Devon Energy
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Commitment Runs Deep
Letter to Shareholders
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(cid:84)(cid:83)(cid:87)(cid:77)(cid:88)(cid:77)(cid:83)(cid:82)(cid:73)(cid:72)(cid:4)(cid:88)(cid:83)(cid:4)(cid:72)(cid:73)(cid:80)(cid:77)(cid:90)(cid:73)(cid:86)(cid:4)(cid:81)(cid:73)(cid:69)(cid:82)(cid:77)(cid:82)(cid:75)(cid:74)(cid:89)(cid:80)(cid:4)(cid:74)(cid:86)(cid:73)(cid:73)(cid:4)(cid:71)(cid:69)(cid:87)(cid:76)(cid:4)(cid:74)(cid:80)(cid:83)(cid:91)(cid:4)(cid:69)(cid:88)(cid:4)(cid:88)(cid:83)(cid:72)(cid:69)(cid:93)(cid:247)(cid:87)(cid:4)
(cid:81)(cid:69)(cid:86)(cid:79)(cid:73)(cid:88)(cid:4)(cid:84)(cid:86)(cid:77)(cid:71)(cid:73)(cid:87)(cid:18)(cid:4)
(cid:4)
(cid:81)(cid:83)(cid:86)(cid:73)(cid:4)(cid:81)(cid:73)(cid:69)(cid:87)(cid:89)(cid:86)(cid:73)(cid:72)(cid:4)(cid:69)(cid:82)(cid:72)(cid:4)(cid:71)(cid:83)(cid:82)(cid:87)(cid:77)(cid:87)(cid:88)(cid:73)(cid:82)(cid:88)(cid:4)(cid:77)(cid:82)(cid:90)(cid:73)(cid:87)(cid:88)(cid:81)(cid:73)(cid:82)(cid:88)(cid:87)(cid:4)(cid:69)(cid:71)(cid:86)(cid:83)(cid:87)(cid:87)(cid:4)(cid:83)(cid:89)(cid:86)(cid:4)
(cid:89)(cid:84)(cid:87)(cid:88)(cid:86)(cid:73)(cid:69)(cid:81)(cid:4)(cid:70)(cid:89)(cid:87)(cid:77)(cid:82)(cid:73)(cid:87)(cid:87)(cid:16)(cid:4)(cid:91)(cid:73)(cid:247)(cid:86)(cid:73)(cid:4)(cid:69)(cid:80)(cid:87)(cid:83)(cid:4)(cid:91)(cid:73)(cid:80)(cid:80)(cid:4)(cid:84)(cid:83)(cid:87)(cid:77)(cid:88)(cid:77)(cid:83)(cid:82)(cid:73)(cid:72)(cid:4)(cid:88)(cid:83)(cid:4)maximize
and expand cash flow(cid:18)(cid:4)(cid:59)(cid:73)(cid:247)(cid:80)(cid:80)(cid:4)(cid:69)(cid:71)(cid:71)(cid:83)(cid:81)(cid:84)(cid:80)(cid:77)(cid:87)(cid:76)(cid:4)(cid:88)(cid:76)(cid:77)(cid:87)(cid:4)(cid:69)(cid:87)(cid:4)(cid:91)(cid:73)(cid:4)(cid:72)(cid:73)(cid:84)(cid:80)(cid:83)(cid:93)(cid:4)
(cid:80)(cid:73)(cid:69)(cid:72)(cid:77)(cid:82)(cid:75)(cid:4)(cid:88)(cid:73)(cid:71)(cid:76)(cid:82)(cid:83)(cid:80)(cid:83)(cid:75)(cid:77)(cid:73)(cid:87)(cid:4)(cid:88)(cid:83)(cid:4)(cid:74)(cid:89)(cid:86)(cid:88)(cid:76)(cid:73)(cid:86)(cid:4)(cid:83)(cid:84)(cid:88)(cid:77)(cid:81)(cid:77)(cid:94)(cid:73)(cid:4)(cid:91)(cid:73)(cid:80)(cid:80)(cid:4)(cid:84)(cid:73)(cid:86)(cid:74)(cid:83)(cid:86)(cid:81)(cid:69)(cid:82)(cid:71)(cid:73)(cid:4)
(cid:69)(cid:82)(cid:72)(cid:4)(cid:69)(cid:75)(cid:75)(cid:86)(cid:73)(cid:87)(cid:87)(cid:77)(cid:90)(cid:73)(cid:80)(cid:93)(cid:4)(cid:86)(cid:73)(cid:72)(cid:89)(cid:71)(cid:73)(cid:4)(cid:71)(cid:83)(cid:87)(cid:88)(cid:87)(cid:4)(cid:88)(cid:83)(cid:4)(cid:75)(cid:73)(cid:88)(cid:4)(cid:88)(cid:76)(cid:73)(cid:4)(cid:81)(cid:83)(cid:87)(cid:88)(cid:4)(cid:90)(cid:69)(cid:80)(cid:89)(cid:73)(cid:4)(cid:83)(cid:89)(cid:88)(cid:4)(cid:83)(cid:74)(cid:4)
(cid:73)(cid:90)(cid:73)(cid:86)(cid:93)(cid:4)(cid:70)(cid:69)(cid:86)(cid:86)(cid:73)(cid:80)(cid:4)(cid:84)(cid:86)(cid:83)(cid:72)(cid:89)(cid:71)(cid:73)(cid:72)(cid:18)
(cid:45)(cid:82)(cid:4)(cid:69)(cid:72)(cid:72)(cid:77)(cid:88)(cid:77)(cid:83)(cid:82)(cid:4)(cid:88)(cid:83)(cid:4)(cid:74)(cid:83)(cid:71)(cid:89)(cid:87)(cid:77)(cid:82)(cid:75)(cid:4)(cid:83)(cid:82)(cid:4)capital efficiency(cid:4)(cid:88)(cid:76)(cid:86)(cid:83)(cid:89)(cid:75)(cid:76)(cid:4)
(cid:4) (cid:59)(cid:73)(cid:4)(cid:69)(cid:80)(cid:87)(cid:83)(cid:4)(cid:77)(cid:82)(cid:88)(cid:73)(cid:82)(cid:72)(cid:4)(cid:88)(cid:83) simplify our portfolio(cid:18)(cid:4)(cid:59)(cid:77)(cid:88)(cid:76)(cid:4)(cid:83)(cid:89)(cid:86)(cid:4)
(cid:40)(cid:73)(cid:80)(cid:69)(cid:91)(cid:69)(cid:86)(cid:73)(cid:4)(cid:69)(cid:82)(cid:72)(cid:4)(cid:55)(cid:56)(cid:37)(cid:39)(cid:47)(cid:4)(cid:69)(cid:87)(cid:87)(cid:73)(cid:88)(cid:87)(cid:4)(cid:86)(cid:69)(cid:84)(cid:77)(cid:72)(cid:80)(cid:93)(cid:4)(cid:70)(cid:89)(cid:77)(cid:80)(cid:72)(cid:77)(cid:82)(cid:75)(cid:4)(cid:81)(cid:83)(cid:81)(cid:73)(cid:82)(cid:88)(cid:89)(cid:81)(cid:4)(cid:69)(cid:82)(cid:72)(cid:4)
(cid:83)(cid:84)(cid:73)(cid:86)(cid:69)(cid:88)(cid:77)(cid:82)(cid:75)(cid:4)(cid:87)(cid:71)(cid:69)(cid:80)(cid:73)(cid:16)(cid:4)(cid:91)(cid:73)(cid:247)(cid:86)(cid:73)(cid:4)(cid:71)(cid:83)(cid:81)(cid:81)(cid:77)(cid:88)(cid:88)(cid:73)(cid:72)(cid:4)(cid:88)(cid:83)(cid:4)(cid:87)(cid:77)(cid:81)(cid:84)(cid:80)(cid:77)(cid:74)(cid:93)(cid:77)(cid:82)(cid:75)(cid:4)(cid:83)(cid:89)(cid:86)(cid:4)(cid:69)(cid:87)(cid:87)(cid:73)(cid:88)(cid:4)
(cid:84)(cid:83)(cid:86)(cid:88)(cid:74)(cid:83)(cid:80)(cid:77)(cid:83)(cid:4)(cid:70)(cid:93)(cid:4)(cid:87)(cid:73)(cid:80)(cid:80)(cid:77)(cid:82)(cid:75)(cid:4)(cid:80)(cid:73)(cid:87)(cid:87)(cid:4)(cid:71)(cid:83)(cid:81)(cid:84)(cid:73)(cid:88)(cid:77)(cid:88)(cid:77)(cid:90)(cid:73)(cid:4)(cid:69)(cid:87)(cid:87)(cid:73)(cid:88)(cid:87)(cid:18)(cid:4)(cid:59)(cid:73)(cid:4)(cid:91)(cid:77)(cid:80)(cid:80)(cid:4)(cid:87)(cid:73)(cid:80)(cid:80)(cid:4)(cid:69)(cid:87)(cid:87)(cid:73)(cid:88)(cid:87)(cid:4)
(cid:83)(cid:82)(cid:80)(cid:93)(cid:4)(cid:69)(cid:88)(cid:4)(cid:88)(cid:76)(cid:73)(cid:4)(cid:86)(cid:77)(cid:75)(cid:76)(cid:88)(cid:4)(cid:84)(cid:86)(cid:77)(cid:71)(cid:73)(cid:4)(cid:69)(cid:87)(cid:4)(cid:81)(cid:69)(cid:86)(cid:79)(cid:73)(cid:88)(cid:4)(cid:71)(cid:83)(cid:82)(cid:72)(cid:77)(cid:88)(cid:77)(cid:83)(cid:82)(cid:87)(cid:4)(cid:69)(cid:80)(cid:80)(cid:83)(cid:91)(cid:4)(cid:88)(cid:83)(cid:4)(cid:73)(cid:82)(cid:87)(cid:89)(cid:86)(cid:73)(cid:4)(cid:91)(cid:73)(cid:4)
(cid:75)(cid:73)(cid:82)(cid:73)(cid:86)(cid:69)(cid:88)(cid:73)(cid:4)(cid:88)(cid:76)(cid:73)(cid:4)(cid:69)(cid:84)(cid:84)(cid:86)(cid:83)(cid:84)(cid:86)(cid:77)(cid:69)(cid:88)(cid:73)(cid:4)(cid:90)(cid:69)(cid:80)(cid:89)(cid:73)(cid:4)(cid:74)(cid:83)(cid:86)(cid:4)(cid:83)(cid:89)(cid:86)(cid:4)(cid:87)(cid:76)(cid:69)(cid:86)(cid:73)(cid:76)(cid:83)(cid:80)(cid:72)(cid:73)(cid:86)(cid:87)(cid:18)(cid:4)(cid:43)(cid:77)(cid:90)(cid:73)(cid:82)(cid:4)
(cid:83)(cid:89)(cid:86)(cid:4)(cid:86)(cid:73)(cid:87)(cid:83)(cid:89)(cid:86)(cid:71)(cid:73)(cid:17)(cid:86)(cid:77)(cid:71)(cid:76)(cid:4)(cid:69)(cid:87)(cid:87)(cid:73)(cid:88)(cid:4)(cid:70)(cid:69)(cid:87)(cid:73)(cid:16)(cid:4)(cid:91)(cid:73)(cid:4)(cid:87)(cid:73)(cid:73)(cid:4)(cid:88)(cid:76)(cid:73)(cid:4)(cid:84)(cid:83)(cid:88)(cid:73)(cid:82)(cid:88)(cid:77)(cid:69)(cid:80)(cid:4)(cid:88)(cid:83)(cid:4)(cid:81)(cid:83)(cid:82)(cid:73)(cid:88)(cid:77)(cid:94)(cid:73)(cid:4)
(cid:81)(cid:83)(cid:86)(cid:73)(cid:4)(cid:88)(cid:76)(cid:69)(cid:82)(cid:4)(cid:390)(cid:399)(cid:4)(cid:70)(cid:77)(cid:80)(cid:80)(cid:77)(cid:83)(cid:82)(cid:4)(cid:83)(cid:74)(cid:4)(cid:82)(cid:83)(cid:82)(cid:17)(cid:71)(cid:83)(cid:86)(cid:73)(cid:4)(cid:69)(cid:87)(cid:87)(cid:73)(cid:88)(cid:87)(cid:18)(cid:4)(cid:51)(cid:90)(cid:73)(cid:86)(cid:4)(cid:88)(cid:77)(cid:81)(cid:73)(cid:16)(cid:4)(cid:91)(cid:73)(cid:4)(cid:73)(cid:92)(cid:84)(cid:73)(cid:71)(cid:88)(cid:4)
(cid:88)(cid:83)(cid:4)(cid:83)(cid:84)(cid:73)(cid:86)(cid:69)(cid:88)(cid:73)(cid:4)(cid:81)(cid:83)(cid:86)(cid:73)(cid:4)(cid:73)(cid:74)(cid:74)(cid:73)(cid:71)(cid:88)(cid:77)(cid:90)(cid:73)(cid:80)(cid:93)(cid:4)(cid:69)(cid:82)(cid:72)(cid:4)(cid:72)(cid:73)(cid:80)(cid:77)(cid:90)(cid:73)(cid:86)(cid:4)(cid:87)(cid:77)(cid:75)(cid:82)(cid:77)(cid:74)(cid:77)(cid:71)(cid:69)(cid:82)(cid:88)(cid:80)(cid:93)(cid:4)(cid:77)(cid:81)(cid:84)(cid:86)(cid:83)(cid:90)(cid:73)(cid:72)(cid:4)
(cid:74)(cid:77)(cid:82)(cid:69)(cid:82)(cid:71)(cid:77)(cid:69)(cid:80)(cid:4)(cid:86)(cid:73)(cid:87)(cid:89)(cid:80)(cid:88)(cid:87)(cid:4)(cid:91)(cid:77)(cid:88)(cid:76)(cid:4)(cid:69)(cid:4)(cid:81)(cid:83)(cid:86)(cid:73)(cid:4)(cid:74)(cid:83)(cid:71)(cid:89)(cid:87)(cid:73)(cid:72)(cid:4)(cid:69)(cid:87)(cid:87)(cid:73)(cid:88)(cid:4)(cid:84)(cid:83)(cid:86)(cid:88)(cid:74)(cid:83)(cid:80)(cid:77)(cid:83)(cid:18)
(cid:4)
(cid:37)(cid:82)(cid:83)(cid:88)(cid:76)(cid:73)(cid:86)(cid:4)(cid:79)(cid:73)(cid:93)(cid:4)(cid:71)(cid:83)(cid:81)(cid:84)(cid:83)(cid:82)(cid:73)(cid:82)(cid:88)(cid:4)(cid:83)(cid:74)(cid:4)(cid:83)(cid:89)(cid:86)(cid:4)(cid:87)(cid:88)(cid:86)(cid:69)(cid:88)(cid:73)(cid:75)(cid:93)(cid:4)(cid:77)(cid:87)(cid:4)(cid:88)(cid:83)(cid:4)(cid:74)(cid:89)(cid:86)(cid:88)(cid:76)(cid:73)(cid:86)(cid:4)
(cid:77)(cid:81)(cid:84)(cid:86)(cid:83)(cid:90)(cid:73)(cid:4)(cid:83)(cid:89)(cid:86)(cid:4)(cid:77)(cid:82)(cid:90)(cid:73)(cid:87)(cid:88)(cid:81)(cid:73)(cid:82)(cid:88)(cid:17)(cid:75)(cid:86)(cid:69)(cid:72)(cid:73) financial strength(cid:18)(cid:4)(cid:59)(cid:73)(cid:247)(cid:86)(cid:73)(cid:4)
(cid:88)(cid:69)(cid:86)(cid:75)(cid:73)(cid:88)(cid:77)(cid:82)(cid:75)(cid:4)(cid:69)(cid:4)(cid:82)(cid:73)(cid:88)(cid:4)(cid:72)(cid:73)(cid:70)(cid:88)(cid:17)(cid:88)(cid:83)(cid:17)(cid:41)(cid:38)(cid:45)(cid:56)(cid:40)(cid:37)(cid:4)(cid:86)(cid:69)(cid:88)(cid:77)(cid:83)(cid:4)(cid:83)(cid:74)(cid:4)(cid:395)(cid:4)(cid:88)(cid:83)(cid:4)(cid:395)(cid:18)(cid:399)(cid:4)(cid:88)(cid:77)(cid:81)(cid:73)(cid:87)(cid:16)(cid:4)(cid:91)(cid:76)(cid:77)(cid:71)(cid:76)(cid:4)
(cid:91)(cid:83)(cid:89)(cid:80)(cid:72)(cid:4)(cid:86)(cid:73)(cid:84)(cid:86)(cid:73)(cid:87)(cid:73)(cid:82)(cid:88)(cid:4)(cid:69)(cid:4)(cid:88)(cid:83)(cid:84)(cid:17)(cid:88)(cid:77)(cid:73)(cid:86)(cid:4)(cid:70)(cid:69)(cid:80)(cid:69)(cid:82)(cid:71)(cid:73)(cid:4)(cid:87)(cid:76)(cid:73)(cid:73)(cid:88)(cid:4)(cid:77)(cid:82)(cid:4)(cid:88)(cid:76)(cid:73)(cid:4)(cid:41)(cid:10)(cid:52)(cid:4)(cid:87)(cid:84)(cid:69)(cid:71)(cid:73)(cid:18)(cid:4)
(cid:59)(cid:73)(cid:4)(cid:74)(cid:89)(cid:82)(cid:72)(cid:69)(cid:81)(cid:73)(cid:82)(cid:88)(cid:69)(cid:80)(cid:80)(cid:93)(cid:4)(cid:70)(cid:73)(cid:80)(cid:77)(cid:73)(cid:90)(cid:73)(cid:4)(cid:88)(cid:76)(cid:73)(cid:4)(cid:71)(cid:83)(cid:81)(cid:70)(cid:77)(cid:82)(cid:69)(cid:88)(cid:77)(cid:83)(cid:82)(cid:4)(cid:83)(cid:74)(cid:4)(cid:80)(cid:83)(cid:91)(cid:4)(cid:72)(cid:73)(cid:70)(cid:88)(cid:4)
(cid:80)(cid:73)(cid:90)(cid:73)(cid:86)(cid:69)(cid:75)(cid:73)(cid:4)(cid:69)(cid:82)(cid:72)(cid:4)(cid:69)(cid:81)(cid:84)(cid:80)(cid:73)(cid:4)(cid:80)(cid:77)(cid:85)(cid:89)(cid:77)(cid:72)(cid:77)(cid:88)(cid:93)(cid:4)(cid:77)(cid:87)(cid:4)(cid:90)(cid:77)(cid:88)(cid:69)(cid:80)(cid:4)(cid:88)(cid:83)(cid:4)(cid:83)(cid:89)(cid:86)(cid:4)(cid:87)(cid:89)(cid:71)(cid:71)(cid:73)(cid:87)(cid:87)(cid:4)(cid:69)(cid:82)(cid:72)(cid:4)(cid:69)(cid:4)(cid:81)(cid:69)(cid:78)(cid:83)(cid:86)(cid:4)
(cid:71)(cid:83)(cid:81)(cid:84)(cid:73)(cid:88)(cid:77)(cid:88)(cid:77)(cid:90)(cid:73)(cid:4)(cid:69)(cid:72)(cid:90)(cid:69)(cid:82)(cid:88)(cid:69)(cid:75)(cid:73)(cid:18)
(cid:37)(cid:87)(cid:4)(cid:91)(cid:73)(cid:4)(cid:84)(cid:89)(cid:86)(cid:87)(cid:89)(cid:73)(cid:4)(cid:83)(cid:89)(cid:86)(cid:4)(cid:90)(cid:77)(cid:87)(cid:77)(cid:83)(cid:82)(cid:4)(cid:88)(cid:83)(cid:4)(cid:70)(cid:73)(cid:4)(cid:50)(cid:83)(cid:86)(cid:88)(cid:76)(cid:4)(cid:37)(cid:81)(cid:73)(cid:86)(cid:77)(cid:71)(cid:69)(cid:247)(cid:87)(cid:4)(cid:84)(cid:86)(cid:73)(cid:81)(cid:77)(cid:73)(cid:86)(cid:4)
(cid:4)
(cid:77)(cid:82)(cid:72)(cid:73)(cid:84)(cid:73)(cid:82)(cid:72)(cid:73)(cid:82)(cid:88)(cid:4)(cid:83)(cid:77)(cid:80)(cid:4)(cid:69)(cid:82)(cid:72)(cid:4)(cid:82)(cid:69)(cid:88)(cid:89)(cid:86)(cid:69)(cid:80)(cid:4)(cid:75)(cid:69)(cid:87)(cid:4)(cid:73)(cid:92)(cid:84)(cid:80)(cid:83)(cid:86)(cid:69)(cid:88)(cid:77)(cid:83)(cid:82)(cid:4)(cid:69)(cid:82)(cid:72)(cid:4)(cid:84)(cid:86)(cid:83)(cid:72)(cid:89)(cid:71)(cid:88)(cid:77)(cid:83)(cid:82)(cid:4)
(cid:71)(cid:83)(cid:81)(cid:84)(cid:69)(cid:82)(cid:93)(cid:16)(cid:4)(cid:91)(cid:73)(cid:247)(cid:86)(cid:73)(cid:4)(cid:84)(cid:86)(cid:83)(cid:90)(cid:77)(cid:72)(cid:77)(cid:82)(cid:75)(cid:4)(cid:86)(cid:73)(cid:80)(cid:77)(cid:69)(cid:70)(cid:80)(cid:73)(cid:16)(cid:4)(cid:73)(cid:82)(cid:90)(cid:77)(cid:86)(cid:83)(cid:82)(cid:81)(cid:73)(cid:82)(cid:88)(cid:69)(cid:80)(cid:80)(cid:93)(cid:4)(cid:86)(cid:73)(cid:87)(cid:84)(cid:83)(cid:82)(cid:87)(cid:77)(cid:70)(cid:80)(cid:73)(cid:4)
(cid:84)(cid:86)(cid:83)(cid:72)(cid:89)(cid:71)(cid:88)(cid:77)(cid:83)(cid:82)(cid:4)(cid:69)(cid:82)(cid:72)(cid:4)(cid:69)(cid:4)(cid:84)(cid:80)(cid:69)(cid:88)(cid:74)(cid:83)(cid:86)(cid:81)(cid:4)(cid:74)(cid:83)(cid:86)(cid:4)(cid:74)(cid:89)(cid:88)(cid:89)(cid:86)(cid:73)(cid:4)(cid:75)(cid:86)(cid:83)(cid:91)(cid:88)(cid:76)(cid:18)(cid:4)(cid:37)(cid:87)(cid:4)(cid:91)(cid:73)(cid:4)(cid:73)(cid:92)(cid:73)(cid:71)(cid:89)(cid:88)(cid:73)(cid:4)
(cid:83)(cid:89)(cid:86)(cid:4)(cid:87)(cid:88)(cid:86)(cid:69)(cid:88)(cid:73)(cid:75)(cid:93)(cid:16)(cid:4)(cid:91)(cid:73)(cid:247)(cid:80)(cid:80)(cid:4)return increasing amounts of cash to
shareholders(cid:4)(cid:88)(cid:76)(cid:86)(cid:83)(cid:89)(cid:75)(cid:76)(cid:4)(cid:76)(cid:77)(cid:75)(cid:76)(cid:73)(cid:86)(cid:4)(cid:72)(cid:77)(cid:90)(cid:77)(cid:72)(cid:73)(cid:82)(cid:72)(cid:87)(cid:4)(cid:69)(cid:82)(cid:72)(cid:4)(cid:83)(cid:84)(cid:84)(cid:83)(cid:86)(cid:88)(cid:89)(cid:82)(cid:77)(cid:87)(cid:88)(cid:77)(cid:71)(cid:4)
(cid:87)(cid:76)(cid:69)(cid:86)(cid:73)(cid:4)(cid:70)(cid:89)(cid:93)(cid:70)(cid:69)(cid:71)(cid:79)(cid:87)(cid:18)(cid:4)(cid:37)(cid:80)(cid:86)(cid:73)(cid:69)(cid:72)(cid:93)(cid:4)(cid:77)(cid:82)(cid:4)(cid:396)(cid:394)(cid:395)(cid:402)(cid:4)(cid:91)(cid:73)(cid:247)(cid:90)(cid:73)(cid:4)(cid:69)(cid:82)(cid:82)(cid:83)(cid:89)(cid:82)(cid:71)(cid:73)(cid:72)(cid:4)(cid:69)(cid:4)(cid:397)(cid:397)(cid:4)(cid:84)(cid:73)(cid:86)(cid:71)(cid:73)(cid:82)(cid:88)(cid:4)
(cid:72)(cid:77)(cid:90)(cid:77)(cid:72)(cid:73)(cid:82)(cid:72)(cid:4)(cid:77)(cid:82)(cid:71)(cid:86)(cid:73)(cid:69)(cid:87)(cid:73)(cid:16)(cid:4)(cid:69)(cid:4)(cid:390)(cid:395)(cid:4)(cid:70)(cid:77)(cid:80)(cid:80)(cid:77)(cid:83)(cid:82)(cid:4)(cid:87)(cid:76)(cid:69)(cid:86)(cid:73)(cid:17)(cid:86)(cid:73)(cid:84)(cid:89)(cid:86)(cid:71)(cid:76)(cid:69)(cid:87)(cid:73)(cid:4)(cid:84)(cid:86)(cid:83)(cid:75)(cid:86)(cid:69)(cid:81)(cid:4)(cid:69)(cid:82)(cid:72)(cid:4)
(cid:69)(cid:4)(cid:390)(cid:395)(cid:4)(cid:70)(cid:77)(cid:80)(cid:80)(cid:77)(cid:83)(cid:82)(cid:4)(cid:72)(cid:73)(cid:70)(cid:88)(cid:17)(cid:86)(cid:73)(cid:72)(cid:89)(cid:71)(cid:88)(cid:77)(cid:83)(cid:82)(cid:4)(cid:84)(cid:80)(cid:69)(cid:82)(cid:18)(cid:4)(cid:56)(cid:83)(cid:4)(cid:70)(cid:73)(cid:4)(cid:71)(cid:80)(cid:73)(cid:69)(cid:86)(cid:16)(cid:4)(cid:88)(cid:76)(cid:77)(cid:87)(cid:4)(cid:77)(cid:87)(cid:4)(cid:78)(cid:89)(cid:87)(cid:88)(cid:4)(cid:88)(cid:76)(cid:73)(cid:4)
(cid:70)(cid:73)(cid:75)(cid:77)(cid:82)(cid:82)(cid:77)(cid:82)(cid:75)(cid:16)(cid:4)(cid:69)(cid:82)(cid:72)(cid:4)(cid:91)(cid:73)(cid:4)(cid:73)(cid:92)(cid:84)(cid:73)(cid:71)(cid:88)(cid:4)(cid:81)(cid:83)(cid:86)(cid:73)(cid:4)(cid:83)(cid:74)(cid:4)(cid:88)(cid:76)(cid:73)(cid:87)(cid:73)(cid:4)(cid:87)(cid:76)(cid:69)(cid:86)(cid:73)(cid:76)(cid:83)(cid:80)(cid:72)(cid:73)(cid:86)(cid:17)(cid:74)(cid:86)(cid:77)(cid:73)(cid:82)(cid:72)(cid:80)(cid:93)(cid:4)
(cid:69)(cid:71)(cid:88)(cid:77)(cid:83)(cid:82)(cid:87)(cid:4)(cid:77)(cid:82)(cid:4)(cid:88)(cid:76)(cid:73)(cid:4)(cid:82)(cid:73)(cid:69)(cid:86)(cid:4)(cid:74)(cid:89)(cid:88)(cid:89)(cid:86)(cid:73)(cid:18)
(cid:4)
(cid:88)(cid:76)(cid:73)(cid:4)(cid:70)(cid:73)(cid:87)(cid:88)(cid:4)(cid:84)(cid:73)(cid:83)(cid:84)(cid:80)(cid:73)(cid:16)(cid:4)(cid:72)(cid:83)(cid:4)(cid:88)(cid:76)(cid:73)(cid:4)(cid:86)(cid:77)(cid:75)(cid:76)(cid:88)(cid:4)(cid:88)(cid:76)(cid:77)(cid:82)(cid:75)(cid:16)(cid:4)(cid:70)(cid:73)(cid:4)(cid:69)(cid:4)(cid:88)(cid:73)(cid:69)(cid:81)(cid:4)(cid:84)(cid:80)(cid:69)(cid:93)(cid:73)(cid:86)(cid:16)(cid:4)(cid:70)(cid:73)(cid:4)(cid:69)(cid:4)
(cid:75)(cid:83)(cid:83)(cid:72)(cid:4)(cid:82)(cid:73)(cid:77)(cid:75)(cid:76)(cid:70)(cid:83)(cid:86)(cid:16)(cid:4)(cid:72)(cid:73)(cid:80)(cid:77)(cid:90)(cid:73)(cid:86)(cid:4)(cid:86)(cid:73)(cid:87)(cid:89)(cid:80)(cid:88)(cid:87)(cid:18)(cid:4)(cid:59)(cid:73)(cid:4)(cid:72)(cid:83)(cid:4)(cid:88)(cid:76)(cid:73)(cid:87)(cid:73)(cid:4)(cid:88)(cid:76)(cid:77)(cid:82)(cid:75)(cid:87)(cid:4)(cid:74)(cid:83)(cid:86)(cid:4)(cid:69)(cid:80)(cid:80)(cid:4)(cid:83)(cid:74)(cid:4)(cid:83)(cid:89)(cid:86)(cid:4)
(cid:87)(cid:88)(cid:69)(cid:79)(cid:73)(cid:76)(cid:83)(cid:80)(cid:72)(cid:73)(cid:86)(cid:87)(cid:18)(cid:4)(cid:59)(cid:83)(cid:86)(cid:79)(cid:77)(cid:82)(cid:75)(cid:4)(cid:87)(cid:69)(cid:74)(cid:73)(cid:80)(cid:93)(cid:4)(cid:69)(cid:82)(cid:72)(cid:4)(cid:83)(cid:84)(cid:73)(cid:86)(cid:69)(cid:88)(cid:77)(cid:82)(cid:75)(cid:4)(cid:86)(cid:73)(cid:87)(cid:84)(cid:83)(cid:82)(cid:87)(cid:77)(cid:70)(cid:80)(cid:93)(cid:16)(cid:4)(cid:91)(cid:73)(cid:247)(cid:80)(cid:80)(cid:4)
(cid:73)(cid:92)(cid:84)(cid:73)(cid:71)(cid:88)(cid:4)(cid:88)(cid:83)(cid:4)(cid:75)(cid:73)(cid:88)(cid:4)(cid:88)(cid:76)(cid:73)(cid:4)(cid:78)(cid:83)(cid:70)(cid:4)(cid:72)(cid:83)(cid:82)(cid:73)(cid:16)(cid:4)(cid:69)(cid:82)(cid:72)(cid:4)(cid:72)(cid:83)(cid:82)(cid:73)(cid:4)(cid:86)(cid:77)(cid:75)(cid:76)(cid:88)(cid:18)
(cid:39)(cid:76)(cid:69)(cid:82)(cid:75)(cid:73)(cid:4)(cid:77)(cid:87)(cid:4)(cid:73)(cid:90)(cid:73)(cid:86)(cid:93)(cid:91)(cid:76)(cid:73)(cid:86)(cid:73)(cid:16)(cid:4)(cid:70)(cid:89)(cid:88)(cid:4)(cid:83)(cid:89)(cid:86)(cid:4)(cid:90)(cid:69)(cid:80)(cid:89)(cid:73)(cid:87)(cid:4)(cid:69)(cid:86)(cid:73)(cid:4)(cid:88)(cid:76)(cid:73)(cid:4)(cid:87)(cid:69)(cid:81)(cid:73)(cid:4)(cid:244)(cid:4)(cid:76)(cid:77)(cid:86)(cid:73)(cid:4)
(cid:55)(cid:77)(cid:82)(cid:71)(cid:73)(cid:86)(cid:73)(cid:80)(cid:93)(cid:16)
Dave Hager
President and CEO
April 9, 2018
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
(Mark One)
(cid:3) ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2017
or
(cid:4) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission File Number 001-32318
DEVON ENERGY CORPORATION
(Exact name of registrant as specified in its charter)
Delaware
(State or other jurisdiction of incorporation or organization)
333 West Sheridan Avenue, Oklahoma City, Oklahoma
(Address of principal executive offices)
73-1567067
(I.R.S. Employer identification No.)
73102-5015
(Zip code)
Registrant’s telephone number, including area code:
(405) 235-3611
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
Common stock, par value $0.10 per share
Name of each exchange on which registered
The New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes (cid:3) No (cid:4)
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes (cid:4) No (cid:3)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities
Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has
been subject to such filing requirements for the past 90 days. Yes (cid:3) No (cid:4)
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive
Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months
(or for such shorter period that the registrant was required to submit and post such files). Yes (cid:3) No (cid:4)
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not
contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by
reference in Part III of this Form 10-K or any amendment to this Form 10-K. (cid:4)
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting
company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and
“emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer
Smaller reporting company
(cid:5) Accelerated filer
(cid:6) Emerging growth company
(cid:6) Non-accelerated filer
(cid:6)
(cid:6)
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for
complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. (cid:6)
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes (cid:4) No (cid:3)
The aggregate market value of the voting common stock held by non-affiliates of the registrant as of June 30, 2017 was approximately
$16.7 billion, based upon the closing price of $31.97 per share as reported by the New York Stock Exchange on such date. On February 7, 2018,
526.1 million shares of common stock were outstanding.
Portions of Registrant’s definitive Proxy Statement relating to Registrant’s 2018 annual meeting of stockholders have been incorporated by
reference in Part III of this Annual Report on Form 10-K.
DOCUMENTS INCORPORATED BY REFERENCE
DEVON ENERGY CORPORATION
FORM 10-K
TABLE OF CONTENTS
Items 1 and 2. Business and Properties
Item 1A. Risk Factors
Item 1B. Unresolved Staff Comments
Item 3. Legal Proceedings
Item 4. Mine Safety Disclosures
PART I
PART II
Item 5. Market for Common Equity, Related Stockholder Matters and Issuer Purchases of Equity
Securities
Item 6. Selected Financial Data
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 7A. Quantitative and Qualitative Disclosures about Market Risk
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
PART III
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 Accountant Fees and Services
Item 15. Exhibits and Financial Statement Schedules
Item 16. Form 10-K Summary
Signatures
PART IV
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6
17
25
25
25
26
26
28
29
53
54
118
118
118
119
119
119
119
119
119
120
120
127
128
2
DEFINITIONS
Unless the context otherwise indicates, references to “us,” “we,” “our,” “ours,” “Devon,” the “Company” and
“Registrant” refer to Devon Energy Corporation and its consolidated subsidiaries. All monetary values, other than
per unit and per share amounts, are stated in millions of U.S. dollars unless otherwise specified. In addition, the
following are other abbreviations and definitions of certain terms used within this Annual Report on Form 10-K:
“2009 Plan” means the Devon Energy Corporation 2009 Long-Term Incentive Plan, as amended and restated.
“2015 Plan” means the Devon Energy Corporation 2015 Long-Term Incentive Plan, as amended and restated.
“2017 Plan” means the Devon Energy Corporation 2017 Long-Term Incentive Plan.
“ASC” means Accounting Standards Codification.
“ASU” means Accounting Standards Update.
“Bbl” or “Bbls” means barrel or barrels.
“Bcf” means billion cubic feet.
“BLM” means the United States Bureau of Land Management.
“Boe” means barrel of oil equivalent. Gas proved reserves and production are converted to Boe, at the
pressure and temperature base standard of each respective state in which the gas is produced, at the rate of six
Mcf of gas per Bbl of oil, based upon the approximate relative energy content of gas and oil. Bitumen and
NGL proved reserves and production are converted to Boe on a one-to-one basis with oil.
“Btu” means British thermal units, a measure of heating value.
“Canada” means the division of Devon encompassing oil and gas properties located in Canada. All dollar
amounts associated with Canada are in U.S. dollars, unless stated otherwise.
“Canadian Plan” means Devon Canada Corporation Incentive Savings Plan.
“DD&A” means depreciation, depletion and amortization expenses.
“Devon Financing” means Devon Financing Company, L.L.C.
“Devon Plan” means Devon Energy Corporation Incentive Savings Plan.
“EMH” means EnLink Midstream Holdings, LP.
“EnLink” means EnLink Midstream Partners, L.P., a master limited partnership.
“EPA” means the United States Environmental Protection Agency.
“FASB” means Financial Accounting Standards Board.
“Federal Funds Rate” means the interest rate at which depository institutions lend balances at the Federal
Reserve to other depository institutions overnight.
“G&A” means general and administrative expenses.
“GAAP” means U.S. generally accepted accounting principles.
“General Partner” means EnLink Midstream, LLC, the indirect general partner entity of EnLink.
“GeoSouthern” means GeoSouthern Energy Corporation.
“Inside FERC” refers to the publication Inside F.E.R.C.’s Gas Market Report.
“LIBOR” means London Interbank Offered Rate.
“LOE” means lease operating expenses.
“MBbls” means thousand barrels.
“MBoe” means thousand Boe.
3
“Mcf” means thousand cubic feet.
“MLP” means master limited partnership.
“MMBbls” means million barrels.
“MMBoe” means million Boe.
“MMBtu” means million Btu.
“MMcf” means million cubic feet.
“M&M operations” means marketing and midstream revenues minus marketing and midstream expenses.
“N/M” means not meaningful.
“NGL” or “NGLs” means natural gas liquids.
“NYMEX” means New York Mercantile Exchange.
“NYSE” means New York Stock Exchange.
“OPEC” means Organization of the Petroleum Exporting Countries.
“OPIS” means Oil Price Information Service.
“PHMSA” means United States Department of Transportation Pipeline and Hazardous Materials Safety
Administration.
“SEC” means United States Securities and Exchange Commission.
“Senior Credit Facility” means Devon’s syndicated unsecured revolving line of credit.
“Standardized measure” means the present value of after-tax future net revenues discounted at 10% per
annum.
“S&P 500 Index” means Standard and Poor’s 500 index.
“Tax Reform Legislation” means Tax Cuts and Jobs Act.
“TSR” means total shareholder return.
“Upstream operations” means upstream revenues minus production expenses.
“U.S.” means United States of America.
“VEX” means Victoria Express Pipeline and related truck terminal and storage assets.
“WTI” means West Texas Intermediate.
“/d” means per day.
“/gal” means per gallon.
4
INFORMATION REGARDING FORWARD-LOOKING STATEMENTS
This report includes “forward-looking statements” as defined by the SEC. Such statements include those
concerning strategic plans, our expectations and objectives for future operations, as well as other future events or
conditions, and are often identified by use of the words “expects,” “believes,” “will,” “would,” “could,” “forecasts,”
“projections,” “estimates,” “plans,” “expectations,” “targets,” “opportunities,” “potential,” “anticipates,” “outlook”
and other similar terminology. Such forward-looking statements are based on our examination of historical operating
trends, the information used to prepare our December 31, 2017 reserve reports and other data in our possession or
available from third parties. Such statements are subject to a number of assumptions, risks and uncertainties, many
of which are beyond our control. Consequently, actual future results could differ materially from our expectations
due to a number of factors, including, but not limited to:
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
the volatility of oil, gas and NGL prices;
uncertainties inherent in estimating oil, gas and NGL reserves;
the extent to which we are successful in acquiring and discovering additional reserves;
the uncertainties, costs and risks involved in oil and gas operations;
regulatory restrictions, compliance costs and other risks relating to governmental regulation, including
with respect to environmental matters;
risks related to our hedging activities;
counterparty credit risks;
risks relating to our indebtedness;
cyberattack risks;
our limited control over third parties who operate some of our oil and gas properties;
midstream capacity constraints and potential interruptions in production;
the extent to which insurance covers any losses we may experience;
competition for leases, materials, people and capital;
our ability to successfully complete mergers, acquisitions and divestitures; and
any of the other risks and uncertainties discussed in this report.
All subsequent written and oral forward-looking statements attributable to Devon, or persons acting on its
behalf, are expressly qualified in their entirety by the cautionary statements above. We assume no duty to update or
revise our forward-looking statements based on new information, future events or otherwise.
5
Items 1 and 2. Business and Properties
General
PART I
A Delaware corporation formed in 1971, and publicly held since 1988, Devon (NYSE: DVN) is an
independent energy company engaged primarily in the exploration, development and production of oil, natural gas
and NGLs. Our operations are concentrated in various North American onshore areas in the U.S. and Canada.
Additionally, we control EnLink, a publicly traded MLP with an integrated midstream business with significant size
and scale in key operating regions in the U.S. For additional information regarding our control of, and ownership
interest in, EnLink and its indirect general partner, the General Partner, see Note 20 in “Item 8. Financial Statements
and Supplementary Data” of this report.
Our principal and administrative offices are located at 333 West Sheridan, Oklahoma City, OK 73102-5015
(telephone 405-235-3611). As of December 31, 2017, Devon and its consolidated subsidiaries had approximately
4,900 employees, of which approximately 1,500 employees are employed by EnLink (through its subsidiaries).
Devon files or furnishes annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on
Form 8-K, as well as any amendments to these reports, with the SEC. Through our website, www.devonenergy.com,
we make available electronic copies of the documents we file or furnish to the SEC, the charters of the committees
of our Board of Directors and other documents related to our corporate governance. The corporate governance
documents available on our website include our Code of Ethics for Chief Executive Officer, Chief Financial Officer
and Chief Accounting Officer, and any amendments to and waivers from any provision of that Code will also be
posted on our website. Access to these electronic filings is available free of charge as soon as reasonably practicable
after filing or furnishing them to the SEC. Printed copies of our committee charters or other governance documents
and filings can be requested by writing to our corporate secretary at the address on the cover of this report. Reports
filed with the SEC are also made available on its website at www.sec.gov.
Devon Strategy
Devon is committed to delivering consistent top-quartile shareholder return among its peer group through a
highly engaged culture focused on innovation, safety, operational excellence, environmental stewardship and social
responsibility. We also maintain a strong commitment to financial strength and flexibility through all commodity
price cycles, as reflected in the company’s investment grade credit ratings.
Devon’s “2020 Vision” is our plan through the end of the decade intended to optimize returns and deliver top-
tier capital-efficient, cash-flow growth. Our 2020 Vision is focused on the following strategic priorities:
•
•
•
•
•
Maximize cash flow by optimizing base production and reducing per-unit cash costs;
Improve capital efficiency with a concentration of investment on highest-returning development
projects in the Delaware Basin and STACK;
Simplify our portfolio by monetizing non-core assets;
Improve financial strength by reducing debt; and
Return cash to shareholders.
