
|
|
|
$
|
7
|
|
|
|
$
|
(126
|
)
|
|
$
|
(1
|
)
|
Other assets
|
|
—
|
|
|
2
|
|
|
|
—
|
|
|
—
|
|
||||
Other current liabilities
|
|
1
|
|
|
45
|
|
|
|
(6
|
)
|
|
(206
|
)
|
||||
Other liabilities
|
|
—
|
|
|
—
|
|
|
|
—
|
|
|
(2
|
)
|
||||
|
|
301
|
|
|
54
|
|
|
|
(132
|
)
|
|
(209
|
)
|
||||
Interest-rate derivatives - Anadarko
(1)
|
|
|
|
|
|
|
|
|
|
||||||||
Other current assets
|
|
22
|
|
|
14
|
|
|
|
—
|
|
|
—
|
|
||||
Other assets
|
|
34
|
|
|
40
|
|
|
|
—
|
|
|
—
|
|
||||
Other current liabilities
|
|
—
|
|
|
—
|
|
|
|
(82
|
)
|
|
(236
|
)
|
||||
Other liabilities
|
|
—
|
|
|
—
|
|
|
|
(1,156
|
)
|
|
(1,183
|
)
|
||||
|
|
56
|
|
|
54
|
|
|
|
(1,238
|
)
|
|
(1,419
|
)
|
||||
Interest-rate derivatives - WES
|
|
|
|
|
|
|
|
|
|
||||||||
Other current liabilities
|
|
—
|
|
|
—
|
|
|
|
(8
|
)
|
|
—
|
|
||||
Total derivatives
|
|
$
|
357
|
|
|
$
|
108
|
|
|
|
$
|
(1,378
|
)
|
|
$
|
(1,628
|
)
|
(1)
|
Excludes amounts related to WES interest-rate swap agreements.
|
|
FINANCIAL STATEMENTS
FOOTNOTES
|
11. Derivative Instruments (Continued)
|
millions
|
|
|
|
|
|
||||||
Classification of (Gain) Loss Recognized
|
2018
|
|
|
2017
|
|
|
2016
|
|
|||
Commodity derivatives - Anadarko
(1)
|
|
|
|
|
|
||||||
Gathering, processing, and marketing sales
|
$
|
8
|
|
|
$
|
(4
|
)
|
|
$
|
6
|
|
(Gains) losses on derivatives, net
|
213
|
|
|
3
|
|
|
147
|
|
|||
Interest-rate derivatives - Anadarko
(1)
|
|
|
|
|
|
||||||
(Gains) losses on derivatives, net
|
(91
|
)
|
|
132
|
|
|
139
|
|
|||
Interest-rate derivatives - WES
|
|
|
|
|
|
||||||
(Gains) losses on derivatives, net
|
8
|
|
|
—
|
|
|
—
|
|
|||
Total (gains) losses on derivatives, net
|
$
|
138
|
|
|
$
|
131
|
|
|
$
|
292
|
|
(1)
|
Excludes amounts related to WES interest-rate swap agreements.
|
|
FINANCIAL STATEMENTS
FOOTNOTES
|
11. Derivative Instruments (Continued)
|
millions
|
Level 1
|
|
|
Level 2
|
|
|
Level 3
|
|
|
Netting
(1)
|
|
Collateral
|
|
|
Total
|
|
|||||||
December 31, 2018
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Assets
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Anadarko
(2)
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Commodity derivatives
|
$
|
1
|
|
|
$
|
300
|
|
|
$
|
—
|
|
|
$
|
(127
|
)
|
|
$
|
—
|
|
|
$
|
174
|
|
Interest-rate derivatives
|
—
|
|
|
56
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
56
|
|
||||||
Total derivative assets
|
$
|
1
|
|
|
$
|
356
|
|
|
$
|
—
|
|
|
$
|
(127
|
)
|
|
$
|
—
|
|
|
$
|
230
|
|
Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Anadarko
(2)
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Commodity derivatives
|
$
|
(2
|
)
|
|
$
|
(130
|
)
|
|
$
|
—
|
|
|
$
|
127
|
|
|
$
|
2
|
|
|
$
|
(3
|
)
|
Interest-rate derivatives
|
—
|
|
|
(1,238
|
)
|
|
—
|
|
|
—
|
|
|
66
|
|
|
(1,172
|
)
|
||||||
WES
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Interest-rate derivatives
|
—
|
|
|
(8
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(8
|
)
|
||||||
Total derivative liabilities
|
$
|
(2
|
)
|
|
$
|
(1,376
|
)
|
|
$
|
—
|
|
|
$
|
127
|
|
|
$
|
68
|
|
|
$
|
(1,183
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
December 31, 2017
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Assets
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Anadarko
(2)
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Commodity derivatives
|
$
|
1
|
|
|
$
|
53
|
|
|
$
|
—
|
|
|
$
|
(46
|
)
|
|
$
|
(1
|
)
|
|
$
|
7
|
|
Interest-rate derivatives
|
—
|
|
|
54
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
54
|
|
||||||
Total derivative assets
|
$
|
1
|
|
|
$
|
107
|
|
|
$
|
—
|
|
|
$
|
(46
|
)
|
|
$
|
(1
|
)
|
|
$
|
61
|
|
Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Anadarko
(2)
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Commodity derivatives
|
$
|
(1
|
)
|
|
$
|
(208
|
)
|
|
$
|
—
|
|
|
$
|
46
|
|
|
$
|
3
|
|
|
$
|
(160
|
)
|
Interest-rate derivatives
|
—
|
|
|
(1,419
|
)
|
|
—
|
|
|
—
|
|
|
170
|
|
|
(1,249
|
)
|
||||||
Total derivative liabilities
|
$
|
(1
|
)
|
|
$
|
(1,627
|
)
|
|
$
|
—
|
|
|
$
|
46
|
|
|
$
|
173
|
|
|
$
|
(1,409
|
)
|
(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.
|
|
FINANCIAL STATEMENTS
FOOTNOTES
|
12. Tangible Equity Units
|
|
FINANCIAL STATEMENTS
FOOTNOTES
|
13. Debt and Interest Expense
|
|
Carrying Value
|
|
||||||||||||||
millions
|
WES
|
|
WGP
(1)
|
|
Anadarko
(2)
|
|
Anadarko Consolidated
|
|
Description
|
|||||||
Balance at December 31, 2016
|
$
|
3,091
|
|
|
$
|
28
|
|
|
$
|
11,959
|
|
|
$
|
15,078
|
|
|
Borrowings
|
|
|
|
|
|
|
|
|
||||||||
|
370
|
|
|
—
|
|
|
—
|
|
|
370
|
|
WES RCF
|
||||
Repayments
|
|
|
|
|
|
|
|
|
||||||||
|
—
|
|
|
—
|
|
|
(6
|
)
|
|
(6
|
)
|
7.000% Debentures due 2027
|
||||
|
—
|
|
|
—
|
|
|
(3
|
)
|
|
(3
|
)
|
6.625% Debentures due 2028
|
||||
|
—
|
|
|
—
|
|
|
(1
|
)
|
|
(1
|
)
|
7.950% Debentures due 2029
|
||||
|
—
|
|
|
—
|
|
|
(34
|
)
|
|
(34
|
)
|
TEUs - senior amortizing notes
|
||||
Other, net
|
4
|
|
|
—
|
|
|
50
|
|
|
54
|
|
Amortization of discounts, premiums, and debt issuance costs
|
||||
Balance at December 31, 2017
|
$
|
3,465
|
|
|
$
|
28
|
|
|
$
|
11,965
|
|
|
$
|
15,458
|
|
|
Issuances
|
|
|
|
|
|
|
|
|
||||||||
|
394
|
|
|
—
|
|
|
—
|
|
|
394
|
|
WES 4.500% Senior Notes due 2028
|
||||
|
687
|
|
|
—
|
|
|
—
|
|
|
687
|
|
WES 5.300% Senior Notes due 2048
|
||||
|
396
|
|
|
—
|
|
|
—
|
|
|
396
|
|
WES 4.750% Senior Notes due 2028
|
||||
|
342
|
|
|
—
|
|
|
—
|
|
|
342
|
|
WES 5.500% Senior Notes due 2048
|
||||
Borrowings
|
|
|
|
|
|
|
|
|
||||||||
|
540
|
|
|
—
|
|
|
—
|
|
|
540
|
|
WES RCF
|
||||
Repayments
|
|
|
|
|
|
|
|
|
||||||||
|
—
|
|
|
—
|
|
|
(114
|
)
|
|
(114
|
)
|
7.050% Debentures due 2018
|
||||
|
—
|
|
|
—
|
|
|
(123
|
)
|
|
(123
|
)
|
4.850% Senior Notes due 2021
|
||||
|
—
|
|
|
—
|
|
|
(375
|
)
|
|
(375
|
)
|
3.450% Senior Notes due 2024
|
||||
|
—
|
|
|
—
|
|
|
(35
|
)
|
|
(35
|
)
|
Zero Coupon Notes due 2036
|
||||
|
(350
|
)
|
|
—
|
|
|
—
|
|
|
(350
|
)
|
WES 2.600% Senior Notes due 2018
|
||||
|
(690
|
)
|
|
—
|
|
|
—
|
|
|
(690
|
)
|
WES RCF
|
||||
|
—
|
|
|
—
|
|
|
(17
|
)
|
|
(17
|
)
|
TEUs - senior amortizing notes
|
||||
Other, net
|
3
|
|
|
—
|
|
|
53
|
|
|
56
|
|
Amortization of discounts, premiums, and debt issuance costs
|
||||
Balance at December 31, 2018
|
$
|
4,787
|
|
|
$
|
28
|
|
|
$
|
11,354
|
|
|
$
|
16,169
|
|
|
(1)
|
Excludes WES.
|
(2)
|
Excludes WES and WGP.
|
|
FINANCIAL STATEMENTS
FOOTNOTES
|
13. Debt and Interest Expense (Continued)
|
|
December 31, 2018
|
||||||||||||||
millions
|
WES
|
|
WGP
(1)
|
|
Anadarko
(2)
|
|
Anadarko Consolidated
|
|
|||||||
6.950% Senior Notes due 2019
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
300
|
|
|
$
|
300
|
|
8.700% Senior Notes due 2019
|
—
|
|
|
—
|
|
|
600
|
|
|
600
|
|
||||
4.850% Senior Notes due 2021
|
—
|
|
|
—
|
|
|
677
|
|
|
677
|
|
||||
WES 5.375% Senior Notes due 2021
|
500
|
|
|
—
|
|
|
—
|
|
|
500
|
|
||||
WES 4.000% Senior Notes due 2022
|
670
|
|
|
—
|
|
|
—
|
|
|
670
|
|
||||
3.450% Senior Notes due 2024
|
—
|
|
|
—
|
|
|
248
|
|
|
248
|
|
||||
6.950% Senior Notes due 2024
|
—
|
|
|
—
|
|
|
650
|
|
|
650
|
|
||||
WES 3.950% Senior Notes due 2025
|
500
|
|
|
—
|
|
|
—
|
|
|
500
|
|
||||
WES 4.650% Senior Notes due 2026
|
500
|
|
|
—
|
|
|
—
|
|
|
500
|
|
||||
5.550% Senior Notes due 2026
|
—
|
|
|
—
|
|
|
1,100
|
|
|
1,100
|
|
||||
7.500% Debentures due 2026
|
—
|
|
|
—
|
|
|
112
|
|
|
112
|
|
||||
7.000% Debentures due 2027
|
—
|
|
|
—
|
|
|
48
|
|
|
48
|
|
||||
7.125% Debentures due 2027
|
—
|
|
|
—
|
|
|
150
|
|
|
150
|
|
||||
WES 4.500% Notes due 2028
|
400
|
|
|
—
|
|
|
—
|
|
|
400
|
|
||||
WES 4.750% Notes due 2028
|
400
|
|
|
—
|
|
|
—
|
|
|
400
|
|
||||
6.625% Debentures due 2028
|
—
|
|
|
—
|
|
|
14
|
|
|
14
|
|
||||
7.150% Debentures due 2028
|
—
|
|
|
—
|
|
|
235
|
|
|
235
|
|
||||
7.200% Debentures due 2029
|
—
|
|
|
—
|
|
|
135
|
|
|
135
|
|
||||
7.950% Debentures due 2029
|
—
|
|
|
—
|
|
|
116
|
|
|
116
|
|
||||
7.500% Senior Notes due 2031
|
—
|
|
|
—
|
|
|
900
|
|
|
900
|
|
||||
7.875% Senior Notes due 2031
|
—
|
|
|
—
|
|
|
500
|
|
|
500
|
|
||||
Zero Coupon Senior Notes due 2036
|
—
|
|
|
—
|
|
|
2,270
|
|
|
2,270
|
|
||||
6.450% Senior Notes due 2036
|
—
|
|
|
—
|
|
|
1,750
|
|
|
1,750
|
|
||||
7.950% Senior Notes due 2039
|
—
|
|
|
—
|
|
|
325
|
|
|
325
|
|
||||
6.200% Senior Notes due 2040
|
—
|
|
|
—
|
|
|
750
|
|
|
750
|
|
||||
4.500% Senior Notes due 2044
|
—
|
|
|
—
|
|
|
625
|
|
|
625
|
|
||||
WES 5.450% Senior Notes due 2044
|
600
|
|
|
—
|
|
|
—
|
|
|
600
|
|
||||
6.600% Senior Notes due 2046
|
—
|
|
|
—
|
|
|
1,100
|
|
|
1,100
|
|
||||
WES 5.300% Notes due 2048
|
700
|
|
|
—
|
|
|
—
|
|
|
700
|
|
||||
WES 5.500% Notes due 2048
|
350
|
|
|
—
|
|
|
—
|
|
|
350
|
|
||||
7.730% Debentures due 2096
|
—
|
|
|
—
|
|
|
61
|
|
|
61
|
|
||||
7.500% Debentures due 2096
|
—
|
|
|
—
|
|
|
78
|
|
|
78
|
|
||||
7.250% Debentures due 2096
|
—
|
|
|
—
|
|
|
49
|
|
|
49
|
|
||||
WES RCF
|
220
|
|
|
—
|
|
|
—
|
|
|
220
|
|
||||
WGP RCF
|
—
|
|
|
28
|
|
|
—
|
|
|
28
|
|
||||
Total borrowings at face value
|
$
|
