☒
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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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41-0747868
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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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Title of each class
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Trading Symbol(s)
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Name of each exchange on which registered
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Common Stock, $0.625 par value
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APA
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New York Stock Exchange
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Common Stock, $0.625 par value
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APA
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Chicago Stock Exchange
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Common Stock, $0.625 par value
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APA
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Nasdaq Global Select Market
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7.75% Notes Due 2029
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APA/29
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New York Stock Exchange
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Aggregate market value of the voting and non-voting common equity held by non-affiliates of registrant as of June 28, 2019
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$
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10,891,448,883
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Number of shares of registrant’s common stock outstanding as of January 31, 2020
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377,316,159
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Item
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Page
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10.
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•
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the market prices of oil, natural gas, natural gas liquids (NGLs), and other products or services;
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•
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our commodity hedging arrangements;
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•
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the supply and demand for oil, natural gas, NGLs, and other products or services;
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•
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production and reserve levels;
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•
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drilling risks;
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•
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economic and competitive conditions;
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•
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the availability of capital resources;
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•
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capital expenditure and other contractual obligations;
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•
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currency exchange rates;
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•
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weather conditions;
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•
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inflation rates;
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•
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the availability of goods and services;
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•
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legislative, regulatory, or policy changes, including initiatives addressing the impact of global climate change or further regulating hydraulic fracturing, methane emissions, flaring, or water disposal;
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•
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our performance on environmental, social, and governance measures;
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•
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terrorism or cyberattacks;
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•
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occurrence of property acquisitions or divestitures;
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•
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the integration of acquisitions;
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•
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the securities or capital markets and related risks such as general credit, liquidity, market, and interest-rate risks; and
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•
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other factors disclosed under Items 1 and 2—Business and Properties—Estimated Proved Reserves and Future Net Cash Flows, Item 1A—Risk Factors, Item 7—Management’s Discussion and Analysis of Financial Condition and Results of Operations, Item 7A—Quantitative and Qualitative Disclosures About Market Risk and elsewhere in this Form 10-K.
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ITEMS 1 and 2.
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BUSINESS AND PROPERTIES
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Production
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Percentage
of Total
Production
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Production
Revenue
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Year-End
Estimated
Proved
Reserves
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Percentage
of Total
Estimated
Proved
Reserves
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Gross
Wells
Drilled
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Gross
Productive
Wells
Drilled
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||||||||
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(In MMboe)
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(In millions)
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(In MMboe)
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||||||||
United States
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102.2
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59
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%
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$
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2,763
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684
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68
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%
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240
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240
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Egypt(1)
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48.6
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28
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2,276
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192
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19
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64
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48
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North Sea(2)
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22.1
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13
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1,276
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135
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13
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11
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11
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Total
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172.9
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100
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%
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$
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6,315
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1,011
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100
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%
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315
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299
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(1)
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Apache’s operations in Egypt, excluding the impacts of a one-third noncontrolling interest, contributed 21 percent of 2019 production and accounted for 13 percent of year-end estimated proved reserves.
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(2)
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Sales volumes from the North Sea for 2019 were 21.8 MMboe. Sales volumes may vary from production volumes as a result of the timing of liftings in the Beryl field.
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•
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Over 2.9 million gross acres (1.8 million net acres) with exposure to numerous plays focused primarily in the Midland Basin, the Central Basin Platform/Northwest Shelf, and the Delaware Basin.
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•
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Estimated proved reserves of 665.8 MMboe at year-end 2019, representing 66 percent of the Company’s worldwide proved reserves.
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•
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In 2019, the Permian region averaged 11 rigs and drilled or participated in 232 wells, 206 of which were horizontal, with a 100 percent success rate.
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•
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Annual production of 254.3 Mboe/d increased 21 percent from 2018. Fourth-quarter 2019 production increased 13 percent from the prior sequential quarter and 22 percent from the fourth quarter of 2018, a reflection of the success of the Company’s Midland Basin oil-focused drilling program and production from its Alpine High field.
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•
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The Egypt region, which includes onshore conventional assets in Egypt’s Western Desert.
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•
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The North Sea region, which includes offshore assets based in the United Kingdom.
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Net Exploratory
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Net Development
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Total Net Wells
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|||||||||||||||||||||
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Productive
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Dry
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Total
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Productive
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Dry
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Total
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Productive
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Dry
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Total
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|||||||||
2019
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|||||||||
United States
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6.3
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—
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6.3
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181.0
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—
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181.0
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187.3
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—
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187.3
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Egypt
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8.5
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13.5
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22.0
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37.2
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1.5
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38.7
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45.7
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15.0
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60.7
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North Sea
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—
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—
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—
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8.4
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—
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8.4
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8.4
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—
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8.4
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Total
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14.8
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13.5
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28.3
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226.6
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1.5
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228.1
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241.4
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15.0
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256.4
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2018
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|||||||||
United States
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47.6
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5.3
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52.9
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188.9
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2.0
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190.9
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236.5
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7.3
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243.8
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Egypt
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28.2
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12.5
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40.7
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57.9
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0.5
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58.4
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86.1
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13.0
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99.1
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North Sea
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1.0
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0.5
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1.5
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6.3
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—
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6.3
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7.3
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0.5
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7.8
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Total
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76.8
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18.3
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95.1
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253.1
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2.5
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255.6
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329.9
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20.8
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350.7
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2017
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|||||||||
United States
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42.9
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4.3
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47.2
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101.5
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1.0
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102.5
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144.4
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5.3
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149.7
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Canada
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—
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1.0
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1.0
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0.2
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—
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0.2
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0.2
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1.0
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1.2
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Egypt
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13.7
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12.0
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25.7
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59.3
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3.0
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62.3
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73.0
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15.0
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88.0
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North Sea
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0.6
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1.9
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2.5
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6.4
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1.0
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7.4
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7.0
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2.9
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9.9
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Other International
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—
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0.5
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0.5
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—
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—
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—
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—
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0.5
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0.5
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Total
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57.2
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19.7
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76.9
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167.4
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5.0
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172.4
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224.6
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24.7
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249.3
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Oil
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Gas
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Total
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||||||||||||
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Gross
|
|
Net
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Gross
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Net
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Gross
|
|
Net
|
||||||
United States
|
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12,280
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|
|
8,035
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1,140
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|
820
|
|
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13,420
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|
|
8,855
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Egypt
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|
1,140
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|
|
1,080
|
|
|
115
|
|
|
110
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|
|
1,255
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|
|
1,190
|
|
North Sea
|
|
155
|
|
|
115
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|
20
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|
|
10
|
|
|
175
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|
|
125
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Total
|
|
13,575
|
|
|
9,230
|
|
|
1,275
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|
|
940
|
|
|
14,850
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|
|
10,170
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Domestic
|
|
12,280
|
|
|
8,035
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|
|
1,140
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|
|
820
|
|
|
13,420
|
|
|
8,855
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|
Foreign
|
|
1,295
|
|
|
1,195
|
|
|
135
|
|
|
120
|
|
|
1,430
|
|
|
1,315
|
|
Total
|
|
13,575
|
|
|
9,230
|
|
|
1,275
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|
|
940
|
|
|
14,850
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|
|
10,170
|
|
|
|
Production
|
|
Average Lease
Operating
Cost per Boe
|
|
Average Sales Price
|
|||||||||||||||||||
|
|
Oil
|
|
NGL
|
|
Gas
|
|
Oil
|
|
NGL
|
|
Gas
|
|||||||||||||
Year Ended December 31,
|
|
(MMbbls)
|
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(MMbbls)
|
|
(Bcf)
|
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(Per bbl)
|
|
(Per bbl)
|
|
(Per Mcf)
|
|||||||||||||
2019
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
United States
|
|
38.3
|
|
|
25.0
|
|
|
233.5
|
|
|
$
|
9.24
|
|
|
$
|
54.71
|
|
|
$
|
14.95
|
|
|
$
|
1.26
|
|
Egypt(1)
|
|
30.9
|
|
|
0.3
|
|
|
104.4
|
|
|
10.77
|
|
|
63.76
|
|
|
33.87
|
|
|
2.83
|
|
||||
North Sea(2)
|
|
18.2
|
|
|
0.6
|
|
|
19.9
|
|
|
16.75
|
|
|
65.10
|
|
|
36.83
|
|
|
4.48
|
|
||||
Total
|
|
87.4
|
|
|
25.9
|
|
|
357.8
|
|
|
10.62
|
|
|
60.05
|
|
|
15.74
|
|
|
1.90
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|
||||
2018
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
United States
|
|
38.3
|
|
|
21.0
|
|
|
216.5
|
|
|
$
|
10.01
|
|
|
$
|
59.36
|
|
|
$
|
26.28
|
|
|
$
|
2.12
|
|
Egypt(1)
|
|
34.2
|
|
|
0.3
|
|
|
119.3
|
|
|
8.71
|
|
|
70.09
|
|
|
39.17
|
|
|
2.84
|
|
||||
North Sea(2)
|
|
17.1
|
|
|
0.4
|
|
|
16.6
|
|
|
18.92
|
|
|
69.02
|
|
|
45.84
|
|
|
7.33
|
|
||||
Total
|
|
89.6
|
|
|
21.7
|
|
|
352.4
|
|
|
10.66
|
|
|
65.30
|
|
|
26.87
|
|
|
2.61
|
|
||||
2017
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
United States
|
|
33.4
|
|
|
17.8
|
|
|
143.9
|
|
|
$
|
8.92
|
|
|
$
|
48.40
|
|
|
$
|
16.14
|
|
|
$
|
2.56
|
|
Canada(3)
|
|
2.4
|
|
|
1.0
|
|
|
48.0
|
|
|
12.01
|
|
|
45.25
|
|
|
16.39
|
|
|
2.17
|
|
||||
Egypt(1)
|
|
35.5
|
|
|
0.3
|
|
|
141.0
|
|
|
6.85
|
|
|
53.57
|
|
|
36.79
|
|
|
2.80
|
|
||||
North Sea(2)
|
|
17.9
|
|
|
0.4
|
|
|
16.6
|
|
|
17.21
|
|
|
53.81
|
|
|
36.22
|
|
|
5.54
|
|
||||
Total
|
|
89.2
|
|
|
19.5
|
|
|
349.5
|
|
|
9.45
|
|
|
51.46
|
|
|
16.90
|
|
|
2.74
|
|
(1)
|
Includes production volumes attributable to a one-third noncontrolling interest in Egypt.
|
(2)
|
Sales volumes from the North Sea for 2019, 2018, and 2017 were 21.8 MMboe, 20.3 MMboe, and 21.2 MMboe, respectively. Sales volumes may vary from production volumes as a result of the timing of liftings in the Beryl field.
|
(3)
|
During the third quarter of 2017, Apache finalized the sale and complete exit of its Canadian operations.
|
|
|
Undeveloped Acreage
|
|
Developed Acreage
|
||||||||
|
|
Gross Acres
|
|
Net Acres
|
|
Gross Acres
|
|
Net Acres
|
||||
|
|
(in thousands)
|
||||||||||
United States
|
|
4,078
|
|
|
2,045
|
|
|
1,126
|
|
|
701
|
|
Egypt
|
|
3,604
|
|
|
3,604
|
|
|
1,518
|
|
|
1,430
|
|
North Sea
|
|
233
|
|
|
208
|
|
|
186
|
|
|
139
|
|
Other International
|
|
2,308
|
|
|
1,111
|
|
|
—
|
|
|
—
|
|
Total
|
|
10,223
|
|
|
6,968
|
|
|
2,830
|
|
|
2,270
|
|
|
|
Oil
|
|
NGL
|
|
Gas
|
|
Total
|
||||
|
|
(MMbbls)
|
|
(MMbbls)
|
|
(Bcf)
|
|
(MMboe)
|
||||
Proved Developed:
|
|
|
|
|
|
|
|
|
||||
United States
|
|
278
|
|
|
159
|
|
|
946
|
|
|
595
|
|
Egypt(1)
|
|
103
|
|
|
1
|
|
|
434
|
|
|
176
|
|
North Sea
|
|
102
|
|
|
2
|
|
|
106
|
|
|
122
|
|
Total Proved Developed
|
|
483
|
|
|
162
|
|
|
1,486
|
|
|
893
|
|
Proved Undeveloped:
|
|
|
|
|
|
|
|
|
||||
United States
|
|
47
|
|
|
23
|
|
|
115
|
|
|
89
|
|
Egypt(1)
|
|
11
|
|
|
—
|
|
|
25
|
|
|
15
|
|
North Sea
|
|
10
|
|
|
1
|
|
|
16
|
|
|
14
|
|
Total Proved Undeveloped
|
|
68
|
|
|
24
|
|
|
156
|
|
|
118
|
|
TOTAL PROVED
|
|
551
|
|
|
186
|
|
|
1,642
|
|
|
1,011
|
|
(1)
|
Includes total proved developed and total proved undeveloped reserves of 59 MMboe and 5 MMboe, respectively, attributable to a one-third noncontrolling interest in Egypt.
|
|
|
For the Year Ended December 31,
|
|||||||
|
|
2019
|
|
2018
|
|
2017
|
|||
BP plc(1)
|
|
10
|
%
|
|
17
|
%
|
|
12
|
%
|
China Petroleum & Chemical Corporation (Sinopec)(2)
|
|
11
|
%
|
|
15
|
%
|
|
16
|
%
|
Egyptian General Petroleum Corporation(3)
|
|
9
|
%
|
|
10
|
%
|
|
11
|
%
|
(1)
|
Sales to BP plc were reported as revenue in the Company’s U.S., Egypt, and North Sea upstream segments in the years ended 2019, 2018, and 2017.
|
(2)
|
Sales to Sinopec were reported as revenue in the Company’s Egypt upstream segment in the year ended 2019 and in the Company’s Egypt and North Sea upstream segments in the years ended 2018 and 2017.
|
(3)
|
Sales to EGPC were reported as revenue in the Company’s Egypt upstream segment in the years ended 2019, 2018, and 2017.
|
ITEM 1A.
|
RISK FACTORS
|
•
|
worldwide and domestic supplies of crude oil, natural gas, and NGLs;
|
•
|
actions taken by foreign oil and gas producing nations, including the Organization of the Petroleum Exporting Countries (OPEC);
|
•
|
political conditions and events (including instability, changes in governments, or armed conflict) in oil and gas producing regions;
|
•
|
the level of global crude oil and natural gas inventories;
|
•
|
the price and level of imported foreign crude oil, natural gas, and NGLs;
|
•
|
the price and availability of alternative fuels, including coal and biofuels;
|
•
|
the availability of pipeline capacity and infrastructure;
|
•
|
the availability of crude oil transportation and refining capacity;
|
•
|
weather conditions;
|
•
|
domestic and foreign governmental regulations and taxes; and
|
•
|
the overall economic environment.
|
•
|
limiting our financial condition, liquidity, and/or ability to fund planned capital expenditures and operations;
|
•
|
reducing the amount of crude oil, natural gas, and NGLs that we can produce economically;
|
•
|
causing us to delay or postpone some of our capital projects;
|
•
|
reducing our revenues, operating income, and cash flows;
|
•
|
limiting our access to sources of capital, such as equity and long-term debt;
|
•
|
reducing the carrying value of our oil and gas properties, resulting in additional non-cash impairments;
|
•
|
reducing the carrying value of our gathering, processing, and transmission facilities, resulting in additional impairments; or
|
•
|
reducing the carrying value of goodwill.
|
•
|
well blowouts, explosions, and cratering;
|
•
|
pipeline or other facility ruptures and spills;
|
•
|
fires;
|
•
|
formations with abnormal pressures;
|
•
|
equipment malfunctions;
|
•
|
hurricanes, storms, and/or cyclones, which could affect our operations in areas such as on and offshore the Gulf Coast and North Sea, and other natural and anthropogenic disasters and weather conditions; and
|
•
|
surface spillage and surface or ground water contamination from petroleum constituents, saltwater, or hydraulic fracturing chemical additives.
|
•
|
our production falls short of the hedged volumes;
|
•
|
there is a widening of price-basis differentials between delivery points for our production and the delivery point assumed in the hedge arrangement;
|
•
|
the counterparties to our hedging or other price risk management contracts fail to perform under those arrangements; or
|
•
|
an unexpected event materially impacts commodity prices.
|
•
|
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;
|
•
|
other adverse weather conditions; and
|
•
|
increases in the cost of or shortages or delays in the availability of drilling rigs and equipment.
|
•
|
historical production from the area compared with production from other areas;
|
•
|
the effects of regulations by governmental agencies, including changes to severance and excise taxes;
|
•
|
future operating costs and capital expenditures; and
|
•
|
workover and remediation costs.
|
•
|
general strikes and civil unrest;
|
•
|
the risk of war, acts of terrorism, expropriation and resource nationalization, and forced renegotiation or modification of existing contracts;
|
•
|
import and export regulations;
|
•
|
taxation policies, including royalty and tax increases and retroactive tax claims, and investment restrictions;
|
•
|
price control;
|
•
|
transportation regulations and tariffs;
|
•
|
constrained oil or natural gas markets dependent on demand in a single or limited geographical area;
|
•
|
exchange controls, currency fluctuations, devaluations, or other activities that limit or disrupt markets and restrict payments or the movement of funds;
|
•
|
laws and policies of the United States affecting foreign trade, including trade sanctions;
|
•
|
the effects of the U.K.’s withdrawal from the European Union, including any resulting instability in global financial markets or the value of foreign currencies such as the British pound;
|
•
|
the possibility of being subject to exclusive jurisdiction of foreign courts in connection with legal disputes relating to licenses to operate and concession rights in countries where we currently operate;
|
•
|
the possible inability to subject foreign persons, especially foreign oil ministries and national oil companies, to the jurisdiction of courts in the United States; and
|
•
|
difficulties in enforcing our rights against a governmental agency because of the doctrine of sovereign immunity and foreign sovereignty over international operations.
|
ITEM 1B.
|
UNRESOLVED STAFF COMMENTS
|
ITEM 3.
|
LEGAL PROCEEDINGS
|
ITEM 4.
|
MINE SAFETY DISCLOSURES
|
ITEM 5.
|
MARKET FOR THE REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES
|
|
|
2014
|
|
2015
|
|
2016
|
|
2017
|
|
2018
|
|
2019
|
||||||||||||
Apache Corporation
|
|
$
|
100.00
|
|
|
$
|
72.26
|
|
|
$
|
105.25
|
|
|
$
|
71.43
|
|
|
$
|
45.44
|
|
|
$
|
45.92
|
|
S&P 500 Index
|
|
100.00
|
|
|
101.38
|
|
|
113.51
|
|
|
138.29
|
|
|
132.23
|
|
|
173.86
|
|
||||||
Dow Jones U.S. Exploration & Production Index
|
|
100.00
|
|
|
76.27
|
|
|
94.94
|
|
|
96.18
|
|
|
79.09
|
|
|
88.10
|
|
ITEM 6.
|
SELECTED FINANCIAL DATA
|
|
|
As of or for the Year Ended December 31,
|
||||||||||||||||||
|
|
2019
|
|
2018
|
|
2017
|
|
2016
|
|
2015
|
||||||||||
|
|
(In millions, except per share amounts)
|
||||||||||||||||||
Income Statement Data
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Oil and gas production revenues
|
|
$
|
6,315
|
|
|
$
|
7,348
|
|
|
$
|
5,887
|
|
|
$
|
5,367
|
|
|
$
|
6,510
|
|
Net income (loss) from continuing operations attributable to common shareholders
|
|
(3,553
|
)
|
|
40
|
|
|
1,304
|
|
|
(1,372
|
)
|
|
(10,844
|
)
|
|||||
Net income (loss) from continuing operations per share:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Basic
|
|
(9.43
|
)
|
|
0.11
|
|
|
3.42
|
|
|
(3.62
|
)
|
|
(28.70
|
)
|
|||||
Diluted
|
|
(9.43
|
)
|
|
0.11
|
|
|
3.41
|
|
|
(3.62
|
)
|
|
(28.70
|
)
|
|||||
Cash dividends declared per common share
|
|
1.00
|
|
|
1.00
|
|
|
1.00
|
|
|
1.00
|
|
|
1.00
|
|
|||||
Balance Sheet Data
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Total assets
|
|
$
|
18,107
|
|
|
$
|
21,582
|
|
|
$
|
21,922
|
|
|
$
|
22,519
|
|
|
$
|
25,500
|
|
Long-term debt
|
|
8,555
|
|
|
8,093
|
|
|
7,934
|
|
|
8,544
|
|
|
8,716
|
|
|||||
Total equity
|
|
4,465
|
|
|
8,812
|
|
|
8,791
|
|
|
7,679
|
|
|
9,490
|
|
|||||
Common shares outstanding
|
|
376
|
|
|
375
|
|
|
381
|
|
|
379
|
|
|
378
|
|
ITEM 7.
|
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
|
•
|
Equivalent production from the Permian region, which accounts for 91 percent of Apache’s total U.S. production, increased 21 percent from 2018 to 2019 driven by the success of the Midland Basin oil-focused drilling program and production increases at its Alpine High field. The Permian region averaged 11 operated rigs during the year, drilling 233 gross wells.
|
•
|
The Egypt region’s gross equivalent production decreased 7 percent and net production decreased 11 percent from 2018 primarily a result of natural decline and fewer wells brought on-line during the period. The region continues to build and enhance its robust drilling inventory, supplemented with recent seismic acquisitions and new play concept evaluations, on both new and existing acreage.
|
•
|
The North Sea region averaged 3 rigs during 2019, drilling 11 gross development wells with a 100 percent success rate. During the year, the region averaged production of 61 Mboe/d and contributed $1.3 billion of revenues. Production increased 9 percent from 2018, primarily the result of production from the Garten field, which came on-line in November 2018.
|
•
|
The North Sea region’s Storr exploration discovery came on-line in the fourth quarter of 2019, and its second well at Garten came on-line in the first quarter of 2020. The first well at the Company’s Storr development is a high-rate gas condensate well that is tied back to existing infrastructure at the Beryl Alpha platform. The Garten #2 well encountered approximately 1,200 feet of net pay and compares favorably to the Garten #1 well, which came on-line in November 2018 with initial 30-day production rates of 13 Mb/d and 17 MMcf/d from 700 feet of net pay. Apache holds a 100 percent working interest in the Garten complex.
|
•
|
During 2019, the Company drilled an exploration well, the Maka Central-1, in Block 58 offshore Suriname and announced a significant oil discovery in January 2020. The well successfully tested the presence of hydrocarbons in multiple stacked targets in the upper Cretaceous-aged Campanian and Santonian intervals. The well confirmed 73 meters of oil pay and 50 meters of light oil and gas condensate pay, and appraisal planning is underway. The Company began drilling its second exploration well, Sapakara West-1, in January 2020. Following completion of the Sapakara West-1, the Company will drill a third, and likely a fourth exploration test in Block 58 during 2020.
|
•
|
In December 2019, Apache entered into a joint venture agreement to explore and develop Block 58 offshore Suriname. Under the terms of the agreement, Apache and Total S.A. will each hold a 50 percent working interest in Block 58, which comprises approximately 1.4 million acres in water depths ranging from less than 100 meters to more than 2,100 meters. In exchange for a 50 percent interest, Apache will receive various forms of consideration, including $5 billion of carry for its first $7.5 billion of appraisal and development capital and 25 percent carry on all appraisal and development capital beyond its first $7.5 billion. The Company also received $100 million at closing and $75 million in the first quarter of 2020 for reimbursement of 50 percent of all costs incurred on Block 58 to date. Apache will receive an additional $75 million upon achievement of first oil production. Apache will operate the drilling of the first three exploration wells in the block (and may operate a fourth), including the Maka Central-1 well, and subsequently transfer operatorship to Total.
|
•
|
Midcontinent/Gulf Coast Divestiture In the second quarter of 2019, Apache completed the sale of non-core, gas-weighted assets in the Woodford-SCOOP and STACK plays for aggregate cash proceeds of approximately $223 million. In the third quarter of 2019, Apache completed the sale of non-core, gas-weighted assets in the western Anadarko Basin of
|
•
|
U.S. Leasehold Divestitures & Other During 2019, the Company also completed the sale of certain other non-core producing assets, GPT assets, and leasehold acreage, primarily in the Permian region, in multiple transactions for total cash proceeds of $73 million.
|
•
|
Altus Transaction In the fourth quarter of 2018, the Company completed the previously announced agreement with Altus Midstream Company and its then wholly-owned subsidiary Altus Midstream LP (collectively, Altus). Altus owns gas gathering, processing, and transmission assets in the Permian Basin of West Texas, anchored by midstream contracts to service Apache’s production from its Alpine High resource play. Altus primarily generates revenue by providing fee-based natural gas gathering, compression, processing, and transmission services.
|
•
|
Altus Pipeline Options As part of the Altus transaction, Apache contributed options to acquire equity interests in five separate third-party pipeline projects to Altus Midstream LP and/or its subsidiaries. As of December 31, 2019, four of the five joint venture equity options had been exercised by Altus to acquire various ownership interests in the associated third-party pipeline limited liability entities.
|
•
|
U.S. and North Sea Divestitures During 2018, Apache completed the sale of certain non-core assets, primarily leasehold acreage in the U.S. and North Sea regions, in multiple transactions for total cash proceeds of approximately $138 million.
|
•
|
Canadian Operations On June 30, 2017, Apache completed the sale of its Canadian assets at Midale and House Mountain for total cash proceeds of approximately $228 million. In August of 2017, Apache completed the sale of its remaining Canadian operations for cash proceeds of approximately $478 million, effectively exiting operations in Canada.
|
•
|
U.S. Leasehold Divestitures During 2017, Apache completed the sale of certain non-core assets, primarily leasehold acreage in the Permian and Midcontinent/Gulf Coast regions, in multiple transactions for total cash proceeds of $798 million.
|
•
|
North Sea Gathering, Processing, and Transmission (GPT) Facility In November 2017, Apache completed the sale of its 30.28 percent interest in the Scottish Area Gas Evacuation (SAGE) gas plant and its 60.56 percent interest in the Beryl pipeline in the North Sea to Ancala Midstream Acquisitions Limited for cash proceeds of $134 million.
|
|
|
For the Year Ended December 31,
|
|||||||||||||||||||
|
|
2019
|
|
2018
|
|
2017
|
|||||||||||||||
|
|
$ Value
|
|
% Contribution
|
|
$ Value
|
|
% Contribution
|
|
$ Value
|
|
% Contribution
|
|||||||||
|
|
($ in millions)
|
|||||||||||||||||||
Total Oil Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
United States
|
|
$
|
2,098
|
|
|
40
|
%
|
|
$
|
2,271
|
|
|
39
|
%
|
|
$
|
1,616
|
|
|
35
|
%
|
Canada
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
110
|
|
|
3
|
%
|
|||
North America
|
|
2,098
|
|
|
40
|
%
|
|
2,271
|
|
|
39
|
%
|
|
1,726
|
|
|
38
|
%
|
|||
Egypt(1)
|
|
1,969
|
|
|
38
|
%
|
|
2,396
|
|
|
41
|
%
|
|
1,901
|
|
|
41
|
%
|
|||
North Sea
|
|
1,163
|
|
|
22
|
%
|
|
1,179
|
|
|
20
|
%
|
|
971
|
|
|
21
|
%
|
|||
International(1)
|
|
3,132
|
|
|
60
|
%
|
|
3,575
|
|
|
61
|
%
|
|
2,872
|
|
|
62
|
%
|
|||
Total(1)
|
|
$
|
5,230
|
|
|
100
|
%
|
|
$
|
5,846
|
|
|
100
|
%
|
|
$
|
4,598
|
|
|
100
|
%
|
Total Natural Gas Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
United States
|
|
$
|
293
|
|
|
43
|
%
|
|
$
|
458
|
|
|
50
|
%
|
|
$
|
368
|
|
|
38
|
%
|
Canada
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
104
|
|
|
11
|
%
|
|||
North America
|
|
293
|
|
|
43
|
%
|
|
458
|
|
|
50
|
%
|
|
472
|
|
|
49
|
%
|
|||
Egypt(1)
|
|
295
|
|
|
44
|
%
|
|
339
|
|
|
37
|
%
|
|
395
|
|
|
41
|
%
|
|||
North Sea
|
|
90
|
|
|
13
|
%
|
|
122
|
|
|
13
|
%
|
|
92
|
|
|
10
|
%
|
|||
International(1)
|
|
385
|
|
|
57
|
%
|
|
461
|
|
|
50
|
%
|
|
487
|
|
|
51
|
%
|
|||
Total(1)
|
|
$
|
678
|
|
|
100
|
%
|
|
$
|
919
|
|
|
100
|
%
|
|
$
|
959
|
|
|
100
|
%
|
Total NGL Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
United States
|
|
$
|
372
|
|
|
91
|
%
|
|
$
|
550
|
|
|
94
|
%
|
|
$
|
287
|
|
|
87
|
%
|
Canada
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
17
|
|
|
5
|
%
|
|||
North America
|
|
372
|
|
|
91
|
%
|
|
550
|
|
|
94
|
%
|
|
304
|
|
|
92
|
%
|
|||
Egypt(1)
|
|
12
|
|
|
3
|
%
|
|
13
|
|
|
2
|
%
|
|
11
|
|
|
3
|
%
|
|||
North Sea
|
|
23
|
|
|
6
|
%
|
|
20
|
|
|
4
|
%
|
|
15
|
|
|
5
|
%
|
|||
International(1)
|
|
35
|
|
|
9
|
%
|
|
33
|
|
|
6
|
%
|
|
26
|
|
|
8
|
%
|
|||
Total(1)
|
|
$
|
407
|
|
|
100
|
%
|
|
$
|
583
|
|
|
100
|
%
|
|
$
|
330
|
|
|
100
|
%
|
Total Oil and Gas Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
United States
|
|
$
|
2,763
|
|
|
44
|
%
|
|
$
|
3,279
|
|
|
45
|
%
|
|
$
|
2,271
|
|
|
39
|
%
|
Canada
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
231
|
|
|
4
|
%
|
|||
North America
|
|
2,763
|
|
|
44
|
%
|
|
3,279
|
|
|
45
|
%
|
|
2,502
|
|
|
43
|
%
|
|||
Egypt(1)
|
|
2,276
|
|
|
36
|
%
|
|
2,748
|
|
|
37
|
%
|
|
2,307
|
|
|
39
|
%
|
|||
North Sea
|
|
1,276
|
|
|
20
|
%
|
|
1,321
|
|
|
18
|
%
|
|
1,078
|
|
|
18
|
%
|
|||
International(1)
|
|
3,552
|
|
|
56
|
%
|
|
4,069
|
|
|
55
|
%
|
|
3,385
|
|
|
57
|
%
|
|||
Total(1)
|
|
$
|
6,315
|
|
|
100
|
%
|
|
$
|
7,348
|
|
|
100
|
%
|
|
$
|
5,887
|
|
|
100
|
%
|
(1)
|
Amounts include revenue attributable to a noncontrolling interest in Egypt.