Our portfolio of exploration and production assets and operations provides stable, environmentally responsible
production and a platform for future growth. In 2017, we continued the development of our world-class operations
in the STACK and Delaware Basin. These assets provide us with a sustainable, multi-decade growth platform that
continues to improve with our successful drilling programs. During 2017, we delivered the best well productivity in
Devon’s 46-year history and continued a five-year streak of increasing Devon’s initial 90-day production rates. With
investments in proprietary data tools, predictive analytics and artificial intelligence, we are delivering industry-
leading, initial-rate well productivity and improving the performance of our established wells. Devon has more than
doubled its onshore North American oil production since 2012 and has a deep inventory of development
opportunities to deliver future oil growth.
6
As we enter 2018 and look toward the future, we expect to achieve additional efficiencies across our portfolio.
We expect to fund activity within our cash flow, and remain committed to allocating capital in a disciplined manner
to maximize value and return. We believe we capture the full value of our assets and improve returns through
maximizing our base production and optimizing our capital program. The activities that support this strategy include
minimizing controllable downtime, enhancing well productivity, ensuring disciplined project execution, performing
premier technical work, focusing on developmental drilling and reducing our operating and capital costs.
We also continue to implement new shareholder-friendly initiatives, which include new returns-based metrics
aligned to employee compensation and the conversion to successful efforts accounting which provides greater
transparency into our financial performance.
EnLink Strategy
EnLink focuses on providing gathering, transmission, processing, storage, fractionation and marketing to
upstream oil and natural gas producers, including Devon.
EnLink connects the wells of natural gas producers in its market areas to its gathering systems, processes
natural gas for the removal of NGLs, fractionates NGLs into purity products and markets those products for a fee,
transports natural gas and ultimately provides natural gas to a variety of markets. Furthermore, EnLink purchases
natural gas from natural gas producers and other supply sources and sells that natural gas to utilities, industrial
consumers, other marketers and pipelines.
EnLink’s primary business objective is to provide stable cash flow, while growing through prudent and
profitable investments. EnLink accomplishes its objectives through long-term, fee-based contracts and maintaining a
strong financial position through a conservative and balanced capital structure highlighted by its investment grade
status. EnLink has consistently demonstrated expertise within the MLP space and continues to employ a proven
business model that includes growing, expanding and executing on its strategy within top basins where Devon and
other successful upstream producers operate.
7
Oil and Gas Properties
Property Profiles
Key summary data from each of our areas of operation as of and for the year ended December 31, 2017 are
detailed in the map below. Notes 23 and 24 to the financial statements included in “Item 8. Financial Statements and
Supplementary Data” of this report contain additional information on our segments and geographical areas.
Rockies Oil
(cid:131) 17 MBoe/d (88% liquids)
(cid:131) 3% of production
(cid:131) 30 MMBoe of proved reserves
(cid:131) 1% of proved reserves
(cid:131) 47 gross wells drilled
Delaware Basin
(cid:131) 56 MBoe/d (73% liquids)
(cid:131) 10% of production
(cid:131) 184 MMBoe of proved reserves
(cid:131) 9% of proved reserves
(cid:131) 72 gross wells drilled
Barnett Shale
(cid:131) 153 MBoe/d (27% liquids)
(cid:131) 28% of production
(cid:131) 938 MMBoe of proved reserves
(cid:131) 44% of proved reserves
(cid:131) 4 gross wells drilled
Heavy Oil
(cid:131) 131 MBoe/d (98% liquids)
(cid:131) 24% of production
(cid:131) 427 MMBoe of proved reserves
(cid:131) 20% of proved reserves
(cid:131) 107 gross wells drilled
STACK
(cid:131) 107 MBoe/d (52% liquids)
(cid:131) 20% of production
(cid:131) 456 MMBoe of proved reserves
(cid:131) 21% of proved reserves
(cid:131) 295 gross wells drilled
Eagle Ford
(cid:131) 62 MBoe/d (74% liquids)
(cid:131) 11% of production
(cid:131) 60 MMBoe of proved reserves
(cid:131) 3% of proved reserves
(cid:131) 74 gross wells drilled
Led by results from our franchise assets, STACK and Delaware Basin, Devon achieved the best drilling
results in our 46-year history. Our initial 90-day production rates in 2017 increased more than 400% from 2012
levels. These productivity improvements were driven by activity focused in top resource plays, improved subsurface
reservoir characterization, leading-edge completion designs and improvements in lateral placement. The most
significant reserves growth came from our U.S. operations, where we replaced approximately 150% of our 2017
production with proved reserves additions from the drill bit.
Delaware Basin – The Delaware Basin is one of Devon’s top-two franchise assets and continues to offer
exploration and low-risk development opportunities from many geologic reservoirs and play types, including the oil-
rich Bone Spring, Delaware, Wolfcamp and Leonard formations. We expect these oil and liquids-rich opportunities
across our acreage in the Delaware Basin to deliver high-margin growth for many years to come. During 2017, our
continued appraisal and development work enabled us to increase our proved reserves by approximately 60%. At
8
December 31, 2017, we had eight operated rigs developing this asset. In 2018, we plan to invest approximately $725
million of capital in the Delaware Basin as we shift to expanded development operations, primarily focused on the
Bone Spring formation.
STACK – The STACK development, located primarily in Oklahoma’s Canadian, Kingfisher and Blaine
counties, is one of Devon’s top-two franchise assets. Devon is currently targeting the Woodford Shale and the
Meramec zones. Our STACK position is one of the largest and best in the industry, providing visible long-term
growth. Completion design enhancements have resulted in greater productivity and improved economics. Drilling
activity in the Meramec has produced record setting initial production across our core position in the oil and liquids
window. At December 31, 2017, we had nine operated rigs with drilling focused in the Meramec formation. In 2018,
we plan approximately $700 million of capital investment and expect to accelerate full-field development activity.
Heavy Oil – Our operations in Canada are focused on our heavy oil assets in Alberta, Canada. Our most
significant Canadian operation is our Jackfish complex, an industry-leading thermal heavy oil operation in the non-
conventional oil sands of east central Alberta. We employ a recovery method known as steam-assisted gravity
drainage at Jackfish. The Jackfish operation consists of three facilities. We expect Jackfish to maintain a reasonably
flat production profile for greater than 20 years requiring approximately $200 million of annual maintenance capital
based on current economic conditions.
Our Pike oil sands acreage is situated directly to the southeast of our Jackfish acreage in east central Alberta
and has similar reservoir characteristics to Jackfish. The Pike leasehold is currently undeveloped and has no proved
reserves or production as of December 31, 2017. With our 50% partner, we continue to evaluate our development
timeline for Pike. The majority of our Pike leasehold does not expire until 2025 and 2026.
In addition to Jackfish and Pike, we hold acreage and own producing assets in the Bonnyville region, located
to the south and east of Jackfish in eastern Alberta. Bonnyville is a low-risk, high margin oil development play that
produces heavy oil by conventional means, without the need for steam injection.
In 2018, we plan approximately $275 million of capital investment in our Canadian Heavy Oil business.
Eagle Ford – We acquired our position in the Eagle Ford in 2014, with acres located in DeWitt and Lavaca
counties in south Texas. In 2017, we closed on the sale of our Lavaca assets for approximately $200 million. Since
acquiring these assets, we have delivered tremendous results by producing 119 million oil-equivalent barrels. Our
excellent results are driven by our development in DeWitt County, located in the economic core of the play. With
the highest margins in our portfolio, our Eagle Ford assets generated significant cash flow in 2017. In 2018, we plan
approximately $250 million of capital investment.
Rockies Oil – Our acreage in the Rockies is focused on emerging oil opportunities in the Powder River Basin
and the Wind River Basin. Recent drilling success in these formations has expanded our drilling inventory, and we
expect further growth as we continue to de-risk this emerging light-oil opportunity. As of December 31, 2017, we
had one operated rig targeting the Turner formation in northern Converse County of the Powder River Basin. In
2018, we plan approximately $150 million of capital investment.
Barnett Shale – This is our largest property in terms of production and proved reserves. Our leases are located
primarily in Denton, Johnson, Parker, Tarrant and Wise counties in north Texas. The Johnson County assets are
currently being marketed as part of our non-core divestiture program. Since acquiring a substantial position in this
field in 2002, we continue to introduce technology and new innovations to optimize production operations and have
transformed this asset into one of the top producing gas fields in North America. Given the sustained low gas price
environment, we continue to focus on enhancing existing well performance through re-fracturing, artificial lift and
line pressure reduction projects. In 2018, we plan on minimal development activity, with planned capital investment
of up to $50 million to optimize base production and further de-risk future development resources.
9
Proved Reserves
For estimates of our proved developed and proved undeveloped reserves and the discussion of the contribution
by each property, see Note 24 in “Item 8. Financial Statements and Supplementary Data” of this report.
Proved oil and gas reserves are those quantities of oil, gas and NGLs which, by analysis of geoscience and
engineering data, can be estimated with reasonable certainty to be economically producible from known reservoirs
under existing economic conditions, operating methods and government regulations. To be considered proved, oil
and gas reserves must be economically producible before contracts providing the right to operate expire, unless
evidence indicates that renewal is reasonably certain. Also, the project to extract the hydrocarbons must have
commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
The process of estimating oil, gas and NGL reserves is complex and requires significant judgment, as
discussed in “Item 1A. Risk Factors” of this report. As a result, we have developed internal policies for estimating
and recording reserves. Such policies require proved reserves to be in compliance with the SEC definitions and
guidance. Our policies assign responsibilities for compliance in reserves bookings to our Reserve Evaluation Group,
(the “Group”). These same policies also require that reserve estimates be made by professionally qualified reserves
estimators, as defined by the Society of Petroleum Engineers’ standards.
The Group, which is led by Devon’s Director of Reserves and Economics, is responsible for the internal
review and certification of reserves estimates. We ensure the Director and key members of the Group have
appropriate technical qualifications to oversee the preparation of reserves estimates. The Group reports to and is
managed through our finance department. No portion of the Group’s compensation is directly dependent on the
quantity of reserves booked.
The Director of the Group has approximately 30 years of industry experience with positions of increasing
responsibility for the estimation and evaluation of reserves. He has been employed by Devon for the past 17 years,
including the past 10 in his current position. His further professional qualifications include a degree in petroleum
engineering, registered professional engineer, member of the Society of Petroleum Engineers and experience in
reserves estimation for projects in the U.S. (both onshore and offshore), as well as in Canada, Asia, the Middle East
and South America.
Throughout the year, the Group performs internal reserves reviews of each operating country’s reserves. The
Group also oversees audits and reserves estimates performed by qualified third-party petroleum consulting firms.
During 2017, we engaged two such firms to audit approximately 88% of our proved reserves in accordance with
generally accepted petroleum engineering and evaluation methods and procedures. LaRoche Petroleum Consultants,
Ltd. audited approximately 85% of our 2017 U.S. reserves, and Deloitte LLP audited approximately 99% of our
Canadian reserves.
In addition to conducting these internal reviews and external reserves audits, we also have a Reserves
Committee that consists of three independent members of our Board of Directors. This committee provides
additional oversight of our reserves estimation and certification process. The members of our Reserves Committee
have educational backgrounds in geology or petroleum engineering, as well as experience relevant to the reserves
estimation process. The Reserves Committee meets a minimum of twice a year to discuss reserves issues and
policies and meets at least once a year separately with our senior reserves engineering personnel and separately with
our third-party petroleum consultants.
10
The following tables present production, price and cost information for each significant field, country and
continent.
Year Ended December 31,
2017
Barnett Shale
STACK
Jackfish
U.S.
Canada
Total North America
2016
Barnett Shale
STACK
Jackfish
U.S.
Canada
Total North America
2015
Barnett Shale
STACK
Jackfish
U.S.
Canada
Total North America
Year Ended December 31,
2017
$
Barnett Shale
$
STACK
$
Jackfish
$
U.S.
Canada
$
Total North America $
2016
$
Barnett Shale
$
STACK
$
Jackfish
$
U.S.
Canada
$
Total North America $
2015
$
Barnett Shale
$
STACK
$
Jackfish
$
U.S.
Canada
$
Total North America $
Oil (MMBbls)
Bitumen
(MMBbls)
Gas (Bcf)
NGLs (MMBbls)
Total (MMBoe)
Production
—
9
—
42
7
49
—
7
—
47
8
55
—
3
—
60
10
70
—
—
40
—
40
40
—
—
40
—
40
40
—
—
31
—
31
31
237
107
—
433
6
439
265
103
—
510
7
517
291
86
—
579
8
587
14
11
—
36
—
36
15
9
—
42
—
42
17
8
—
50
—
50
54
38
40
150
48
198
60
33
40
174
49
223
66
25
31
206
42
248
Oil (Per Bbl)
Bitumen (Per
Bbl)
Gas (Per Mcf)
NGLs (Per Bbl)
Production Cost
(Per Boe) (1)
Average Sales Price
2.47 $
2.40 $
— $
2.48 $
N/M $
2.48 $
1.76 $
1.91 $
— $
1.84 $
N/M $
1.84 $
2.00 $
2.22 $
— $
2.14 $
N/M $
2.14 $
13.67 $
17.78 $
— $
15.66 $
— $
15.66 $
10.31 $
10.86 $
— $
9.81 $
— $
9.81 $
9.62 $
8.97 $
— $
9.32 $
— $
9.32 $
6.86
4.72
11.02
6.74
11.70
7.94
5.75
4.34
8.70
6.44
9.36
7.08
5.96
5.39
12.43
7.52
13.18
8.48
49.72 $
48.43 $
— $
49.41 $
33.73 $
47.31 $
41.03 $
39.81 $
— $
38.92 $
23.96 $
36.72 $
46.47 $
43.73 $
— $
44.01 $
30.58 $
42.12 $
— $
— $
29.38 $
— $
29.38
29.38 $
— $
— $
19.82 $
— $
19.82
19.82 $
— $
— $
23.41 $
— $
23.41
23.41 $
11
(1) Represents production expense per BOE excluding production and property taxes. Jackfish and Canada
include purchases of natural gas used to heat the heavy oil reservoirs. The gas is purchased at prevailing
market prices, which vary from year to year.
Drilling Statistics
The following table summarizes our development and exploratory drilling results.
Year Ended December 31,
2017
U.S.
Canada
Total North America
2016
U.S.
Canada
Total North America
2015
U.S.
Canada
Total North America
Development Wells
(1)
Productive Dry
Exploratory Wells (1)
Productive Dry
Total Wells (1)
Productive Dry
Total
149.8 —
100.5 —
250.3 —
44.0 —
— —
44.0 —
193.8 — 193.8
100.5 — 100.5
294.3 — 294.3
88.5 —
21.5 —
110.0 —
36.4
2.0
— —
2.0
36.4
124.9
2.0 126.9
21.5 — 21.5
2.0 148.4
146.4
298.6
1.8
79.0 —
1.8
377.6
40.7 —
— —
40.7 —
339.3
1.8 341.1
79.0 — 79.0
1.8 420.1
418.3
(1) Well counts represent net wells completed during each year. Net wells are gross wells multiplied by our
fractional working interests.
The following table presents the wells that were in progress on December 31, 2017. As of February 1, 2018,
these wells were still in progress.
U.S.
Canada
Total North America
Gross (1)
Net (2)
26.0
5.0
31.0
10.1
5.0
15.1
(1) Gross wells are the sum of all wells in which we own a working interest.
(2) Net wells are gross wells multiplied by our fractional working interests in each well.
Productive Wells
The following table sets forth our producing wells as of December 31, 2017.
U.S.
Canada
Total North America
Oil Wells (1)
Natural Gas Wells
Total Wells (1)
Gross (2)(4)
Net (3)
Gross (2)(4)
Net (3)
Gross (2)(4)
Net (3)
9,165
3,195
12,360
3,379
3,085
6,464
10,103
590
10,693
7,245
413
7,658
19,268
3,785
23,053
10,624
3,498
14,122
Includes bitumen wells.
(1)
(2) Gross wells are the sum of all wells in which we own a working interest.
12
(3) Net wells are gross wells multiplied by our fractional working interests in each well.
(4)
Includes 821 and 367 gross oil and gas wells, respectively, which had multiple completions.
The day-to-day operations of oil and gas properties are the responsibility of an operator designated under
pooling or operating agreements. The operator supervises production, maintains production records, employs field
personnel and performs other functions. We are the operator of approximately 14,600 gross wells. As operator, we
receive reimbursement for direct expenses incurred to perform our duties, as well as monthly per-well producing,
drilling, and construction overhead reimbursement at rates customarily charged in the respective areas. In presenting
our financial data, we record the monthly overhead reimbursements as a reduction of G&A, which is a common
industry practice.
Acreage Statistics
The following table sets forth our developed and undeveloped lease and mineral acreage as of December 31,
2017. Of our 4.3 million net acres, approximately 2.3 million acres are held by production. The acreage in the table
includes 0.1 million, 0.2 million and 0.1 million net acres subject to leases that are scheduled to expire during 2018,
2019 and 2020, respectively. As of December 31, 2017, there were no proved undeveloped reserves associated with
our expiring acreage. Of the 0.4 million net acres set to expire by December 31, 2020, we anticipate performing
operational and administrative actions to continue the lease terms for portions of the acreage that we intend to
further assess. However, we do expect to allow a portion of the acreage to expire in the normal course of business.
In 2017, we allowed approximately 0.2 million acres to expire.
U.S.
Canada
Total North America
Developed
Undeveloped
Total
Gross (1)
Net (2)
Gross (1)
Net (2)
Gross (1)
Net (2)
1,808
685
2,493
1,203
504
1,707
(Thousands)
3,587
2,091
5,678
1,598
968
2,566
5,395
2,776
8,171
2,801
1,472
4,273
(1) Gross acres are the sum of all acres in which we own a working interest.
(2) Net acres are gross acres multiplied by our fractional working interests in the acreage.
Title to Properties
Title to properties is subject to contractual arrangements customary in the oil and gas industry, liens for taxes
not yet due and, in some instances, other encumbrances. We believe that such burdens do not materially detract from
the value of properties or from the respective interests therein or materially interfere with their use in the operation
of the business.
As is customary in the industry, a preliminary title investigation, typically consisting of a review of local title
records, is made at the time of acquisitions of undeveloped properties. More thorough title investigations, which
generally include a review of title records and the preparation of title opinions by outside counsel, are made prior to
the consummation of an acquisition of producing properties and before commencement of drilling operations on
undeveloped properties.
13
EnLink Midstream Properties
EnLink represents the primary component of our midstream operations. EnLink’s assets are comprised of
systems and other assets located in four primary regions:
•
•
•
•
Texas – The Texas assets consist of natural gas gathering, processing and transmission operations in
north Texas and the Midland and Delaware Basins in west Texas.
Oklahoma – The Oklahoma assets consist of natural gas gathering, processing and transmission
activities in Cana-Woodford, Arkoma-Woodford, Northern Oklahoma Woodford, STACK and Central
Northern Oklahoma Woodford shale areas.
Louisiana – The Louisiana assets consist of natural gas pipelines, natural gas processing plants, gas and
NGL storage facilities, fractionation facilities and NGL pipelines located in Louisiana.
Crude and Condensate – The Crude and Condensate assets consist of Ohio River Valley crude oil,
condensate, condensate stabilization, natural gas compression and brine disposal activities in the Utica
and Marcellus Shales, crude oil operations in the Permian Basin and central Oklahoma, and crude oil
activities associated with VEX located in the Eagle Ford Shale.
Marketing Activities
Oil, Gas and NGL Marketing
The spot markets for oil, gas and NGLs are subject to volatility as supply and demand factors fluctuate. As
detailed below, we sell our production under both long-term (one year or more) and short-term (less than one year)
agreements at prices negotiated with third parties. Regardless of the term of the contract, the vast majority of our
production is sold at variable, or market-sensitive, prices.
Additionally, we may enter into financial hedging arrangements or fixed-price contracts associated with a
portion of our oil, gas and NGL production. These activities are intended to support targeted price levels and to
manage our exposure to price fluctuations. See Note 4 in “Item 8. Financial Statements and Supplementary Data” of
this report for further information.
As of January 2018, our production was sold under the following contract terms.
Oil and bitumen
Natural gas
NGLs
Delivery Commitments
Short-Term
Long-Term
Variable
Fixed
Variable
Fixed
80%
52%
33%
—
4%
20%
20%
44%
47%
—
—
—
A portion of our production is sold under certain contractual arrangements that specify the delivery of a fixed
and determinable quantity. As of December 31, 2017, we were committed to deliver the following fixed quantities
of production.
Oil and bitumen (MMBbls)
Natural gas (Bcf)
NGLs (MMBbls)
Total (MMBoe)
Total
Less Than 1 Year
31
265
11
86
86
293
11
146
1-3 Years
3-5 Years
49
28
—
54
6
—
—
6
14
We expect to fulfill our delivery commitments primarily with production from our proved developed reserves.
Moreover, our proved reserves have generally been sufficient to satisfy our delivery commitments during the three
most recent years, and we expect such reserves will continue to be the primary means of fulfilling our future
commitments. However, where our proved reserves are not sufficient to satisfy our delivery commitments, we can
and may use spot market purchases to satisfy the commitments.
Customers
During 2017, 2016 and 2015, no purchaser accounted for over 10% of our consolidated sales revenue.
Competition
See “Item 1A. Risk Factors.”
Public Policy and Government Regulation
Our industry is subject to a wide range of regulations. Laws, rules, regulations, taxes, fees and other policy
implementation actions affecting our industry have been pervasive and are under constant review for amendment or
expansion. Numerous government agencies have issued extensive regulations which are binding on our industry and
its individual members, some of which carry substantial penalties for failure to comply. These laws and regulations
increase the cost of doing business and consequently affect profitability. Because public policy changes are
commonplace, and existing laws and regulations are frequently amended, we are unable to predict the future cost or
impact of compliance. However, we do not expect that any of these laws and regulations will affect our operations
materially differently than they would affect other companies with similar operations, size and financial strength.
The following are significant areas of government control and regulation affecting our operations.
Exploration and Production Regulation
Our operations are subject to federal, tribal, state, provincial and local laws and regulations. These laws and
regulations relate to matters that include:
•
•
•
•
•
•
•
•
•
•
•
•
•
acquisition of seismic data;
location, drilling and casing of wells;
well design;
hydraulic fracturing;
well production;
spill prevention plans;
emissions and discharge permitting;
use, transportation, storage and disposal of fluids and materials incidental to oil and gas operations;
surface usage and the restoration of properties upon which wells have been drilled;
calculation and disbursement of royalty payments and production taxes;
plugging and abandoning of wells;
transportation of production; and
endangered species and habitat.
15
Our operations also are subject to conservation regulations, including the regulation of the size of drilling and
spacing units or proration units; the number of wells that may be drilled in a unit; the rate of production allowable
from oil and gas wells; and the unitization or pooling of oil and gas properties. In the U.S., some states allow the
forced pooling or integration of tracts to facilitate exploration, while other states rely on voluntary pooling of lands
and leases, which may make it more difficult to develop oil and gas properties. In addition, federal and state
conservation laws generally limit the venting or flaring of natural gas, and state conservation laws impose certain
requirements regarding the ratable purchase of production. These regulations limit the amounts of oil and gas we can
produce from our wells and the number of wells or the locations at which we can drill.
Certain of our U.S. natural gas and oil leases are granted or approved by the federal government and
administered by the BLM or Bureau of Indian Affairs of the Department of the Interior. Such leases require
compliance with detailed federal regulations and orders that regulate, among other matters, drilling and operations
on lands covered by these leases and calculation and disbursement of royalty payments to the federal government,
tribes or tribal members. The federal government has been particularly active in recent years in evaluating and, in
some cases, promulgating new rules and regulations regarding competitive lease bidding, venting and flaring, oil
and gas measurement and royalty payment obligations for production from federal lands. In addition, permitting
activities on federal lands are subject to frequent delays.
Royalties and Incentives in Canada
The royalty calculation in Canada is a significant factor in the profitability of Canadian oil and gas production.
Oil sands crown royalties are determined by government regulations and are generally calculated as a percentage of
the value of the gross production, net of allowed deductions. The royalty percentage is determined on a sliding-scale
based on crown posted prices. For pre-payout oil sands projects, the regulations prescribe lower royalty rates for oil
sands projects until allowable capital costs have been recovered. In early 2016, the Alberta government adopted the
recommendation of its Royalty Review Panel. The new royalty framework preserves the existing royalty structure
and rates for oil sands. For conventional oil and gas royalty calculations, wells drilled after January 1, 2017 would
use the Modernized Royalty Framework (MRF) which prescribes a lower royalty rate until allowable costs have
been recovered. The calculation for wells post payout is based on a percentage of production net of allowed
deductions and varies with commodity price.
Marketing in Canada
Any oil or gas export requires an exporter to obtain export authorizations from Canada’s National Energy
Board.
Environmental, Pipeline Safety and Occupational Regulations
We are subject to many federal, state, provincial, tribal and local laws and regulations concerning
occupational safety and health as well as the discharge of materials into, and the protection of, the environment and
natural resources. Environmental laws and regulations relate to:
•
•
•
•
•
the discharge of pollutants into federal, provincial and state waters;
assessing the environmental impact of seismic acquisition, drilling or construction activities;
the generation, storage, transportation and disposal of waste materials, including hazardous substances;
the emission of certain gases into the atmosphere;
the monitoring, abandonment, reclamation and remediation of well and other sites, including sites of
former operations;
16
•
•
•
•
the development of emergency response and spill contingency plans;
the monitoring, repair and design of pipelines used for the transportation of oil and natural gas;
the protection of threatened and endangered species; and
worker protection.
Failure to comply with these laws and regulations can lead to the imposition of remedial liabilities,
administrative, civil or criminal fines or penalties or injunctions limiting our operations in affected areas. Moreover,
multiple environmental laws provide for citizen suits, which allow environmental organizations to act in the place of
the government and sue operators for alleged violations of environmental law. We consider the costs of
environmental protection and safety and health compliance necessary, manageable parts of our business. We have
been able to plan for and comply with environmental, safety and health initiatives without materially altering our
operating strategy or incurring significant unreimbursed expenditures. However, based on regulatory trends and
increasingly stringent laws, our capital expenditures and operating expenses related to the protection of the
environment and safety and health compliance have increased over the years and may continue to increase. We
cannot predict with any reasonable degree of certainty our future exposure concerning such matters.
Item 1A. Risk Factors
Our business and operations, and our industry in general, are subject to a variety of risks. The risks described
below may not be the only risks we face, as our business and operations may also be subject to risks that we do not
yet know of, or that we currently believe are immaterial. If any of the following risks should occur, our business,
financial condition, results of operations and liquidity could be materially and adversely impacted. As a result,
holders of our securities could lose part or all of their investment in Devon.
Volatile Oil, Gas and NGL Prices Significantly Impact our Business
Our financial condition, results of operations and the value of our properties are highly dependent on the
general supply and demand for oil, gas and NGLs, which impact the prices we ultimately realize on our sales of
these commodities. Historically, market prices and our realized prices have been volatile. For example, in recent
years, NYMEX WTI oil and NYMEX Henry Hub prices ranged from a high of over $100 per Bbl and $6 per
MMBtu, respectively, to a low of under $27 per Bbl and $1.70 per MMBtu, respectively. Such volatility is likely to
continue in the future due to numerous factors beyond our control, including, but not limited to:
•
•
•
•
•
•
•
•
•
•
•
supply of and demand for oil, gas and NGLs, including consumer demand in emerging markets, such as
China and India;
volatility and trading patterns in the commodity-futures markets;
conservation and environmental protection efforts;
production levels of members of OPEC, Russia or other producing countries;
geopolitical risks, including political and civil unrest in the Middle East, Africa and South America;
adverse weather conditions and natural disasters, such as tornadoes, earthquakes and hurricanes;
regional pricing differentials;
differing quality of production, including NGL content of gas produced;
the level of imports and exports of oil, gas and NGLs and the level of global oil, gas and NGL
inventories;
the price and availability of alternative fuels;
technological advances affecting energy consumption and production;
17
•
•
the overall economic environment; and
governmental regulations and taxes.
Commodity prices began to decline in the second half of 2014 and, despite a moderate recovery, have
generally been pressured since then. This commodity price decline adversely affected our business and results of
operations and led to substantial impairments to our oil and gas properties during 2015. A sustained weakness or
further deterioration in commodity prices could materially and adversely impact our business by resulting in, or
exacerbating, the following effects:
•
•
•
•
•
reducing the amount of oil, gas and NGLs that we can produce economically;
limiting our financial flexibility, liquidity and access to sources of capital, such as equity and debt;
reducing our revenues, operating cash flows and profitability;
causing us to decrease our capital expenditures or maintain reduced capital spending for an extended
period, resulting in lower future production of oil, gas and NGLs; and
reducing the carrying value of our properties, resulting in additional noncash write-downs.
Estimates of Oil, Gas and NGL Reserves Are Uncertain and May Be Subject to Revision
The process of estimating oil, gas and NGL reserves is complex and requires significant judgment in the
evaluation of available geological, engineering and economic data for each reservoir, particularly for new
discoveries. Because of the high degree of judgment involved, different reserve engineers may develop different
estimates of reserve quantities and related revenue based on the same data. In addition, the reserve estimates for a
given reservoir may change substantially over time as a result of several factors, including additional development
and appraisal activity, the viability of production under varying economic conditions, including commodity price
declines, and variations in production levels and associated costs. Consequently, material revisions to existing
reserve estimates may occur as a result of changes in any of these factors. Such revisions to proved reserves could
have a material adverse effect on our financial condition and the value of our properties, as well as the estimates of
our future net revenue and profitability. Our policies and internal controls related to estimating and recording
reserves are included in “Items 1 and 2. Business and Properties” of this report.
Discoveries or Acquisitions of Reserves Are Needed to Avoid a Material Decline in Reserves and Production
The production rates from oil and gas properties generally decline as reserves are depleted, while related per
unit production costs generally increase due to decreasing reservoir pressures and other factors. Therefore, our
estimated proved reserves and future oil, gas and NGL production will decline materially as reserves are produced
unless we conduct successful exploration and development activities, such as identifying additional producing zones
in existing wells, utilizing secondary or tertiary recovery techniques or acquiring additional properties containing
proved reserves. Consequently, our future oil, gas and NGL production and related per unit production costs are
highly dependent upon our level of success in finding or acquiring additional reserves.
18
Oil and Gas Operations Are Uncertain and Involve Substantial Costs and Risks
Our operating activities are subject to numerous costs and risks, including the risk that we will not encounter
commercially productive oil or gas reservoirs. Drilling for oil, gas and NGLs can be unprofitable, not only from dry
holes, but from productive wells that do not return a profit because of insufficient revenue from production or high
costs. Substantial costs are required to locate, acquire and develop oil and gas properties, and we are often uncertain
as to the amount and timing of those costs. Our cost of drilling, completing, equipping and operating wells is often
uncertain before drilling commences. Declines in commodity prices and overruns in budgeted expenditures are
common risks that can make a particular project uneconomic or less economic than forecasted. While both
exploratory and developmental drilling activities involve these risks, exploratory drilling involves greater risks of
dry holes or failure to find commercial quantities of hydrocarbons. In addition, our oil and gas properties can
become damaged, our operations may be curtailed, delayed or canceled and the costs of such operations may
increase as a result of a variety of factors, including, but not limited to:
•
•
•
•
•
•
•
•
•
unexpected drilling conditions, pressure conditions or irregularities in reservoir formations;
equipment failures or accidents;
fires, explosions, blowouts, cratering or loss of well control, as well as the mishandling or underground
migration of fluids and chemicals;
adverse weather conditions and natural disasters, such as tornadoes, earthquakes, hurricanes and
extreme temperatures;
issues with title or in receiving governmental permits or approvals;
restricted takeaway capacity for our production, including due to inadequate midstream infrastructure or
constrained downstream markets;
environmental hazards or liabilities;
restrictions in access to, or disposal of, water used or produced in drilling and completion operations;
and
shortages or delays in the availability of services or delivery of equipment.
The occurrence of one or more of these factors could result in a partial or total loss of our investment in a
particular property, as well as significant liabilities. Moreover, certain of these events could result in environmental
pollution and impact to third parties, including persons living in proximity to our operations, our employees and
employees of our contractors, leading to possible injuries, death or significant damage to property and natural
resources.
We Are Subject to Extensive Governmental Regulation, Which Can Change and Could Adversely Impact
Our Business
Our operations are subject to extensive federal, state, provincial, tribal, local and other laws, rules and
regulations, including with respect to environmental matters, worker health and safety, wildlife conservation, the
gathering and transportation of oil, gas and NGLs, conservation policies, reporting obligations, royalty payments,
unclaimed property and the imposition of taxes. Such regulations include requirements for permits to drill and to
conduct other operations and for provision of financial assurances (such as bonds) covering drilling, completion and
well operations. If permits are not issued, or if unfavorable restrictions or conditions are imposed on our drilling or
completion activities, we may not be able to conduct our operations as planned. In addition, we may be required to
make large expenditures to comply with applicable governmental laws, rules, regulations, permits or orders. For
example, certain regulations require the plugging and abandonment of wells and removal of production facilities by
current and former operators, which may result in significant costs associated with the removal of tangible
equipment and other restorative actions at the end of operations.
19
In addition, changes in public policy have affected, and in the future could further affect, our operations.
Regulatory developments could, among other things, restrict production levels, impose price controls, change
environmental protection requirements and increase taxes, royalties and other amounts payable to governments or
governmental agencies. Our operating and other compliance costs could increase further if existing laws and
regulations are revised or reinterpreted or if new laws and regulations become applicable to our operations.
Although we are unable to predict changes to existing laws and regulations, such changes could significantly impact
our profitability, financial condition and liquidity, particularly changes related to hydraulic fracturing, pipeline
safety, seismic activity, income taxes and climate change, as discussed below.
Hydraulic Fracturing – In recent years, the EPA has made proposals that subject hydraulic fracturing to
further regulation and that could potentially restrict the practice of hydraulic fracturing. For example, the EPA has
issued final regulations under the federal Clean Air Act establishing performance standards for oil and gas activities,
including standards for the capture of air emissions released during hydraulic fracturing and finalized in 2016
regulations that prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned
wastewater treatment plants. The EPA also released a study in 2016 finding that certain aspects of hydraulic
fracturing, such as water withdrawals and wastewater management practices, could result in impacts to water
resources, although the report did not identify a direct link between hydraulic fracturing and impacts to groundwater
resources. The BLM previously finalized regulations to regulate hydraulic fracturing on federal lands, but
subsequently issued a repeal of those regulations in 2017. Several states in which we operate have already adopted
and more states are considering adopting laws and/or regulations that require disclosure of chemicals used in
hydraulic fracturing and impose more stringent permitting, disclosure and well-construction requirements on
hydraulic fracturing operations. In addition, some states and municipalities have significantly limited drilling
activities and/or hydraulic fracturing or are considering doing so. Although it is not possible at this time to predict
the final outcome of these proposals, any new federal, state or local restrictions on hydraulic fracturing that may be
imposed in areas in which we conduct business could potentially result in increased compliance costs, delays in
development or restrictions on our operations.
Pipeline Safety – The pipeline assets in which we own interests, through EnLink or otherwise, are subject to
stringent and complex regulations related to pipeline safety and integrity management. The PHMSA has established
a series of rules that require pipeline operators to develop and implement integrity management programs for gas,
NGL and condensate transmission pipelines as well as certain low stress pipelines and gathering lines transporting
hazardous liquids, such as oil, that, in the event of a failure, could affect “high consequence areas.” Additional
action by PHMSA with respect to pipeline integrity management requirements may occur in the future. For
example, in 2016 PHMSA proposed new rules for gas pipelines that extend pipeline safety programs beyond high
consequence areas to newly proposed “moderate consequence areas” and would also impose more rigorous testing
and reporting requirements on such pipelines. To date, no further action has been taken. More recently, in January
2017, PHMSA finalized regulations for hazardous liquid pipelines that significantly extend and expand the reach of
certain PHMSA integrity management requirements (i.e., periodic assessments, leak detection and repairs),
regardless of the pipeline’s proximity to a high consequence area. The final rule also imposes new reporting
requirements for certain unregulated pipelines, including all hazardous liquid gathering lines. Following the change
in presidential administrations, implementation of this rule was delayed, but the final rule is expected to be
published in the Federal Register and become effective during the first quarter of 2018. At this time, we cannot
predict the cost of such requirements, but they could be significant. Moreover, violations of pipeline safety
regulations can result in the imposition of significant penalties.
Seismic Activity – Earthquakes in northern and central Oklahoma and elsewhere have prompted concerns
about seismic activity and possible relationships with the energy industry. Legislative and regulatory initiatives
intended to address these concerns may result in additional levels of regulation or other requirements that could lead
to operational delays, increase our operating and compliance costs or otherwise adversely affect our operations. In
addition, we are currently defending against certain third-party lawsuits and could be subject to additional claims,
seeking alleged property damages or other remedies as a result of alleged induced seismic activity in our areas of
operation.
Changes to Tax Laws – We are subject to U.S. federal income tax as well as income or capital taxes in various
state and foreign jurisdictions, and our operating cash flow is sensitive to the amount of income taxes we must pay.
In the jurisdictions in which we operate, income taxes are assessed on our earnings after consideration of all
20
allowable deductions and credits. Changes in the types of earnings that are subject to income tax, the types of costs
that are considered allowable deductions or the rates assessed on our taxable earnings would all impact our income
taxes and resulting operating cash flow. Recently enacted legislation commonly referred to as the Tax Cuts and Jobs
Act (the “Tax Reform Legislation”) significantly affects U.S. tax law by changing how the U.S. imposes income tax
on multinational corporations. These changes include, among others, a permanent reduction to the corporate income
tax offset by other items intended to broaden the tax base (for example, by imposing significant additional
limitations on the deductibility of interest expense and limiting the ability to deduct net operating losses).
The U.S. Department of Treasury has broad authority to issue regulations and interpretative guidance that may
significantly impact how we will apply the law and impact our results of operations in the period issued. Further,
compliance with the Tax Reform Legislation and the accounting for such provisions require complex computations
and accumulation of information not previously required or regularly produced. As a result, we have provided a
provisional estimate in our financial statements of the effect of the Tax Reform Legislation. As additional regulatory
guidance is issued by the applicable taxing authorities, as accounting treatment is clarified, as we perform additional
analysis on the application of the law, and as we refine estimates in calculating the effect, our final analysis, which
will be recorded in the period completed, may be different from our current provisional amounts, which could
materially affect our tax obligations and effective tax rate.
Climate Change – Continuing political and social attention to the issue of climate change has resulted in
legislative, regulatory and other initiatives to reduce greenhouse gas emissions, such as carbon dioxide and methane.
Policy makers at both the U.S. federal and state levels have introduced legislation and proposed new regulations
designed to quantify and limit the emission of greenhouse gases through inventories, limitations and/or taxes on
greenhouse gas emissions. For example, both the EPA and the BLM have issued regulations for the control of
methane emissions, which also include leak detection and repair requirements, for the oil and gas industry; however,
following the change in presidential administrations, both agencies have published proposed rules that seek to delay
implementation of their previously issued methane standards while the agencies review and reconsider both rules.
Nevertheless, several states where we operate, including Wyoming, have imposed venting and flaring limitations
designed to reduce methane emissions from oil and gas exploration and production activities. Legislative and state
initiatives to date have generally focused on the development of cap-and-trade and/or carbon tax programs. A cap-
and-trade program generally would cap overall greenhouse gas emissions on an economy-wide basis and require
major sources of greenhouse gas emissions or major fuel producers to acquire and surrender emission allowances.
Carbon taxes could likewise affect us by being based on emissions from our equipment and/or emissions resulting
from the use of our products by our customers.
In Canada, greenhouse gas emissions are also being addressed at both the federal and provincial level. Recent
climate policies include a legislated oil sands emission limit, and forthcoming policies include methane emissions
reduction targets. Beginning January 1, 2018, large industrial emitters are subject to the Carbon Competitiveness
Incentive Regulation (CCIR). This regulation prices carbon, but provides cost protection to emission-intensive /
trade-exposed industries, including Devon’s oil sands operations. The impact to our operations from these
regulations is expected to be minimal in the near term. Oil and gas facilities that are not subject to the CCIR are
exempt from the economy-wide carbon levy until 2023.
In addition, activists concerned about the potential effects of climate change have directed their attention at
sources of funding for fossil-fuel energy companies, which has resulted in certain financial institutions, funds and
other sources of capital restricting or eliminating their investment in oil and natural gas activities. Ultimately, this
could make it more difficult to secure funding for exploration and production activities. These various legislative,
regulatory and other activities addressing greenhouse gas emissions could adversely affect our business, including
by imposing reporting obligations on, or limiting emissions of greenhouse gases from, our equipment and
operations, which could require us to incur costs to reduce emissions of greenhouse gases associated with our
operations. Limitations on greenhouse gas emissions could also adversely affect demand for oil and gas, which
could lower the value of our reserves and have a material adverse effect on our profitability, financial condition and
liquidity.
21
Our Hedging Activities Limit Participation in Commodity Price Increases and Involve Other Risks
We enter into hedging activities with respect to a portion of our production to manage our exposure to oil, gas
and NGL price volatility. To the extent that we engage in price risk management activities to protect ourselves from
commodity price declines, we may be prevented from fully realizing the benefits of commodity price increases
above the prices established by our hedging contracts. In addition, our hedging arrangements may expose us to the
risk of financial loss in certain circumstances, including instances in which the contract counterparties fail to
perform under the contracts. Moreover, as a result of the Dodd-Frank Wall Street Reform and Consumer Protection
Act and other legislation, hedging transactions and many of our contract counterparties have become subject to
increased governmental oversight and regulations in recent years. Although we cannot predict the ultimate impact of
these laws and the related rulemaking, some of which is ongoing, existing or future regulations may adversely affect
the cost and availability of our hedging arrangements, including by causing our contract counterparties, which are
generally financial institutions and other market participants, to curtail or cease their derivatives activities.
The Credit Risk of Our Counterparties Could Adversely Affect Us
We enter into a variety of transactions that expose us to counterparty credit risk. For example, we have
exposure to financial institutions and insurance companies through our hedging arrangements, our syndicated
revolving credit facility and our insurance policies. Disruptions in the financial markets or otherwise may impact
these counterparties and affect their ability to fulfill their existing obligations and their willingness to enter into
future transactions with us.
In addition, we are exposed to the risk of financial loss from trade, joint interest billing and other receivables.