4,840
|
|
|
$
|
28
|
|
|
$
|
12,793
|
|
|
$
|
17,661
|
|
Net unamortized discounts, premiums, and debt issuance costs
(3)
|
(53
|
)
|
|
—
|
|
|
(1,439
|
)
|
|
(1,492
|
)
|
||||
Total borrowings
(4)
|
4,787
|
|
|
28
|
|
|
11,354
|
|
|
16,169
|
|
||||
Capital lease obligations
|
—
|
|
|
—
|
|
|
248
|
|
|
248
|
|
||||
Less short-term debt
|
—
|
|
|
28
|
|
|
919
|
|
|
947
|
|
||||
Total long-term debt
|
$
|
4,787
|
|
|
$
|
—
|
|
|
$
|
10,683
|
|
|
$
|
15,470
|
|
|
FINANCIAL STATEMENTS
FOOTNOTES
|
13. Debt and Interest Expense (Continued)
|
|
December 31, 2017
|
||||||||||||||
millions
|
WES
|
|
|
WGP
(1)
|
|
Anadarko
(2)
|
|
Anadarko Consolidated
|
|
||||||
7.050% Debentures due 2018
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
114
|
|
|
$
|
114
|
|
TEUs - senior amortizing notes due 2018
|
—
|
|
|
—
|
|
|
17
|
|
|
17
|
|
||||
WES 2.600% Senior Notes due 2018
|
350
|
|
|
—
|
|
|
—
|
|
|
350
|
|
||||
6.950% Senior Notes due 2019
|
—
|
|
|
—
|
|
|
300
|
|
|
300
|
|
||||
8.700% Senior Notes due 2019
|
—
|
|
|
—
|
|
|
600
|
|
|
600
|
|
||||
4.850% Senior Notes due 2021
|
—
|
|
|
—
|
|
|
800
|
|
|
800
|
|
||||
WES 5.375% Senior Notes due 2021
|
500
|
|
|
—
|
|
|
—
|
|
|
500
|
|
||||
WES 4.000% Senior Notes due 2022
|
670
|
|
|
—
|
|
|
—
|
|
|
670
|
|
||||
3.450% Senior Notes due 2024
|
—
|
|
|
—
|
|
|
625
|
|
|
625
|
|
||||
6.950% Senior Notes due 2024
|
—
|
|
|
—
|
|
|
650
|
|
|
650
|
|
||||
WES 3.950% Senior Notes due 2025
|
500
|
|
|
—
|
|
|
—
|
|
|
500
|
|
||||
WES 4.650% Senior Notes due 2026
|
500
|
|
|
—
|
|
|
—
|
|
|
500
|
|
||||
5.550% Senior Notes due 2026
|
—
|
|
|
—
|
|
|
1,100
|
|
|
1,100
|
|
||||
7.500% Debentures due 2026
|
—
|
|
|
—
|
|
|
112
|
|
|
112
|
|
||||
7.000% Debentures due 2027
|
—
|
|
|
—
|
|
|
48
|
|
|
48
|
|
||||
7.125% Debentures due 2027
|
—
|
|
|
—
|
|
|
150
|
|
|
150
|
|
||||
6.625% Debentures due 2028
|
—
|
|
|
—
|
|
|
14
|
|
|
14
|
|
||||
7.150% Debentures due 2028
|
—
|
|
|
—
|
|
|
235
|
|
|
235
|
|
||||
7.200% Debentures due 2029
|
—
|
|
|
—
|
|
|
135
|
|
|
135
|
|
||||
7.950% Debentures due 2029
|
—
|
|
|
—
|
|
|
116
|
|
|
116
|
|
||||
7.500% Senior Notes due 2031
|
—
|
|
|
—
|
|
|
900
|
|
|
900
|
|
||||
7.875% Senior Notes due 2031
|
—
|
|
|
—
|
|
|
500
|
|
|
500
|
|
||||
Zero Coupon Senior Notes due 2036
|
—
|
|
|
—
|
|
|
2,360
|
|
|
2,360
|
|
||||
6.450% Senior Notes due 2036
|
—
|
|
|
—
|
|
|
1,750
|
|
|
1,750
|
|
||||
7.950% Senior Notes due 2039
|
—
|
|
|
—
|
|
|
325
|
|
|
325
|
|
||||
6.200% Senior Notes due 2040
|
—
|
|
|
—
|
|
|
750
|
|
|
750
|
|
||||
4.500% Senior Notes due 2044
|
—
|
|
|
—
|
|
|
625
|
|
|
625
|
|
||||
WES 5.450% Senior Notes due 2044
|
600
|
|
|
—
|
|
|
—
|
|
|
600
|
|
||||
6.600% Senior Notes due 2046
|
—
|
|
|
—
|
|
|
1,100
|
|
|
1,100
|
|
||||
7.730% Debentures due 2096
|
—
|
|
|
—
|
|
|
61
|
|
|
61
|
|
||||
7.500% Debentures due 2096
|
—
|
|
|
—
|
|
|
78
|
|
|
78
|
|
||||
7.250% Debentures due 2096
|
—
|
|
|
—
|
|
|
49
|
|
|
49
|
|
||||
WES RCF
|
370
|
|
|
—
|
|
|
—
|
|
|
370
|
|
||||
WGP RCF
|
—
|
|
|
28
|
|
|
—
|
|
|
28
|
|
||||
Total borrowings at face value
|
$
|
3,490
|
|
|
$
|
28
|
|
|
$
|
13,514
|
|
|
$
|
17,032
|
|
Net unamortized discounts, premiums, and debt issuance costs
(3)
|
(25
|
)
|
|
—
|
|
|
(1,549
|
)
|
|
(1,574
|
)
|
||||
Total borrowings
(4)
|
3,465
|
|
|
28
|
|
|
11,965
|
|
|
15,458
|
|
||||
Capital lease obligations
|
—
|
|
|
—
|
|
|
231
|
|
|
231
|
|
||||
Less short-term debt
|
—
|
|
|
—
|
|
|
142
|
|
|
142
|
|
||||
Total long-term debt
|
$
|
3,465
|
|
|
$
|
28
|
|
|
$
|
12,054
|
|
|
$
|
15,547
|
|
(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.
|
|
FINANCIAL STATEMENTS
FOOTNOTES
|
13. Debt and Interest Expense (Continued)
|
|
Principal Amount of Debt Maturities
|
||||||||||||||
millions
|
WES
|
|
|
WGP
(1)
|
|
Anadarko
(2)
|
|
Anadarko Consolidated
|
|
||||||
2019
|
$
|
—
|
|
|
$
|
28
|
|
|
$
|
900
|
|
|
$
|
928
|
|
2020
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||
2021
|
500
|
|
|
—
|
|
|
677
|
|
|
1,177
|
|
||||
2022
|
670
|
|
|
—
|
|
|
—
|
|
|
670
|
|
||||
2023
|
220
|
|
|
—
|
|
|
—
|
|
|
220
|
|
(1)
|
Excludes WES.
|
(2)
|
Excludes WES and WGP.
|
|
FINANCIAL STATEMENTS
FOOTNOTES
|
13. Debt and Interest Expense (Continued)
|
|
FINANCIAL STATEMENTS
FOOTNOTES
|
13. Debt and Interest Expense (Continued)
|
|
FINANCIAL STATEMENTS
FOOTNOTES
|
13. Debt and Interest Expense (Continued)
|
millions
|
|
||
2019
|
$
|
58
|
|
2020
|
50
|
|
|
2021
|
48
|
|
|
2022
|
45
|
|
|
2023
|
43
|
|
|
Thereafter
|
323
|
|
|
Total future minimum lease payments
|
$
|
567
|
|
Less portion representing imputed interest
|
319
|
|
|
Capital lease obligations
|
$
|
248
|
|
millions
|
2018
|
|
|
2017
|
|
|
2016
|
|
|||
Debt and other
|
$
|
1,028
|
|
|
$
|
1,003
|
|
|
$
|
1,022
|
|
Capitalized interest
|
(81
|
)
|
|
(71
|
)
|
|
(132
|
)
|
|||
Total interest expense
|
$
|
947
|
|
|
$
|
932
|
|
|
$
|
890
|
|
|
FINANCIAL STATEMENTS
FOOTNOTES
|
14. Income Taxes
|
millions
|
2018
|
|
|
2017
|
|
|
2016
|
|
|||
Current
|
|
|
|
|
|
||||||
Federal
|
$
|
14
|
|
|
$
|
236
|
|
|
$
|
(140
|
)
|
State
|
(1
|
)
|
|
48
|
|
|
(1
|
)
|
|||
Foreign
|
595
|
|
|
414
|
|
|
378
|
|
|||
Total current tax expense (benefit)
|
608
|
|
|
698
|
|
|
237
|
|
|||
Deferred
|
|
|
|
|
|
||||||
Federal
|
150
|
|
|
(2,082
|
)
|
|
(1,020
|
)
|
|||
State
|
(26
|
)
|
|
(17
|
)
|
|
(148
|
)
|
|||
Foreign
|
1
|
|
|
(76
|
)
|
|
(90
|
)
|
|||
Total deferred tax expense (benefit)
|
125
|
|
|
(2,175
|
)
|
|
(1,258
|
)
|
|||
Total income tax expense (benefit)
|
$
|
733
|
|
|
$
|
(1,477
|
)
|
|
$
|
(1,021
|
)
|
|
FINANCIAL STATEMENTS
FOOTNOTES
|
14. Income Taxes (Continued)
|
millions except percentages
|
2018
|
|
|
2017
|
|
|
2016
|
|
|||
Income (loss) before income taxes
|
|
|
|
|
|
||||||
Domestic
|
$
|
492
|
|
|
$
|
(1,322
|
)
|
|
$
|
(3,728
|
)
|
Foreign
|
993
|
|
|
(366
|
)
|
|
(101
|
)
|
|||
Total
|
$
|
1,485
|
|
|
$
|
(1,688
|
)
|
|
$
|
(3,829
|
)
|
U.S. federal statutory tax rate
|
21
|
%
|
|
35
|
%
|
|
35
|
%
|
|||
Tax computed at the U.S. federal statutory rate
|
$
|
312
|
|
|
$
|
(591
|
)
|
|
$
|
(1,340
|
)
|
(Income) loss attributable to noncontrolling interests
|
(29
|
)
|
|
(85
|
)
|
|
(92
|
)
|
|||
Adjustments resulting from
|
|
|
|
|
|
||||||
State income taxes (net of federal income tax benefit)
|
(18
|
)
|
|
25
|
|
|
(108
|
)
|
|||
U.S. federal tax reform
|
95
|
|
|
(1,168
|
)
|
|
—
|
|
|||
Tax impact from foreign operations
|
181
|
|
|
166
|
|
|
80
|
|
|||
Non-deductible Algerian exceptional profits tax
|
154
|
|
|
110
|
|
|
106
|
|
|||
Net changes in uncertain tax positions
|
(29
|
)
|
|
90
|
|
|
90
|
|
|||
Dispositions of non-deductible goodwill
|
—
|
|
|
6
|
|
|
205
|
|
|||
Other, net
|
67
|
|
|
(30
|
)
|
|
38
|
|
|||
Total income tax expense (benefit)
|
$
|
733
|
|
|
$
|
(1,477
|
)
|
|
$
|
(1,021
|
)
|
Effective tax rate
|
49
|
%
|
|
88
|
%
|
|
27
|
%
|
millions
|
2018
|
|
|
2017
|
|
||
Federal
|
$
|
(1,972
|
)
|
|
$
|
(1,758
|
)
|
State, net of federal
|
(176
|
)
|
|
(200
|
)
|
||
Foreign
|
(255
|
)
|
|
(255
|
)
|
||
Total deferred taxes
(1)
|
$
|
(2,403
|
)
|
|
$
|
(2,213
|
)
|
(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.
|
|
FINANCIAL STATEMENTS
FOOTNOTES
|
14. Income Taxes (Continued)
|
millions
|
2018
|
|
|
2017
|
|
||
Deferred tax liabilities
|
|
|
|
||||
Oil and gas exploration and development operations
|
$
|
(2,403
|
)
|
|
$
|
(2,622
|
)
|
Midstream and other depreciable properties
|
(662
|
)
|
|
(543
|
)
|
||
Mineral operations
|
(238
|
)
|
|
(312
|
)
|
||
Other
|
(134
|
)
|
|
(53
|
)
|
||
Gross long-term deferred tax liabilities
|
(3,437
|
)
|
|
(3,530
|
)
|
||
Deferred tax assets
|
|
|
|
||||
Oil and gas exploration and development costs
|
303
|
|
|
309
|
|
||
Foreign and state net operating loss carryforwards
|
445
|
|
|
562
|
|
||
U.S. foreign tax credit carryforwards
|
2,665
|
|
|
2,685
|
|
||
Compensation and benefit plans
|
301
|
|
|
365
|
|
||
Other
|
308
|
|
|
420
|
|
||
Gross long-term deferred tax assets
|
4,022
|
|
|
4,341
|
|
||
Valuation allowances on deferred tax assets not expected to be realized
|
(2,988
|
)
|
|
(3,024
|
)
|
||
Net long-term deferred tax assets
|
1,034
|
|
|
1,317
|
|
||
Total deferred taxes
|
$
|
(2,403
|
)
|
|
$
|
(2,213
|
)
|
millions
|
2018
|
|
|
2017
|
|
|
2016
|
|
|||
Balance at January 1
|
$
|
(3,024
|
)
|
|
$
|
(1,755
|
)
|
|
$
|
(1,403
|
)
|
Changes due to U.S. foreign tax credits
|
(50
|
)
|
|
(1,287
|
)
|
|
(477
|
)
|
|||
Changes due to foreign and state net operating loss carryforwards
|
72
|
|
|
75
|
|
|
13
|
|
|||
Changes due to foreign capitalized costs
|
14
|
|
|
(57
|
)
|
|
112
|
|
|||
Balance at December 31
|
$
|
(2,988
|
)
|
|
$
|
(3,024
|
)
|
|
$
|
(1,755
|
)
|
millions
|
Domestic
|
|
|
Foreign
|
|
Expiration
|
||
Net operating loss—state
(1)
|
$
|
4,250
|
|
|
$
|
—
|
|
2019-2038
|
Net operating loss—foreign
|
$
|
—
|
|
|
$
|
820
|
|
2019-Indefinite
|
Foreign tax credits
(2)
|
$
|
2,665
|
|
|
$
|
—
|
|
2023-2028
|
Texas margins tax credit
|
$
|
27
|
|
|
$
|
—
|
|
2026
|
(1)
|
Net of
$711 million
uncertain tax position at December 31, 2018.