|
|
|
For the Year Ended December 31,
|
|||||||||||
|
|
2019
|
|
Increase
(Decrease)
|
|
2018
|
|
Increase
(Decrease)
|
|
2017
|
|||
Oil Volume – b/d:
|
|
|
|
|
|
|
|
|
|
|
|||
United States
|
|
105,051
|
|
|
—
|
|
104,800
|
|
|
15%
|
|
91,489
|
|
Canada
|
|
—
|
|
|
—
|
|
—
|
|
|
—
|
|
6,643
|
|
North America
|
|
105,051
|
|
|
—
|
|
104,800
|
|
|
7%
|
|
98,132
|
|
Egypt(1)(2)
|
|
84,617
|
|
|
(10)%
|
|
93,656
|
|
|
(4)%
|
|
97,242
|
|
North Sea
|
|
49,746
|
|
|
6%
|
|
46,953
|
|
|
(4)%
|
|
48,889
|
|
International
|
|
134,363
|
|
|
(4)%
|
|
140,609
|
|
|
(4)%
|
|
146,131
|
|
Total
|
|
239,414
|
|
|
(2)%
|
|
245,409
|
|
|
—
|
|
244,263
|
|
Natural Gas Volume – Mcf/d:
|
|
|
|
|
|
|
|
|
|
|
|||
United States
|
|
639,580
|
|
|
8%
|
|
593,254
|
|
|
50%
|
|
394,366
|
|
Canada
|
|
—
|
|
|
—
|
|
—
|
|
|
—
|
|
131,479
|
|
North America
|
|
639,580
|
|
|
8%
|
|
593,254
|
|
|
13%
|
|
525,845
|
|
Egypt(1)(2)
|
|
285,972
|
|
|
(12)%
|
|
326,811
|
|
|
(15)%
|
|
386,194
|
|
North Sea
|
|
54,642
|
|
|
20%
|
|
45,466
|
|
|
—
|
|
45,521
|
|
International
|
|
340,614
|
|
|
(9)%
|
|
372,277
|
|
|
(14)%
|
|
431,715
|
|
Total
|
|
980,194
|
|
|
2%
|
|
965,531
|
|
|
1%
|
|
957,560
|
|
NGL Volume – b/d:
|
|
|
|
|
|
|
|
|
|
|
|||
United States
|
|
68,381
|
|
|
19%
|
|
57,451
|
|
|
18%
|
|
48,674
|
|
Canada
|
|
—
|
|
|
—
|
|
—
|
|
|
—
|
|
2,827
|
|
North America
|
|
68,381
|
|
|
19%
|
|
57,451
|
|
|
12%
|
|
51,501
|
|
Egypt(1)(2)
|
|
931
|
|
|
1%
|
|
923
|
|
|
13%
|
|
816
|
|
North Sea
|
|
1,739
|
|
|
46%
|
|
1,189
|
|
|
3%
|
|
1,149
|
|
International
|
|
2,670
|
|
|
26%
|
|
2,112
|
|
|
7%
|
|
1,965
|
|
Total
|
|
71,051
|
|
|
19%
|
|
59,563
|
|
|
11%
|
|
53,466
|
|
BOE per day:(3)
|
|
|
|
|
|
|
|
|
|
|
|||
United States
|
|
280,029
|
|
|
7%
|
|
261,126
|
|
|
27%
|
|
205,891
|
|
Canada
|
|
—
|
|
|
—
|
|
—
|
|
|
—
|
|
31,383
|
|
North America
|
|
280,029
|
|
|
7%
|
|
261,126
|
|
|
10%
|
|
237,274
|
|
Egypt(1)(2)
|
|
133,209
|
|
|
(11)%
|
|
149,048
|
|
|
(8)%
|
|
162,424
|
|
North Sea(4)
|
|
60,592
|
|
|
9%
|
|
55,719
|
|
|
(3)%
|
|
57,624
|
|
International
|
|
193,801
|
|
|
(5)%
|
|
204,767
|
|
|
(7)%
|
|
220,048
|
|
Total
|
|
473,830
|
|
|
2%
|
|
465,893
|
|
|
2%
|
|
457,322
|
|
(1)
|
Gross oil, natural gas, and NGL production in Egypt were as follows:
|
|
|
2019
|
|
|
|
2018
|
|
|
|
2017
|
|||
Oil (b/d)
|
|
193,886
|
|
|
|
|
206,378
|
|
|
|
|
198,335
|
|
Natural Gas (Mcf/d)
|
|
708,682
|
|
|
|
|
769,468
|
|
|
|
|
805,478
|
|
NGL (b/d)
|
|
1,722
|
|
|
|
|
1,502
|
|
|
|
|
1,353
|
|
(2)
|
Includes net production volumes per day attributable to a noncontrolling interest in Egypt of:
|
|
|
2019
|
|
|
|
2018
|
|
|
|
2017
|
|||
Oil (b/d)
|
|
28,220
|
|
|
|
|
31,240
|
|
|
|
|
32,461
|
|
Natural Gas (Mcf/d)
|
|
95,539
|
|
|
|
|
109,169
|
|
|
|
|
128,756
|
|
NGL (b/d)
|
|
310
|
|
|
|
|
308
|
|
|
|
|
272
|
|
(3)
|
The table shows production on a boe basis in which natural gas is converted to an equivalent barrel of oil based on a ratio of 6 Mcf to 1 bbl. This ratio is not reflective of the price ratio between the two products.
|
(4)
|
Average sales volumes from the North Sea were 59,797 boe/d, 55,568 boe/d, and 58,177 boe/d for 2019, 2018, and 2017, respectively. Sales volumes may vary from production volumes as a result of the timing of liftings in the Beryl field.
|
|
|
For the Year Ended December 31,
|
||||||||||||||
|
|
2019
|
|
Increase
(Decrease)
|
|
2018
|
|
Increase
(Decrease)
|
|
2017
|
||||||
Average Oil Price - Per barrel:
|
|
|
|
|
|
|
|
|
|
|
||||||
United States
|
|
$
|
54.71
|
|
|
(8)%
|
|
$
|
59.36
|
|
|
23%
|
|
$
|
48.40
|
|
Canada
|
|
—
|
|
|
—
|
|
—
|
|
|
—
|
|
45.25
|
|
|||
North America
|
|
54.71
|
|
|
(8)%
|
|
59.36
|
|
|
23%
|
|
48.18
|
|
|||
Egypt
|
|
63.76
|
|
|
(9)%
|
|
70.09
|
|
|
31%
|
|
53.57
|
|
|||
North Sea
|
|
65.10
|
|
|
(6)%
|
|
69.02
|
|
|
28%
|
|
53.81
|
|
|||
International
|
|
64.25
|
|
|
(8)%
|
|
69.73
|
|
|
30%
|
|
53.65
|
|
|||
Total
|
|
60.05
|
|
|
(8)%
|
|
65.30
|
|
|
27%
|
|
51.46
|
|
|||
Average Natural Gas Price - Per Mcf:
|
|
|
|
|
|
|
|
|
|
|
||||||
United States
|
|
$
|
1.26
|
|
|
(41)%
|
|
$
|
2.12
|
|
|
(17)%
|
|
$
|
2.56
|
|
Canada
|
|
—
|
|
|
—
|
|
—
|
|
|
—
|
|
2.17
|
|
|||
North America
|
|
1.26
|
|
|
(41)%
|
|
2.12
|
|
|
(14)%
|
|
2.46
|
|
|||
Egypt
|
|
2.83
|
|
|
—
|
|
2.84
|
|
|
1%
|
|
2.80
|
|
|||
North Sea
|
|
4.48
|
|
|
(39)%
|
|
7.33
|
|
|
32%
|
|
5.54
|
|
|||
International
|
|
3.09
|
|
|
(9)%
|
|
3.39
|
|
|
10%
|
|
3.09
|
|
|||
Total
|
|
1.90
|
|
|
(27)%
|
|
2.61
|
|
|
(5)%
|
|
2.74
|
|
|||
Average NGL Price - Per barrel:
|
|
|
|
|
|
|
|
|
|
|
||||||
United States
|
|
$
|
14.95
|
|
|
(43)%
|
|
$
|
26.28
|
|
|
63%
|
|
$
|
16.14
|
|
Canada
|
|
—
|
|
|
—
|
|
—
|
|
|
—
|
|
16.39
|
|
|||
North America
|
|
14.95
|
|
|
(43)%
|
|
26.28
|
|
|
63%
|
|
16.15
|
|
|||
Egypt
|
|
33.87
|
|
|
(14)%
|
|
39.17
|
|
|
6%
|
|
36.79
|
|
|||
North Sea
|
|
36.83
|
|
|
(20)%
|
|
45.84
|
|
|
27%
|
|
36.22
|
|
|||
International
|
|
35.80
|
|
|
(17)%
|
|
42.93
|
|
|
18%
|
|
36.46
|
|
|||
Total
|
|
15.74
|
|
|
(41)%
|
|
26.87
|
|
|
59%
|
|
16.90
|
|
•
|
North America has a common market. Most of the Company’s gas is sold on a monthly or daily basis at either monthly or daily index-based prices. The Company’s U.S. regions averaged $1.26 per Mcf in 2019, down from $2.12 per Mcf in 2018. Current year prices realized by Apache were negatively influenced by limited pipeline takeaway capacity from the Permian Basin that resulted in over supply at various locations in the basin.
|
•
|
In Egypt, our gas is sold to Egyptian General Petroleum Corporation (EGPC), primarily under an industry-pricing formula, a sliding scale based on Dated Brent crude oil with a minimum of $1.50 per MMBtu and a maximum of $2.65 per MMBtu,
|
•
|
Natural gas from the North Sea Beryl field is processed through the SAGE gas plant. The gas is sold to a third party at the St. Fergus entry point of the national grid on a National Balancing Point index price basis. The region averaged $4.48 per Mcf in 2019, a 39 percent decrease from an average of $7.33 per Mcf in 2018.
|
|
|
For the Year Ended December 31,
|
||||||||||
|
|
2019
|
|
2018
|
|
2017
|
||||||
|
|
(In millions)
|
||||||||||
Lease operating expenses
|
|
$
|
1,447
|
|
|
$
|
1,439
|
|
|
$
|
1,384
|
|
Gathering, processing, and transmission
|
|
306
|
|
|
348
|
|
|
195
|
|
|||
Taxes other than income
|
|
207
|
|
|
215
|
|
|
151
|
|
|||
Exploration
|
|
805
|
|
|
503
|
|
|
549
|
|
|||
General and administrative
|
|
406
|
|
|
431
|
|
|
395
|
|
|||
Transaction, reorganization, and separation
|
|
50
|
|
|
28
|
|
|
16
|
|
|||
Depreciation, depletion, and amortization:
|
|
|
|
|
|
|
||||||
Oil and gas property and equipment
|
|
2,512
|
|
|
2,265
|
|
|
2,136
|
|
|||
GPT assets
|
|
105
|
|
|
83
|
|
|
73
|
|
|||
Other assets
|
|
63
|
|
|
57
|
|
|
71
|
|
|||
Asset retirement obligation accretion
|
|
107
|
|
|
108
|
|
|
130
|
|
|||
Impairments
|
|
2,949
|
|
|
511
|
|
|
8
|
|
|||
Financing costs, net
|
|
462
|
|
|
478
|
|
|
397
|
|
|
|
For the Year Ended December 31,
|
||||||||||
|
|
2019
|
|
2018
|
|
2017
|
||||||
|
|
(In millions)
|
||||||||||
|
|
|
|
|
|
|
||||||
Third-party processing and transmission costs
|
|
$
|
250
|
|
|
$
|
294
|
|
|
$
|
179
|
|
Midstream service affiliate costs
|
|
134
|
|
|
77
|
|
|
15
|
|
|||
Upstream processing and transmission costs
|
|
384
|
|
|
371
|
|
|
194
|
|
|||
Midstream operating expenses
|
|
56
|
|
|
54
|
|
|
16
|
|
|||
Intersegment eliminations
|
|
(134
|
)
|
|
(77
|
)
|
|
(15
|
)
|
|||
Total Gathering, processing, and transmission
|
|
$
|
306
|
|
|
$
|
348
|
|
|
$
|
195
|
|
|
|
For the Year Ended December 31,
|
||||||||||
|
|
2019
|
|
2018
|
|
2017
|
||||||
|
|
(In millions)
|
||||||||||
Unproved leasehold impairments
|
|
$
|
619
|
|
|
$
|
214
|
|
|
$
|
246
|
|
Dry hole expense
|
|
57
|
|
|
137
|
|
|
183
|
|
|||
Geological and geophysical expense
|
|
59
|
|
|
55
|
|
|
47
|
|
|||
Exploration overhead and other
|
|
70
|
|
|
97
|
|
|
73
|
|
|||
Total Exploration
|
|
$
|
805
|
|
|
$
|
503
|
|
|
$
|
549
|
|
|
|
For the Year Ended December 31,
|
||||||||||
|
|
2019
|
|
2018
|
|
2017
|
||||||
|
|
(In millions)
|
||||||||||
Oil and gas proved property
|
|
$
|
1,484
|
|
|
$
|
328
|
|
|
$
|
—
|
|
GPT facilities
|
|
1,295
|
|
|
56
|
|
|
—
|
|
|||
Equity method investment
|
|
—
|
|
|
113
|
|
|
—
|
|
|||
Divested unproved properties and leasehold
|
|
149
|
|
|
10
|
|
|
—
|
|
|||
Inventory and other
|
|
21
|
|
|
4
|
|
|
8
|
|
|||
Total Impairments
|
|
$
|
2,949
|
|
|
$
|
511
|
|
|
$
|
8
|
|
|
|
For the Year Ended December 31,
|
||||||||||
|
|
2019
|
|
2018
|
|
2017
|
||||||
|
|
(In millions)
|
||||||||||
Interest expense
|
|
$
|
430
|
|
|
$
|
441
|
|
|
$
|
457
|
|
Amortization of debt issuance costs
|
|
7
|
|
|
9
|
|
|
9
|
|
|||
Capitalized interest
|
|
(37
|
)
|
|
(44
|
)
|
|
(51
|
)
|
|||
Loss on extinguishment of debt
|
|
75
|
|
|
94
|
|
|
1
|
|
|||
Interest income
|
|
(13
|
)
|
|
(22
|
)
|
|
(19
|
)
|
|||
Total Financing costs, net
|
|
$
|
462
|
|
|
$
|
478
|
|
|
$
|
397
|
|
•
|
maintain its current dividend;
|
•
|
retain cash flow to initiate progress on debt reduction goals;
|
•
|
allocate approximately $200 million to exploration; and
|
•
|
achieve flat-to-low single-digit corporate oil production growth, year-over-year.
|
•
|
16 percent in the Gulf Coast Express natural gas pipeline (GCX);
|
•
|
15 percent in the EPIC crude pipeline (EPIC);
|
•
|
26.7 percent in the Permian Highway natural gas pipeline (PHP); and
|
•
|
33 percent in the Shin Oak NGL pipeline (Shin Oak).
|
|
|
For the Year Ended December 31,
|
||||||||||
|
|
2019
|
|
2018
|
|
2017
|
||||||
|
|
(In millions)
|
||||||||||
Sources of Cash and Cash Equivalents:
|
|
|
|
|
|
|
||||||
Net cash provided by operating activities
|
|
$
|
2,867
|
|
|
$
|
3,777
|
|
|
$
|
2,428
|
|
Proceeds from Altus transaction
|
|
—
|
|
|
628
|
|
|
—
|
|
|||
Proceeds from asset divestitures, net of cash divested
|
|
718
|
|
|
138
|
|
|
1,419
|
|
|||
Fixed-rate debt borrowings
|
|
989
|
|
|
992
|
|
|
—
|
|
|||
Proceeds from Altus credit facility
|
|
396
|
|
|
—
|
|
|
—
|
|
|||
Redeemable noncontrolling interest - Altus Preferred Unit limited partners
|
|
611
|
|
|
—
|
|
|
—
|
|
|||
|
|
5,581
|
|
|
5,535
|
|
|
3,847
|
|
|||
Uses of Cash and Cash Equivalents:
|
|
|
|
|
|
|
||||||
Additions to oil and gas property(1)
|
|
$
|
2,594
|
|
|
$
|
3,190
|
|
|
$
|
2,052
|
|
Additions to Altus gathering, processing, and transmission facilities(1)
|
|
327
|
|
|
581
|
|
|
530
|
|
|||
Leasehold and property acquisitions
|
|
40
|
|
|
133
|
|
|
178
|
|
|||
Altus equity method interests
|
|
1,172
|
|
|
91
|
|
|
—
|
|
|||
Payments on fixed-rate debt
|
|
1,150
|
|
|
1,370
|
|
|
70
|
|
|||
Dividends paid
|
|
376
|
|
|
382
|
|
|
380
|
|
|||
Distributions to noncontrolling interest - Egypt
|
|
305
|
|
|
345
|
|
|
265
|
|
|||
Shares repurchased
|
|
—
|
|
|
305
|
|
|
—
|
|
|||
Other
|
|
84
|
|
|
92
|
|
|
81
|
|
|||
|
|
6,048
|
|
|
6,489
|
|
|
3,556
|
|
|||
Increase (decrease) in cash and cash equivalents
|
|
$
|
(467
|
)
|
|
$
|
(954
|
)
|
|
$
|
291
|
|
(1)
|
The table presents capital expenditures on a cash basis; therefore, the amounts may differ from those discussed elsewhere in this document, which include accruals.
|
|
|
At December 31,
|
||||||
|
|
2019
|
|
2018
|
||||
|
|
(In millions)
|
||||||
Cash and cash equivalents
|
|
$
|
247
|
|
|
$
|
714
|
|
Total debt
|
|
8,566
|
|
|
8,244
|
|
||
Equity
|
|
4,465
|
|
|
8,812
|
|
||
Available committed borrowing capacity
|
|
4,000
|
|
|
3,857
|
|
||
Available committed borrowing capacity - Altus
|
|
404
|
|
|
450
|
|
|
|
On-Balance Sheet
|
|
Off-Balance Sheet
|
|
|
||||||||||||||||||||||
Obligations by Period
|
|
Debt, at Face Value
|
|
Altus Credit Facility(1)
|
|
Interest Payments
|
|
Finance Leases(2)
|
|
Operating Leases(3)
|
|
Purchase Obligations(4)(5)
|
|
Total(6)
|
||||||||||||||
|
|
(In millions)
|
||||||||||||||||||||||||||
2020
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
401
|
|
|
$
|
13
|
|
|
$
|
165
|
|
|
$
|
152
|
|
|
$
|
731
|
|
2021
|
|
293
|
|
|
—
|
|
|
395
|
|
|
3
|
|
|
82
|
|
|
191
|
|
|
964
|
|
|||||||
2022
|
|
463
|
|
|
—
|
|
|
383
|
|
|
3
|
|
|
50
|
|
|
181
|
|
|
1,080
|
|
|||||||
2023
|
|
181
|
|
|
396
|
|
|
373
|
|
|
3
|
|
|
33
|
|
|
213
|
|
|
1,199
|
|
|||||||
2024
|
|
—
|
|
|
—
|
|
|
370
|
|
|
3
|
|
|
27
|
|
|
195
|
|
|
595
|
|
|||||||
Thereafter
|
|
7,280
|
|
|
—
|
|
|
5,339
|
|
|
37
|
|
|
32
|
|
|
910
|
|
|
13,598
|
|
|||||||
Total
|
|
$
|
8,217
|
|
|
$
|
396
|
|
|
$
|
7,261
|
|
|
$
|
62
|
|
|
$
|
389
|
|
|
$
|
1,842
|
|
|
$
|
18,167
|
|
(1)
|
Includes outstanding principal amounts at December 31, 2019. This table does not include future commitment fees, interest expense, or other fees on Altus’ credit facility because they are floating rate instruments, and management cannot determine with accuracy the timing of future loan advances, repayments, or future interest rates to be charged.
|
(2)
|
Amounts represent the Company’s undiscounted finance lease obligation related to physical power generators being leased on a one-year term with the right to purchase and a separate lease for the Company’s Midland, Texas regional office building.
|
(3)
|
Amounts represent future lease payments associated with oil and gas operations inclusive of amounts billable to partners and other working interest owners. Such payments may be capitalized as a component of oil and gas properties and subsequently depreciated, impaired, or written off as exploration expense.
|
(4)
|
Amounts represent any agreements to purchase goods or services that are enforceable and legally binding and that specify all significant terms. These include minimum commitments associated with take-or-pay contracts, NGL processing agreements, drilling work program commitments, and agreements to secure capacity rights on third-party pipelines. Amounts exclude certain product purchase obligations related to marketing and trading activities for which there are no minimum purchase requirements or the amounts are not fixed or determinable. Total costs incurred under take-or-pay and throughput obligations were $111 million, $132 million, and $134 million for 2019, 2018, and 2017, respectively.
|
(5)
|
Subsequent to December 31, 2019, Apache entered into an agreement to assign approximately $171 million of its firm transportation obligations beginning in March 2020.
|
(6)
|
This table does not include the Company’s liability for dismantlement, abandonment, and restoration costs of oil and gas properties or pension or postretirement benefit obligations. For additional information regarding these liabilities, please see Notes 8 and 12, respectively, in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Form 10-K.
|
ITEM 8.
|
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
|
ITEM 9.
|
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
|
ITEM 9A.
|
CONTROLS AND PROCEDURES
|
ITEM 9B.
|
OTHER INFORMATION
|
ITEM 10.
|
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
|
ITEM 11.
|
EXECUTIVE COMPENSATION
|
ITEM 12.
|
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
|
ITEM 13.
|
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
|
ITEM 14.
|
PRINCIPAL ACCOUNTING FEES AND SERVICES
|
ITEM 15.
|
EXHIBITS, FINANCIAL STATEMENT SCHEDULES
|
(a)
|
Documents included in this report:
|
1.
|
Financial Statements
|
Report of management on internal control over financial reporting
|
F-1
|
Report of independent registered public accounting firm
|
F-2
|
Report of independent registered public accounting firm
|
F-3
|
Statement of consolidated operations for each of the three years in the period ended December 31, 2019
|
F-6
|
Statement of consolidated comprehensive income (loss) for each of the three years in the period ended December 31, 2019
|
F-7
|
Statement of consolidated cash flows for each of the three years in the period ended December 31, 2019
|
F-8
|
Consolidated balance sheet as of December 31, 2019 and 2018
|
F-9
|
Statement of consolidated changes in equity and noncontrolling interest for each of the three years in the period ended December 31, 2019
|
F-10
|
Notes to consolidated financial statements
|
F-11
|
2.
|
Financial Statement Schedules
|
|
Financial statement schedules have been omitted because they are either not required, not applicable or the information required to be presented is included in the Company’s financial statements and related notes.
|
3.
|
Exhibits
|
EXHIBIT
NO.
|
|
DESCRIPTION
|
3.1
|
–
|
|
3.2
|
–
|
|
3.3
|
–
|
|
4.1
|
–
|
|
4.2
|
–
|
|
4.3
|
–
|
|
4.4
|
–
|
|
4.5
|
–
|
|
4.6
|
–
|
|
4.7
|
–
|
|
4.8
|
–
|
EXHIBIT
NO.
|
|
DESCRIPTION
|
4.9
|
–
|
|
4.10
|
–
|
|
4.11
|
–
|
|
4.12
|
–
|
|
4.13
|
–
|
|
4.14
|
–
|
|
*4.15
|
–
|
|
4.16
|
–
|
|
4.17
|
–
|
|
*4.18
|
–
|
|
4.19
|
–
|
|
*4.20
|
–
|
|
4.21
|
–
|
|
†4.22
|
–
|
|
†4.23
|
–
|
|
†4.24
|
–
|
|
*4.25
|
–
|
EXHIBIT
NO.
|
|
DESCRIPTION
|
*4.26
|
–
|
|
10.1
|
–
|
|
†10.2
|
–
|
|
†10.3
|
–
|
|
†10.4
|
–
|
|
†10.5
|
–
|
|
†10.6
|
–
|
|
†10.7
|
–
|
|
†10.8
|
–
|
|
†10.9
|
–
|
|
†10.10
|
–
|
|
†10.11
|
–
|
|
†10.12
|
–
|
|
*†10.13
|
–
|
|
†10.14
|
–
|
|
*†10.15
|
–
|
|
†10.16
|
–
|
|
†10.17
|
–
|
|
†10.18
|
–
|
EXHIBIT
NO.
|
|
DESCRIPTION
|
†10.19
|
–
|
|
†10.20
|
–
|
|
†10.21
|
–
|
|
†10.22
|
–
|
|
†10.23
|
–
|
|
†10.24
|
–
|
|
†10.25
|
–
|
|
†10.26
|
–
|
|
†10.27
|
–
|
|
†10.28
|
–
|
|
†10.29
|
–
|
|
†10.30
|
–
|
|
†10.31
|
–
|
|
†10.32
|
–
|
|
†10.33
|
–
|
|
†10.34
|
–
|
|
†10.35
|
–
|
|
†10.36
|
–
|
|
†10.37
|
–
|
EXHIBIT
NO.
|
|
DESCRIPTION
|
†10.38
|
–
|
|
†10.39
|
–
|
|
†10.40
|
–
|
|
†10.41
|
–
|
|
†10.42
|
–
|
|
†10.43
|
–
|
|
†10.44
|
–
|
|
†10.45
|
–
|
|
†10.46
|
–
|
|
†10.47
|
–
|
|
†10.48
|
–
|
|
†10.49
|
–
|
|
†10.50
|
–
|
|
†10.51
|
–
|
|
*†10.52
|
–
|
|
*†10.53
|
–
|
|
*†10.54
|
–
|
|
*†10.55
|
–
|
|
*†10.56
|
–
|
|
*†10.57
|
–
|
|
*†10.58
|
–
|
|
*21.1
|
–
|
|
*23.1
|
–
|
|
*23.2
|
–
|
* Filed herewith.
|
† Management contracts or compensatory plans or arrangements required to be filed herewith pursuant to Item 15 hereof.
|
ITEM 16.
|
FORM 10-K SUMMARY
|
Name
|
|
Title
|
|
Date
|
/s/ John J. Christmann IV
John J. Christmann IV
|
|
Director, Chief Executive Officer, and President
(principal executive officer)
|
|
February 27, 2020
|
/s/ Stephen J. Riney
Stephen J. Riney
|
|
Executive Vice President and Chief Financial Officer (principal financial officer)
|
|
February 27, 2020
|
/s/ Rebecca A. Hoyt
Rebecca A. Hoyt
|
|
Senior Vice President, Chief Accounting Officer, and Controller
(principal accounting officer)
|
|
February 27, 2020
|
/s/ Annell R. Bay
Annell R. Bay
|
|
Director
|
|
February 27, 2020
|
/s/ Juliet S. Ellis
Juliet S. Ellis |
|
Director
|
|
February 27, 2020
|
/s/ Chansoo Joung
Chansoo Joung |
|
Director
|
|
February 27, 2020
|
/s/ Rene R. Joyce
Rene R. Joyce |
|
Director
|
|
February 27, 2020
|
/s/ John E. Lowe
John E. Lowe
|
|
Director, Non-Executive Chairman of the Board
|
|
February 27, 2020
|
/s/ William C. Montgomery
William C. Montgomery
|
|
Director
|
|
February 27, 2020
|
/s/ Amy H. Nelson
Amy H. Nelson
|
|
Director
|
|
February 27, 2020
|
/s/ Daniel W. Rabun
Daniel W. Rabun
|
|
Director
|
|
February 27, 2020
|
/s/ Peter A. Ragauss
Peter A. Ragauss
|
|
Director
|
|
February 27, 2020
|
/s/ John J. Christmann IV
|
Chief Executive Officer and President
|
(principal executive officer)
|
|
/s/ Stephen J. Riney
|
Executive Vice President and Chief Financial Officer
|
(principal financial officer)
|
|
/s/ Rebecca A. Hoyt
|
Senior Vice President, Chief Accounting Officer and Controller
|
(principal accounting officer)
|
|
|
Depreciation, depletion and amortization and impairment of property and equipment
|
Description of
the Matter
|
|
At December 31, 2019, the carrying value of the Company’s property and equipment was $14,158 million, and depreciation, depletion and amortization (DD&A) expense was $2,680 million, and impairment expense was $2,949 million for the year then ended. As described in Note 1, the Company follows the successful efforts method of accounting for its oil and gas properties. DD&A of the cost of proved oil and gas properties is calculated using the unit-of-production method based on proved oil and gas reserves, as estimated by the Company’s internal reservoir engineers. When circumstances indicate that the carrying value of property and equipment may not be recoverable, the Company compares unamortized capitalized costs to the expected undiscounted pre-tax future cash flows for the associated assets. If the expected undiscounted pre-tax future cash flows are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value.
Proved oil and gas reserves are those quantities of natural gas, crude oil, condensate, and natural gas liquids, which by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. Additionally, the expected future cash flows used for impairment reviews and related fair value calculations are based on judgmental assessments of future production volumes from estimated oil and gas reserves. Significant judgment is required by the Company’s internal reservoir engineers in evaluating geological and engineering data when estimating oil and gas reserves. Estimating reserves also requires the selection of inputs, including oil and gas price assumptions, future operating and capital costs assumptions, and tax rates by jurisdiction, among others. Because of the complexity involved in estimating oil and gas reserves, management engaged independent petroleum engineers to audit the proved oil and gas reserve estimates prepared by the Company’s internal reservoir engineers for select properties as of December 31, 2019.
Auditing the Company’s DD&A and impairment calculations is complex because of the use of the work of the internal reservoir engineers and the independent petroleum engineers and the evaluation of management’s determination of the inputs described above used by the engineers in estimating oil and gas reserves.
|
|
|
|
How We
Addressed the Matter in Our Audit |
|
We obtained an understanding, evaluated the design, and tested the operating effectiveness of the Company’s controls over its process to calculate DD&A and impairment, including management’s controls over the completeness and accuracy of the financial data provided to the engineers for use in estimating oil and gas reserves.
Our audit procedures included, among others, evaluating the professional qualifications and objectivity of the Company’s internal reservoir engineers primarily responsible for overseeing the preparation of the reserve estimates and the independent petroleum engineers used to audit the proved oil and gas reserve estimates for select properties. In addition, in assessing whether we can use the work of the engineers, we evaluated the completeness and accuracy of the financial data and inputs described above used by the engineers in estimating oil and gas reserves by agreeing them to source documentation, and we identified and evaluated corroborative and contrary evidence. For proved undeveloped reserves, we evaluated management’s development plan for compliance with the SEC rule that undrilled locations are scheduled to be drilled within five years, unless specific circumstances justify a longer time, by assessing consistency of the development projections with the Company’s development plan and the availability of capital relative to the development plan. We also tested the mathematical accuracy of the DD&A and impairment calculations, including comparing the oil and gas reserve amounts used in the calculations to the Company’s reserve reports.
|
|
|
Accounting for asset retirement obligation for the North Sea segment
|
Description of
the Matter |
|
At December 31, 2019, the asset retirement obligation (ARO) balance totaled $1,858 million. As further described in Note 8, the Company’s ARO reflects the estimated present value of the amount of dismantlement, removal, site reclamation, and similar activities associated with the Company’s oil and gas properties and other long-lived assets. The estimation of the ARO related to the North Sea segment requires significant judgment given the magnitude of the expected retirement costs and higher estimation uncertainty related to the timing of settlements and settlement amounts.