We sell our oil, gas and NGLs to a variety of purchasers, and, as an operator, we pay expenses and bill our non-
operating partners for their respective share of costs. We also frequently look to buyers of oil and gas properties
from us to perform certain obligations associated with the disposed assets, including the removal of production
facilities and plugging and abandonment of wells. Certain of these counterparties may experience insolvency,
liquidity problems or other issues and may not be able to meet their obligations and liabilities (including contingent
liabilities) owed to, and assumed from, us, particularly during a depressed or volatile commodity price environment.
Any such default by these counterparties may result in us being forced to cover the costs of those obligations and
liabilities, which could adversely impact our financial results and condition.
Our Debt May Limit Our Liquidity and Financial Flexibility, and Any Downgrade of Our Credit Rating
Could Adversely Impact Us
As of December 31, 2017, we had total consolidated indebtedness of $10.4 billion. Our indebtedness and other
financial commitments have important consequences to our business, including, but not limited to:
•
•
•
requiring us to dedicate a significant portion of our cash flows from operations to debt service
payments, thereby limiting our ability to fund working capital, capital expenditures, investments or
acquisitions and other general corporate purposes;
increasing our vulnerability to general adverse economic and industry conditions, including low
commodity price environments; and
limiting our ability to obtain additional financing due to higher costs and more restrictive covenants.
In addition, we receive credit ratings from rating agencies in the U.S. with respect to our debt. Factors that
may impact our credit ratings include, among others, debt levels, planned asset sales and purchases, liquidity,
forecasted production growth and commodity prices. We are currently required to provide letters of credit or other
assurances under certain of our contractual arrangements. Any credit downgrades could adversely impact our ability
to access financing and trade credit, require us to provide additional letters of credit or other assurances under
contractual arrangements and increase our interest rate under any credit facility borrowing as well as the cost of any
other future debt.
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Environmental Matters and Related Costs Can Be Significant
As an owner, lessee or operator of oil and gas properties, we are subject to various federal, state, provincial,
tribal and local laws and regulations relating to discharge of materials into, and protection of, the environment.
These laws and regulations may, among other things, impose liability on us for the cost of remediating pollution that
results from our operations. Environmental laws may impose strict, joint and several liability, and failure to comply
with environmental laws and regulations can result in the imposition of administrative, civil or criminal fines and
penalties, as well as injunctions limiting operations in affected areas. Any future environmental costs of fulfilling
our commitments to the environment are uncertain and will be governed by several factors, including future changes
to regulatory requirements. Changes in or additions to public policy regarding the protection of the environment
could have a significant impact on our operations and profitability.
Cyber Attacks May Adversely Impact Our Operations
Our business has become increasingly dependent on digital technologies, and we anticipate expanding our use
of technology in our operations, including through process automation and data analytics. Concurrent with this
growing dependence on technology is greater sensitivity to cyberattack activities, which have been increasing
against our industry. Cyber attackers often attempt to gain unauthorized access to digital systems for purposes of
misappropriating sensitive information, intellectual property or other assets, corrupting data or causing operational
disruptions. These attacks may be perpetrated by third parties or insiders. Techniques used in these attacks range
from highly sophisticated efforts to electronically circumvent network security to more traditional intelligence
gathering and social engineering aimed at obtaining information necessary to gain access. Cyber attacks may also be
carried out in a manner that does not require gaining unauthorized access, such as by causing denial-of-service
attacks. In addition, our vendors, midstream providers and other business partners may separately suffer disruptions
or breaches from cyber attacks, which, in turn, could adversely impact our operations and compromise our
information. Although we have not suffered material losses related to cyber attacks to date, if we were successfully
attacked, we could incur substantial remediation and other costs or suffer other negative consequences, including
litigation risks. Moreover, as the sophistication of cyber attacks continues to evolve, we may be required to expend
significant additional resources to further enhance our digital security or to remediate vulnerabilities.
Limited Control on Properties Operated by Others
Certain of the properties in which we have an interest are operated by other companies and involve third-party
working interest owners. We have limited influence and control over the operation or future development of such
properties, including compliance with environmental, health and safety regulations or the amount and timing of
required future capital expenditures. These limitations and our dependence on the operator and other working
interest owners for these properties could result in unexpected future costs and delays, curtailments or cancellations
of operations or future development, which could adversely affect our financial condition and results of operations.
Midstream Capacity Constraints and Interruptions Impact Commodity Sales
We rely on midstream facilities and systems to process our gas production and to transport our oil, gas and
NGL production to downstream markets. Such midstream systems include EnLink’s systems, as well as other
systems operated by us or third parties. Regardless of who operates the midstream systems we rely upon, a portion
of our production in any region may be interrupted or shut in from time to time due to losing access to plants,
pipelines or gathering systems. Such access could be lost due to a number of factors, including, but not limited to,
weather conditions and natural disasters, accidents, field labor issues or strikes. Additionally, we and third parties
may be subject to constraints that limit our or their ability to construct, maintain or repair midstream facilities
needed to process and transport our production. Such interruptions or constraints could negatively impact our
production and associated profitability.
23
Insurance Does Not Cover All Risks
As discussed above, our business is hazardous and is subject to all of the operating risks normally associated
with the exploration, development, production, processing and transportation of oil, gas and NGLs.
To mitigate financial losses resulting from these operational hazards, we maintain comprehensive general
liability insurance, as well as insurance coverage against certain losses resulting from physical damages, loss of well
control, business interruption and pollution events that are considered sudden and accidental. We also maintain
workers’ compensation and employer’s liability insurance. However, our insurance coverage does not provide 100%
reimbursement of potential losses resulting from these operational hazards. Additionally, insurance coverage is
generally not available to us for pollution events that are considered gradual, and we have limited or no insurance
coverage for certain risks such as political risk and war. Our insurance does not cover penalties or fines assessed by
governmental authorities. The occurrence of a significant event against which we are not fully insured could have a
material adverse effect on our profitability, financial condition and liquidity.
Competition for Assets, Materials, People and Capital Can Be Significant
Strong competition exists in all sectors of the oil and gas industry. We compete with major integrated and
independent oil and gas companies for the acquisition of oil and gas leases and properties. We also compete for the
equipment and personnel required to explore, develop and operate properties. Typically, during times of rising
commodity prices, drilling and operating costs will also increase. During these periods, there is often a shortage of
drilling rigs and other oilfield services, which could adversely affect our ability to execute our development plans on
a timely basis and within budget. Competition is also prevalent in the marketing of oil, gas and NGLs. Certain of our
competitors have financial and other resources substantially greater than ours. They also may have established
strategic long-term positions and relationships in areas in which we may seek new entry. As a consequence, we may
be at a competitive disadvantage in bidding for assets or services and accessing capital. In addition, many of our
larger competitors may have a competitive advantage when responding to factors that affect demand for oil and gas
production, such as changing worldwide price and production levels, the cost and availability of alternative fuels and
the application of government regulations.
Our Acquisition and Divestiture Activities Involve Substantial Risks
Our business depends, in part, on making acquisitions that complement or expand our current business and
successfully integrating any acquired assets or businesses. If we are unable to make attractive acquisitions, our
future growth could be limited. Furthermore, even if we do make acquisitions, they may not result in an increase in
our cash flow from operations or otherwise result in the benefits anticipated due to various risks, including, but not
limited to:
•
•
•
mistaken estimates or assumptions about reserves, potential drilling locations, revenues and costs,
including synergies and the overall costs of equity or debt;
difficulties in integrating the operations, technologies, products and personnel of the acquired assets or
business; and
unknown and unforeseen liabilities or other issues related to any acquisition for which contractual
protections prove inadequate, including environmental liabilities and title defects.
In addition, from time to time, we may sell or otherwise dispose of certain of our properties as a result of an
evaluation of our asset portfolio and to help enhance our liquidity. These transactions also have inherent risks,
including possible delays in closing, the risk of lower-than-expected sales proceeds for the disposed assets and
potential post-closing claims for indemnification. Moreover, volatility in commodity prices may result in fewer
potential bidders, unsuccessful sales efforts and a higher risk that buyers may seek to terminate a transaction prior to
closing.
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Item 1B. Unresolved Staff Comments
Not applicable.
Item 3. Legal Proceedings
We are involved in various legal proceedings incidental to our business. However, to our knowledge as of the
date of this report, there were no material pending legal proceedings to which we are a party or to which any of our
property is subject.
Devon Gas Services, L.P., a wholly-owned subsidiary of the Company, is currently in negotiations with the
EPA with respect to alleged noncompliance with the leak detection and repair requirements of EPA regulations
promulgated under the Clean Air Act at its Beaver Creek Gas Plant located near Riverton, Wyoming. Although
management cannot predict the outcome of settlement negotiations, the resolution of this matter may result in a fine
or penalty in excess of $100,000.
Item 4. Mine Safety Disclosures
Not applicable.
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PART II
Item 5. Market for Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Our common stock is traded on the NYSE. On February 7, 2018, there were 7,466 holders of record of our
common stock. We began paying regular quarterly cash dividends in the second quarter of 1993. The declaration of
future dividends is a business decision made by our Board of Directors from time to time, and will depend on
Devon’s financial condition and other relevant factors. The following table sets forth the quarterly high and low
prices for our common stock during 2017 and 2016, as well as the quarterly dividends per share.
Quarter Ended 2017:
December 31, 2017
September 30, 2017
June 30, 2017
March 31, 2017
Quarter Ended 2016:
December 31, 2016
September 30, 2016
June 30, 2016
March 31, 2016
Price Range of Common Stock
High
Low
Dividends
Per Share
$
$
$
$
$
$
$
$
42.60 $
37.44 $
43.50 $
49.45 $
50.66 $
45.62 $
39.47 $
32.93 $
33.98 $
28.80 $
29.89 $
38.02 $
36.64 $
35.01 $
25.55 $
18.07 $
0.06
0.06
0.06
0.06
0.06
0.06
0.06
0.24
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Performance Graph
The following graph compares the cumulative TSR over a five-year period on Devon’s common stock with
the cumulative total returns of the S&P 500 Index and a peer group of companies to which we compare our
performance. The peer group includes Anadarko Petroleum Corporation, Apache Corporation, Chesapeake Energy
Corporation, Concho Resources, Inc., ConocoPhillips, Continental Resources, Inc., Encana Corporation, EOG
Resources, Inc., Hess Corporation, Marathon Oil Corporation, Murphy Oil Corporation, Noble Energy, Inc.,
Occidental Petroleum Corporation and Pioneer Natural Resources Company. The graph was prepared assuming
$100 was invested on December 31, 2012 in Devon’s common stock, the S&P 500 Index and the peer group, and
dividends have been reinvested subsequent to the initial investment.
Comparison of 5-Year Cumulative Total Return
Devon, S&P 500 Index and Peer Group
$250
$200
$150
$100
$50
$-
Devon
S&P 500
Peer Group
2012
$100.00
$100.00
$100.00
2013
$120.69
$132.39
$129.02
2014
$121.13
$150.51
$116.72
2015
$64.69
$152.59
$81.53
2016
$93.62
$170.84
$108.01
2017
$85.43
$208.14
$105.93
The graph and related information should not be deemed “soliciting material” or to be “filed” with the SEC,
nor should such information be incorporated by reference into any future filing under the Securities Act of 1933, as
amended, or the Securities Exchange Act of 1934, as amended, except to the extent that we specifically incorporate
such information by reference into such a filing. The graph and information is included for historical comparative
purposes only and should not be considered indicative of future stock performance.
Issuer Purchases of Equity Securities
The following table details purchases of our common stock that were made by us during the fourth quarter of
2017. During 2017, we did not repurchase any shares that were a part of a publicly announced program.
Period
October 1 - October 31
November 1 - November 30
December 1 - December 31
Total
Total Number of
Shares Purchased (1)
9,768 $
29,160 $
2,321 $
41,249 $
Average Price Paid
per Share
35.27
38.68
39.06
37.89
(1)
Share repurchases represent shares received by us from employees for the payment of personal income tax
withholding on share-based compensation vesting.
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Under the Devon Plan, eligible employees may purchase shares of our common stock through an investment
in the Devon Stock Fund, which is administered by an independent trustee. Eligible employees purchased
approximately 46,000 shares of our common stock in 2017, at then-prevailing stock prices, that they held through
their ownership in the Devon Stock Fund. We acquired the shares of our common stock sold under this plan through
open-market purchases.
Similarly, eligible Canadian employees may purchase shares of our common stock through an investment in
the Canadian Plan, which is administered by an independent trustee. Eligible employees purchased approximately
6,200 shares of our common stock in 2017. Shares sold under the Canadian Plan were acquired through open-market
purchases. These shares and any interest in the Canadian Plan were offered and sold in reliance on the exemptions
for offers and sales of securities made outside of the U.S., including under Regulation S for offers and sales of
securities to employees pursuant to an employee benefit plan established and administered in accordance with the
law of a country other than the U.S.
Item 6. Selected Financial Data
The financial information below should be read in conjunction with “Item 7. Management’s Discussion and
Analysis of Financial Condition and Results of Operations” and “Item 8. Financial Statements and Supplementary
Data” of this report.
Statement of Earnings data:
Upstream revenues
Total revenues
Earnings (loss) from continuing operations (1)
Earnings (loss) from continuing operations
attributable to Devon (1)
Earnings (loss) from continuing operations per share
attributable to Devon:
Basic (1)
Diluted (1)
Cash dividends per common share
Balance Sheet data:
Total assets (1)
Long-term debt (2)
Stockholders' equity
Common shares outstanding
2017
2016*
2015*
2014*
2013*
$ 5,307 $ 3,981 $ 5,885 $ 11,619 $ 7,296
$ 13,949 $ 10,304 $ 13,145 $ 19,285 $ 9,362
(938)
$ 1,078 $ (1,458) $(13,645) $
(753) $
$
898 $ (1,056) $(12,896) $
(837) $
(938)
$
$
$
1.71 $ (2.09) $ (31.72) $ (2.08) $ (2.34)
1.70 $ (2.09) $ (31.72) $ (2.08) $ (2.34)
0.86
0.24 $
0.94 $
0.96 $
0.42 $
$ 30,241 $ 28,675 $ 29,673 $ 49,253 $ 44,390
$ 10,291 $ 10,154 $ 12,056 $ 9,761 $ 7,888
$ 14,104 $ 12,722 $ 11,111 $ 24,789 $ 20,729
406
409
418
525
523
*
Prior year amounts have been recast due to change in accounting principle. See Note 2 in “Item 8. Financial
Statements and Supplementary Data” of this report.
(1) Material asset impairments and acquisition and divestiture activity have had significant impacts on operating
results and the carrying value of our oil and gas assets. More discussion on these items can be found in “Item
7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and in Note 3
and Note 6 of “Item 8. Financial Statements and Supplementary Data” of this report.
(2) Debt balances at December 31, 2017, 2016, 2015 and 2014 include $3.5 billion, $3.3 billion, $3.1 billion and
$2.0 billion, respectively, of EnLink and the General Partner debt that is non-recourse to Devon.
28
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Introduction
The following discussion and analysis presents management’s perspective of our business, financial condition
and overall performance. This information is intended to provide investors with an understanding of our past
performance, current financial condition and outlook for the future and should be read in conjunction with “Item 8.
Financial Statements and Supplementary Data” of this report.
Overview of 2017 Results
During 2017, we generated solid operating results with our strategy of operating in North America’s best
resource plays, delivering superior execution, continuing disciplined capital allocation and maintaining a high
degree of financial strength. Led by our development in the STACK and Delaware Basin, we continued to improve
our 90-day initial production rates. With investments in proprietary data tools, predictive analytics and artificial
intelligence, we are delivering industry-leading, initial-rate well productivity performance and improving the
performance of our established wells.
Compared to 2016, commodity prices increased significantly and were the primary driver for improvements in
Devon’s earnings and cash flow during 2017. We exited 2017 with liquidity comprised of $2.7 billion of cash and
$2.9 billion of available credit under our Senior Credit Facility. We have no significant debt maturities until 2021.
We further enhanced our financial strength by completing approximately $415 million of our announced $1
billion asset divestiture program in 2017. We anticipate closing the remaining divestitures in 2018.
In 2018 and beyond, we have the financial capacity to further accelerate investment across our best-in-class
U.S. resource plays. We are increasing drilling activity and will continue to shift our production mix to high-margin
products. We will continue our premier technical work to drive capital allocation and efficiency and industry-
leading well productivity results. We will continue to maximize the value of our base production by sustaining the
operational efficiencies we have achieved. Finally, we will continue to manage activity levels within our cash flows.
We expect this disciplined approach will position us to deliver capital-efficient, cash-flow expansion over the next
two years.
Key measures of our financial performance in 2017 are summarized in the following table. Increased
commodity prices as well as continued focus on our production expenses improved our 2017 financial performance
as compared to 2016, as seen in the table below. More details for these metrics are found within the “Results of
Operations – 2017 vs. 2016”, below.
2017
Change
2016* Change
2015*
Net earnings (loss) attributable to Devon
Net earnings (loss) per diluted share attributable to Devon
Core earnings (loss) attributable to Devon (1)
Core earnings (loss) per diluted share attributable to Devon (1)
Retained production (MBoe/d)
Total production (MBoe/d)
Realized price per Boe (2)
Operating cash flow
Capitalized expenditures, including acquisitions
Shareholder and noncontrolling interests distributions
Cash and cash equivalents
Total debt
Reserves (MMBoe)
29
$
$
$
$
- 4%
- 11%
898 +185% $ (1,056) +92% $(12,896)
1.70 +181% $ (2.09) +93% $ (31.72)
111
427 +217% $ (367) - 430% $
0.26
0.81 +210% $ (0.73) - 382% $
580
- 3%
541
- 10%
680
543
- 14% $ 21.68
- 69% $ 4,898
- 32% $ 5,712
- 19% $
650
- 15% $ 2,310
- 22% $ 13,032
2,182
- 6%
563
611
$ 25.96 +39% $ 18.72
$ 2,909 +94% $ 1,500
- 25% $ 3,908
$ 2,937
$
525
- 8% $
481
$ 2,673 +36% $ 1,959
+2% $10,154
$10,406
+5% 2,058
2,152
*
Prior year amounts have been recast due to change in accounting principle. See Note 2 in “Item 8. Financial
Statements and Supplementary Data” of this report.
(1) Core earnings and core earnings per share attributable to Devon are financial measures not prepared in
accordance with GAAP. For a description of core earnings and core earnings per share attributable to Devon,
as well as reconciliations to the comparable GAAP measures, see “Non-GAAP Measures” in this Item 7.
Excludes any impact of oil, gas and NGL derivatives.
(2)
Business and Industry Outlook
Devon marked its 46th anniversary in the oil and gas business and its 29th year as a public company during
2017. As an established company with a strong leadership team, we have experience operating in periods of
challenged commodity prices. With our focused strategy and portfolio of quality assets, we are focused on
navigating the current environment while ensuring our long-term financial strength.
Market prices for crude oil and natural gas are inherently volatile. Therefore, we cannot predict with certainty
the future prices for the commodities we produce and sell. During 2017, WTI oil prices ranged from approximately
$42.00/Bbl to $60.00/Bbl, supported by increasing global demand and historically high OPEC compliance with its
oil production cuts that were put in place in 2016 for the first half of 2017. Following the decision by both OPEC
and non-OPEC producers to extend the agreement to reduce output by nearly 1.8 million barrels per day through the
end of 2018, oil prices increased approximately 15% in the fourth quarter of 2017, averaging $55.49/Bbl. Current
market fundamentals indicate improved prices for crude oil in 2018; however, changes in OPEC production
strategies, the macro-economic environment, geopolitical risks or other factors could impact current forecasts. As
such, we anticipate continued volatility into 2018 and we continue to execute on our hedging strategy to mitigate
such volatility.
Leveraging the success of our 2017 results, we have a solid financial condition and anticipate expanding our
oil and gas investment by approximately 10% in 2018, while drilling and completing approximately 25% more
wells. Our 2018 outlook is focused on our high returning assets in the STACK and Delaware Basin and achieving
top-line oil-equivalent production growth of 6%-9%, on a retained asset basis, through some of our best-in-class
positions. Additionally, we continued to execute our hedging program in 2017 and now have approximately 40% of
our oil and 50% of our gas production hedged for 2018. With our anticipated results and hedging program, we
intend to fully fund our increased activity with our operating cash flow. Additionally, we are targeting reducing our
debt by approximately $1 billion.
Finally, EnLink continues to be a strategic advantage for us. With annual distributions to us of approximately
$270 million, EnLink provides a visible cash flow stream to be further invested in our upstream capital programs.
30
Results of Operations – 2017 vs. 2016
The following graphs, discussion and analysis are intended to provide an understanding of our results of
operations and current financial condition. Specifically, the graph below shows the change in net earnings from
2016 to 2017. The material changes are further discussed by category on the following pages. To facilitate the
review, these numbers are being presented before consideration of earnings attributable to noncontrolling interests.
Additional information regarding noncontrolling interests is discussed in Note 20 in “Item 8. Financial Statements
and Supplementary Data” of this report.
The graph below presents the drivers of the upstream operations change presented above, with additional
details and discussion of the drivers following the graph.
*
Prior year amounts, including amounts in the following tables, have been recast due to change in accounting
principle. See Note 2 in “Item 8. Financial Statements and Supplementary Data” of this report.
31
Upstream Operations
Oil, Gas and NGL Production
2017
% of
Total
2016 Change
Oil and bitumen (MBbls/d)
STACK
Delaware Basin
Rockies Oil
Heavy Oil
Eagle Ford
Barnett Shale
Other
Retained assets
Divested assets
Total Oil
Bitumen
Total Oil and bitumen
Gas (MMcf/d)
STACK
Delaware Basin
Rockies Oil
Heavy Oil
Eagle Ford
Barnett Shale
Other
Retained assets
Divested assets
Total
NGLs (MBbls/d)
STACK
Delaware Basin
Rockies Oil
Eagle Ford
Barnett Shale
Other
Retained assets
Divested assets
Total
26 11% 19 +38%
- 7%
31 13% 33
+1%
6% 14
14
- 19%
18
7% 22
- 14%
34 14% 39
- 25%
1%
1
- 28%
2% 11
- 4%
132 54% 139
- 87%
1% 12
- 11%
134 55% 151
+1%
110 45% 109
- 6%
260
244
1
8
2
2017
% of
Total
2016 Change
90
15
17
95
304 25% 293
90
7%
25
1%
2%
20
8% 101
667 55% 741
13
1,199 99% 1,283
1% 130
1,413
4
1,203
1%
11
+4%
+1%
- 39%
- 14%
- 6%
- 10%
- 16%
- 7%
- 97%
- 15%
2017
% of
Total
2016 Change
1
1%
31 31% 26 +18%
- 9%
11 11% 12
+2%
1
- 19%
13 13% 16
- 8%
41 42% 45
2 +39%
- 2%
14 - 100%
- 15%
116
99 100% 102
— —
99
2%
2
Combined (MBoe/d)
STACK
Delaware Basin
Rockies Oil
Heavy Oil
Eagle Ford
Barnett Shale
Other
Retained assets
Divested assets
Total
2017
% of
Total
2016 Change
107 20% 93 +15%
- 6%
56 10% 60
- 8%
17
3% 19
- 2%
131 24% 134
- 13%
62 11% 72
- 10%
153 28% 169
- 5%
15
3% 16
- 4%
541 99% 563
- 96%
1% 48
- 11%
611
2
543
Production declines reduced our upstream
revenues by $427 million primarily as a result of our
U.S. non-core divestitures that occurred throughout
2016 and 2017. Retained production volumes decreased
due to reduced completion activity in the Eagle Ford
and natural production declines in the Barnett Shale.
These decreases were partially offset by expanded
drilling and performance in the STACK.
Oil, Gas and NGL Prices
2017 Realization 2016 Change
Oil and bitumen (per
Bbl)
WTI index
Access Western Blend
index
U.S.
Canada
Realized price,
unhedged
Cash settlements
Realized price, with
hedges
$50.99
$43.36 +18%
$36.90
$49.41
$29.99
$26.96 +37%
97% $38.92 +27%
59% $20.53 +46%
$39.23
$ 0.23
77% $29.65 +32%
$ (0.43)
$39.46
77% $29.22 +35%
2017 Realization 2016 Change
Gas (per Mcf)
Henry Hub index
Realized price, unhedged
Cash settlements
Realized price, with
hedges
$3.11
$2.48
$0.08
$2.46 +26%
80% $1.84 +35%
$0.07
$2.56
82% $1.91 +34%
2017 Realization 2016 Change
NGLs (per Bbl)
Mont Belvieu blended
index (1)
Realized price,
unhedged
Cash settlements
Realized price, with
hedges
$24.77
$17.20 +44%
$15.66
$ (0.10)
63% $ 9.81 +60%
$ (0.11)
$15.56
63% $ 9.70 +60%
(1) Based upon composition of our NGL barrel.
32
2017 2016 Change
Production Expenses
Combined (per Boe)
U.S.
Canada
Realized price, unhedged
Cash settlements
Realized price, with hedges
$ 24.88 $ 18.34 +36%
$ 29.39 $ 20.07 +46%
$ 25.96 $ 18.72 +39%
$ 0.27 $ (0.05)
$ 26.23 $ 18.67 +40%
Upstream revenues increased $1.4 billion as a
result of higher unhedged, realized prices across our
entire portfolio. The increase in oil and bitumen sales
primarily resulted from higher average WTI crude
index prices, which were 18% higher in 2017.
Additionally, our oil and bitumen sales benefited from
tighter differentials to the WTI index. The increase in
gas sales were driven by higher North American
regional index prices upon which our gas sales are
based and higher NGL prices at the Mont Belvieu,
Texas hub.
As further discussed in Note 1 in “Item 8.
Financial Statements and Supplementary Data” of this
report, in 2018 the presentation of certain processing
arrangements will change from a net to a gross
presentation. We estimate the change to increase our
upstream revenues and production expenses by
approximately $250 million annually with no impact to
net earnings.
Commodity Derivatives
Oil
Natural gas
NGL
Total cash settlements
Valuation changes
Total
$
2017 2016 Change
$
(41) +151%
21 $
+0%
35
35
(5) +40%
(3)
(11) N/M
53
104
(190) +155%
157 $ (201) +178%
Cash settlements as presented in the tables above
represent realized gains or losses related to the
instruments described in Note 4 in “Item 8. Financial
Statements and Supplementary Data” of this report.
In addition to cash settlements, we also recognize
fair value changes on our oil, gas and NGL derivative
instruments in each reporting period. The changes in
fair value resulted from new positions and settlements
that occurred during each period, as well as the
relationship between contract prices and the associated
forward curves.
LOE
Gathering & transportation
Production taxes
Property taxes
Total
Per Boe:
LOE
Gathering & transportation
Percent of oil, gas and NGL sales:
2017
927
$
647
194
55
$ 1,823
2016
$ 1,027
555
147
74
$ 1,803
$
$
4.67
3.26
$
$
4.59
2.48
Change
- 10 %
+17 %
+32 %
- 26 %
+1 %
+2 %
+31 %
3.8 %
3.5 %
Production taxes
+7 %
LOE decreased $100 million primarily due to our
non-core U.S. property divestitures in 2016. Continued
well optimization and cost reduction initiatives across
our portfolio have offset industry inflation. These
initiatives have been primarily focused on reducing
costs associated with water disposal, power and fuel,
compression and workovers.
Gathering and transportation expense increased
$92 million primarily due to a full year of the Access
Pipeline transportation tolls, which commenced in the
fourth quarter of 2016 subsequent to the sale of our
interest in the pipeline. Our Access transportation
agreement contains a base transportation commitment,
which for the initial five years averages $110 million
annually.
Production taxes increased on an absolute dollar
basis primarily due to the increase in our U.S. upstream
revenues, on which the majority of our production taxes
are assessed.
Property taxes decreased as a result of lower
property value assessments from the local taxing
authorities across our key operating areas and as a
result of our U.S. non-core divestitures.
Marketing & Midstream Operations
Operating revenues
Product purchases
Operations and maintenance expenses
EnLink margin
Devon margin
Total
2017 2016 Change
$ 5,740 $ 4,252
(4,362) (3,015)
(398)
839
(49)
790
(418)
960
(48)
912 $
+35%
+45%
+5%
+14%
- 2%
+15%
$
The overall increase in marketing and midstream
operating margin was primarily due to an increase in
EnLink’s throughput volumes related to gas processing
and transmission activities. Devon’s margins continue
to be negatively impacted by downstream marketing
commitments. We are actively engaged in optimization
activities to reduce the costs of downstream
commitments; however, we expect such commitments
will continue to negatively impact our margin in 2018.
As further discussed in Note 1 in “Item 8. Financials
Statements and Supplementary Data” of this report, in
2018 EnLink’s marketing and midstream revenues are
estimated to decrease by 6-10% with a corresponding
decrease to marketing and midstream expenses as a
result of complying with the new revenue recognition
accounting standard.
33
Exploration Expenses
Financing Costs, net
Unproved impairments
Geological and geophysical
Exploration overhead and other
Total
$
2017 2016 Change
$
217 $
110
53
380 $
77 +182%
65 +70%
- 27%
73
215 +77%
Unproved impairments primarily relate to a
portion of acreage in our U.S. non-core operations upon
which we do not intend to pursue further exploration
and development. Geological and geophysical costs
increased primarily in the STACK and Delaware Basin.
Depreciation, Depletion and Amortization
Oil and gas per Boe
Oil and gas
Midstream and other assets
Devon
EnLink
Total
2017 2016 Change
$ 7.15 $ 6.47 +11%
- 2%
$ 1,419 $ 1,446
- 25%
146
- 4%
1,529 1,592
+8%
504
- 1%
$ 2,074 $ 2,096
110
545
Our oil and gas DD&A remained relatively flat as
compared to the prior year. Increases in oil and gas
DD&A rates due to continued development in the
STACK and Delaware Basin were offset by reduced
production volumes resulting from the 2016 U.S. asset
divestitures. DD&A from our midstream and other
assets decreased due to the divestiture of the Access
Pipeline in the fourth quarter of 2016.
General and Administrative Expenses
Labor and benefits
Non-labor
Reimbursed G&A
Total Devon
EnLink
Total
2017 2016 Change
$ 589 $ 614
215
(82)
747
118
$ 872 $ 865
- 4%
+6%
- 11%
- 0%
+8%
+1%
228
(73)
744
128
Labor and benefits decreased primarily as a result
of the workforce reduction that occurred in February
2016 as discussed in Note 7 in “Item 8. Financial
Statements and Supplementary Data” of this report.
Non-labor costs were higher due to an increase in costs
related to automation and process improvements.
Reimbursed G&A decreased primarily due the
divestitures of operated properties in 2016. EnLink
G&A increased primarily due to higher compensation
costs.
Financing costs, net decreased $409 million
primarily as a result of our $2.1 billion early debt
retirement in 2016. For further discussion of early
retirement premiums and reduced interest expense
resulting from our lower debt balances, see Note 16 in
“Item 8. Financial Statements and Supplementary Data”
of this report.
Other
Asset impairments
Asset dispositions
Restructuring
Other
Total
2017 2016 Change
$
17 $ 1,310
(217) (1,483)
—
(124)
$ (324) $
267 N/M
108 - 215%
202 - 260%
- 99%
- 85%
Asset impairments in 2016 primarily related to
goodwill and other intangible asset impairments related
to EnLink’s business. Additional information regarding
the impairments is discussed in Note 6 in “Item 8.
Financial Statements and Supplementary Data” of this
report.
We recognized gains in conjunction with our
non-core U.S. upstream asset dispositions in both 2016
and 2017 and the divestiture of our 50% interest in the
Access Pipeline in 2016. For further discussion, see
Note 3 in “Item 8. Financial Statements and
Supplementary Data” of this report.
During 2016, we recognized restructuring and
transaction costs of $267 million primarily as a result of
our workforce reduction. For discussion of our
reorganization programs and the associated
restructuring costs, see Note 7 in “Item 8. Financial
Statements and Supplementary Data” of this report.
The remaining change in other expense was
driven primarily by changes on foreign currency
exchange instruments as further discussed in Note 7 in
“Item 8. Financial Statements and Supplementary Data”
of this report.
Income Taxes
2017
2016
Current expense
Deferred expense (benefit)
Total expense (benefit)
Effective income tax rate
$
$
$
112
(294)
(182)
$
(20%)
100
41
141
(11%)
For discussion on income taxes, see Note 8 in
“Item 8. Financial Statements and Supplementary Data”
of this report.
34
Results of Operations – 2016 vs. 2015
The graph below shows the change in net earnings from 2015 to 2016. The material changes are further
discussed by category on the following pages. To facilitate the review, these numbers are being presented before
consideration of earnings attributable to noncontrolling interests. Additional information regarding noncontrolling
interests is discussed in Note 20 in “Item 8. Financial Statements and Supplementary Data” of this report.
The graph below presents the drivers of the upstream operations changed presented above, with additional
details and discussion of the drivers following the graph.
*
Prior year amounts, including amounts in the following tables, have been recast due to change in accounting
principle. See Note 2 in “Item 8. Financial Statements and Supplementary Data” of this report.
35
Upstream Operations
Oil, Gas and NGL Production
2016
% of
Total
2015 Change
Oil and bitumen (MBbls/d)
STACK
Delaware Basin
Rockies Oil
Heavy Oil
Eagle Ford
Barnett Shale
Other
Retained assets
Divested assets
Total Oil
Bitumen
Total Oil and bitumen
Gas (MMcf/d)
STACK
Delaware Basin
Rockies Oil
Heavy Oil
Eagle Ford
Barnett Shale
Other
Retained assets
Divested assets
Total
NGLs (MBbls/d)
STACK
Delaware Basin
Rockies Oil
Eagle Ford
Barnett Shale
Other
Retained assets
Divested assets
Total
7%
7 +152%
19
- 16%
33 13% 39
- 9%
5% 15
14
- 17%
22
9% 27
- 35%
39 15% 61
- 28%
0%
1
1
- 11%
11
4% 13
- 15%
139 53% 163
- 56%
12
5% 28
151 58% 191
- 21%
109 42% 84 +29%
- 6%
260
275
2016
% of
Total
2015 Change
293 21% 239 +23%
71 +27%
6%
90
- 37%
40
2%
25
- 11%
1%
22
20
- 28%
101
7% 141
- 9%
741 53% 815
- 22%
17
- 5%
1,283 91% 1,345
- 51%
9% 265
130
- 12%
1,610
1,413
1%
13
2016
% of
Total
2015 Change
1
26 23% 21 +22%
9 +28%
12 10%
- 9%
1
1%
- 33%
16 14% 23
- 12%
45 39% 51
- 59%
4
- 7%
102 88% 109
- 50%
14 12% 27
- 15%
136
116
1%
2
Combined (MBoe/d)
STACK
Delaware Basin
Rockies Oil
Heavy Oil
Eagle Ford
Barnett Shale
Other
Retained assets
Divested assets
Total
2016
% of
Total
2015 Change
93 15% 68 +37%
- 1%
60 10% 60
19
- 17%
3% 23
134 22% 115 +17%
- 33%
72 12% 107
- 10%
169 28% 188
- 13%
2% 19
16
- 3%
563 92% 580
- 52%
8% 100
48
- 10%
680
611
Production declines reduced our upstream
revenues by $620 million. Production volumes
decreased due to our reduction in exploration and
development activity related to our retained assets
during 2016. While expanded drilling in the STACK
and the performance of our Jackfish assets drove
production increases, these production increases were
more than offset by reduced completion activity in the
Eagle Ford and natural production declines in the
Barnett Shale and Rockies Oil. Additionally, our
production decreased as a result of our U.S. non-core
divestitures that occurred throughout 2016.
Oil, Gas and NGL Prices
2016 Realization 2015 Change
Oil and bitumen (per
Bbl)
WTI index
Access Western Blend
index
U.S.
Canada
Realized price,
unhedged
Cash settlements
Realized price, with
hedges
$43.36
$48.87
- 11%
$26.96
$38.92
$20.53
$32.18
90% $44.01
47% $25.14
$29.65
$ (0.43)
68% $36.39
$20.72
- 16%
- 12%
- 18%
- 19%
$29.22
67% $57.11
- 49%
2016 Realization 2015 Change
Gas (per Mcf)
Henry Hub index
Realized price, unhedged
Cash settlements
Realized price, with
hedges
NGLs (per Bbl)
Mont Belvieu blended index
(1)
Realized price, unhedged
Cash settlements
Realized price, with hedges
$2.46
$1.84
$0.07
$2.67
75% $2.14
$0.57
- 8%
- 14%
$1.91
77% $2.71
- 30%
2016 Realization 2015 Change
$17.20
$ 9.81
$ (0.11)
$ 9.70
$16.93
57% $ 9.32
$ —
56% $ 9.32
+2%
+5%
+4%
(1) Based upon composition of average Devon NGL
barrel.
36
are assessed. Property taxes decreased as a result of
lower property value assessments from the local taxing
authorities across our key operating areas and as a
result of our U.S. non-core divestitures.
Marketing & Midstream Operations
Operating revenues
Product purchases
Operations and maintenance
expenses
EnLink margin
Devon margin
Total
2016 2015 Change
$ 4,252 $ 4,451
(3,015) (3,245)
- 4%
- 7%
(398)
839
(49)
790 $
$
- 5%
+7%
(419)
787
12 N/M
799
- 1%
The overall decrease was primarily due to lower
margins on Devon’s downstream marketing
commitments, offset by EnLink’s margin growth
largely related to its acquisition activity in late 2015
and the first quarter of 2016.
Exploration Expenses
Unproved impairments
Geological and geophysical
Exploration overhead and other
Total
$
2016 2015 Change
$
77 $
65
73
215 $
260
108
83
451
- 70%
- 40%
- 13%
- 52%
Unproved impairments primarily relate to a
portion of acreage in our non-core U.S. operations upon
which we do not intend to pursue further exploration
and development. Geological and geophysical costs
were lower due to a reduced exploration capital
program in 2016.
Depreciation, Depletion and Amortization
Oil and gas per Boe
Oil and gas
Midstream and other assets
Devon
EnLink
Total
2016 2015 Change
$ 6.47 $ 13.99
$ 1,446 $ 3,474
161
1,592 3,635
- 54%
- 58%
- 10%
- 56%
387 +30%
- 48%
$ 2,096 $ 4,022
146
504
DD&A from our oil and gas properties decreased
largely because of our significant asset impairments
recognized in 2015. For discussion on asset
impairments, see Note 6 in “Item 8. Financial
Statements and Supplementary Data” of this report.
EnLink’s DD&A increased primarily due to
acquisitions in 2015 and 2016.
Combined (per Boe)
U.S.
Canada
Realized price, unhedged
Cash settlements
Realized price, with hedges
2016 2015 Change
$ 18.34 $ 21.12
$ 20.07 $ 24.46
$ 18.72 $ 21.68
$ (0.05) $ 9.74
$ 18.67 $ 31.42
- 13%
- 18%
- 14%
- 41%
Upstream revenues decreased $580 million as a
result of lower unhedged, realized prices for oil,
bitumen and gas. The decrease in oil and bitumen sales
primarily resulted from lower average WTI crude index
prices, which were 11% lower in 2016 as compared to
2015. The decrease in gas sales was driven by lower
North American regional index prices upon which our
gas sales are based. These decreases were partially
offset by slightly higher NGL prices at the Mont
Belvieu, Texas hub.
Commodity Derivatives
Oil
Natural gas
NGL
Total cash settlements
Valuation changes
Total
Production Expenses
LOE
Gathering & transportation
Production taxes
Property taxes
Total
Per Boe:
LOE
Gathering & transportation
Percent of oil, gas and NGL
sales:
2016 2015 Change
$
(41) $ 2,083 - 102%
- 89%
333
35
(5)
— N/M
(11) 2,416 - 100%
(190) (1,913) +90%
503 - 140%
$ (201) $
2016
$1,027
555
147
74
$1,803
2015
$1,509
595
207
128
$2,439
$ 4.59
$ 2.48
$ 6.08
$ 2.40
Change
- 32%
- 7%
- 29%
- 42%
- 26%
- 24%
+4%
Production taxes
3.5%
3.8%
- 8%
LOE and LOE per BOE decreased as a result of
our cost reduction initiatives, well optimization and our
non-core oil and gas property divestitures. On an
absolute dollar basis, LOE decreased approximately
$200 million as a result of our U.S. upstream
divestitures.
Gathering and transportation decreased primarily
as a result of U.S. upstream asset divestitures partially
offset by $28 million of Access Pipeline transportation
tolls which commenced in the fourth quarter of 2016
subsequent to the sale of our interest in the pipeline.
Production taxes decreased on an absolute dollar
basis primarily due to the decrease in our U.S. upstream
revenues, on which the majority of our production taxes
37
General and Administrative Expenses
Labor and benefits
Non-labor
Reimbursed G&A
Total Devon
EnLink
Total
2016 2015 Change
$ 614 $ 866
310
215
(82)
(120)
747 1,056
137
118
$ 865 $ 1,193
- 29%
- 31%
- 31%
- 29%
- 14%
- 27%
G&A decreased due to workforce reductions, as
discussed in Note 7 in “Item 8. Financial Statements
and Supplementary Data” of this report, and other cost
reduction initiatives in response to the decline in
commodity prices. Reimbursed G&A decreased
primarily due to a reduction in drilling activity, as well
as the divestiture of operated properties. EnLink G&A
decreased primarily due to lower employee
compensation expense and other cost reduction
initiatives during 2016.
Financing Costs, net
Financing costs, net increased $388 million
primarily as a result of our $2.1 billion early debt
retirement. For further discussion, see Note 16 in “Item
8. Financial Statements and Supplementary Data” of
this report.
Other
Asset impairments
Asset dispositions
Restructuring
Other
Total
- 93%
2016 2015 Change
$ 1,310 $17,647
(1,483)
267
108
186
202 $17,918
7 N/M
78 +242%
- 42%
- 99%
$
Asset impairments largely related to our oil and
gas assets and resulted from a significant decline in
forecasted commodity prices during 2015 and 2016.
Asset impairments for 2016 and 2015 also related to
goodwill and other intangible asset impairments related
to EnLink’s business. Additional information regarding
the impairments is discussed in Note 6 in “Item 8.
Financial Statements and Supplementary Data” of this
report.
We recognized gains in conjunction with our
non-core U.S. upstream asset dispositions in 2016 and
the divestiture of our 50% interest in the Access
Pipeline in 2016. For further discussion, see Note 3 in
“Item 8. Financial Statements and Supplementary Data”
of this report.
During 2016, we recognized restructuring and
transactions costs of $267 million primarily as a result
of our workforce reduction. For discussion of our
restructuring programs and the associated restructuring
costs, see Note 7 in “Item 8. Financial Statements and
Supplementary Data” of this report.
Income Taxes
Current expense
Deferred expense (benefit)
Total expense (benefit)
Effective income tax rate
$
$
2016
2015
100
41
141
$
$
(237)
(5,976)
(6,213)
(11%)
31%
For discussion on income taxes, see Note 8 in
“Item 8. Financial Statements and Supplementary Data”
of this report.