|
(2)
|
Net of
$378 million
uncertain tax position at December 31, 2018.
|
|
FINANCIAL STATEMENTS
FOOTNOTES
|
14. Income Taxes (Continued)
|
millions
|
|
|
|
||||
Balance Sheet Classification
|
2018
|
|
|
2017
|
|
||
Income taxes receivable
|
|
|
|
||||
Accounts receivable—other
|
$
|
46
|
|
|
$
|
53
|
|
Other assets
|
51
|
|
|
101
|
|
||
|
97
|
|
|
154
|
|
||
Income taxes (payable)
|
|
|
|
||||
Other current liabilities
|
(167
|
)
|
|
(71
|
)
|
||
Total net income taxes receivable (payable)
|
$
|
(70
|
)
|
|
$
|
83
|
|
|
Assets (Liabilities)
|
||||||||||
millions
|
2018
|
|
|
2017
|
|
|
2016
|
|
|||
Balance at January 1
|
$
|
(1,317
|
)
|
|
$
|
(1,456
|
)
|
|
$
|
(1,780
|
)
|
Increases related to prior-year tax positions
|
(21
|
)
|
|
(15
|
)
|
|
(86
|
)
|
|||
Decreases related to prior-year tax positions
|
48
|
|
|
214
|
|
|
436
|
|
|||
Increases related to current-year tax positions
|
—
|
|
|
(72
|
)
|
|
(26
|
)
|
|||
Settlements
|
1
|
|
|
12
|
|
|
—
|
|
|||
Lapse of statute of limitations
|
2
|
|
|
—
|
|
|
—
|
|
|||
Balance at December 31
|
$
|
(1,287
|
)
|
|
$
|
(1,317
|
)
|
|
$
|
(1,456
|
)
|
|
FINANCIAL STATEMENTS
FOOTNOTES
|
14. Income Taxes (Continued)
|
|
Tax Years
|
United States
|
2013-2018
|
Algeria
|
2015-2018
|
Ghana
|
2015-2018
|
15. Asset Retirement Obligations
|
millions
|
2018
|
|
|
2017
|
|
||
Carrying amount at January 1
|
$
|
2,794
|
|
|
$
|
2,931
|
|
Liabilities acquired
|
—
|
|
|
4
|
|
||
Liabilities incurred
|
153
|
|
|
191
|
|
||
Property dispositions
|
(99
|
)
|
|
(154
|
)
|
||
Liabilities settled
|
(274
|
)
|
|
(135
|
)
|
||
Accretion expense
|
130
|
|
|
144
|
|
||
Revisions in estimated liabilities
|
395
|
|
|
(187
|
)
|
||
Carrying amount at December 31
|
$
|
3,099
|
|
|
$
|
2,794
|
|
|
FINANCIAL STATEMENTS
FOOTNOTES
|
16. Conveyance of Future Hard-Minerals Royalty Revenues
|
millions
|
|
||
2019
|
$
|
52
|
|
2020
|
57
|
|
|
2021
|
57
|
|
|
2022
|
58
|
|
|
2023
|
60
|
|
|
Thereafter
|
144
|
|
|
Total
|
$
|
428
|
|
|
FINANCIAL STATEMENTS
FOOTNOTES
|
17. Commitments
|
millions
|
|
||
2019
|
$
|
264
|
|
2020
|
139
|
|
|
2021
|
57
|
|
|
2022
|
35
|
|
|
2023
|
24
|
|
|
Thereafter
|
135
|
|
|
Total future minimum lease payments
|
$
|
654
|
|
millions
|
|
||
2019
|
$
|
1,147
|
|
2020
|
1,155
|
|
|
2021
|
993
|
|
|
2022
|
786
|
|
|
2023
|
646
|
|
|
Thereafter
|
1,498
|
|
|
Total
(1)
|
$
|
6,225
|
|
(1)
|
Excludes purchase commitments for jointly owned fields and facilities for which the Company is not the operator.
|
|
FINANCIAL STATEMENTS
FOOTNOTES
|
18. Contingencies
|
19. Restructuring Charges
|
|
FINANCIAL STATEMENTS
FOOTNOTES
|
20. Pension Plans, Other Postretirement Benefits, and Defined-Contribution Plans
|
|
Pension Benefits
|
|
Other Benefits
|
||||||||||||||
millions
|
|
2018
|
|
|
2017
|
|
|
|
2018
|
|
|
2017
|
|
||||
Change in benefit obligation
|
|
|
|
|
|
|
|
|
|
||||||||
Benefit obligation at beginning of year
|
|
$
|
2,218
|
|
|
$
|
2,301
|
|
|
|
$
|
302
|
|
|
$
|
296
|
|
Service cost
|
|
90
|
|
|
87
|
|
|
|
1
|
|
|
2
|
|
||||
Interest cost
|
|
77
|
|
|
84
|
|
|
|
11
|
|
|
12
|
|
||||
Actuarial (gain) loss
|
|
(176
|
)
|
|
107
|
|
|
|
(23
|
)
|
|
15
|
|
||||
Curtailments, settlements, and special termination benefits expense
|
|
15
|
|
|
23
|
|
|
|
—
|
|
|
(1
|
)
|
||||
Participant contributions
|
|
—
|
|
|
—
|
|
|
|
7
|
|
|
5
|
|
||||
Benefit payments
|
|
(268
|
)
|
|
(396
|
)
|
|
|
(25
|
)
|
|
(27
|
)
|
||||
Foreign-currency exchange-rate changes
|
|
(8
|
)
|
|
12
|
|
|
|
—
|
|
|
—
|
|
||||
Benefit obligation at end of year
(1)
|
|
$
|
1,948
|
|
|
$
|
2,218
|
|
|
|
$
|
273
|
|
|
$
|
302
|
|
Change in plan assets
|
|
|
|
|
|
|
|
|
|
||||||||
Fair value of plan assets at beginning of year
|
|
$
|
1,424
|
|
|
$
|
1,340
|
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Actual return on plan assets
|
|
(57
|
)
|
|
209
|
|
|
|
—
|
|
|
—
|
|
||||
Employer contributions
|
|
225
|
|
|
254
|
|
|
|
19
|
|
|
22
|
|
||||
Participant contributions
|
|
—
|
|
|
—
|
|
|
|
7
|
|
|
5
|
|
||||
Benefits paid related to plan settlements
|
|
(212
|
)
|
|
(337
|
)
|
|
|
(1
|
)
|
|
(3
|
)
|
||||
Benefit payments, other
|
|
(56
|
)
|
|
(59
|
)
|
|
|
(25
|
)
|
|
(24
|
)
|
||||
Foreign-currency exchange-rate changes
|
|
(10
|
)
|
|
17
|
|
|
|
—
|
|
|
—
|
|
||||
Fair value of plan assets at end of year
|
|
$
|
1,314
|
|
|
$
|
1,424
|
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Funded status of the plans at end of year
|
|
$
|
(634
|
)
|
|
$
|
(794
|
)
|
|
|
$
|
(273
|
)
|
|
$
|
(302
|
)
|
Amounts recognized on the balance sheet
|
|
|
|
|
|
|
|
|
|
||||||||
Other assets
|
|
$
|
63
|
|
|
$
|
58
|
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Other current liabilities
|
|
(42
|
)
|
|
(16
|
)
|
|
|
(21
|
)
|
|
(21
|
)
|
||||
Other long-term liabilities—other
|
|
(655
|
)
|
|
(836
|
)
|
|
|
(252
|
)
|
|
(281
|
)
|
||||
Total
|
|
$
|
(634
|
)
|
|
$
|
(794
|
)
|
|
|
$
|
(273
|
)
|
|
$
|
(302
|
)
|
Amounts recognized in accumulated other comprehensive income
|
|
|
|
|
|
|
|
|
|
||||||||
Prior service (credit) cost
|
|
$
|
1
|
|
|
$
|
—
|
|
|
|
$
|
(2
|
)
|
|
$
|
(26
|
)
|
Net actuarial (gain) loss
|
|
399
|
|
|
501
|
|
|
|
(9
|
)
|
|
14
|
|
||||
Total
|
|
$
|
400
|
|
|
$
|
501
|
|
|
|
$
|
(11
|
)
|
|
$
|
(12
|
)
|
(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
.
|
|
FINANCIAL STATEMENTS
FOOTNOTES
|
20. Pension Plans, Other Postretirement Benefits, and Defined-Contribution Plans (Continued)
|
millions
|
2018
|
|
|
2017
|
|
||
Projected benefit obligation
|
$
|
1,828
|
|
|
$
|
2,079
|
|
Accumulated benefit obligation
|
1,527
|
|
|
1,749
|
|
||
Fair value of plan assets
|
1,131
|
|
|
1,227
|
|
|
Pension Benefits
|
|
Other Benefits
|
||||||||||||||||||||||
millions
|
|
2018
|
|
|
2017
|
|
|
2016
|
|
|
|
2018
|
|
|
2017
|
|
|
2016
|
|
||||||
Components of net periodic benefit cost
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Service cost
|
|
$
|
90
|
|
|
$
|
87
|
|
|
$
|
99
|
|
|
|
$
|
1
|
|
|
$
|
2
|
|
|
$
|
3
|
|
Interest cost
|
|
77
|
|
|
84
|
|
|
95
|
|
|
|
11
|
|
|
12
|
|
|
12
|
|
||||||
Expected (return) loss on plan assets
|
|
(83
|
)
|
|
(84
|
)
|
|
(97
|
)
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Amortization of net actuarial (gain) loss
|
|
25
|
|
|
25
|
|
|
42
|
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Amortization of net prior service (credit) cost
|
|
—
|
|
|
(1
|
)
|
|
—
|
|
|
|
(24
|
)
|
|
(24
|
)
|
|
(25
|
)
|
||||||
Settlement expense
(1)
|
|
49
|
|
|
91
|
|
|
146
|
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Termination benefits expense
(1)
|
|
7
|
|
|
4
|
|
|
44
|
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Curtailment expense
(1)
|
|
(1
|
)
|
|
—
|
|
|
8
|
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Net periodic benefit cost
(2)
|
|
$
|
164
|
|
|
$
|
206
|
|
|
$
|
337
|
|
|
|
$
|
(12
|
)
|
|
$
|
(10
|
)
|
|
$
|
(10
|
)
|
(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.
|
|
Pension Benefits
|
|
Other Benefits
|
||||||||||||||||||||||
millions
|
|
2018
|
|
|
2017
|
|
|
2016
|
|
|
|
2018
|
|
|
2017
|
|
|
2016
|
|
||||||
Amounts recognized in other comprehensive income (expense)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Net actuarial gain (loss)
|
|
$
|
27
|
|
|
$
|
—
|
|
|
$
|
(150
|
)
|
|
|
$
|
23
|
|
|
$
|
(14
|
)
|
|
$
|
(25
|
)
|
Amortization of net actuarial (gain) loss
|
|
74
|
|
|
116
|
|
|
188
|
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Amortization of net prior service (credit) cost
|
|
—
|
|
|
(1
|
)
|
|
—
|
|
|
|
(24
|
)
|
|
(24
|
)
|
|
(34
|
)
|
||||||
Total amounts recognized in other comprehensive income (expense)
|
|
$
|
101
|
|
|
$
|
115
|
|
|
$
|
38
|
|
|
|
$
|
(1
|
)
|
|
$
|
(38
|
)
|
|
$
|
(59
|
)
|
|
FINANCIAL STATEMENTS
FOOTNOTES
|
20. Pension Plans, Other Postretirement Benefits, and Defined-Contribution Plans (Continued)
|
|
Pension Benefits
|
|
Other Benefits
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
|
|
2018
|
|
2017
|
|
2016
|
|
Benefit obligation assumptions
|
|
|
|
|
|
|
|
||||||
Discount rate
|
4.30
|
%
|
3.62
|
%
|
4.06
|
%
|
|
4.43
|
%
|
3.75
|
%
|
4.26
|
%
|
Rates of increase in compensation levels
|
5.33
|
%
|
5.36
|
%
|
5.40
|
%
|
|
5.43
|
%
|
5.46
|
%
|
5.48
|
%
|
Net periodic benefit cost assumptions
|
|
|
|
|
|
|
|
||||||
Discount rate
|
3.62
|
%
|
4.06
|
%
|
4.62
|
%
|
|
3.75
|
%
|
4.26
|
%
|
5.00
|
%
|
Long-term rate of return on plan assets
|
6.09
|
%
|
6.12
|
%
|
6.77
|
%
|
|
N/A
|
|
N/A
|
|
N/A
|
|
Rates of increase in compensation levels
|
5.36
|
%
|
5.40
|
%
|
5.34
|
%
|
|
5.46
|
%
|
5.48
|
%
|
5.41
|
%
|
|
FINANCIAL STATEMENTS
FOOTNOTES
|
20. Pension Plans, Other Postretirement Benefits, and Defined-Contribution Plans (Continued)
|
|
FINANCIAL STATEMENTS
FOOTNOTES
|
20. Pension Plans, Other Postretirement Benefits, and Defined-Contribution Plans (Continued)
|
millions
|
|
|
|
|
|
|
|
||||||||
December 31, 2018
|
Level 1
|
|
|
Level 2
|
|
|
Level 3
(3)
|
|
|
Total
|
|
||||
Investments
|
|
|
|
|
|
|
|
||||||||
Cash and cash equivalents
|
$
|
28
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
28
|
|
Fixed income
|
43
|
|
|
28
|
|
|
—
|
|
|
71
|
|
||||
Equity securities
|
189
|
|
|
—
|
|
|
—
|
|
|
189
|
|
||||
Other
|
|
|
|
|
|
|
|
||||||||
Real estate
|
—
|
|
|
—
|
|
|
13
|
|
|
13
|
|
||||
Other
|
—
|
|
|
49
|
|
|
—
|
|
|
49
|
|
||||
Investments measured at net asset value
(1)
|
—
|
|
|
—
|
|
|
—
|
|
|
964
|
|
||||
Total investments
(2)
|
$
|
260
|
|
|
$
|
77
|
|
|
$
|
13
|
|
|
$
|
1,314
|
|
|
|
|
|
|
|
|
|
||||||||
December 31, 2017
|
|
|
|
|
|
|
|
||||||||
Investments
|
|
|
|
|
|
|
|
||||||||
Cash and cash equivalents
|
$
|
1
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
1
|
|
Fixed income
|
55
|
|
|
31
|
|
|
—
|
|
|
86
|
|
||||
Equity securities
|
185
|
|
|
—
|
|
|
—
|
|
|
185
|
|
||||
Other
|
|
|
|
|
|
|
|
||||||||
Real estate
|
—
|
|
|
—
|
|
|
13
|
|
|
13
|
|
||||
Other
|
—
|
|
|
53
|
|
|
—
|
|
|
53
|
|
||||
Investments measured at net asset value
(1)
|
—
|
|
|
—
|
|
|
—
|
|
|
1,086
|
|
||||
Total investments
(2)
|
$
|
241
|
|
|
$
|
84
|
|
|
$
|
13
|
|
|
$
|
1,424
|
|
(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.