Auditing the Company’s ARO for the North Sea segment is complex and highly judgmental because of the significant estimation required by management in determining the obligation. In particular, the estimate was sensitive to significant subjective assumptions such as retirement cost estimates and the estimated timing of settlements, which are both affected by expectations about future market and economic conditions.
|
How We
Addressed the Matter in Our Audit |
|
We obtained an understanding, evaluated the design, and tested the operating effectiveness of the Company’s internal controls over its ARO estimation process, including management’s review of the significant assumptions that have a material effect on the determination of the obligations. We also tested management’s controls over the completeness and accuracy of financial data used in the valuation.
To test the ARO for the North Sea segment, our audit procedures included, among others, assessing the significant assumptions and inputs used in the valuation, such as retirement cost estimates and timing of settlement assumptions. For example, we evaluated retirement cost estimates by comparing the Company’s estimates to recent offshore activities and costs. Additionally, we compared assumptions for the timing of settlements to production forecasts. We also involved our internal specialists in testing the underlying retirement cost estimates.
|
|
|
For the Year Ended December 31,
|
||||||||||
|
|
2019
|
|
2018
|
|
2017
|
||||||
|
|
(In millions, except per common share data)
|
||||||||||
REVENUES AND OTHER:
|
|
|
|
|
|
|
||||||
Oil and gas production revenues:
|
|
|
|
|
|
|
||||||
Oil revenues
|
|
$
|
5,230
|
|
|
$
|
5,846
|
|
|
$
|
4,598
|
|
Natural gas revenues
|
|
678
|
|
|
919
|
|
|
959
|
|
|||
Natural gas liquids revenues
|
|
407
|
|
|
583
|
|
|
330
|
|
|||
|
|
6,315
|
|
|
7,348
|
|
|
5,887
|
|
|||
Gain on divestitures
|
|
43
|
|
|
23
|
|
|
627
|
|
|||
Other
|
|
53
|
|
|
53
|
|
|
(91
|
)
|
|||
|
|
6,411
|
|
|
7,424
|
|
|
6,423
|
|
|||
OPERATING EXPENSES:
|
|
|
|
|
|
|
||||||
Lease operating expenses
|
|
1,447
|
|
|
1,439
|
|
|
1,384
|
|
|||
Gathering, processing, and transmission
|
|
306
|
|
|
348
|
|
|
195
|
|
|||
Taxes other than income
|
|
207
|
|
|
215
|
|
|
151
|
|
|||
Exploration
|
|
805
|
|
|
503
|
|
|
549
|
|
|||
General and administrative
|
|
406
|
|
|
431
|
|
|
395
|
|
|||
Transaction, reorganization, and separation
|
|
50
|
|
|
28
|
|
|
16
|
|
|||
Depreciation, depletion, and amortization
|
|
2,680
|
|
|
2,405
|
|
|
2,280
|
|
|||
Asset retirement obligation accretion
|
|
107
|
|
|
108
|
|
|
130
|
|
|||
Impairments
|
|
2,949
|
|
|
511
|
|
|
8
|
|
|||
Financing costs, net
|
|
462
|
|
|
478
|
|
|
397
|
|
|||
|
|
9,419
|
|
|
6,466
|
|
|
5,505
|
|
|||
NET INCOME (LOSS) BEFORE INCOME TAXES
|
|
(3,008
|
)
|
|
958
|
|
|
918
|
|
|||
Current income tax provision
|
|
660
|
|
|
894
|
|
|
595
|
|
|||
Deferred income tax provision (benefit)
|
|
14
|
|
|
(222
|
)
|
|
(1,180
|
)
|
|||
NET INCOME (LOSS) INCLUDING NONCONTROLLING INTERESTS
|
|
(3,682
|
)
|
|
286
|
|
|
1,503
|
|
|||
Net income attributable to noncontrolling interest - Egypt
|
|
167
|
|
|
245
|
|
|
199
|
|
|||
Net income (loss) attributable to noncontrolling interest - Altus
|
|
(334
|
)
|
|
1
|
|
|
—
|
|
|||
Net income attributable to Altus Preferred Unit limited partners
|
|
38
|
|
|
—
|
|
|
—
|
|
|||
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK
|
|
$
|
(3,553
|
)
|
|
$
|
40
|
|
|
$
|
1,304
|
|
|
|
|
|
|
|
|
||||||
NET INCOME (LOSS) PER COMMON SHARE:
|
|
|
|
|
|
|
||||||
Basic
|
|
$
|
(9.43
|
)
|
|
$
|
0.11
|
|
|
$
|
3.42
|
|
Diluted
|
|
$
|
(9.43
|
)
|
|
$
|
0.11
|
|
|
$
|
3.41
|
|
WEIGHTED-AVERAGE NUMBER OF COMMON SHARES OUTSTANDING:
|
|
|
|
|
|
|
||||||
Basic
|
|
377
|
|
|
382
|
|
|
381
|
|
|||
Diluted
|
|
377
|
|
|
384
|
|
|
383
|
|
|
|
For the Year Ended December 31,
|
||||||||||
|
|
2019
|
|
2018
|
|
2017
|
||||||
|
|
(In millions)
|
||||||||||
NET INCOME (LOSS) INCLUDING NONCONTROLLING INTERESTS
|
|
$
|
(3,682
|
)
|
|
$
|
286
|
|
|
$
|
1,503
|
|
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX:
|
|
|
|
|
|
|
||||||
Pension and postretirement benefit plan
|
|
13
|
|
|
—
|
|
|
7
|
|
|||
Currency translation adjustment
|
|
—
|
|
|
—
|
|
|
109
|
|
|||
Share of equity method interests other comprehensive loss
|
|
(1
|
)
|
|
—
|
|
|
—
|
|
|||
|
|
12
|
|
|
—
|
|
|
116
|
|
|||
COMPREHENSIVE INCOME (LOSS) INCLUDING NONCONTROLLING INTERESTS
|
|
(3,670
|
)
|
|
286
|
|
|
1,619
|
|
|||
Comprehensive income attributable to noncontrolling interest - Egypt
|
|
167
|
|
|
245
|
|
|
199
|
|
|||
Comprehensive income (loss) attributable to noncontrolling interest - Altus
|
|
(334
|
)
|
|
1
|
|
|
—
|
|
|||
Comprehensive income attributable to Altus Preferred Unit limited partners
|
|
38
|
|
|
—
|
|
|
—
|
|
|||
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK
|
|
$
|
(3,541
|
)
|
|
$
|
40
|
|
|
$
|
1,420
|
|
|
|
For the Year Ended December 31,
|
||||||||||
|
|
2019
|
|
2018
|
|
2017
|
||||||
|
|
(In millions)
|
||||||||||
CASH FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
|
||||||
Net income (loss) including noncontrolling interests
|
|
$
|
(3,682
|
)
|
|
$
|
286
|
|
|
$
|
1,503
|
|
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
|
|
|
|
|
|
|
||||||
Gain on divestitures
|
|
(43
|
)
|
|
(23
|
)
|
|
(627
|
)
|
|||
Exploratory dry hole expense and unproved leasehold impairments
|
|
676
|
|
|
351
|
|
|
429
|
|
|||
Depreciation, depletion, and amortization
|
|
2,680
|
|
|
2,405
|
|
|
2,280
|
|
|||
Asset retirement obligation accretion
|
|
107
|
|
|
108
|
|
|
130
|
|
|||
Impairments
|
|
2,949
|
|
|
511
|
|
|
8
|
|
|||
Provision for (benefit from) deferred income taxes
|
|
14
|
|
|
(222
|
)
|
|
(1,180
|
)
|
|||
Loss from extinguishment of debt
|
|
75
|
|
|
94
|
|
|
1
|
|
|||
Other
|
|
94
|
|
|
22
|
|
|
204
|
|
|||
Changes in operating assets and liabilities:
|
|
|
|
|
|
|
||||||
Receivables
|
|
133
|
|
|
150
|
|
|
(270
|
)
|
|||
Inventories
|
|
(41
|
)
|
|
(6
|
)
|
|
32
|
|
|||
Drilling advances
|
|
(21
|
)
|
|
(11
|
)
|
|
(128
|
)
|
|||
Deferred charges and other
|
|
51
|
|
|
83
|
|
|
(58
|
)
|
|||
Accounts payable
|
|
(5
|
)
|
|
77
|
|
|
63
|
|
|||
Accrued expenses
|
|
(84
|
)
|
|
5
|
|
|
4
|
|
|||
Deferred credits and noncurrent liabilities
|
|
(36
|
)
|
|
(53
|
)
|
|
37
|
|
|||
NET CASH PROVIDED BY OPERATING ACTIVITIES
|
|
2,867
|
|
|
3,777
|
|
|
2,428
|
|
|||
CASH FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
||||||
Additions to oil and gas property
|
|
(2,594
|
)
|
|
(3,190
|
)
|
|
(2,052
|
)
|
|||
Additions to Altus gathering, processing, and transmission (GPT) facilities
|
|
(327
|
)
|
|
(581
|
)
|
|
(530
|
)
|
|||
Leasehold and property acquisitions
|
|
(40
|
)
|
|
(133
|
)
|
|
(178
|
)
|
|||
Altus equity method interests
|
|
(1,172
|
)
|
|
(91
|
)
|
|
—
|
|
|||
Proceeds from sale of Canadian assets, net of cash divested
|
|
—
|
|
|
—
|
|
|
661
|
|
|||
Proceeds from sale of oil and gas properties and GPT, other
|
|
718
|
|
|
138
|
|
|
758
|
|
|||
Other, net
|
|
(31
|
)
|
|
(87
|
)
|
|
(75
|
)
|
|||
NET CASH USED IN INVESTING ACTIVITIES
|
|
(3,446
|
)
|
|
(3,944
|
)
|
|
(1,416
|
)
|
|||
CASH FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
||||||
Commercial paper, credit facilities and bank notes, net
|
|
—
|
|
|
—
|
|
|
—
|
|
|||
Proceeds from Altus credit facility
|
|
396
|
|
|
—
|
|
|
—
|
|
|||
Fixed rate debt borrowings
|
|
989
|
|
|
992
|
|
|
—
|
|
|||
Payments on fixed-rate debt
|
|
(1,150
|
)
|
|
(1,370
|
)
|
|
(70
|
)
|
|||
Proceeds from Altus transaction
|
|
—
|
|
|
628
|
|
|
—
|
|
|||
Distributions to noncontrolling interest - Egypt
|
|
(305
|
)
|
|
(345
|
)
|
|
(265
|
)
|
|||
Redeemable noncontrolling interest - Altus Preferred Unit limited partners
|
|
611
|
|
|
—
|
|
|
—
|
|
|||
Dividends paid
|
|
(376
|
)
|
|
(382
|
)
|
|
(380
|
)
|
|||
Treasury stock activity, net
|
|
2
|
|
|
(305
|
)
|
|
—
|
|
|||
Other
|
|
(55
|
)
|
|
(5
|
)
|
|
(6
|
)
|
|||
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES
|
|
112
|
|
|
(787
|
)
|
|
(721
|
)
|
|||
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
|
|
(467
|
)
|
|
(954
|
)
|
|
291
|
|
|||
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR
|
|
714
|
|
|
1,668
|
|
|
1,377
|
|
|||
CASH AND CASH EQUIVALENTS AT END OF PERIOD
|
|
$
|
247
|
|
|
$
|
714
|
|
|
$
|
1,668
|
|
SUPPLEMENTARY CASH FLOW DATA:
|
|
|
|
|
|
|
||||||
Interest paid, net of capitalized interest
|
|
$
|
394
|
|
|
$
|
402
|
|
|
$
|
405
|
|
Income taxes paid, net of refunds
|
|
$
|
649
|
|
|
$
|
867
|
|
|
$
|
516
|
|
|
|
December 31,
|
||||||
In millions except share and per-share amounts
|
|
2019
|
|
2018
|
||||
ASSETS
|
|
|
|
|
||||
CURRENT ASSETS:
|
|
|
|
|
||||
Cash and cash equivalents ($6 and $450 related to Altus VIE)
|
|
$
|
247
|
|
|
$
|
714
|
|
Receivables, net of allowance of $88 and $92
|
|
1,062
|
|
|
1,194
|
|
||
Other current assets (Note 5) ($5 and $7 related to Altus VIE)
|
|
652
|
|
|
779
|
|
||
|
|
1,961
|
|
|
2,687
|
|
||
PROPERTY AND EQUIPMENT:
|
|
|
|
|
||||
Oil and gas, on the basis of successful efforts accounting:
|
|
|
|
|
||||
Proved properties
|
|
40,540
|
|
|
42,345
|
|
||
Unproved properties and properties under development
|
|
666
|
|
|
1,435
|
|
||
Gathering, processing, and transmission facilities ($203 and $1,251 related to Altus VIE)
|
|
799
|
|
|
1,856
|
|
||
Other ($4 and nil related to Altus VIE)
|
|
1,140
|
|
|
1,120
|
|
||
|
|
43,145
|
|
|
46,756
|
|
||
Less: Accumulated depreciation, depletion, and amortization ($1 and $24 related to Altus VIE)
|
|
(28,987
|
)
|
|
(28,335
|
)
|
||
|
|
14,158
|
|
|
18,421
|
|
||
OTHER ASSETS:
|
|
|
|
|
||||
Equity method interests (Note 6) ($1,258 and $91 related to Altus VIE)
|
|
1,258
|
|
|
121
|
|
||
Deferred charges and other ($4 and $71 related to Altus VIE)
|
|
730
|
|
|
353
|
|
||
|
|
$
|
18,107
|
|
|
$
|
21,582
|
|
LIABILITIES, NONCONTROLLING INTEREST, AND EQUITY
|
|
|
|
|
||||
CURRENT LIABILITIES:
|
|
|
|
|
||||
Accounts payable
|
|
$
|
695
|
|
|
$
|
709
|
|
Current debt ($10 and nil related to Altus VIE)
|
|
11
|
|
|
151
|
|
||
Other current liabilities (Note 7) ($21 and $85 related to Altus VIE)
|
|
1,149
|
|
|
1,341
|
|
||
|
|
1,855
|
|
|
2,201
|
|
||
LONG-TERM DEBT (Note 9) ($396 and nil related to Altus VIE)
|
|
8,555
|
|
|
8,093
|
|
||
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
|
|
|
|
|
||||
Income taxes
|
|
346
|
|
|
391
|
|
||
Asset retirement obligation ($60 and $29 related to Altus VIE)
|
|
1,811
|
|
|
1,866
|
|
||
Other ($107 and nil related to Altus VIE)
|
|
520
|
|
|
219
|
|
||
|
|
2,677
|
|
|
2,476
|
|
||
COMMITMENTS AND CONTINGENCIES (Note 11)
|
|
|
|
|
||||
|
|
|
|
|
||||
REDEEMABLE NONCONTROLLING INTEREST - ALTUS PREFERRED UNIT LIMITED PARTNERS (Note 13)
|
|
555
|
|
|
—
|
|
||
|
|
|
|
|
||||
EQUITY:
|
|
|
|
|
||||
Common stock, $0.625 par, 860,000,000 shares authorized, 417,026,863 and 415,692,116 shares issued, respectively
|
|
261
|
|
|
260
|
|
||
Paid-in capital
|
|
11,769
|
|
|
12,106
|
|
||
Accumulated deficit
|
|
(5,601
|
)
|
|
(2,048
|
)
|
||
Treasury stock, at cost, 40,964,193 and 40,995,894 shares, respectively
|
|
(3,190
|
)
|
|
(3,192
|
)
|
||
Accumulated other comprehensive income
|
|
16
|
|
|
4
|
|
||
APACHE SHAREHOLDERS’ EQUITY
|
|
3,255
|
|
|
7,130
|
|
||
Noncontrolling interest - Egypt
|
|
1,137
|
|
|
1,275
|
|
||
Noncontrolling interest - Altus
|
|
73
|
|
|
407
|
|
||
TOTAL EQUITY
|
|
4,465
|
|
|
8,812
|
|
||
|
|
$
|
18,107
|
|
|
$
|
21,582
|
|
|
|
Redeemable Noncontrolling Interest - Altus Preferred Unit Limited Partners
|
|
|
Common
Stock
|
|
Paid-In
Capital
|
|
Accumulated Deficit
|
|
Treasury
Stock
|
|
Accumulated
Other
Comprehensive
Income (Loss)
|
|
APACHE
SHAREHOLDERS’
EQUITY
|
|
Noncontrolling
Interests
|
|
TOTAL
EQUITY
|
||||||||||||||||||
|
|
(In millions)
|
|
|
(In millions)
|
||||||||||||||||||||||||||||||||
BALANCE AT DECEMBER 31, 2016
|
|
$
|
—
|
|
|
|
$
|
258
|
|
|
$
|
12,364
|
|
|
$
|
(3,385
|
)
|
|
$
|
(2,887
|
)
|
|
$
|
(112
|
)
|
|
$
|
6,238
|
|
|
$
|
1,441
|
|
|
$
|
7,679
|
|
Net income attributable to common stock
|
|
—
|
|
|
|
—
|
|
|
—
|
|
|
1,304
|
|
|
—
|
|
|
—
|
|
|
1,304
|
|
|
—
|
|
|
1,304
|
|
|||||||||
Net income attributable to noncontrolling interest - Egypt
|
|
—
|
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
199
|
|
|
199
|
|
|||||||||
Distributions to noncontrolling interest - Egypt
|
|
—
|
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(265
|
)
|
|
(265
|
)
|
|||||||||
Pension & Postretirement benefit plans, net of tax
|
|
—
|
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
7
|
|
|
7
|
|
|
—
|
|
|
7
|
|
|||||||||
Common dividends ($1.00 per share)
|
|
—
|
|
|
|
—
|
|
|
(381
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(381
|
)
|
|
—
|
|
|
(381
|
)
|
|||||||||
Common stock activity, net
|
|
—
|
|
|
|
1
|
|
|
(40
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(39
|
)
|
|
—
|
|
|
(39
|
)
|
|||||||||
Compensation expense
|
|
—
|
|
|
|
—
|
|
|
174
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
174
|
|
|
—
|
|
|
174
|
|
|||||||||
Other
|
|
—
|
|
|
|
—
|
|
|
11
|
|
|
(7
|
)
|
|
—
|
|
|
109
|
|
|
113
|
|
|
—
|
|
|
113
|
|
|||||||||
BALANCE AT DECEMBER 31, 2017
|
|
$
|
—
|
|
|
|
$
|
259
|
|
|
$
|
12,128
|
|
|
$
|
(2,088
|
)
|
|
$
|
(2,887
|
)
|
|
$
|
4
|
|
|
$
|
7,416
|
|
|
$
|
1,375
|
|
|
$
|
8,791
|
|
Net income attributable to common stock
|
|
—
|
|
|
|
—
|
|
|
—
|
|
|
40
|
|
|
—
|
|
|
—
|
|
|
40
|
|
|
—
|
|
|
40
|
|
|||||||||
Net income attributable to noncontrolling interest - Egypt
|
|
—
|
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
245
|
|
|
245
|
|
|||||||||
Net income attributable to noncontrolling interest - Altus
|
|
—
|
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
1
|
|
|||||||||
Distributions to noncontrolling interest - Egypt
|
|
—
|
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(345
|
)
|
|
(345
|
)
|
|||||||||
Common dividends ($1.00 per share)
|
|
—
|
|
|
|
—
|
|
|
(380
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(380
|
)
|
|
—
|
|
|
(380
|
)
|
|||||||||
Common stock activity, net
|
|
—
|
|
|
|
1
|
|
|
(29
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(28
|
)
|
|
—
|
|
|
(28
|
)
|
|||||||||
Treasury stock activity, net
|
|
—
|
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(305
|
)
|
|
—
|
|
|
(305
|
)
|
|
—
|
|
|
(305
|
)
|
|||||||||
Proceeds from Altus transaction
|
|
—
|
|
|
|
—
|
|
|
222
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
222
|
|
|
406
|
|
|
628
|
|
|||||||||
Compensation expense
|
|
—
|
|
|
|
—
|
|
|
160
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
160
|
|
|
—
|
|
|
160
|
|
|||||||||
Other
|
|
—
|
|
|
|
—
|
|
|
5
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
5
|
|
|
—
|
|
|
5
|
|
|||||||||
BALANCE AT DECEMBER 31, 2018
|
|
$
|
—
|
|
|
|
$
|
260
|
|
|
$
|
12,106
|
|
|
$
|
(2,048
|
)
|
|
$
|
(3,192
|
)
|
|
$
|
4
|
|
|
$
|
7,130
|
|
|
$
|
1,682
|
|
|
$
|
8,812
|
|
Net loss attributable to common stock
|
|
—
|
|
|
|
—
|
|
|
—
|
|
|
(3,553
|
)
|
|
—
|
|
|
—
|
|
|
(3,553
|
)
|
|
—
|
|
|
(3,553
|
)
|
|||||||||
Net income attributable to noncontrolling interest - Egypt
|
|
—
|
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
167
|
|
|
167
|
|
|||||||||
Net loss attributable to noncontrolling interest - Altus
|
|
—
|
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(334
|
)
|
|
(334
|
)
|
|||||||||
Issuance of Altus Preferred Units
|
|
517
|
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||||
Net income attributable to Altus Preferred Unit limited partners
|
|
38
|
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||||
Distributions to noncontrolling interest - Egypt
|
|
—
|
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(305
|
)
|
|
(305
|
)
|
|||||||||
Pension & Postretirement benefit plans, net of tax
|
|
—
|
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
13
|
|
|
13
|
|
|
—
|
|
|
13
|
|
|||||||||
Common dividends ($1.00 per share)
|
|
—
|
|
|
|
—
|
|
|
(376
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(376
|
)
|
|
—
|
|
|
(376
|
)
|
|||||||||
Common stock activity, net
|
|
—
|
|
|
|
1
|
|
|
(22
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(21
|
)
|
|
—
|
|
|
(21
|
)
|
|||||||||
Compensation expense
|
|
—
|
|
|
|
—
|
|
|
61
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
61
|
|
|
—
|
|
|
61
|
|
|||||||||
Other
|
|
—
|
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2
|
|
|
(1
|
)
|
|
1
|
|
|
—
|
|
|
1
|
|
|||||||||
BALANCE AT DECEMBER 31, 2019
|
|
$
|
555
|
|
|
|
$
|
261
|
|
|
$
|
11,769
|
|
|
$
|
(5,601
|
)
|
|
$
|
(3,190
|
)
|
|
$
|
16
|
|
|
$
|
3,255
|
|
|
$
|
1,210
|
|
|
$
|
4,465
|
|
|
|
For the Year Ended December 31,
|
||||||||||
|
|
2019
|
|
2018
|
|
2017
|
||||||
|
|
(In millions)
|
||||||||||
Oil and gas proved property
|
|
$
|
1,484
|
|
|
$
|
328
|
|
|
$
|
—
|
|
GPT facilities
|
|
1,295
|
|
|
56
|
|
|
—
|
|
|||
Equity method investment
|
|
—
|
|
|
113
|
|
|
—
|
|
|||
Divested unproved properties and leasehold
|
|
149
|
|
|
10
|
|
|
—
|
|
|||
Inventory and other
|
|
21
|
|
|
4
|
|
|
8
|
|
|||
Total Impairments
|
|
$
|
2,949
|
|
|
$
|
511
|
|
|
$
|
8
|
|
|
|
2019
|
|
2018
|
|
2017
|
||||||
|
|
(In millions)
|
||||||||||
Allowance for doubtful accounts at beginning of year
|
|
$
|
92
|
|
|
$
|
84
|
|
|
$
|
93
|
|
Additional provisions for the year
|
|
3
|
|
|
9
|
|
|
4
|
|
|||
Uncollectible accounts written off net of recoveries
|
|
(7
|
)
|
|
(1
|
)
|
|
(13
|
)
|
|||
Allowance for doubtful accounts at end of year
|
|
$
|
88
|
|
|
$
|
92
|
|
|
$
|
84
|
|
|
|
For the Year Ended December 31,
|
||||||||||
|
|
2019
|
|
2018
|
|
2017
|
||||||
|
|
(In millions)
|
||||||||||
Proved Properties:
|
|
|
|
|
|
|
||||||
U.S.
|
|
$
|
1,484
|
|
|
$
|
265
|
|
|
$
|
—
|
|
Egypt
|
|
—
|
|
|
63
|
|
|
—
|
|
|||
Total Proved
|
|
$
|
1,484
|
|
|
$
|
328
|
|
|
$
|
—
|
|
Unproved Properties:
|
|
|
|
|
|
|
||||||
U.S.
|
|
$
|
760
|
|
|
$
|
96
|
|
|
$
|
244
|
|
Egypt
|
|
8
|
|
|
—
|
|
|
—
|
|
|||
North Sea
|
|
—
|
|
|
128
|
|
|
—
|
|
|||
Canada
|
|
—
|
|
|
—
|
|
|
2
|
|
|||
Total Unproved
|
|
$
|
768
|
|
|
$
|
224
|
|
|
$
|
246
|
|
|
|
For the Year Ended December 31,
|
||||||
|
|
2019
|
|
2018
|
||||
|
|
(In millions)
|
||||||
Oil and gas production revenues from customers
|
|
$
|
6,315
|
|
|
$
|
7,348
|
|
Less: oil and gas production revenues from non-customer(1)
|
|
(451
|
)
|
|
(652
|
)
|
||
Purchased oil and gas sales from customers(2)
|
|
176
|
|
|
357
|
|
||
Revenues from contracts with customers
|
|
$
|
6,040
|
|
|
$
|
7,053
|
|
(1)
|
Oil and gas production revenues from non-customer represents income taxes paid to the Arab Republic of Egypt by EGPC on behalf of the Company. Revenue and associated expenses related to such tax volumes are recorded as “Oil and gas production revenues” and “Current income tax provision,” respectively, in the Company’s statement of consolidated operations.
|
(2)
|
Purchased oil and gas sales represent proceeds from the sale of commodity volumes which were purchased from third parties to fulfill volume commitments. Proceeds and associated costs related to such volumes are both recorded as “Other” under “Revenues and Other” in the Company’s statement of consolidated operations. Associated purchase costs totaled $142 million and $340 million for the years ended December 31, 2019 and 2018, respectively.
|
|
|
2019
|
|
2018
|
|
2017
|
||||||
|
|
(In millions)
|
||||||||||
Balance at January 1
|
|
$
|
159
|
|
|
$
|
350
|
|
|
$
|
264
|
|
Additions pending determination of proved reserves
|
|
286
|
|
|
602
|
|
|
477
|
|
|||
Divestitures and other
|
|
(100
|
)
|
|
(82
|
)
|
|
(3
|
)
|
|||
Reclassifications to proved properties
|
|
(179
|
)
|
|
(647
|
)
|
|
(373
|
)
|
|||
Charged to exploration expense
|
|
(25
|
)
|
|
(64
|
)
|
|
(15
|
)
|
|||
Balance at December 31
|
|
$
|
141
|
|
|
$
|
159
|
|
|
$
|
350
|
|
|
|
2019
|
|
2018
|
|
2017
|
||||||
|
|
(In millions)
|
||||||||||
Exploratory well costs capitalized for a period of one year or less
|
|
$
|
108
|
|
|
$
|
126
|
|
|
$
|
160
|
|
Exploratory well costs capitalized for a period greater than one year
|
|
33
|
|
|
33
|
|
|
190
|
|
|||
Balance at December 31
|
|
$
|
141
|
|
|
$
|
159
|
|
|
$
|
350
|
|
|
|
|
|
|
|
|
||||||
Number of projects with exploratory well costs capitalized for a period greater than one year
|
|
2
|
|
|
2
|
|
|
4
|
|
|
|
|
|
|
|
|
|
2016 and
|
||||||||
|
|
Total
|
|
2018
|
|
2017
|
|
Prior
|
||||||||
|
|
(In millions)
|
||||||||||||||
United States
|
|
$
|
24
|
|
|
$
|
24
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Egypt
|
|
9
|
|
|
9
|
|
|
—
|
|
|
—
|
|
||||
|
|
$
|
33
|
|
|
$
|
33
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
Fair Value Measurements Using
|
|
|
|
|
|
|
||||||||||||||||
|
|
Quoted Price in Active Markets (Level 1)
|
|
Significant Other Inputs (Level 2)
|
|
Significant Unobservable Inputs
(Level 3)
|
|
Total Fair Value
|
|
Netting(1)
|
|
Carrying Amount
|
||||||||||||
|
|
(In millions)
|
||||||||||||||||||||||
December 31, 2019
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Pipeline Capacity Embedded Derivative
|
|
$
|
—
|
|
|
$
|
8
|
|
|
$
|
—
|
|
|
$
|
8
|
|
|
$
|
—
|
|
|
$
|
8
|
|
Foreign Currency Derivative Instruments
|
|
—
|
|
|
1
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|
1
|
|
||||||
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Preferred Units Embedded Derivative
|
|
—
|
|
|
—
|
|
|
103
|
|
|
103
|
|
|
—
|
|
|
103
|
|
||||||
December 31, 2018
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Commodity Derivative Instruments
|
|
$
|
—
|
|
|
$
|
69
|
|
|
$
|
—
|
|
|
$
|
69
|
|
|
$
|
(14
|
)
|
|
$
|
55
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Commodity Derivative Instruments
|
|
—
|
|
|
25
|
|
|
—
|
|
|
25
|
|
|
(14
|
)
|
|
11
|
|
(1)
|
The derivative fair values are based on analysis of each contract on a gross basis, excluding the impact of netting agreements with counterparties.
|
|
|
December 31, 2019
|
|
December 31, 2018
|
||||
|
|
(In millions)
|
||||||
Current Assets: Other current assets
|
|
$
|
2
|
|
|
$
|
55
|
|
Noncurrent Assets: Deferred charges and other
|
|
7
|
|
|
—
|
|
||
Total Assets
|
|
$
|
9
|
|
|
$
|
55
|
|
|
|
|
|
|
||||
Current Liabilities: Other current liabilities
|
|
$
|
—
|
|
|
$
|
11
|
|
Deferred Credits and Other Noncurrent Liabilities: Other
|
|
103
|
|
|
—
|
|
||
Total Liabilities
|
|
$
|
103
|
|
|
$
|
11
|
|
|
|
For the Year Ended December 31,
|
||||||||||
2019
|
|
2018
|
|
2017
|
||||||||
|
|
(In millions)
|
||||||||||
Realized gain (loss):
|
|
|
|
|
|
|
||||||
Derivative settlements, realized gain (loss)
|
|
$
|
9
|
|
|
$
|
(81
|
)
|
|
$
|
24
|
|
Amortization of put premium, realized loss
|
|
—
|
|
|
(39
|
)
|
|
(100
|
)
|
|||
Unrealized gain (loss)
|
|
(44
|
)
|
|
103
|
|
|
(59
|
)
|
|||
Derivative instrument losses, net
|
|
$
|
(35
|
)
|
|
$
|
(17
|
)
|
|
$
|
(135
|
)
|
5.