38
Capital Resources, Uses and Liquidity
The following table presents the major source and use categories of Devon and EnLink’s cash and cash
equivalents.
Operating cash flow
Issuance of common stock
Divestitures of property
and investments
Capital expenditures
Acquisitions of property,
equipment and businesses
Debt activity, net
Shareholder and noncontrolling
interests distributions
EnLink and General Partner
distributions
Subsidiary unit transactions
Effect of exchange rate
and other
Net change in cash and
cash equivalents
Cash and cash equivalents at
end of period
Devon
2016* 2015* 2017 2016* 2015* 2017
Consolidated
2016* 2015*
2017
$ 2,209 $
834 $ 4,271 $ 700 $ 666 $ 627 $ 2,909 $ 1,500 $ 4,898
— 1,469 — — — — — 1,469 —
EnLink
415 3,020
93
(1,968) (1,384) (4,214) (791) (663)
106 192
1
107
607 3,113
(573) (2,759) (2,047) (4,787)
(46)
(849)
— (3,383)
(583) — (792)
770
(524)
2 228 1,061
(46) (1,641) (1,107)
2 (3,155) 1,831
(127)
(221)
(396) (354) (304)
(254)
(481)
(525)
(650)
265
265
— —
268 (265) (265)
654 501 892
(268) — — —
679
892
501
25
(53)
(96)
4
34 139
(145)
(19)
43
(141)
$
695 $ (345) $
880 $ 19 $
(6) $ (50) $
714 $ (351) $
830
$ 2,642 $ 1,947 $ 2,292 $ 31 $ 12 $
18 $ 2,673 $ 1,959 $ 2,310
*
Prior year amounts have been recast due to change in accounting principle. See Note 2 in “Item 8. Financial
Statements and Supplementary Data” of this report.
Devon Sources and Uses of Cash
Operating Cash Flow
Net cash provided by operating activities continued to be a significant source of capital and liquidity in 2017.
Our operating cash flow increased $1.4 billion, or 165%, as compared to 2016 due to significantly higher
commodity prices. In 2017, our operating cash flow fully funded our capital expenditure program as well as our
dividends.
Our operating cash flow decreased $3.4 billion, or 80% from 2015 to 2016. While commodity prices
decreased from 2015 to 2016, the primary driver of the decrease was due to the expiration of certain favorable hedge
positions that provided us with an additional $2.4 billion of additional operating cash flow in 2015. In 2016 and
2015, our operating cash flow did not fully fund our capital requirements and dividends; as a result, we utilized
available cash balances and divestiture proceeds to supplement our operating cash flows.
Issuance of Common Stock
In February 2016, we issued 79 million shares of our common stock to the public, inclusive of 10 million
shares sold as part of the underwriters’ option. Net proceeds from the offering were approximately $1.5 billion.
Divestitures of Property and Investments
During 2017, as part of our announced divestiture program, we sold non-core U.S. assets for $415 million. For
further discussion, see Note 3 in “Item 8. Financial Statements and Supplementary Data” of this report.
39
During 2016, we divested certain non-core upstream assets in the U.S. and our 50% interest in the Access
Pipeline in Canada for approximately $3.0 billion, net of purchase price adjustments. Proceeds from these
divestitures were used primarily for debt repayment and to support capital investment in Devon’s core resource
plays. For further discussion, see Note 3 in “Item 8. Financial Statements and Supplementary Data” of this report.
We did not have significant current cash income taxes resulting from the divestitures in 2017 and 2016.
Capital Expenditures
The following table summarizes our capital expenditures and property acquisitions.
Oil and gas
Corporate and other
Total capital expenditures
Acquisitions
Year Ended December 31,
2017
2016*
2015*
$
$
$
1,879 $
89
1,968 $
46 $
1,341 $
43
1,384 $
849 $
4,056
158
4,214
583
*
Prior year amounts have been recast due to change in accounting principle. See Note 2 in “Item 8. Financial
Statements and Supplementary Data” of this report.
Capital expenditures consist primarily of amounts related to our oil and gas exploration and development
operations and other corporate activities. The vast majority of our capital expenditures are for the acquisition,
drilling and development of oil and gas properties. Our capital program is designed to operate within operating cash
flow and may fluctuate with changes to commodity prices and other factors impacting cash flow. This is evidenced
by our operating cash flow fully funding capital expenditures in 2017. In response to the lower commodity prices,
our total capital expenditures have been reduced by approximately 50% since 2015.
Acquisition costs in 2016 primarily consisted of Devon’s bolt-on acquisition of assets in the STACK play for
$1.5 billion. Approximately $849 million was paid in cash at closing with the remainder of the purchase price
funded with equity consideration. In 2015 our acquisition activity primarily consisted of the Powder River Basin
asset acquisition in the fourth quarter. For further discussion on acquisition activity, see Note 3 in “Item 8. Financial
Statements and Supplementary Data” of this report.
Debt Activity, Net
During 2016, our debt decreased $3.1 billion. The decrease was primarily due to completed tender offers to
purchase and redeem $2.1 billion of debt securities prior to their maturity and a $1 billion reduction in short-term
borrowings. In conjunction with the tender offers, we recognized a $269 million loss on the early retirement of debt,
including $265 million of cash retirement costs and fees.
During 2015, our net debt increased $770 million. In June 2015, we issued $750 million of 5.0% senior notes.
We used these proceeds to repay the aggregate principal amount of our floating rate senior notes upon maturity on
December 15, 2015, as well as outstanding commercial paper balances. In December 2015, we issued $850 million
of 5.85% senior notes to fund acquisitions announced in the fourth quarter.
Shareholder Distributions
Devon paid common stock dividends of $127 million, $221 million and $396 million during 2017, 2016 and
2015, respectively. In response to the depressed commodity price environment, we reduced our quarterly dividend
from $0.24 to $0.06 per share in the second quarter of 2016.
40
EnLink and General Partner Distributions
Devon received $265 million, $265 million and $268 million in distributions from EnLink and the General
Partner during 2017, 2016 and 2015, respectively.
Subsidiary Unit Transactions
In 2015, we conducted an underwritten secondary public offering of 26.2 million common units representing
limited partner interests in EnLink, raising proceeds of $654 million, net of underwriting discount. See Note 20 in
“Item 8. Financial Statements and Supplementary Data” of this report.
EnLink Sources and Uses of Cash
EnLink’s operating cash flow has increased each year since 2015 as a result of the growth experienced from
its acquisition activity and continued development activities.
Capital expenditures for EnLink’s midstream operations are primarily for the construction and expansion of
oil and gas gathering facilities and pipelines. During 2016, EnLink acquired Anadarko Basin gathering and
processing midstream assets for $1.5 billion. Approximately $792 million was paid in cash at closing with the
remainder of the purchase price funded with equity consideration and debt. For additional information on this
acquisition, see Note 3 in “Item 8. Financial Statements and Supplementary Data” of this report. EnLink’s
acquisitions in 2015 consisted of additional oil and gas pipeline assets, including gathering, transportation and
processing facilities.
During 2017, EnLink divested its ownership interest in Howard Energy Partners for approximately $190
million. Proceeds were primarily used to pay a portion of the first $250 million installment payment related to
EnLink’s 2016 acquisition noted above.
During 2017, EnLink’s debt increased $247 million. In May 2017, EnLink issued $500 million of 5.45%
senior notes due in 2047 to repay outstanding borrowings under its revolving credit facility and for general
partnership purposes. In June 2017, EnLink redeemed its 7.125% senior unsecured notes due in 2022 for aggregate
cash consideration of $174 million. Additionally, EnLink reduced its credit facility borrowings to $74 million during
2017. As noted above, EnLink made the first installment payment in 2017 related to its 2016 acquisition.
EnLink and the General Partner distributed $354 million, $304 million and $254 million to non-Devon
unitholders during 2017, 2016 and 2015, respectively.
During 2017, 2016 and 2015, EnLink issued and sold approximately 6.2 million, 10.0 million and 1.3 million
common units through general public offerings and its “at the market” equity program, generating net proceeds of
approximately $107 million, $167 million and $25 million, respectively.
In 2017, EnLink issued preferred units in an underwritten public offering generating net proceeds of
approximately $394 million.
In 2016, to fund a portion of the cash consideration of its acquisition of Anadarko Basin gathering and
processing midstream assets, EnLink issued 50 million preferred units in a private placement generating cash
proceeds of approximately $725 million. General Partner common units were also issued as consideration in the
transaction.
In 2017 and 2016, EnLink received contributions from noncontrolling interests. For further discussion see
Note 3 in “Item 8. Financial Statements and Supplementary Data” of this report.
Devon Liquidity
Historically, our primary sources of capital and liquidity have been our operating cash flow, asset divestiture
proceeds and cash on hand. Additionally, we maintain a commercial paper program, supported by our revolving line
41
of credit, which can be accessed as needed to supplement operating cash flow and cash balances. Available sources
of capital and liquidity also include, among other things, debt and equity securities that can be issued pursuant to our
shelf registration statement filed with the SEC, as well as the sale of a portion of our common units representing
interests in our investment in EnLink and the General Partner. The most significant source of liquidity in 2017 has
come from our operating cash flow supplemented with approximately $415 million of proceeds related to our asset
divestitures. We estimate the combination of these sources of capital will continue to be adequate to fund our
planned capital expenditures, future debt repayments, dividends and other contractual commitments as discussed in
this section.
Operating Cash Flow
Our operating cash flow is sensitive to many variables, the most volatile of which are the prices of the oil,
bitumen, gas and NGLs we produce and sell. Our consolidated operating cash flow increased 165% in 2017 largely
due to increases in commodity prices. We expect operating cash flow to continue to be a key source of liquidity as
we adjust our capital program to invest within our operating cash flow. Furthermore, proceeds from our non-core
asset divestitures will provide additional liquidity as needed.
Commodity Prices – Prices are determined primarily by prevailing market conditions. Regional and
worldwide economic activity, weather and other substantially variable factors influence market conditions for these
products. These factors, which are difficult to predict, create volatility in prices and are beyond our control. To
mitigate some of the risk inherent in prices, we utilize various derivative financial instruments to protect a portion of
our production against downside price risk. We target hedging approximately 50% of our production in a manner
that systematically places hedges for several quarters in advance, allowing us to maintain a disciplined risk
management program as it relates to commodity price volatility. We supplement the systematic hedging program
with discretionary hedges that take advantage of favorable market conditions. As a result, entering into 2018 we
have hedged approximately 40% of our anticipated oil and 50% of our anticipated gas production. The key terms to
our oil, gas and NGL derivative financial instruments as of December 31, 2017 are presented in Note 4 in “Item 8.
Financial Statements and Supplementary Data” of this report.
Commodity prices can also affect our operating cash flow through an indirect effect on operating expenses.
Significant commodity price decreases can lead to a decrease in drilling and development activities. As a result, the
demand and cost for people, services, equipment and materials may also decrease, causing a positive impact on our
cash flow as the prices paid for services and equipment decline. However, the inverse is also generally true during
periods of rising commodity prices.
Divestitures of Property and Equipment – In 2017, we announced a program to divest approximately $1
billion of upstream assets. These non-core assets identified for monetization include select portions of the Barnett
Shale focused primarily in and around Johnson County and other properties located principally within Devon’s U.S.
resource base. Through December 31, 2017, Devon completed divestiture transactions totaling approximately $415
million. The most significant asset remaining in this program is select Barnett Shale properties which we expect to
close in 2018.
Interest Rates – Our operating cash flow can also be impacted by interest rate fluctuations. As of December
31, 2017, we had total debt of $6.9 billion that bears fixed interest rates averaging 5.7%.
As of December 31, 2017, we had open interest rate swap positions that are presented in Note 4 in “Item 8.
Financial Statements and Supplementary Data” in this report.
Credit Losses – Our operating cash flow is also exposed to credit risk in a variety of ways. This includes the
credit risk related to customers who purchase our oil, gas and NGL production, the collection of receivables from
our joint-interest partners for their proportionate share of expenditures made on projects we operate and
counterparties to our derivative financial contracts. We utilize a variety of mechanisms to limit our exposure to the
credit risks of our customers, partners and counterparties. Such mechanisms include, under certain conditions,
requiring letters of credit, prepayments or collateral postings.
42
At the end of 2017, we held approximately $2.6 billion of cash. Included in this total was $732 million of cash
held by our foreign subsidiaries.
Credit Availability
We have a $3.0 billion Senior Credit Facility. The maturity date for $164 million of the Senior Credit Facility
is October 24, 2018. The maturity date for the remaining $2.8 billion is October 24, 2019. This credit facility
supports our $3.0 billion of short-term credit under our commercial paper program. As of December 31, 2017, there
were no borrowings under our commercial paper program. See Note 16 in “Item 8. Financial Statements and
Supplementary Data” of this report for further discussion.
The Senior Credit Facility contains only one material financial covenant. This covenant requires us to
maintain a ratio of total funded debt to total capitalization, as defined in the credit agreement, of no more than 65%.
The credit agreement defines total funded debt as funds received through the issuance of debt securities such as
debentures, bonds, notes payable, credit facility borrowings and short-term commercial paper borrowings. In
addition, total funded debt includes all obligations with respect to payments received in consideration for oil, gas
and NGL production yet to be acquired or produced at the time of payment. Funded debt excludes our outstanding
letters of credit and trade payables. The credit agreement defines total capitalization as the sum of funded debt and
stockholders’ equity adjusted for noncash financial write-downs, such as oil and gas property impairments and
goodwill impairments. As of December 31, 2017, we were in compliance with this covenant. Our debt-to-
capitalization ratio at December 31, 2017, as calculated pursuant to the terms of the agreement, was 27.2%.
Our access to funds from the Senior Credit Facility is not restricted under any “material adverse effect”
clauses. It is not uncommon for credit agreements to include such clauses. These clauses can remove the obligation
of the banks to fund the credit line if any condition or event would reasonably be expected to have a material and
adverse effect on the borrower’s financial condition, operations, properties or business considered as a whole, the
borrower’s ability to make timely debt payments or the enforceability of material terms of the credit agreement.
While our credit facility includes covenants that require us to report a condition or event having a material adverse
effect, the obligation of the banks to fund the credit facility is not conditioned on the absence of a material adverse
effect.
As market conditions warrant and subject to our contractual restrictions, liquidity position and other factors,
we may from time to time seek to repurchase or retire our outstanding debt through cash purchases and/or exchanges
for other debt or equity securities in open market transactions, privately negotiated transactions, by tender offer or
otherwise. Any such cash repurchases by us may be funded by cash on hand or incurring new debt. The amounts
involved in any such transactions, individually or in the aggregate, may be material. Furthermore, any such
repurchases or exchanges may result in our acquiring and retiring a substantial amount of such indebtedness, which
would impact the trading liquidity of such indebtedness. We are currently targeting up to $1.5 billion of debt
reduction in 2018.
Debt Ratings
We receive debt ratings from the major ratings agencies in the U.S. In determining our debt ratings, the
agencies consider a number of qualitative and quantitative items including, but not limited to, commodity pricing
levels, our liquidity, asset quality, reserve mix, debt levels, cost structure, planned asset sales and near-term and
long-term production growth opportunities. Our credit rating from Standard and Poor’s Financial Services is BBB
with a stable outlook. In March 2017, Fitch Ratings affirmed our BBB+ rating and revised our outlook to stable
from negative. In April 2017, Moody’s Investor Service upgraded our credit rating from Ba2 to Ba1 with a stable
outlook. Any rating downgrades may result in additional letters of credit or cash collateral being posted under
certain contractual arrangements.
There are no “rating triggers” in any of our or EnLink’s contractual debt obligations that would accelerate
scheduled maturities should our debt rating fall below a specified level. However, a downgrade could adversely
impact our and EnLink’s interest rate on any credit facility borrowings and the ability to economically access debt
markets in the future.
43
Capital Expenditures
Our 2018 exploration and development budget is expected to be approximately $2.2 billion to $2.4 billion and
funded within operating cash flow. Although negative movements in any of the variables discussed above would
impact our operating cash flow, we likely would not change our 2018 planned capital investment. Should our
operating cash flow decrease from our forecasts, we could divest non-core assets to balance capital sources and uses.
EnLink Liquidity
EnLink has a $1.5 billion unsecured revolving credit facility. The General Partner has a $250 million
revolving credit facility. As of December 31, 2017, there were $10 million in outstanding letters of credit and no
outstanding borrowings under the $1.5 billion credit facility and $74 million outstanding borrowings under the $250
million credit facility. All of EnLink’s and the General Partner’s debt is non-recourse to Devon.
As of December 31, 2017, EnLink had total debt of $3.5 billion. Of this amount, $3.4 billion bears fixed
interest rates averaging 4.6% and $74 million is comprised of floating rate debt with interest rates averaging 3.2%.
EnLink’s 2018 capital budget includes approximately $600 million to $800 million of identified growth
projects. EnLink’s primary capital projects for 2018 include the construction of the Thunderbird processing plant in
Central Oklahoma, the Lobo III processing plant in the Delaware Basin and the development of additional gathering
and compression assets in Central Oklahoma and the Permian Basin.
EnLink expects to fund the growth capital expenditures with borrowings under its bank credit facility and
proceeds from other debt and equity sources, including capital contributions by joint venture partners. EnLink
expects to fund its 2018 maintenance capital expenditures from operating cash flows. EnLink employs a strategy
that includes maintaining stable operating cash flows that are supported by long-term, fixed-fee contracts.
Approximately 94% of EnLink’s cash flows were generated from fee-based services in 2017. It is possible that not
all of the planned projects for 2018 will be commenced or completed. EnLink’s ability to pay distributions to its
unitholders, fund planned capital expenditures and make acquisitions will depend upon its future operating
performance, which will be affected by prevailing economic conditions in the industry and financial, business and
other factors, some of which are beyond its control.
44
Contractual Obligations
The following table presents a summary of our contractual obligations as of December 31, 2017.
Devon obligations:
Debt (1)
Interest expense (2)
Purchase obligations (3)
Operational agreements (4)
Operational agreements with EnLink (5)
Asset retirement obligations (6)
Drilling and facility obligations (7)
Lease obligations (8)
Other (9)
Total Devon obligations
EnLink obligations:
Debt (1)
Interest expense (2)
Other (9)
Total EnLink obligations
Total obligations
Payments Due by Period
Total
Less Than 1
Year
1-3 Years
3-5 Years
More Than
5 Years
$
$
6,933 $
6,188
1,880
5,259
909
1,152
629
381
115
23,446
3,574
2,573
496
6,643
30,089 $
115 $
390
613
522
637
39
216
88
115
2,735
—
160
306
466
3,201 $
162 $
756
1,133
756
272
134
218
157
—
3,588
474
304
55
833
4,421 $
1,500 $
715
134
739
—
171
89
117
—
3,465
—
298
45
343
3,808 $
5,156
4,327
—
3,242
—
808
106
19
—
13,658
3,100
1,811
90
5,001
18,659
(1) Debt amounts represent scheduled maturities of debt obligations at December 31, 2017, excluding net
(2)
(3)
discounts and debt issue costs included in the carrying value of debt.
Interest expense represents the scheduled cash payments on long-term fixed-rate debt (including current
portion of long term debt).
Purchase obligation amounts represent contractual commitments primarily to purchase condensate at market
prices for use at our heavy oil projects in Canada. We have entered into these agreements because condensate
is an integral part of the heavy oil transportation process. Any disruption in our ability to obtain condensate
could negatively affect our ability to transport heavy oil at these locations. Our total obligation related to
condensate purchases expires in 2021. The value of the obligation in the table above is based on the
contractual volumes and our internal estimate of future condensate market prices.
(4) Operational agreements represent commitments to transport or process certain volumes of oil, gas and NGLs
for a fixed fee. We have entered into these agreements to aid the movement of our production to downstream
markets.
(5) Operational agreements between Devon and EnLink represent fixed-fee gathering and processing and
transportation agreements. These agreements also include minimum volume commitments that will remain in
effect for approximately one more year, as well as annual rate escalators.
(6) Asset retirement obligations represent estimated discounted costs for future dismantlement, abandonment and
rehabilitation costs. These obligations are recorded as liabilities on our December 31, 2017 balance sheet.
(7) Drilling and facility obligations represent gross contractual agreements with third-party service providers to
procure drilling rigs and other related services for developmental and exploratory drilling and facilities
construction.
Lease obligations consist primarily of non-cancelable leases for office space and equipment.
(8)
(9) Other Devon obligations primarily relate to uncertain tax positions as discussed in Note 8 in “Item 8. Financial
Statements and Supplementary Data” of this report. Other EnLink obligations primarily consist of a $250
million installment payment on the Anadarko Basin assets acquisition as discussed in Note 3 in “Item 8.
Financial Statements and Supplementary Data” of this report.
45
Contingencies and Legal Matters
For a detailed discussion of contingencies and legal matters, see Note 21 in “Item 8. Financial Statements and
Supplementary Data” of this report.
Critical Accounting Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the
U.S. requires us to make estimates, judgments and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported
amounts of revenues and expenses during the reporting period. Actual amounts could differ from these estimates,
and changes in these estimates are recorded when known. We consider the following to be our most critical
accounting estimates that involve judgment and have reviewed these critical accounting estimates with the Audit
Committee of our Board of Directors.
Oil and Gas Assets Accounting, Reserves, Classification & Valuation
Change in Accounting Principle
In the fourth quarter of 2017, we changed our method of accounting for our oil and gas exploration and
development activities from the full cost method to the successful efforts method. In accordance with FASB ASC
250 “Accounting Changes and Error Corrections,” financial information for prior periods has been recast to reflect
retrospective application of the successful efforts method, as prescribed by the FASB ASC 932 “Extractive
Activities—Oil and Gas.” As required by ASC 250, we have presented the accumulated effect of the change in
accounting principle from Devon’s inception to December 31, 2014 as a change in the beginning balance of our
2015 consolidated statements of equity.
To recast our financial statements, we made certain critical estimates, judgments and assumptions to apply
successful efforts accounting to our historical operations. These critical items are similar to those pertaining to our
ongoing successful efforts accounting, which are described below. For additional information regarding the effects
of the change to the successful efforts method, including our underlying successful efforts accounting policies, see
Note 2 in “Item 8. Financial Statements and Supplementary Data” of this report.
To illustrate the effect of the change to successful efforts accounting, the following table summarizes the $1.9
billion increase to our historical equity as of September 30, 2017, the date of our conversion. The increase was
primarily driven by lower impairments, offset by higher DD&A and less capitalized expenses.
Category
Total equity as of September 30, 2017 (Full Cost)
Adjustments from inception through 2007, net
Adjustments after 2007:
Lower asset impairments, net
Exploration expense
Higher DD&A, driven largely by lower impairments
G&A expensed rather than capitalized
Other (asset dispositions, foreign exchange cumulative translation adjustment, etc.)
Deferred income tax on the above items
Total adjustments after 2007
Equity increase (+16%)
Total equity as of September 30, 2017 (Successful Efforts)
$
11,934
(2,147)
18,317
(5,402)
(5,036)
(3,075)
418
(1,152)
4,070
1,923
13,857
$
46
Reserves
Our estimates of proved and proved developed reserves are a major component of DD&A calculations.
Additionally, our proved reserves represent the element of these calculations that require the most subjective
judgments. Estimates of reserves are forecasts based on engineering data, projected future rates of production and
the timing of future expenditures. The process of estimating oil, gas and NGL reserves requires substantial
judgment, resulting in imprecise determinations, particularly for new discoveries. Different reserve engineers may
make different estimates of reserve quantities based on the same data. Our engineers prepare our reserve estimates.
We then subject certain of our reserve estimates to audits performed by third-party petroleum consulting firms. In
2017, 88% of our reserves were subjected to such audits.
The passage of time provides more qualitative information regarding estimates of reserves, when revisions are
made to prior estimates to reflect updated information. In the past five years, annual performance revisions to our
reserve estimates, which have been both increases and decreases in individual years, have averaged less than 5% of
the previous year’s estimate. However, there can be no assurance that more significant revisions will not be
necessary in the future. The data for a given reservoir may also change substantially over time as a result of
numerous factors including, but not limited to, additional development activity, evolving production history and
continual reassessment of the viability of production under varying economic conditions.
Successful Efforts Method of Accounting and Classification
We utilize the successful efforts method of accounting for our oil and natural gas exploration and development
activities which requires management’s assessment of the proper designation of wells and associated costs as
developmental or exploratory. This classification assessment is dependent on the determination and existence of
proved reserves, which is a critical estimate discussed in the previous section. The classification of developmental
and exploratory costs has a direct impact on the amount of costs we initially recognize as exploration expense or
capitalize, then subject to DD&A calculations and impairment assessments and valuations.
Once a well is drilled, the determination that proved reserves have been discovered may take considerable
time and requires both judgment and application of industry experience. Development wells are always capitalized.
Costs associated with drilling an exploratory well are initially capitalized, or suspended, pending a determination as
to whether proved reserves have been found. At the end of each quarter, management reviews the status of all
suspended exploratory drilling costs to determine whether the costs should continue to remain capitalized or shall be
expensed. When making this determination, management considers current activities, near-term plans for additional
exploratory or appraisal drilling and the likelihood of reaching a development program. If management determines
future development activities and the determination of proved reserves are unlikely to occur, the associated
suspended exploratory well costs are recorded as dry hole expense and reported in exploration expense in the
Consolidated Comprehensive Statement of Earnings. Otherwise, the costs of exploratory wells remain capitalized.
At December 31, 2017, Devon had approximately $200 million of well costs suspended for more than one year,
which largely pertain to its Pike Heavy Oil project. Stratigraphic testing has demonstrated reserves can be produced
economically at Pike. However, this capital intensive, long-duration project remains unsanctioned by Devon and its
50% partner, which is the primary reason reserves have not been designated as proven at Pike. With no lease
expiration at Pike in the near future, management continues to keep the Pike exploratory costs capitalized.
Similar to the evaluation of suspended exploratory well costs, costs for undeveloped leasehold, for which
reserves have not been proven, must also be evaluated for continued capitalization or impairment. At the end of each
quarter, management assesses undeveloped leasehold costs for impairment by considering future drilling plans,
drilling activity results, commodity price outlooks, planned future sales or expiration of all or a portion of such
projects. Based on this assessment, Devon impaired $139 million of undeveloped leasehold in the fourth quarter of
2017. At December 31, 2017, Devon had $1.4 billion of undeveloped leasehold and capitalized interest which
includes approximately $750 million related to Pike. Consistent with the evaluation above on suspended well costs,
the costs for Pike continue to remain capitalized. Of the remaining undeveloped leasehold costs at December 31,
2017, $85 million is scheduled to expire in 2018. The leasehold expiring in 2018 relates to areas in which Devon is
actively drilling. If our drilling is not successful, this leasehold could become partially or entirely impaired.
47
Valuation of Long-Lived Assets
Long-lived assets used in operations, including proved and unproved oil and gas properties, are depreciated
and assessed for impairment annually or whenever changes in facts and circumstances indicate a possible significant
deterioration in future cash flows expected to be generated by an asset group. For DD&A calculations and
impairment assessments, management groups individual assets based on a judgmental assessment of the lowest level
(“common operating field”) for which there are identifiable cash flows that are largely independent of the cash flows
of other groups of assets. The determination of common operating fields is largely based on geological structural
features or stratigraphic condition, which requires judgment. Management also considers the nature of production,
common infrastructure, common sales points, common processing plants, common regulation and management
oversight to make common operating field determinations. These determinations impact the amount of DD&A
recognized each period and could impact the determination and measurement of a potential asset impairment.
Management evaluates assets for impairment through an established process in which changes to significant
assumptions such as prices, volumes, and future development plans are reviewed. If, upon review, the sum of the
undiscounted pre-tax cash flows is less than the carrying value of the asset group, the carrying value is written down
to estimated fair value. Because there usually is a lack of quoted market prices for long-lived assets, the fair value of
impaired assets is typically determined based on the present values of expected future cash flows using discount
rates believed to be consistent with those used by principal market participants. The expected future cash flows used
for impairment reviews and related fair value calculations are typically based on judgmental assessments of future
production volumes, commodity prices, operating costs, and capital investment plans, considering all available
information at the date of review. Besides the estimates of reserves and future production volumes, future
commodity prices are the largest driver in the variability of undiscounted pre-tax cash flows. For our impairment
determinations, we generally utilize the forward strip prices for the first five years and apply internally generated
price forecasts for subsequent years. We estimate and escalate or de-escalate future capital and operating costs by
using a method that correlates cost movements to price movements similar to recent history. Changes to any of these
assumptions could result in lower undiscounted pre-tax cash flows and impact both the recognition and timing of
impairments. Due to suppressed commodity prices in 2015 and 2016, we recognized significant asset impairments in
each of those years. With more stabilized and higher pricing in 2017, we did not recognize material asset
impairments.
Goodwill and Other Intangibles
Goodwill
We test goodwill for impairment annually at October 31, or more frequently if events or changes in
circumstances dictate that the carrying value of goodwill may not be recoverable. While we use data as of
October 31 for our test, we typically complete the test in late December or early January as the October 31 market
data used in our test becomes available.
We assess the qualitative and quantitative factors to determine whether the fair value of a reporting unit is less
than its carrying amount. Because quoted market prices are not available for our reporting units, the fair values of
the reporting units are estimated based upon several valuation analyses, including comparable companies,
comparable transactions and premiums paid. If the carrying value of a reporting unit exceeds its fair value, an
impairment loss is recognized in an amount equal to that excess. The determination of fair value requires judgment
and involves the use of significant estimates and assumptions about expected future cash flows derived from internal
forecasts and the impact of market conditions on those assumptions. Critical assumptions primarily include revenue
growth rates driven by future commodity prices and volume expectations, operating margins and capital
expenditures.
For the October 31, 2017 impairment tests for Devon’s U.S. reporting unit and each of EnLink’s reporting
units, the fair value of each reporting unit exceeded its carrying value.
Sustained weakness in the overall energy sector driven by low commodity prices, together with a decline in
the EnLink unit price, caused a change in circumstances warranting an interim impairment test for EnLink’s
reporting units in 2015 and an update to be performed at December 31, 2015. Using the fair value approaches
48
described above, it was determined that the estimated fair value of EnLink’s Texas, Louisiana and Crude and
Condensate reporting units were less than their carrying amounts and a goodwill impairment loss of $492 million,
$787 million and $49 million, respectively, was recognized in 2015.
Additionally, another interim impairment test was warranted during 2016 for EnLink’s reporting units. Using
the fair value approaches described above, it was determined that the estimated fair value of EnLink’s Texas,
General Partner and Crude and Condensate reporting units were less than their carrying amounts and a goodwill
impairment loss of $473 million, $307 million and $93 million, respectively, was recognized in 2016.
Our impairment determinations involved significant assumptions and judgments, as discussed above.
Differing assumptions regarding any of these inputs could have a significant effect on the various valuations. If
actual future results are not consistent with these assumptions and estimates, or the assumptions and estimates
change due to new information, we may be exposed to additional goodwill impairment charges, which would be
recognized in the period in which we would determine that the carrying value exceeds fair value. We would expect
that a prolonged or sustained period of lower commodity prices would adversely affect the estimate of future
operating results, which could result in future goodwill impairments for our reporting units due to the potential
impact on the cash flows of our operations.
The impairment of goodwill has no effect on liquidity or capital resources. However, it adversely affects our
results of operations in the period recognized.
Other Intangible Assets
In 2015, the assessment of customer relationships was updated due to the factors described in the
aforementioned goodwill section. This assessment resulted in a $223 million impairment of other intangible assets
related to EnLink’s Crude and Condensate reporting unit. Level 3 fair value measurements were utilized for the
impairment analysis of definite-lived intangible assets, which included discounted cash flow estimates, consistent
with those utilized in the goodwill impairment assessment.
The other intangible assets impairment has no effect on liquidity or capital resources. However, it adversely
affects our results of operations in the period recognized.
Income Taxes
The amount of income taxes recorded requires interpretations of complex rules and regulations of federal,
state, provincial and foreign tax jurisdictions. We recognize current tax expense based on estimated taxable income
for the current period and the applicable statutory tax rates. We routinely assess potential uncertain tax positions
and, if required, estimate and establish accruals for such amounts. We have recognized deferred tax assets and
liabilities for temporary differences, operating losses and other tax carryforwards. We routinely assess our deferred
tax assets and reduce such assets by a valuation allowance if we deem it is more likely than not that some portion or
all of the deferred tax assets will not be realized. At the end of 2017 and 2016, we had deferred tax assets that
largely resulted from the asset impairments recognized throughout 2016. As a result of our recent cumulative losses
and our current realization assessment, we recorded a 100% valuation allowance against our U.S. deferred tax assets
as of December 31, 2017 and December 31, 2016. Further, in 2017, we recognized a $660 million partial valuation
allowance against certain Canadian deferred tax assets as a result of the Canadian legal entity restructuring.
The accruals for deferred tax assets and liabilities are often based on assumptions that are subject to a
significant amount of judgment by management. These assumptions and judgments are reviewed and adjusted as
facts and circumstances change. Material changes to our income tax accruals may occur in the future based on the
progress of ongoing audits, changes in legislation or resolution of pending matters.
We also assess factors relative to whether our foreign earnings are considered indefinitely reinvested. These
factors include forecasted and actual results for both our U.S. and Canadian operations, borrowing conditions in the
U.S. and existing U.S. income tax laws, particularly the laws pertaining to the deductibility of intangible drilling
costs and repatriations of foreign earnings. Changes in any of these factors could require recognition of additional
49
deferred, or even current, U.S. income tax expense. We accrue deferred U.S. income tax expense on our foreign
earnings when the factors indicate that these earnings are no longer considered indefinitely reinvested.
For our foreign earnings deemed indefinitely reinvested, we do not calculate a hypothetical deferred tax
liability on these earnings. Calculating a hypothetical tax on these accumulated earnings is much different from the
calculation of the deferred tax liability on our earnings deemed not indefinitely reinvested. A hypothetical tax
calculation on the indefinitely reinvested earnings would require the following additional activities:
•
•
•
•
separate analysis of a diverse chain of foreign entities;
relying on tax rates on a future remittance that could vary significantly depending on alternative
approaches available to repatriate the earnings;
determining the nature of a yet-to-be-determined future remittance, such as whether the distribution
would be a non-taxable return of capital or a distribution of taxable earnings and calculation of associated
withholding taxes, which would vary significantly depending on the circumstances at the deemed time of
remittance; and
further analysis of a variety of other inputs such as the earnings, profits, U.S./foreign country tax treaty
provisions and the related foreign taxes paid by our foreign subsidiaries, whose earnings are deemed
permanently reinvested, over a lengthy history of operations.
Because of the administrative burden required to perform these additional activities, it is impractical to
calculate a hypothetical tax on the foreign earnings associated with this separate and more complicated chain of
companies.
Under the Tax Reform Legislation, the corporate income tax rate was reduced to 21% effective January 1,
2018. We are required to recognize the effect of the tax law changes in the period of enactment, such as determining
the transition tax, remeasuring our U.S. deferred tax assets and liabilities and reassessing the net realizability of our
deferred tax assets and liabilities.
In December 2017, the SEC staff issued Staff Accounting Bulletin No. 118, Income Tax Accounting
Implications of the Tax Cuts and Jobs Act (SAB 118), which allows us to record provisional amounts during a
measurement period not to extend beyond one year after the enactment date. As the Tax Reform Legislation was
passed late in the fourth quarter of 2017 and ongoing guidance and accounting interpretation are expected over the
next 12 months, we consider the accounting of the transition tax, deferred tax remeasurements, and other items to be
incomplete due to the forthcoming guidance and our ongoing analysis of final year-end data and tax positions. We
expect to complete our analysis within the measurement period in accordance with SAB 118.
Absent unexpected events and unexpected effects of the Tax Reform Legislation, Devon expects a positive
impact on its future after-tax earnings, primarily due to the lower federal statutory tax rate.
Non-GAAP Measures
We make reference to “core earnings (loss) attributable to Devon” and “core earnings (loss) per share
attributable to Devon” in “Overview of 2017 Results” in this Item 7. that are not required by or presented in
accordance with GAAP. These non-GAAP measures should not be considered as alternatives to GAAP measures.
Core earnings attributable to Devon, as well as the per share amount, represent net earnings excluding certain
noncash or non-recurring items that are typically excluded by securities analysts in their published estimates of our
financial results. Our non-GAAP measures are typically used as a quarterly performance measure. Items may appear
to be recurring when comparing on an annual basis. In the table below, restructuring and transaction costs were
incurred in two of the three year periods; however, these costs relate to different restructuring programs. Amounts
excluded for 2017 relate to asset dispositions, noncash asset impairments including noncash unproved asset
impairments (included in exploration expenses), U.S. tax reform changes, deferred tax asset valuation allowance,
derivatives and financial instrument fair value changes, legal entity restructuring and costs associated with early
retirement of debt.
Amounts excluded for 2016 relate to asset dispositions, noncash asset impairments (including an impairment
of goodwill) including noncash unproved asset impairments and dry hole costs relating to exploration expenses, rig
50
stacking costs, deferred tax asset valuation allowance, restructuring and transaction costs associated with the 2016
workforce reduction, derivatives and financial instrument fair value changes and costs associated with early
retirement of debt.
Amounts excluded for 2015 relate to asset dispositions, noncash asset impairments (including an impairment
of goodwill) including noncash unproved asset impairments and dry hole costs relating to exploration expenses, rig
stacking costs, deferred tax asset valuation allowance, restructuring and transaction costs, derivatives and financial
instrument fair value changes and repatriation of funds to the U.S.
We believe these non-GAAP measures facilitate comparisons of our performance to earnings estimates
published by securities analysts, which typically make similar adjustments in their estimates of our financial results.
We also believe these non-GAAP measures can facilitate comparisons of our performance between periods and to
the performance of our peers.
51
Below are reconciliations of our core earnings and earnings per share to their comparable GAAP measures.
2017
Earnings attributable to Devon (GAAP)
Adjustments:
Asset dispositions
Asset and exploration impairments
U.S. tax reform
Deferred tax asset valuation allowance
Fair value changes in financial
instruments and foreign currency
Legal entity restructuring
Early retirement of debt
Core earnings attributable to Devon (Non-GAAP)
2016*
Loss attributable to Devon (GAAP)
Adjustments:
Asset dispositions
Asset and exploration impairments
Rig stacking costs
Deferred tax asset valuation allowance
Restructuring and transaction costs
Fair value changes in financial
instruments and foreign currency
Early retirement of debt
2015*
Loss attributable to Devon (GAAP)
Adjustments:
Asset dispositions
Asset and exploration impairments
Rig stacking costs
Deferred tax asset valuation allowance
Restructuring and transaction costs
Fair value changes in financial
instruments and foreign currency
Repatriations
Core loss attributable to Devon (Non-GAAP)
$
Before tax
After tax
After
Noncontrolling
Interests
Per Diluted
Share
$
896
$
1,078
$
898
$
1.70
$
$
(217)
234
—
—
(218)
—
(9)
686
$
(138)
152
(211)
(76)
(202)
(86)
(7)
510
$
(138)
146
(112)
(76)
(201)
(86)
(4)
427
$
(0.26)
0.27
(0.21)
(0.14)
(0.38)
(0.16)
(0.01)
0.81
(1,317)
$
(1,458)
$
(1,056)
$
(2.09)
(1,483)
1,430
10
—
267
(989)
1,230
6
385
173
270
269
(554)
$
153
171
(329)
$
(995)
807
6
385
170
145
171
(367)
$
(1.95)
1.60
0.01
0.76
0.33
0.28
0.33
(0.73)
$ (19,858)
$ (13,645)
$
(12,896)
$
(31.72)
7
17,914
54
—
78
8
11,955
34
403
52
8
11,131
34
403
52
1,967
—
162
$
1,349
33
189
$
1,346
33
111
$
0.02
27.37
0.08
0.99
0.13
3.31
0.08
0.26
Core earnings attributable to Devon (Non-GAAP)
$
*
Prior year amounts have been recast due to change in accounting principle. See Note 2 in “Item 8. Financial
Statements and Supplementary Data” of this report.
52
Item 7A. Quantitative and Qualitative Disclosures about Market Risk
The primary objective of the following information is to provide forward-looking quantitative and qualitative
information about our potential exposure to market risks. The term “market risk” refers to our risk of loss arising
from adverse changes in oil, gas and NGL prices, interest rates and foreign currency exchange rates. The following
disclosures are not meant to be precise indicators of expected future losses but rather indicators of reasonably
possible losses. This forward-looking information provides indicators of how we view and manage our ongoing
market risk exposures. All of our market risk sensitive instruments were entered into for purposes other than
speculative trading.
Commodity Price Risk
Our major market risk exposure is the pricing applicable to our oil, gas and NGL production. Realized pricing
is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our U.S. and
Canadian gas and NGL production. Pricing for oil and gas production has been volatile and unpredictable as
discussed in “Item 1A. Risk Factors” of this report. Consequently, we systematically hedge a portion of our
production through various financial transactions. The key terms to our oil and gas derivative financial instruments
as of December 31, 2017 are presented in Note 4 in “Item 8. Financial Statements and Supplementary Data” of this
report.
The fair values of our commodity derivatives are largely determined by estimates of the forward curves of the
relevant price indices. At December 31, 2017, a 10% change in the forward curves associated with our commodity
derivative instruments would have changed our net asset positions by approximately $260 million.
Interest Rate Risk
At December 31, 2017, we had total debt of $10.4 billion. Of this amount, $10.3 billion bears fixed interest
rates averaging 5.3%, and approximately $74 million is comprised of floating rate debt with interest rates averaging
3.2%.
As of December 31, 2017, we had open interest rate swap positions that are presented in Note 4 in “Item 8.
Financial Statements and Supplementary Data” of this report. The fair values of our interest rate swaps are largely
determined by estimates of the forward curves of the three month LIBOR rate. A 10% change in these forward
curves would not have materially impacted our balance sheet or liquidity at December 31, 2017.
Foreign Currency Risk
Our net assets, net earnings and cash flows from our Canadian subsidiaries are based on the U.S. dollar
equivalent of such amounts measured in the Canadian dollar functional currency. Assets and liabilities of the
Canadian subsidiaries are translated to U.S. dollars using the applicable exchange rate as of the end of a reporting
period. Revenues, expenses and cash flow are translated using an average exchange rate during the reporting period.
A 10% unfavorable change in the Canadian-to-U.S. dollar exchange rate would not have materially impacted our
December 31, 2017 balance sheet.