|
|
FINANCIAL STATEMENTS
FOOTNOTES
|
20. Pension Plans, Other Postretirement Benefits, and Defined-Contribution Plans (Continued)
|
millions
|
Expected 2019
|
|
|
2018
|
|
||
Funded pension plans
|
$
|
90
|
|
|
$
|
161
|
|
Unfunded pension plans
|
43
|
|
|
64
|
|
||
Unfunded other postretirement plans
|
22
|
|
|
19
|
|
||
Total
|
$
|
155
|
|
|
$
|
244
|
|
millions
|
Pension Benefit
Payments
|
|
Other Benefit
Payments
|
|
||||
2019
|
|
$
|
223
|
|
|
$
|
22
|
|
2020
|
|
148
|
|
|
21
|
|
||
2021
|
|
150
|
|
|
20
|
|
||
2022
|
|
190
|
|
|
20
|
|
||
2023
|
|
181
|
|
|
20
|
|
||
2024-2028
|
|
839
|
|
|
86
|
|
|
FINANCIAL STATEMENTS
FOOTNOTES
|
21. Stockholders’ Equity
|
|
FINANCIAL STATEMENTS
FOOTNOTES
|
21. Stockholders’ Equity (Continued)
|
millions
|
2018
|
|
2017
|
|
2016
|
|
Shares of common stock issued
|
|
|
|
|||
Shares at January 1
|
574
|
|
572
|
|
528
|
|
Exercise of stock options
|
—
|
|
—
|
|
1
|
|
Issuance of common stock
|
—
|
|
—
|
|
41
|
|
Issuance of restricted stock
|
3
|
|
2
|
|
2
|
|
Shares at December 31
|
577
|
|
574
|
|
572
|
|
Shares of common stock held in treasury
|
|
|
|
|||
Shares at January 1
|
43
|
|
21
|
|
20
|
|
Purchase of treasury stock
|
43
|
|
22
|
|
—
|
|
Shares received for restricted stock vested and stock options exercised
|
1
|
|
—
|
|
1
|
|
Shares at December 31
|
87
|
|
43
|
|
21
|
|
Shares of common stock outstanding at December 31
|
490
|
|
531
|
|
551
|
|
millions except per-share amounts
|
2018
|
|
|
2017
|
|
|
2016
|
|
|||
Net income (loss)
|
|
|
|
|
|
||||||
Net income (loss) attributable to common stockholders
|
$
|
615
|
|
|
$
|
(456
|
)
|
|
$
|
(3,071
|
)
|
Income (loss) effect of TEUs
|
(4
|
)
|
|
(7
|
)
|
|
(6
|
)
|
|||
Less distributions on participating securities
|
5
|
|
|
1
|
|
|
1
|
|
|||
Basic
|
$
|
606
|
|
|
$
|
(464
|
)
|
|
$
|
(3,078
|
)
|
Income (loss) effect of TEUs
|
(1
|
)
|
|
(2
|
)
|
|
(1
|
)
|
|||
Diluted
|
$
|
605
|
|
|
$
|
(466
|
)
|
|
$
|
(3,079
|
)
|
Shares
|
|
|
|
|
|
||||||
Average number of common shares outstanding—basic
|
504
|
|
|
548
|
|
|
522
|
|
|||
Average number of common shares outstanding—diluted
|
504
|
|
|
548
|
|
|
522
|
|
|||
Excluded due to anti-dilutive effect
|
9
|
|
|
11
|
|
|
11
|
|
|||
Net income (loss) per common share
|
|
|
|
|
|
||||||
Basic
|
$
|
1.20
|
|
|
$
|
(0.85
|
)
|
|
$
|
(5.90
|
)
|
Diluted
|
$
|
1.20
|
|
|
$
|
(0.85
|
)
|
|
$
|
(5.90
|
)
|
Dividends per common share
|
$
|
1.05
|
|
|
$
|
0.20
|
|
|
$
|
0.20
|
|
|
FINANCIAL STATEMENTS
FOOTNOTES
|
22. Accumulated Other Comprehensive Income (Loss)
|
millions
|
Interest-rate
Derivatives
Previously
Subject to Hedge
Accounting
|
|
Pension
and Other Postretirement
Plans
|
|
|
Total
|
|
|||||
Balance at December 31, 2015
|
|
$
|
(42
|
)
|
|
$
|
(341
|
)
|
|
$
|
(383
|
)
|
Other comprehensive income (loss), before reclassifications
|
|
—
|
|
|
(107
|
)
|
|
(107
|
)
|
|||
Reclassifications to Consolidated Statement of Income
|
|
5
|
|
|
94
|
|
|
99
|
|
|||
Net other comprehensive income (loss)
|
|
5
|
|
|
(13
|
)
|
|
(8
|
)
|
|||
Balance at December 31, 2016
|
|
$
|
(37
|
)
|
|
$
|
(354
|
)
|
|
$
|
(391
|
)
|
Other comprehensive income (loss), before reclassifications
|
|
—
|
|
|
(10
|
)
|
|
(10
|
)
|
|||
Reclassifications to Consolidated Statement of Income
|
|
2
|
|
|
61
|
|
|
63
|
|
|||
Net other comprehensive income (loss)
|
|
2
|
|
|
51
|
|
|
53
|
|
|||
Balance at December 31, 2017
|
|
$
|
(35
|
)
|
|
$
|
(303
|
)
|
|
$
|
(338
|
)
|
Other comprehensive income (loss), before reclassifications
|
|
—
|
|
|
39
|
|
|
39
|
|
|||
Reclassifications to Consolidated Statement of Income
|
|
2
|
|
|
35
|
|
|
37
|
|
|||
Cumulative effect of accounting change
(1)
|
|
(7
|
)
|
|
(66
|
)
|
|
(73
|
)
|
|||
Net other comprehensive income (loss)
|
|
(5
|
)
|
|
8
|
|
|
3
|
|
|||
Balance at December 31, 2018
|
|
$
|
(40
|
)
|
|
$
|
(295
|
)
|
|
$
|
(335
|
)
|
(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.
|
|
FINANCIAL STATEMENTS
FOOTNOTES
|
23. Share-Based Compensation
|
millions
|
2018
|
|
|
2017
|
|
|
2016
|
|
|||
Restricted stock
(1)
|
$
|
147
|
|
|
$
|
145
|
|
|
$
|
175
|
|
Stock options
(1)
|
21
|
|
|
17
|
|
|
20
|
|
|||
Other equity-classified awards
|
1
|
|
|
1
|
|
|
2
|
|
|||
Performance-based unit awards
(1)
|
19
|
|
|
(13
|
)
|
|
38
|
|
|||
Pretax share-based compensation expense
|
$
|
188
|
|
|
$
|
150
|
|
|
$
|
235
|
|
Income tax benefit
|
$
|
43
|
|
|
$
|
35
|
|
|
$
|
86
|
|
(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.
|
|
Shares
(millions)
|
|
Weighted-Average
Grant-Date
Fair Value
(per share)
|
|
||
Non-vested at January 1, 2018
|
4.69
|
|
|
$
|
59.24
|
|
Granted
|
2.72
|
|
|
$
|
58.30
|
|
Vested
|
(2.30
|
)
|
|
$
|
61.19
|
|
Forfeited
|
(0.42
|
)
|
|
$
|
58.07
|
|
Non-vested at December 31, 2018
|
4.69
|
|
|
$
|
57.88
|
|
|
FINANCIAL STATEMENTS
FOOTNOTES
|
23. Share-Based Compensation (Continued)
|
•
|
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.
|
|
2018
|
|
|
2017
|
|
|
2016
|
|
|||
Weighted-average grant-date fair value
|
$
|
15.36
|
|
|
$
|
14.77
|
|
|
$
|
15.92
|
|
Assumptions
|
|
|
|
|
|
||||||
Expected option life—years
|
4.8
|
|
|
4.8
|
|
|
4.1
|
|
|||
Volatility
|
33.5
|
%
|
|
33.6
|
%
|
|
38.2
|
%
|
|||
Risk-free interest rate
|
2.9
|
%
|
|
2.0
|
%
|
|
1.3
|
%
|
|||
Dividend yield
|
1.9
|
%
|
|
0.4
|
%
|
|
0.6
|
%
|
|
Shares
(millions)
|
|
Weighted-
Average
Exercise
Price
(per share)
|
|
Weighted-
Average
Remaining
Contractual
Term
(years)
|
Aggregate
Intrinsic
Value
(millions)
|
|
||||
Outstanding at January 1, 2018
|
6.57
|
|
|
$
|
71.44
|
|
|
|
|
||
Granted
|
1.19
|
|
|
$
|
55.47
|
|
|
|
|
||
Exercised
(1)
|
(0.10
|
)
|
|
$
|
65.03
|
|
|
|
|
||
Forfeited or expired
|
(1.30
|
)
|
|
$
|
79.55
|
|
|
|
|
||
Outstanding at December 31, 2018
|
6.36
|
|
|
$
|
67.00
|
|
3.92
|
|
$
|
—
|
|
Vested or expected to vest at December 31, 2018
|
6.36
|
|
|
$
|
67.00
|
|
3.92
|
|
$
|
—
|
|
Exercisable at December 31, 2018
|
4.12
|
|
|
$
|
74.19
|
|
2.66
|
|
$
|
—
|
|
(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.
|
|
FINANCIAL STATEMENTS
FOOTNOTES
|
23. Share-Based Compensation (Continued)
|
24. Noncontrolling Interests
|
|
FINANCIAL STATEMENTS
FOOTNOTES
|
25. Variable Interest Entities
|
millions
|
2018
|
|
|
2017
|
|
|
2016
|
|
|||
Statement of Operations Data
|
|
|
|
|
|
||||||
Total revenues and other
|
$
|
1,990
|
|
|
$
|
2,248
|
|
|
$
|
1,804
|
|
Operating income (loss)
|
625
|
|
|
704
|
|
|
705
|
|
|||
Net income (loss)
|
449
|
|
|
573
|
|
|
597
|
|
|||
Statement of Cash Flows Data
|
|
|
|
|
|
||||||
Net cash provided by (used in) operating activities
|
$
|
1,017
|
|
|
$
|
897
|
|
|
$
|
913
|
|
Net cash provided by (used in) investing activities
|
(1,460
|
)
|
|
(764
|
)
|
|
(1,106
|
)
|
|||
Net cash provided by (used in) financing activities
|
456
|
|
|
(413
|
)
|
|
452
|
|
millions
|
2018
|
|
|
2017
|
|
||
Balance Sheet Data
|
|
|
|
||||
Net property, plant, and equipment
|
$
|
6,612
|
|
|
$
|
5,731
|
|
Total assets
|
9,239
|
|
|
8,016
|
|
||
Long-term debt
|
4,787
|
|
|
3,493
|
|
||
Total liabilities
|
5,734
|
|
|
4,071
|
|
||
Total equity and partners’ capital
|
3,505
|
|
|
3,945
|
|
millions
|
2018
|
|
|
2017
|
|
|
2016
|
|
|||
WGP distributions to Anadarko
(1)
|
$
|
408
|
|
|
$
|
368
|
|
|
$
|
321
|
|
WGP distributions to third parties
|
494
|
|
|
443
|
|
|
362
|
|
(1)
|
WGP distributions to Anadarko are eliminated upon consolidation.
|
|
FINANCIAL STATEMENTS
FOOTNOTES
|
25. Variable Interest Entities (Continued)
|
|
FINANCIAL STATEMENTS
FOOTNOTES
|
26. Supplemental Cash Flow Information
|
millions
|
2018
|
|
|
2017
|
|
|
2016
|
|
|||
Cash paid (received)
|
|
|
|
|
|
||||||
Interest, net of amounts capitalized
|
$
|
982
|
|
|
$
|
906
|
|
|
$
|
856
|
|
Income taxes, net of refunds
(1)
|
51
|
|
|
64
|
|
|
(882
|
)
|
|||
Non-cash investing activities
|
|
|
|
|
|
||||||
Fair value of properties and equipment acquired
|
$
|
22
|
|
|
$
|
640
|
|
|
$
|
3
|
|
Asset retirement cost additions
|
523
|
|
|
66
|
|
|
298
|
|
|||
Accruals of property, plant, and equipment
|
822
|
|
|
824
|
|
|
549
|
|
|||
Net liabilities assumed (divested) in acquisitions and divestitures
|
(111
|
)
|
|
(158
|
)
|
|
723
|
|
|||
Non-cash investing and financing activities
|
|
|
|
|
|
||||||
Acquisition contingent consideration
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
103
|
|
Non-cash financing activities
|
|
|
|
|
|
||||||
Settlement of tangible equity units
|
$
|
300
|
|
|
$
|
—
|
|
|
$
|
—
|
|
(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.