|
OTHER CURRENT ASSETS
|
|
|
December 31, 2019
|
|
December 31, 2018
|
||||
|
|
(In millions)
|
||||||
Inventories
|
|
$
|
502
|
|
|
$
|
401
|
|
Drilling advances
|
|
92
|
|
|
218
|
|
||
Prepaid assets and other
|
|
58
|
|
|
160
|
|
||
Total Other current assets
|
|
$
|
652
|
|
|
$
|
779
|
|
6.
|
EQUITY METHOD INTERESTS
|
|
|
December 31, 2019
|
|
December 31, 2018
|
||||||||||
|
|
Interest
|
|
Amount
|
|
Interest
|
|
Amount
|
||||||
|
|
($ in millions)
|
||||||||||||
Gulf Coast Express Pipeline LLC
|
|
16.0
|
%
|
|
$
|
291
|
|
|
15.0
|
%
|
|
$
|
91
|
|
EPIC Crude Holdings, LP
|
|
15.0
|
%
|
|
163
|
|
|
—
|
|
|
—
|
|
||
Permian Highway Pipeline LLC
|
|
26.7
|
%
|
|
311
|
|
|
—
|
|
|
—
|
|
||
Shin Oak Pipeline (Breviloba, LLC)
|
|
33.0
|
%
|
|
493
|
|
|
—
|
|
|
—
|
|
||
|
|
|
|
$
|
1,258
|
|
|
|
|
$
|
91
|
|
|
|
Gulf Coast Express Pipeline LLC
|
|
EPIC Crude Holdings, LP
|
|
Permian Highway Pipeline LLC
|
|
Breviloba, LLC
|
|
Total(2)
|
||||||||||
|
|
(In millions)
|
||||||||||||||||||
Balance at December 31, 2018
|
|
$
|
91
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
91
|
|
Acquisitions
|
|
15
|
|
|
52
|
|
|
162
|
|
|
442
|
|
|
671
|
|
|||||
Capital contributions
|
|
184
|
|
|
123
|
|
|
147
|
|
|
47
|
|
|
501
|
|
|||||
Distributions
|
|
(16
|
)
|
|
—
|
|
|
—
|
|
|
(9
|
)
|
|
(25
|
)
|
|||||
Capitalized interest(1)
|
|
—
|
|
|
—
|
|
|
2
|
|
|
—
|
|
|
2
|
|
|||||
Equity income (loss), net
|
|
17
|
|
|
(11
|
)
|
|
—
|
|
|
13
|
|
|
19
|
|
|||||
Accumulated other comprehensive loss
|
|
—
|
|
|
(1
|
)
|
|
—
|
|
|
—
|
|
|
(1
|
)
|
|||||
Balance at December 31, 2019
|
|
$
|
291
|
|
|
$
|
163
|
|
|
$
|
311
|
|
|
$
|
493
|
|
|
$
|
1,258
|
|
(1)
|
Altus’ proportionate share of the Permian Highway Pipeline (PHP) construction costs is funded with Altus’ revolving credit facility. Accordingly, Altus capitalized $2 million of related interest expense, which is included in the basis of the PHP equity interest.
|
(2)
|
At December 31, 2019, consolidated retained earnings, net of amortized basis differences, included $5 million related to undistributed earnings of equity method investments.
|
|
|
For the Year Ended December 31,
|
||||||
|
|
2019(1)
|
|
2018(1)
|
||||
|
|
(In millions)
|
||||||
Operating revenues
|
|
$
|
302
|
|
|
$
|
2
|
|
Operating expenses
|
|
181
|
|
|
8
|
|
||
Operating income (loss)
|
|
121
|
|
|
(6
|
)
|
||
Net income (loss)
|
|
115
|
|
|
(6
|
)
|
||
Other comprehensive loss
|
|
(8
|
)
|
|
—
|
|
(1)
|
The financial results for all equity method interests are presented for the entire twelve months for both periods for comparability.
|
|
|
December 31,
|
||||||
|
|
2019
|
|
2018
|
||||
|
|
(In millions)
|
||||||
Current assets
|
|
$
|
441
|
|
|
$
|
451
|
|
Noncurrent assets
|
|
6,431
|
|
|
2,377
|
|
||
Total assets
|
|
$
|
6,872
|
|
|
$
|
2,828
|
|
|
|
|
|
|
||||
Current liabilities
|
|
$
|
478
|
|
|
$
|
805
|
|
Noncurrent liabilities
|
|
958
|
|
|
1
|
|
||
Equity
|
|
5,436
|
|
|
2,022
|
|
||
Total liabilities and equity
|
|
$
|
6,872
|
|
|
$
|
2,828
|
|
|
|
December 31,
|
||||||
|
|
2019
|
|
2018
|
||||
|
|
(In millions)
|
||||||
Accrued operating expenses
|
|
$
|
143
|
|
|
$
|
65
|
|
Accrued exploration and development
|
|
319
|
|
|
667
|
|
||
Accrued gathering, processing, and transmission - Altus
|
|
17
|
|
|
81
|
|
||
Accrued compensation and benefits
|
|
212
|
|
|
177
|
|
||
Accrued interest
|
|
135
|
|
|
137
|
|
||
Accrued income taxes
|
|
51
|
|
|
58
|
|
||
Current asset retirement obligation
|
|
47
|
|
|
66
|
|
||
Current operating lease liability
|
|
169
|
|
|
—
|
|
||
Other
|
|
56
|
|
|
90
|
|
||
Total Other current liabilities
|
|
$
|
1,149
|
|
|
$
|
1,341
|
|
|
|
2019
|
|
2018
|
||||
|
|
(In millions)
|
||||||
Asset retirement obligation at beginning of year
|
|
$
|
1,932
|
|
|
$
|
1,835
|
|
Liabilities incurred
|
|
41
|
|
|
51
|
|
||
Liabilities divested
|
|
(56
|
)
|
|
—
|
|
||
Liabilities settled
|
|
(56
|
)
|
|
(52
|
)
|
||
Accretion expense
|
|
107
|
|
|
108
|
|
||
Revisions in estimated liabilities
|
|
(110
|
)
|
|
(10
|
)
|
||
Asset retirement obligation at end of year
|
|
1,858
|
|
|
1,932
|
|
||
Less current portion
|
|
(47
|
)
|
|
(66
|
)
|
||
Asset retirement obligation, long-term
|
|
$
|
1,811
|
|
|
$
|
1,866
|
|
|
|
December 31,
|
||||||
|
|
2019
|
|
2018
|
||||
|
|
(In millions)
|
||||||
Commercial paper
|
|
$
|
—
|
|
|
$
|
—
|
|
7.625% notes due 2019(1)
|
|
—
|
|
|
150
|
|
||
3.625% notes due 2021(2)
|
|
293
|
|
|
393
|
|
||
3.25% notes due 2022(2)
|
|
463
|
|
|
687
|
|
||
2.625% notes due 2023(2)
|
|
181
|
|
|
403
|
|
||
7.7% notes due 2026
|
|
79
|
|
|
79
|
|
||
7.95% notes due 2026
|
|
133
|
|
|
133
|
|
||
4.375% notes due 2028(2)
|
|
1,000
|
|
|
1,000
|
|
||
7.75% notes due 2029(2)(3)
|
|
247
|
|
|
300
|
|
||
4.25% notes due 2030(2)
|
|
600
|
|
|
—
|
|
||
6.0% notes due 2037(2)
|
|
467
|
|
|
800
|
|
||
5.1% notes due 2040(2)
|
|
1,499
|
|
|
1,499
|
|
||
5.25% notes due 2042(2)
|
|
500
|
|
|
500
|
|
||
4.75% notes due 2043(2)
|
|
1,413
|
|
|
1,413
|
|
||
4.25% notes due 2044(2)
|
|
753
|
|
|
753
|
|
||
7.375% debentures due 2047
|
|
150
|
|
|
150
|
|
||
5.35% notes due 2049(2)
|
|
400
|
|
|
—
|
|
||
7.625% debentures due 2096
|
|
39
|
|
|
39
|
|
||
Notes and debentures before unamortized discount and debt issuance costs(4)
|
|
8,217
|
|
|
8,299
|
|
||
Altus credit facility(5)
|
|
396
|
|
|
—
|
|
||
Finance lease obligations
|
|
48
|
|
|
40
|
|
||
Unamortized discount
|
|
(42
|
)
|
|
(44
|
)
|
||
Debt issuance costs
|
|
(53
|
)
|
|
(51
|
)
|
||
Total debt
|
|
8,566
|
|
|
8,244
|
|
||
Current maturities
|
|
(11
|
)
|
|
(151
|
)
|
||
Long-term debt
|
|
$
|
8,555
|
|
|
$
|
8,093
|
|
(1)
|
On July 1, 2019, Apache’s 7.625% senior notes due 2019 in original principal amount of $150 million matured and were repaid.
|
(2)
|
These notes are redeemable, as a whole or in part, at Apache’s option, subject to a make-whole premium, except that the 7.75% notes due 2029 are only redeemable as whole for principal and accrued interest in the event of certain Canadian tax law changes. The remaining notes and debentures are not redeemable.
|
(3)
|
Assumed by Apache in August 2017 as permitted by terms of these notes originally issued by a subsidiary and guaranteed by Apache. Since these notes historically have been included in Apache’s long-term debt, the assumption did not change Apache’s long-term debt or total debt.
|
(4)
|
The fair value of the Company’s notes and debentures was $8.4 billion and $7.8 billion as of December 31, 2019 and 2018, respectively. Apache uses a market approach to determine the fair value of its notes and debentures using estimates provided by an independent investment financial data services firm (a Level 2 fair value measurement).
|
(5)
|
The carrying amount of borrowings by Altus Midstream LP on its credit facility approximate fair value because the interest rates are variable and reflective of market rates.
|
|
(In millions)
|
||
2020
|
$
|
—
|
|
2021
|
293
|
|
|
2022
|
463
|
|
|
2023
|
181
|
|
|
2024
|
—
|
|
|
Thereafter
|
7,280
|
|
|
Notes and debentures, excluding discounts and debt issuance costs
|
$
|
8,217
|
|
|
|
For the Year Ended December 31,
|
||||||||||
|
|
2019
|
|
2018
|
|
2017
|
||||||
|
|
(In millions)
|
||||||||||
Interest expense
|
|
$
|
430
|
|
|
$
|
441
|
|
|
$
|
457
|
|
Amortization of debt issuance costs
|
|
7
|
|
|
9
|
|
|
9
|
|
|||
Capitalized interest
|
|
(37
|
)
|
|
(44
|
)
|
|
(51
|
)
|
|||
Loss on extinguishment of debt
|
|
75
|
|
|
94
|
|
|
1
|
|
|||
Interest income
|
|
(13
|
)
|
|
(22
|
)
|
|
(19
|
)
|
|||
Financing costs, net
|
|
$
|
462
|
|
|
$
|
478
|
|
|
$
|
397
|
|
|
|
For the Year Ended December 31,
|
||||||||||
|
|
2019
|
|
2018
|
|
2017
|
||||||
|
|
(In millions)
|
||||||||||
U.S.
|
|
$
|
(4,397
|
)
|
|
$
|
(723
|
)
|
|
$
|
(3,620
|
)
|
Foreign
|
|
1,389
|
|
|
1,681
|
|
|
4,538
|
|
|||
Total
|
|
$
|
(3,008
|
)
|
|
$
|
958
|
|
|
$
|
918
|
|
|
|
For the Year Ended December 31,
|
||||||||||
|
|
2019
|
|
2018
|
|
2017
|
||||||
|
|
(In millions)
|
||||||||||
Current income taxes:
|
|
|
|
|
|
|
||||||
Federal
|
|
$
|
1
|
|
|
$
|
(1
|
)
|
|
$
|
(38
|
)
|
State
|
|
—
|
|
|
—
|
|
|
(8
|
)
|
|||
Foreign
|
|
659
|
|
|
895
|
|
|
641
|
|
|||
|
|
660
|
|
|
894
|
|
|
595
|
|
|||
Deferred income taxes:
|
|
|
|
|
|
|
||||||
Federal
|
|
67
|
|
|
(65
|
)
|
|
(1,010
|
)
|
|||
State
|
|
—
|
|
|
2
|
|
|
—
|
|
|||
Foreign
|
|
(53
|
)
|
|
(159
|
)
|
|
(170
|
)
|
|||
|
|
14
|
|
|
(222
|
)
|
|
(1,180
|
)
|
|||
Total
|
|
$
|
674
|
|
|
$
|
672
|
|
|
$
|
(585
|
)
|
|
|
For the Year Ended December 31,
|
||||||||||
|
|
2019
|
|
2018
|
|
2017
|
||||||
|
|
(In millions)
|
||||||||||
Income tax expense (benefit) at U.S. statutory rate
|
|
$
|
(631
|
)
|
|
$
|
201
|
|
|
$
|
321
|
|
State income tax, less federal effect(1)
|
|
1
|
|
|
2
|
|
|
(6
|
)
|
|||
Taxes related to foreign operations
|
|
328
|
|
|
436
|
|
|
(105
|
)
|
|||
Tax credits
|
|
(6
|
)
|
|
(13
|
)
|
|
(33
|
)
|
|||
Tax on deemed repatriation of foreign earnings
|
|
—
|
|
|
103
|
|
|
419
|
|
|||
Foreign tax credits
|
|
—
|
|
|
(336
|
)
|
|
(201
|
)
|
|||
Deferred tax on undistributed foreign earnings
|
|
—
|
|
|
—
|
|
|
(1,872
|
)
|
|||
Change in U.S. tax rate
|
|
—
|
|
|
161
|
|
|
516
|
|
|||
Net change in tax contingencies
|
|
1
|
|
|
(2
|
)
|
|
(1
|
)
|
|||
Sale of Canadian assets
|
|
—
|
|
|
—
|
|
|
279
|
|
|||
Sale of North Sea assets
|
|
—
|
|
|
(30
|
)
|
|
(48
|
)
|
|||
Valuation allowances(1)
|
|
972
|
|
|
118
|
|
|
161
|
|
|||
All other, net
|
|
9
|
|
|
32
|
|
|
(15
|
)
|
|||
|
|
$
|
674
|
|
|
$
|
672
|
|
|
$
|
(585
|
)
|
(1)
|
The change in state valuation allowance is included as a component of state income tax.
|
|
|
December 31,
|
||||||
|
|
2019
|
|
2018
|
||||
|
|
(In millions)
|
||||||
Deferred tax assets:
|
|
|
|
|
||||
U.S. and state net operating losses
|
|
$
|
2,108
|
|
|
$
|
1,633
|
|
Capital losses
|
|
626
|
|
|
636
|
|
||
Tax credits and other tax incentives
|
|
32
|
|
|
39
|
|
||
Foreign tax credits
|
|
2,241
|
|
|
2,241
|
|
||
Accrued expenses and liabilities
|
|
97
|
|
|
117
|
|
||
Asset retirement obligation
|
|
618
|
|
|
649
|
|
||
Equity investments
|
|
—
|
|
|
4
|
|
||
Investment in Altus Midstream LP
|
|
107
|
|
|
—
|
|
||
Net interest expense limitation
|
|
162
|
|
|
65
|
|
||
Lease liability
|
|
108
|
|
|
—
|
|
||
Other
|
|
88
|
|
|
97
|
|
||
Total deferred tax assets
|
|
6,187
|
|
|
5,481
|
|
||
Valuation allowance
|
|
(4,959
|
)
|
|
(3,947
|
)
|
||
Net deferred tax assets
|
|
1,228
|
|
|
1,534
|
|
||
Deferred tax liabilities:
|
|
|
|
|
||||
Deferred income
|
|
1
|
|
|
10
|
|
||
Investment in Altus Midstream LP
|
|
—
|
|
|
73
|
|
||
Property and equipment
|
|
1,432
|
|
|
1,747
|
|
||
Right-of-use asset
|
|
106
|
|
|
—
|
|
||
Other
|
|
6
|
|
|
4
|
|
||
Total deferred tax liabilities
|
|
1,545
|
|
|
1,834
|
|
||
Net deferred income tax liability
|
|
$
|
317
|
|
|
$
|
300
|
|
|
|
December 31,
|
||||||
|
|
2019
|
|
2018
|
||||
|
|
(In millions)
|
||||||
Assets:
|
|
|
|
|
||||
Deferred charges and other
|
|
$
|
29
|
|
|
$
|
91
|
|
Liabilities:
|
|
|
|
|
||||
Deferred income taxes
|
|
346
|
|
|
391
|
|
||
Net deferred income tax liability
|
|
$
|
317
|
|
|
$
|
300
|
|
|
|
2019
|
|
2018
|
|
2017
|
||||||
|
|
(In millions)
|
||||||||||
Balance at beginning of year
|
|
$
|
3,947
|
|
|
$
|
3,816
|
|
|
$
|
5,401
|
|
State(1)
|
|
41
|
|
|
15
|
|
|
139
|
|
|||
U.S.
|
|
971
|
|
|
124
|
|
|
905
|
|
|||
Foreign(2)
|
|
—
|
|
|
(8
|
)
|
|
(2,629
|
)
|
|||
Balance at end of year
|
|
$
|
4,959
|
|
|
$
|
3,947
|
|
|
$
|
3,816
|
|
(1)
|
Reported as a component of state income taxes.
|
(2)
|
In 2017, the Company completed the sale of its Canadian assets. As such, except for capital losses incurred on the sale, the deferred tax assets, liabilities, and valuation allowance related to these assets were removed for 2017.
|
|
|
Amount
|
|
Expiration
|
||
|
|
(In millions)
|
|
|
||
Net operating losses:
|
|
|
|
|
||
U.S.
|
|
$
|
8,052
|
|
|
2019 - Indefinite
|
State
|
|
6,090
|
|
|
Various
|
|
|
Amount
|
|
Expiration
|
||
|
|
(In millions)
|
|
|
||
Foreign tax credits
|
|
$
|
2,241
|
|
|
2025-2026
|
|
|
2019
|
|
2018
|
|
2017
|
||||||
|
|
(In millions)
|
||||||||||
Balance at beginning of year
|
|
$
|
24
|
|
|
$
|
26
|
|
|
$
|
15
|
|
Additions based on tax positions related to prior year
|
|
49
|
|
|
—
|
|
|
—
|
|
|||
Additions based on tax positions related to the current year
|
|
9
|
|
|
—
|
|
|
12
|
|
|||
Reductions for tax positions of prior years
|
|
—
|
|
|
(2
|
)
|
|
(1
|
)
|
|||
Balance at end of year
|
|
$
|
82
|
|
|
$
|
24
|
|
|
$
|
26
|
|
U.S.
|
2014
|
Egypt
|
2005
|
U.K.
|
2018
|
|
|
Operating Leases
|
|
Finance Leases
|
||
Weighted average remaining lease term
|
|
3.8 years
|
|
|
10.9 years
|
|
Weighted average discount rate
|
|
4.4
|
%
|
|
4.3
|
%
|
Net Minimum Commitments(1)
|
|
Operating Leases(2)
|
|
Finance Leases(3)
|
|
Purchase Obligations(4)(5)
|
||||||
|
|
(In millions)
|
||||||||||
2020
|
|
$
|
165
|
|
|
$
|
13
|
|
|
$
|
152
|
|
2021
|
|
82
|
|
|
3
|
|
|
191
|
|
|||
2022
|
|
50
|
|
|
3
|
|
|
181
|
|
|||
2023
|
|
33
|
|
|
3
|
|
|
213
|
|
|||
2024
|
|
27
|
|
|
3
|
|
|
195
|
|
|||
Thereafter
|
|
32
|
|
|
37
|
|
|
910
|
|
|||
Total future minimum payments
|
|
389
|
|
|
62
|
|
|
$
|
1,842
|
|
||
Less: imputed interest
|
|
(23
|
)
|
|
(14
|
)
|
|
N/A
|
|
|||
Total lease liabilities
|
|
366
|
|
|
48
|
|
|
N/A
|
|
|||
Current portion
|
|
169
|
|
|
11
|
|
|
N/A
|
|
|||
Non-current portion
|
|
$
|
197
|
|
|
$
|
37
|
|
|
N/A
|
|
(1)
|
Excludes commitments for jointly owned fields and facilities for which the Company is not the operator.
|
(2)
|
Amounts represent future payments associated with oil and gas operations inclusive of amounts billable to partners and other working interest owners. Such payments may be capitalized as a component of oil and gas properties and subsequently depreciated, impaired, or written off as exploration expense.
|
(3)
|
Amounts represent the Company’s finance lease obligation related to physical power generators being leased on a one-year term with the right to purchase and a separate lease for the Company’s Midland, Texas regional office building.
|
(4)
|
Amounts represent any agreements to purchase goods or services that are enforceable and legally binding and that specify all significant terms. These include minimum commitments associated with take-or-pay contracts, NGL processing agreements, drilling work program commitments, and agreements to secure capacity rights on third-party pipelines. Amounts exclude certain product purchase obligations related to marketing and trading activities for which there are no minimum purchase requirements or the amounts are not fixed or determinable. Total costs incurred under take-or-pay and throughput obligations were $111 million, $132 million, and $134 million for 2019, 2018, and 2017, respectively.
|
(5)
|
Subsequent to December 31, 2019, Apache entered into an agreement to assign approximately $171 million of its firm transportation obligations beginning in March 2020.
|
|
|
Operating Leases(1)
|
|
Finance Leases(2)
|
||||
|
|
(In millions)
|
||||||
Year ended December 31, 2018
|
|
|
|
|
||||
2019
|
|
$
|
61
|
|
|
$
|
1
|
|
2020-2021
|
|
64
|
|
|
3
|
|
||
2022-2023
|
|
53
|
|
|
4
|
|
||
2024 & Beyond
|
|
42
|
|
|
32
|
|
||
Total
|
|
$
|
220
|
|
|
$
|
40
|
|
|
|
|
|
|
||||
Year ended December 31, 2017
|
|
|
|
|
||||
2018
|
|
$
|
54
|
|
|
$
|
1
|
|
2019-2020
|
|
81
|
|
|
3
|
|
||
2021-2022
|
|
57
|
|
|
3
|
|
||
2023 & Beyond
|
|
41
|
|
|
34
|
|
||
Total
|
|
$
|
233
|
|
|
$
|
41
|
|
(1)
|
Includes leases for buildings, facilities, and related equipment with varying expiration dates through 2042. Amounts represent future payments associated with oil and gas operations inclusive of amounts billable to partners and other working interest owners. Such payments may be capitalized as a component of oil and gas properties and subsequently depreciated, impaired, or written off as exploration expense. Total rent expense, net of amounts capitalized and sublease income was $76 million and $82 million for 2018, and 2017, respectively.
|
(2)
|
This represents the Company’s capital lease obligation related to its Midland, Texas office building. The imputed interest rate necessary to reduce the net minimum lease payments to present value of the lease term is 4.4 percent, or $16 million and $18 million as of December 31, 2018 and December 31, 2017, respectively.
|
|
|
2019
|
|
2018
|
|
2017
|
||||||||||||||||||
|
|
Pension
Benefits
|
|
Postretirement
Benefits
|
|
Pension
Benefits
|
|
Postretirement
Benefits
|
|
Pension
Benefits
|
|
Postretirement
Benefits
|
||||||||||||
|
|
(In millions)
|
||||||||||||||||||||||
Change in Projected Benefit Obligation
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Projected benefit obligation at beginning of year
|
|
$
|
187
|
|
|
$
|
27
|
|
|
$
|
216
|
|
|
$
|
27
|
|
|
$
|
202
|
|
|
$
|
26
|
|
Service cost
|
|
3
|
|
|
2
|
|
|
4
|
|
|
2
|
|
|
4
|
|
|
2
|
|
||||||
Interest cost
|
|
5
|
|
|
1
|
|
|
5
|
|
|
1
|
|
|
6
|
|
|
1
|
|
||||||
Foreign currency exchange rates
|
|
7
|
|
|
—
|
|
|
(11
|
)
|
|
—
|
|
|
20
|
|
|
—
|
|
||||||
Actuarial losses (gains)
|
|
15
|
|
|
(9
|
)
|
|
(11
|
)
|
|
(2
|
)
|
|
(4
|
)
|
|
1
|
|
||||||
Plan settlements
|
|
(14
|
)
|
|
—
|
|
|
(11
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Benefits paid
|
|
(4
|
)
|
|
(2
|
)
|
|
(5
|
)
|
|
(3
|
)
|
|
(12
|
)
|
|
(4
|
)
|
||||||
Retiree contributions
|
|
—
|
|
|
1
|
|
|
—
|
|
|
2
|
|
|
—
|
|
|
1
|
|
||||||
Projected benefit obligation at end of year
|
|
199
|
|
|
20
|
|
|
187
|
|
|
27
|
|
|
216
|
|
|
27
|
|
||||||
Change in Plan Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Fair value of plan assets at beginning of year
|
|
208
|
|
|
—
|
|
|
238
|
|
|
—
|
|
|
206
|
|
|
—
|
|
||||||
Actual return on plan assets
|
|
25
|
|
|
—
|
|
|
(6
|
)
|
|
—
|
|
|
17
|
|
|
—
|
|
||||||
Foreign currency exchange rates
|
|
8
|
|
|
—
|
|
|
(13
|
)
|
|
—
|
|
|
22
|
|
|
—
|
|
||||||
Employer contributions
|
|
5
|
|
|
1
|
|
|
5
|
|
|
2
|
|
|
5
|
|
|
3
|
|
||||||
Plan settlements
|
|
(14
|
)
|
|
—
|
|
|
(11
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Benefits paid
|
|
(4
|
)
|
|
(2
|
)
|
|
(5
|
)
|
|
(4
|
)
|
|
(12
|
)
|
|
(4
|
)
|
||||||
Retiree contributions
|
|
—
|
|
|
1
|
|
|
—
|
|
|
2
|
|
|
—
|
|
|
1
|
|
||||||
Fair value of plan assets at end of year
|
|
228
|
|
|
—
|
|
|
208
|
|
|
—
|
|
|
238
|
|
|
—
|
|
||||||
Funded status at end of year
|
|
$
|
29
|
|
|
$
|
(20
|
)
|
|
$
|
21
|
|
|
$
|
(27
|
)
|
|
$
|
22
|
|
|
$
|
(27
|
)
|
Amounts recognized in Consolidated Balance Sheet
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Current liability
|
|
$
|
—
|
|
|
$
|
(2
|
)
|
|
$
|
—
|
|
|
$
|
(2
|
)
|
|
$
|
—
|
|
|
$
|
(2
|
)
|
Non-current asset (liability)
|
|
29
|
|
|
(18
|
)
|
|
21
|
|
|
(25
|
)
|
|
22
|
|
|
(25
|
)
|
||||||
|
|
$
|
29
|
|
|
$
|
(20
|
)
|
|
$
|
21
|
|
|
$
|
(27
|
)
|
|
$
|
22
|
|
|
$
|
(27
|
)
|
Pre-tax Amounts Recognized in Accumulated Other Comprehensive Income (Loss)
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Accumulated gain (loss)
|
|
$
|
(7
|
)
|
|
$
|
19
|
|
|
$
|
(13
|
)
|
|
$
|
10
|
|
|
$
|
(11
|
)
|
|
$
|
8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Weighted Average Assumptions used as of December 31
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Discount rate
|
|
2.10
|
%
|
|
3.00
|
%
|
|
2.90
|
%
|
|
4.13
|
%
|
|
2.60
|
%
|
|
3.44
|
%
|
||||||
Salary increases
|
|
4.30
|
%
|
|
N/A
|
|
|
4.70
|
%
|
|
N/A
|
|
|
4.70
|
%
|
|
N/A
|
|
||||||
Expected return on assets
|
|
2.80
|
%
|
|
N/A
|
|
|
2.80
|
%
|
|
N/A
|
|
|
2.90
|
%
|
|
N/A
|
|
||||||
Healthcare cost trend
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Initial
|
|
N/A
|
|
|
6.25
|
%
|
|
N/A
|
|
|
6.50
|
%
|
|
N/A
|
|
|
6.75
|
%
|
||||||
Ultimate in 2025
|
|
N/A
|
|
|
5.00
|
%
|
|
N/A
|
|
|
5.00
|
%
|
|
N/A
|
|
|
5.00
|
%
|
|
|
Target
Allocation
|
|
Percentage of
Plan Assets at
Year-End
|
|||||
|
|
2019
|
|
2019
|
|
2018
|
|||
Asset Category
|
|
|
|
|
|
|
|||
Equity securities:
|
|
|
|
|
|
|
|||
Overseas quoted equities
|
|
22
|
%
|
|
23
|
%
|
|
22
|
%
|
Total equity securities
|
|
22
|
%
|
|
23
|
%
|
|
22
|
%
|
Debt securities:
|
|
|
|
|
|
|
|||
U.K. Government bonds
|
|
62
|
%
|
|
62
|
%
|
|
62
|
%
|
U.K. corporate bonds
|
|
16
|
%
|
|
15
|
%
|
|
15
|
%
|
Total debt securities
|
|
78
|
%
|
|
77
|
%
|
|
77
|
%
|
Cash
|
|
—
|
|
|
—
|
|
|
1
|
%
|
Total
|
|
100
|
%
|
|
100
|
%
|
|
100
|
%
|
|
|
December 31, 2019
|
|
December 31, 2018
|
||||
|
|
(In millions)
|
||||||
Equity securities:
|
|
|
|
|
||||
Overseas quoted equities(1)
|
|
$
|
52
|
|
|
$
|
46
|
|
Total equity securities
|
|
52
|
|
|
46
|
|
||
Debt securities:
|
|
|
|
|
||||
U.K. Government bonds(2)
|
|
140
|
|
|
129
|
|
||
U.K. corporate bonds(3)
|
|
35
|
|
|
32
|
|
||
Total debt securities
|
|
175
|
|
|
161
|
|
||
Cash
|
|
1
|
|
|
1
|
|
||
Fair value of plan assets
|
|
$
|
228
|
|
|
$
|
208
|
|
(1)
|
This category includes overseas equities, which comprises 20 percent passive global equities benchmarked against the MSCI World (NDR) Index, 25 percent passive global equities (hedged) benchmarked against the MSCI World (NDR) Hedged Index, 20 percent fundamental indexation global equities benchmarked against the FTSE RAFI Developed 1000 index, 25 percent fundamental indexation global equities (hedged) benchmarked against the FTSE RAFI Developed 1000 Hedge Index, and 10 percent emerging markets benchmarked against the MSCI Emerging Markets (NDR) Index, which has a performance target of 2 percent per annum over the benchmark over a rolling three-year period.
|
(2)
|
This category includes U.K. Government bonds, which comprises 61 percent index-linked gilts benchmarked against the FTSE Actuaries Government Securities Index-Linked Over 5 Years Index, 8 percent sterling nominal LDI bonds, and 31 percent sterling inflation linked LDI bonds, both benchmarked against ILIM Custom Benchmark index.
|
(3)
|
This category comprises U.K. corporate bonds benchmarked against the BofAML Sterling Corporate & Collaterlised (excluding Subordinated) Index.