Our non-Canadian foreign subsidiaries have a U.S. dollar functional currency. However, some of these
subsidiaries hold Canadian-dollar cash and engage in intercompany loans with Canadian subsidiaries that are based
in Canadian dollars. The value of the Canadian-dollar cash and intercompany loans increases or decreases from the
remeasurement of the cash and loans into the U.S. dollar functional currency. Based on the amount of the cash and
intercompany loans as of December 31, 2017, a 10% change in the foreign currency exchange rates would not have
materially impacted our balance sheet.
53
Item 8. Financial Statements and Supplementary Data
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
AND CONSOLIDATED FINANCIAL STATEMENT SCHEDULES
Report of Independent Registered Public Accounting Firm
Consolidated Financial Statements
Consolidated Comprehensive Statements of Earnings
Consolidated Statements of Cash Flows
Consolidated Balance Sheets
Consolidated Statements of Equity
Notes to Consolidated Financial Statements
Note 1 – Summary of Significant Accounting Policies
Note 2 – Change in Accounting Principle
Note 3 – Acquisitions and Divestitures
Note 4 – Derivative Financial Instruments
Note 5 – Share-Based Compensation
Note 6 – Asset Impairments
Note 7 – Other Expenses
Note 8 – Income Taxes
Note 9 – Net Earnings (Loss) Per Share Attributable to Devon
Note 10 – Other Comprehensive Earnings
Note 11 – Supplemental Information to Statements of Cash Flows
Note 12 – Accounts Receivable
Note 13 – Property, Plant and Equipment
Note 14 – Goodwill and Other Intangible Assets
Note 15 – Other Current Liabilities
Note 16 – Debt and Related Expenses
Note 17 – Asset Retirement Obligations
Note 18 – Retirement Plans
Note 19 – Stockholders’ Equity
Note 20 – Noncontrolling Interests
Note 21 – Commitments and Contingencies
Note 22 – Fair Value Measurements
Note 23 – Segment Information
Note 24 – Supplemental Information on Oil and Gas Operations (Unaudited)
Note 25 – Supplemental Quarterly Financial Information (Unaudited)
55
57
58
59
60
61
61
71
74
76
78
82
82
84
88
88
89
89
90
92
93
94
97
97
101
101
102
104
105
107
115
All financial statement schedules are omitted as they are inapplicable or the required information has been
included in the consolidated financial statements or notes thereto.
54
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders
Devon Energy Corporation:
Opinions on the Consolidated Financial Statements and Internal Control Over Financial Reporting
We have audited the accompanying consolidated balance sheets of Devon Energy Corporation and subsidiaries (the
“Company”) as of December 31, 2017 and 2016, the related consolidated statements of comprehensive earnings,
stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2017, and the
related notes (collectively, the “consolidated financial statements”). We also have audited the Company’s internal
control over financial reporting as of December 31, 2017, based on criteria established in Internal Control –
Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the
financial position of as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each
of the years in the three-year period ended December 31, 2017, in conformity with U.S. generally accepted
accounting principles. Also in our opinion, the Company maintained, in all material respects, effective internal
control over financial reporting as of December 31, 2017, based on criteria established in Internal Control –
Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
Change in Accounting Principle
As discussed in Note 1 to the consolidated financial statements, the Company has elected to change its method of
accounting for oil and gas exploration and development activities from the full cost method of accounting to the
successful efforts method of accounting in 2017.
Basis for Opinion
The Company’s management is responsible for these consolidated financial statements, for maintaining effective
internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial
reporting, included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting
contained in “Item 9A. Controls and Procedures.” Our responsibility is to express an opinion on the Company’s
consolidated financial statements and an opinion on the Company’s internal control over financial reporting based
on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board
(United States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the
U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and
the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and
perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of
material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting
was maintained in all material respects.
Our audits of the consolidated financial statements included performing procedures to assess the risks of material
misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that
respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and
disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles
used and significant estimates made by management, as well as evaluating the overall presentation of the
consolidated financial statements. Our audit of internal control over financial reporting included obtaining an
understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and
testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our
audits also included performing such other procedures as we considered necessary in the circumstances. We believe
that our audits provide a reasonable basis for our opinions.
55
Definition and Limitations of Internal Control Over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance
regarding the reliability of financial reporting and the preparation of financial statements for external purposes in
accordance with generally accepted accounting principles. A company’s internal control over financial reporting
includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail,
accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable
assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance
with generally accepted accounting principles, and that receipts and expenditures of the company are being made
only in accordance with authorizations of management and directors of the company; and (3) provide reasonable
assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s
assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.
Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may
deteriorate.
/s/ KPMG LLP
We have served as the Company’s auditor since 1980.
Oklahoma City, Oklahoma
February 21, 2018
56
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED COMPREHENSIVE STATEMENTS OF EARNINGS
Upstream revenues
Marketing and midstream revenues
Total revenues
Production expenses
Exploration expenses
Marketing and midstream expenses
Depreciation, depletion and amortization
Asset impairments
Asset dispositions
General and administrative expenses
Financing costs, net
Other expenses
Total expenses
Earnings (loss) before income taxes
Income tax expense (benefit)
Net earnings (loss)
Net earnings (loss) attributable to noncontrolling interests
Net earnings (loss) attributable to Devon
Net earnings (loss) per share attributable to Devon:
Basic
Diluted
Comprehensive earnings (loss):
Net earnings (loss)
Other comprehensive earnings, net of tax:
Foreign currency translation and other
Pension and postretirement plans
Other comprehensive earnings, net of tax
Comprehensive earnings (loss)
Comprehensive earnings (loss) attributable to
noncontrolling interests
Comprehensive earnings (loss) attributable to Devon
$
$
$
$
$
Year Ended December 31,
2016*
2017
2015*
5,307 $
8,642
13,949
1,823
380
7,730
2,074
17
(217)
872
498
(124)
13,053
896
(182)
1,078
180
898 $
3,981 $
6,323
10,304
1,803
215
5,533
2,096
1,310
(1,483)
865
907
375
11,621
(1,317)
141
(1,458)
(402)
(1,056) $
5,885
7,260
13,145
2,439
451
6,461
4,022
17,647
7
1,193
519
264
33,003
(19,858)
(6,213)
(13,645)
(749)
(12,896)
1.71 $
1.70 $
(2.09) $
(2.09) $
(31.72)
(31.72)
1,078 $
(1,458) $
(13,645)
83
29
112
1,190
11
22
33
(1,425)
(443)
10
(433)
(14,078)
$
180
1,010 $
(402)
(1,023) $
(749)
(13,329)
*
Prior year amounts have been recast due to change in accounting principle. See Note 2 in “Item 8. Financial
Statements and Supplementary Data” of this report.
See accompanying notes to consolidated financial statements.
57
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
Cash flows from operating activities:
Net earnings (loss)
Adjustments to reconcile net earnings (loss) to net cash
from operating activities:
Depreciation, depletion and amortization
Exploratory dry hole expense and unproved leasehold impairments
Asset impairments
Gains and losses on asset sales
Deferred income tax expense (benefit)
Commodity derivatives
Cash settlements on commodity derivatives
Other derivatives and financial instruments
Cash settlements on other derivatives and financial instruments
Asset retirement obligation accretion
Share-based compensation
Other
Net change in working capital
Change in long-term other assets
Change in long-term other liabilities
Net cash from operating activities
Cash flows from investing activities:
Capital expenditures
Acquisitions of property, equipment and businesses
Divestitures of property and equipment
Proceeds from sale of investment
Other
Net cash from investing activities
Cash flows from financing activities:
Borrowings of long-term debt, net of issuance costs
Repayments of long-term debt
Payment of installment payable
Net short-term debt repayments
Early retirement of debt
Issuance of common stock
Sale of subsidiary units
Issuance of subsidiary units
Dividends paid on common stock
Contributions from noncontrolling interests
Distributions to noncontrolling interests
Shares exchanged for tax withholdings
Other
Net cash from financing activities
Effect of exchange rate changes on cash
Net change in cash and cash equivalents
Cash and cash equivalents at beginning of period
Cash and cash equivalents at end of period
Year Ended December 31,
2016*
2017
2015*
$
1,078 $
(1,458) $
(13,645)
2,074
219
17
(217)
(294)
(157)
53
23
(6)
62
198
(122)
21
(46)
6
2,909
(2,759)
(46)
417
190
(12)
(2,210)
2,376
(2,118)
(250)
—
(6)
—
—
501
(127)
57
(354)
(68)
(2)
9
6
714
1,959
2,673 $
2,096
113
1,310
(1,483)
41
201
1
185
(143)
75
233
270
24
36
(1)
1,500
(2,047)
(1,641)
3,113
—
(19)
(594)
2,145
(4,409)
—
(626)
(265)
1,469
—
892
(221)
168
(304)
(35)
(10)
(1,196)
(61)
(351)
2,310
1,959 $
4,022
248
17,647
7
(5,976)
(503)
2,416
(235)
272
75
244
312
(265)
285
(6)
4,898
(4,787)
(1,107)
107
—
(16)
(5,803)
4,772
(2,634)
—
(307)
—
—
654
25
(396)
16
(254)
(51)
(13)
1,812
(77)
830
1,480
2,310
$
*
Prior year amounts have been recast due to change in accounting principle. See Note 2 in “Item 8. Financial Statements and
Supplementary Data” of this report.
See accompanying notes to consolidated financial statements.
58
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
December 31, 2017
December 31, 2016*
Current assets:
Cash and cash equivalents
Accounts receivable
Assets held for sale
Other current assets
Total current assets
Oil and gas property and equipment, based on successful efforts
accounting, net
Midstream and other property and equipment, net
Total property and equipment, net
Goodwill
Other long-term assets
Total assets
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable
Revenues and royalties payable
Short-term debt
Other current liabilities
Total current liabilities
Long-term debt
Asset retirement obligations
Other long-term liabilities
Deferred income taxes
Equity:
Common stock, $0.10 par value. Authorized 1.0 billion shares; issued
525 million and 523 million shares in 2017 and 2016, respectively
Additional paid-in capital
Retained earnings (accumulated deficit)
Accumulated other comprehensive earnings
Total stockholders’ equity attributable to Devon
Noncontrolling interests
Total equity
Total liabilities and equity
$
$
$
$
2,673 $
1,670
—
448
4,791
13,318
7,853
21,171
2,383
1,896
30,241 $
819 $
1,180
115
1,201
3,315
10,291
1,113
583
835
53
7,333
702
1,166
9,254
4,850
14,104
30,241 $
1,959
1,356
193
264
3,772
12,998
7,535
20,533
2,383
1,987
28,675
642
908
—
1,066
2,616
10,154
1,226
894
1,063
52
7,237
(69)
1,054
8,274
4,448
12,722
28,675
*
Prior year amounts have been recast due to change in accounting principle. See Note 2 in “Item 8. Financial
Statements and Supplementary Data” of this report.
See accompanying notes to consolidated financial statements.
59
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF EQUITY
Retained
Additional Earnings
Accumulated
Other
Common Stock Paid-In (Accumulated Comprehensive Treasury Noncontrolling Total
Shares Amount Capital
Deficit)
Earnings
Stock
Interests
Equity
409 $
41 $
4,088 $
16,631 $
779 $
— $
4,802 $ 26,341
—
—
—
(2,227 )
675
—
—
(1,552 )
409 $
4,088 $
14,404 $
Previously reported as of December 31,
2014
Effect of change in accounting
principle
Balance as of December 31, 2014 as
recast*
Net loss
—
Other comprehensive loss, net of tax —
Stock option exercises
—
Restricted stock grants, net of
cancellations
Common stock repurchased
Common stock retired
Common stock dividends
Common stock issued
Share-based compensation
Share-based compensation tax
expense
Subsidiary equity transactions
Distributions to noncontrolling
interests
2
—
—
—
7
—
—
—
Balance as of December 31, 2015*
Net loss
Other comprehensive earnings, net of
tax
Restricted stock grants, net of
cancellations
Common stock repurchased
Common stock retired
Common stock dividends
Common stock issued
Share-based compensation
Subsidiary equity transactions
Distributions to noncontrolling
interests
Balance as of December 31, 2016*
Net earnings
Other comprehensive earnings, net of
tax
Restricted stock grants, net of
cancellations
Common stock repurchased
Common stock retired
Common stock dividends
Share-based compensation
Subsidiary equity transactions
Distributions to noncontrolling
interests
Balance as of December 31, 2017
—
418 $
—
—
2
—
—
—
103
—
—
—
523 $
—
—
1
—
—
—
1
—
41 $
—
—
—
—
—
—
—
1
—
—
—
—
42 $
—
—
—
—
—
—
10
—
—
—
52 $
—
—
1
—
—
—
—
—
—
—
4
—
—
(35 )
—
198
165
(9 )
585
—
4,996 $
—
—
—
—
(28 )
(96 )
2,117
168
80
—
7,237 $
—
—
—
—
(44 )
—
126
14
(12,896 )
—
—
—
—
—
(396 )
—
—
—
—
—
1,112 $
(1,056 )
—
—
—
—
(125 )
—
—
—
—
(69 ) $
898
—
—
—
—
(127 )
—
—
—
702 $
1,454 $
—
(433 )
—
—
—
—
—
—
—
—
—
—
1,021 $
—
33
—
—
—
—
—
—
—
—
1,054 $
—
— $
—
—
—
—
(35 )
35
—
—
—
—
—
—
— $
—
—
—
(28 )
28
—
—
—
—
—
— $
—
4,802 $ 24,789
(749 ) (13,645 )
(433 )
4
—
—
—
—
—
—
—
—
—
141
—
(35 )
—
(396 )
199
165
(9 )
726
(254 )
(254 )
3,940 $ 11,111
(402 )
(1,458 )
—
33
—
—
—
—
—
—
1,214
—
(28 )
—
(221 )
2,127
168
1,294
(304 )
(304 )
4,448 $ 12,722
180
1,078
112
—
—
112
—
—
—
—
—
—
—
1,166 $
—
(44 )
44
—
—
—
—
— $
—
—
—
—
—
576
1
(44 )
—
(127 )
126
590
(354 )
(354 )
4,850 $ 14,104
—
525 $
—
53 $
—
7,333 $
*
Prior year amounts have been recast due to change in accounting principle. See Note 2 in “Item 8. Financial Statements and
Supplementary Data” of this report.
See accompanying notes to consolidated financial statements.
60
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1.
Summary of Significant Accounting Policies
Devon is a leading independent energy company engaged primarily in the exploration, development and
production of oil, natural gas and NGLs. Devon’s operations are concentrated in various North American onshore
areas in the U.S. and Canada. Devon also owns natural gas pipelines, plants and treatment facilities through its
ownership in EnLink and the General Partner.
Accounting policies used by Devon and its subsidiaries conform to accounting principles generally accepted
in the U.S. and reflect industry practices. The more significant of such policies are discussed below.
Change in Accounting Principle and Presentation Changes
In the fourth quarter of 2017, Devon changed its method of accounting for its oil and gas exploration and
development activities from the full cost method to the successful efforts method. In accordance with FASB ASC
250 “Accounting Changes and Error Corrections,” financial information for prior periods has been recast to reflect
retrospective application of the successful efforts method, as prescribed by the FASB ASC 932 “Extractive
Activities—Oil and Gas.” Although the full cost method of accounting for oil and gas exploration and development
activities continues to be an accepted alternative, the successful efforts method of accounting is the preferred method
and is more widely used in the industry and will improve comparison to Devon’s peer group. Devon believes the
successful efforts method provides a more transparent representation of its results of operations. The successful
efforts method also provides our investments in oil and gas properties to be assessed for impairment as of the
balance sheet date in accordance with FASB ASC 360 “Property, Plant and Equipment” rather than valuations
based on 12-month historical prices and costs prescribed under the full cost method. For more detailed information
regarding the effects of the change in accounting principle to the successful efforts method, see Note 2.
As Devon recast its financial statements to the successful efforts method, the financial statements and
disclosures were examined through the lens of simplicity and transparency. From this assessment, certain changes
were made to the financial statement presentation not specifically required by the successful efforts method of
accounting. In general, Devon sought to simplify the presentation of its consolidated comprehensive statements of
earnings and provide expanded and improved disclosures of key components in its operating results. These
presentation judgments improve the clarity and utility of the financial operating results for investors and other
stakeholders. As a result, certain prior period amounts have been reclassified to align to this new approach. To
ensure financial statement users clearly understand the changes, a description of each enhancement is provided
below.
•
•
•
Operating income – Devon previously segregated expenses between operating and nonoperating on the
statement of operations. The only material nonoperating expense was generally financing costs. Devon
streamlined the overall comprehensive statements of earnings by eliminating the operating income
distinction.
Upstream revenues – On the statement of operations, Devon is combining sales of oil, gas and NGL
volumes, as well as oil, gas and NGL derivative activity, into this new line item. With the streamlined
presentation of upstream revenues, MD&A and other disclosures of these items were expanded.
Production expenses – Similar to streamlining the presentation of upstream revenues, Devon is
simplifying the presentation of cash-based expenses associated with upstream production. Previously
these expenses were reported separately as lease operations and production and property taxes in the
comprehensive statements of earnings. These items are now combined in this new line item. Devon has
expanded the MD&A and other disclosures of expenses for lease operations, gathering and
transportation, production taxes and property taxes.
61
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
•
•
Asset impairments – Except for unproved oil and gas property impairments, this line item will capture
all impairments of Devon’s assets. After research of peers, Devon decided to report unproved
impairments as part of exploration expenses. Because asset impairments are non-routine adjustments to
the cost basis of assets, this item was placed adjacent to DD&A, the routine adjustment of the cost basis
of assets, on the comprehensive statements of earnings.
Asset dispositions – This line item will capture gains and losses from dispositions of assets. As a full
cost company, Devon rarely had material gains and losses on asset dispositions. However, when it did,
such amounts were reported as part of revenues. Devon has more gains and losses under the successful
efforts method of accounting. Since recognizing gains and losses on asset dispositions are largely
affected by previously recognized DD&A and asset impairments, this item was placed adjacent to those
items on the comprehensive statements of earnings.
Principles of Consolidation
The accompanying consolidated financial statements include the accounts of Devon and entities in which it
holds a controlling interest. All intercompany transactions have been eliminated. Undivided interests in oil and
natural gas exploration and production joint ventures are consolidated on a proportionate basis. Investments in non-
controlled entities, over which Devon has the ability to exercise significant influence over operating and financial
policies, are accounted for using the equity method. In applying the equity method of accounting, the investments
are initially recognized at cost and subsequently adjusted for Devon’s proportionate share of earnings, losses,
contributions and distributions. Investments accounted for using the equity method and cost method are reported as a
component of other long-term assets.
Devon completed a business combination in 2014 whereby Devon controls both EnLink and the General
Partner. Devon controls both the General Partner’s and EnLink’s operations; therefore, the General Partner’s and
EnLink’s accounts are included in Devon’s accompanying consolidated financial statements subsequent to the
completion of the transaction. The portions of the General Partner’s and EnLink’s net earnings and equity not
attributable to Devon’s controlling interest are shown separately as noncontrolling interests in the accompanying
consolidated comprehensive statements of earnings and consolidated balance sheets.
Use of Estimates
The preparation of financial statements requires management to make estimates and assumptions that affect
the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the
financial statements and the reported amounts of revenues and expenses during the reporting period. Actual amounts
could differ from these estimates, and changes in these estimates are recorded when known. Significant items
subject to such estimates and assumptions include the following:
•
•
•
•
•
•
•
•
•
proved reserves and related present value of future net revenues;
evaluation of suspended well costs;
the carrying and fair values of oil and gas properties, midstream assets and product and equipment
inventories;
derivative financial instruments;
the fair value of reporting units and related assessment of goodwill for impairment;
the fair value of intangible assets other than goodwill;
income taxes;
asset retirement obligations;
obligations related to employee pension and postretirement benefits;
62
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
•
•
legal and environmental risks and exposures; and
general credit risk associated with receivables and other assets.
Revenue Recognition
Oil, gas and NGL sales are recognized when production is sold to a purchaser at a fixed or determinable price,
delivery has occurred, title has transferred and collectability of the revenue is probable. Delivery occurs and title
typically is transferred when production has been delivered to a pipeline, railcar or truck. Cash received relating to
future production is deferred and recognized when all revenue recognition criteria are met. Taxes assessed by
governmental authorities on oil, gas and NGL sales are presented separately from such revenues in the
accompanying consolidated comprehensive statements of earnings.
Marketing and midstream revenues are recorded at the time products are sold or services are provided to third
parties at a fixed or determinable price, delivery or performance has occurred, title has transferred and collectability
of the revenue is probable. Revenues and expenses attributable to oil, gas and NGL purchases, transportation and
processing contracts are reported on a gross basis when Devon takes title to the products and has risks and rewards
of ownership.
During 2017, 2016 and 2015, no purchaser accounted for more than 10% of Devon’s consolidated sales
revenue.
Derivative Financial Instruments
Devon is exposed to certain risks relating to its ongoing business operations, including risks related to
commodity prices, interest rates and Canadian to U.S. dollar exchange rates. As discussed more fully below, Devon
uses derivative instruments primarily to manage commodity price risk, interest rate risk and foreign exchange risk.
Devon does not intend to issue or hold derivative financial instruments for speculative trading purposes.
Devon enters into derivative financial instruments with respect to a portion of its oil, gas and NGL production
to hedge future prices received. Additionally, Devon and EnLink periodically enter into derivative financial
instruments with respect to a portion of their oil, gas and NGL marketing activities. These instruments are used to
manage the inherent uncertainty of future revenues resulting from commodity price volatility. Devon’s derivative
financial instruments typically include financial price swaps, basis swaps, costless price collars and call options.
Under the terms of the price swaps, Devon receives a fixed price for its production and pays a variable market price
to the contract counterparty. For the basis swaps, Devon receives a fixed differential between two regional index
prices and pays a variable differential on the same two index prices to the contract counterparty. The price collars set
a floor and ceiling price for the hedged production. If the applicable monthly price indices are outside of the ranges
set by the floor and ceiling prices in the various collars, Devon will cash-settle the difference with the counterparty
to the collars. The call options give counterparties the right to purchase production at a predetermined price.
Devon periodically enters into interest rate swaps to manage its exposure to interest rate volatility and foreign
exchange forward contracts to manage its exposure to fluctuations in the U.S. and Canadian dollar exchange rates.
As of December 31, 2017, Devon did not have any open foreign exchange contracts.
All derivative financial instruments are recognized at their current fair value as either assets or liabilities in the
balance sheet. Changes in the fair value of these derivative financial instruments are recorded in earnings unless
specific hedge accounting criteria are met. For derivative financial instruments held during the three-year period
ended December 31, 2017, Devon chose not to meet the necessary criteria to qualify its derivative financial
instruments for hedge accounting treatment. Cash settlements with counterparties on Devon’s derivative financial
instruments are also recorded in earnings. Cash settlements that Devon is entitled to are accrued for in other current
assets in the accompanying consolidated balance sheets.
63
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
By using derivative financial instruments to hedge exposures to changes in commodity prices, interest rates
and foreign currency rates, Devon is exposed to credit risk. Credit risk is the failure of the counterparty to perform
under the terms of the derivative contract. To mitigate this risk, the hedging instruments are placed with a number of
counterparties whom Devon believes are acceptable credit risks. It is Devon’s policy to enter into derivative
contracts only with investment-grade rated counterparties deemed by management to be competent and competitive
market makers. Additionally, Devon’s derivative contracts generally require cash collateral to be posted if either its
or the counterparty’s credit rating falls below certain credit rating levels. As of December 31, 2017, Devon held no
cash collateral of its counterparties nor posted collateral to its counterparties.
General and Administrative Expenses
G&A is reported net of amounts reimbursed by working interest owners of the oil and gas properties operated
by Devon.
Share-Based Compensation
Independent of EnLink, Devon grants share-based awards to members of its Board of Directors and select
employees. EnLink and the General Partner also grant share-based awards to members of its Board of Directors and
select employees. All such awards are measured at fair value on the date of grant and are generally recognized as a
component of G&A in the accompanying consolidated comprehensive statements of earnings over the applicable
requisite service periods. As a result of Devon’s restructuring activity discussed in Note 7, certain share-based
awards were accelerated and recognized as a component of restructuring costs in the accompanying 2016
consolidated comprehensive statements of earnings.
Generally, Devon uses new shares from approved incentive programs to grant share-based awards and to issue
shares upon stock option exercises. Shares repurchased under approved programs are generally available to be
issued as part of Devon’s share-based awards. However, Devon has historically canceled these shares upon
repurchase.
Income Taxes
Devon is subject to current income taxes assessed by the federal and various state jurisdictions in the U.S. and
by other foreign jurisdictions. In addition, Devon accounts for deferred income taxes related to these jurisdictions
using the asset and liability method. Under this method, deferred tax assets and liabilities are recognized for the
future tax consequences attributable to differences between the financial statement carrying amounts of assets and
liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates
expected to apply to taxable income in the years in which those temporary differences and carryforwards are
expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is
recognized in income in the period that includes the enactment date.
Deferred tax assets are also recognized for the future tax benefits attributable to the expected utilization of
existing tax net operating loss carryforwards and other types of carryforwards. If the future utilization of some
portion of the deferred tax assets is determined to be unlikely, a valuation allowance is provided to reduce the
recorded tax benefits from such assets. Devon periodically weighs the positive and negative evidence to determine if
it is more likely than not that some or all of the deferred tax assets will be realized. Forming a conclusion that a
valuation allowance is not required is difficult when there is negative evidence, such as cumulative losses in recent
years. See Note 8 for further discussion.
Devon recognizes the financial statement effects of tax positions when it is more likely than not, based on the
technical merits, that the position will be sustained upon examination by a taxing authority. Recognized tax
positions are initially and subsequently measured as the largest amount of tax benefit that is more likely than not of
being realized upon ultimate settlement with a taxing authority. Liabilities for unrecognized tax benefits related to
such tax positions are included in other long-term liabilities unless the tax position is expected to be settled within
64
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
the upcoming year, in which case the liabilities are included in other current liabilities. Interest and penalties related
to unrecognized tax benefits are included in current income tax expense.
Devon estimates its annual effective income tax rate in recording its provision for income taxes in the various
jurisdictions in which it operates. Statutory tax rate changes and other significant or unusual items are recognized as
discrete items in the period in which they occur.
Net Earnings (Loss) Per Share Attributable to Devon
Devon’s basic earnings per share amounts have been computed based on the average number of shares of
common stock outstanding for the period. Basic earnings per share includes the effect of participating securities,
which primarily consist of Devon’s outstanding restricted stock awards, as well as performance-based restricted
stock awards that have met the requisite performance targets. Diluted earnings per share is calculated using the
treasury stock method to reflect the assumed issuance of common shares for all potentially dilutive securities. Such
securities primarily consist of unvested performance share units.
Cash and Cash Equivalents
Devon considers all highly liquid investments with original contractual maturities of three months or less to be
cash equivalents.
Accounts Receivable
Devon’s accounts receivable balance primarily consists of oil and gas sales receivables, marketing and
midstream revenue receivables and joint interest receivables for which Devon does not require collateral security.
Devon has established an allowance for bad debts equal to the estimable portions of accounts receivable for which
failure to collect is considered probable. When a portion of the receivable is deemed uncollectible, the write-off is
made against the allowance.
Property and Equipment
Oil and Gas Property and Equipment
Devon follows the successful efforts method of accounting for its oil and gas properties. Under this method
exploration costs, such as exploratory geological and geophysical costs, and costs associated with nonproductive
exploratory wells, delay rentals and exploration overhead are charged against earnings as incurred. Costs of drilling
successful exploratory wells along with acquisition costs and the costs of drilling development wells, including
those that are unsuccessful, are capitalized. Devon groups its oil and gas properties with a common geological
structure or stratigraphic condition (“common operating field”) in accordance with ASC 932 “Extractive Activities –
Oil and Gas” for purposes of computing DD&A, assessing proved property impairments and accounting for asset
dispositions.
Exploratory drilling costs and exploratory-type stratigraphic test wells are initially capitalized, or suspended,
pending the determination of proved reserves. If proved reserves are found, drilling costs remain capitalized as
proved properties. Costs of unsuccessful wells are charged to exploration expense. For exploratory wells that find
reserves that cannot be classified as proved when drilling is completed, costs continue to be capitalized as suspended
exploratory well costs if there have been sufficient reserves found to justify completion as a producing well and
sufficient progress is being made in assessing the reserves and the economic and operating viability of the project. If
management determines that future appraisal drilling or development activities are unlikely to occur, associated
suspended exploratory well costs are expensed. In some instances, this determination may take longer than one year.
Devon reviews the status of all suspended exploratory drilling costs quarterly.
65
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Capitalized costs of proved oil and gas properties are depleted by an equivalent unit-of-production method,
converting gas to oil at the ratio of six Mcf of gas to one Bbl of oil. Proved leasehold acquisition costs, less
accumulated amortization, are depleted over total proved reserves, which includes proved undeveloped reserves.
Capitalized costs of wells and related equipment and facilities, including estimated asset retirement costs, net of
estimated salvage values and less accumulated amortization are depreciated over proved developed reserves
associated with those capitalized costs. Depletion is calculated by applying the DD&A rate (amortizable base
divided by beginning of period proved reserves) to current period production.
Costs associated with unproved properties are excluded from the depletion calculation until it is determined
whether or not proved reserves can be assigned to such properties. Devon assesses its unproved properties for
impairment annually, or more frequently if events or changes in circumstances dictate that the carrying value of
those assets may not be recoverable. Significant unproved properties are assessed individually. Costs of insignificant
unproved properties are amortized to exploration expense on a group basis using estimated lease surrender rates over
average lease terms.
Proved properties are assessed for impairment annually, or more frequently if events or changes in
circumstances dictate that the carrying value of those assets may not be recoverable. Individual assets are grouped
for impairment purposes based on a common operating field. If there is an indication the carrying amount of an asset
may not be recovered, the asset is assessed for potential impairment by management through an established process.
If, upon review, the sum of the undiscounted pre-tax cash flows is less than the carrying value of the asset, the
carrying value is written down to estimated fair value. Because there is usually a lack of quoted market prices for
long-lived assets, the fair value of impaired assets is typically determined based on the present values of expected
future cash flows using discount rates believed to be consistent with those used by principal market participants or
by comparable transactions. The expected future cash flows used for impairment reviews and related fair value
calculations are typically based on judgmental assessments of future production volumes, commodity prices,
operating costs, and capital investment plans, considering all available information at the date of review.
Gains or losses are recorded for sales or dispositions of oil and gas properties which constitute an entire
common operating field or which result in a significant alteration of the common operating field’s DD&A rate.
These gains and losses are classified as asset dispositions in the accompanying consolidated statements of earnings.
Partial common operating field sales or dispositions deemed not to significantly alter the DD&A rates are generally
accounted for as adjustments to capitalized costs with no gain or loss recognized.
Devon capitalizes interest costs incurred and attributable to material unproved oil and gas properties and major
development projects of oil and gas properties.
Midstream and Other Property and Equipment
Costs for midstream assets that are in use are depreciated over the assets’ estimated useful lives, using the
straight-line method. Depreciation and amortization of other property and equipment, including corporate and
leasehold improvements, are provided using the straight-line method based on estimated useful lives ranging from
three to 60 years. Interest costs incurred and attributable to major midstream and corporate construction projects are
also capitalized.
Asset Retirement Obligations
Devon recognizes liabilities for retirement obligations associated with tangible long-lived assets, such as
producing well sites and midstream pipelines and processing plants when there is a legal obligation associated with
the retirement of such assets and the amount can be reasonably estimated. The initial measurement of an asset
retirement obligation is recorded as a liability at its fair value, with an offsetting asset retirement cost recorded as an
increase to the associated property and equipment on the consolidated balance sheet. When the assumptions used to
estimate a recorded asset retirement obligation change, a revision is recorded to both the asset retirement obligation
and the asset retirement cost. Devon’s asset retirement obligations also include estimated environmental remediation
costs which arise from normal operations and are associated with the retirement of such long-lived assets. The asset
retirement cost is depreciated using a systematic and rational method similar to that used for the associated property
and equipment.
66
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Goodwill
Goodwill represents the excess of the purchase price of business combinations over the fair value of the net
assets acquired and is tested for impairment annually, or more frequently if events or changes in circumstances
dictate that the carrying value of goodwill may not be recoverable. Such test includes an assessment of qualitative
and quantitative factors. The impairment test requires the fair value of each reporting unit be compared to the
carrying value of the reporting unit. If the fair value of the reporting unit is less than the carrying value, then
goodwill is written down to the fair value of the goodwill through a charge to expense. Because quoted market
prices are not available for Devon’s reporting units, the fair values of the reporting units are estimated based upon
several valuation analyses, including comparable companies, comparable transactions and premiums paid.
Devon and EnLink performed annual impairment tests of goodwill in the fourth quarters of 2017, 2016 and
2015. No impairment was required as a result of the annual tests in 2017 or 2016; however, sustained weakness in
the overall energy sector driven by lower commodity prices, together with a decline in the EnLink unit price, caused
a change in circumstances warranting an interim impairment test and write-down for certain of EnLink’s reporting
units in the first quarter of 2016. Write-downs were also required in 2015 for certain EnLink reporting units. See
Note 14 for further discussion.
Intangible Assets
Unamortized capitalized intangible assets, consisting of EnLink customer relationships, are presented in other
long-term assets in the accompanying consolidated balance sheets. These assets are amortized on a straight-line
basis over the expected periods of benefits, which range from 10 to 20 years. During 2017, 2016 and 2015, EnLink’s
customer relationships were also evaluated for impairment, and in 2015, a portion of these intangible assets was
considered impaired. See Note 14 for further discussion.
Commitments and Contingencies
Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded
when it is probable that a liability has been incurred and the amount can be reasonably estimated. Liabilities for
environmental remediation or restoration claims resulting from allegations of improper operation of assets are
recorded when it is probable that obligations have been incurred and the amounts can be reasonably estimated.
Expenditures related to such environmental matters are expensed or capitalized in accordance with Devon’s
accounting policy for property and equipment.
Fair Value Measurements
Certain of Devon’s assets and liabilities are measured at fair value at each reporting date. Fair value represents
the price that would be received to sell the asset or paid to transfer the liability in an orderly transaction between
market participants. This price is commonly referred to as the “exit price.” Fair value measurements are classified
according to a hierarchy that prioritizes the inputs underlying the valuation techniques. This hierarchy consists of
three broad levels:
•
•
•
Level 1 – Inputs consist of unadjusted quoted prices in active markets for identical assets and liabilities
and have the highest priority. When available, Devon measures fair value using Level 1 inputs because
they generally provide the most reliable evidence of fair value.
Level 2 – Inputs consist of quoted prices that are generally observable for the asset or liability. Common
examples of Level 2 inputs include quoted prices for similar assets and liabilities in active markets or
quoted prices for identical assets and liabilities in markets not considered to be active.
Level 3 – Inputs are not observable from objective sources and have the lowest priority. The most
common Level 3 fair value measurement is an internally developed cash flow model.
67
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Foreign Currency Translation Adjustments
The U.S. dollar is the functional currency for Devon’s consolidated operations except its Canadian
subsidiaries, which use the Canadian dollar as the functional currency. Assets and liabilities of the Canadian
subsidiaries are translated to U.S. dollars using the applicable exchange rate as of the end of a reporting period.
Revenues, expenses and cash flow are translated using an average exchange rate during the reporting period.
Translation adjustments have no effect on net income and are included in accumulated other comprehensive
earnings in stockholders’ equity.
Noncontrolling Interests
Noncontrolling interests represent third-party ownership in the net assets of Devon’s consolidated subsidiaries
and are presented as a component of equity. Changes in Devon’s ownership interests in subsidiaries that do not
result in deconsolidation are recognized in equity.
Recently Adopted Accounting Standards
In January 2017, Devon adopted ASU 2016-09, Compensation – Stock Compensation (Topic 718),
Improvements to Employee Share-Based Payment Accounting. Its objective is to simplify several aspects of the
accounting for share-based payments, including income taxes when awards vest or are settled, statutory withholding
and forfeitures. As the result of adoption, Devon made certain income tax presentation changes, most notably
prospectively presenting excess tax benefits and deficiencies in the consolidated comprehensive statements of
earnings and as operating cash flows in the consolidated statements of cash flows. Devon also retrospectively
applied the new cash flow statement guidance dictating the presentation of shares exchanged for tax-withholding
purposes as a financing activity. The adoption of the new guidance did not materially impact the consolidated
financial statements for the year ended December 31, 2017 or previously reported financial information but could
have a more material future impact.
In January 2017, the FASB issued ASU 2017-04, Intangibles – Goodwill And Other (Topic 350), Simplifying
the Test for Goodwill Impairment (ASU 2017-04). ASU 2017-04 simplifies the accounting for goodwill
impairments by eliminating the requirement to compare the implied fair value of goodwill with its carrying amount
as part of step two of the goodwill impairment test. Under ASU 2017-04, an entity should perform its goodwill
impairment test by comparing the fair value of a reporting unit with its carrying amount. An impairment charge
should be recognized for the amount by which the carrying amount exceeds the reporting unit's fair value. However,
the impairment loss recognized should not exceed the total amount of goodwill allocated to that reporting unit. ASU
2017-04 is effective for annual reporting periods beginning after December 15, 2019, including any interim
impairment tests within those annual periods, with early application for interim or annual goodwill impairment tests
performed on testing dates after January 1, 2017. In January 2017, Devon elected to early adopt ASU 2017-04. The
adoption had no impact on the consolidated financial statements.
Issued Accounting Standards Not Yet Adopted
In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (ASU 2014-09),
which established ASC Topic 606, Revenue from Contracts with Customers (ASC 606). ASC 606 will replace
existing revenue recognition requirements in GAAP and will require entities to recognize revenue at an amount that
reflects the consideration to which they expect to be entitled in exchange for transferring goods or services to a
customer. ASC 606 will also require significantly expanded disclosures containing qualitative and quantitative
information regarding the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts
with customers. In May 2016, the FASB issued ASU 2016-12, Revenue from Contracts with Customers (Topic
606): Narrow-Scope Improvements and Practical Expedients (ASU 2016-12), which updated ASU 2014-09. ASU
2016-12 clarifies certain core recognition principles, including collectability, sales tax presentation, noncash
consideration, contract modifications and completed contracts at transition and disclosures no longer required if the
full retrospective transition method is adopted. ASU 2014-09 and ASU 2016-12 are effective for annual reporting
68
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
periods beginning after December 15, 2017, including interim periods within those annual periods, and are to be
applied using the modified retrospective or full retrospective transition methods, with early application permitted for
annual reporting periods beginning after December 15, 2016. Devon will adopt ASC 606 using the modified
retrospective method for annual and interim reporting periods beginning January 1, 2018.
Devon has aggregated and reviewed its contracts that are within the scope of ASC 606. Based on its
evaluation, Devon does not anticipate the adoption of ASC 606 will have a material impact on its balance sheet or
related consolidated statements of earnings, equity or cash flows. Accordingly, Devon will continue to recognize
revenue at the time commodities are delivered. However, ASC 606 will affect how certain transactions are presented
in its financial statements. Under this guidance, an entity generally shall record revenue on a gross basis if it controls
a promised good or service before transferring it to a customer, whereas an entity shall record revenue on a net basis
if its role is to arrange for another entity to provide the goods or services to a customer. Devon will change its
presentation of certain processing arrangements from a net presentation to a gross presentation. This change will
impact Devon’s upstream revenues and production expenses by approximately $250 million for 2016 and 2017, and
will impact 2018 by a similar amount. EnLink will change the presentation of certain marketing and midstream
revenues to marketing and midstream operating expenses or from marketing and midstream operating expenses to
marketing and midstream revenues. Devon estimates this reclassification will result in a net decrease in EnLink’s
marketing and midstream revenues of approximately 6-10%. These estimates are based on historical information and
could change based on future volumes and commodity prices. These presentation changes will have no impact on
net earnings or cash flows.
Based on the disclosure requirements of ASC 606, upon adoption, Devon expects to provide expanded
disclosures relating to its revenue recognition policies and how these relate to its revenue-generating contractual
performance obligations. In addition, Devon expects to present revenues disaggregated based on the type of good or
service in order to more fully depict the nature of its revenues.
The FASB issued ASU 2016-02, Leases (Topic 842). This ASU will supersede the lease requirements in
Topic 840, Leases. Its objective is to increase transparency and comparability among organizations. This ASU
provides guidance requiring lessees to recognize most leases on their balance sheet. Lessor accounting does not
significantly change, except for some changes made to align with new revenue recognition requirements. This ASU
is effective for Devon beginning January 1, 2019. Early adoption is permitted, but Devon does not plan to early
adopt. Currently the guidance would be applied using a modified retrospective transition method, which requires
applying the new guidance to leases that exist or are entered into after the beginning of the earliest period in the
financial statements. However, the FASB recently issued Proposed ASU No. 2018-200, Leases (Topic 842),
Targeted Improvements which would allow entities to apply the transition provisions of the new standard at its
adoption date instead of at the earliest comparative period presented in the consolidated financial statements. The
proposed ASU will allow entities to continue to apply the legacy guidance in Topic 840, including its disclosure
requirements, in the comparative periods presented in the year the new leases standard is adopted. Entities that elect
this option would still adopt the new leases standard using a modified retrospective transition method, but would
recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption rather
than in the earliest period presented. Devon is in the process of evaluating contracts and gathering the necessary
terms and data elements for purposes of determining the impact this ASU will have on its consolidated financial
statements and related disclosures. Recently, the FASB issued ASU No. 2018-01, Leases (Topic 842), Land
Easement Practical Expedient for Transition to Topic 842. This ASU would permit an entity not to apply Topic 842
to land easements and rights-of-way that exist or expired before the effective date of Topic 842 and that were not
previously assessed under Topic 840. An entity would continue to apply its current accounting policy for accounting
for land easements that existed before the effective date of Topic 842. Once an entity adopts Topic 842, it would
apply that Topic prospectively to all new (or modified) land easements and rights-of-way to determine whether the
arrangement should be accounted for as a lease. For Devon, these contracts represent a relatively small percentage of
the aggregate value of contracts being evaluated but represent a significant number of contracts.
Based on continuing research, Devon estimates a large number of contracts and data elements must be
gathered and reviewed to ensure proper accounting of these contracts once this ASU is effective. Devon has
preliminarily determined its portfolio of leased assets and is reviewing all related contracts to determine the impact
the adoption will have on its consolidated financial statements. Devon anticipates the adoption of this standard will
69
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
significantly impact its consolidated financial statements, systems, processes and controls and is evaluating
technology requirements and solutions needed to comply with the requirements of this ASU. While we cannot
currently estimate the quantitative effect that ASU 2016-02 will have on our consolidated financial statements, the
adoption will increase our asset and liability balances on the consolidated balance sheets due to the required
recognition of right-of-use assets and corresponding lease liabilities.