|
|
December 31,
|
||||||
millions
|
2018
|
|
|
2017
|
|
||
Cash and cash equivalents
|
$
|
1,295
|
|
|
$
|
4,553
|
|
Restricted cash and restricted cash equivalents included in Other Assets
|
134
|
|
|
121
|
|
||
Cash, Cash Equivalents, Restricted Cash, and Restricted Cash Equivalents
|
$
|
1,429
|
|
|
$
|
4,674
|
|
|
FINANCIAL STATEMENTS
FOOTNOTES
|
27. Segment Information
|
millions
|
2018
|
|
|
2017
|
|
|
2016
|
|
|||
Income (loss) before income taxes
|
$
|
1,485
|
|
|
$
|
(1,688
|
)
|
|
$
|
(3,829
|
)
|
(Gains) losses on divestitures, net
|
(20
|
)
|
|
(674
|
)
|
|
757
|
|
|||
Exploration expense
(1)
|
459
|
|
|
2,535
|
|
|
944
|
|
|||
DD&A
|
4,254
|
|
|
4,279
|
|
|
4,301
|
|
|||
Impairments
|
800
|
|
|
408
|
|
|
227
|
|
|||
Interest expense
|
947
|
|
|
932
|
|
|
890
|
|
|||
Total (gains) losses on derivatives, net, less net cash from settlement of commodity derivatives
|
(407
|
)
|
|
156
|
|
|
559
|
|
|||
Restructuring and reorganization-related charges
|
53
|
|
|
21
|
|
|
389
|
|
|||
Other operating expense
|
—
|
|
|
—
|
|
|
1
|
|
|||
(Gains) losses on early extinguishment of debt
|
(2
|
)
|
|
2
|
|
|
155
|
|
|||
Certain other nonoperating items
|
—
|
|
|
—
|
|
|
(58
|
)
|
|||
Less net income (loss) attributable to noncontrolling interests
|
137
|
|
|
245
|
|
|
263
|
|
|||
Consolidated Adjusted EBITDAX
|
$
|
7,432
|
|
|
$
|
5,726
|
|
|
$
|
4,073
|
|
(1)
|
Includes reorganization-related charges of
$20 million
for the
year ended December 31, 2018
.
|
|
FINANCIAL STATEMENTS
FOOTNOTES
|
27. Segment Information (Continued)
|
millions
|
Exploration
& Production
|
|
WES Midstream
|
|
Other Midstream
|
|
Other and
Intersegment
Eliminations
|
|
Total
|
|
|||||||||
2018
|
|
|
|
|
|
|
|
|
|
||||||||||
Sales revenues
|
|
$
|
11,401
|
|
|
$
|
1,501
|
|
|
$
|
117
|
|
|
$
|
51
|
|
$
|
13,070
|
|
Intersegment revenues
|
|
81
|
|
|
488
|
|
|
307
|
|
|
(876
|
)
|
—
|
|
|||||
Other
|
|
(4
|
)
|
|
173
|
|
|
41
|
|
|
82
|
|
292
|
|
|||||
Total revenues and other
(1)
|
|
11,478
|
|
|
2,162
|
|
|
465
|
|
|
(743
|
)
|
13,362
|
|
|||||
Operating costs and expenses
(2)
|
|
3,917
|
|
|
964
|
|
|
105
|
|
|
257
|
|
5,243
|
|
|||||
Net cash from settlement of commodity derivatives
|
|
—
|
|
|
—
|
|
|
—
|
|
|
545
|
|
545
|
|
|||||
Other (income) expense, net
(3)
|
|
—
|
|
|
(8
|
)
|
|
—
|
|
|
21
|
|
13
|
|
|||||
Net income (loss) attributable to noncontrolling interests
|
|
—
|
|
|
—
|
|
|
—
|
|
|
137
|
|
137
|
|
|||||
Total expenses and other
|
|
3,917
|
|
|
956
|
|
|
105
|
|
|
960
|
|
5,938
|
|
|||||
Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement
|
|
—
|
|
|
—
|
|
|
—
|
|
|
8
|
|
8
|
|
|||||
Adjusted EBITDAX
|
|
$
|
7,561
|
|
|
$
|
1,206
|
|
|
$
|
360
|
|
|
$
|
(1,695
|
)
|
$
|
7,432
|
|
Net properties and equipment
|
|
$
|
18,184
|
|
|
$
|
6,612
|
|
|
$
|
1,877
|
|
|
$
|
1,942
|
|
$
|
28,615
|
|
Capital expenditures
|
|
$
|
4,095
|
|
|
$
|
1,178
|
|
|
$
|
743
|
|
|
$
|
169
|
|
$
|
6,185
|
|
Goodwill
|
|
$
|
4,343
|
|
|
$
|
416
|
|
|
$
|
30
|
|
|
$
|
—
|
|
$
|
4,789
|
|
(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.
|
|
FINANCIAL STATEMENTS
FOOTNOTES
|
27. Segment Information (Continued)
|
millions
|
Exploration
& Production
|
|
WES Midstream
|
|
Other Midstream
|
|
Other and
Intersegment
Eliminations
|
|
Total
|
|
|||||||||
2017
|
|
|
|
|
|
|
|
|
|
||||||||||
Sales revenues
|
|
$
|
8,946
|
|
|
$
|
1,715
|
|
|
$
|
187
|
|
|
$
|
121
|
|
$
|
10,969
|
|
Intersegment revenues
|
|
23
|
|
|
523
|
|
|
172
|
|
|
(718
|
)
|
—
|
|
|||||
Other
|
|
15
|
|
|
153
|
|
|
30
|
|
|
67
|
|
265
|
|
|||||
Total revenues and other
(1)
|
|
8,984
|
|
|
2,391
|
|
|
389
|
|
|
(530
|
)
|
11,234
|
|
|||||
Operating costs and expenses
(2)
|
|
3,545
|
|
|
1,330
|
|
|
226
|
|
|
157
|
|
5,258
|
|
|||||
Net cash from settlement of commodity derivatives
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(27
|
)
|
(27
|
)
|
|||||
Other (income) expense, net
(3)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
26
|
|
26
|
|
|||||
Net income (loss) attributable to noncontrolling interests
|
|
—
|
|
|
—
|
|
|
—
|
|
|
245
|
|
245
|
|
|||||
Total expenses and other
|
|
3,545
|
|
|
1,330
|
|
|
226
|
|
|
401
|
|
5,502
|
|
|||||
Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(6
|
)
|
(6
|
)
|
|||||
Adjusted EBITDAX
|
|
$
|
5,439
|
|
|
$
|
1,061
|
|
|
$
|
163
|
|
|
$
|
(937
|
)
|
$
|
5,726
|
|
Net properties and equipment
|
|
$
|
18,598
|
|
|
$
|
5,731
|
|
|
$
|
1,140
|
|
|
$
|
1,982
|
|
$
|
27,451
|
|
Capital expenditures
|
|
$
|
3,779
|
|
|
$
|
956
|
|
|
$
|
458
|
|
|
$
|
107
|
|
$
|
5,300
|
|
Goodwill
|
|
$
|
4,343
|
|
|
$
|
416
|
|
|
$
|
30
|
|
|
$
|
—
|
|
$
|
4,789
|
|
2016
|
|
|
|
|
|
|
|
|
|
||||||||||
Sales revenues
|
|
$
|
7,146
|
|
|
$
|
1,055
|
|
|
$
|
146
|
|
|
$
|
100
|
|
$
|
8,447
|
|
Intersegment revenues
|
|
7
|
|
|
712
|
|
|
185
|
|
|
(904
|
)
|
—
|
|
|||||
Other
|
|
(5
|
)
|
|
114
|
|
|
19
|
|
|
51
|
|
179
|
|
|||||
Total revenues and other
(1)
|
|
7,148
|
|
|
1,881
|
|
|
350
|
|
|
(753
|
)
|
8,626
|
|
|||||
Operating costs and expenses
(2)
|
|
3,516
|
|
|
853
|
|
|
225
|
|
|
(18
|
)
|
4,576
|
|
|||||
Net cash from settlement of commodity derivatives
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(265
|
)
|
(265
|
)
|
|||||
Other (income) expense, net
(3)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(13
|
)
|
(13
|
)
|
|||||
Net income (loss) attributable to noncontrolling interests
|
|
—
|
|
|
—
|
|
|
—
|
|
|
263
|
|
263
|
|
|||||
Total expenses and other
|
|
3,516
|
|
|
853
|
|
|
225
|
|
|
(33
|
)
|
4,561
|
|
|||||
Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement
|
|
—
|
|
|
—
|
|
|
—
|
|
|
8
|
|
8
|
|
|||||
Adjusted EBITDAX
|
|
$
|
3,632
|
|
|
$
|
1,028
|
|
|
$
|
125
|
|
|
$
|
(712
|
)
|
$
|
4,073
|
|
Net properties and equipment
|
|
$
|
24,251
|
|
|
$
|
5,050
|
|
|
$
|
885
|
|
|
$
|
1,982
|
|
$
|
32,168
|
|
Capital expenditures
|
|
$
|
2,688
|
|
|
$
|
491
|
|
|
$
|
60
|
|
|
$
|
75
|
|
$
|
3,314
|
|
Goodwill
|
|
$
|
4,550
|
|
|
$
|
418
|
|
|
$
|
32
|
|
|
$
|
—
|
|
$
|
5,000
|
|
(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.
|
|
FINANCIAL STATEMENTS
FOOTNOTES
|
27. Segment Information (Continued)
|
|
Years Ended December 31,
|
||||||||||
millions
|
2018
|
|
|
2017
|
|
|
2016
|
|
|||
Sales Revenues
|
|
|
|
|
|
||||||
United States
|
$
|
10,659
|
|
|
$
|
9,176
|
|
|
$
|
7,049
|
|
Algeria
|
1,596
|
|
|
1,249
|
|
|
1,103
|
|
|||
Other International
|
815
|
|
|
544
|
|
|
295
|
|
|||
Total sales revenues
|
$
|
13,070
|
|
|
$
|
10,969
|
|
|
$
|
8,447
|
|
|
December 31,
|
||||||
millions
|
2018
|
|
|
2017
|
|
||
Net Properties and Equipment
|
|
|
|
||||
United States
|
$
|
25,891
|
|
|
$
|
24,382
|
|
Algeria
|
808
|
|
|
965
|
|
||
Other International
(1)
|
1,916
|
|
|
2,104
|
|
||
Total net properties and equipment
|
$
|
28,615
|
|
|
$
|
27,451
|
|
(1)
|
Includes
$519 million
of capitalized costs related to the Mozambique LNG project at
December 31, 2018
.
|
SUPPLEMENTAL QUARTERLY INFORMATION (UNAUDITED)
|
Quarterly Financial Data
|
millions except per-share amounts
|
First
Quarter
|
|
|
Second
Quarter
|
|
|
Third
Quarter
|
|
|
Fourth
Quarter
|
|
||||
2018
|
|
|
|
|
|
|
|
||||||||
Sales revenues
|
$
|
3,026
|
|
|
$
|
3,168
|
|
|
$
|
3,607
|
|
|
$
|
3,269
|
|
Gains (losses) on divestitures and other, net
|
19
|
|
|
123
|
|
|
90
|
|
|
80
|
|
||||
Impairments
|
19
|
|
|
128
|
|
|
172
|
|
|
481
|
|
||||
Operating income (loss)
|
551
|
|
|
819
|
|
|
979
|
|
|
270
|
|
||||
Net income (loss)
|
174
|
|
|
17
|
|
|
427
|
|
|
134
|
|
||||
Net income (loss) attributable to noncontrolling interests
|
53
|
|
|
(12
|
)
|
|
64
|
|
|
32
|
|
||||
Net income (loss) attributable to common stockholders
|
121
|
|
|
29
|
|
|
363
|
|
|
102
|
|
||||
Earnings per share
|
|
|
|
|
|
|
|
||||||||
Net income (loss) attributable to common stockholders—basic
|
$
|
0.23
|
|
|
$
|
0.05
|
|
|
$
|
0.72
|
|
|
$
|
0.21
|
|
Net income (loss) attributable to common stockholders—diluted
|
$
|
0.22
|
|
|
$
|
0.05
|
|
|
$
|
0.72
|
|
|
$
|
0.21
|
|
Average number common shares outstanding—basic
|
518
|
|
|
504
|
|
|
499
|
|
|
493
|
|
||||
Average number common shares outstanding—diluted
|
519
|
|
|
505
|
|
|
500
|
|
|
494
|
|
||||
|
|
|
|
|
|
|
|
||||||||
2017
|
|
|
|
|
|
|
|
||||||||
Sales revenues
|
$
|
2,898
|
|
|
$
|
2,419
|
|
|
$
|
2,610
|
|
|
$
|
3,042
|
|
Gains (losses) on divestitures and other, net
|
869
|
|
|
297
|
|
|
(114
|
)
|
|
(113
|
)
|
||||
Impairments
|
373
|
|
|
10
|
|
|
—
|
|
|
25
|
|
||||
Operating income (loss)
|
(100
|
)
|
|
(67
|
)
|
|
(749
|
)
|
|
351
|
|
||||
Net income (loss)
(1)
|
(275
|
)
|
|
(334
|
)
|
|
(641
|
)
|
|
1,039
|
|
||||
Net income (loss) attributable to noncontrolling interests
|
43
|
|
|
81
|
|
|
58
|
|
|
63
|
|
||||
Net income (loss) attributable to common stockholders
|
(318
|
)
|
|
(415
|
)
|
|
(699
|
)
|
|
976
|
|
||||
Earnings per share
|
|
|
|
|
|
|
|
||||||||
Net income (loss) attributable to common stockholders—basic
|
$
|
(0.58
|
)
|
|
$
|
(0.76
|
)
|
|
$
|
(1.27
|
)
|
|
$
|
1.80
|
|
Net income (loss) attributable to common stockholders—diluted
|
$
|
(0.58
|
)
|
|
$
|
(0.76
|
)
|
|
$
|
(1.27
|
)
|
|
$
|
1.80
|
|
Average number common shares outstanding—basic
|
551
|
|
|
552
|
|
|
553
|
|
|
537
|
|
||||
Average number common shares outstanding—diluted
|
551
|
|
|
552
|
|
|
553
|
|
|
537
|
|
(1)
|
Includes a one-time deferred tax benefit of $1.2 billion in the fourth quarter of 2017 related to the Tax Reform Legislation.