|
|
|
2019
|
|
2018
|
|
2017
|
||||||||||||||||||
|
|
Pension
Benefits
|
|
Postretirement
Benefits
|
|
Pension
Benefits
|
|
Postretirement
Benefits
|
|
Pension
Benefits
|
|
Postretirement
Benefits
|
||||||||||||
|
|
(In millions)
|
||||||||||||||||||||||
Components of Net Periodic Benefit Cost
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Service cost
|
|
$
|
3
|
|
|
$
|
2
|
|
|
$
|
4
|
|
|
$
|
2
|
|
|
$
|
4
|
|
|
$
|
2
|
|
Interest cost
|
|
5
|
|
|
1
|
|
|
5
|
|
|
1
|
|
|
6
|
|
|
1
|
|
||||||
Expected return on assets
|
|
(5
|
)
|
|
—
|
|
|
(7
|
)
|
|
—
|
|
|
(8
|
)
|
|
—
|
|
||||||
Amortization of actuarial (gain) loss
|
|
—
|
|
|
(1
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1
|
)
|
||||||
Settlement loss
|
|
—
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Net periodic benefit cost
|
|
$
|
3
|
|
|
$
|
2
|
|
|
$
|
3
|
|
|
$
|
3
|
|
|
$
|
2
|
|
|
$
|
2
|
|
Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost for the Years Ended December 31
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Discount rate
|
|
2.90
|
%
|
|
4.13
|
%
|
|
2.60
|
%
|
|
3.44
|
%
|
|
2.70
|
%
|
|
3.76
|
%
|
||||||
Salary increases
|
|
4.70
|
%
|
|
N/A
|
|
|
4.70
|
%
|
|
N/A
|
|
|
4.80
|
%
|
|
N/A
|
|
||||||
Expected return on assets
|
|
2.80
|
%
|
|
N/A
|
|
|
2.90
|
%
|
|
N/A
|
|
|
3.40
|
%
|
|
N/A
|
|
||||||
Healthcare cost trend
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Initial
|
|
N/A
|
|
|
6.50
|
%
|
|
N/A
|
|
|
6.75
|
%
|
|
N/A
|
|
|
7.00
|
%
|
||||||
Ultimate in 2025
|
|
N/A
|
|
|
5.00
|
%
|
|
N/A
|
|
|
5.00
|
%
|
|
N/A
|
|
|
5.00
|
%
|
|
|
Postretirement Benefits
|
||||||
|
|
1% Increase
|
|
1% Decrease
|
||||
|
|
(In millions)
|
||||||
Effect on service and interest cost components
|
|
$
|
1
|
|
|
$
|
(1
|
)
|
Effect on postretirement benefit obligation
|
|
2
|
|
|
(1
|
)
|
|
|
Pension
Benefits
|
|
Postretirement
Benefits
|
||||
|
|
(In millions)
|
||||||
2020
|
|
$
|
5
|
|
|
$
|
2
|
|
2021
|
|
4
|
|
|
2
|
|
||
2022
|
|
5
|
|
|
2
|
|
||
2023
|
|
6
|
|
|
2
|
|
||
2024
|
|
6
|
|
|
2
|
|
||
Years 2025-2029
|
|
32
|
|
|
8
|
|
13.
|
REDEEMABLE NONCONTROLLING INTEREST - ALTUS
|
•
|
The Preferred Units bear quarterly distributions at a rate of 7 percent per annum, increasing after the fifth anniversary of Closing and upon the occurrence of specified events. Altus Midstream LP may pay distributions in-kind for the first six quarters after the Preferred Units are issued.
|
•
|
The Preferred Units are redeemable at Altus Midstream LP’s option at any time in cash at a redemption price (the Redemption Price) equal to the greater of an 11.5 percent internal rate of return (increasing after the fifth anniversary of Closing to 13.75 percent) and a 1.3x multiple of invested capital. The Preferred Units will be redeemable at the holder’s option upon a change of control or liquidation of Altus Midstream LP and certain other events, including certain asset dispositions.
|
•
|
The Preferred Units will be exchangeable for shares of ALTM’s Class A common stock at the holder’s election after the seventh anniversary of Closing or upon the occurrence of specified events. Each Preferred Unit will be exchangeable for a number of shares of ALTM’s Class A common stock equal to the Redemption Price divided by the volume-weighted average trading price of ALTM’s Class A common stock on the Nasdaq Capital Market for the 20 trading days immediately preceding the second trading day prior to the applicable exchange date, less a 6 percent discount.
|
•
|
Each outstanding Preferred Unit has a liquidation preference equal to the Redemption Price payable before any amounts are paid in respect of Altus Midstream LP’s common units and any other units that rank junior to the Preferred Units with respect to distributions or distributions upon liquidation.
|
•
|
Preferred Units holders have rights to approve certain partnership business, financial, and governance-related matters.
|
•
|
Altus Midstream LP is restricted from declaring or making cash distributions on its common units until all required distributions on the Preferred Units have been paid. In addition, before the fifth anniversary of Closing, aggregate cash distributions on, and redemptions of, Altus Midstream LP’s common units are limited to $650 million of cash from ordinary course operations if permitted under its credit facility. Cash distributions on, and redemptions of, Altus Midstream LP’s common units also are subject to satisfaction of leverage ratio requirements specified in its partnership agreement.
|
|
|
June 12, 2019
|
||
|
|
(In millions)
|
||
Redeemable noncontrolling interest - Altus Preferred Unit Limited Partners
|
|
$
|
517
|
|
Preferred Units embedded derivative
|
|
94
|
|
|
|
|
$
|
611
|
|
|
|
Units Outstanding
|
|
Financial Position(2)
|
|||
|
|
(In millions, except unit data)
|
|||||
Redeemable noncontrolling interest - Altus Preferred Unit Limited Partners: beginning of period
|
|
—
|
|
|
$
|
—
|
|
Issuance of Preferred Units, net
|
|
625,000
|
|
|
517
|
|
|
Distribution of in-kind additional Preferred Units(1)
|
|
13,163
|
|
|
—
|
|
|
Allocation of Altus Midstream LP net income
|
|
N/A
|
|
|
38
|
|
|
Redeemable noncontrolling interest - Altus Preferred Unit Limited Partners: end of period
|
|
638,163
|
|
|
555
|
|
|
Preferred Units embedded derivative
|
|
|
|
103
|
|
||
|
|
|
|
$
|
658
|
|
(1)
|
Subsequent to the balance sheet date, Altus Midstream LP provided notice to the Preferred Unit holders of record at December 31, 2019 of the amount of the distribution on the Preferred Units for the quarter ended December 31, 2019. The holders also were notified that Altus Midstream LP elected to pay the entire amount of the approximate $11 million distribution in-kind in additional Preferred Units (PIK Units) on February 14, 2020. In total, 11,168 PIK Units were issued in satisfaction of the required distribution.
|
(2)
|
As at December 31, 2019, the aggregate Redemption Price was $664 million, based on an internal rate of return of 11.5 percent.
|
|
|
2019
|
|
2018
|
|
2017
|
|||
Balance, beginning of year
|
|
374,696,222
|
|
|
380,954,864
|
|
|
379,439,676
|
|
Shares issued for stock-based compensation plans:
|
|
|
|
|
|
|
|||
Treasury shares issued
|
|
31,701
|
|
|
2,454
|
|
|
1,411
|
|
Common shares issued
|
|
1,334,747
|
|
|
1,566,237
|
|
|
1,513,777
|
|
Treasury shares acquired
|
|
—
|
|
|
(7,827,333
|
)
|
|
—
|
|
Balance, end of year
|
|
376,062,670
|
|
|
374,696,222
|
|
|
380,954,864
|
|
|
|
2019
|
|
2018
|
|
2017
|
|||||||||||||||||||||||||||
|
|
Loss
|
|
Shares
|
|
Per Share
|
|
Income
|
|
Shares
|
|
Per Share
|
|
Income
|
|
Shares
|
|
Per Share
|
|||||||||||||||
|
|
(In millions, except per share amounts)
|
|||||||||||||||||||||||||||||||
Basic:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||
Income (loss) attributable to common stock
|
|
$
|
(3,553
|
)
|
|
377
|
|
|
$
|
(9.43
|
)
|
|
$
|
40
|
|
|
382
|
|
|
$
|
0.11
|
|
|
$
|
1,304
|
|
|
381
|
|
|
$
|
3.42
|
|
Effect of Dilutive Securities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||
Stock options and other
|
|
$
|
—
|
|
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
2
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
2
|
|
|
$
|
(0.01
|
)
|
Diluted:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||
Income (loss) attributable to common stock
|
|
$
|
(3,553
|
)
|
|
377
|
|
|
$
|
(9.43
|
)
|
|
$
|
40
|
|
|
384
|
|
|
$
|
0.11
|
|
|
$
|
1,304
|
|
|
383
|
|
|
$
|
3.41
|
|
|
|
For the Year Ended December 31,
|
||||||||||
|
|
2019
|
|
2018
|
|
2017
|
||||||
|
|
(In millions)
|
||||||||||
Stock-settled and cash-settled compensation expensed
|
|
$
|
110
|
|
|
$
|
157
|
|
|
$
|
142
|
|
Stock-settled and cash-settled compensation capitalized
|
|
28
|
|
|
37
|
|
|
41
|
|
|||
Total stock-settled and cash-settled compensation costs
|
|
$
|
138
|
|
|
$
|
194
|
|
|
$
|
183
|
|
|
|
2019
|
|
2018
|
|
2017
|
|||||||||||||||
|
|
Shares
Under Option |
|
Weighted Average
Exercise Price
|
|
Shares
Under Option
|
|
Weighted Average
Exercise Price
|
|
Shares
Under Option
|
|
Weighted Average
Exercise Price
|
|||||||||
Outstanding, beginning of year
|
|
4,872
|
|
|
$
|
75.95
|
|
|
4,593
|
|
|
$
|
83.36
|
|
|
5,113
|
|
|
$
|
84.89
|
|
Granted
|
|
—
|
|
|
—
|
|
|
812
|
|
|
45.93
|
|
|
490
|
|
|
63.25
|
|
|||
Exercised
|
|
—
|
|
|
—
|
|
|
(29
|
)
|
|
41.79
|
|
|
(15
|
)
|
|
41.24
|
|
|||
Forfeited
|
|
(80
|
)
|
|
34.58
|
|
|
(121
|
)
|
|
74.58
|
|
|
(691
|
)
|
|
84.65
|
|
|||
Expired
|
|
(494
|
)
|
|
88.82
|
|
|
(383
|
)
|
|
104.21
|
|
|
(304
|
)
|
|
76.09
|
|
|||
Outstanding, end of year(1)
|
|
4,298
|
|
|
75.24
|
|
|
4,872
|
|
|
75.95
|
|
|
4,593
|
|
|
83.36
|
|
|||
Expected to vest(2)
|
|
495
|
|
|
49.11
|
|
|
1,274
|
|
|
48.74
|
|
|
947
|
|
|
51.83
|
|
|||
Exercisable, end of year(3)
|
|
3,803
|
|
|
78.64
|
|
|
3,598
|
|
|
85.59
|
|
|
3,646
|
|
|
91.56
|
|
(1)
|
As of December 31, 2019, options outstanding had a weighted average remaining contractual life of 4.1 years and no intrinsic value.
|
(2)
|
As of December 31, 2019, options expected to vest had a weighted average remaining contractual life of 7.8 years and no intrinsic value.
|
(3)
|
As of December 31, 2019, options exercisable had a weighted average remaining contractual life of 3.6 years and no intrinsic value.
|
|
|
2019
|
|
2018
|
|
2017
|
||||
Expected volatility
|
|
N/A
|
|
33.47
|
%
|
|
34.58
|
%
|
||
Expected dividend yields
|
|
N/A
|
|
2.16
|
%
|
|
1.58
|
%
|
||
Expected term (in years)
|
|
N/A
|
|
6
|
|
|
6
|
|
||
Risk-free rate
|
|
N/A
|
|
2.42
|
%
|
|
2.02
|
%
|
||
Weighted-average grant-date fair value
|
|
N/A
|
|
$
|
13.15
|
|
|
$
|
19.38
|
|
|
|
2019
|
|
2018
|
|
2017
|
|||||||||||||||
Stock-settled Restricted Stocks Units
|
|
Shares
|
|
Weighted-
Average Grant-
Date Fair Value
|
|
Shares
|
|
Weighted-
Average Grant- Date Fair Value |
|
Shares
|
|
Weighted-
Average Grant- Date Fair Value |
|||||||||
Non-vested, beginning of year
|
|
3,153
|
|
|
$
|
55.54
|
|
|
4,920
|
|
|
$
|
56.67
|
|
|
6,062
|
|
|
$
|
55.11
|
|
Granted
|
|
1,479
|
|
|
36.81
|
|
|
608
|
|
|
45.59
|
|
|
1,948
|
|
|
62.74
|
|
|||
Vested(3)
|
|
(1,899
|
)
|
|
53.99
|
|
|
(2,023
|
)
|
|
55.10
|
|
|
(2,288
|
)
|
|
58.77
|
|
|||
Forfeited
|
|
(285
|
)
|
|
45.06
|
|
|
(352
|
)
|
|
56.69
|
|
|
(802
|
)
|
|
55.54
|
|
|||
Non-vested, end of year(1)(2)
|
|
2,448
|
|
|
46.65
|
|
|
3,153
|
|
|
55.54
|
|
|
4,920
|
|
|
56.67
|
|
(1)
|
As of December 31, 2019, there was $18 million of total unrecognized compensation cost related to 2,447,910 unvested stock-settled restricted stock units.
|
(2)
|
As of December 31, 2019, the weighted-average remaining life of unvested stock-settled restricted stock units is approximately 0.7 years.
|
(3)
|
The grant date fair values of the stock-settled awards vested during 2019, 2018, and 2017 were approximately $103 million, $111 million, and $135 million, respectively.
|
Cash-settled Restricted Stock Phantom Units(1)
|
|
2019
|
|
2018
|
||
Non-vested, beginning of year
|
|
1,818
|
|
|
59
|
|
Granted(2)
|
|
4,831
|
|
|
1,973
|
|
Vested
|
|
(616
|
)
|
|
(38
|
)
|
Forfeited
|
|
(649
|
)
|
|
(176
|
)
|
Non-vested, end of year(3)
|
|
5,384
|
|
|
1,818
|
|
(1)
|
The Company issued no cash-settled restricted stock phantom units in 2017.
|
(2)
|
The 2019 restricted stock phantom units included 3,401,477 awards based on the per-share market price of Apache’s common stock and 1,429,135 awards based on the per-share market price of ALTM’s common stock.
|
(3)
|
The outstanding liability for the unvested cash-settled restricted stock phantom units that has not been recognized as of December 31, 2019 was approximately $52 million.
|
•
|
In January 2016, the Company’s Board of Directors approved the 2016 Performance Program, pursuant to the 2011 Plan. Eligible employees received initial stock-settled conditional restricted stock unit awards totaling 871,369. The results for the performance period ending December 31, 2018, yielded a payout of 100 percent of target. A total of 325,008 units were outstanding as of December 31, 2019.
|
•
|
In January 2017, the Company’s Board of Directors approved the 2017 Performance Program, pursuant to the 2016 Plan. Eligible employees received initial stock-settled conditional restricted stock unit awards totaling 620,885 units. A total of 455,499 units were outstanding as of December 31, 2019. The results for the performance period yielded a payout of 54 percent of target.
|
•
|
In January 2018, the Company’s Board of Directors approved the 2018 Performance Program, pursuant to the 2016 Plan. Eligible employees received initial cash-settled conditional phantom units totaling 931,049 units. The actual amount of shares awarded will be between zero and 200 percent of target. A total of 796,829 phantom units were outstanding as of December 31, 2019, from which a minimum of zero to a maximum of 1,593,658 phantom units could be awarded.
|
•
|
In January 2019, the Company’s Board of Directors approved the 2019 Performance Program, pursuant to the 2016 Plan. Eligible employees received initial cash-settled conditional phantom units totaling 1,679,832 units. The actual amount of shares awarded will be between zero and 200 percent of target. A total of 1,523,360 phantom units were outstanding as of December 31, 2019, from which a minimum of zero to a maximum of 3,046,720 phantom units could be awarded.
|
Stock-settled Conditional Restricted Stock Units
|
|
Shares
|
|
Weighted
Average Grant-
Date Fair
Value(1)
|
|||
|
|
(In thousands)
|
|
|
|||
Non-vested, beginning of year
|
|
1,347
|
|
|
$
|
49.58
|
|
Granted
|
|
345
|
|
|
32.75
|
|
|
Vested
|
|
(510
|
)
|
|
45.62
|
|
|
Forfeited
|
|
(71
|
)
|
|
53.96
|
|
|
Expired
|
|
(330
|
)
|
|
29.78
|
|
|
Non-vested, end of year(2)(3)
|
|
781
|
|
|
52.69
|
|
(1)
|
The fair value of each conditional restricted stock unit award is estimated as of the date of grant using a Monte Carlo simulation with the following assumptions used for all grants made under the plan: (i) a three-year continuous risk-free interest rate; (ii) a constant volatility assumption based on the historical realized stock price volatility of the Company and the designated peer group; and (iii) the historical stock prices and expected dividends of the common stock of the Company and its designated peer group.
|
(2)
|
As of December 31, 2019, there was $2 million of total unrecognized compensation cost related to 780,507 unvested stock-settled conditional restricted stock units.
|
(3)
|
As of December 31, 2019, the weighted-average remaining life of the unvested stock-settled conditional restricted stock units is approximately 0.3 years.
|
Cash-settled Conditional Restricted Stock Phantom Units
|
|
Phantom Units
|
|
|
|
(In thousands)
|
|
Non-vested, beginning of year
|
|
890
|
|
Granted
|
|
1,680
|
|
Vested
|
|
(2
|
)
|
Forfeited
|
|
(248
|
)
|
Non-vested, end of year(1)
|
|
2,320
|
|
(1)
|
As of December 31, 2019, the outstanding liability for the unvested cash-settled conditional restricted stock units that has not been recognized was approximately $26 million.
|
|
|
As of December 31,
|
||||||||||
|
|
2019
|
|
2018
|
|
2017
|
||||||
|
|
(In millions)
|
||||||||||
Share of equity method interests other comprehensive loss
|
|
$
|
(1
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
Pension and postretirement benefit plan (Note 12)
|
|
17
|
|
|
4
|
|
|
4
|
|
|||
Accumulated other comprehensive income
|
|
$
|
16
|
|
|
$
|
4
|
|
|
$
|
4
|
|
|
|
For the Year Ended December 31,
|
|||||||
|
|
2019
|
|
2018
|
|
2017
|
|||
BP plc(1)
|
|
10
|
%
|
|
17
|
%
|
|
12
|
%
|
China Petroleum & Chemical Corporation (Sinopec)(2)
|
|
11
|
%
|
|
15
|
%
|
|
16
|
%
|
Egyptian General Petroleum Corporation(3)
|
|
9
|
%
|
|
10
|
%
|
|
11
|
%
|
(1)
|
Sales to BP plc were reported as revenue in the Company’s U.S., Egypt, and North Sea upstream segments in the years ended 2019, 2018, and 2017.
|
(2)
|
Sales to Sinopec were reported as revenue in the Company’s Egypt upstream segment in the year ended 2019 and in the Company’s Egypt and North Sea upstream segments in the years ended 2018 and 2017.
|
(3)
|
Sales to EGPC were reported as revenue in the Company’s Egypt upstream segment in the years ended 2019, 2018, and 2017.
|
|
|
Egypt(1)
|
|
North Sea
|
|
U.S.
|
|
Altus Midstream
|
|
Intersegment Eliminations & Other
|
|
Total(2)
|
||||||||||||
|
|
Upstream
|
|
|
|
|||||||||||||||||||
|
|
(In millions)
|
||||||||||||||||||||||
2019
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Oil revenues
|
|
$
|
1,969
|
|
|
$
|
1,163
|
|
|
$
|
2,098
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
5,230
|
|
Natural gas revenues
|
|
295
|
|
|
90
|
|
|
293
|
|
|
—
|
|
|
—
|
|
|
678
|
|
||||||
Natural gas liquids revenues
|
|
12
|
|
|
23
|
|
|
372
|
|
|
—
|
|
|
—
|
|
|
407
|
|
||||||
Oil and gas production revenues
|
|
2,276
|
|
|
1,276
|
|
|
2,763
|
|
|
—
|
|
|
—
|
|
|
6,315
|
|
||||||
Midstream service affiliate revenues
|
|
—
|
|
|
—
|
|
|
—
|
|
|
136
|
|
|
(136
|
)
|
|
—
|
|
||||||
Operating Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Lease operating expenses
|
|
484
|
|
|
320
|
|
|
645
|
|
|
—
|
|
|
(2
|
)
|
|
1,447
|
|
||||||
Gathering, processing, and transmission
|
|
40
|
|
|
45
|
|
|
299
|
|
|
56
|
|
|
(134
|
)
|
|
306
|
|
||||||
Taxes other than income
|
|
—
|
|
|
—
|
|
|
194
|
|
|
13
|
|
|
—
|
|
|
207
|
|
||||||
Exploration
|
|
100
|
|
|
2
|
|
|
688
|
|
|
—
|
|
|
15
|
|
|
805
|
|
||||||
Depreciation, depletion, and amortization
|
|
708
|
|
|
366
|
|
|
1,566
|
|
|
40
|
|
|
—
|
|
|
2,680
|
|
||||||
Asset retirement obligation accretion
|
|
—
|
|
|
76
|
|
|
29
|
|
|
2
|
|
|
—
|
|
|
107
|
|
||||||
Impairments
|
|
—
|
|
|
—
|
|
|
1,648
|
|
|
1,301
|
|
|
—
|
|
|
2,949
|
|
||||||
|
|
1,332
|
|
|
809
|
|
|
5,069
|
|
|
1,412
|
|
|
(121
|
)
|
|
8,501
|
|
||||||
Operating Income (Loss)
|
|
$
|
944
|
|
|
$
|
467
|
|
|
$
|
(2,306
|
)
|
|
$
|
(1,276
|
)
|
|
$
|
(15
|
)
|
|
(2,186
|
)
|
|
Other Income (Expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Gain on divestitures, net
|
|
|
|
|
|
|
|
|
|
|
|
43
|
|
|||||||||||
Other(3)
|
|
|
|
|
|
|
|
|
|
|
|
53
|
|
|||||||||||
General and administrative
|
|
|
|
|
|
|
|
|
|
|
|
(406
|
)
|
|||||||||||
Transaction, reorganization, and separation
|
|
|
|
|
|
|
|
|
|
|
|
(50
|
)
|
|||||||||||
Financing costs, net
|
|
|
|
|
|
|
|
|
|
|
|
(462
|
)
|
|||||||||||
Loss Before Income Taxes
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(3,008
|
)
|
||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Net Property and Equipment
|
|
$
|
2,573
|
|
|
$
|
1,956
|
|
|
$
|
9,385
|
|
|
$
|
206
|
|
|
$
|
38
|
|
|
$
|
14,158
|
|
Total Assets(5)
|
|
$
|
3,700
|
|
|
$
|
2,473
|
|
|
$
|
10,388
|
|
|
$
|
1,479
|
|
|
$
|
67
|
|
|
$
|
18,107
|
|
Additions to Net Property and Equipment
|
|
$
|
454
|
|
|
$
|
183
|
|
|
$
|
1,696
|
|
|
$
|
308
|
|
|
$
|
93
|
|
|
$
|
2,734
|
|
|
|
Egypt(1)
|
|
North Sea
|
|
U.S.
|
|
Altus Midstream
|
|
Intersegment Eliminations & Other
|
|
Total(2)
|
||||||||||||
|
|
Upstream
|
|
|
|
|||||||||||||||||||
|
|
(In millions)
|
||||||||||||||||||||||
2018
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Oil revenues
|
|
$
|
2,396
|
|
|
$
|
1,179
|
|
|
$
|
2,271
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
5,846
|
|
Natural gas revenues
|
|
339
|
|
|
122
|
|
|
458
|
|
|
—
|
|
|
—
|
|
|
919
|
|
||||||
Natural gas liquids revenues
|
|
13
|
|
|
20
|
|
|
550
|
|
|
—
|
|
|
—
|
|
|
583
|
|
||||||
Oil and gas production revenues
|
|
2,748
|
|
|
1,321
|
|
|
3,279
|
|
|
—
|
|
|
—
|
|
|
7,348
|
|
||||||
Midstream service affiliate revenues
|
|
—
|
|
|
—
|
|
|
—
|
|
|
77
|
|
|
(77
|
)
|
|
—
|
|
||||||
Operating Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Lease operating expenses
|
|
428
|
|
|
341
|
|
|
670
|
|
|
—
|
|
|
—
|
|
|
1,439
|
|
||||||
Gathering, processing, and transmission
|
|
47
|
|
|
42
|
|
|
282
|
|
|
54
|
|
|
(77
|
)
|
|
348
|
|
||||||
Taxes other than income
|
|
—
|
|
|
—
|
|
|
207
|
|
|
8
|
|
|
—
|
|
|
215
|
|
||||||
Exploration
|
|
88
|
|
|
192
|
|
|
219
|
|
|
—
|
|
|
4
|
|
|
503
|
|
||||||
Depreciation, depletion, and amortization
|
|
745
|
|
|
375
|
|
|
1,266
|
|
|
19
|
|
|
—
|
|
|
2,405
|
|
||||||
Asset retirement obligation accretion
|
|
—
|
|
|
75
|
|
|
32
|
|
|
1
|
|
|
—
|
|
|
108
|
|
||||||
Impairments
|
|
63
|
|
|
10
|
|
|
438
|
|
|
—
|
|
|
—
|
|
|
511
|
|
||||||
|
|
1,371
|
|
|
1,035
|
|
|
3,114
|
|
|
82
|
|
|
(73
|
)
|
|
5,529
|
|
||||||
Operating Income (Loss)
|
|
$
|
1,377
|
|
|
$
|
286
|
|
|
$
|
165
|
|
|
$
|
(5
|
)
|
|
$
|
(4
|
)
|
|
1,819
|
|
|
Other Income (Expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Gain on divestitures, net
|
|
|
|
|
|
|
|
|
|
|
|
23
|
|
|||||||||||
Other(3)
|
|
|
|
|
|
|
|
|
|
|
|
53
|
|
|||||||||||
General and administrative
|
|
|
|
|
|
|
|
|
|
|
|
(431
|
)
|
|||||||||||
Transaction, reorganization, and separation
|
|
|
|
|
|
|
|
|
|
|
|
(28
|
)
|
|||||||||||
Financing costs, net
|
|
|
|
|
|
|
|
|
|
|
|
(478
|
)
|
|||||||||||
Income Before Income Taxes
|
|
|
|
|
|
|
|
|
|
|
|
$
|
958
|
|
||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Net Property and Equipment
|
|
$
|
2,856
|
|
|
$
|
2,148
|
|
|
$
|
12,145
|
|
|
$
|
1,227
|
|
|
$
|
45
|
|
|
$
|
18,421
|
|
Total Assets(5)
|
|
$
|
4,260
|
|
|
$
|
2,456
|
|
|
$
|
12,962
|
|
|
$
|
1,857
|
|
|
$
|
47
|
|
|
$
|
21,582
|
|
Additions to Net Property and Equipment
|
|
$
|
594
|
|
|
$
|
223
|
|
|
$
|
2,544
|
|
|
$
|
545
|
|
|
$
|
8
|
|
|
$
|
3,914
|
|
|
|
Egypt
|
|
North Sea
|
|
Canada(4)
|
|
U.S.
|
|
Altus Midstream
|
|
Intersegment Eliminations & Other
|
|
Total(2)
|
||||||||||||||
|
|
Upstream
|
|
|
|
|||||||||||||||||||||||
|
|
(In millions)
|
||||||||||||||||||||||||||
2017
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Oil revenues
|
|
$
|
1,901
|
|
|
$
|
971
|
|
|
$
|
110
|
|
|
$
|
1,616
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
4,598
|
|
Natural gas revenues
|
|
395
|
|
|
92
|
|
|
104
|
|
|
368
|
|
|
—
|
|
|
—
|
|
|
959
|
|
|||||||
Natural gas liquids revenues
|
|
11
|
|
|
15
|
|
|
17
|
|
|
287
|
|
|
—
|
|
|
—
|
|
|
330
|
|
|||||||
Oil and gas production revenues
|
|
2,307
|
|
|
1,078
|
|
|
231
|
|
|
2,271
|
|
|
—
|
|
|
—
|
|
|
5,887
|
|
|||||||
Midstream service affiliate revenues
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
15
|
|
|
(15
|
)
|
|
—
|
|
|||||||
Operating Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Lease operating expenses
|
|
362
|
|
|
335
|
|
|
103
|
|
|
584
|
|
|
—
|
|
|
—
|
|
|
1,384
|
|
|||||||
Gathering, processing, and transmission
|
|
44
|
|
|
30
|
|
|
34
|
|
|
86
|
|
|
16
|
|
|
(15
|
)
|
|
195
|
|
|||||||
Taxes other than income
|
|
—
|
|
|
(14
|
)
|
|
12
|
|
|
153
|
|
|
—
|
|
|
—
|
|
|
151
|
|
|||||||
Exploration
|
|
62
|
|
|
86
|
|
|
11
|
|
|
363
|
|
|
—
|
|
|
27
|
|
|
549
|
|
|||||||
Depreciation, depletion, and amortization
|
|
758
|
|
|
446
|
|
|
76
|
|
|
994
|
|
|
6
|
|
|
—
|
|
|
2,280
|
|
|||||||
Asset retirement obligation accretion
|
|
—
|
|
|
72
|
|
|
27
|
|
|
31
|
|
|
—
|
|
|
—
|
|
|
130
|
|
|||||||
Impairments
|
|
—
|
|
|
8
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
8
|
|
|||||||
|
|
1,226
|
|
|
963
|
|
|
263
|
|
|
2,211
|
|
|
22
|
|
|
12
|
|
|
4,697
|
|
|||||||
Operating Income (Loss)
|
|
$
|
1,081
|
|
|
$
|
115
|
|
|
$
|
(32
|
)
|
|
$
|
60
|
|
|
$
|
(7
|
)
|
|
$
|
(27
|
)
|
|
1,190
|
|
|
Other Income (Expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Gain on divestitures, net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
627
|
|
|||||||||||||
Other(3)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(91
|
)
|
|||||||||||||
General and administrative
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(395
|
)
|
|||||||||||||
Transaction, reorganization, and separation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(16
|
)
|
|||||||||||||
Financing costs, net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(397
|
)
|
|||||||||||||
Income Before Income Taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
918
|
|
||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Net Property and Equipment
|
|
$
|
3,099
|
|
|
$
|
2,553
|
|
|
$
|
—
|
|
|
$
|
11,370
|
|
|
$
|
700
|
|
|
$
|
37
|
|
|
$
|
17,759
|
|
Total Assets(5)
|
|
$
|
4,658
|
|
|
$
|
2,977
|
|
|
$
|
—
|
|
|
$
|
13,522
|
|
|
$
|
706
|
|
|
$
|
59
|
|
|
$
|
21,922
|
|
Additions to Net Property and Equipment
|
|
$
|
517
|
|
|
$
|
374
|
|
|
$
|
—
|
|
|
$
|
1,847
|
|
|
$
|
550
|
|
|
$
|
14
|
|
|
$
|
3,302
|
|
(1)
|
Includes revenue from non-customers for the years ended 2019 and 2018 of:
|
|
|
For the Year Ended December 31,
|
||||||
|
|
2019
|
|
2018
|
||||
|
|
(In millions)
|
||||||
Oil
|
|
$
|
410
|
|
|
$
|
592
|
|
Natural gas
|
|
40
|
|
|
58
|
|
||
Natural gas liquids
|
|
1
|
|
|
2
|
|
(2)
|
Includes a noncontrolling interest in Egypt for years 2019, 2018, and 2017, and Altus for the years 2019 and 2018.