The FASB issued ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715), Improving the
Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost. This ASU will require
entities to present the service cost component of net periodic benefit cost in the same line item as other employee
compensation costs. Only the service cost component of net periodic benefit cost is eligible for capitalization. This
ASU is effective for Devon beginning January 1, 2018, and income statement presentation changes will be applied
retrospectively, while service cost component capitalization will be applied prospectively. Upon adoption of this
ASU, Devon will reclassify $7 million, $14 million and $16 million of non-service cost components of net periodic
benefit costs for 2017, 2016 and 2015, respectively, as other expenses. Such amounts are currently classified in
Devon’s G&A. No other changes upon adopting this ASU are expected to be material.
The FASB issued ASU 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash. This ASU requires
an entity to show the changes in the total of cash, cash equivalents, restricted cash, and restricted cash equivalents on
the statement of cash flows and to provide a reconciliation of the totals in the statement of cash flows to the related
captions in the balance sheet when the cash, cash equivalents, restricted cash, and restricted cash equivalents are
presented in more than one line item on the balance sheet. This reconciliation can be presented either on the face of
the consolidated statement of cash flows or in the notes to the financial statements. This ASU is effective for Devon
beginning January 1, 2018, and will be applied retrospectively. Currently, Devon does not expect the adoption to
have a material impact on its consolidated statement of cash flows.
The FASB issued ASU 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business.
This ASU clarifies the definition of a business to assist entities with evaluating whether a set of transferred assets
and activities should be accounted for as an acquisition or disposals of assets or as a business. The guidance requires
an entity to evaluate if substantially all of the fair value of the gross assets acquired, or disposed of, are concentrated
in a single identifiable asset or a group of similar identifiable assets; if so, the set of transferred assets and activities
would not represent a business. The guidance also requires that a set of assets must include an input and a
substantive process that together significantly contribute to the ability to create an output to be considered a
business. This ASU is effective for Devon beginning January 1, 2018, and will be applied prospectively. Devon does
not expect the adoption to have a material impact on its consolidated financial statements; however these
amendments could result in the recording of fewer business combinations in future periods.
The FASB issued ASU 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting
for Hedging Activities. This ASU will expand hedge accounting for nonfinancial and financial risk components and
amend measurement methodologies to more closely align hedge accounting with a company's risk management
activities. The guidance also eliminates the requirement to separately measure and report hedge ineffectiveness. This
ASU only applies to entities that elect hedge accounting, which Devon has not for derivative financial instruments
during the three year period ended December 31, 2017. This ASU is effective for annual and interim periods
beginning January 1, 2019, with early adoption permitted in 2018. The ASU is required to be adopted using a
cumulative effect (modified retrospective) transition method, which utilizes a cumulative-effect adjustment to
retained earnings in the period of adoption to account for prior period effects rather than restating previously
reported results. Devon is currently evaluating the provisions of this ASU and assessing the impact it may have on
its consolidated financial statements if hedge accounting were elected by Devon in the future.
70
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
2.
Change in Accounting Principle
In the fourth quarter of 2017, Devon changed its method of accounting for oil and gas exploration and
development activities from the full cost method to the successful efforts method. Accordingly, financial
information for prior periods has been recast to reflect retrospective application of the successful efforts method. In
general, under successful efforts, exploration costs such as exploratory dry holes, exploratory geological and
geophysical costs, delay rentals, unproved impairments, and exploration overhead are charged against earnings as
incurred, versus being capitalized under the full cost method of accounting. In addition, gains or losses, if
applicable, are recognized more frequently on the dispositions of oil and gas property and equipment under the
successful efforts method. Devon has recast certain historical information for all periods presented, including the
Consolidated Comprehensive Statements of Earnings, Consolidated Statements of Cash Flows, Consolidated
Balance Sheets, Consolidated Statements of Equity and related information in Notes 1, 2, 3, 5, 6, 7, 8, 9, 10, 11, 13,
14, 16, 22, 23, 24 and 25.
The following tables present the effects of the change to the successful efforts method in the consolidated
financial statements.
For the Year Ended December 31, 2017
Exploration expenses
Depreciation, depletion and amortization
Asset dispositions
General and administrative expenses
Financing costs, net
Other expenses
Earnings before income taxes
Income tax benefit
Net earnings
Net earnings attributable to Devon
Net earnings per share attributable to Devon:
Basic
Diluted
Comprehensive earnings:
Net earnings
Foreign currency translation and other
Comprehensive earnings
Comprehensive earnings attributable to Devon
Changes to the Consolidated Comprehensive
Statement of Earnings
Under Full Cost
$
— $
1,579
(5)
682
494
(102)
1,731
(140)
1,871
1,691
Changes
As Reported Under
Successful Efforts
380
2,074
(217)
872
498
(124)
896
(182)
1,078
898
380 $
495
(212)
190
4
(22)
(835)
(42)
(793)
(793)
3.22
3.20
1,871
4
1,904
1,724
(1.51)
(1.50)
(793)
79
(714)
(714)
1.71
1.70
1,078
83
1,190
1,010
71
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Changes to the Consolidated Comprehensive
Statement of Earnings
For the Year Ended December 31, 2016
Exploration expenses
Depreciation, depletion and amortization
Asset impairments
Asset dispositions
General and administrative expenses
Financing costs, net
Other expenses
Loss before income taxes
Income tax expense (benefit)
Net loss
Net loss attributable to Devon
Net loss per share attributable to Devon:
Basic
Diluted
Comprehensive loss:
Net loss
Foreign currency translation and other
Comprehensive loss
Comprehensive loss attributable to Devon
For the Year Ended December 31, 2015
Exploration expenses
Depreciation, depletion and amortization
Asset impairments
Asset dispositions
General and administrative expenses
Financing costs, net
Other expenses
Loss before income taxes
Income tax benefit
Net loss
Net loss attributable to Devon
Net loss per share attributable to Devon:
Basic
Diluted
Comprehensive loss:
Net loss
Foreign currency translation and other
Comprehensive loss
Comprehensive loss attributable to Devon
Under Full Cost
$
— $
1,792
4,975
(1,887)
658
904
403
(3,877)
(173)
(3,704)
(3,302)
Changes
As Reported Under
Successful Efforts
215
2,096
1,310
(1,483)
865
907
375
(1,317)
141
(1,458)
(1,056)
215 $
304
(3,665)
404
207
3
(28)
2,560
314
2,246
2,246
(6.52)
(6.52)
(3,704)
32
(3,650)
(3,248)
4.43
4.43
2,246
(21)
2,225
2,225
(2.09)
(2.09)
(1,458)
11
(1,425)
(1,023)
Changes to the Consolidated Comprehensive
Statement of Earnings
Under Full Cost
$
— $
3,129
20,820
—
868
517
179
(21,268)
(6,065)
(15,203)
(14,454)
Changes
As Reported Under
Successful Efforts
451
4,022
17,647
7
1,193
519
264
(19,858)
(6,213)
(13,645)
(12,896)
451 $
893
(3,173)
7
325
2
85
1,410
(148)
1,558
1,558
(35.55)
(35.55)
(15,203)
(559)
(15,752)
(15,003)
3.83
3.83
1,558
116
1,674
1,674
(31.72)
(31.72)
(13,645)
(443)
(14,078)
(13,329)
72
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
For the Year Ended December 31, 2017
Net earnings
$
Depreciation, depletion and amortization
Exploratory dry hole expense and unproved
leasehold impairments
Gains and losses on asset sales
Deferred income tax benefit
Share-based compensation
Other
Net cash from operating activities
Capital expenditures
Divestitures of property and equipment
Net cash from investing activities
For the Year Ended December 31, 2016
Net loss
$
Depreciation, depletion and amortization
Exploratory dry hole expense and unproved
leasehold impairments
Asset impairments
Gains and losses on asset sales
Deferred income tax expense (benefit)
Share-based compensation
Other
Net cash from operating activities
Capital expenditures
Divestitures of property and equipment
Net cash from investing activities
For the Year Ended December 31, 2015
Net loss
Depreciation, depletion and amortization
Exploratory dry hole expense and unproved
leasehold impairments
Asset impairments
Gains and losses on asset sales
Deferred income tax benefit
Share-based compensation
Other
Net cash from operating activities
Capital expenditures
Net cash from investing activities
Changes to the Consolidated
Statement of Cash Flows
Under Full Cost
Changes
As Reported Under
Successful Efforts
1,871 $
1,579
—
(5)
(252)
158
(108)
3,216
(3,074)
425
(2,517)
(793) $
495
219
(212)
(42)
40
(14)
(307)
315
(8)
307
1,078
2,074
219
(217)
(294)
198
(122)
2,909
(2,759)
417
(2,210)
Changes to the Consolidated
Statement of Cash Flows
Under Full Cost
Changes
As Reported Under
Successful Efforts
(3,704) $
1,792
—
4,975
(1,887)
(273)
194
303
1,778
(2,330)
3,118
(872)
2,246 $
304
113
(3,665)
404
314
39
(33)
(278)
283
(5)
278
(1,458)
2,096
113
1,310
(1,483)
41
233
270
1,500
(2,047)
3,113
(594)
Changes to the Consolidated
Statement of Cash Flows
Under Full Cost
Changes
As Reported Under
Successful Efforts
1,558 $
893
248
(3,173)
7
(148)
63
31
(521)
521
521
(13,645)
4,022
248
17,647
7
(5,976)
244
312
4,898
(4,787)
(5,803)
$
(15,203) $
3,129
—
20,820
—
(5,828)
181
281
5,419
(5,308)
(6,324)
73
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Changes to the Consolidated Balance Sheet
For the Year Ended December 31, 2017
Oil and gas property and equipment, net
Total property and equipment, net
Goodwill
Total assets
Deferred income taxes
Additional paid-in capital
Retained earnings
Accumulated other comprehensive earnings
Total stockholders’ equity attributable to Devon
Total equity
Total liabilities and equity
Under Full Cost
$
9,702
17,555
3,964
28,206
434
7,206
44
317
7,620
12,470
28,206
Changes
As Reported Under
Successful Efforts
13,318
21,171
2,383
30,241
835
7,333
702
1,166
9,254
14,104
30,241
3,616 $
3,616
(1,581)
2,035
401
127
658
849
1,634
1,634
2,035
Changes to the Consolidated Balance Sheet
For the Year Ended December 31, 2016
Oil and gas property and equipment, net
Total property and equipment, net
Goodwill
Total assets
Deferred income taxes
Accumulated deficit
Accumulated other comprehensive earnings
Total stockholders’ equity attributable to Devon
Total equity
Total liabilities and equity
Under Full Cost
$
8,655 $
16,190
3,964
25,913
648
(1,646)
284
5,927
10,375
25,913
3.
Acquisitions and Divestitures
Devon Acquisitions
Changes
As Reported Under
Successful Efforts
12,998
20,533
2,383
28,675
1,063
(69)
1,054
8,274
12,722
28,675
4,343 $
4,343
(1,581)
2,762
415
1,577
770
2,347
2,347
2,762
In January 2016, Devon acquired approximately 80,000 net acres (unaudited) and assets in the STACK play
for approximately $1.5 billion. Devon funded the acquisition with $849 million of cash, after adjustments, and $659
million of equity. The allocation of the purchase price was approximately $1.3 billion to unproved properties and
approximately $200 million to proved properties.
In December 2015, Devon acquired approximately 253,000 net acres (unaudited) and assets in the Powder
River Basin for approximately $499 million. Devon funded the acquisition with $300 million of cash and $199
million of equity. The allocation of the purchase price was $393 million to unproved properties and $106 million to
proved properties.
Devon Asset Divestitures
Upstream Assets
In May 2017, Devon announced a program to divest approximately $1 billion of upstream assets. The non-
core assets identified for monetization include select portions of the Barnett Shale focused primarily in and around
Johnson County and other properties located principally within Devon’s U.S. resource base. Through December 31,
2017, Devon completed divestiture transactions with proceeds totaling approximately $415 million, before purchase
price adjustments, and a net gain of $212 million. Estimated proved reserves associated with these assets were less
than 1% of total U.S. proved reserves. Devon’s remaining divestiture of Johnson County assets is expected to close
in 2018.
74
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
During 2016, in several separate transactions with different purchasers, Devon divested non-core assets
located in the Mississippian, east Texas, the Anadarko Basin and the Midland Basin. The following table presents a
summary of Devon’s divestiture activity for 2016.
Date
Proceeds Received
Gains on Sale
Second quarter 2016 $
Third quarter 2016
Total
$
200 $
1,653
1,853 $
83
726
809
Proved Reserves
(MMBoe)
Percentage of U.S.
Proved Reserves
11
146
157
1%
9%
10%
These divestitures in 2017 and 2016 primarily related to sales of entire common operating fields. Therefore,
Devon recognized a gain on the transactions. As part of the gain computations, approximately $290 million of asset
retirement obligations were assumed by purchasers and $80 million of goodwill was allocated to these divested
assets.
Access Pipeline
In October 2016, Devon divested its 50% interest in Access Pipeline for $1.1 billion ($1.4 billion Canadian
dollars) and recognized a gain of approximately $540 million on the transaction. In conjunction with the divestiture,
Devon entered into a transportation agreement whereby Devon’s Canadian thermal-oil acreage is dedicated to
Access Pipeline for an initial term of 25 years. Devon will be charged a market-based toll on its thermal-oil
production over this term. Devon is committed to use less than 90% of the potential pipeline capacity. In addition,
Devon is entitled to an incremental payment of approximately $150 million Canadian dollars following sanctioning
and committing to the requisite volume increase in respect of a new thermal-oil project on Devon’s Pike lease in
Alberta, with such incremental payment being received prior to tolls being payable on such volumes.
EnLink Acquisitions
In January 2016, EnLink acquired Anadarko Basin gathering and processing midstream assets, along with
dedicated acreage service rights and service contracts, for approximately $1.4 billion. The purchase price was $1.0
billion to intangible assets and approximately $400 million to property and equipment. EnLink funded the
acquisition with approximately $215 million of General Partner common units and approximately $800 million of
cash, primarily financed with the issuance of EnLink preferred units. The remaining $500 million of the purchase
price was to be paid within one year with the option to defer $250 million of the final payment 24 months from the
close date. The first installment payment of $250 million was paid in January 2017 using divestiture proceeds,
proceeds from equity issuances and borrowings under EnLink’s credit facility. The remaining $250 million payment
is reported in other current liabilities in the accompanying consolidated balance sheets and was made in January
2018 using proceeds from equity issuances and borrowings under EnLink’s credit facility.
In August 2016, EnLink formed a joint venture to operate and expand its midstream assets in the Delaware
Basin. The joint venture is initially owned 50.1% by EnLink and 49.9% by the joint venture partner. As of
December 31, 2016, EnLink contributed approximately $251 million of existing non-monetary assets and cash to the
joint venture and had committed an additional $285 million in capital to fund potential future development projects
and potential acquisitions. The joint venture partner committed an aggregate of approximately $400 million of
capital, including cash contributions of approximately $144 million, and granted EnLink call rights beginning in
2021 to acquire increasing portions of the joint venture partner’s interest.
In November 2016, EnLink entered into a gathering and compression joint venture with a commitment of
approximately $40 million to expand its midstream assets in the STACK. The joint venture is initially owned 30%
by EnLink and 70% by the joint venture partner. As of December 31, 2016, EnLink contributed approximately $29
million in cash for new infrastructure build. After the initial capital commitment, EnLink and the joint venture
partner will be responsible for their proportionate share of capital costs.
75
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The following table presents a summary of EnLink’s acquisition activity for 2015.
Purchase Price
Allocation
Date
Midstream assets
Cash
$
January 2015 Permian Basin
March 2015
$
Permian Basin
October 2015 Delaware Basin $
108
240
141
$
EnLink
Units
PP&E
— $
360 $
— $
30
302
36
Goodwill
$
$
$
30
18
11
Intangibles
43
$
281
$
99
$
$
$
$
Other
5
(1)
(5 ))
EnLink Asset Divestitures and Dropdowns
In December 2016, EnLink entered into definitive agreements to divest approximately $278 million of certain
non-core midstream assets. As of December 31, 2016, these assets were classified as held for sale. During the first
quarter of 2017, EnLink divested its ownership interest in Howard Energy Partners for approximately $190 million.
In February 2015, EnLink acquired a 25% equity interest in EMH from the General Partner in exchange for
units valued at approximately $925 million. In May 2015, EnLink acquired the remaining 25% equity interest in
EMH from the General Partner in exchange for units valued at approximately $900 million.
In April 2015, EnLink acquired VEX from Devon for approximately $176 million in cash and equity. EnLink
also assumed approximately $35 million in certain future construction costs to expand the system to full capacity.
Because Devon controls EnLink and the General Partner, the acquisition of VEX by EnLink from Devon was
accounted for as a transfer of net assets between entities under common control.
4.
Derivative Financial Instruments
Commodity Derivatives
As of December 31, 2017, Devon had the following open oil derivative positions. The first table presents
Devon’s oil derivatives that settle against the average of the prompt month NYMEX WTI futures price. The second
table presents Devon’s oil derivatives that settle against the respective indices noted within the table.
Period
Q1-Q4 2018
Q1-Q4 2019
Price Swaps
Weighted
Average
Price ($/Bbl)
Price Collars
Weighted
Average Floor
Price ($/Bbl)
Weighted
Average
Ceiling Price
($/Bbl)
Volume
(Bbls/d)
52.13 51,860 $
6,559 $
52.22
46.06 $
45.82 $
56.06
55.82
Volume
(Bbls/d)
49,625 $
7,307 $
Oil Basis Swaps
Volume
(Bbls/d)
Weighted Average
Differential to WTI
($/Bbl)
Volume
(Bbls/d)
Oil Basis Collars
Weighted
Average Floor
Differential to
WTI ($/Bbl)
Weighted
Average Ceiling
Differential to
WTI ($/Bbl)
Period
Q1-Q4 2018
Q1-Q4 2018
Q1-Q4 2018
Q1-Q4 2019
Index
Midland Sweet
Argus LLS
23,000 $
12,000 $
Western Canadian Select 75,490 $
27,000 $
Midland Sweet
(1.02)
3.95
(14.84)
(0.47)
— $
— $
1,830 $
— $
— $
— $
(15.50) $
— $
—
—
(13.93)
—
76
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
As of December 31, 2017, Devon had the following open natural gas derivative positions. The first table
presents Devon’s natural gas derivatives that settle against the Inside FERC first of the month Henry Hub index. The
second table presents Devon’s natural gas derivatives that settle against the respective indices noted within the table.
Period
Q1-Q4 2018
Q1-Q4 2019
Price Swaps
Volume
(MMBtu/d)
Weighted
Average Price
($/MMBtu)
371,956
28,466
$
$
3.06
2.98
Volume
(MMBtu/d)
197,516
28,466
Price Collars
Weighted
Average Floor
Price ($/MMBtu)
2.94
2.84
$
$
Weighted Average
Ceiling Price
($/MMBtu)
$
$
3.26
3.14
Period
Q1-Q4 2018
Index
Panhandle Eastern Pipe Line
Volume
(MMBtu/d)
50,000
Weighted Average
Differential to
Henry Hub
($/MMBtu)
$
(0.29 )
Natural Gas Basis Swaps
As of December 31, 2017, Devon had the following open NGL derivative positions. Devon’s NGL positions
settle against the average of the prompt month OPIS Mont Belvieu, Texas index.
Price Swaps
Period
Q1-Q4 2018
Q1-Q4 2018
Q1-Q4 2018
Q1-Q4 2018
Volume (Bbls/d)
Product
Ethane
Natural Gasoline
Normal Butane
Propane
Weighted Average
Price ($/Bbl)
6,747 $
5,500 $
6,750 $
9,500 $
11.89
54.24
38.46
33.19
As of December 31, 2017, EnLink had the following open derivative positions associated with gas processing
and fractionation. EnLink’s NGL positions settle by purity product against the average of the prompt month OPIS
Mont Belvieu, Texas index. EnLink’s natural gas positions settle against the Henry Hub Gas Daily index.
Period
Q1-Q4 2018
Q1 2018-Q1 2019
Product
Propane
Natural Gas
Volume (Total)
681
122,629
MBbls
MMBtu/d
Weighted
Average Price
Paid
Index
Index
Weighted
Average Price
Received
$0.88/gal
$2.57/MMBtu
Interest Rate Derivatives
As of December 31, 2017, Devon had the following open interest rate derivative positions:
$
$
Notional
750
100
Rate Received
Three Month LIBOR
1.76%
Rate Paid
2.98%
Three Month LIBOR
Expiration
December 2048 (1)
January 2019
(1) Mandatory settlement in December 2018.
77
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Financial Statement Presentation
The following table presents the net gains and losses by derivative financial instrument type followed by the
corresponding individual consolidated comprehensive statements of earnings caption.
Commodity derivatives:
Upstream revenues
Marketing and midstream revenues
Interest rate derivatives:
Other expenses
Foreign currency derivatives:
Other expenses
Net gains (losses) recognized
$
Year Ended December 31,
2017
2016
2015
$
157 $
(1)
(201) $
(13)
(22)
(19)
—
134 $
(153)
(386) $
503
9
(20)
246
738
The following table presents the derivative fair values by derivative financial instrument type followed by the
corresponding individual consolidated balance sheet caption.
Commodity derivative assets:
Other current assets
Other long-term assets
Interest rate derivative assets:
Other current assets
Total derivative assets
Commodity derivative liabilities:
Other current liabilities
Other long-term liabilities
Interest rate derivative liabilities:
Other current liabilities
Other long-term liabilities
Total derivative liabilities
December 31, 2017 December 31, 2016
$
$
$
$
209 $
2
1
212 $
267 $
27
64
—
358 $
9
1
1
11
187
16
—
41
244
5.
Share-Based Compensation
In the second quarter of 2017, Devon’s stockholders approved the 2017 Plan. The 2017 Plan replaces the 2015
Plan. From the effective date of the 2017 Plan, no further awards may be made under the 2015 Plan, and awards
previously granted will continue to be governed by the terms of the respective award documents. Subject to the
terms of the 2017 Plan, awards may be made for a total of 33.5 million shares of Devon common stock, plus the
number of shares available for issuance under the 2015 Plan (including shares subject to outstanding awards that
were transferred to the 2017 Plan in accordance with its terms). The 2017 Plan authorizes the Compensation
Committee, which consists of independent, non-management members of Devon’s Board of Directors, to grant
nonqualified and incentive stock options, restricted stock awards or units, Canadian restricted stock units,
performance units and stock appreciation rights to eligible employees. The 2017 Plan also authorizes the grant of
nonqualified stock options, restricted stock awards or units and stock appreciation rights to non-employee directors.
To calculate the number of shares that may be granted in awards under the 2017 Plan, options and stock appreciation
rights represent one share and other awards represent 2.3 shares.
78
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The vesting for certain share-based awards was accelerated in 2016 in conjunction with the reduction of
workforce described in Note 7. Approximately $60 million of associated expense for these accelerated awards is
included in other expenses in the accompanying consolidated comprehensive statements of earnings.
The table below presents the share-based compensation expense included in Devon’s accompanying
consolidated comprehensive statements of earnings.
G&A
Exploration expenses
Total Devon
G&A
Marketing and midstream expenses
Total EnLink
Total
Related income tax benefit
2017
Year Ended December 31,
2016
2015
$
$
$
141 $
7
148
37
11
48
196 $
6 $
124 $
6
130
24
7
31
161 $
6 $
185
9
194
31
5
36
230
67
The following table presents a summary of Devon’s unvested restricted stock awards and units, performance-
based restricted stock awards and performance share units granted under the plans.
Restricted Stock
Awards and Units
Performance-Based
Restricted Stock Awards
Performance
Share Units
Weighted
Average
Grant-Date
Fair Value
Awards and
Units
Awards
Weighted
Average
Grant-Date
Fair Value
Units
Weighted
Average
Grant-Date
Fair Value
(Thousands, except fair value data)
6,407 $
2,691 $
(2,431) $
(339) $
6,328 $
34.40
44.87
39.51
35.92
36.81
585 $
223 $
(233) $
— $
575 $
37.60
44.85
41.27
—
38.92
2,604 $
$
1,010
$
(832)
$
(24)
2,758 (1 ) $
46.66
52.58
78.19
40.70
41.21
Unvested at 12/31/16
Granted
Vested
Forfeited
Unvested at 12/31/17
(1) A maximum of 5.5 million common shares could be awarded based upon Devon’s final TSR ranking.
The following table presents the aggregate fair value of awards and units that vested during the indicated
period.
Restricted Stock Awards and Units
Performance-Based Restricted Stock Awards
Performance Share Units
2017
2016
2015
$
$
$
105 $
10 $
38 $
73 $
5 $
13 $
101
8
22
The following table presents the unrecognized compensation cost and the related weighted average
recognition period associated with unvested awards and units as of December 31, 2017.
Unrecognized compensation cost
Weighted average period for recognition (years)
Restricted Stock
Awards and Units
$
135 $
2.4
Performance-Based
Restricted Stock
Awards
Performance
Share Units
5 $
1.6
28
1.9
79
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Restricted Stock Awards and Units
Restricted stock awards and units are subject to the terms, conditions, restrictions and limitations, if any, that
the Compensation Committee deems appropriate, including restrictions on continued employment. Generally, the
service requirement for vesting ranges from one to four years. During the vesting period, recipients of restricted
stock awards made under the 2015 Plan or 2009 Plan receive dividends that are not subject to restrictions or other
limitations. However, dividends declared during the vesting period with respect to restricted stock awards made
under the 2017 Plan and all restricted stock units will not be paid until the underlying award vests. Devon estimates
the fair values of restricted stock awards and units as the closing price of Devon’s common stock on the grant date
of the award or unit, which is expensed over the applicable vesting period.
Performance-Based Restricted Stock Awards
Performance-based restricted stock awards are granted to certain members of Devon’s senior management.
Vesting of the awards is dependent on Devon meeting certain internal performance targets and the recipient meeting
certain service requirements. Generally, the service requirement for vesting ranges from one to four years. In order
for awards to vest, the performance target must be met in the first year. If the performance target is met, the recipient
is entitled to dividends under the same terms described above for nonperformance-based restricted stock. If the
performance target and service period requirements are not met, the award does not vest. Devon estimates the fair
values of the awards as the closing price of Devon’s common stock on the grant date of the award, which is
expensed over the applicable vesting period.
Performance Share Units
Performance share units are granted to certain members of Devon’s management and senior employees. Each
unit that vests entitles the recipient to one share of Devon common stock. The vesting of these units is based on
comparing Devon’s TSR to the TSR of a predetermined group of fourteen peer companies over the specified three-
year performance period. The vesting of units may be between zero and 200% of the units granted depending on
Devon’s TSR as compared to the peer group on the vesting date.
At the end of the vesting period, recipients receive dividend equivalents with respect to the number of units
vested. The fair value of each performance share unit 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 risk-free interest rate based
on U.S. Treasury rates as of the grant date; (ii) a volatility assumption based on the historical realized price volatility
of Devon and the designated peer group; and (iii) an estimated ranking of Devon among the designated peer group.
The fair value of the unit on the date of grant is expensed over the applicable vesting period. The following table
presents the assumptions related to performance share units granted.
Grant-date fair value
Risk-free interest rate
Volatility factor
Contractual term (years)
2017
$ 51.05 — $
1.50%
45.8%
2.89
53.12 $
9.24 — $ 10.61 $ 81.99 — $ 85.05
2016
2015
0.94%
37.7%
2.83
1.06%
26.2%
2.89
80
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Stock Options
In accordance with Devon’s incentive plans, the exercise price of stock options granted may not be less than
the market value of the stock at the date of grant. In addition, options granted are exercisable during a period
established for each grant, which may not exceed eight years from the date of grant. The recipient must pay the
exercise price in cash or in common stock, or a combination thereof, at the time that the option is exercised.
Generally, the service requirement for vesting ranges from one to four years. The fair value of stock options on the
date of grant is expensed over the applicable vesting period. No stock options were granted in 2017, 2016 and 2015.
The following table presents a summary of Devon’s outstanding stock options.
Outstanding at December 31, 2016
Expired
Outstanding at December 31, 2017
Exercisable at December 31, 2017
Weighted Average
Options
Exercise Price Remaining Term
(Thousands)
(Years)
Intrinsic
Value
2,532 $
(786) $
1,746 $
1,746 $
68.06
63.67
70.04
70.04
1.33 $
1.33 $
—
—
The aggregate intrinsic value of stock options that were exercised during 2015 was $0.2 million. As of
December 31, 2017, Devon had no unrecognized compensation cost related to unvested stock options.
EnLink Share-Based Awards
In March 2017, the General Partner and EnLink issued restricted incentive units as bonus payments to officers
and certain employees. The combined grant date fair value was $10 million, and the total cost was recognized in the
first quarter of 2017 due to the awards vesting immediately.
The following table presents a summary of the unrecognized compensation cost and the related weighted
average recognition period associated with the General Partner’s and EnLink’s unvested restricted incentive units
and performance units as of December 31, 2017.
General Partner
EnLink
Unrecognized compensation cost
Weighted average period for recognition (years)
Restricted
Incentive Units
$
11 $
1.7
Performance Restricted
Units
Incentive Units
Performance
Units
5 $
1.8
12 $
1.7
5
1.8
81
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
6.
Asset Impairments
The following table presents a summary of Devon’s asset impairments. Unproved impairments shown below
are included in exploration expenses in the consolidated comprehensive statements of earnings.
Proved oil and gas assets
EnLink goodwill
EnLink other intangible assets
Other assets
Total asset impairments
Unproved impairments
Proved Oil and Gas Impairments
2017
Year Ended December 31,
2016
2015
— $
—
—
17
17 $
435 $
873
—
2
1,310 $
16,076
1,328
223
20
17,647
217 $
77 $
260
$
$
$
In 2015 and 2016, Devon impaired a significant portion of its U.S. oil and gas portfolio due to lower
forecasted oil, gas and NGL prices.
EnLink Goodwill and Other Intangible Assets Impairments
In 2016 and 2015, Devon recognized goodwill and other intangible asset impairments related to EnLink’s
business. Additional information regarding the impairments is discussed in Note 14.
Unproved Impairments
In 2017, 2016 and 2015, Devon allowed certain non-core acreage to expire without plans for development
resulting in unproved impairments
7.
Other Expenses
The following table summarizes Devon’s other expenses presented in the accompanying consolidated
comprehensive statement of earnings.
Foreign exchange (gain) loss, net
Asset retirement obligation accretion
Restructuring and transaction costs
Other, net
Total
2017
Year Ended December 31,
2016
2015
$
$
(132) $
62
—
(54)
(124) $
39 $
75
267
(6)
375 $
25
75
78
86
264
82
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Certain of Devon’s non-Canadian foreign subsidiaries have a U.S. dollar functional currency, hold Canadian-
dollar cash and engage in intercompany loans with Canadian subsidiaries that are based in Canadian dollars. The
value of the Canadian-dollar cash and intercompany loans increases or decreases from the remeasurement of the
cash and loans into the U.S. dollar functional currency. During 2017, Devon recognized foreign exchange gains
related to these activities resulting from the weakening of the U.S. dollar in relation to the Canadian dollar.
Restructuring and Transaction Costs
The following table summarizes Devon’s restructuring liabilities presented in the accompanying consolidated
balance sheets.
Other
Current
Liabilities
Other
Long-term
Liabilities
Total
Balance as of December 31, 2015
Changes related to prior years' restructurings
Balance as of December 31, 2016
Changes related to prior years' restructurings
Balance as of December 31, 2017
$
$
$
13 $
35
48 $
(29)
19 $
63 $
(1)
62 $
(31)
31 $
76
34
110
(60)
50
Prior Years’ Restructurings
In 2016, Devon recognized $227 million in employee-related and other costs associated with a reduction in
workforce that was made in response to the depressed commodity price environment. Of these employee-related
costs, approximately $60 million resulted from accelerated vesting of share-based grants, which are noncash
charges. Additionally, approximately $24 million resulted from estimated defined benefit settlements.
As a result of the reduction of workforce, Devon ceased using certain office space that was subject to non-
cancellable operating lease arrangements. Devon recognized $23 million in restructuring costs that represent the
present value of its future obligations under the leases and impairment charges for leasehold improvements and
furniture associated with the office space it ceased using.
In 2015, Devon recognized $24 million of employee-related and other costs associated with the reduction in
workforce made subsequent to the completion of the Jackfish development projects and a decrease in planned
Canadian capital investment resulting from the drop in commodity prices.
As part of the U.S. corporate headquarters office consolidation, Devon recognized an additional $54 million
expense in 2015, due to the inability to fully sublease remaining office space.
Transaction Costs
In 2016, Devon and EnLink recognized $17 million in transaction costs primarily associated with the closing
of the acquisitions discussed in Note 3.
83
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
8.
Income Taxes
Income Tax Expense (Benefit)
The following table presents Devon’s income tax components.
Current income tax expense (benefit):
U.S. federal
Various states
Canada and various provinces
Total current tax expense (benefit)
Deferred income tax expense (benefit):
U.S. federal
Various states
Canada and various provinces
Total deferred tax expense (benefit)
Total income tax expense (benefit)
Year Ended December 31,
2016
2015
2017
$
$
10 $
—
102
112
(192)
(5)
(97)
(294)
(182) $
5 $
(11)
106
100
(3)
—
44
41
141 $
(243)
(8)
14
(237)
(5,487)
(332)
(157)
(5,976)
(6,213)
Total income tax expense (benefit) differed from the amounts computed by applying the U.S. federal income
tax rate to earnings before income taxes as a result of the following:
Total income tax expense (benefit)
U.S. statutory income tax rate
Non-deductible goodwill and intangible impairment
U.S. Tax Reform
Legal entity restructuring
Other
Deferred tax asset valuation allowance
Effective income tax rate
Year Ended December 31,
2017
2016
2015
$
(182)
$
141
$
(6,213)
35%
0%
8%
(81%)
(13%)
31%
(20%)
35%
(23%)
0%
6%
0%
(29%)
(11%)
35%
(3%)
0%
0%
1%
(2%)
31%
Devon and its subsidiaries are subject to U.S. federal income tax as well as income or capital taxes in various
state and foreign jurisdictions. Devon’s tax reserves are related to tax years that may be subject to examinations by
the relevant taxing authority. Devon is under audit in the U.S. and various foreign jurisdictions as part of its normal
course of business.
Devon assesses the realizability of its deferred tax assets. If Devon concludes that it is more likely than not
that some portion or all of the deferred tax assets will not be realized, the asset is reduced by a valuation allowance.
Numerous judgements and assumptions are inherent in the determination of future taxable income, including factors
such as future operating conditions (particularly as related to prevailing oil and gas prices) and changing tax laws.
84
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
2017
On December 22, 2017, the Tax Reform Legislation was enacted into law and contains several key tax
provisions that affect Devon, including a one-time mandatory transition tax on accumulated foreign earnings and a
reduction of the corporate income tax rate to 21% effective January 1, 2018, among others. Devon is required to
recognize the effect of the tax law changes in the period of enactment, such as determining the transition tax,
remeasuring U.S. deferred tax assets and liabilities and reassessing the net realizability of deferred tax assets and
liabilities.
In December 2017, the SEC staff issued Staff Accounting Bulletin No. 118, Income Tax Accounting
Implications of the Tax Cuts and Jobs Act (SAB 118), which allows Devon to record provisional amounts during a
measurement period not to extend beyond one year after the enactment date. As the Tax Reform Legislation was
passed late in the fourth quarter of 2017 and ongoing guidance and accounting interpretation are expected over the
next 12 months, Devon considers the accounting of the transition tax, deferred tax remeasurements, and other items
to be incomplete due to the forthcoming guidance and our ongoing analysis of final year-end data and tax positions.
Devon expects to complete its analysis within the measurement period in accordance with SAB 118. Provisional
amounts recorded this quarter are as follows:
(a) Devon’s U.S. segment recognized $167 million of deferred tax expense for the one-time mandatory
transition tax on accumulated foreign earnings.
(b) Devon’s U.S. segment recognized $108 million in deferred tax expense and EnLink recognized $211
million in deferred tax benefit related to the reduction of the U.S. corporate income tax rate to 21%.
In the fourth quarter of 2017, Devon’s Canadian segment generated nonrecurring capital losses from internal
legal entity restructuring. A deferred tax asset of $727 million was recognized related to the capital losses, offset by
a $641 million increase in the valuation allowance.
Throughout 2017, Devon continued to maintain a 100% valuation allowance against its U.S. deferred tax
assets resulting from prior year cumulative financial losses largely due to asset impairments and significant net
operating losses for U.S. federal and state income tax. Devon reduced its U.S. segment valuation allowance by $323
million in 2017 based primarily on the financial income recorded during the period. Furthermore, a partial allowance
continues to be held against certain Canadian segment deferred tax assets. The valuation allowances impacted the
effective tax rate and are discussed in the next section.
Also in the table above, the “other” effect is primarily composed of permanent differences for which dollar
amounts do not increase or decrease in relation to the change in pre-tax earnings. Generally, such items have an
insignificant impact on our effective income tax rate. However, these items have a more noticeable impact to our
rate in 2017 due to lower relative earnings during the period. During 2017, “other” is primarily related to the
taxation of other financing items.
2016
During 2016, Devon’s U.S. segment recognized an additional $313 million valuation allowance against its
deferred tax assets. The allowance results from continued financial losses in 2016. As of December 31, 2016, the
allowance continued to represent a 100% valuation against the U.S. net deferred tax assets. Additionally, the
Canadian segment recognized a $71 million partial valuation allowance resulting from continued financial losses.
In the first quarter of 2016, EnLink recognized a goodwill impairment of approximately $873 million.
Additionally, during the third quarter of 2016, Devon derecognized $83 million of goodwill related to its U.S.
operations in conjunction with the divestiture of certain non-core U.S. upstream oil and gas assets. These items are
not deductible for purposes of calculating income tax and, therefore, impact the effective tax rate.
85
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
2015
In the third and fourth quarters of 2015, EnLink recognized goodwill and intangibles impairments of
approximately $1.6 billion, which impacted the effective tax rate.
During 2015, Devon recognized approximately $16 billion of oil and gas impairments related to its U.S.
operations. These impairments resulted in deferred tax assets against which Devon recognized a $403 million
valuation allowance.
Deferred Tax Assets and Liabilities
The following table presents the tax effects of temporary differences that gave rise to Devon’s deferred tax
assets and liabilities.
Deferred tax assets:
Asset retirement obligations
Accrued liabilities
Net operating loss carryforwards
Pension benefit obligations
Canadian capital loss carryforwards
Other
Total deferred tax assets before valuation allowance
Less: valuation allowance
Net deferred tax assets
Deferred tax liabilities:
Property and equipment
Long-term debt
Other
Total deferred tax liabilities
Net deferred tax liability
December 31,
2017
2016
$
$
313
62
865
54
760
135
2,189
(968)
1,221
(1,703)
(92)
(261)
(2,056)
$
(835) $
488
130
777
98
17
186
1,696
(645)
1,051
(1,635)
(53)
(426)
(2,114)
(1,063)
At December 31, 2017, Devon has recognized $865 million of deferred tax assets related to various net
operating loss carryforwards available to offset future income taxes. The Canadian segment has $710 million of
noncapital loss carryforwards expiring between 2029 and 2037. Devon’s U.S. segment has $2.4 billion of U.S.
federal carryforwards expiring between 2036 and 2037 and $1.7 billion of U.S. state carryforwards expiring between
2018 and 2037. EnLink has $259 million of U.S. federal carryforwards expiring between 2034 and 2037 and $263
million of state carryforwards expiring between 2028 and 2037. In the current environment, Devon expects tax
benefits from the Canadian carryforwards to be utilized in 2018 and beyond and EnLink carryforwards to be utilized
in 2020 and beyond. Devon currently does not anticipate utilizing the U.S. federal or state net operating loss
carryforwards, as indicated by the full valuation allowance position in the U.S. segment.
As a result of the reduction in U.S. statutory income tax rate and favorable temporary differences, Devon
reduced its valuation allowance by $337 million against the U.S. deferred tax assets in 2017 and remains in a full
valuation allowance position. Also during 2017, Devon’s Canadian segment recognized a $660 million partial
valuation allowance against the deferred tax asset related to the Canadian capital loss carryforward due to projected
lack of future capital gain income. In the event Devon were to determine that it would be able to realize the deferred
income tax assets in the future, Devon would adjust the valuation allowance, reducing the provision for income
taxes in the period of such adjustment.
86
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
As of December 31, 2017, Devon’s unremitted foreign earnings from its international operations totaled
approximately $908 million. All of this amount was deemed to be indefinitely reinvested into the development and
growth of Devon’s Canadian business. Therefore, Devon has not recognized a deferred tax liability for U.S. income
taxes associated with such earnings. If such earnings were to be repatriated to the U.S., Devon may be subject to
U.S. income taxes and foreign withholding taxes. However, it is not practical to estimate the amount of such
additional taxes that may be payable due to the inter-relationship of the various factors involved in making such an
estimate.
Unrecognized Tax Benefits
The following table presents changes in Devon’s unrecognized tax benefits.
Balance at beginning of year
Tax positions taken in prior periods
Tax positions taken in current year
Accrual of interest related to tax positions taken
Settlements
Lapse of statute of limitations
Foreign currency translation
Balance at end of year
December 31,
2017
2016
$
$
$
202
(7)
(3)
16
(101)
—
8
115 $
131
36
—
39
—
(5)
1
202
Devon’s unrecognized tax benefit balance at December 31, 2017 and 2016 included $28 million and $68
million, respectively, of interest and penalties. If recognized, $115 million of Devon’s unrecognized tax benefits as
of December 31, 2017 would affect Devon’s effective income tax rate. During 2017, Devon removed $101 million
of unrecognized tax benefits, including $50 million of interest, as a result of the settlement of certain tax
examinations. Included below is a summary of the tax years, by jurisdiction, that remain subject to examination by
taxing authorities.
Jurisdiction
U.S. Federal
Various U.S. states
Canada Federal
Various Canadian provinces
Tax Years Open
2012-2017
2012-2017
2004-2017
2004-2017
Certain statute of limitation expirations are scheduled to occur in the next twelve months. However, Devon is
currently in various stages of the administrative review process for certain open tax years. In addition, Devon is
currently subject to various income tax audits that have not reached the administrative review process.
87
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
9.
Net Earnings (Loss) Per Share Attributable to Devon
The following table reconciles net earnings (loss) attributable to Devon and weighted-average common shares
outstanding used in the calculations of basic and diluted net earnings (loss) per share.