|
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION
AND PRODUCTION ACTIVITIES (UNAUDITED)
|
Oil and Gas Reserves
|
|
Oil
per Bbl
|
|
Natural Gas
per MMBtu
|
|
|
NGLs
per Bbl
|
|
||||
December 31, 2018
|
$
|
65.56
|
|
|
$
|
3.10
|
|
|
$
|
37.68
|
|
December 31, 2017
|
$
|
51.34
|
|
|
$
|
2.98
|
|
|
$
|
31.83
|
|
December 31, 2016
|
$
|
42.75
|
|
|
$
|
2.48
|
|
|
$
|
19.74
|
|
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION
AND PRODUCTION ACTIVITIES (UNAUDITED)
|
Oil and Gas Reserves (Continued)
|
|
Oil
(MMBbls)
|
|
Natural Gas
(Bcf)
|
||||||||||
|
United States
|
|
International
|
|
Total
|
|
|
United States
|
|
International
|
|
Total
|
|
Proved Reserves
|
|
|
|
|
|
|
|
||||||
December 31, 2015
|
525
|
|
188
|
|
713
|
|
|
5,991
|
|
30
|
|
6,021
|
|
Revisions of prior estimates
(1)
|
11
|
|
3
|
|
14
|
|
|
310
|
|
—
|
|
310
|
|
Extensions, discoveries, and other additions
|
24
|
|
—
|
|
24
|
|
|
59
|
|
—
|
|
59
|
|
Purchases in place
|
81
|
|
—
|
|
81
|
|
|
68
|
|
—
|
|
68
|
|
Sales in place
|
(14
|
)
|
—
|
|
(14
|
)
|
|
(1,263
|
)
|
—
|
|
(1,263
|
)
|
Production
|
(86
|
)
|
(30
|
)
|
(116
|
)
|
|
(766
|
)
|
(5
|
)
|
(771
|
)
|
December 31, 2016
|
541
|
|
161
|
|
702
|
|
|
4,399
|
|
25
|
|
4,424
|
|
Revisions of prior estimates
(1)
|
47
|
|
23
|
|
70
|
|
|
644
|
|
12
|
|
656
|
|
Extensions, discoveries, and other additions
|
72
|
|
5
|
|
77
|
|
|
119
|
|
6
|
|
125
|
|
Purchases in place
|
1
|
|
—
|
|
1
|
|
|
6
|
|
—
|
|
6
|
|
Sales in place
|
(63
|
)
|
—
|
|
(63
|
)
|
|
(1,514
|
)
|
—
|
|
(1,514
|
)
|
Production
|
(97
|
)
|
(32
|
)
|
(129
|
)
|
|
(461
|
)
|
(6
|
)
|
(467
|
)
|
December 31, 2017
|
501
|
|
157
|
|
658
|
|
|
3,193
|
|
37
|
|
3,230
|
|
Revisions of prior estimates
(1)
|
65
|
|
12
|
|
77
|
|
|
220
|
|
—
|
|
220
|
|
Extensions, discoveries, and other additions
|
104
|
|
—
|
|
104
|
|
|
190
|
|
—
|
|
190
|
|
Sales in place
|
(34
|
)
|
—
|
|
(34
|
)
|
|
(15
|
)
|
—
|
|
(15
|
)
|
Production
|
(107
|
)
|
(31
|
)
|
(138
|
)
|
|
(390
|
)
|
(5
|
)
|
(395
|
)
|
December 31, 2018
|
529
|
|
138
|
|
667
|
|
|
3,198
|
|
32
|
|
3,230
|
|
Proved Developed Reserves
|
|
|
|
|
|
|
|
||||||
December 31, 2015
|
332
|
|
159
|
|
491
|
|
|
5,184
|
|
30
|
|
5,214
|
|
December 31, 2016
|
360
|
|
147
|
|
507
|
|
|
3,637
|
|
25
|
|
3,662
|
|
December 31, 2017
|
361
|
|
136
|
|
497
|
|
|
2,640
|
|
24
|
|
2,664
|
|
December 31, 2018
|
392
|
|
123
|
|
515
|
|
|
2,564
|
|
24
|
|
2,588
|
|
Proved Undeveloped Reserves
|
|
|
|
|
|
|
|
||||||
December 31, 2015
|
193
|
|
29
|
|
222
|
|
|
807
|
|
—
|
|
807
|
|
December 31, 2016
|
181
|
|
14
|
|
195
|
|
|
762
|
|
—
|
|
762
|
|
December 31, 2017
|
140
|
|
21
|
|
161
|
|
|
553
|
|
13
|
|
566
|
|
December 31, 2018
|
137
|
|
15
|
|
152
|
|
|
634
|
|
8
|
|
642
|
|
(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
.
|
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION
AND PRODUCTION ACTIVITIES (UNAUDITED)
|
Oil and Gas Reserves (Continued)
|
|
NGLs
(MMBbls)
|
|
Total
(MMBOE)
|
||||||||||
|
United States
|
|
International
|
|
Total
|
|
|
United States
|
|
International
|
|
Total
|
|
Proved Reserves
|
|
|
|
|
|
|
|
||||||
December 31, 2015
|
325
|
|
15
|
|
340
|
|
|
1,849
|
|
208
|
|
2,057
|
|
Revisions of prior estimates
(1)
|
45
|
|
2
|
|
47
|
|
|
108
|
|
5
|
|
113
|
|
Extensions, discoveries, and other additions
|
6
|
|
—
|
|
6
|
|
|
40
|
|
—
|
|
40
|
|
Purchases in place
|
5
|
|
—
|
|
5
|
|
|
97
|
|
—
|
|
97
|
|
Sales in place
|
(69
|
)
|
—
|
|
(69
|
)
|
|
(294
|
)
|
—
|
|
(294
|
)
|
Production
|
(44
|
)
|
(2
|
)
|
(46
|
)
|
|
(258
|
)
|
(33
|
)
|
(291
|
)
|
December 31, 2016
|
268
|
|
15
|
|
283
|
|
|
1,542
|
|
180
|
|
1,722
|
|
Revisions of prior estimates
(1)
|
45
|
|
(2
|
)
|
43
|
|
|
199
|
|
23
|
|
222
|
|
Extensions, discoveries, and other additions
|
16
|
|
—
|
|
16
|
|
|
108
|
|
6
|
|
114
|
|
Purchases in place
|
1
|
|
—
|
|
1
|
|
|
3
|
|
—
|
|
3
|
|
Sales in place
|
(64
|
)
|
—
|
|
(64
|
)
|
|
(379
|
)
|
—
|
|
(379
|
)
|
Production
|
(34
|
)
|
(2
|
)
|
(36
|
)
|
|
(208
|
)
|
(35
|
)
|
(243
|
)
|
December 31, 2017
|
232
|
|
11
|
|
243
|
|
|
1,265
|
|
174
|
|
1,439
|
|
Revisions of prior estimates
(1)
|
34
|
|
1
|
|
35
|
|
|
136
|
|
13
|
|
149
|
|
Extensions, discoveries, and other additions
|
28
|
|
—
|
|
28
|
|
|
164
|
|
—
|
|
164
|
|
Purchases in place
|
—
|
|
—
|
|
—
|
|
|
—
|
|
—
|
|
—
|
|
Sales in place
|
—
|
|
—
|
|
—
|
|
|
(37
|
)
|
—
|
|
(37
|
)
|
Production
|
(36
|
)
|
(2
|
)
|
(38
|
)
|
|
(208
|
)
|
(34
|
)
|
(242
|
)
|
December 31, 2018
|
258
|
|
10
|
|
268
|
|
|
1,320
|
|
153
|
|
1,473
|
|
Proved Developed Reserves
|
|
|
|
|
|
|
|
||||||
December 31, 2015
|
257
|
|
15
|
|
272
|
|
|
1,453
|
|
179
|
|
1,632
|
|
December 31, 2016
|
193
|
|
15
|
|
208
|
|
|
1,159
|
|
166
|
|
1,325
|
|
December 31, 2017
|
176
|
|
10
|
|
186
|
|
|
977
|
|
150
|
|
1,127
|
|
December 31, 2018
|
192
|
|
10
|
|
202
|
|
|
1,011
|
|
137
|
|
1,148
|
|
Proved Undeveloped Reserves
|
|
|
|
|
|
|
|
||||||
December 31, 2015
|
68
|
|
—
|
|
68
|
|
|
396
|
|
29
|
|
425
|
|
December 31, 2016
|
75
|
|
—
|
|
75
|
|
|
383
|
|
14
|
|
397
|
|
December 31, 2017
|
56
|
|
1
|
|
57
|
|
|
288
|
|
24
|
|
312
|
|
December 31, 2018
|
66
|
|
—
|
|
66
|
|
|
309
|
|
16
|
|
325
|
|
(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
.
|
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION
AND PRODUCTION ACTIVITIES (UNAUDITED)
|
MMBOE
|
December 31, 2018
|
|
Revisions due to changes in year-end prices (price impact to opening balance)
|
29
|
|
Other revisions of prior estimates
|
|
|
Revisions due to performance
|
4
|
|
Revisions due to cost updates
|
(10
|
)
|
Revisions due to successful infill drilling
|
181
|
|
Revisions due to development plan updates
|
(51
|
)
|
Other revisions
|
(4
|
)
|
Total other revisions of prior estimates
|
120
|
|
Revisions of prior estimates
|
149
|
|
–
|
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.
|
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION
AND PRODUCTION ACTIVITIES (UNAUDITED)
|
MMBOE
|
December 31, 2017
|
|
Revisions due to changes in year-end prices (price impact to opening balance)
|
92
|
|
Other revisions of prior estimates
|
|
|
Revisions due to performance
|
60
|
|
Revisions due to cost reductions
|
(4
|
)
|
Revisions due to successful infill drilling
|
71
|
|
Revisions due to development plan updates
|
5
|
|
Other revisions
|
(2
|
)
|
Total other revisions of prior estimates
|
130
|
|
Revisions of prior estimates
|
222
|
|
–
|
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.
|
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION
AND PRODUCTION ACTIVITIES (UNAUDITED)
|
MMBOE
|
December 31, 2016
|
|
Revisions due to changes in year-end prices (price impact to opening balance)
|
(147
|
)
|
Other revisions of prior estimates
|
|
|
Revisions due to performance
|
74
|
|
Revisions due to cost reductions
|
100
|
|
Revisions due to successful infill drilling
|
69
|
|
Revisions due to development plan updates
|
(3
|
)
|
Other revisions
|
20
|
|
Total other revisions of prior estimates
|
260
|
|
Revisions of prior estimates
|
113
|
|
–
|
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, 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.
|
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION
AND PRODUCTION ACTIVITIES (UNAUDITED)
|
Capitalized Costs
|
millions
|
United States
|
|
International
|
|
|
Total
|
|
|||||
December 31, 2018
|
|
|
|
|
|
|
||||||
Capitalized
|
|
|
|
|
|
|
||||||
Unproved properties
|
|
$
|
1,453
|
|
|
$
|
214
|
|
|
$
|
1,667
|
|
Proved properties
|
|
43,945
|
|
|
5,978
|
|
|
49,923
|
|
|||
|
|
45,398
|
|
|
6,192
|
|
|
51,590
|
|
|||
Less accumulated DD&A
|
|
29,898
|
|
|
3,859
|
|
|
33,757
|
|
|||
Net capitalized costs
|
|
$
|
15,500
|
|
|
$
|
2,333
|
|
|
$
|
17,833
|
|
|
|
|
|
|
|
|
||||||
December 31, 2017
|
|
|
|
|
|
|
||||||
Capitalized
|
|
|
|
|
|
|
||||||
Unproved properties
|
|
$
|
2,099
|
|
|
$
|
284
|
|
|
$
|
2,383
|
|
Proved properties
|
|
40,969
|
|
|
5,773
|
|
|
46,742
|
|
|||
|
|
43,068
|
|
|
6,057
|
|
|
49,125
|
|
|||
Less accumulated DD&A
|
|
27,511
|
|
|
3,279
|
|
|
30,790
|
|
|||
Net capitalized costs
|
|
$
|
15,557
|
|
|
$
|
2,778
|
|
|
$
|
18,335
|
|
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION
AND PRODUCTION ACTIVITIES (UNAUDITED)
|
Costs Incurred in Oil and Gas Property Acquisition, Exploration, and Development
|
millions
|
United States
|
|
International
|
|
|
Total
|
|
|||||
Year Ended December 31, 2018
|
|
|
|
|
|
|
||||||
Property acquisitions
|
|
|
|
|
|
|
||||||
Unproved
|
|
$
|
202
|
|
|
$
|
—
|
|
|
$
|
202
|
|
Proved
|
|
43
|
|
|
—
|
|
|
43
|
|
|||
Exploration
|
|
491
|
|
|
78
|
|
|
569
|
|
|||
Development
|
|
3,624
|
|
|
129
|
|
|
3,753
|
|
|||
Total costs incurred
|
|
$
|
4,360
|
|
|
$
|
207
|
|
|
$
|
4,567
|
|
Year Ended December 31, 2017
|
|
|
|
|
|
|
||||||
Property acquisitions
|
|
|
|
|
|
|
||||||
Unproved
|
|
$
|
490
|
|
|
$
|
9
|
|
|
$
|
499
|
|
Proved
|
|
7
|
|
|
—
|
|
|
7
|
|
|||
Exploration
|
|
661
|
|
|
318
|
|
|
979
|
|
|||
Development
|
|
2,579
|
|
|
29
|
|
|
2,608
|
|
|||
Total costs incurred
|
|
$
|
3,737
|
|
|
$
|
356
|
|
|
$
|
4,093
|
|
Year Ended December 31, 2016
|
|
|
|
|
|
|
||||||
Property acquisitions
|
|
|
|
|
|
|
||||||
Unproved
|
|
$
|
178
|
|
|
$
|
9
|
|
|
$
|
187
|
|
Proved
|
|
2,498
|
|
|
—
|
|
|
2,498
|
|
|||
Exploration
|
|
398
|
|
|
433
|
|
|
831
|
|
|||
Development
|
|
1,780
|
|
|
337
|
|
|
2,117
|
|
|||
Total costs incurred
|
|
$
|
4,854
|
|
|
$
|
779
|
|
|
$
|
5,633
|
|
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION
AND PRODUCTION ACTIVITIES (UNAUDITED)
|
RESULTS OF OPERATIONS
|
millions
|
United States
|
|
International
|
|
|
Total
|
|
|||||
Year Ended December 31, 2018
|
|
|
|
|
|
|
||||||
Net revenues from production
|
|
|
|
|
|
|
||||||
Third-party sales
|
|
$
|
7,428
|
|
|
$
|
910
|
|
|
$
|
8,338
|
|
Sales to consolidated affiliates
|
|
1,643
|
|
|
1,501
|
|
|
3,144
|
|
|||
Gains (losses) on property dispositions
|
|
20
|
|
|
—
|
|
|
20
|
|
|||
Total revenues
|
|
9,091
|
|
|
2,411
|
|
|
11,502
|
|
|||
Oil and gas operating
|
|
906
|
|
|
247
|
|
|
1,153
|
|
|||
Production, property, and other taxes
|
|
355
|
|
|
405
|
|
|
760
|
|
|||
Oil and gas transportation
|
|
844
|
|
|
34
|
|
|
878
|
|
|||
Technical support and other
(1)
|
|
310
|
|
|
28
|
|
|
338
|
|
|||
Exploration expenses
|
|
417
|
|
|
42
|
|
|
459
|
|
|||
DD&A
|
|
3,198
|
|
|
601
|
|
|
3,799
|
|
|||
Impairments related to oil and gas properties
|
|
373
|
|
|
—
|
|
|
373
|
|
|||
Other operating expense
|
|
141
|
|
|
8
|
|
|
149
|
|
|||
Total expenses
|
|
6,544
|
|
|
1,365
|
|
|
7,909
|
|
|||
Results of operations before income taxes
|
|
2,547
|
|
|
1,046
|
|
|
3,593
|
|
|||
Income tax expense (benefit)
(2)
|
|
585
|
|
|
590
|
|
|
1,175
|
|
|||
Results of operations
|
|
$
|
1,962
|
|
|
$
|
456
|
|
|
$
|
2,418
|
|
(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.