|
(3)
|
Included in Other are sales proceeds related to U.S. third-party purchased oil and gas volumes which are determined to be revenue from customers. Proceeds for these volumes totaled $176 million and $357 million for the years ended 2019 and 2018, respectively.
|
(4)
|
During 2017, Apache completed the sale of its Canadian operations. For more information regarding this divestiture, please refer to Note 2—Acquisitions and Divestitures.
|
(5)
|
Intercompany balances are excluded from total assets.
|
|
|
United
States
|
|
Canada(3)
|
|
Egypt(4)
|
|
North Sea
|
|
Other
International
|
|
Total(4)
|
||||||||||||
|
|
(In millions, except per boe)
|
||||||||||||||||||||||
2019
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Oil and gas production revenues
|
|
$
|
2,763
|
|
|
$
|
—
|
|
|
$
|
2,276
|
|
|
$
|
1,276
|
|
|
$
|
—
|
|
|
$
|
6,315
|
|
Operating cost:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Depreciation, depletion, and amortization(1)
|
|
1,508
|
|
|
—
|
|
|
641
|
|
|
363
|
|
|
—
|
|
|
2,512
|
|
||||||
Asset retirement obligation accretion
|
|
29
|
|
|
—
|
|
|
—
|
|
|
76
|
|
|
—
|
|
|
105
|
|
||||||
Lease operating expenses
|
|
645
|
|
|
—
|
|
|
484
|
|
|
320
|
|
|
—
|
|
|
1,449
|
|
||||||
Gathering, processing, and transmission
|
|
299
|
|
|
—
|
|
|
40
|
|
|
45
|
|
|
—
|
|
|
384
|
|
||||||
Exploration expenses
|
|
688
|
|
|
—
|
|
|
100
|
|
|
2
|
|
|
15
|
|
|
805
|
|
||||||
Impairments related to oil and gas properties
|
|
1,633
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,633
|
|
||||||
Production taxes(2)
|
|
191
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
191
|
|
||||||
Income tax
|
|
(468
|
)
|
|
—
|
|
|
455
|
|
|
188
|
|
|
—
|
|
|
175
|
|
||||||
|
|
4,525
|
|
|
—
|
|
|
1,720
|
|
|
994
|
|
|
15
|
|
|
7,254
|
|
||||||
Results of operations
|
|
$
|
(1,762
|
)
|
|
$
|
—
|
|
|
$
|
556
|
|
|
$
|
282
|
|
|
$
|
(15
|
)
|
|
$
|
(939
|
)
|
2018
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Oil and gas production revenues
|
|
$
|
3,279
|
|
|
$
|
—
|
|
|
$
|
2,748
|
|
|
$
|
1,321
|
|
|
$
|
—
|
|
|
$
|
7,348
|
|
Operating cost:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Depreciation, depletion, and amortization(1)
|
|
1,206
|
|
|
—
|
|
|
688
|
|
|
371
|
|
|
—
|
|
|
2,265
|
|
||||||
Asset retirement obligation accretion
|
|
32
|
|
|
—
|
|
|
—
|
|
|
75
|
|
|
—
|
|
|
107
|
|
||||||
Lease operating expenses
|
|
670
|
|
|
—
|
|
|
428
|
|
|
341
|
|
|
—
|
|
|
1,439
|
|
||||||
Gathering, processing, and transmission
|
|
282
|
|
|
—
|
|
|
47
|
|
|
42
|
|
|
—
|
|
|
371
|
|
||||||
Exploration expenses
|
|
219
|
|
|
—
|
|
|
88
|
|
|
192
|
|
|
4
|
|
|
503
|
|
||||||
Impairments related to oil and gas properties
|
|
265
|
|
|
—
|
|
|
63
|
|
|
10
|
|
|
—
|
|
|
338
|
|
||||||
Production taxes(2)
|
|
203
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
203
|
|
||||||
Income tax
|
|
87
|
|
|
—
|
|
|
645
|
|
|
116
|
|
|
—
|
|
|
848
|
|
||||||
|
|
2,964
|
|
|
—
|
|
|
1,959
|
|
|
1,147
|
|
|
4
|
|
|
6,074
|
|
||||||
Results of operations
|
|
$
|
315
|
|
|
$
|
—
|
|
|
$
|
789
|
|
|
$
|
174
|
|
|
$
|
(4
|
)
|
|
$
|
1,274
|
|
2017
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Oil and gas production revenues
|
|
$
|
2,271
|
|
|
$
|
231
|
|
|
$
|
2,307
|
|
|
$
|
1,078
|
|
|
$
|
—
|
|
|
$
|
5,887
|
|
Operating cost:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Depreciation, depletion, and amortization(1)
|
|
924
|
|
|
72
|
|
|
707
|
|
|
433
|
|
|
—
|
|
|
2,136
|
|
||||||
Asset retirement obligation accretion
|
|
31
|
|
|
27
|
|
|
—
|
|
|
72
|
|
|
—
|
|
|
130
|
|
||||||
Lease operating expenses
|
|
584
|
|
|
103
|
|
|
362
|
|
|
335
|
|
|
—
|
|
|
1,384
|
|
||||||
Gathering, processing, and transmission
|
|
86
|
|
|
34
|
|
|
44
|
|
|
30
|
|
|
—
|
|
|
194
|
|
||||||
Exploration expenses
|
|
363
|
|
|
11
|
|
|
62
|
|
|
86
|
|
|
27
|
|
|
549
|
|
||||||
Production taxes(2)
|
|
153
|
|
|
11
|
|
|
—
|
|
|
(14
|
)
|
|
—
|
|
|
150
|
|
||||||
Income tax
|
|
45
|
|
|
(7
|
)
|
|
509
|
|
|
54
|
|
|
—
|
|
|
601
|
|
||||||
|
|
2,186
|
|
|
251
|
|
|
1,684
|
|
|
996
|
|
|
27
|
|
|
5,144
|
|
||||||
Results of operations
|
|
$
|
85
|
|
|
$
|
(20
|
)
|
|
$
|
623
|
|
|
$
|
82
|
|
|
$
|
(27
|
)
|
|
$
|
743
|
|
(1)
|
This amount only reflects DD&A of capitalized costs of oil and gas properties and, therefore, does not agree with DD&A reflected on Note 17—Business Segment Information.
|
(2)
|
Only reflects amounts directly related to oil and gas producing properties and, therefore, does not agree with taxes other than income reflected on Note 17—Business Segment Information.
|
(3)
|
During the third quarter of 2017, Apache completed the sale of its Canadian operations. For more information regarding this divestiture, please refer to Note 2—Acquisitions and Divestitures
|
(4)
|
Includes noncontrolling interest in Egypt.
|
|
|
United
States
|
|
Canada
|
|
Egypt(2)
|
|
North Sea
|
|
Other
International
|
|
Total(2)
|
||||||||||||
|
|
(In millions)
|
||||||||||||||||||||||
2019
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Acquisitions:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Proved
|
|
$
|
3
|
|
|
$
|
—
|
|
|
$
|
5
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
8
|
|
Unproved
|
|
47
|
|
|
—
|
|
|
10
|
|
|
—
|
|
|
—
|
|
|
57
|
|
||||||
Exploration
|
|
162
|
|
|
—
|
|
|
139
|
|
|
62
|
|
|
105
|
|
|
468
|
|
||||||
Development
|
|
1,500
|
|
|
—
|
|
|
374
|
|
|
119
|
|
|
3
|
|
|
1,996
|
|
||||||
Costs incurred(1)
|
|
$
|
1,712
|
|
|
$
|
—
|
|
|
$
|
528
|
|
|
$
|
181
|
|
|
$
|
108
|
|
|
$
|
2,529
|
|
(1) Includes capitalized interest and asset retirement costs as follows:
|
|
|
|
|
|
|||||||||||||||||||
Capitalized interest
|
|
$
|
23
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
5
|
|
|
$
|
4
|
|
|
$
|
32
|
|
Asset retirement costs
|
|
14
|
|
|
—
|
|
|
—
|
|
|
(111
|
)
|
|
—
|
|
|
(97
|
)
|
||||||
2018
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Acquisitions:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Proved
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
6
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
6
|
|
Unproved
|
|
111
|
|
|
—
|
|
|
16
|
|
|
—
|
|
|
—
|
|
|
127
|
|
||||||
Exploration
|
|
640
|
|
|
—
|
|
|
175
|
|
|
113
|
|
|
12
|
|
|
940
|
|
||||||
Development
|
|
1,791
|
|
|
—
|
|
|
457
|
|
|
133
|
|
|
—
|
|
|
2,381
|
|
||||||
Costs incurred(1)
|
|
$
|
2,542
|
|
|
$
|
—
|
|
|
$
|
654
|
|
|
$
|
246
|
|
|
$
|
12
|
|
|
$
|
3,454
|
|
(1) Includes capitalized interest and asset retirement costs as follows:
|
|
|
|
|||||||||||||||||||||
Capitalized interest
|
|
$
|
23
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
11
|
|
|
$
|
2
|
|
|
$
|
36
|
|
Asset retirement costs
|
|
93
|
|
|
—
|
|
|
—
|
|
|
(62
|
)
|
|
—
|
|
|
31
|
|
||||||
2017
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Acquisitions:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Proved
|
|
$
|
3
|
|
|
$
|
—
|
|
|
$
|
4
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
7
|
|
Unproved
|
|
136
|
|
|
5
|
|
|
40
|
|
|
—
|
|
|
—
|
|
|
181
|
|
||||||
Exploration
|
|
602
|
|
|
11
|
|
|
122
|
|
|
131
|
|
|
25
|
|
|
891
|
|
||||||
Development
|
|
1,118
|
|
|
52
|
|
|
387
|
|
|
250
|
|
|
—
|
|
|
1,807
|
|
||||||
Costs incurred(1)
|
|
$
|
1,859
|
|
|
$
|
68
|
|
|
$
|
553
|
|
|
$
|
381
|
|
|
$
|
25
|
|
|
$
|
2,886
|
|
(1) Includes capitalized interest and asset retirement costs as follows:
|
|
|
||||||||||||||||||||||
Capitalized interest
|
|
$
|
23
|
|
|
$
|
2
|
|
|
$
|
—
|
|
|
$
|
17
|
|
|
$
|
2
|
|
|
$
|
44
|
|
Asset retirement costs
|
|
15
|
|
|
—
|
|
|
—
|
|
|
55
|
|
|
—
|
|
|
70
|
|
||||||
(2) Includes a noncontrolling interest in Egypt.
|
|
|
United
States
|
|
Egypt(1)
|
|
North
Sea
|
|
Other
International
|
|
Total(1)
|
||||||||||
|
|
(In millions)
|
||||||||||||||||||
2019
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Proved properties
|
|
$
|
20,291
|
|
|
$
|
11,614
|
|
|
$
|
8,635
|
|
|
$
|
—
|
|
|
$
|
40,540
|
|
Unproved properties
|
|
509
|
|
|
109
|
|
|
10
|
|
|
38
|
|
|
666
|
|
|||||
|
|
20,800
|
|
|
11,723
|
|
|
8,645
|
|
|
38
|
|
|
41,206
|
|
|||||
Accumulated DD&A
|
|
(11,783
|
)
|
|
(9,377
|
)
|
|
(6,700
|
)
|
|
—
|
|
|
(27,860
|
)
|
|||||
|
|
$
|
9,017
|
|
|
$
|
2,346
|
|
|
$
|
1,945
|
|
|
$
|
38
|
|
|
$
|
13,346
|
|
2018
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Proved properties
|
|
$
|
22,699
|
|
|
$
|
11,184
|
|
|
$
|
8,462
|
|
|
$
|
—
|
|
|
$
|
42,345
|
|
Unproved properties
|
|
1,275
|
|
|
110
|
|
|
5
|
|
|
45
|
|
|
1,435
|
|
|||||
|
|
23,974
|
|
|
11,294
|
|
|
8,467
|
|
|
45
|
|
|
43,780
|
|
|||||
Accumulated DD&A
|
|
(12,217
|
)
|
|
(8,736
|
)
|
|
(6,332
|
)
|
|
—
|
|
|
(27,285
|
)
|
|||||
|
|
$
|
11,757
|
|
|
$
|
2,558
|
|
|
$
|
2,135
|
|
|
$
|
45
|
|
|
$
|
16,495
|
|
(1) Includes a noncontrolling interest in Egypt.
|
|
|
|
|
|
|
Crude Oil and Condensate
|
|||||||||||||
|
|
(Thousands of barrels)
|
|||||||||||||
|
|
United
States
|
|
Canada
|
|
Egypt(1)
|
|
North
Sea
|
|
Total(1)
|
|||||
Proved developed reserves:
|
|
|
|
|
|
|
|
|
|
|
|||||
December 31, 2016
|
|
300,900
|
|
|
51,508
|
|
|
138,771
|
|
|
91,138
|
|
|
582,317
|
|
December 31, 2017
|
|
304,279
|
|
|
—
|
|
|
124,568
|
|
|
92,598
|
|
|
521,445
|
|
December 31, 2018
|
|
300,484
|
|
|
—
|
|
|
110,014
|
|
|
104,491
|
|
|
514,989
|
|
December 31, 2019
|
|
278,145
|
|
|
—
|
|
|
103,573
|
|
|
101,712
|
|
|
483,430
|
|
Proved undeveloped reserves:
|
|
|
|
|
|
|
|
|
|
|
|||||
December 31, 2016
|
|
21,088
|
|
|
7,906
|
|
|
20,187
|
|
|
10,784
|
|
|
59,965
|
|
December 31, 2017
|
|
31,904
|
|
|
—
|
|
|
16,198
|
|
|
14,013
|
|
|
62,115
|
|
December 31, 2018
|
|
45,182
|
|
|
—
|
|
|
9,484
|
|
|
11,278
|
|
|
65,944
|
|
December 31, 2019
|
|
46,716
|
|
|
—
|
|
|
10,831
|
|
|
10,049
|
|
|
67,596
|
|
Total proved reserves:
|
|
|
|
|
|
|
|
|
|
|
|||||
Balance December 31, 2016
|
|
321,988
|
|
|
59,414
|
|
|
158,958
|
|
|
101,922
|
|
|
642,282
|
|
Extensions, discoveries and other additions
|
|
48,391
|
|
|
14,025
|
|
|
27,140
|
|
|
16,023
|
|
|
105,579
|
|
Purchases of minerals in-place
|
|
46
|
|
|
375
|
|
|
—
|
|
|
—
|
|
|
421
|
|
Revisions of previous estimates
|
|
825
|
|
|
1,829
|
|
|
(9,839
|
)
|
|
6,510
|
|
|
(675
|
)
|
Production
|
|
(33,394
|
)
|
|
(2,425
|
)
|
|
(35,493
|
)
|
|
(17,844
|
)
|
|
(89,156
|
)
|
Sales of minerals in-place
|
|
(1,673
|
)
|
|
(73,218
|
)
|
|
—
|
|
|
—
|
|
|
(74,891
|
)
|
Balance December 31, 2017
|
|
336,183
|
|
|
—
|
|
|
140,766
|
|
|
106,611
|
|
|
583,560
|
|
Extensions, discoveries and other additions
|
|
61,976
|
|
|
—
|
|
|
22,473
|
|
|
15,682
|
|
|
100,131
|
|
Purchases of minerals in-place
|
|
140
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
140
|
|
Revisions of previous estimates
|
|
(14,334
|
)
|
|
—
|
|
|
(9,556
|
)
|
|
10,613
|
|
|
(13,277
|
)
|
Production
|
|
(38,252
|
)
|
|
—
|
|
|
(34,185
|
)
|
|
(17,137
|
)
|
|
(89,574
|
)
|
Sales of minerals in-place
|
|
(47
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(47
|
)
|
Balance December 31, 2018
|
|
345,666
|
|
|
—
|
|
|
119,498
|
|
|
115,769
|
|
|
580,933
|
|
Extensions, discoveries and other additions
|
|
52,297
|
|
|
—
|
|
|
21,039
|
|
|
9,017
|
|
|
82,353
|
|
Purchases of minerals in-place
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Revisions of previous estimates
|
|
(16,446
|
)
|
|
—
|
|
|
4,752
|
|
|
5,132
|
|
|
(6,562
|
)
|
Production
|
|
(38,344
|
)
|
|
—
|
|
|
(30,885
|
)
|
|
(18,157
|
)
|
|
(87,386
|
)
|
Sales of minerals in-place
|
|
(18,312
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(18,312
|
)
|
Balance December 31, 2019
|
|
324,861
|
|
|
—
|
|
|
114,404
|
|
|
111,761
|
|
|
551,026
|
|
(1)
|
2019, 2018, 2017, and 2016 includes proved reserves of 38 MMbbls, 40 MMbbls, 47 MMbbls, and 53 MMbbls, respectively, attributable to a noncontrolling interest in Egypt.
|
|
|
Natural Gas Liquids
|
|||||||||||||
|
|
(Thousands of barrels)
|
|||||||||||||
|
|
United
States
|
|
Canada
|
|
Egypt(1)
|
|
North
Sea
|
|
Total(1)
|
|||||
Proved developed reserves:
|
|
|
|
|
|
|
|
|
|
|
|||||
December 31, 2016
|
|
155,124
|
|
|
13,866
|
|
|
1,266
|
|
|
1,627
|
|
|
171,883
|
|
December 31, 2017
|
|
171,005
|
|
|
—
|
|
|
685
|
|
|
2,025
|
|
|
173,715
|
|
December 31, 2018
|
|
197,574
|
|
|
—
|
|
|
502
|
|
|
1,938
|
|
|
200,014
|
|
December 31, 2019
|
|
158,794
|
|
|
—
|
|
|
667
|
|
|
2,317
|
|
|
161,778
|
|
Proved undeveloped reserves:
|
|
|
|
|
|
|
|
|
|
|
|||||
December 31, 2016
|
|
17,311
|
|
|
2,473
|
|
|
131
|
|
|
646
|
|
|
20,561
|
|
December 31, 2017
|
|
29,559
|
|
|
—
|
|
|
39
|
|
|
353
|
|
|
29,951
|
|
December 31, 2018
|
|
33,796
|
|
|
—
|
|
|
60
|
|
|
631
|
|
|
34,487
|
|
December 31, 2019
|
|
23,569
|
|
|
—
|
|
|
90
|
|
|
660
|
|
|
24,319
|
|
Total proved reserves:
|
|
|
|
|
|
|
|
|
|
|
|||||
Balance December 31, 2016
|
|
172,435
|
|
|
16,339
|
|
|
1,397
|
|
|
2,273
|
|
|
192,444
|
|
Extensions, discoveries and other additions
|
|
33,806
|
|
|
1,794
|
|
|
50
|
|
|
845
|
|
|
36,495
|
|
Purchases of minerals in-place
|
|
206
|
|
|
199
|
|
|
—
|
|
|
—
|
|
|
405
|
|
Revisions of previous estimates
|
|
12,982
|
|
|
(1,060
|
)
|
|
(425
|
)
|
|
(321
|
)
|
|
11,176
|
|
Production
|
|
(17,766
|
)
|
|
(1,032
|
)
|
|
(298
|
)
|
|
(419
|
)
|
|
(19,515
|
)
|
Sales of minerals in-place
|
|
(1,099
|
)
|
|
(16,240
|
)
|
|
—
|
|
|
—
|
|
|
(17,339
|
)
|
Balance December 31, 2017
|
|
200,564
|
|
|
—
|
|
|
724
|
|
|
2,378
|
|
|
203,666
|
|
Extensions, discoveries and other additions
|
|
60,990
|
|
|
—
|
|
|
144
|
|
|
1,444
|
|
|
62,578
|
|
Purchases of minerals in-place
|
|
40
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
40
|
|
Revisions of previous estimates
|
|
(9,250
|
)
|
|
—
|
|
|
31
|
|
|
(819
|
)
|
|
(10,038
|
)
|
Production
|
|
(20,969
|
)
|
|
—
|
|
|
(337
|
)
|
|
(434
|
)
|
|
(21,740
|
)
|
Sales of minerals in-place
|
|
(5
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(5
|
)
|
Balance December 31, 2018
|
|
231,370
|
|
|
—
|
|
|
562
|
|
|
2,569
|
|
|
234,501
|
|
Extensions, discoveries and other additions
|
|
41,343
|
|
|
—
|
|
|
27
|
|
|
697
|
|
|
42,067
|
|
Purchases of minerals in-place
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Revisions of previous estimates
|
|
(32,569
|
)
|
|
—
|
|
|
508
|
|
|
345
|
|
|
(31,716
|
)
|
Production
|
|
(24,959
|
)
|
|
—
|
|
|
(340
|
)
|
|
(634
|
)
|
|
(25,933
|
)
|
Sales of minerals in-place
|
|
(32,822
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(32,822
|
)
|
Balance December 31, 2019
|
|
182,363
|
|
|
—
|
|
|
757
|
|
|
2,977
|
|
|
186,097
|
|
|
|
Natural Gas
|
|||||||||||||
|
|
(Millions of cubic feet)
|
|||||||||||||
|
|
United
States
|
|
Canada
|
|
Egypt(1)
|
|
North
Sea
|
|
Total(1)
|
|||||
Proved developed reserves:
|
|
|
|
|
|
|
|
|
|
|
|||||
December 31, 2016
|
|
1,200,379
|
|
|
553,724
|
|
|
675,559
|
|
|
86,948
|
|
|
2,516,610
|
|
December 31, 2017
|
|
1,347,009
|
|
|
—
|
|
|
540,667
|
|
|
83,342
|
|
|
1,971,018
|
|
December 31, 2018
|
|
1,626,403
|
|
|
—
|
|
|
476,132
|
|
|
95,347
|
|
|
2,197,882
|
|
December 31, 2019
|
|
945,938
|
|
|
—
|
|
|
433,382
|
|
|
106,329
|
|
|
1,485,649
|
|
Proved undeveloped reserves:
|
|
|
|
|
|
|
|
|
|
|
|||||
December 31, 2016
|
|
231,304
|
|
|
45,312
|
|
|
42,109
|
|
|
23,813
|
|
|
342,538
|
|
December 31, 2017
|
|
297,226
|
|
|
—
|
|
|
47,255
|
|
|
11,063
|
|
|
355,544
|
|
December 31, 2018
|
|
267,090
|
|
|
—
|
|
|
33,006
|
|
|
15,804
|
|
|
315,900
|
|
December 31, 2019
|
|
115,040
|
|
|
—
|
|
|
24,704
|
|
|
16,604
|
|
|
156,348
|
|
Total proved reserves:
|
|
|
|
|
|
|
|
|
|
|
|||||
Balance December 31, 2016
|
|
1,431,683
|
|
|
599,036
|
|
|
717,668
|
|
|
110,761
|
|
|
2,859,148
|
|
Extensions, discoveries and other additions
|
|
378,747
|
|
|
49,780
|
|
|
81,245
|
|
|
17,646
|
|
|
527,418
|
|
Purchases of minerals in-place
|
|
4,434
|
|
|
4,319
|
|
|
—
|
|
|
—
|
|
|
8,753
|
|
Revisions of previous estimates
|
|
(5,431
|
)
|
|
92,207
|
|
|
(70,030
|
)
|
|
(17,387
|
)
|
|
(641
|
)
|
Production
|
|
(143,943
|
)
|
|
(47,990
|
)
|
|
(140,961
|
)
|
|
(16,615
|
)
|
|
(349,509
|
)
|
Sales of minerals in-place
|
|
(21,255
|
)
|
|
(697,352
|
)
|
|
—
|
|
|
—
|
|
|
(718,607
|
)
|
Balance December 31, 2017
|
|
1,644,235
|
|
|
—
|
|
|
587,922
|
|
|
94,405
|
|
|
2,326,562
|
|
Extensions, discoveries and other additions
|
|
704,135
|
|
|
—
|
|
|
79,394
|
|
|
55,274
|
|
|
838,803
|
|
Purchases of minerals in-place
|
|
906
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
906
|
|
Revisions of previous estimates
|
|
(239,204
|
)
|
|
—
|
|
|
(38,892
|
)
|
|
(21,933
|
)
|
|
(300,029
|
)
|
Production
|
|
(216,538
|
)
|
|
—
|
|
|
(119,286
|
)
|
|
(16,595
|
)
|
|
(352,419
|
)
|
Sales of minerals in-place
|
|
(41
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(41
|
)
|
Balance December 31, 2018
|
|
1,893,493
|
|
|
—
|
|
|
509,138
|
|
|
111,151
|
|
|
2,513,782
|
|
Extensions, discoveries and other additions
|
|
249,205
|
|
|
—
|
|
|
34,758
|
|
|
27,711
|
|
|
311,674
|
|
Purchases of minerals in-place
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Revisions of previous estimates
|
|
(509,753
|
)
|
|
—
|
|
|
18,570
|
|
|
4,015
|
|
|
(487,168
|
)
|
Production
|
|
(233,447
|
)
|
|
—
|
|
|
(104,380
|
)
|
|
(19,944
|
)
|
|
(357,771
|
)
|
Sales of minerals in-place
|
|
(338,520
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(338,520
|
)
|
Balance December 31, 2019
|
|
1,060,978
|
|
|
—
|
|
|
458,086
|
|
|
122,933
|
|
|
1,641,997
|
|
|
|
Total Equivalent Reserves
|
|||||||||||||
|
|
(Thousands barrels of oil equivalent)
|
|||||||||||||
|
|
United
States
|
|
Canada
|
|
Egypt(1)
|
|
North
Sea
|
|
Total(1)
|
|||||
Proved developed reserves:
|
|
|
|
|
|
|
|
|
|
|
|||||
December 31, 2016
|
|
656,087
|
|
|
157,662
|
|
|
252,630
|
|
|
107,256
|
|
|
1,173,635
|
|
December 31, 2017
|
|
699,786
|
|
|
—
|
|
|
215,364
|
|
|
108,513
|
|
|
1,023,663
|
|
December 31, 2018
|
|
769,125
|
|
|
—
|
|
|
189,871
|
|
|
122,320
|
|
|
1,081,316
|
|
December 31, 2019
|
|
594,595
|
|
|
—
|
|
|
176,470
|
|
|
121,751
|
|
|
892,816
|
|
Proved undeveloped reserves:
|
|
|
|
|
|
|
|
|
|
|
|||||
December 31, 2016
|
|
76,950
|
|
|
17,931
|
|
|
27,336
|
|
|
15,399
|
|
|
137,616
|
|
December 31, 2017
|
|
111,001
|
|
|
—
|
|
|
24,112
|
|
|
16,210
|
|
|
151,323
|
|
December 31, 2018
|
|
123,493
|
|
|
—
|
|
|
15,045
|
|
|
14,543
|
|
|
153,081
|
|
December 31, 2019
|
|
89,458
|
|
|
—
|
|
|
15,038
|
|
|
13,476
|
|
|
117,972
|
|
Total proved reserves:
|
|
|
|
|
|
|
|
|
|
|
|||||
Balance December 31, 2016
|
|
733,037
|
|
|
175,593
|
|
|
279,966
|
|
|
122,655
|
|
|
1,311,251
|
|
Extensions, discoveries and other additions
|
|
145,322
|
|
|
24,115
|
|
|
40,731
|
|
|
19,809
|
|
|
229,977
|
|
Purchases of minerals in-place
|
|
991
|
|
|
1,294
|
|
|
—
|
|
|
—
|
|
|
2,285
|
|
Revisions of previous estimates
|
|
12,903
|
|
|
16,136
|
|
|
(21,936
|
)
|
|
3,291
|
|
|
10,394
|
|
Production
|
|
(75,151
|
)
|
|
(11,455
|
)
|
|
(59,285
|
)
|
|
(21,032
|
)
|
|
(166,923
|
)
|
Sales of minerals in-place
|
|
(6,315
|
)
|
|
(205,683
|
)
|
|
—
|
|
|
—
|
|
|
(211,998
|
)
|
Balance December 31, 2017
|
|
810,787
|
|
|
—
|
|
|
239,476
|
|
|
124,723
|
|
|
1,174,986
|
|
Extensions, discoveries and other additions
|
|
240,322
|
|
|
—
|
|
|
35,849
|
|
|
26,338
|
|
|
302,509
|
|
Purchases of minerals in-place
|
|
331
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
331
|
|
Revisions of previous estimates
|
|
(63,451
|
)
|
|
—
|
|
|
(16,007
|
)
|
|
6,139
|
|
|
(73,319
|
)
|
Production
|
|
(95,312
|
)
|
|
—
|
|
|
(54,402
|
)
|
|
(20,337
|
)
|
|
(170,051
|
)
|
Sales of minerals in-place
|
|
(59
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(59
|
)
|
Balance December 31, 2018
|
|
892,618
|
|
|
—
|
|
|
204,916
|
|
|
136,863
|
|
|
1,234,397
|
|
Extensions, discoveries and other additions
|
|
135,174
|
|
|
—
|
|
|
26,859
|
|
|
14,333
|
|
|
176,366
|
|
Purchases of minerals in-place
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Revisions of previous estimates
|
|
(133,974
|
)
|
|
—
|
|
|
8,355
|
|
|
6,146
|
|
|
(119,473
|
)
|
Production
|
|
(102,211
|
)
|
|
—
|
|
|
(48,622
|
)
|
|
(22,115
|
)
|
|
(172,948
|
)
|
Sales of minerals in-place
|
|
(107,554
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(107,554
|
)
|
Balance December 31, 2019
|
|
684,053
|
|
|
—
|
|
|
191,508
|
|
|
135,227
|
|
|
1,010,788
|
|
|
|
United
States
|
|
Egypt(2)
|
|
North
Sea
|
|
Total(2)
|
||||||||
|
|
(In millions)
|
||||||||||||||
2019
|
|
|
|
|
|
|
|
|
||||||||
Cash inflows
|
|
$
|
21,694
|
|
|
$
|
8,306
|
|
|
$
|
7,454
|
|
|
$
|
37,454
|
|
Production costs
|
|
(10,642
|
)
|
|
(1,847
|
)
|
|
(2,730
|
)
|
|
(15,219
|
)
|
||||
Development costs
|
|
(1,740
|
)
|
|
(707
|
)
|
|
(2,651
|
)
|
|
(5,098
|
)
|
||||
Income tax expense
|
|
(27
|
)
|
|
(1,930
|
)
|
|
(784
|
)
|
|
(2,741
|
)
|
||||
Net cash flows
|
|
9,285
|
|
|
3,822
|
|
|
1,289
|
|
|
14,396
|
|
||||
10 percent discount rate
|
|
(4,003
|
)
|
|
(808
|
)
|
|
297
|
|
|
(4,514
|
)
|
||||
Discounted future net cash flows(1)
|
|
$
|
5,282
|
|
|
$
|
3,014
|
|
|
$
|
1,586
|
|
|
$
|
9,882
|
|
2018
|
|
|
|
|
|
|
|
|
||||||||
Cash inflows
|
|
$
|
29,906
|
|
|
$
|
9,866
|
|
|
$
|
9,206
|
|
|
$
|
48,978
|
|
Production costs
|
|
(13,699
|
)
|
|
(1,799
|
)
|
|
(2,588
|
)
|
|
(18,086
|
)
|
||||
Development costs
|
|
(2,150
|
)
|
|
(792
|
)
|
|
(2,714
|
)
|
|
(5,656
|
)
|
||||
Income tax expense
|
|
(19
|
)
|
|
(2,455
|
)
|
|
(1,352
|
)
|
|
(3,826
|
)
|
||||
Net cash flows
|
|
14,038
|
|
|
4,820
|
|
|
2,552
|
|
|
21,410
|
|
||||
10 percent discount rate
|
|
(6,516
|
)
|
|
(1,066
|
)
|
|
(107
|
)
|
|
(7,689
|
)
|
||||
Discounted future net cash flows(1)
|
|
$
|
7,522
|
|
|
$
|
3,754
|
|
|
$
|
2,445
|
|
|
$
|
13,721
|
|
2017
|
|
|
|
|
|
|
|
|
||||||||
Cash inflows
|
|
$
|
24,271
|
|
|
$
|
9,254
|
|
|
$
|
6,230
|
|
|
$
|
39,755
|
|
Production costs
|
|
(10,618
|
)
|
|
(1,749
|
)
|
|
(2,459
|
)
|
|
(14,826
|
)
|
||||
Development costs
|
|
(1,659
|
)
|
|
(1,052
|
)
|
|
(2,795
|
)
|
|
(5,506
|
)
|
||||
Income tax expense
|
|
(42
|
)
|
|
(2,078
|
)
|
|
(353
|
)
|
|
(2,473
|
)
|
||||
Net cash flows
|
|
11,952
|
|
|
4,375
|
|
|
623
|
|
|
16,950
|
|
||||
10 percent discount rate
|
|
(6,080
|
)
|
|
(1,034
|
)
|
|
247
|
|
|
(6,867
|
)
|
||||
Discounted future net cash flows(1)
|
|
$
|
5,872
|
|
|
$
|
3,341
|
|
|
$
|
870
|
|
|
$
|
10,083
|
|
(1)
|
Estimated future net cash flows before income tax expense, discounted at 10 percent per annum, totaled approximately $12.4 billion, $16.9 billion, and $12.2 billion as of December 31, 2019, 2018, and 2017, respectively.