Net earnings (loss):
Net earnings (loss) attributable to Devon
Attributable to participating securities
Basic and diluted earnings (loss)
Common shares:
Common shares outstanding - total
Attributable to participating securities
Common shares outstanding - basic
Dilutive effect of potential common shares issuable
Common shares outstanding - diluted
Net earnings (loss) per share attributable to Devon:
Basic
Diluted
Antidilutive options (1)
$
$
$
$
2017
Year Ended December 31,
2016
2015
898 $
(10)
888 $
525
(5)
520
3
523
1.71 $
1.70 $
2
(1,056) $
(2)
(1,058) $
(12,896)
(5)
(12,901)
513
(6)
507
—
507
(2.09) $
(2.09) $
3
412
(5)
407
—
407
(31.72)
(31.72)
4
(1) Amounts represent options to purchase shares of Devon’s common stock that are excluded from the diluted
net earnings per share calculations because the options are antidilutive.
10. Other Comprehensive Earnings
Components of other comprehensive earnings consist of the following:
Foreign currency translation and other:
Beginning accumulated foreign currency translation and other
Change in cumulative translation adjustment and other
Income tax benefit (expense)
Ending accumulated foreign currency translation and other
$
Pension and postretirement benefit plans:
Beginning accumulated pension and postretirement benefits
Net actuarial loss and prior service cost arising in current year
Recognition of net actuarial loss and prior service cost in earnings (1)
Curtailment and settlement of pension benefits
Income tax expense
Ending accumulated pension and postretirement benefits
Accumulated other comprehensive earnings, net of tax
$
Year Ended December 31,
2016
2015
2017
1,226 $
113
(30)
1,309
(172)
10
19
—
—
(143)
1,166 $
1,215 $
22
(11)
1,226
(194)
(28)
26
24
—
(172)
1,054 $
1,658
(490)
47
1,215
(204)
(5)
21
—
(6)
(194)
1,021
(1)
These accumulated other comprehensive earnings components are included in the computation of net periodic
benefit cost, which is a component of G&A on the accompanying consolidated comprehensive statements of
earnings. See Note 18 for additional details.
88
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
11.
Supplemental Information to Statements of Cash Flows
Net change in working capital accounts,
net of assets and liabilities assumed:
Accounts receivable
Income taxes receivable
Other current assets
Accounts payable
Revenues and royalties payable
Other current liabilities
Net change in working capital
Interest paid (net of capitalized interest)
Income taxes paid (received)
Year Ended December 31,
2017
2016
2015
$
$
$
$
(284) $
8
(12)
105
257
(53)
21 $
481 $
78 $
(176) $
130
215
(167)
96
(74)
24 $
569 $
(159) $
942
384
(57)
(190)
(526)
(818)
(265)
497
(279)
In 2016, Devon’s acquisition of certain STACK assets included the noncash issuance of Devon common
stock. Further, in 2016, EnLink’s acquisition of Anadarko Basin gathering and processing midstream assets included
noncash issuance of General Partner common units. Additionally, EnLink’s formation of a joint venture during the
third quarter of 2016 included non-monetary asset contributions. See Note 3 for additional details.
In 2015, Devon’s acquisition of certain Powder River Basin assets included a noncash common stock issuance
totaling $199 million. EnLink’s acquisitions in 2015 also included $360 million of noncash equity.
12. Accounts Receivable
Components of accounts receivable include the following:
Oil, gas and NGL sales
Joint interest billings
Marketing and midstream revenues
Other
Gross accounts receivable
Allowance for doubtful accounts
Net accounts receivable
December 31, 2017 December 31, 2016
487
559 $
$
110
134
708
959
69
29
1,374
1,681
(18)
(11)
1,356
1,670 $
$
89
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
13.
Property, Plant and Equipment
Capitalized Costs
The following tables reflect the aggregate capitalized costs related to Devon’s oil and gas and non-oil and gas
activities.
Proved
Unproved and properties under development
Total oil and gas
Accumulated DD&A
Oil and gas property and equipment, net
Proved
Unproved and properties under development
Total oil and gas
Accumulated DD&A
Oil and gas property and equipment, net
$
$
$
$
December 31, 2017
U.S.
Canada
Total
40,491 $
984
41,475
(32,379)
9,096 $
6,804 $
1,473
8,277
(4,055)
4,222 $
47,295
2,457
49,752
(36,434)
13,318
December 31, 2016
U.S.
Canada
Total
38,842 $
2,115
40,957
(31,979)
8,978 $
6,163 $
1,277
7,440
(3,420)
4,020 $
December 31,
2017
2016
45,005
3,392
48,397
(35,399)
12,998
8,381
1,919
10,300
(2,124)
(641)
(2,765)
7,535
EnLink
Devon
Total midstream and other
EnLink
Devon
Total accumulated DD&A
$
Midstream and other property and equipment, net
$
9,120 $
1,955
11,075
(2,533)
(689)
(3,222)
7,853 $
Suspended Exploratory Well Costs
The following summarizes the changes in suspended exploratory well costs for the three years ended
December 31, 2017.
Beginning balance
Additions pending determination of proved reserves
Charges to exploration expense
Reclassifications to proved properties
Foreign currency translation adjustment
Ending balance
Year Ended December 31,
2016
2015
2017
$
$
261 $
504
—
(466)
14
313 $
225 $
247
(29)
(189)
7
261 $
199
348
(5)
(285)
(32)
225
90
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The following table provides an aging of capitalized well costs and the number of projects for which
exploratory well costs have been capitalized for a period greater than one year since the completion of drilling.
Exploratory well costs capitalized for a period of one year or less
Exploratory well costs capitalized for a period greater than one year
Ending balance
Number of projects with exploratory well costs capitalized for a
period greater than one year
Year Ended December 31,
2016
2015
2017
$
$
113 $
200
313 $
88 $
173
261 $
2
2
60
165
225
2
Projects with suspended exploratory well costs capitalized for a period greater than one year since the
completion of drilling relate to Devon’s heavy oil operations. Management believes these projects with suspended
exploratory well costs exhibit sufficient quantities of hydrocarbons to justify potential development. Devon
continues to assess the development timeline of these long cycle projects.
91
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
14.
Goodwill and Other Intangible Assets
Goodwill
The following table presents a summary of Devon’s goodwill. For the year ended December 31, 2017, there
were no changes to the carrying amount of goodwill.
Balance as of December 31, 2015
Acquired during period
Asset divestitures
Impairment
Balance as of December 31, 2016
U.S.
EnLink
Total
923 $
—
(83)
—
840 $
2,414 $
2
—
(873)
1,543 $
3,337
2
(83)
(873)
2,383
$
$
The following table presents the General Partner’s and EnLink’s goodwill activity by reporting unit. For the
year ended December 31, 2017, there were no changes to the carrying amount of goodwill.
Balance as of December 31, 2015
Acquired during period
Impairment
Balance as of December 31, 2016
Asset Divestitures
Texas
Oklahoma
Crude and
Condensate General Partner
Total
$
$
704 $
2
(473)
233 $
190 $
—
—
190 $
93 $
—
(93)
— $
1,427 $
—
(307)
1,120 $
2,414
2
(873)
1,543
In conjunction with the U.S. non-core upstream asset divestitures in 2016 discussed in Note 3, Devon
removed goodwill allocated to these assets.
Impairment
As further discussed in Note 1, Devon performs an annual impairment test of goodwill at October 31, or more
frequently if events or changes in circumstances indicate that the carrying value of a reporting unit may not be
recoverable. Sustained weakness in the overall energy sector driven by low commodity prices, together with a
decline in EnLink’s unit price, caused a change in circumstances warranting an interim impairment test of EnLink’s
reporting units in the first quarter of 2016. Based on that test, EnLink recorded noncash goodwill impairments
related to its Texas, Crude and Condensate and General Partner reporting units.
Additionally, during 2015, EnLink recorded noncash goodwill impairments related to its Texas, Louisiana and
Crude and Condensate reporting units.
92
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Other Intangible Assets
The following table presents other intangible assets reported in other long-term assets in the accompanying
consolidated balance sheets.
Customer relationships
Accumulated amortization
Net intangibles
December 31, 2017
December 31, 2016
$
$
1,796
$
(299)
$
1,497
1,796
(172)
1,624
The weighted-average amortization period for the customer relationships is 15 years. Amortization expense
for intangibles was approximately $127 million, $117 million and $56 million for the years ended 2017, 2016 and
2015, respectively. The remaining aggregate amortization expense is estimated to be approximately $123 million in
each of the next five years.
15. Other Current Liabilities
Components of other current liabilities include the following:
Derivative liabilities
Installment payment - see Note 3
Income taxes payable
Accrued interest payable
Restructuring liabilities
Other
Other current liabilities
December 31, 2017
$
331 $
250
145
131
19
325
1,201 $
December 31, 2016
187
249
32
130
48
420
1,066
$
93
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
16. Debt and Related Expenses
See below for a summary of debt instruments and balances. The notes and debentures are senior, unsecured
obligations of Devon.
Devon debt:
December 31, 2017 December 31, 2016
8.25% due July 1, 2018 (1)(2)
2.25% due December 15, 2018 (1)
6.30% due January 15, 2019 (1)
4.00% due July 15, 2021
3.25% due May 15, 2022
5.85% due December 15, 2025 (1)
7.50% due September 15, 2027 (1)(2)
7.875% due September 30, 2031 (1)(3)
7.95% due April 15, 2032 (1)
5.60% due July 15, 2041
4.75% due May 15, 2042
5.00% due June 15, 2045
Net discount on debentures and notes
Debt issuance costs
Total Devon debt
EnLink and General Partner debt:
Credit facilities
2.70% due April 1, 2019
7.125% due June 1, 2022
4.40% due April 1, 2024
4.15% due June 1, 2025
4.85% due July 15, 2026
5.60% due April 1, 2044
5.05% due April 1, 2045
5.45% due June 1, 2047
Net premium (discount) on debentures and notes
Debt issuance costs
Total EnLink and General Partner debt
Total debt
Less amount classified as short-term debt (4)
Total long-term debt
$
$
20 $
95
162
500
1,000
485
73
1,059
789
1,250
750
750
(30)
(39)
6,864
74
400
—
550
750
500
350
450
500
(6)
(26)
3,542
10,406
115
10,291 $
20
95
162
500
1,000
485
73
1,059
789
1,250
750
750
(30)
(44)
6,859
148
400
163
550
750
500
350
450
—
9
(25)
3,295
10,154
—
10,154
(1)
(2)
(3)
(4)
These senior notes were included in 2016 tender offer redemptions discussed below.
These instruments were assumed by Devon in April 2003 in conjunction with the merger with Ocean Energy.
The fair value and effective rates of these 8.25% notes and 7.50% notes at the time assumed was $147 million
and 5.5%, respectively, and $169 million and 6.5%, respectively. These instruments are the unsecured and
unsubordinated obligations of Devon OEI Operating, L.L.C. and are guaranteed by Devon Energy Production
Company, L.P. Each of these entities is a wholly-owned subsidiary of Devon.
Issued in October 2001, these are unsecured and unsubordinated obligations of Devon Financing, a wholly
owned finance subsidiary of Devon. These instruments are fully and unconditionally guaranteed by Devon.
2017 short-term debt consists of $20 million of 8.25% senior notes due July 1, 2018 and $95 million of 2.25%
senior notes due December 15, 2018.
94
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Debt maturities as of December 31, 2017, excluding debt issuance costs, premiums and discounts, are as
follows:
2018
2019
2020
2021
2022
Thereafter
Total
Credit Lines
Devon
EnLink
Total
$
$
115 $
162
—
500
1,000
5,156
6,933 $
— $
474
—
—
—
3,100
3,574 $
115
636
—
500
1,000
8,256
10,507
Devon has a $3.0 billion Senior Credit Facility. The facility matures as follows: $164 million on October 24,
2018 and the remaining $2.8 billion on October 24, 2019. Amounts borrowed under the Senior Credit Facility may,
at the election of Devon, bear interest at various fixed rate options for periods of up to twelve months. Such rates are
generally less than the prime rate. However, Devon may elect to borrow at the prime rate. The Senior Credit Facility
currently provides for an annual facility fee of $7.4 million. As of December 31, 2017, Devon had $59 million in
outstanding letters of credit under the Senior Credit Facility. There were no borrowings under the Senior Credit
Facility as of December 31, 2017.
The Senior Credit Facility contains only one material financial covenant. This covenant requires Devon’s ratio
of total funded debt to total capitalization, as defined in the credit agreement, to be no greater than 65%. The credit
agreement contains definitions of total funded debt and total capitalization that include adjustments to the respective
amounts reported in the accompanying consolidated financial statements. Also, total capitalization is adjusted to add
back noncash financial write-downs such as asset impairments. As of December 31, 2017, Devon was in compliance
with this covenant with a debt-to-capitalization ratio of 27.2%. Devon’s change to successful efforts did not
materially change this ratio.
Commercial Paper
Devon’s Senior Credit Facility supports its $3.0 billion of short-term credit under its commercial paper
program. Commercial paper debt generally has a maturity of between 1 and 90 days, although it can have a maturity
of up to 365 days, and bears interest at rates agreed to at the time of the borrowing. The interest rate is generally
based on a standard index such as the Federal Funds Rate, LIBOR or the money market rate as found in the
commercial paper market. As of December 31, 2017, Devon had no outstanding commercial paper borrowings.
Retirement of Senior Notes
During 2016, Devon completed tender offers to repurchase $2.1 billion of debt securities, using proceeds from
the asset divestitures discussed in Note 3. Devon recognized a loss on early retirement of debt, primarily consisting
of $265 million in cash retirement costs and other fees. These costs, along with other minimal noncash charges
associated with retiring the debt, are included in net financing costs in the consolidated comprehensive statements of
earnings.
EnLink Debt
All of EnLink’s and the General Partner’s debt is non-recourse to Devon.
95
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
EnLink has a $1.5 billion unsecured revolving credit facility that will mature on March 6, 2020. As of
December 31, 2017, there were $10 million in outstanding letters of credit and no outstanding borrowings under the
$1.5 billion credit facility. The General Partner has a $250 million revolving credit facility that will mature on
March 7, 2019. As of December 31, 2017, the General Partner had $74 million in outstanding borrowings under the
$250 million credit facility at a weighted average borrowing rate of 3.2%. EnLink and the General Partner were in
compliance with all financial covenants in their respective credit facilities as of December 31, 2017.
In the second quarter of 2017, EnLink issued $500 million of 5.45% unsecured senior notes due in 2047. The
proceeds were used to repay outstanding borrowings under its revolving credit facility and for general partnership
purposes. Additionally, in the second quarter of 2017, EnLink redeemed its $163 million 7.125% senior unsecured
notes due in 2022. EnLink redeemed the notes at 103.6% of the principal amount, plus accrued unpaid interest, for
aggregate cash consideration of $174 million, which resulted in a gain on extinguishment of debt of $9 million
during the second quarter of 2017. The gain is included in net financing costs in the consolidated comprehensive
statement of earnings.
In July 2016, EnLink issued $500 million of 4.85% unsecured senior notes due 2026. EnLink used the net
proceeds to repay outstanding borrowings under its revolving credit facility and for general partnership purposes.
Financing Costs, Net
The following schedule includes the components of net financing costs.
Devon net financing costs:
Interest based on debt outstanding
Early retirement of debt
Capitalized interest
Other
Total Devon net financing costs
EnLink net financing costs:
Interest based on debt outstanding
Interest accretion on deferred installment payment
Early retirement of debt
Other
Total EnLink net financing costs
Total net financing costs
2017
Year Ended December 31,
2016
2015
390 $
—
(69)
(4)
317
167
26
(9)
(3)
181
498 $
488 $
269
(61)
21
717
144
52
—
(6)
190
907 $
450
—
(52)
14
412
115
—
—
(8)
107
519
$
$
96
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
17. Asset Retirement Obligations
The following table presents the changes in asset retirement obligations.
Asset retirement obligations as of beginning of period
Liabilities incurred and assumed through acquisitions
Liabilities settled and divested
Revision of estimated obligation
Accretion expense on discounted obligation
Foreign currency translation adjustment
Asset retirement obligations as of end of period
Less current portion
Asset retirement obligations, long-term
Year Ended December 31,
2016
2017
$
$
1,272 $
40
(68)
(184)
62
30
1,152
39
1,113 $
1,414
27
(324)
66
75
14
1,272
46
1,226
During 2017, Devon reduced its asset retirement obligations by $184 million primarily due to changes in the
assumed inflation rate and retirement dates for its oil and gas assets.
During 2016, Devon reduced its asset retirement obligation by $287 million for those obligations that were
assumed by purchasers of certain upstream U.S. assets.
18. Retirement Plans
Defined Contribution Plans
Devon sponsors defined contribution plans covering its employees in the U.S. and Canada. Such plans include
its 401(k) plan, enhanced contribution plan and Canadian pension and savings plan. Contributions are primarily
based upon percentages of annual compensation and years of service. In addition, each plan is subject to regulatory
limitations by each respective government. Devon contributed $60 million, $64 million and $79 million to these
plans in 2017, 2016 and 2015, respectively.
Defined Benefit Plans
Devon has various non-contributory defined benefit pension plans, including qualified plans and nonqualified
plans covering eligible U.S. and Canadian employees and former employees meeting certain age and service
requirements. Benefits under the defined benefit plans have been closed to new employees since 2007; however,
eligible employees continue to accrue benefits based upon years of service and compensation. Benefits are primarily
funded from assets held in the plans’ trusts.
Devon’s investment objective for its plans’ assets is to achieve stability of the funded status while providing
long-term growth of invested capital and income to ensure benefit payments can be funded when required. Devon
has established certain investment strategies, including target allocation percentages and permitted and prohibited
investments, designed to mitigate risks inherent with investing. Devon’s target allocations for its plan assets are 70%
fixed income, 20% equity and 10% other. See the following discussion for Devon’s pension assets by asset class.
97
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Fixed-income – Devon’s fixed-income securities consist of U.S. Treasury obligations, bonds issued by
investment-grade companies from diverse industries and asset-backed securities. These fixed-income securities are
actively traded securities that can be redeemed upon demand. The fair values of these Level 1 securities are based
upon quoted market prices and were $342 million and $311 million at December 31, 2017 and 2016, respectively.
Also, included are commingled funds that primarily invest in long-term bonds and U.S. Treasury securities. These
fixed income securities can be redeemed on demand but are not actively traded. The fair values of these securities
are based upon the net asset values provided by the investment managers and were $401 million and $367 million at
December 31, 2017 and 2016, respectively.
Equity – Devon’s equity securities include a commingled global equity fund that invests in large, mid- and
small capitalization stocks across the world’s developed and emerging markets. These equity securities can be
redeemed on demand but are not actively traded. The fair values of these securities are based upon the net asset
values provided by the investment managers and were $157 million and $171 million at December 31, 2017 and
2016, respectively.
Other – Devon’s other securities include short-term investments funds, an actively traded global mutual fund
focusing on alternative investment strategies and a hedge fund that invests both long and short using a variety of
investment strategies. The fair value of these securities is based upon the net asset values provided by investment
managers and were $135 million and $136 million at December 31, 2017 and 2016, respectively.
Defined Postretirement Plans
Devon also has defined benefit postretirement plans that provide benefits for substantially all qualifying U.S.
retirees. The plans provide medical and in some cases, life insurance benefits and are either contributory or non-
contributory, depending on the type of plan. Benefit obligations for such plans are estimated based on Devon’s
future cost-sharing intentions. Devon’s funding policy for the plans is to fund the benefits as they become payable
with available cash and cash equivalents.
98
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Benefit Obligations and Funded Status
The following table summarizes the benefit obligations, assets, funded status and balance sheet impacts
associated with its defined pension and postretirement plans. Devon’s benefit obligations and plan assets are
measured each year as of December 31. The accumulated benefit obligation for pension plans approximated the
projected benefit obligation at December 31, 2017 and 2016.
Change in benefit obligation:
Benefit obligation at beginning of year
Service cost
Interest cost
Actuarial loss (gain)
Plan amendments
Plan curtailments
Plan settlements
Foreign exchange rate changes
Participant contributions
Benefits paid
Benefit obligation at end of year
Change in plan assets:
Fair value of plan assets at beginning of year
Actual return on plan assets
Employer contributions
Participant contributions
Plan settlements
Benefits paid
Foreign exchange rate changes
Fair value of plan assets at end of year
Funded status at end of year
Amounts recognized in balance sheet:
Other long-term assets
Other current liabilities
Other long-term liabilities
Net amount
Amounts recognized in accumulated other
comprehensive earnings:
Net actuarial loss (gain)
Prior service cost (credit)
Total
Pension Benefits
Postretirement Benefits
2017
2016
2017
2016
$
$
$
$
$
$
1,249 $
15
42
59
—
—
—
2
—
(88)
1,279
985
122
14
—
—
(88)
2
1,035
(244) $
1,308 $
15
42
63
2
(31)
(94)
1
—
(57)
1,249
1,059
61
16
—
(94)
(57)
—
985
(264) $
4 $
(13)
(235)
(244) $
3 $
(13)
(254)
(264) $
21 $
—
—
—
—
—
—
—
1
(3)
19
—
—
2
1
—
(3)
—
—
(19) $
— $
(3)
(16)
(19) $
257 $
6
263 $
285 $
8
293 $
(11) $
(3)
(14) $
23
—
1
(1)
—
—
—
—
—
(2)
21
—
—
2
—
—
(2)
—
—
(21)
—
(3)
(18)
(21)
(11)
(5)
(16)
Certain of Devon’s pension plans are unfunded and have a combined projected benefit obligation and
accumulated benefit obligation of $239 million and $225 million, respectively, at December 31, 2017 and $234
million and $211 million, respectively, at December 31, 2016.
99
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The following table presents the components of net periodic benefit cost and other comprehensive earnings.
Pension Benefits
2016
2017
Postretirement Benefits
2015
2017
2016
2015
Net periodic benefit cost:
Service cost
Interest cost
Expected return on plan assets
Recognition of net actuarial loss (gain) (1)
Recognition of prior service cost (1)
Total net periodic benefit cost (2)
Other comprehensive loss (earnings):
Actuarial loss (gain) arising in current year
Prior service cost (credit) arising in current year
Recognition of net actuarial loss, including
settlement
expense, in net periodic benefit cost (3)
Recognition of prior service cost, including
curtailment, in net periodic benefit cost (3)
Total other comprehensive loss (earnings)
Total recognized
$
15 $
42
(54)
19
2
24
(9)
—
15 $
42
(55)
25
3
30
1
33 $ — $ — $
1
1
52 —
(58) — — —
(1)
20
(2)
4
(1)
51
(1)
(1)
(2)
(1)
(1)
(1)
26
(1) —
2 — — —
5
(19)
(43)
(20)
1
1
(2)
(30)
(6) $
(9)
(24)
6 $
(4)
(19)
32 $
1
1
(1) $
1
2
1 $
$
(1)
1
1
1
2
1
These net periodic benefit costs were reclassified out of other comprehensive earnings in the current period.
(1)
(2) Net periodic benefit cost is a component of G&A on the accompanying consolidated comprehensive
(3)
statements of earnings.
These amounts include restructuring costs that were reclassified out of other comprehensive earnings in 2016.
See Note 7 for further discussion.
The estimated net actuarial loss and prior service cost for our pension and postretirement benefits that will be
amortized from accumulated other comprehensive earnings into net periodic benefit cost during 2018 are $14
million and $1 million, respectively.
Assumptions
Assumptions to determine benefit obligations:
Discount rate
Rate of compensation increase
Assumptions to determine net periodic benefit cost:
Pension Benefits
Postretirement Benefits
2017
2016
2015
2017
2016
2015
3.59% 4.07% 4.25% 3.25% 3.46% 3.63%
2.50% 4.49% 4.49% N/A N/A N/A
Discount rate
Rate of compensation increase
Expected return on plan assets
4.08% 4.39% 3.90% 3.46% 3.63% 3.25%
4.48% 4.49% 4.49% N/A N/A N/A
5.69% 5.20% 5.22% N/A N/A N/A
Discount Rate - Future pension and post-retirement obligations are discounted based on the rate at which
obligations could be effectively settled, considering the timing of expected future cash flows related to the plans.
This rate is based on high-quality bond yields, after allowing for call and default risk.
Expected return on plan assets – This was determined by evaluating input from external consultants and
economists, as well as long-term inflation assumptions and consideration of target allocation of investment types.
100
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Mortality rate – Devon utilized the Society of Actuaries produced mortality tables and an improvement scale
derived from the updated tables and the actuary’s best estimate of mortality for the population of participants in
Devon’s plans.
Other assumptions – For measurement of the 2017 benefit obligation for the other postretirement medical
plans, a 7.3% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2018.
The rate was assumed to decrease annually to an ultimate rate of 5% in the year 2029 and remain at that level
thereafter. A one percentage point change in assumed health care cost trend rates would not have a material impact
on periodic benefit cost or benefit obligations.
Expected Cash Flows
Devon expects benefit plan payments to average approximately $76 million a year for the next five years and
$406 million total for the five years thereafter. Of these payments to be paid in 2018, $3 million is expected to be
funded from Devon’s available cash and cash equivalents.
19.
Stockholders’ Equity
The authorized capital stock of Devon consists of 1.0 billion shares of common stock, par value $0.10 per
share, and 4.5 million shares of preferred stock, par value $1.00 per share. The preferred stock may be issued in one
or more series, and the terms and rights of such stock will be determined by the Board of Directors.
Common Stock Issued
In January 2016, Devon issued approximately 23 million shares of common stock in conjunction with the
STACK asset acquisition discussed in Note 3. Additionally, in February 2016, Devon issued 79 million shares of
common stock to the public, inclusive of 10 million shares sold as part of the underwriters’ option. Net proceeds
from the offering were $1.5 billion.
In December 2015, Devon issued approximately 7 million shares of common stock as part of the Powder
River Basin asset acquisition discussed in Note 3.
Dividends
Devon paid common stock dividends of $127 million, $221 million and $396 million during 2017, 2016 and
2015, respectively. In response to the depressed commodity price environment, Devon reduced the quarterly
dividend rate from $0.24 to $0.06 per share in the second quarter of 2016.
20. Noncontrolling Interests
Subsidiary Equity Transactions
EnLink has the ability to sell common units through its “at the market” equity offering programs. In the third
quarter of 2017, EnLink entered into additional equity distribution agreements to sell up to $600 million in common
units through its programs. Future common units that EnLink issues will be issued under the new equity distribution
agreement. During 2017, 2016 and 2015, EnLink issued and sold approximately 6.2 million, 10.0 million and 1.3
million common units through its “at the market” program and general public offerings, generating net proceeds of
$107 million, $167 million and $25 million, respectively. During the first quarter of 2016, the General Partner issued
common units in conjunction with the Anadarko Basin assets acquisition discussed in Note 3.
101
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
In October 2015, EnLink issued approximately 2.8 million common units in a private placement transaction
with the General Partner, generating approximately $50 million in proceeds. In 2015, Devon conducted an
underwritten secondary public offering of 26.2 million common units representing limited partner interests in
EnLink, raising net proceeds of $654 million.
In September 2017, EnLink issued 400,000 preferred units through an underwritten public offering for net
proceeds of approximately $394 million. As a result of these transactions and EnLink’s acquisition and dropdown
activity discussed further in Note 3, the table below shows the ownership interest activity in the General Partner and
EnLink for the last three years.
Ownership interest as of
December 31, 2015
December 31, 2016
December 31, 2017
Devon
28%
24%
23%
Distributions to Noncontrolling Interests
EnLink
Non-Devon
Unitholders
45%
53%
55%
General
Partner
27%
23%
22%
General Partner
Devon
70%
64%
64%
Non-Devon
Unitholders
30%
36%
36%
EnLink and the General Partner distributed $354 million, $304 million and $254 million to non-Devon
unitholders during 2017, 2016 and 2015, respectively.
21. Commitments and Contingencies
Devon is party to various legal actions arising in the normal course of business. Matters that are probable of
unfavorable outcome to Devon and which can be reasonably estimated are accrued. Such accruals are based on
information known about the matters, Devon’s estimates of the outcomes of such matters and its experience in
contesting, litigating and settling similar matters. None of the actions are believed by management to involve future
amounts that would be material to Devon’s financial position or results of operations after consideration of recorded
accruals. Actual amounts could differ materially from management’s estimates.
Royalty Matters
Numerous oil and gas producers and related parties, including Devon, have been named in various lawsuits
alleging royalty underpayments. These suits typically assert various allegations, including that the producers and
related parties used below-market prices, made improper deductions, used improper measurement techniques and
entered into gas purchase and processing arrangements with affiliates that resulted in the underpayment of royalties
in connection with oil, natural gas and NGLs produced and sold. Devon is also involved in governmental agency
proceedings and audits and is subject to related contracts and regulatory controls in the ordinary course of business,
some that may lead to additional royalty claims. Devon does not currently believe that it is subject to material
exposure with respect to such royalty matters.
Environmental Matters
Devon is subject to certain laws and regulations relating to environmental remediation activities associated
with past operations, such as the Comprehensive Environmental Response, Compensation, and Liability Act and
similar state statutes. In response to liabilities associated with these activities, loss accruals primarily consist of
estimated uninsured remediation costs. Devon’s monetary exposure for environmental matters is not expected to be
material.
102
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Other Matters
Devon is involved in other various legal proceedings incidental to its business. However, to Devon’s
knowledge, there were no material pending legal proceedings to which Devon is a party or to which any of its
property is subject.
Commitments
The following table presents Devon’s commitments that have initial or remaining noncancelable terms in
excess of one year as of December 31, 2017.
Year Ending December 31,
Purchase
Obligations
Drilling and
Facility
Obligations
Operational
Agreements
Office and
Equipment
Leases
EnLink
Obligations
2018
2019
2020
2021
2022
Thereafter
Total
$
$
613 $
577
556
134
—
—
1,880 $
216 $
109
109
51
38
106
629 $
1,159 $
562
466
366
373
3,242
6,168 $
88 $
84
73
61
56
19
381 $
53
36
19
18
17
90
233
Purchase obligation amounts represent contractual commitments primarily to purchase condensate at market
prices for use at Devon’s heavy oil projects in Canada. Devon has entered into these agreements because condensate
is an integral part of the heavy oil transportation process. Any disruption in Devon’s ability to obtain condensate
could negatively affect its ability to transport heavy oil at these locations. Devon’s total obligation related to
condensate purchases expires in 2021. The value of the obligation in the table above is based on the contractual
volumes and Devon’s internal estimate of future condensate market prices.
Devon has certain drilling and facility obligations under contractual agreements with third-party service
providers to procure drilling rigs and other related services for developmental and exploratory drilling and facilities
construction. The value of the drilling obligations reported is based on gross contractual value.
Devon has certain operational agreements whereby Devon has committed to transport or process certain
volumes of oil, gas and NGLs for a fixed fee. Devon has entered into these agreements to aid the movement of its
production to downstream markets.
Devon leases certain office space and equipment under operating lease arrangements. Total rental expense
recognized for operating leases, net of sublease income, was $67 million, $78 million and $88 million in 2017, 2016
and 2015, respectively.
103
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
22. Fair Value Measurements
The following table provides carrying value and fair value measurement information for certain of Devon’s
financial assets and liabilities. None of the items below are measured using Level 3 inputs. The carrying values of
cash, accounts receivable, other current receivables, accounts payable, other current payables and accrued expenses
included in the accompanying consolidated balance sheets approximated fair value at December 31, 2017 and
December 31, 2016, as applicable. Therefore, such financial assets and liabilities are not presented in the following
table. Additionally, the fair values of oil and gas assets, goodwill and other intangible assets and related impairments
are measured as of the impairment date using Level 3 inputs. More information on these items and the pension plan
assets is provided in Note 6, Note 14 and Note 18, respectively.
December 31, 2017 assets (liabilities):
Cash equivalents
Commodity derivatives
Commodity derivatives
Interest rate derivatives
Interest rate derivatives
Debt
Installment payment
Capital lease obligations
December 31, 2016 assets (liabilities):
Cash equivalents
Commodity derivatives
Commodity derivatives
Interest rate derivatives
Interest rate derivatives
Debt
Installment payment
Capital lease obligations
Fair Value
Measurements Using:
Carrying
Amount
Total Fair
Value
Level 1
Inputs
Level 2
Inputs
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
1,533
211
$
(294) $
1
$
(64) $
(10,406) $
(250) $
(4) $
$
1,533
211
$
(294) $
$
1
(64) $
(11,782) $
(250) $
(3) $
$
1,542
10
$
(203) $
1
$
(41) $
(10,154) $
(473) $
(7) $
$
1,542
10
$
(203) $
$
1
(41) $
(10,760) $
(477) $
(6) $
1,454
—
—
—
—
—
—
—
1,298
—
—
—
—
—
—
—
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
79
211
(294)
1
(64)
(11,782)
(250)
(3)
244
10
(203)
1
(41)
(10,760)
(477)
(6)
The following methods and assumptions were used to estimate the fair values in the tables above.
Level 1 Fair Value Measurements
Cash equivalents – Amounts consist primarily of U.S. and Canadian treasury securities and money market
investments. The fair value approximates the carrying value.
Level 2 Fair Value Measurements
Cash equivalents – Amounts consist primarily of commercial paper and Canadian agency and provincial
securities investments. The fair value approximates the carrying value.
Commodity and interest rate derivatives– The fair values of commodity and interest rate derivatives are
estimated using internal discounted cash flow calculations based upon forward curves and data obtained from
independent third parties for contracts with similar terms or data obtained from counterparties to the agreements.
104
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Debt – Devon’s debt instruments do not actively trade in an established market. The fair values of its debt are
estimated based on rates available for debt with similar terms and maturity. The fair values of commercial paper and
credit facility balances are the carrying values.
Installment payment – The fair value of the EnLink installment payment was based on Level 2 inputs from
third-party market quotations.
Capital lease obligations – The fair value was calculated using inputs from third-party banks.
23.
Segment Information
Devon manages its operations through distinct operating segments, which are defined primarily by geographic
areas. For financial reporting purposes, Devon aggregates its U.S. operating segments into one reporting segment
due to the similar nature of the businesses. However, Devon’s Canadian exploration and production operating
segment is reported as a separate reporting segment primarily due to the significant differences between the U.S. and
Canadian regulatory environments. Devon’s U.S. and Canadian segments are both primarily engaged in oil and gas
exploration and production activities, and certain information regarding such activities for each segment is included
in Note 24.
Devon considers EnLink, combined with the General Partner, to be an operating segment that is distinct from
the U.S. and Canadian operating segments. EnLink’s operations consist of midstream assets and operations located
across the U.S. Additionally, EnLink has a management team that is primarily responsible for capital and resource
allocation decisions. Therefore, EnLink is presented as a separate reporting segment.
105
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
U.S. (1)
Canada
EnLink (1) Eliminations
Total
Year Ended December 31, 2017:
Revenues from external customers
Intersegment revenues
Depreciation, depletion and amortization
Asset impairments
Asset dispositions
Interest expense
Earnings before income taxes
Income tax expense (benefit)
Net earnings
Net earnings attributable to noncontrolling interests
Net earnings attributable to Devon
Property and equipment, net
Total assets
Capital expenditures, including acquisitions
Year Ended December 31, 2016:
Revenues from external customers
Intersegment revenues
Depreciation, depletion and amortization
Asset impairments
Asset dispositions
Restructuring and transaction costs
Interest expense
Earnings (loss) before income taxes
Income tax expense (benefit)
Net earnings (loss)
Net earnings (loss) attributable to noncontrolling interests
Net earnings (loss) attributable to Devon
Property and equipment, net
Total assets
Capital expenditures, including acquisitions
Year Ended December 31, 2015:
Revenues from external customers
Intersegment revenues
Depreciation, depletion and amortization
Asset impairments
Asset dispositions
Restructuring and transaction costs
Interest expense
Loss before income taxes
Income tax expense (benefit)
Net loss
Net earnings (loss) attributable to noncontrolling interests
Net loss attributable to Devon
Property and equipment, net
Total assets
Capital expenditures, including acquisitions
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
7,326 $
— $
1,149 $
— $
(218) $
324 $
500 $
9 $
491 $
— $
491 $
10,274 $
14,254 $
1,821 $
5,722 $
— $
1,178 $
435 $
(955) $
242 $
624 $
(673) $
(8) $
(665) $
1 $
(666) $
10,166 $
13,390 $
2,640 $
8,360 $
— $
3,164 $
16,069 $
(33) $
54 $
368 $
(17,898) $
(6,100) $
(11,798) $
1 $
(11,799) $
10,357 $
14,399 $
4,143 $
1,552 $
— $
380 $
— $
1 $
69 $
273 $
6 $
267 $
— $
267 $
4,310 $
5,498 $
348 $
1,031 $
— $
414 $
2 $
(541) $
19 $
184 $
240 $
149 $
91 $
— $
91 $
4,110 $
5,071 $
186 $
1,012 $
— $
471 $
15 $
39 $
24 $
97 $
(576) $
(143) $
(433) $
— $
(433) $
4,962 $
5,830 $
591 $
5,071 $
669 $
545 $
17 $
— $
181 $
123 $
(197) $
320 $
180 $
140 $
6,587 $
10,538 $
768 $
3,551 $
701 $
504 $
873 $
13 $
6 $
190 $
(884) $
— $
(884) $
(403) $
(481) $
6,257 $
10,276 $
1,082 $
3,773 $
679 $
387 $
1,563 $
1 $
— $
107 $
(1,384) $
30 $
(1,414) $
(750) $
(664) $
5,667 $
9,541 $
978 $
— $
(669) $
— $
— $
— $
(57) $
— $
— $
— $
— $
— $
— $
(49) $
— $
— $
(701) $
— $
— $
— $
— $
(84) $
— $
— $
— $
— $
— $
— $
(62) $
— $
— $
(679) $
— $
— $
— $
— $
(46) $
— $
— $
— $
— $
— $
— $
(97) $
— $
13,949
—
2,074
17
(217)
517
896
(182)
1,078
180
898
21,171
30,241
2,937
10,304
—
2,096
1,310
(1,483)
267
914
(1,317)
141
(1,458)
(402)
(1,056)
20,533
28,675
3,908
13,145
—
4,022
17,647
7
78
526
(19,858)
(6,213)
(13,645)
(749)
(12,896)
20,986
29,673
5,712
(1) Due to Devon’s control of EnLink through its control of the General Partner, the acquisition of VEX by EnLink from Devon in
the second quarter of 2015 was considered a transfer of net assets between entities under common control, and EnLink was
required to recast its financial statements as of December 31, 2015 to include the activities of such assets from the date of
common control. Therefore, the results of VEX have been moved from the U.S. segment to the EnLink segment for the recast
period.
106
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
24.
Supplemental Information on Oil and Gas Operations (Unaudited)
Supplemental unaudited information regarding Devon’s oil and gas activities is presented in this note. The
information is provided separately by country.
Included in this note are disclosures of Devon’s results of operations for oil and gas producing activities and
standardized measure of discounted future net cash flows relating to proved oil and gas reserve quantities. In
conjunction with Devon’s oil and gas accounting policy change discussed in Note 1, Devon also modified its
treatment of certain “production support” costs in these two disclosures. Production support costs consisted of labor,
supervision, materials and supplies for oil and gas production monitoring and support activities, including
information technology, accounting and certain other administrative support functions. These costs are included in
G&A expenses in the accompanying consolidated comprehensive statements of earnings. Devon used a method to
allocate these costs to its country-based results of operations and standardized measure disclosures. In 2016 and
2015, Devon’s results of operations disclosures included production support costs of $168 million and $224 million,
respectively, and its standardized measure disclosures included estimated future production support costs of $2.8
billion and $2.7 billion, respectively.
Devon’s 2016 and 2015 disclosures have been revised to exclude these amounts.
Based on research conducted by Devon, diversity of practice has existed across peer companies regarding the
treatment of production support costs in results of operations and standardized measure disclosures. Devon’s
research of public filings indicates most companies exclude such costs from results of operations and standardized
measure disclosures, but some companies appear to include such costs in their disclosures. Considering the apparent
diversity of practice, Devon is making this disclosure change for two primary reasons. First, by converting to the
successful efforts method of accounting and making this disclosure change, Devon’s results of operations and
standardized measure disclosures will be most comparable to the vast majority of its peers. Second, allocating these
costs to more granular common operating fields as opposed to country-based full cost pools is cost prohibitive and
not materially important to investors and stakeholders, considering such allocated costs represented approximately
4% of Devon’s 2016 and 2015 oil, gas and NGL sales.
107
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Costs Incurred
The following tables reflect the costs incurred in oil and gas property acquisition, exploration and
development activities.
Property acquisition costs:
Proved properties
Unproved properties
Exploration costs
Development costs
Costs incurred
Property acquisition costs:
Proved properties
Unproved properties
Exploration costs
Development costs
Costs incurred
Property acquisition costs:
Proved properties
Unproved properties
Exploration costs
Development costs
Costs incurred
Year Ended December 31, 2017
U.S.
Canada
Total
2 $
50
590
1,036
1,678 $
— $
4
87
225
316 $
2
54
677
1,261
1,994
Year Ended December 31, 2016
U.S.
Canada
Total
237 $
1,356
282
875
2,750 $
— $
2
78
54
134 $
237
1,358
360
929
2,884
Year Ended December 31, 2015
U.S.
Canada
Total
193 $
635
432
2,982
4,242 $
2 $
81
120
351
554 $
195
716
552
3,333
4,796
$
$
$
$
$
$
Development costs in the tables above include additions and revisions to Devon’s asset retirement obligations.
Additionally, Devon capitalizes interest costs incurred and attributable to unproved oil and gas properties and major
development projects of oil and gas properties. Capitalized interest expenses, which are included in the costs shown
in the preceding tables, were $69 million, $61 million and $52 million in 2017, 2016 and 2015, respectively.
108
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Results of Operations
The following tables include revenues and expenses associated with Devon’s oil and gas producing activities.
They do not include any allocation of Devon’s interest costs or general corporate overhead and, therefore, are not
necessarily indicative of the contribution to net earnings of Devon’s oil and gas operations. Income tax expense has
been calculated by applying statutory income tax rates to oil, gas and NGL sales after deducting costs, including
DD&A and after giving effect to permanent differences.
Oil, gas and NGL sales
Production expenses
Exploration expenses
Depreciation, depletion and amortization
Asset dispositions
Accretion of asset retirement obligations
Income tax expense
Results of operations
Depreciation, depletion and amortization per Boe
Oil, gas and NGL sales
Production expenses
Exploration expenses
Depreciation, depletion and amortization
Asset dispositions
Asset impairments
Accretion of asset retirement obligations
Income tax expense
Results of operations
Depreciation, depletion and amortization per Boe
Oil, gas and NGL sales
Production expenses
Exploration expenses
Depreciation, depletion and amortization
Asset dispositions
Asset impairments
Accretion of asset retirement obligations
Income tax benefit
Results of operations
Depreciation, depletion and amortization per Boe
December 31, 2017
U.S.