|
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION
AND PRODUCTION ACTIVITIES (UNAUDITED)
|
RESULTS OF OPERATIONS (Continued)
|
millions
|
United States
|
International
|
|
Total
|
||||||||
Year Ended December 31, 2017
|
|
|
|
|
|
|
||||||
Net revenues from production
|
|
|
|
|
|
|
||||||
Third-party sales
|
|
$
|
5,429
|
|
|
$
|
710
|
|
|
$
|
6,139
|
|
Sales to consolidated affiliates
|
|
1,746
|
|
|
1,084
|
|
|
2,830
|
|
|||
Gains (losses) on property dispositions
|
|
520
|
|
|
13
|
|
|
533
|
|
|||
Total revenues
|
|
7,695
|
|
|
1,807
|
|
|
9,502
|
|
|||
Oil and gas operating
|
|
791
|
|
|
198
|
|
|
989
|
|
|||
Production, property, and other taxes
|
|
226
|
|
|
290
|
|
|
516
|
|
|||
Oil and gas transportation
|
|
881
|
|
|
33
|
|
|
914
|
|
|||
Technical support and other
(1)
|
|
342
|
|
|
17
|
|
|
359
|
|
|||
Exploration expenses
|
|
1,692
|
|
|
843
|
|
|
2,535
|
|
|||
DD&A
|
|
3,260
|
|
|
634
|
|
|
3,894
|
|
|||
Impairments related to oil and gas properties
|
|
229
|
|
|
—
|
|
|
229
|
|
|||
Other operating expense
|
|
106
|
|
|
108
|
|
|
214
|
|
|||
Total expenses
|
|
7,527
|
|
|
2,123
|
|
|
9,650
|
|
|||
Results of operations before income taxes
|
|
168
|
|
|
(316
|
)
|
|
(148
|
)
|
|||
Income tax expense (benefit)
(2)
|
|
62
|
|
|
191
|
|
|
253
|
|
|||
Results of operations
|
|
$
|
106
|
|
|
$
|
(507
|
)
|
|
$
|
(401
|
)
|
Year Ended December 31, 2016
|
|
|
|
|
|
|
||||||
Net revenues from production
|
|
|
|
|
|
|
||||||
Third-party sales
|
|
$
|
3,884
|
|
|
$
|
619
|
|
|
$
|
4,503
|
|
Sales to consolidated affiliates
|
|
1,871
|
|
|
779
|
|
|
2,650
|
|
|||
Gains (losses) on property dispositions
|
|
(855
|
)
|
|
(6
|
)
|
|
(861
|
)
|
|||
Total revenues
|
|
4,900
|
|
|
1,392
|
|
|
6,292
|
|
|||
Oil and gas operating
|
|
603
|
|
|
204
|
|
|
807
|
|
|||
Production, property, and other taxes
|
|
189
|
|
|
282
|
|
|
471
|
|
|||
Oil and gas transportation
|
|
964
|
|
|
38
|
|
|
1,002
|
|
|||
Technical support and other
(1)
|
|
317
|
|
|
22
|
|
|
339
|
|
|||
Exploration expenses
|
|
538
|
|
|
406
|
|
|
944
|
|
|||
DD&A
|
|
3,512
|
|
|
395
|
|
|
3,907
|
|
|||
Impairments related to oil and gas properties
|
|
55
|
|
|
—
|
|
|
55
|
|
|||
Other operating expense
|
|
62
|
|
|
49
|
|
|
111
|
|
|||
Total expenses
|
|
6,240
|
|
|
1,396
|
|
|
7,636
|
|
|||
Results of operations before income taxes
|
|
(1,340
|
)
|
|
(4
|
)
|
|
(1,344
|
)
|
|||
Income tax expense (benefit)
(2)
|
|
(491
|
)
|
|
155
|
|
|
(336
|
)
|
|||
Results of operations
|
|
$
|
(849
|
)
|
|
$
|
(159
|
)
|
|
$
|
(1,008
|
)
|
(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.
|
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION
AND PRODUCTION ACTIVITIES (UNAUDITED)
|
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
|
millions
|
United States
|
International
|
|
Total
|
||||||||
December 31, 2018
|
|
|
|
|
|
|
||||||
Future cash inflows
|
|
$
|
49,540
|
|
|
$
|
10,058
|
|
|
$
|
59,598
|
|
Future production costs
|
|
19,715
|
|
|
3,073
|
|
|
22,788
|
|
|||
Future development costs
|
|
5,216
|
|
|
444
|
|
|
5,660
|
|
|||
Future income tax expenses
|
|
4,868
|
|
|
2,728
|
|
|
7,596
|
|
|||
Future net cash flows
|
|
19,741
|
|
|
3,813
|
|
|
23,554
|
|
|||
10% annual discount for estimated timing of cash flows
|
|
5,606
|
|
|
806
|
|
|
6,412
|
|
|||
Standardized measure of discounted future net cash flows
|
|
$
|
14,135
|
|
|
$
|
3,007
|
|
|
$
|
17,142
|
|
December 31, 2017
|
|
|
|
|
|
|
||||||
Future cash inflows
|
|
$
|
38,909
|
|
|
$
|
8,741
|
|
|
$
|
47,650
|
|
Future production costs
|
|
16,947
|
|
|
3,164
|
|
|
20,111
|
|
|||
Future development costs
|
|
5,512
|
|
|
679
|
|
|
6,191
|
|
|||
Future income tax expenses
|
|
3,106
|
|
|
2,147
|
|
|
5,253
|
|
|||
Future net cash flows
|
|
13,344
|
|
|
2,751
|
|
|
16,095
|
|
|||
10% annual discount for estimated timing of cash flows
|
|
3,856
|
|
|
579
|
|
|
4,435
|
|
|||
Standardized measure of discounted future net cash flows
|
|
$
|
9,488
|
|
|
$
|
2,172
|
|
|
$
|
11,660
|
|
December 31, 2016
|
|
|
|
|
|
|
||||||
Future cash inflows
|
|
$
|
33,513
|
|
|
$
|
7,328
|
|
|
$
|
40,841
|
|
Future production costs
|
|
16,921
|
|
|
3,290
|
|
|
20,211
|
|
|||
Future development costs
|
|
7,292
|
|
|
566
|
|
|
7,858
|
|
|||
Future income tax expenses
|
|
2,606
|
|
|
1,408
|
|
|
4,014
|
|
|||
Future net cash flows
|
|
6,694
|
|
|
2,064
|
|
|
8,758
|
|
|||
10% annual discount for estimated timing of cash flows
|
|
1,658
|
|
|
470
|
|
|
2,128
|
|
|||
Standardized measure of discounted future net cash flows
|
|
$
|
5,036
|
|
|
$
|
1,594
|
|
|
$
|
6,630
|
|
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION
AND PRODUCTION ACTIVITIES (UNAUDITED)
|
Changes in Standardized Measure of Discounted Future Net Cash Flows
Relating to Proved Oil and Gas Reserves
|
millions
|
United States
|
|
International
|
|
|
Total
|
|
|||||
2018
|
|
|
|
|
|
|
||||||
Balance at January 1
|
|
$
|
9,488
|
|
|
$
|
2,172
|
|
|
$
|
11,660
|
|
Sales and transfers of oil and gas produced, net of production costs
|
|
(6,657
|
)
|
|
(1,703
|
)
|
|
(8,360
|
)
|
|||
Net changes in prices and production costs
|
|
3,847
|
|
|
2,351
|
|
|
6,198
|
|
|||
Changes in estimated future development costs
|
|
(1,957
|
)
|
|
124
|
|
|
(1,833
|
)
|
|||
Extensions, discoveries, additions, and improved recovery, less related costs
|
|
3,429
|
|
|
—
|
|
|
3,429
|
|
|||
Development costs incurred during the period
|
|
2,677
|
|
|
86
|
|
|
2,763
|
|
|||
Revisions of previous quantity estimates
|
|
4,023
|
|
|
329
|
|
|
4,352
|
|
|||
Purchases of minerals in place
|
|
5
|
|
|
—
|
|
|
5
|
|
|||
Sales of minerals in place
|
|
(417
|
)
|
|
—
|
|
|
(417
|
)
|
|||
Accretion of discount
|
|
1,161
|
|
|
382
|
|
|
1,543
|
|
|||
Net change in income taxes
|
|
(1,268
|
)
|
|
(461
|
)
|
|
(1,729
|
)
|
|||
Other
|
|
(196
|
)
|
|
(273
|
)
|
|
(469
|
)
|
|||
Balance at December 31
|
|
$
|
14,135
|
|
|
$
|
3,007
|
|
|
$
|
17,142
|
|
2017
|
|
|
|
|
|
|
||||||
Balance at January 1
|
|
$
|
5,036
|
|
|
$
|
1,594
|
|
|
$
|
6,630
|
|
Sales and transfers of oil and gas produced, net of production costs
|
|
(4,924
|
)
|
|
(1,260
|
)
|
|
(6,184
|
)
|
|||
Net changes in prices and production costs
|
|
5,116
|
|
|
1,591
|
|
|
6,707
|
|
|||
Changes in estimated future development costs
|
|
184
|
|
|
(92
|
)
|
|
92
|
|
|||
Extensions, discoveries, additions, and improved recovery, less related costs
|
|
1,478
|
|
|
98
|
|
|
1,576
|
|
|||
Development costs incurred during the period
|
|
1,304
|
|
|
6
|
|
|
1,310
|
|
|||
Revisions of previous quantity estimates
|
|
2,918
|
|
|
882
|
|
|
3,800
|
|
|||
Purchases of minerals in place
|
|
28
|
|
|
—
|
|
|
28
|
|
|||
Sales of minerals in place
|
|
(864
|
)
|
|
—
|
|
|
(864
|
)
|
|||
Accretion of discount
|
|
674
|
|
|
260
|
|
|
934
|
|
|||
Net change in income taxes
|
|
(416
|
)
|
|
(641
|
)
|
|
(1,057
|
)
|
|||
Other
|
|
(1,046
|
)
|
|
(266
|
)
|
|
(1,312
|
)
|
|||
Balance at December 31
|
|
$
|
9,488
|
|
|
$
|
2,172
|
|
|
$
|
11,660
|
|
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION
AND PRODUCTION ACTIVITIES (UNAUDITED)
|
Changes in Standardized Measure of Discounted Future Net Cash Flows
Relating to Proved Oil and Gas Reserves (Continued)
|
millions
|
United States
|
|
International
|
|
|
Total
|
|
|||||
2016
|
|
|
|
|
|
|
||||||
Balance at January 1
|
|
$
|
7,092
|
|
|
$
|
2,593
|
|
|
$
|
9,685
|
|
Sales and transfers of oil and gas produced, net of production costs
|
|
(3,678
|
)
|
|
(856
|
)
|
|
(4,534
|
)
|
|||
Net changes in prices and production costs
|
|
(1,953
|
)
|
|
(1,607
|
)
|
|
(3,560
|
)
|
|||
Changes in estimated future development costs
|
|
742
|
|
|
(126
|
)
|
|
616
|
|
|||
Extensions, discoveries, additions, and improved recovery, less related costs
|
|
429
|
|
|
—
|
|
|
429
|
|
|||
Development costs incurred during the period
|
|
1,223
|
|
|
203
|
|
|
1,426
|
|
|||
Revisions of previous quantity estimates
|
|
1,388
|
|
|
320
|
|
|
1,708
|
|
|||
Purchases of minerals in place
|
|
193
|
|
|
—
|
|
|
193
|
|
|||
Sales of minerals in place
|
|
(1,277
|
)
|
|
—
|
|
|
(1,277
|
)
|
|||
Accretion of discount
|
|
949
|
|
|
431
|
|
|
1,380
|
|
|||
Net change in income taxes
|
|
690
|
|
|
717
|
|
|
1,407
|
|
|||
Other
|
|
(762
|
)
|
|
(81
|
)
|
|
(843
|
)
|
|||
Balance at December 31
|
|
$
|
5,036
|
|
|
$
|
1,594
|
|
|
$
|
6,630
|
|
EVALUATION AND DISCLOSURE CONTROLS AND PROCEDURES
|
MANAGEMENT’S ANNUAL REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
|
ATTESTATION REPORT OF THE REGISTERED PUBLIC ACCOUNTING FIRM
|
CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING
|
PART III
|
PART IV
|
(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.