|
(2)
|
Includes discounted future net cash flows of approximately $1.0 billion, $1.3 billion, and $1.1 billion in 2019, 2018, and 2017, respectively, attributable to a noncontrolling interest in Egypt.
|
|
|
For the Year Ended December 31,
|
||||||||||
|
|
2019
|
|
2018
|
|
2017
|
||||||
|
|
(In millions)
|
||||||||||
Sales, net of production costs
|
|
$
|
(4,291
|
)
|
|
$
|
(5,335
|
)
|
|
$
|
(4,158
|
)
|
Net change in prices and production costs
|
|
(3,034
|
)
|
|
3,902
|
|
|
3,651
|
|
|||
Discoveries and improved recovery, net of related costs
|
|
2,042
|
|
|
3,889
|
|
|
2,273
|
|
|||
Change in future development costs
|
|
(75
|
)
|
|
47
|
|
|
(279
|
)
|
|||
Previously estimated development costs incurred during the period
|
|
983
|
|
|
910
|
|
|
719
|
|
|||
Revision of quantities
|
|
(741
|
)
|
|
(648
|
)
|
|
(344
|
)
|
|||
Purchases of minerals in-place
|
|
—
|
|
|
6
|
|
|
9
|
|
|||
Accretion of discount
|
|
1,693
|
|
|
1,216
|
|
|
952
|
|
|||
Change in income taxes
|
|
720
|
|
|
(1,125
|
)
|
|
(617
|
)
|
|||
Sales of minerals in-place
|
|
(817
|
)
|
|
(1
|
)
|
|
(809
|
)
|
|||
Change in production rates and other
|
|
(319
|
)
|
|
777
|
|
|
626
|
|
|||
|
|
$
|
(3,839
|
)
|
|
$
|
3,638
|
|
|
$
|
2,023
|
|
|
|
First
|
|
Second
|
|
Third
|
|
Fourth
|
||||||||
|
|
(In millions, except per share amounts)
|
||||||||||||||
2019
|
|
|
|
|
|
|
|
|
||||||||
Oil and gas production revenues
|
|
$
|
1,654
|
|
|
$
|
1,598
|
|
|
$
|
1,438
|
|
|
$
|
1,625
|
|
Operating income (loss)(1)
|
|
408
|
|
|
124
|
|
|
175
|
|
|
(2,893
|
)
|
||||
Net income (loss) before income taxes
|
|
165
|
|
|
(152
|
)
|
|
14
|
|
|
(3,035
|
)
|
||||
Net loss including noncontrolling interests
|
|
(2
|
)
|
|
(316
|
)
|
|
(117
|
)
|
|
(3,247
|
)
|
||||
Net loss attributable to common stock
|
|
(47
|
)
|
|
(360
|
)
|
|
(170
|
)
|
|
(2,976
|
)
|
||||
Net loss per common share(2):
|
|
|
|
|
|
|
|
|
||||||||
Basic
|
|
$
|
(0.12
|
)
|
|
$
|
(0.96
|
)
|
|
$
|
(0.45
|
)
|
|
$
|
(7.89
|
)
|
Diluted
|
|
$
|
(0.12
|
)
|
|
$
|
(0.96
|
)
|
|
$
|
(0.45
|
)
|
|
$
|
(7.89
|
)
|
2018
|
|
|
|
|
|
|
|
|
||||||||
Oil and gas production revenues
|
|
$
|
1,733
|
|
|
$
|
1,936
|
|
|
$
|
1,976
|
|
|
$
|
1,703
|
|
Operating income (loss)(1)
|
|
587
|
|
|
738
|
|
|
698
|
|
|
(204
|
)
|
||||
Net income (loss) before income taxes
|
|
388
|
|
|
508
|
|
|
406
|
|
|
(344
|
)
|
||||
Net income (loss) including noncontrolling interests
|
|
206
|
|
|
269
|
|
|
161
|
|
|
(350
|
)
|
||||
Net income (loss) attributable to common stock
|
|
145
|
|
|
195
|
|
|
81
|
|
|
(381
|
)
|
||||
Net income (loss) per common share(2):
|
|
|
|
|
|
|
|
|
||||||||
Basic
|
|
$
|
0.38
|
|
|
$
|
0.51
|
|
|
$
|
0.21
|
|
|
$
|
(1.00
|
)
|
Diluted
|
|
$
|
0.38
|
|
|
$
|
0.51
|
|
|
$
|
0.21
|
|
|
$
|
(1.00
|
)
|
(1)
|
Operating expenses for 2019 include asset and leasehold impairments totaling $23 million, $279 million, $21 million, and $3.2 billion in the first, second, third, and fourth quarters of 2019, respectively. Operating expenses for 2018 include asset and leasehold impairments totaling $16 million, $21 million, $49 million, and $639 million in the first, second, third, and fourth quarters of 2018, respectively.
|
(2)
|
The sum of the individual quarterly net income (loss) per common share amounts may not agree with full-year net income (loss) per common share as each quarterly computation is based on the weighted-average number of common shares outstanding during that period.
|
•
|
liens existing on the date of the Indenture or provided for under the terms of agreements existing on the date of the Indenture;
|
•
|
liens securing all or part of the cost of exploring, producing, gathering, processing, marketing, drilling or developing any of our or our subsidiaries’ properties, or securing indebtedness incurred to provide funds therefor or indebtedness incurred to finance all or part of the cost of acquiring,
|
•
|
liens securing only indebtedness owed by one of our subsidiaries to us or to one or more of our subsidiaries;
|
•
|
liens on the property of any corporation or other entity existing at the time it becomes our subsidiary;
|
•
|
liens on any property to secure indebtedness incurred in connection with the construction, installation or financing of pollution control or abatement facilities or other forms of industrial revenue bond financing or indebtedness issued or guaranteed by the United States or any state or any department, agency or instrumentality of either or indebtedness issued to or guaranteed for the benefit of a foreign government or any state or any department, agency or instrumentality of either or an international finance agency or any division or department thereof, including the World Bank, the International Finance Corp. and the Multilateral Investment Guarantee Agency;
|
•
|
any extension, renewal or replacement or successive extensions, renewals or replacements of any lien referred to in the foregoing clauses that existed on the date of the Indenture;
|
•
|
certain other liens incurred in the ordinary course of business; or
|
•
|
liens which secure “Limited Recourse Indebtedness,” as defined in the Indenture.
|
•
|
the sale or other transfer of crude oil, natural gas or other petroleum hydrocarbons in place for a period of time until, or in an amount that, the transferee will receive as a result of the transfer a specified amount of money or of crude oil, natural gas or other petroleum hydrocarbons;
|
•
|
the sale or other transfer of any other interest in property of the character commonly referred to as a production payment, overriding royalty, forward sale or similar interest; and
|
•
|
liens required by any contract or statute in order to permit us or one of our subsidiaries to perform any contract or subcontract made by it with or at the request of the U.S. government or any foreign government or international finance agency, any state or any department thereof, or any agency or instrumentality of either, or to secure partial, progress, advance or other payments to us or one of our subsidiaries by any of these entities pursuant to the provisions of any contract or statute.
|
•
|
either we or our subsidiaries would be entitled to create debt secured by a lien on the property to be leased in a principal amount equal to or exceeding the value of that sale/leaseback transaction;
|
•
|
since the date of the Indenture and within a period commencing six months before the consummation of that arrangement and ending six months after the consummation of the arrangement, we or our subsidiaries have expended or will expend for any property — including amounts expended for the acquisition, exploration, drilling or development of the property, and for additions, alterations, improvements and repairs to the property — an amount equal to all or a portion of the net proceeds of that arrangement and we or our subsidiaries designate that amount as a credit against that arrangement, with any amount not being so designated to be applied as set forth in the next item; or
|
•
|
during or immediately after the expiration of the 12 months after the effective date of that transaction, we or any of our other subsidiaries apply to the voluntary defeasance or retirement of the debt securities and or other senior indebtedness, as defined in the Indenture, an amount equal to the greater of the net proceeds of the sale or transfer of the property leased in that transaction or the fair value of the property at the time of entering into the transaction, in either case adjusted to reflect the remaining term of the lease and any amount we utilize as set forth in the prior item. The amount will be reduced by the principal amount of senior indebtedness we voluntarily retire within that 12-month period.
|
•
|
if we fail to pay any interest on the Notes when due, and the failure continues for 30 days;
|
•
|
if we fail to pay principal of or any premium on the Notes when due and payable, either at maturity or otherwise;
|
•
|
if we fail to perform or breach any of the other covenants or warranties in the Indenture or the Notes — other than a covenant or warranty included in the Indenture solely for the benefit of a series of securities other than the Notes — and that breach or failure continues for 60 days after written notice as provided in the Indenture;
|
•
|
if any of our or any of our subsidiaries’ indebtedness, as defined in the Indenture, in excess of an aggregate of $25,000,000 in principal amount is accelerated under any event of default as defined in any mortgage, indenture or instrument and the acceleration has not been rescinded or annulled within 30 days after written notice as provided in the Indenture specifying the event of default and requiring us to cause that acceleration to be rescinded or annulled;
|
•
|
if we or any of our subsidiaries fail to pay, bond or otherwise discharge within 60 days of entry, a judgment, court order or uninsured monetary damage award against us or them in excess of an aggregate of $25,000,000 which is not stayed on appeal or otherwise being appropriately contested in good faith;
|
•
|
certain events of bankruptcy, insolvency or reorganization involving us or any of our subsidiaries; and
|
•
|
any other event of default provided in or pursuant to the Indenture with respect to the Notes.
|
•
|
the event causing the change in control and the date of the event;
|
•
|
the date by which notice of the change in control is required by the Indenture to be given;
|
•
|
the date, 35 business days after the occurrence of the change in control, by which we must purchase the Notes we are obligated to purchase pursuant to the selling holder’s exercise of rights on change in control;
|
•
|
the price we must pay for the Notes we are obligated to purchase;
|
•
|
the name and address of the trustee;
|
•
|
the procedure for surrendering Notes to the trustee or other designated office or agent for payment;
|
•
|
a statement of our obligation to make prompt payment on proper surrender of the Notes;
|
•
|
the procedure for holders’ exercise of rights of sale of the Notes; and
|
•
|
the procedures by which a holder may withdraw the notice after it is given.
|
•
|
any event requiring the filing of any report under or in response to Schedule 13D or 14D-1 pursuant to the Securities Exchange Act of 1934, as amended, disclosing beneficial ownership of either 50% or more of our common stock then outstanding or 50% or more of the voting power of our voting stock then outstanding;
|
•
|
the completion of any sale, transfer, lease, or conveyance of our properties and assets substantially as an entirety to any person or persons that is not our subsidiary, as those terms are defined in the Indenture; or
|
•
|
the completion of a consolidation or merger of us with or into any other person or entity in a transaction in which either we are not the sole surviving corporation or our common stock existing before the transaction is converted into cash, securities or other property and those exchanging our common stock do not, as a result of the transaction, receive either 75% or more of the survivor’s common stock or 75% or more of the voting power of the survivor’s voting stock.
|
•
|
have become due and payable;
|
•
|
will become due and payable within one year; or
|
•
|
are scheduled for redemption within one year.
|
•
|
to defease and be discharged from any and all obligations with respect to the Notes, which is referred to as “legal defeasance”; or
|
•
|
to be released from the obligations with respect to the Notes under the covenants described in “The Indenture Limits Our Ability to Incur Liens” and “The Indenture Limits Our Ability to Engage in Sale/Leaseback Transactions” above or, if provided pursuant to section 301 of the Indenture, the obligations with respect to any other covenant, which is referred to as “covenant defeasance.”
|
•
|
to pay additional amounts, if any, upon the occurrence of certain events of taxation, assessment or governmental charge with respect to payments on the Notes;
|
•
|
to register the transfer or exchange of the Notes;
|
•
|
to replace temporary or mutilated, destroyed, lost or stolen Notes; and
|
•
|
to maintain an office or agency with respect to the Notes and to hold moneys for payment in trust.
|
•
|
the applicable defeasance does not result in a breach or violation of, or constitute a default under, the Indenture or any other material agreement or instrument to which we are a party or by which we are bound;
|
•
|
no default or event of default with respect to the Notes shall have occurred and be continuing on the date of the establishment of the trust; and
|
•
|
we have delivered to the trustee an opinion of counsel to the effect that the holders of the Notes will not recognize income, gain or loss for U.S. federal income tax purposes as a result of the defeasance and will be subject to U.S. federal income tax on the same amounts, in the same manner and at the same times as would have been the case if the defeasance had not occurred, and the opinion of counsel, in the case of legal defeasance, must refer to and be based upon a letter ruling of the Internal Revenue Service received by us, a Revenue Ruling published by the Internal Revenue Service or a change in applicable U.S. federal income tax law occurring after the date of the Indenture.
|
•
|
direct obligations of the United States, for the payment of which its full faith and credit is pledged; or
|
•
|
obligations of a person or entity controlled or supervised by and acting as an agency or instrumentality of the United States, the timely payment of which is unconditionally guaranteed as a full faith and credit obligation by the United States.
|
•
|
change the stated maturity of the principal of, or premium, if any, on, or any installment of principal, if any, of or interest on, or any additional amounts payable with respect to, any debt security;
|
•
|
reduce the principal amount of, or premium or interest on, or any additional amounts payable with respect to, any debt security;
|
•
|
change the coin or currency in which any debt security or any premium or any interest on the debt security or any additional amounts payable with respect to the debt security is payable;
|
•
|
impair the right to institute suit for the enforcement of any payment on or after the stated maturity of any debt securities or, in the case of redemption, exchange or conversion, on or after the redemption, exchange or conversion date or, in the case of repayment at the option of any holder, on or after the date for repayment or in the case of a change in control, after the change in control purchase date;
|
•
|
reduce the percentage and principal amount of the outstanding debt securities, the consent of whose holders is required in order to take certain actions;
|
•
|
change any of our obligations to maintain an office or agency in the places and for the purposes required by the Indenture;
|
•
|
modify or affect in any manner adverse to the holders of the debt securities the terms and conditions of our obligations regarding the due and punctual payment of principal or, any premium on or all interest on the debt securities; or
|
•
|
modify any of the above provisions.
|
•
|
a payment default with respect to debt securities of that series; or
|
•
|
a default of a covenant or provision of the Indenture that cannot be modified or amended without the consent of the holder of each debt security of any series.
|
•
|
that all payments on the Notes in respect of the principal of and any premium and interest shall be made without withholding or deduction for any present or future taxes, duties, assessments or governmental charges of any nature imposed or levied by or on behalf of the person’s jurisdiction of organization or political subdivision or taxing authority, unless the taxes are required by the jurisdiction, subdivision or authority to be withheld or deducted, in which case the person will pay additional amounts so that after deducting the taxes the holder of Notes receives the same amount that the holder would have received if no withholding or deduction was required; and
|
•
|
to indemnify immediately the holder of Notes against any tax, assessment or governmental charge imposed on the holder or required to be withheld or deducted from any payment to the holder as a consequence of the transaction; and
|
•
|
any other tax costs or other tax expenses of the transaction.
|
•
|
we expressly assume the obligations in an assumption agreement or supplemental indenture that is executed and delivered to the trustee in a form that is acceptable to the trustee;
|
•
|
no event of default and no event that after a notice or the lapse of time or both would become an event of default occurs and is continuing after giving effect to our assuming the obligations; and
|
•
|
we expressly agree in an assumption agreement or supplemental indenture to indemnify the holders of the debt securities against any tax assessment or government charge imposed on a holder or required to be withheld or deducted from any payment made to a holder, including any charge or withholding required on account of this indemnification, and any costs or expenses incurred by a holder on account of our assuming the obligations. If we deliver to the trustee an opinion of an independent tax counsel or consultant of recognized standing stating that the
|
•
|
any tax that would not have been imposed but for the fact that the holder
|
•
|
was a resident, domiciled or national of, or engaged in business or maintained a permanent establishment or was physically present in Canada or otherwise had some connection with Canada other than merely owning the Notes;
|
•
|
presented, if presentation is required, the Notes for payment in Canada, unless the Notes could not have been presented for payment elsewhere;
|
•
|
presented, if presentation is required, the Notes more than 30 days after the date on which the payment relating to the Notes first became due and payable or provided for, whichever is later, except to the extent that the holder would have been entitled to the additional interest if it had presented the Notes for payment on any day within this 30 day period;
|
•
|
is not dealing with us, directly or indirectly, on an arm’s-length basis; or
|
•
|
entered into or participated in a scheme to avoid Canadian withholding tax that we neither were a party to nor participated in;
|
•
|
any estate, inheritance, gift, sale, transfer, personal property or similar tax, assessment or other governmental charge;
|
•
|
any tax that is payable other than by withholding or deduction from payments of, or in respect of, principal of or any premium or interest on the Notes;
|
•
|
any tax that is imposed or withheld because the holder or the beneficial owner of Notes failed, upon our request to provide information concerning the nationality, residence or identity of the holder or the beneficial owner, or to make any declaration or other similar claim or satisfy any information or reporting requirement that is required or imposed by Canadian federal income tax laws as a precondition to exemption from all or part of the tax, assessment or other governmental charge; or
|
•
|
any combination of four items listed above.
|
•
|
subject to U.S. tax by reason of the holder being connected with the U.S. otherwise than by holding or owning the Notes; or
|
•
|
not dealing at arm’s length with us.
|
•
|
we will be required to pay any additional amounts under the Indenture or the terms of the Notes
|
•
|
in respect of interest on the next succeeding interest payment date; or
|
•
|
in respect of the principal of any discounted Notes on the date of the determination, assuming that a payment in respect of principal were required to be made on this date under the terms of the Notes; and
|
•
|
we cannot avoid paying the additional amount by taking reasonable measures available to us,
|
•
|
no notice of redemption may be given earlier than 60 days before the earliest date on which we would be obligated to pay any additional amounts if a payment was due in respect of the Notes; and
|
•
|
at the time any redemption notice is given, the obligation to pay any additional amounts must remain in effect.
|
•
|
we have consolidated with or merged into, or conveyed or transferred or leased our properties and assets as an entirety or substantially as an entirety to, any person that is organized under the laws of any jurisdiction other than the United States or Canada;
|
•
|
as the result of any change in or any amendment to the laws, regulations or published tax rulings of the jurisdiction under which our successor is organized or of its political subdivisions or taxing authorities affecting taxation, or any change in the official administration, application or interpretation of its laws, regulations or published tax rulings either generally or in relation to the Notes, our successor must pay any additional amounts under the Indenture or the terms of the Notes
|
•
|
in respect of interest on the Notes on the next succeeding interest payment date; or
|
•
|
in respect of the principal of any discounted Notes on the date of the determination, assuming the principal must be paid on that date under the terms of the Notes; and
|
•
|
we or our successor taking reasonable measures cannot avoid this obligation,
|
•
|
by the applicable depositary to a nominee of the depositary,
|
•
|
by any nominee to the depositary itself or another nominee, or
|
•
|
by the depositary or any nominee to a successor depositary or any nominee of the successor.
|
•
|
will not be entitled to have any of the underlying debt securities registered in their names;
|
•
|
will not receive or be entitled to receive physical delivery of any of the underlying debt securities in definitive form; and
|
•
|
will not be considered the owners or holders under the Indenture relating to those debt securities.
|
•
|
newly-created directorships resulting from an increase in the number of directors and any vacancy on the Board may be filled solely and exclusively by a majority vote of the remaining directors then in office, even if less than a quorum (and not by stockholders);
|
•
|
stockholders seeking to present proposals before a meeting of stockholders or to nominate candidates for election as directors at a meeting of stockholders must provide notice in writing in a timely manner and be stockholders of record entitled to vote at such meeting on the date of the giving of such notice, and also specify requirements as to the form and content of a stockholder’s notice;
|
•
|
stockholders may not act by written consent in lieu of a duly called annual or special meeting of stockholders;
|
•
|
no stockholder shall have cumulative voting rights for the election of directors;
|
•
|
the affirmative vote of 80% of the Company’s outstanding voting stock is required to (i) adopt any agreement for the merger or consolidation of the Company with or into any other corporation which is the beneficial owner of more than 5% of the Company’s outstanding voting stock, and (ii) authorize any sale or lease of all or any substantial part of the Company’s assets to any beneficial holder of 5% or more of the Company’s outstanding voting stock;
|
•
|
any tender offer made by a beneficial owner of more than 5% of the Company’s outstanding voting stock in connection with any (i) plan of merger, consolidation or reorganization; (ii) sale or lease of substantially all of the Company’s assets; or (iii) issuance of equity securities to the 5% stockholder must provide at least as favorable terms to each holder of Common Stock (other than the stockholder making the tender offer) as the most favorable terms granted by such stockholder pursuant to such offer; and
|
•
|
the Company may not acquire any voting stock from the beneficial owner of more than 5% of the Company’s outstanding voting stock, except for acquisitions pursuant to a tender offer to all holders of the Company’s outstanding voting stock on the same price, terms and conditions, acquisitions in compliance with Rule 10b-18 under the Exchange Act and acquisitions at a price not exceeding the market value per share.
|
•
|
a stockholder who owns 15% or more of the Company’s outstanding voting stock (otherwise known as an “interested stockholder”);
|
•
|
an affiliate of an interested stockholder; or
|
•
|
an associate of an interested stockholder,
|
•
|
the Board approves the transaction that made the stockholder an “interested stockholder,” prior to the date of the transaction;
|
•
|
after the completion of the transaction that resulted in the stockholder becoming an interested stockholder, that stockholder owned at least 85% of the Company’s voting stock outstanding at the time the transaction commenced, other than statutorily excluded shares of common stock; or
|
•
|
on or subsequent to the date of the transaction, the business combination is approved by the Board and authorized at a meeting of the Company’s stockholders, and not by written consent, by an affirmative vote of at least two-thirds of the outstanding voting stock not owned by the interested stockholder.
|
Attest:
|
|
|
|
|
APACHE CORPORATION
|
|
|
|
|
|
|
|
|
|
|
|
|
/s/ Rajesh Sharma
|
|
|
|
By:
|
/s/ Dominic J. Ricotta
|
Rajesh Sharma
|
|
|
|
|
Dominic J. Ricotta
|
Corporate Secretary
|
|
|
|
|
Senior Vice President,
|
|
|
|
|
|
Human Resources
|
Attest:
|
|
|
|
|
APACHE CORPORATION
|
|
|
|
|
|
|
|
|
|
|
|
|
/s/ Rajesh Sharma
|
|
|
|
By:
|
/s/ Dominic J. Ricotta
|
Rajesh Sharma
|
|
|
|
|
Dominic J. Ricotta
|
Corporate Secretary
|
|
|
|
|
Senior Vice President,
|
|
|
|
|
|
Human Resources
|
(a)
|
There is a material diminution in the Recipient’s base compensation, compared to his or her rate of base compensation on the date of the Change of Control.
|
(b)
|
There is a material diminution in the Recipient’s authority, duties or responsibilities.
|
(c)
|
There is a material diminution in the authority, duties or responsibilities of the Recipient’s supervisor, such as a requirement that the Recipient (or his or her supervisor) report to a corporate officer or employee instead of reporting directly to the board of directors.
|
(d)
|
There is a material diminution in the budget over which the Recipient retains authority.
|
(e)
|
There is a material change in the geographic location at which the Recipient must perform his or her service, including, for example the assignment of the Recipient to a regular workplace that is more than 50 miles from his or her regular workplace on the date of the Change of Control.
|
(a)
|
There is a material diminution in the Recipient’s base compensation, compared to his or her rate of base compensation on the date of the Change of Control.
|
(b)
|
There is a material diminution in the Recipient’s authority, duties or responsibilities.
|
(c)
|
There is a material diminution in the authority, duties or responsibilities of the Recipient’s supervisor, such as a requirement that the Recipient (or his or her supervisor) report to a corporate officer or employee instead of reporting directly to the board of directors.
|
(d)
|
There is a material diminution in the budget over which the Recipient retains authority.
|
(e)
|
There is a material change in the geographic location at which the Recipient must perform his or her service, including, for example the assignment of the Recipient to a regular workplace that is more than 50 miles from his or her regular workplace on the date of the Change of Control.
|
Recipient Name:
|
[Name]
|
Company:
|
Apache Corporation
|
Notice:
|
A summary of the terms of Conditional Grants of Restricted Stock Units (“RSUs”) under the 2020 Performance Share Program is set out in this notice (the “Award Notice”) but subject always to the terms of the Apache Corporation 2016 Omnibus Compensation Plan (the “Plan”) and the 2020 Performance Share Program Agreement (the “Agreement”). In the event of any inconsistency between the terms of this Award Notice, the terms of the Plan and the Agreement, the terms of the Plan and the Agreement shall prevail. The Conditional Grant is a Cash-Based Award under Section 10 of the Plan and is subject to the provisions of the Plan governing Performance Awards.
|
Type of Award:
|
A conditional award of RSUs based on a target percentage of annual base salary determined at the beginning of the Performance Period derived from job level (the “Conditional Grant”).
|
Restricted Stock Unit:
|
A Restricted Stock Unit (“RSU”) as defined in the Plan and meaning the right granted to the Recipient of the Conditional Grant, as adjusted at the end of the Performance Period, to receive one share of Stock or the cash equivalent thereof for each RSU at the end of the specified Vesting Period.
|
Stock:
|
The $0.625 par value common stock of the Company or as otherwise defined in the Plan.
|
Grant:
|
A Conditional Grant related to ______ Restricted Stock Units (“Target Amount”).
|
Grant Date:
|
[Date]
|
Conditions:
|
Subject always to the terms of the Plan and the Agreement, the Conditional Grant of RSUs shall be made as of the Grant Date. At the end of the Performance Period, the Committee shall derive and confirm the number of Conditional Grant RSUs that will actually be awarded as RSUs to the Recipient based upon measurement of the specific performance goals, applicable performance percentage levels and applicable weighting percentages during the Performance Period as set forth in Schedule B to the Agreement, provided that the Recipient remains an Eligible Person and employed by the Company or its Affiliate as of the final day of the Performance Period. Once granted at the conclusion of the Performance Period, such RSUs shall remain subject to a vesting schedule (as set forth below) (the “Vesting Period”). Once vested, the Recipient shall be paid the value of his or her RSUs in cash (net of cash withheld for applicable tax withholdings) provided that the Recipient remains employed as an Eligible Person during the Vesting Period including the vesting date.
|
Performance Measure:
|
The performance measures for the Conditional Grant, the performance percentage levels, and the applicable weighting percentages to be applied over the Performance Period are set forth on Schedule B to the Agreement.
|
Performance Period:
|
The three-year period commencing January 1, 2020 and ending December 31, 2022.
|
Vesting Period:
|
Except upon a change of control (as described below), death or Disability (as described below), or Retirement (as described below), cessation of employment during the Performance Period shall result in the immediate forfeiture of the entire amount of the Conditional Grant. Any such RSUs awarded shall vest in accordance with the following schedule, provided that the Recipient remains employed as an Eligible Person as of such vesting date:
|
Withholding:
|
The Company and the Recipient will comply with all federal and state laws and regulations respecting the required withholding, deposit and payment of any income, employment, or other taxes relating to the Grant.
|
Clawback:
|
This Grant is subject to the Company’s Executive Compensation Clawback Policy (a copy of which is provided with this Notice) and the recoupment and reimbursement policies as provided in the Agreement.
|
Dividends:
|
The Company will credit each of the Recipient’s Conditional Grant RSUs and RSUs, as applicable, with Dividend Equivalents. For purposes of this Grant, a Dividend Equivalent is an amount equal to the cash dividend payable per share of Stock multiplied by the number of shares of Stock then underlying such outstanding Conditional Grant RSUs or RSUs, as applicable. Such amount will be credited to a book entry account on Recipient’s behalf at the time the Company pays any cash dividend on its Stock. The Recipient’s rights in any such Dividend Equivalents will vest at the same time as, and only to the extent that, the underlying Conditional Grant RSUs or RSUs, as applicable, vest and will be distributed at the same time in cash (subject to applicable withholdings), and only to the extent, as the related RSUs are to be distributed to the Recipient as provided in the Agreement and to which such Dividend Equivalents apply. Dividend Equivalents on Conditional Grant RSUs will accrue and be credited by the Company but will be subject to the same performance goals, applicable performance percentage levels and applicable weighting percentages as the related Conditional Grant RSUs. Dividend Equivalents (as so adjusted) will not be paid to a Recipient until such Recipient becomes vested in the related RSUs granted at the end of the Performance Period and will be forfeited in the event of the forfeiture and cancellation of the related Conditional Grant RSUs and RSUs pursuant to this Agreement.