|
Exhibit
Number
|
|
Description
|
||
|
2
|
(i)
|
|
|
#
|
|
(ii)
|
|
|
|
3
|
(i)
|
|
|
|
|
(ii)
|
|
|
|
4
|
(i)
|
|
|
|
|
(ii)
|
|
|
|
|
(iii)
|
|
|
|
|
(iv)
|
|
|
|
|
(v)
|
|
|
|
|
(vi)
|
|
|
|
|
(vii)
|
|
|
|
|
(viii)
|
|
|
|
|
(ix)
|
|
|
|
|
(x)
|
|
|
|
|
(xi)
|
|
Exhibit
Number
|
|
Description
|
||
|
4
|
(xii)
|
|
|
|
|
(xiii)
|
|
|
|
|
(xiv)
|
|
|
|
|
(xv)
|
|
|
|
|
(xvi)
|
|
|
|
|
(xvii)
|
|
|
|
|
(xviii)
|
|
|
†
|
10
|
(i)
|
|
|
†
|
|
(ii)
|
|
|
†
|
|
(iii)
|
|
|
†
|
|
(iv)
|
|
|
†
|
|
(v)
|
|
|
†
|
|
(vi)
|
|
|
†
|
|
(vii)
|
|
|
†
|
|
(viii)
|
|
|
†
|
|
(ix)
|
|
|
†
|
|
(x)
|
|
|
†
|
|
(xi)
|
|
|
†
|
|
(xii)
|
|
|
†
|
|
(xiii)
|
|
|
†
|
|
(xiv)
|
|
|
†
|
|
(xv)
|
|
Exhibit
Number
|
|
Description
|
||
†
|
10
|
(xvi)
|
|
|
†
|
|
(xvii)
|
|
|
†
|
|
(xviii)
|
|
|
†
|
|
(xix)
|
|
|
†
|
|
(xx)
|
|
|
†
|
|
(xxi)
|
|
|
†
|
|
(xxii)
|
|
|
†
|
|
(xxiii)
|
|
|
†
|
|
(xxiv)
|
|
|
†
|
|
(xxv)
|
|
|
†
|
|
(xxvi)
|
|
|
†
|
|
(xxvii)
|
|
|
†
|
|
(xxviii)
|
|
|
†
|
|
(xxix)
|
|
|
†
|
|
(xxx)
|
|
|
†
|
|
(xxxi)
|
|
|
†
|
|
(xxxii)
|
|
|
†
|
|
(xxxiii)
|
|
|
†
|
|
(xxxiv)
|
|
|
†
|
|
(xxxv)
|
|
|
†
|
|
(xxxvi)
|
|
|
†
|
|
(xxxvii)
|
|
Exhibit
Number
|
|
Description
|
||
†
|
10
|
(xxxviii)
|
|
|
†
|
|
(xxxix)
|
|
|
†
|
|
(xl)
|
|
|
†
|
|
(xli)
|
|
|
†
|
|
(xlii)
|
|
|
†
|
|
(xliii)
|
|
|
†
|
|
(xliv)
|
|
|
†
|
|
(xlv)
|
|
|
†
|
|
(xlvi)
|
|
|
†
|
|
(xlvii)
|
|
|
†
|
|
(xlviii)
|
|
|
†
|
|
(xlix)
|
|
|
†
|
|
(l)
|
|
|
†
|
|
(li)
|
|
|
†
|
|
(lii)
|
|
|
|
|
(liii)
|
|
|
|
|
(liv)
|
|
|
|
|
(lv)
|
|
Exhibit
Number
|
|
Description
|
||
|
10
|
(lvi)
|
|
|
|
|
(lvii)
|
|
|
|
|
(lviii)
|
|
|
|
|
(lix)
|
|
|
†
|
|
(lx)
|
|
|
|
|
(lxi)
|
|
|
|
|
(lxii)
|
|
|
|
|
(lxiii)
|
|
|
*
|
21
|
|
|
|
*
|
23
|
(i)
|
|
|
*
|
23
|
(ii)
|
|
|
*
|
24
|
|
|
|
*
|
31
|
(i)
|
|
|
*
|
31
|
(ii)
|
|
|
**
|
32
|
|
|
|
*
|
99
|
|
|
|
*
|
101
|
.INS
|
|
XBRL Instance Document
|
*
|
101
|
.SCH
|
|
XBRL Schema Document
|
*
|
101
|
.CAL
|
|
XBRL Calculation Linkbase Document
|
*
|
101
|
.DEF
|
|
XBRL Definition Linkbase Document
|
*
|
101
|
.LAB
|
|
XBRL Label Linkbase Document
|
*
|
101
|
.PRE
|
|
XBRL Presentation Linkbase Document
|
†
|
Management contracts or compensatory plans or arrangements required to be filed pursuant to Item 15.
|
#
|
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.
|
SIGNATURES
|
|
|
|
ANADARKO PETROLEUM CORPORATION
|
|
|
|
|
February 14, 2019
|
By:
|
|
/s/ BENJAMIN M. FINK
|
|
|
|
Benjamin M. Fink
Executive Vice President, Finance and Chief Financial Officer |
Name and Signature
|
|
Title
|
|
|
|
(i) Principal executive officer and director:
|
|
|
|
|
|
/s/ R. A. WALKER
|
|
Chairman and Chief Executive Officer
|
R. A. Walker
|
|
|
|
|
|
(ii) Principal financial officer:
|
|
|
/s/ BENJAMIN M. FINK
|
|
Executive Vice President, Finance and Chief Financial Officer
|
Benjamin M. Fink
|
|
|
|
|
|
(iii) Principal accounting officer:
|
|
|
|
|
|
/s/ CHRISTOPHER O. CHAMPION
|
|
Senior Vice President, Chief Accounting Officer and Controller
|
Christopher O. Champion
|
|
|
|
|
|
(iv) Directors:*
|
|
|
ANTHONY R. CHASE
DAVID E. CONSTABLE
H. PAULETT EBERHART
CLAIRE S. FARLEY
PETER J. FLUOR
JOSEPH W. GORDER
JOHN R. GORDON
SEAN GOURLEY
MICHAEL K. GRIMM
MARK C. MCKINLEY
ERIC D. MULLINS
ALEXANDRA PRUNER
|
|
|
* Signed on behalf of each of these persons and on his own behalf:
|
By:
|
/s/ BENJAMIN M. FINK
|
|
|
Benjamin M. Fink, Attorney-in-Fact
|
|
LIST OF SUBSIDIARIES
(1)
|
|
At December 31, 2018
|
|
|
|
Name of Subsidiary
|
State, Province, or Country in Which Organized
|
Anadarko E&P Onshore LLC
(2)
|
Delaware
|
Anadarko Petroleum Corporation
(2)
|
Delaware
|
Anadarko Realty, LLC
|
Texas
|
APC Aviation, Inc.
|
Delaware
|
Anadarko Gathering Company LLC
(2)
|
Delaware
|
Springfield Pipeline LLC
|
Texas
|
Anadarko Energy Services Company
(2)
|
Delaware
|
Anadarko Algeria Company, LLC
(2)
|
Delaware
|
Anadarko Offshore Holding Company, LLC
|
Delaware
|
Anadarko Egypt Holdings Company
|
Delaware
|
Anadarko USH1 Corporation
(2)
|
Delaware
|
Anadarko Land Corp.
|
Nebraska
|
Upland Industries Corporation
|
Nebraska
|
Rock Springs Royalty Company LLC
|
Utah
|
Anadarko Holding Company
(2)
|
Utah
|
Anadarko Energy Marketing, Inc.
|
Delaware
|
Venezuela US SRL
|
Barbados
|
Anadarko Offshore Well Containment Company LLC
|
Delaware
|
Anadarko Venezuela LLC
|
Delaware
|
Anadarko Venezuela Company
|
Cayman Islands
|
Anadarko WCTP Company
(2)
|
Cayman Islands
|
Anadarko Global Funding 1 Company
|
Cayman Islands
|
APC International Holdings LLC
|
Delaware
|
Anadarko Moçambique Área 1, Limitada
|
Mozambique
|
Anadarko Worldwide Holdings C.V.
|
The Netherlands
|
Anadarko West Texas LLC
|
Delaware
|
Anadarko Ghana Mahogany-1 Company
|
Cayman Islands
|
Anadarko Midkiff/Chaney Dell LLC
|
Delaware
|
Anadarko Development Company
|
Cayman Islands
|
Anadarko China Holdings 2 Company
|
Cayman Islands
|
Anadarko Brazil Investment I LLC
|
Delaware
|
Anadarko Côte d'Ivoire Block 103 Company
|
Cayman Islands
|
Anadarko Côte d'Ivoire Company
|
Cayman Islands
|
Chipeta Processing LLC
|
Delaware
|
Mountain Gas Resources LLC
|
Delaware
|
Western Gas Resources, Inc.
(2)
|
Delaware
|
MIGC LLC
|
Delaware
|
Anadarko Colombia Company
|
Cayman Islands
|
Anadarko Rockies LLC
|
Delaware
|
APC Midstream Holdings, LLC
|
Delaware
|
Delaware Basin Midstream, LLC
(2)
|
Delaware
|
Kerr-McGee Corporation
(2)
|
Delaware
|
Kerr-McGee Worldwide Corporation
(2)
|
Delaware
|
Anadarko US Offshore LLC
(2)
|
Delaware
|
Anadarko Exploracao e Producao de Petroleo e Gas Natural Ltda.
|
Brazil
|
Kerr-McGee Oil & Gas Onshore LP
(2)
|
Delaware
|
Kerr-McGee Gathering LLC
(2)
|
Colorado
|
Kerr-McGee Energy Services Corporation
|
Delaware
|
KM BM-C-Seven Ltd.
(2)
|
Cayman Islands
|
Anadarko Global Funding II Ltd.
|
Bahama Islands
|
WGR Asset Holding Company LLC
|
Delaware
|
Western Gas Equity Partners, LP
|
Delaware
|
Western Gas Partners, LP
(2)
|
Delaware
|
Delaware Basin JV Gathering LLC
|
Delaware
|
WGR Operating, LP
(2)
|
Delaware
|
Anadarko Wattenberg Oil Complex LLC
|
Delaware
|
Anadarko Consolidated Holdings LLC
(2)
|
Delaware
|
Headwater II, LLC
|
Delaware
|
DBM Oil Services, LLC
|
Delaware
|
APC Water Holdings 1, LLC
|
Delaware
|
Anadarko Development Holding Limited
|
Gibraltar
|
Anadarko Global Energy S.a.r.l.
(2)
|
Luxembourg
|
Anadarko International Development S.a.r.l.
|
Luxembourg
|
Anadarko Uintah Midstream, LLC
|
Delaware
|
(1)
|
The names of certain subsidiaries have been omitted since, considered in the aggregate as a single subsidiary, they would not constitute a significant subsidiary, as of the end of the year covered by this report, as defined under the Securities and Exchange Commission Regulation S-X 210.1-02(w).
|
(2)
|
Subsidiary meets the conditions of a significant subsidiary under the Securities and Exchange Commission Regulation S-X 210.1-02(w).
|
/s/ KPMG LLP
|
|
Houston, Texas
|
February 14, 2019
|
Re:
|
Securities and Exchange Commission
|
|
Form 10-K of Anadarko Petroleum Corporation
|
|
Very truly yours,
|
|
|
|
|
|
MILLER AND LENTS
|
|
|
Texas Registered Engineering Firm No. F-1442
|
|
By:
|
/s/ ROBERT J. OBERST
|
|
|
Robert J. Oberst, P.E.
|
|
|
Chairman
|
|
/s/ R. A. WALKER
|
|
/s/ ANTHONY R. CHASE
|
R. A. Walker
|
|
Anthony R. Chase
|
|
|
|
/s/ DAVID E. CONSTABLE
|
|
/s/ H. PAULETT EBERHART
|
David E. Constable
|
|
H. Paulett Eberhart
|
|
|
|
/s/ CLAIRE S. FARLEY
|
|
/s/ PETER J. FLUOR
|
Claire S. Farley
|
|
Peter J. Fluor
|
|
|
|
/s/ JOSEPH W. GORDER
|
|
/s/ JOHN R. GORDON
|
Joseph W. Gorder
|
|
John R. Gordon
|
|
|
|
/s/ SEAN GOURLEY
|
|
/s/ MICHAEL K. GRIMM
|
Sean Gourley
|
|
Michael K. Grimm
|
|
|
|
/s/ MARK C. MCKINLEY
|
|
/s/ ERIC D. MULLINS
|
Mark C. McKinley
|
|
Eric D. Mullins
|
|
|
|
/s/ ALEXANDRA PRUNER
|
|
|
Alexandra Pruner
|
|
|
1.
|
I have reviewed this
annual
report on Form
10-K
of Anadarko Petroleum Corporation;
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
4.
|
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
|
a)
|
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
b)
|
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
|
c)
|
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
|
d)
|
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
|
5.
|
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
|
a)
|
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
|
b)
|
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
|
/s/ R. A. WALKER
|
R. A. Walker
|
Chairman and Chief Executive Officer
|
1.
|
I have reviewed this
annual
report on Form
10-K
of Anadarko Petroleum Corporation;
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
4.
|
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
|
a)
|
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
b)
|
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
|
c)
|
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
|
d)
|
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
|
5.
|
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
|
a)
|
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
|
b)
|
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
|
/s/ BENJAMIN M. FINK
|
Benjamin M. Fink
|
Executive Vice President, Finance and Chief Financial Officer
|
(1)
|
the
Annual
Report on Form
10-K
of the Company for the period ended
December 31, 2018
, as filed with the Securities and Exchange Commission on the date hereof (Report), fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
|
(2)
|
the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
|
February 14, 2019
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/s/ R. A. WALKER
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R. A. Walker
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Chairman and Chief Executive Officer
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February 14, 2019
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/s/ BENJAMIN M. FINK
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Benjamin M. Fink
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Executive Vice President, Finance and Chief Financial Officer
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Re:
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Procedures and Methods Review of Anadarko Petroleum Corporation
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Proved Reserves and Future Net Cash Flows As of December 31, 2018
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Very truly yours,
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MILLER AND LENTS, LTD.
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Texas Registered Engineering Firm No. F-1442
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By:
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/s/ ROBERT J. OBERST
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Robert J. Oberst, P.E.
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Chairman
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