|
Acceptance
|
Please complete the on-line grant acceptance as promptly as possible to accept or reject your Conditional Grant. You can access this through your account at netbenefits.fidelity.com. By accepting your Conditional Grant, you will have agreed to the terms and conditions set forth in the Agreement, including, but not limited to, the non-
|
Performance Goals:
|
1. Total Shareholder Return
|
|
At the end of the Performance Period, the Committee shall derive and confirm a portion of the number of Conditional Grant RSUs that will actually be awarded as RSUs to the Recipient based upon measurement of total shareholder return (“TSR”) of Stock as compared to a designated Peer Group during the Performance Period, provided that the Recipient remains an Eligible Person and employed by the Company or its Affiliate as of the final day of the Performance Period.
|
–
|
Begin Price = Average per share closing price of a share or share equivalent on the applicable stock exchange for the month of December immediately preceding the beginning of the performance period
|
–
|
End Price = Average per share closing price of a share or share equivalent on the applicable stock exchange for the month in which the performance period ends
|
–
|
Dividends = Includes dividends paid throughout performance period
|
–
|
TSR ranking compared to designated Peer Group (16 companies and one index selected)
|
o
|
Antero Resources Corp.
|
o
|
Cabot Oil & Gas Corporation
|
o
|
Cimarex Energy Co.
|
o
|
Concho Resources Inc.
|
o
|
ConocoPhillips Company
|
o
|
Devon Energy Corporation
|
o
|
Diamondback Energy, Inc.
|
o
|
Encana Corporation
|
o
|
EOG Resources, Inc.
|
o
|
EQT Corporation
|
o
|
Hess Corporation
|
o
|
Marathon Oil Corporation
|
o
|
Murphy Oil Corporation
|
o
|
Noble Energy Inc.
|
o
|
Occidental Petroleum Corporation
|
o
|
Pioneer Natural Resources Co.
|
o
|
S&P 500 Index
|
–
|
Apache’s performance over a three-year performance period will be directly ranked within the peer group, resulting in the application of a single multiplier to the target shares to derive the number of shares awarded. The multiplier will range from 0 for performance in the bottom 1/6th to 2.0 for ranking in the top 1/6th among the peer group.
|
–
|
Should consolidation among peers in the marketplace occur, the ranking schedule would adjust to accommodate the reduced number of peers.
|
•
|
Cash Return on Invested Capital
|
Metric
|
Weighting
|
Threshold
|
Target
|
Max
|
Total Shareholder Return
|
50%
|
15th
|
9th - 10th
|
1st – 3rd
|
Cash Return on Invested Capital
|
50%
|
50%
|
100%
|
200%
|
–
|
1/1/2020 to 12/31/2022
|
Measurement:
|
At the conclusion of the three-year performance period, a calculation of TSR performance will be made and confirmed. 50% of the total Target Amount of RSUs will be determined based upon the final TSR performance as follows:
|
Rank Against
Peers
|
Payout
Multiple
|
1
|
2.00
|
2
|
2.00
|
3
|
2.00
|
4
|
1.85
|
5
|
1.70
|
6
|
1.55
|
7
|
1.40
|
8
|
1.25
|
9
|
1.10
|
10
|
0.90
|
11
|
0.75
|
12
|
0.60
|
13
|
0.45
|
14
|
0.30
|
15
|
0.15
|
16
|
0.00
|
17
|
0.00
|
18
|
0.00
|
Metric
|
Threshold
|
Target
|
Max
|
Cash Return on Invested Capital
|
50%
|
100%
|
200%
|
(a)
|
There is a material diminution in the Recipient’s base compensation, compared to his or her rate of base compensation on the date of the Change of Control.
|
(b)
|
There is a material diminution in the Recipient’s authority, duties or responsibilities.
|
(c)
|
There is a material diminution in the authority, duties or responsibilities of the Recipient’s supervisor, such as a requirement that the Recipient (or his or her supervisor) report to a corporate officer or employee instead of reporting directly to the board of directors.
|
(d)
|
There is a material diminution in the budget over which the Recipient retains authority.
|
(e)
|
There is a material change in the geographic location at which the Recipient must perform his or her service, including, for example the assignment of the Recipient to a regular workplace that is more than 50 miles from his or her regular workplace on the date of the Change of Control.
|
Age
|
|
Advance Written Notice
|
65 or older
|
|
3 months
|
between (and including) 55 and 64
|
|
6 months
|
Recipient Name:
|
[Name]
|
Company:
|
Apache Corporation
|
Notice:
|
A summary of the terms of your grant of Restricted Stock Units (“RSUs”) is set out in this notice (the “Grant Notice”) but subject always to the terms of the Apache Corporation 2016 Omnibus Compensation Plan (the “Plan”) and the Restricted Stock Unit Award Agreement (the “Agreement”). In the event of any inconsistency between the terms of this Grant Notice, the terms of the Plan and the Agreement, the terms of the Plan and the Agreement shall prevail. The Grant is a Cash-Based Award under Section 10 of the Plan and is subject to the provisions of the Plan governing RSUs.
|
Type of Award:
|
Restricted Stock Unit(s)
|
Restricted Stock Unit:
|
A Restricted Stock Unit (“RSU”) under this Agreement means the right granted to the Recipient to receive the cash equivalent of one share of Stock (as defined below) for each RSU at the end of the specified Vesting Period.
|
Stock:
|
The $0.0001 par value Class A common stock of Altus Midstream Company.
|
Grant:
|
A Grant related to ______ Restricted Stock Units.
|
Grant Date:
|
[Date]
|
Conditions:
|
The Recipient may elect, at the time of the grant, to have his or her RSUs deferred into the Deferred Delivery Plan (the “DDP”) when the RSUs vest, in which case the Recipient will receive the value of
|
Vesting Period:
|
RSUs granted shall vest (i.e., restrictions shall lapse) in accordance with the following schedule (the “Vesting Period”), provided that the Recipient remains employed as an Eligible Person as of such vesting date:
|
Withholding:
|
The Company and the Recipient will comply with all federal and state laws and regulations respecting the required withholding, deposit, and payment of any income, employment, or other taxes relating to the Grant.
|
Dividends:
|
The Company will credit each of the Recipient’s RSUs with Dividend Equivalents. For purposes of this Grant, a Dividend Equivalent is an amount equal to the cash dividend payable per share of Stock multiplied by the number of shares of Stock then underlying such outstanding RSUs. Such amount will be credited to a book entry account on Recipient’s behalf at the time Altus Midstream Company pays any cash dividend on its Stock. The Recipient’s rights in any such Dividend Equivalents will vest at the same time as, and only to the extent that, the underlying RSUs vest and will be distributed at the same time in cash (subject to applicable withholdings), and only to the extent, as the related RSUs are to be distributed to the Recipient as provided in the Agreement and to which such Dividend Equivalents apply.
|
Acceptance:
|
Please complete the on-line grant acceptance as promptly as possible to accept or reject your Grant. You can access this through your account at netbenefits.fidelity.com. By accepting your Grant, you will have agreed to the terms and conditions set forth in the Agreement, including, but not limited to, the non-compete and non-disparagement provisions set forth in sections 5 and 6 of the Agreement, and the terms and conditions of the Plan. If you do not accept your Grant, your RSUs will not vest and you will be unable to receive your RSUs.
|
(a)
|
There is a material diminution in the Recipient’s base compensation, compared to his or her rate of base compensation on the date of the Change of Control.
|
(b)
|
There is a material diminution in the Recipient’s authority, duties or responsibilities.
|
(c)
|
There is a material diminution in the authority, duties or responsibilities of the Recipient’s supervisor, such as a requirement that the Recipient (or his or her supervisor) report to a corporate officer or employee instead of reporting directly to the board of directors.
|
(d)
|
There is a material diminution in the budget over which the Recipient retains authority.
|
(e)
|
There is a material change in the geographic location at which the Recipient must perform his or her service, including, for example the assignment of the Recipient to a regular workplace that is more than 50 miles from his or her regular workplace on the date of the Change of Control.
|
Age
|
|
Advance Written Notice
|
65 or older
|
|
3 months
|
between (and including) 55 and 64
|
|
6 months
|
Recipient Name:
|
[Name]
|
Company:
|
Apache Corporation
|
Notice:
|
A summary of the terms of your grant of Restricted Stock Units (“RSUs”) is set out in this notice (the “Grant Notice”) but subject always to the terms of the Apache Corporation 2016 Omnibus Compensation Plan (the “Plan”) and the Restricted Stock Unit Award Agreement (the “Agreement”). In the event of any inconsistency between the terms of this Grant Notice, the terms of the Plan and the Agreement, the terms of the Plan and the Agreement shall prevail. The Grant is a Cash-Based Award under Section 10 of the Plan and is subject to the provisions of the Plan governing RSUs.
|
Type of Award:
|
Restricted Stock Unit(s)
|
Restricted Stock Unit:
|
A Restricted Stock Unit (“RSU”) as defined in the Plan and meaning the right granted to the Recipient to receive one share of Stock or the cash equivalent thereof for each RSU at the end of the specified Vesting Period.
|
Stock:
|
The $0.625 par value common stock of the Company or as otherwise defined in the Plan.
|
Grant:
|
A Grant related to ______ Restricted Stock Units.
|
Grant Date:
|
[Date]
|
Conditions:
|
The Recipient may elect, at the time of the grant, to have his or her RSUs deferred into the Deferred Delivery Plan (the “DDP”) when
|
Vesting Period:
|
RSUs granted shall vest (i.e., restrictions shall lapse) in accordance with the following schedule (the “Vesting Period”), provided that the Recipient remains employed as an Eligible Person as of such vesting date:
|
Withholding:
|
The Company and the Recipient will comply with all federal and state laws and regulations respecting the required withholding, deposit, and payment of any income, employment, or other taxes relating to the Grant.
|
Dividends:
|
The Company will credit each of the Recipient’s RSUs with Dividend Equivalents. For purposes of this Grant, a Dividend Equivalent is an amount equal to the cash dividend payable per share of Stock multiplied by the number of shares of Stock then underlying such outstanding RSUs. Such amount will be credited to a book entry account on Recipient’s behalf at the time the Company pays any cash dividend on its Stock. The Recipient’s rights in any such Dividend Equivalents will vest at the same time as, and only to the extent that, the underlying RSUs vest and will be distributed at the same time in cash (subject to applicable withholdings), and only to the extent, as the related RSUs are to be distributed to the Recipient as provided in the Agreement and to which such Dividend Equivalents apply.
|
Acceptance:
|
Please complete the on-line grant acceptance as promptly as possible to accept or reject your Grant. You can access this through your account at netbenefits.fidelity.com. By accepting your Grant, you will have agreed to the terms and conditions set forth in the Agreement, including, but not limited to, the non-compete and non-disparagement provisions set forth in sections 5 and 6 of the Agreement, and the terms and conditions of the Plan. If you do not accept your Grant, your RSUs will not vest and you will be unable to receive your RSUs.
|
(a)
|
There is a material diminution in the Recipient’s base compensation, compared to his or her rate of base compensation on the date of the Change of Control.
|
(b)
|
There is a material diminution in the Recipient’s authority, duties or responsibilities.
|
(c)
|
There is a material diminution in the authority, duties or responsibilities of the Recipient’s supervisor, such as a requirement that the Recipient (or his or her supervisor) report to a corporate officer or employee instead of reporting directly to the board of directors.
|
(d)
|
There is a material diminution in the budget over which the Recipient retains authority.
|
(e)
|
There is a material change in the geographic location at which the Recipient must perform his or her service, including, for example the assignment of the Recipient to a regular workplace that is more than 50 miles from his or her regular workplace on the date of the Change of Control.
|
Age
|
|
Advance Written Notice
|
65 or older
|
|
3 months
|
between (and including) 55 and 64
|
|
6 months
|
Recipient Name:
|
[Name]
|
Company:
|
Apache Corporation
|
Notice:
|
A summary of the terms of your grant of Restricted Stock Units (“RSUs”) is set out in this notice (the “Grant Notice”) but subject always to the terms of the Apache Corporation 2016 Omnibus Compensation Plan (the “Plan”) and the Restricted Stock Unit Award Agreement (the “Agreement”). In the event of any inconsistency between the terms of this Grant Notice, the terms of the Plan and the Agreement, the terms of the Plan and the Agreement shall prevail.
|
Type of Award:
|
Restricted Stock Unit(s)
|
Restricted Stock Unit:
|
A Restricted Stock Unit (“RSU”) as defined in the Plan and meaning the right granted to the Recipient to receive one share of Stock for each RSU at the end of the specified Vesting Period.
|
Stock:
|
The $0.625 par value common stock of the Company or as otherwise defined in the Plan.
|
Grant:
|
A Grant related to ______ Restricted Stock Units.
|
Grant Date:
|
[Date]
|
Conditions:
|
The Recipient may elect, at the time of the grant, to have his or her RSUs deferred into the Deferred Delivery Plan (the “DDP”) when the RSUs vest, in which case the Recipient will receive the value of the RSUs at the times specified pursuant to the DDP. For RSUs that are not deferred, once the RSU vests, the Recipient shall be paid the
|
Vesting Period:
|
RSUs granted shall vest (i.e., restrictions shall lapse) in accordance with the following schedule (the “Vesting Period”), provided that the Recipient remains employed as an Eligible Person as of such vesting date:
|
Withholding:
|
The Company and the Recipient will comply with all federal and state laws and regulations respecting the required withholding, deposit, and payment of any income, employment, or other taxes relating to the Grant.
|
Dividends:
|
The Company will credit each of the Recipient’s RSUs with Dividend Equivalents. For purposes of this Grant, a Dividend Equivalent is an amount equal to the cash dividend payable per share of Stock multiplied by the number of shares of Stock then underlying such outstanding RSUs. Such amount will be credited to a book entry account on Recipient’s behalf at the time the Company pays any cash dividend on its Stock. The Recipient’s rights in any such Dividend Equivalents will vest at the same time as, and only to the extent that, the underlying RSUs vest and will be distributed at the same time in cash (subject to applicable withholdings), and only to the extent, as the related RSUs are to be distributed to the Recipient as provided in the Agreement and to which such Dividend Equivalents apply.
|
Acceptance:
|
Please complete the on-line grant acceptance as promptly as possible to accept or reject your Grant. You can access this through your account at netbenefits.fidelity.com. By accepting your Grant, you will have agreed to the terms and conditions set forth in the Agreement, including, but not limited to, the non-compete and non-disparagement provisions set forth in sections 5 and 6 of the Agreement, and the terms and conditions of the Plan. If you do not accept your Grant, your RSUs will not vest and you will be unable to receive your RSUs.
|
(a)
|
There is a material diminution in the Recipient’s base compensation, compared to his or her rate of base compensation on the date of the Change of Control.
|
(b)
|
There is a material diminution in the Recipient’s authority, duties or responsibilities.
|
(c)
|
There is a material diminution in the authority, duties or responsibilities of the Recipient’s supervisor, such as a requirement that the Recipient (or his or her supervisor) report to a corporate officer or employee instead of reporting directly to the board of directors.
|
(d)
|
There is a material diminution in the budget over which the Recipient retains authority.
|
(e)
|
There is a material change in the geographic location at which the Recipient must perform his or her service, including, for example the assignment of the Recipient to a regular workplace that is more than 50 miles from his or her regular workplace on the date of the Change of Control.
|
Age
|
|
Advance Written Notice
|
65 or older
|
|
3 months
|
between (and including) 55 and 64
|
|
6 months
|
|
|
Exhibit 21.1
|
|
|
|
Apache Corporation (a Delaware corporation)
|
||
Listing of Subsidiaries as of December 31, 2019
|
||
|
|
|
Exact Name of Subsidiary and Name
|
|
Jurisdiction of
|
under which Subsidiary does Business
|
|
Incorporation or Organization
|
Alta Vista Oil Corporation
|
|
Delaware
|
*Altus Midstream Company
|
|
Delaware
|
*Altus Midstream GP LLC
|
|
Delaware
|
**Altus Midstream Subsidiary GP LLC
|
|
Delaware
|
Apache Alaska Corporation
|
|
Delaware
|
Apache Corporation (New Jersey)
|
|
New Jersey
|
Apache Crude Oil Marketing, Inc.
|
|
Delaware
|
Apache Deepwater LLC
|
|
Delaware
|
Apache Dominican Republic Corporation LDC
|
|
Cayman Islands
|
Apache Fertilizer Holdings II Corporation LDC
|
|
Cayman Islands
|
Apache Finance Louisiana Corporation
|
|
Delaware
|
Apache Foundation
|
|
Minnesota
|
Apache Gathering Company
|
|
Delaware
|
Apache Holdings, Inc.
|
|
Delaware
|
Apache International Employment Inc.
|
|
Delaware
|
Apache Louisiana Holdings LLC
|
|
Delaware
|
Apache Louisiana Minerals LLC
|
|
Delaware
|
Apache Marketing, Inc.
|
|
Delaware
|
Apache Midstream LLC
|
|
Delaware
|
Alpine High Oil Pipeline LLC
|
|
Delaware
|
Apache Natural Gas Transportation Fuels LLC
|
|
Delaware
|
Apache North America LLC
|
|
Delaware
|
Apache Oil Corporation
|
|
Texas
|
Apache Overseas LLC
|
|
Delaware
|
Apache Asia Pacific Corporation LDC
|
|
Cayman Islands
|
Apache East Ras Budran Corporation LDC
|
|
Cayman Islands
|
Apache Egypt Investment Corporation LDC
|
|
Cayman Islands
|
Apache Egypt Holdings III Corporation LDC
|
|
Cayman Islands
|
Apache Egypt GP Corporation LDC
|
|
Cayman Islands
|
Apache Egypt Holdings II Corporation LDC
|
|
Cayman Islands
|
Apache Abu Gharadig Corporation LDC
|
|
Cayman Islands
|
Apache East Bahariya Corporation LDC
|
|
Cayman Islands
|
Apache El Diyur Corporation LDC
|
|
Cayman Islands
|
Apache Faiyum Corporation LDC
|
|
Cayman Islands
|
Apache Khalda Corporation LDC
|
|
Cayman Islands
|
Apache Egypt Midstream Holdings I LDC
|
|
Cayman Islands
|
Apache Khalda II Corporation LDC
|
|
Cayman Islands
|
Apache Matruh Corporation LDC
|
|
Cayman Islands
|
Apache Mediterranean Corporation LDC
|
|
Cayman Islands
|
Apache North Bahariya Corporation LDC
|
|
Cayman Islands
|
Apache North El Diyur Corporation LDC
|
|
Cayman Islands
|
Apache North Tarek Corporation LDC
|
|
Cayman Islands
|
Apache Qarun Corporation LDC
|
|
Cayman Islands
|
|
|
Exhibit 21.1
|
|
|
|
Apache Corporation (a Delaware corporation)
|
||
Listing of Subsidiaries as of December 31, 2019
|
||
|
|
|
Exact Name of Subsidiary and Name
|
|
Jurisdiction of
|
under which Subsidiary does Business
|
|
Incorporation or Organization
|
Apache Qarun Exploration Company LDC
|
|
Cayman Islands
|
Apache Shushan Corporation LDC
|
|
Cayman Islands
|
Apache South Umbarka Corporation LDC
|
|
Cayman Islands
|
Apache Umbarka Corporation LDC
|
|
Cayman Islands
|
Apache West Kalabsha Corporation LDC
|
|
Cayman Islands
|
Apache West Kanayis Corporation LDC
|
|
Cayman Islands
|
Apache UK Corporation LDC
|
|
Cayman Islands
|
Apache International Corporation LDC
|
|
Cayman Islands
|
Apache North Sea Limited
|
|
England and Wales
|
Apache UK Pension Trustee Ltd.
|
|
England and Wales
|
Apache North Sea Production Limited
|
|
England and Wales
|
Apache UK Investment Limited
|
|
England and Wales
|
Apache Beryl I Limited
|
|
Cayman Islands
|
Apache EMEA Corporation LDC
|
|
Cayman Islands
|
Apache Exploration LDC
|
|
Cayman Islands
|
Apache Fertilizer Holdings Corporation LDC
|
|
Cayman Islands
|
Apache International Finance S.a.r.l.
|
|
Luxembourg
|
Apache International Finance II S.a.r.l.
|
|
Luxembourg
|
Apache Latin America II Corporation LDC
|
|
Cayman Islands
|
Apache Netherlands Investment B.V.
|
|
The Netherlands
|
Apache Suriname Corporation LDC
|
|
Cayman Islands
|
Apache Netherlands Investment II B.V.
|
|
The Netherlands
|
Apache Suriname 58 Holdings Corporation LDC
|
|
Cayman Islands
|
Apache Suriname 58 Corporation LDC
|
|
Cayman Islands
|
Apache Overseas Holdings LLC
|
|
Delaware
|
Apache Switzerland Holdings AG
|
|
Switzerland
|
Apache Kenya Holdings LLC
|
|
Delaware
|
Apache Kenya Limited
|
|
Kenya
|
Apache Overseas Holdings II, Inc.
|
|
Delaware
|
Apache Finance Pty Limited
|
|
Australian Capital Territory
|
Apache Ravensworth Corporation LDC
|
|
Cayman Islands
|
Apache Shady Lane Ranch Inc.
|
|
Delaware
|
Apache Shelf Exploration LLC
|
|
Delaware
|
Apache Shelf, Inc.
|
|
Delaware
|
Apache Texas Property Holding Company LLC
|
|
Delaware
|
Apache UK Limited
|
|
England and Wales
|
Apache Well Containment LLC
|
|
Delaware
|
Apache Western Exploration LLC
|
|
Delaware
|
BLPL Holdings LLC
|
|
Delaware
|
Clear Creek Hunting Preserve, Inc.
|
|
Wyoming
|
Cordillera Energy Partners III, LLC
|
|
Colorado
|
Cottonwood Aviation, Inc.
|
|
Delaware
|
CV Energy Corporation
|
|
Delaware
|
|
|
Exhibit 21.1
|
|
|
|
Apache Corporation (a Delaware corporation)
|
||
Listing of Subsidiaries as of December 31, 2019
|
||
|
|
|
Exact Name of Subsidiary and Name
|
|
Jurisdiction of
|
under which Subsidiary does Business
|
|
Incorporation or Organization
|
DEK Energy LLC
|
|
Delaware
|
Apache Finance Canada LLC
|
|
Delaware
|
Apache Permian Basin Investment LLC
|
|
Delaware
|
Apache Permian Basin Corporation
|
|
Delaware
|
Apache Permian Exploration and Production LLC
|
|
Delaware
|
LeaCo New Mexico Exploration and Production LLC
|
|
Delaware
|
Permian Basin Joint Venture LLC (95%)
|
|
Delaware
|
ZPZ Delaware I LLC
|
|
Delaware
|
Apache Canada Management LLC
|
|
Delaware
|
Apache Canada Holdings LLC
|
|
Delaware
|
Apache Canada Management II LLC
|
|
Delaware
|
Apache Finance Canada III LLC
|
|
Delaware
|
Apache Finance Canada IV LLC
|
|
Delaware
|
Stallion Canada Holdings LLC
|
|
Delaware
|
Edge Petroleum Exploration Company
|
|
Delaware
|
Granite Operating Company
|
|
Texas
|
Phoenix Exploration Resources, Ltd.
|
|
Delaware
|
Texas International Company
|
|
Delaware
|
Texas and New Mexico Exploration LLC
|
|
Delaware
|
ZPZ Acquisitions, Inc.
|
|
Delaware
|
ZPZ Delaware II LLC
|
|
Delaware
|
ZPZ Delaware III LLC
|
|
Delaware
|
Phoenix Exploration Louisiana C LLC (75%)
|
|
Delaware
|
(1)
|
Registration Statements (Form S-3 Nos. 333-57785, 333-75633, 333-32580, 333-105536, 333-155884, 333-174429, 333-197491, and 333-219345) of Apache Corporation and in the related Prospectuses,
|
(2)
|
Registration Statements (Form S-4 Nos. 333-107934 and 333-166964) of Apache Corporation and in the related Prospectuses, and
|
(3)
|
Registration Statements (Form S-8 Nos. 33-59721, 33-63817, 333-26255, 333-32557, 333-36131, 333-31092, 333-48758, 333-97403, 333-102330, 333-103758, 333-106213, 333-125232, 333-125233, 333-135044, 333-143115, 333-170533, 333-175250, 333-178672, 333-190619, and 333-212237) of Apache Corporation;
|
1.
|
I have reviewed this Annual Report on Form 10-K of Apache 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/ John J. Christmann IV
|
|
John J. Christmann IV
|
|
Chief Executive Officer and President
|
|
(principal executive officer)
|
|
1.
|
I have reviewed this Annual Report on Form 10-K of Apache 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/ Stephen J. Riney
|
|
Stephen J. Riney
|
|
Executive Vice President and Chief Financial Officer
|
|
(principal financial officer)
|
|
/s/ John J. Christmann IV
|
|
||
By:
|
|
John J. Christmann IV
|
|
Title:
|
|
Chief Executive Officer and President
|
|
|
|
(principal executive officer)
|
|
/s/ Stephen J. Riney
|
|
||
By:
|
|
Stephen J. Riney
|
|
Title:
|
|
Executive Vice President and Chief Financial Officer
|
|
|
|
(principal financial officer)
|
|
/s/ Ali A. Porbandarwala
|
Ali A. Porbandarwala, P.E.
|
TBPE License No. 107652
|
Senior Vice President
|
As of December 31, 2019
|
|
% Crude
Oil &
Condensate
Reserves
Reviewed
|
% Natural
Gas
Liquids
Reserves
Reviewed
|
% Gas
Reserves
Reviewed
|
Reviewed by Ryder Scott
|
Not Reviewed
|
Total
|
||||||
Crude Oil &
Condensate
MBarrels
|
Natural
Gas
Liquids
MBarrels
|
Sales
Gas
MMCF
|
Crude Oil &
Condensate
MBarrels
|
Natural
Gas
Liquids
MBarrels
|
Sales
Gas
MMCF
|
Crude Oil &
Condensate
MBarrels
|
Natural
Gas
Liquids
MBarrels
|
Sales
Gas
MMCF
|
||||
|
|
|
|
|
|
|
|
|
|
|
|
|
Developed
|
85.4
|
86.1
|
84.9
|
413,089
|
139,335
|
1,260,743
|
70,341
|
22,442
|
224,905
|
483,430
|
161,777
|
1,485,648
|
Undeveloped
|
82.6
|
80.7
|
70.2
|
55,837
|
19,627
|
109,743
|
11,757
|
4,693
|
46,605
|
67,594
|
24,320
|
156,348
|
Total Proved
|
85.1
|
85.4
|
83.5
|
468,926
|
158,962
|
1,370,486
|
82,098
|
27,135
|
271,510
|
551,024
|
186,097
|
1,641,996
|
As of December 31, 2019
|
|
% Crude
Oil &
Condensate
Reserves
Reviewed
|
% Natural
Gas
Liquids
Reserves
Reviewed
|
% Gas
Reserves
Reviewed
|
Reviewed by Ryder Scott
|
Not Reviewed
|
Total
|
||||||
Crude Oil &
Condensate
MBarrels
|
Natural
Gas
Liquids
MBarrels
|
Sales
Gas
MMcf
|
Crude Oil &
Condensate
MBarrels
|
Natural
Gas
Liquids
MBarrels
|
Sales
Gas
MMcf
|
Crude Oil &
Condensate
MBarrels
|
Natural
Gas
Liquids
MBarrels
|
Sales
Gas
MMcf
|
||||
|
|
|
|
|
|
|
|
|
|
|
|
|
USA
|
|
|
|
|
|
|
|
|
|
|
|
|
Developed
|
86.1
|
86.3
|
85.0
|
239,553
|
137,028
|
803,969
|
38,592
|
21,766
|
141,968
|
278,145
|
158,794
|
945,937
|
Undeveloped
|
83.0
|
80.5
|
79.0
|
38,773
|
18,982
|
90,923
|
7,943
|
4,587
|
24,117
|
46,716
|
23,569
|
115,040
|
Total Proved
|
85.7
|
85.5
|
84.3
|
278,326
|
156,010
|
894,892
|
46,535
|
26,353
|
166,085
|
324,861
|
182,363
|
1,060,977
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Egypt
|
|
|
|
|
|
|
|
|
|
|
|
|
Developed
|
87.3
|
87.3
|
89.9
|
90,456
|
582
|
389,718
|
13,117
|
84
|
43,665
|
103,573
|
666
|
433,383
|
Undeveloped
|
71.2
|
13
|
12.3
|
7,713
|
12
|
3,043
|
3,117
|
79
|
21,661
|
10,830
|
91
|
24,704
|
Total Proved
|
85.8
|
78.5
|
85.7
|
98,169
|
594
|
392,761
|
16,234
|
163
|
65,326
|
114,403
|
757
|
458,087
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United Kingdom
|
|
|
|
|
|
|
|
|
|
|
|
|
Developed
|
81.7
|
74.4
|
63.1
|
83,080
|
1,725
|
67,056
|
18,632
|
592
|
39,272
|
101,712
|
2,317
|
106,328
|
Undeveloped
|
93.1
|
95.9
|
95.0
|
9,351
|
633
|
15,777
|
697
|
27
|
827
|
10,048
|
660
|
16,604
|
Total Proved
|
82.7
|
79.2
|
67.4
|
92,431
|
2,358
|
82,833
|
19,329
|
619
|
40,099
|
111,760
|
2,977
|
122,932
|
Geographic Area
|
Product
|
Price
Reference
|
Average
Benchmark
Prices
|
Average Realized
Prices
|
United States
|
Oil/Condensate
|
WTI Cushing
|
$55.69/Bbl
|
$52.80/Bbl
|
|
NGLs
|
Mt. Belvieu Non-Tet Propane
|
$23.14/Bbl
|
$14.93/Bbl
|
|
Gas
|
Henry Hub
|
$2.63/MMBTU
|
$0.98/Mcf
|
|
|
|
|
|
Egypt
|
Oil/Condensate
|
Brent
|
$62.74/Bbl
|
$61.04/Bbl
|
|
NGLs
|
Brent
|
$62.74/Bbl
|
$32.10/Bbl
|
|
Gas
|
Contracts
|
Contract
|
$2.86/Mcf
|
|
|
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United Kingdom
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Oil/Condensate
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Brent
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$62.74/Bbl
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$60.77/Bbl
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NGLs
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Brent
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$62.74/Bbl
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$35.49/Bbl
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Gas
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NBP
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$4.49/MMBTU
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$4.58/Mcf
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(1)
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completion intervals that are open at the time of the estimate but which have not yet started producing;
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(2)
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wells which were shut-in for market conditions or pipeline connections; or
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(3)
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wells not capable of production for mechanical reasons.
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(i)
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Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
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