Canada
Total
3,746
$
(1,232)
(346)
(1,050)
211
(38)
—
1,291 $
6.97 $
1,404
$
(591)
(34)
(369)
1
(24)
(104)
283 $
7.73 $
5,150
(1,823)
(380)
(1,419)
212
(62)
(104)
1,574
7.15
December 31, 2016
U.S.
Canada
Total
3,198
$
(1,311)
(176)
(1,066)
946
(435)
(49)
—
1,107 $
6.11 $
984
$
(492)
(39)
(380)
1
—
(26)
(13)
35 $
7.75 $
4,182
(1,803)
(215)
(1,446)
947
(435)
(75)
(13)
1,142
6.47
December 31, 2015
U.S.
Canada
Total
$
4,356
(1,853)
(323)
(3,051)
32
(16,061)
(47)
5,783
(11,164) $
14.79 $
$
1,026
(586)
(128)
(423)
(39)
(15)
(28)
50
(143) $
10.08 $
5,382
(2,439)
(451)
(3,474)
(7)
(16,076)
(75)
5,833
(11,307)
13.99
$
$
$
$
$
$
$
$
$
109
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Proved Reserves
The following table presents Devon’s estimated proved reserves by product and by country.
Oil (MMBbls)
Bitumen
(MMBbls)
U.S. Canada Total Canada U.S.
Gas (Bcf)
Canada Total
NGL
(MMBbls) Combined (MMBoe) (1)
U.S.
Canada Total
U.S.
Proved developed and undeveloped
reserves:
December 31, 2014
Revisions due to prices
Revisions other than price
Extensions and discoveries
Purchase of reserves
Production
Sale of reserves
December 31, 2015
Revisions due to prices
Revisions other than price
Extensions and discoveries
Purchase of reserves
Production
Sale of reserves
December 31, 2016
Revisions due to prices
Revisions other than price
Extensions and discoveries
Production
Sale of reserves
December 31, 2017
Proved developed reserves:
December 31, 2014
December 31, 2015
December 31, 2016
December 31, 2017
Proved developed-producing reserves:
December 31, 2014
December 31, 2015
December 31, 2016
December 31, 2017
Proved undeveloped reserves:
December 31, 2014
December 31, 2015
December 31, 2016
December 31, 2017
5 —
351
(53)
(52)
51
23 374
4 (49)
2 (50)
3 54
5
(60)
(10) (70)
— — —
22 264
242
(2) (20)
(18)
1
3
(2)
2 38
36
8
(47)
(8) (55)
(25) — (25)
17 211
194
(1) 11
12
2
8
6
4 94
90
(7) (49)
(42)
(3)
15 272
(3) —
8 —
257
(579)
521 7,651
103 (1,412)
(84)
(3)
11
—
(31)
—
520 5,808
23
(19)
—
—
(40)
—
484 5,615
(37)
398
(10) —
12
(40)
—
409 5,974
36 7,687
(9) (1,421)
(9)
(6)
171
171 —
17
17 —
(587)
(8)
(37)
(37) —
13 5,821
(103)
638
280
33
(517)
(521)
16 5,631
399
1
2
2
403
403 —
(439)
(6)
(433)
(9)
(9) —
13 5,987
(103) —
10
628
280 —
33 —
(510)
(7)
(521) —
9 —
(7) —
578 2,205
(119) (408)
(6)
(59)
24 104
1
(50) (206)
—
428 1,638
(13)
(48)
48 151
42 124
7
549 2,754
106 (302)
(83) (142)
14 118
9
(42) (248)
(7)
544 2,182
21
(27)
(14) 137
2 126
20
(42) (174)
(49) (223)
(45) (157) — (157)
504 2,058
425 1,554
73
(38)
32 111
(7)
(10)
(12)
(5)
16 237
63 221
(48) (198)
(36) (150)
(6)
427 2,152
473 1,725
20 —
(6) —
(1)
255
203
160
178
224
192
143
165
23 278
22 225
17 177
15 193
19 243
19 211
13 156
12 177
137 6,948
219 5,694
190 5,361
200 5,619
36 6,984
13 5,707
16 5,377
13 5,632
486 1,900
411 1,563
387 1,439
410 1,524
165 2,065
243 1,806
210 1,649
218 1,742
137 6,746
219 5,546
190 5,243
197 5,512
34 6,780
13 5,559
16 5,259
13 5,525
467 1,815
393 1,509
370 1,386
397 1,481
162 1,977
240 1,749
207 1,593
212 1,693
96 — 96
39 — 39
34 — 34
79 — 79
384
301
294
209
703 —
114 —
254 —
355 —
703
114
254
355
92 305
75
17
38 115
63 201
384 689
301 376
294 409
209 410
(1) Gas reserves are converted to Boe at the rate of six Mcf per Bbl of oil, based upon the approximate relative
energy content of gas and oil. This rate is not necessarily indicative of the relationship of natural gas and oil
prices. Bitumen and NGL reserves are converted to Boe on a one-to-one basis with oil.
110
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Proved Undeveloped Reserves
The following table presents the changes in Devon’s total proved undeveloped reserves during 2017
(MMBoe).
Proved undeveloped reserves as of December 31, 2016
Extensions and discoveries
Revisions due to prices
Revisions other than price
Conversion to proved developed reserves
Proved undeveloped reserves as of December 31, 2017
U.S.
Canada
Total
115
116
—
(21)
(9)
201
294
12
(27)
(6)
(64)
209
409
128
(27)
(27)
(73)
410
Total proved undeveloped reserves remained consistent from 2016 to 2017 with the year-end 2017 balance
representing 19% of total proved reserves. Devon’s focus on drilling and development activities in the STACK and
Delaware Basin was the primary driver of the 128 MMBoe increase in extensions and discoveries. Continued
development primarily at Jackfish led to the conversion of 73 MMBoe, or 18%, of the 2016 proved undeveloped
reserves to proved developed reserves. Costs incurred to develop and convert Devon’s proved undeveloped reserves
were approximately $237 million for 2017.
A significant amount of Devon’s proved undeveloped reserves at the end of 2017 related to its Jackfish
operations. At December 31, 2017 and 2016, Devon’s Jackfish proved undeveloped reserves were 209 MMBoe and
294 MMBoe, respectively. Development schedules for the Jackfish reserves are primarily controlled by the need to
keep the processing plants at their 35 MBbl daily facility capacity. Processing plant capacity is controlled by factors
such as total steam processing capacity and steam-oil ratios. Furthermore, development of these projects involves
the up-front construction of steam injection/distribution and bitumen processing facilities. Due to the large up-front
capital investments and large reserves required to provide economic returns, the project conditions meet the specific
circumstances requiring a period greater than five years for conversion to developed reserves. As a result, these
reserves are classified as proved undeveloped for more than five years. Currently, the development schedule for
these reserves extends through 2028. At the end of 2017, approximately 196 MMBoe of proved undeveloped
reserves at Jackfish have remained undeveloped for five years or more since the initial booking. No other projects
have proved undeveloped reserves that have remained undeveloped more than five years from the initial booking of
the reserves. Furthermore, approximately 88 MMBoe of proved undeveloped reserves at Jackfish will require in
excess of five years, from the date of this filing, to develop.
Price Revisions
Reserves increased 111 MMBoe in the U.S. primarily due to significant price increases in the trailing 12
month average for oil, gas and NGLs in 2017. Reserves decreased 38 MMBoe in Canada due to a significant
increase in the trailing 12 month average price for bitumen in 2017. The increased price has the effect of increasing
its royalties, which decreases its after-royalty volumes.
Reserves decreased 27 MMBoe and 302 MMBoe during 2016 and 2015, respectively, primarily due to lower
commodity prices for oil and gas. The lower bitumen price increased Canadian reserves due to the decline in
royalties, which increases Devon’s after-royalty volumes.
Revisions Other Than Price
Total revisions other than price in 2016 primarily related to Devon’s evaluation of certain dry gas regions and
NGLs, with the largest revisions being made in the Barnett Shale and STACK (Cana-Woodford Shale).
111
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Revisions other than price for 2015 primarily related to evaluations of Eagle Ford and Jackfish. Negative
revisions other than price at Jackfish were primarily due to a refined reserves methodology that resulted in a reduced
recovery factor.
Extensions and Discoveries
2017 – Over 80% of the additions were through our focused efforts in the STACK (120 MMBoe) and the
Delaware Basin (79 MMBoe). The remaining extensions were added throughout the remainder of Devon’s portfolio.
The 2017 extensions and discoveries included 66 MMBoe related to additions from Devon’s infill drilling
activities, which was primarily related to the STACK.
2016 – Of the 126 MMBoe of extensions and discoveries, 97 MMBoe related to STACK, 18 MMBoe related
to the Delaware Basin and 7 MMBoe related to the Eagle Ford.
The 2016 extensions and discoveries included 74 MMBoe related to additions from Devon’s infill drilling
activities, primarily consisting of 73 MMBoe related to STACK.
2015 – Of the 118 MMBoe of extensions and discoveries, 38 MMBoe related to the Delaware Basin, 30
MMBoe related to the Anadarko Basin, 21 MMBoe related to the Eagle Ford and 11 MMBoe related to Jackfish.
The 2015 extensions and discoveries included 13 MMBoe related to additions from Devon’s infill drilling
activities, primarily consisting of 11 MMBoe at Jackfish.
Purchase of Reserves
2016 – Primarily related to Devon’s acquisition in the STACK play.
2015 – Primarily related to Devon’s acquisition in the Powder River Basin.
Sale of Reserves
2017 – Related to Devon’s non-core asset divestitures in the U.S. as discussed further in Note 3.
2016 – Related to Devon’s non-core upstream asset divestitures discussed further in Note 3.
112
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Standardized Measure
The following tables reflect Devon’s standardized measure of discounted future net cash flows from its proved
reserves.
Future cash inflows
Future costs:
Development
Production
Future income tax expense
Future cash inflows
Future costs:
Development
Production
Future income tax expense
Future cash inflows
Future costs:
Development
Production
Future income tax expense
Future net cash flow
10% discount to reflect timing of cash flows
Standardized measure of discounted future net cash flows
$
Future net cash flow
10% discount to reflect timing of cash flows
Standardized measure of discounted future net cash flows
$
Year Ended December 31, 2017
U.S.
Canada
Total
$
34,701
$
13,602
$
48,303
(3,316)
(15,526)
—
15,859
(7,541)
8,318 $
(1,853)
(5,986)
(988)
4,775
(1,756)
3,019 $
(5,169)
(21,512)
(988)
20,634
(9,297)
11,337
Year Ended December 31, 2016
U.S.
Canada
Total
$
22,847
$
9,672
$
32,519
(2,784)
(11,934)
—
8,129
(3,524)
4,605 $
(2,201)
(6,049)
(121)
1,301
(466)
835 $
(4,985)
(17,983)
(121)
9,430
(3,990)
5,440
Year Ended December 31, 2015
U.S.
Canada
Total
$
27,398
$
13,047
$
40,445
(3,306)
(14,938)
—
9,154
(3,230)
5,924 $
(2,759)
(6,501)
(580)
3,207
(1,248)
1,959 $
(6,065)
(21,439)
(580)
12,361
(4,478)
7,883
Future net cash flow
10% discount to reflect timing of cash flows
Standardized measure of discounted future net cash flows
$
Future cash inflows, development costs and production costs were computed using the same assumptions for
prices and costs that were used to estimate Devon’s proved oil and gas reserves at the end of each year. For 2017
estimates, Devon’s future realized prices were assumed to be $47.86 per Bbl of oil, $31.86 per Bbl of bitumen,
$2.43 per Mcf of gas and $16.25 per Bbl of NGLs. Of the $5.2 billion of future development costs as of the end of
2017, $0.9 billion, $0.8 billion and $0.5 billion are estimated to be spent in 2018, 2019 and 2020, respectively.
Future development costs include not only development costs but also future asset retirement costs. Included
as part of the $5.2 billion of future development costs are $1.3 billion of future asset retirement costs. The future
income tax expenses have been computed using statutory tax rates, giving effect to allowable tax deductions and tax
credits under current laws.
113
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The principal changes in Devon’s standardized measure of discounted future net cash flows are as follows:
Beginning balance
Net changes in prices and production costs
Oil, bitumen, gas and NGL sales, net of production costs
Changes in estimated future development costs
Extensions and discoveries, net of future development costs
Purchase of reserves
Sales of reserves in place
Revisions of quantity estimates
Previously estimated development costs incurred during the period
Accretion of discount
Foreign exchange and other
Net change in income taxes
Ending balance
Year Ended December 31,
$
2017
5,440 $
5,218
(3,327)
789
2,497
2
(3)
(318)
559
1,034
(7)
(547)
$ 11,337 $
2015
2016
7,883 $ 21,583
(2,027) (21,330)
(2,943)
(2,379)
1,313
112
1,102
674
93
224
(77)
(577)
(1,312)
(21)
2,158
663
702
537
(1,148)
74
7,742
277
7,883
5,440 $
114
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
25.
Supplemental Quarterly Financial Information (Unaudited)
Net Earnings (Loss) Attributable to Devon
The following tables present a summary of Devon’s unaudited interim results of operations as recast under the
successful efforts method of accounting. See Note 2 for additional details. As a result of the conversion to the
successful efforts method of accounting in the fourth quarter of 2017, Devon has provided the full consolidated
comprehensive statements of earnings for each interim quarter in 2017 to aid investors and facilitate comparative
periods to be shown during 2018. Devon has provided the required summary information for each interim quarter in
2016.
Upstream revenues
Marketing and midstream revenues
Total revenues
Production expenses
Exploration expenses
Marketing and midstream expenses
Depreciation, depletion and amortization
Asset impairments
Asset dispositions
General and administrative expenses
Financing costs, net
Other expenses
Total expenses
Earnings before income taxes
Income tax expense (benefit)
Net earnings
Net earnings attributable to noncontrolling interests
Net earnings attributable to Devon
Net earnings per share attributable to Devon:
Basic
Diluted
Comprehensive earnings:
Net earnings
Other comprehensive earnings, net of tax:
Foreign currency translation and other
Pension and postretirement plans
Other comprehensive earnings, net of tax
Comprehensive earnings
Comprehensive earnings attributable to
noncontrolling interests
Comprehensive earnings attributable to Devon
First
Quarter
2017, under Successful Efforts
Third
Quarter
Second
Quarter
1,541 $
2,010
3,551
457
95
1,814
528
7
(3)
233
128
(33)
3,226
325
8
317
14
303 $
1,332 $
1,927
3,259
455
57
1,714
506
—
(27)
214
116
(20)
3,015
244
(1)
245
26
219 $
1,101 $
2,055
3,156
448
57
1,824
512
2
(169)
203
128
(76)
2,929
227
15
212
19
193 $
Fourth
Quarter Full Year
5,307
8,642
13,949
1,823
380
7,730
2,074
17
(217)
872
498
(124)
13,053
896
(182)
1,078
180
898
1,333 $
2,650
3,983
463
171
2,378
528
8
(18)
222
126
5
3,883
100
(204)
304
121
183 $
0.58 $
0.58 $
0.41 $
0.41 $
0.37 $
0.37 $
0.35 $
0.35 $
1.71
1.70
317 $
245 $
212 $
304 $
1,078
$
$
$
$
$
8
5
13
330
28
4
32
277
14
316 $
26
251 $
$
42
5
47
259
19
240 $
5
15
20
324
121
203 $
83
29
112
1,190
180
1,010
First
Quarter
2016, under Successful Efforts
Third
Quarter
Second
Quarter
Fourth
Quarter Full Year
10,304
(1,317)
(1,056)
(2.09)
(2.09)
2,808 $
271 $
207 $
0.41 $
0.41 $
$
Total revenues
$
Earnings (loss) before income taxes
Net earnings (loss) attributable to Devon
$
Basic net earnings (loss) per share attributable to Devon $
Diluted net earnings (loss) per share attributable to Devon $
2,126 $
(2,036) $
(1,550) $
(3.27) $
(3.27) $
2,488 $
(339) $
(326) $
(0.63) $
(0.63) $
2,882 $
787 $
613 $
1.17 $
1.16 $
115
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The 2017 results include gains from asset dispositions of approximately $217 million (or $0.42 per diluted
share), as discussed in Note 3.
The 2016 results include asset impairments of $1.2 billion (or $2.59 per diluted share) and $81 million (or
$0.15 per diluted share), during the first quarter and the fourth quarter of 2016, respectively, as discussed in Note 6.
Additionally, the 2016 quarterly results include gains from asset dispositions of approximately $3 million (or $0.01
per diluted share), $75 million (or $0.14 per diluted share), $830 million (or $1.59 per diluted share) and $575
million (or $1.10 per diluted share) during the first quarter through the fourth quarter of 2016, respectively, as
discussed in Note 3.
The following tables present a summary of Devon’s quarterly consolidated comprehensive statements of
earnings information for 2017 and 2016 reported under the full cost method.
First
Quarter
2017, under Full Cost
Third
Quarter
Second
Quarter
Total revenues
Earnings before income taxes
Net earnings attributable to Devon
Basic net earnings per share attributable to Devon
Diluted net earnings per share attributable to Devon
$
$
$
$
$
3,551 $
598 $
565 $
1.08 $
1.07 $
3,259 $
458 $
425 $
0.81 $
0.80 $
3,156 $
272 $
228 $
0.43 $
0.43 $
First
Quarter
2016, under Full Cost
Third
Quarter
Second
Quarter
$
Total revenues
$
Earnings (loss) before income taxes
Net earnings (loss) attributable to Devon
$
Basic net earnings (loss) per share attributable to Devon $
Diluted net earnings (loss) per share attributable to Devon $
2,126 $
(3,685) $
(3,056) $
(6.44) $
(6.44) $
2,488 $
(1,745) $
(1,570) $
(3.04) $
(3.04) $
2,882 $
1,178 $
993 $
1.90 $
1.89 $
Quarterly Cash Flow
Fourth
Quarter Full Year
13,949
1,731
1,691
3.22
3.20
3,983 $
403 $
473 $
0.90 $
0.89 $
Fourth
Quarter Full Year
10,304
(3,877)
(3,302)
(6.52)
(6.52)
2,808 $
375 $
331 $
0.63 $
0.63 $
The following table presents a summary of Devon’s quarterly cash flow information as recast under the
successful efforts method of accounting. See Note 2 for additional details. Devon has provided this information for
each interim quarter in 2017 to aid investors and facilitate comparative periods to be shown during 2018.
Net earnings
Net cash from operating activities
Net cash from investing activities
Net cash from financing activities
Effect of exchange rate changes on cash
Net change in cash and cash equivalents
$
Cash and cash equivalents at beginning of period
Cash and cash equivalents at end of period
$
First
Quarter
Second
Quarter
2017
Third
Quarter
317 $
746
(454)
(124)
(8)
160
1,959
2,119 $
245 $
738
(587)
91
8
250
2,119
2,369 $
212 $
700
(457)
157
12
412
2,369
2,781 $
Fourth
Quarter Full Year
1,078
2,909
(2,210)
9
6
714
1,959
2,673
304 $
725
(712)
(115)
(6)
(108)
2,781
2,673 $
116
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Effects of Accounting Change on Fourth Quarter
As Devon recast the financial statements due to a change in accounting principle during the fourth quarter of
2017, the effects of the accounting change on the fourth quarter consolidated comprehensive statement of earnings
and consolidated statement of cash flow are included below. See Note 2 for additional details.
For the Quarter Ended December 31, 2017
Exploration expenses
Depreciation, depletion and amortization
Asset dispositions
General and administrative expenses
Financing costs, net
Other expenses
Earnings before income taxes
Income tax benefit
Net earnings
Net earnings attributable to Devon
Net earnings per share attributable to Devon:
Basic
Diluted
Comprehensive earnings:
Net earnings
Foreign currency translation and other
Comprehensive earnings
Comprehensive earnings attributable to Devon
Changes to the Consolidated Comprehensive
Statement of Earnings
Under Full Cost
$
— $
417
1
174
124
15
403
(191)
594
473
Changes
As Reported Under
Successful Efforts
171
528
(18)
222
126
5
100
(204)
304
183
171 $
111
(19)
48
2
(10)
(303)
(13)
(290)
(290)
0.90
0.89
594
6
615
494
(0.55)
(0.54)
(290)
(1)
(291)
(291)
0.35
0.35
304
5
324
203
For the Quarter Ended December 31, 2017
Net earnings
$
Depreciation, depletion and amortization
Exploratory dry hole expense and unproved
leasehold impairments
Gains and losses on asset sales
Deferred income tax benefit
Share-based compensation
Other
Net cash from operating activities
Capital expenditures
Divestitures of property and equipment
Net cash from investing activities
Changes to the Consolidated
Statement of Cash Flows
Under Full Cost
Changes
As Reported Under
Successful Efforts
594 $
417
—
1
(232)
36
26
796
(871)
102
(783)
(290) $
111
139
(19)
(13)
11
(10)
(71)
72
(1)
71
304
528
139
(18)
(245)
47
16
725
(799)
101
(712)
117
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Not applicable.
Item 9A. Controls and Procedures
Disclosure Controls and Procedures
We have established disclosure controls and procedures to ensure that material information relating to Devon,
including its consolidated subsidiaries, is made known to the officers who certify Devon’s financial reports and to
other members of senior management and the Board of Directors.
Based on their evaluation, our principal executive and principal financial officers have concluded that our
disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act
of 1934) were effective as of December 31, 2017 to ensure that the information required to be disclosed by Devon in
the reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized
and reported within the time periods specified in the SEC rules and forms.
Management’s Annual Report on Internal Control Over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial
reporting for Devon, as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of
1934. Under the supervision and with the participation of Devon’s management, including our principal executive
and principal financial officers, we conducted an evaluation of the effectiveness of our internal control over financial
reporting based on the framework in Internal Control – Integrated Framework issued in 2013 by the Committee of
Sponsoring Organizations of the Treadway Commission (the “2013 COSO Framework”). Based on this evaluation
under the 2013 COSO Framework, which was completed on February 21, 2018, management concluded that its
internal control over financial reporting was effective as of December 31, 2017.
The effectiveness of our internal control over financial reporting as of December 31, 2017 has been audited by
KPMG LLP, an independent registered public accounting firm who audited our consolidated financial statements as
of and for the year ended December 31, 2017, as stated in their report, which is included under “Item 8. Financial
Statements and Supplementary Data” of this report.
Changes in Internal Control Over Financial Reporting
In the fourth quarter of 2017, we added and modified certain internal control processes as a result of changing
our method of accounting for oil and gas exploration and development activities from the full cost method to the
successful efforts method. There were no other changes in our internal control over financial reporting during the
fourth quarter of 2017 that materially affected, or are reasonably likely to materially affect, our internal control over
financial reporting.
Item 9B. Other Information
Not applicable.
118
Item 10. Directors, Executive Officers and Corporate Governance
PART III
The information called for by this Item 10 is incorporated herein by reference to the definitive Proxy
Statement to be filed by Devon pursuant to Regulation 14A of the General Rules and Regulations under the
Securities Exchange Act of 1934 no later than 120 days following the fiscal year ended December 31, 2017.
Item 11. Executive Compensation
The information called for by this Item 11 is incorporated herein by reference to the definitive Proxy
Statement to be filed by Devon pursuant to Regulation 14A of the General Rules and Regulations under the
Securities Exchange Act of 1934 no later than 120 days following the fiscal year ended December 31, 2017.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
The information called for by this Item 12 is incorporated herein by reference to the definitive Proxy
Statement to be filed by Devon pursuant to Regulation 14A of the General Rules and Regulations under the
Securities Exchange Act of 1934 no later than 120 days following the fiscal year ended December 31, 2017.
Item 13. Certain Relationships and Related Transactions, and Director Independence
The information called for by this Item 13 is incorporated herein by reference to the definitive Proxy
Statement to be filed by Devon pursuant to Regulation 14A of the General Rules and Regulations under the
Securities Exchange Act of 1934 no later than 120 days following the fiscal year ended December 31, 2017.
Item 14. Principal Accountant Fees and Services
The information called for by this Item 14 is incorporated herein by reference to the definitive Proxy
Statement to be filed by Devon pursuant to Regulation 14A of the General Rules and Regulations under the
Securities Exchange Act of 1934 no later than 120 days following the fiscal year ended December 31, 2017.
119
PART IV
Item 15. Exhibits and Financial Statement Schedules
(a) The following documents are included as part of this report:
1. Consolidated Financial Statements
Reference is made to the Index to Consolidated Financial Statements and Consolidated Financial Statement
Schedules appearing at “Item 8. Financial Statements and Supplementary Data” in this report.
2. Consolidated Financial Statement Schedules
All financial statement schedules are omitted as they are inapplicable, or the required information has been
included in the consolidated financial statements or notes thereto.
3. Exhibits
Exhibit No.
2.1
2.2
3.1
3.2
4.1
4.2
Description
Agreement and Plan of Merger dated October 21, 2013, by and among Registrant, Devon Gas Services,
L.P., Acacia Natural Gas Corp I, Inc., Crosstex Energy, Inc., New Public Rangers L.L.C., Boomer
Merger Sub, Inc. and Rangers Merger Sub, Inc. (incorporated by reference to Exhibit 2.1 to
Registrant’s Form 8-K filed October 22, 2013; File No. 001-32318).
Contribution Agreement dated October 21, 2013, by and among Registrant, Devon Gas Corporation,
Devon Gas Services, L.P., Southwestern Gas Pipeline, Inc., Crosstex Energy, L.P. and Crosstex Energy
Services, L.P. (incorporated by reference to Exhibit 2.2 to Registrant’s Form 8-K filed October 22,
2013; File No. 001-32318).
Registrant’s Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.1 of
Registrant’s Form 10-K filed February 21, 2013; File No. 001-32318).
Registrant’s Bylaws (incorporated by reference to Exhibit 3.1 of Registrant’s Form 8-K filed
January 27, 2016; File No. 001-32318).
Indenture, dated as of July 12, 2011, between Registrant and UMB Bank, National Association, as
Trustee (incorporated by reference to Exhibit 4.1 to Registrant’s Form 8-K filed July 12, 2011; File No.
001-32318).
Supplemental Indenture No. 1, dated as of July 12, 2011, to Indenture dated as of July 12, 2011,
between Registrant and UMB Bank, National Association, as Trustee, relating to the 4.00% Senior
Notes due 2021 and the 5.60% Senior Notes due 2041 (incorporated by reference to Exhibit 4.2 to
Registrant’s Form 8-K filed July 12, 2011; File No. 001-32318).
120
Exhibit No.
4.3
4.4
4.5
4.6
4.7
4.8
4.9
4.10
4.11
4.12
4.13
Description
Supplemental Indenture No. 2, dated as of May 14, 2012, to Indenture dated as of July 12, 2011,
between Registrant and UMB Bank, National Association, as Trustee, relating to the 3.250% Senior
Notes due 2022 and the 4.750% Senior Notes due 2042 (incorporated by reference to Exhibit 4.1 to
Registrant’s Form 8-K filed May 14, 2012; File No. 001-32318).
Supplemental Indenture No. 3, dated as of December 19, 2013, to Indenture dated as of July 12, 2011,
between Registrant and UMB Bank, National Association, as Trustee, relating to the 2.25% Senior
Notes due 2018 (incorporated by reference to Exhibit 4.1 to Registrant’s Form 8-K filed December 19,
2013; File No. 001-32318).
Supplemental Indenture No. 4, dated as of June 16, 2015, to Indenture dated as of July 12, 2011,
between Registrant and UMB Bank, National Association, as Trustee, relating to the 5.000% Senior
Notes due 2045 (incorporated by reference to Exhibit 4.1 to Registrant’s Form 8-K filed June 16, 2015;
File No. 001-32318).
Supplemental Indenture No. 5, dated as of December 15, 2015, to Indenture dated as of July 12, 2011,
between Registrant and UMB Bank, National Association, as Trustee, relating to the 5.850% Senior
Notes due 2025 (incorporated by reference to Exhibit 4.1 to Registrant’s Form 8-K filed December 15,
2015; File No. 001-32318).
Indenture, dated as of March 1, 2002, between Registrant and The Bank of New York Mellon Trust
Company, N.A. (as successor to The Bank of New York), as Trustee (incorporated by reference to
Exhibit 4.1 of Registrant’s Form 8-K filed April 9, 2002; File No. 000-30176).
Supplemental Indenture No. 1, dated as of March 25, 2002, to Indenture dated as of March 1, 2002,
between Registrant and The Bank of New York Mellon Trust Company, N.A., as Trustee, relating to
the 7.95% Senior Debentures due 2032 (incorporated by reference to Exhibit 4.2 to Registrant’s Form
8-K filed April 9, 2002; File No. 000-30176).
Supplemental Indenture No. 3, dated as of January 9, 2009, to Indenture dated as of March 1, 2002,
between Registrant and The Bank of New York Mellon Trust Company, N.A., as Trustee, relating to
the 6.30% Senior Notes due 2019 (incorporated by reference to Exhibit 4.1 to Registrant’s Form 8-K
filed January 9, 2009; File No. 000-32318).
Indenture, dated as of October 3, 2001, among Devon Financing Company, L.L.C. (f/k/a Devon
Financing Corporation, U.L.C.), as Issuer, Registrant, as Guarantor, and The Bank of New York Mellon
Trust Company, N.A., originally The Chase Manhattan Bank, as Trustee, relating to the 7.875%
Debentures due 2031 (incorporated by reference to Exhibit 4.7 to Registrant’s Registration Statement
on Form S-4 filed October 31, 2001; File No. 333-68694).
Indenture, dated as of July 8, 1998, among Devon OEI Operating, L.L.C. (as successor to Ocean
Energy, Inc.), its Subsidiary Guarantors, and Wells Fargo Bank, N.A. (as successor to Norwest Bank
Minnesota, National Association), as Trustee, relating to the 8.25% Senior Notes due 2018
(incorporated by reference to Exhibit 10.24 to Ocean Energy, Inc.’s Form 10-Q filed August 14, 1998;
File No. 001-14252).
First Supplemental Indenture, dated March 30, 1999, to Indenture dated as of July 8, 1998, by and
among Devon OEI Operating, L.L.C., its Subsidiary Guarantor, and Wells Fargo Bank, N.A., as
Trustee, relating to the 8.25% Senior Notes due 2018 (incorporated by reference to Exhibit 4.5 to
Ocean Energy, Inc.’s Form 10-Q filed May 17, 1999; File No. 001-08094).
Second Supplemental Indenture, dated as of May 9, 2001, to Indenture dated as of July 8, 1998, by and
among Devon OEI Operating, L.L.C., its Subsidiary Guarantor, and Wells Fargo Bank, N.A., as
Trustee, relating to the 8.25% Senior Notes due 2018 (incorporated by reference to Exhibit 99.2 to
Ocean Energy, Inc.’s Form 8-K filed May 14, 2001; File No. 033-06444).
121
Exhibit No.
4.14
4.15
4.16
4.17
4.18
4.19
4.20
4.21
4.22
4.23
4.24
Description
Third Supplemental Indenture, dated January 23, 2006, to Indenture dated as of July 8, 1998, by and
among Devon OEI Operating, L.L.C., as Issuer, Devon Energy Production Company, L.P., as
Successor Guarantor, and Wells Fargo Bank, N.A., as Trustee, relating to the 8.25% Senior Notes due
2018 (incorporated by reference to Exhibit 4.23 of Registrant’s Form 10-K filed March 3, 2006; File
No. 001-32318).
Senior Indenture, dated as of September 1, 1997, between Devon OEI Operating, L.L.C. (as successor
to Seagull Energy Corporation) and The Bank of New York Mellon Trust Company, N.A. (as successor
to The Bank of New York), as Trustee, and related Specimen of 7.50% Senior Notes due 2027
(incorporated by reference to Exhibit 4.4 to Ocean Energy Inc.’s Form 10-K filed March 23, 1998; File
No. 001-08094).
First Supplemental Indenture, dated as of March 30, 1999, to Senior Indenture dated as of September 1,
1997, by and among Devon OEI Operating, L.L.C., its Subsidiary Guarantor, and The Bank of New
York Mellon Trust Company, N.A., as Trustee, relating to the 7.50% Senior Notes due 2027
(incorporated by reference to Exhibit 4.10 to Ocean Energy, Inc.’s Form 10-Q filed May 17, 1999; File
No. 001-08094).
Second Supplemental Indenture, dated as of May 9, 2001, to Senior Indenture dated as of September 1,
1997, by and among Devon OEI Operating, L.L.C., its Subsidiary Guarantor, and The Bank of New
York Mellon Trust Company, N.A., as Trustee, relating to the 7.50% Senior Notes due 2027
(incorporated by reference to Exhibit 99.4 to Ocean Energy, Inc.’s Form 8-K filed May 14, 2001; File
No. 033-06444).
Third Supplemental Indenture, dated as of December 31, 2005, to Senior Indenture dated as of
September 1, 1997, by and among Devon OEI Operating, L.L.C., as Issuer, Devon Energy Production
Company, L.P., as Successor Guarantor, and The Bank of New York Mellon Trust Company, N.A., as
Trustee, relating to the 7.50% Senior Notes due 2027 (incorporated by reference to Exhibit 4.27 of
Registrant’s Form 10-K filed March 3, 2006; File No. 001-32318).
Indenture, dated as of March 19, 2014, by and between EnLink Midstream Partners, LP and Wells
Fargo Bank, National Association, as Trustee (the “EnLink Indenture”) (incorporated by reference to
Exhibit 4.2 to EnLink Midstream Partners, LP’s Form 8-K filed March 21, 2014; File No. 001-36340).†
First Supplemental Indenture, dated as of March 19, 2014, to the EnLink Indenture, by and between
EnLink Midstream Partners, LP and Wells Fargo Bank, National Association, as Trustee (incorporated
by reference to Exhibit 4.3 to EnLink Midstream Partners, LP’s Form 8-K filed March 21, 2014; File
No. 001-36340).†
Second Supplemental Indenture, dated as of November 12, 2014, to the EnLink Indenture, by and
between EnLink Midstream Partners, LP and Wells Fargo Bank, National Association, as Trustee
(incorporated by reference to Exhibit 4.3 to EnLink Midstream Partners, LP’s Form 8-K filed
November 12, 2014; File No. 001-36340).†
Third Supplemental Indenture, dated as of May 12, 2015, to the EnLink Indenture, by and between
EnLink Midstream Partners, LP and Wells Fargo Bank, National Association, as Trustee (incorporated
by reference to Exhibit 4.3 to EnLink Midstream Partners, LP’s Form 8-K filed May 12, 2015; File No.
001-36340).†
Fourth Supplemental Indenture, dated as of July 14, 2016, to the EnLink Indenture, by and between
EnLink Midstream Partners, LP and Wells Fargo Bank, National Association, as Trustee (incorporated
by reference to Exhibit 4.2 to EnLink Midstream Partners, LP’s Form 8-K filed July 14, 2016; File No.
001-36340).†
Fifth Supplemental Indenture, dated as May 11, 2017, to the EnLink Indenture, by and between EnLink
Midstream Partners, LP and Wells Fargo Bank, National Association, as Trustee (incorporated by
reference to Exhibit 4.2 to EnLink Midstream Partners, LP’s Form 8-K filed May 11, 2017; File
No. 001-36340).†
122
Exhibit No.
10.1
10.2
10.3
10.4
10.5
10.6
10.7
10.8
10.9
10.10
10.11
10.12
Description
Credit Agreement, dated as of October 24, 2012, among Registrant, as U.S. Borrower, Devon Canada
Corporation, as Canadian Borrower, each lender from time to time party thereto, each L/C Issuer from
time to time party thereto, and Bank of America, N.A., as Administrative Agent, Canadian Swing Line
Lender and U.S. Swing Line Lender (incorporated by reference to Exhibit 10.1 of Registrant’s Form 8-
K filed October 29, 2012; File No. 001-32318).
Extension Agreement, dated as of September 3, 2013, to the Credit Agreement dated October 24, 2012,
among Registrant, as U.S. Borrower, Devon Canada Corporation, as Canadian Borrower, Devon
Financing Company, L.L.C., the consenting lenders, and Bank of America, N.A., as Administrative
Agent, Canadian Swing Line Lender and U.S. Swing Line Lender, with respect to the extension of the
maturity date from October 24, 2017 to October 24, 2018 (incorporated by reference to Exhibit 10.1 to
Registrant’s Form 10-Q filed November 6, 2013; File No. 001-32318).
First Amendment to Credit Agreement, dated as of February 3, 2014, to the Credit Agreement dated
October 24, 2012, among Registrant, as U.S. Borrower, Devon Canada Corporation, as Canadian
Borrower, each lender from time to time party thereto, each L/C Issuer from time to time party thereto,
and Bank of America, N.A., as Administrative Agent, Canadian Swing Line Lender and U.S. Swing
Line Lender (incorporated by reference to Exhibit 10.1 of Registrant’s Form 8-K filed February 7,
2014; File No. 001-32318).
Extension Agreement, dated as of October 17, 2014, to the Credit Agreement dated October 24, 2012,
among Registrant, as U.S. Borrower, Devon Canada Corporation, as Canadian Borrower, Devon
Financing Company, L.L.C., the consenting lenders, and Bank of America, N.A., as Administrative
Agent, Canadian Swing Line Lender and U.S. Swing Line Lender with respect to the extension of the
maturity date from October 24, 2018 to October 24, 2019 (incorporated by reference to Exhibit 10.1 to
Registrant’s Form 10-Q filed November 5, 2014; File No. 001-32318).
Devon Energy Corporation 2017 Long-Term Incentive Plan (incorporated by reference to Exhibit 99.1
to Registrant’s Form S-8 filed June 7, 2017; File No. 333-218561).*
Devon Energy Corporation 2015 Long-Term Incentive Plan (incorporated by reference to Exhibit 99.1
to Registrant’s Form S-8 filed June 3, 2015; File No. 333-204666).*
Devon Energy Corporation 2009 Long-Term Incentive Plan (as amended and restated effective June 6,
2012) (incorporated by reference to Exhibit 10.2 to the Registrant’s Form 8-K filed June 8, 2012; File
No. 001-32318).*
2013 Amendment (effective as of March 6, 2013) to the Devon Energy Corporation 2009 Long-Term
Incentive Plan (as amended and restated effective June 6, 2012) (incorporated by reference to Exhibit
10.1 to Registrant’s Form 10-Q filed May 1, 2013; File No. 001-32318).*
Devon Energy Corporation Annual Incentive Compensation Plan (amended and restated effective as of
January 1, 2017) (incorporated by reference to Exhibit 10.1 to Registrant’s Form 8-K filed June 12,
2017; File No. 001-32318).*
Devon Energy Corporation Non-Qualified Deferred Compensation Plan (amended and restated
effective as of April 15, 2014) (incorporated by reference to Exhibit 10.1 to Registrant’s Form 10-Q
filed August 6, 2014; File No. 001-32318).*
Amendment 2014-2, executed May 9, 2014, to the Devon Energy Corporation Non-Qualified Deferred
Compensation Plan (amended and restated effective April 15, 2014) (incorporated by reference to
Exhibit 10.11 to Registrant’s Form 10-K filed February 20, 2015; File No. 001-32318).*
Amendment 2016-1, executed October 20, 2016, to the Devon Energy Corporation Non-Qualified
Deferred Compensation Plan (amended and restated effective April 15, 2014) (incorporated by
reference to Exhibit 10.13 to Registrant’s Form 10-K filed February 15, 2017; File No. 001-32318).*
123
Exhibit No.
10.13
10.14
10.15
10.16
10.17
10.18
10.19
10.20
10.21
10.22
10.23
10.24
10.25
10.26
10.27
Description
Devon Energy Corporation Benefit Restoration Plan (amended and restated effective January 1, 2012)
(incorporated by reference to Exhibit 10.15 to Registrant’s Form 10-K filed February 24, 2012; File No.
001-32318).*
Amendment 2014-1, executed March 7, 2014, to the Devon Energy Corporation Benefit Restoration
Plan (amended and restated effective January 1, 2012) (incorporated by reference to Exhibit 10.6 to
Registrant’s Form 10-Q filed May 9, 2014; File No. 001-32318).*
Amendment 2015-1, executed April 15, 2015, to the Devon Energy Corporation Benefit Restoration
Plan (amended and restated effective January 1, 2012) (incorporated by reference to Exhibit 10.1 to
Registrant’s Form 10-Q filed May 6, 2015; File No. 001-32318).*
Amendment 2016-1, executed October 20, 2016, to the Devon Energy Corporation Benefit Restoration
Plan (amended and restated effective January 1, 2012) (incorporated by reference to Exhibit 10.17 to
Registrant’s Form 10-K filed February 15, 2017; File No. 001-32318).*
Devon Energy Corporation Defined Contribution Restoration Plan (amended and restated effective
January 1, 2012) (incorporated by reference to Exhibit 10.16 to Registrant’s Form 10-K filed February
24, 2012; File No. 001-32318).*
Amendment 2014-1, executed March 7, 2014, to the Devon Energy Corporation Defined Contribution
Restoration Plan (amended and restated effective January 1, 2012) (incorporated by reference to Exhibit
10.7 to Registrant’s Form 10-Q filed May 9, 2014; File No. 001-32318).*
Amendment 2016-1, executed October 20, 2016, to the Devon Energy Corporation Defined
Contribution Restoration Plan (amended and restated effective January 1, 2012) (incorporated by
reference to Exhibit 10.20 to Registrant’s Form 10-K filed February 15, 2017; File No. 001-32318).*
Devon Energy Corporation Supplemental Contribution Plan (amended and restated effective January 1,
2012) (incorporated by reference to Exhibit 10.17 to Registrant’s Form 10-K filed February 24, 2012;
File No. 001-32318).*
Amendment 2014-1, executed March 7, 2014, to the Devon Energy Corporation Supplemental
Contribution Plan (amended and restated effective January 1, 2012) (incorporated by reference to
Exhibit 10.8 to Registrant’s Form 10-Q filed May 9, 2014; File No. 001-32318).*
Amendment 2016-1, executed October 20, 2016, to the Devon Energy Corporation Supplemental
Contribution Plan (amended and restated effective January 1, 2012) (incorporated by reference to
Exhibit 10.23 to Registrant’s Form 10-K filed February 15, 2017; File No. 001-32318).*
Devon Energy Corporation Supplemental Executive Retirement Plan (amended and restated effective
January 1, 2012) (incorporated by reference to Exhibit 10.18 to Registrant’s Form 10-K filed February
24, 2012; File No. 001-32318).*
Amendment 2016-1, executed October 20, 2016, to the Devon Energy Corporation Supplemental
Executive Retirement Plan (amended and restated effective January 1, 2012) (incorporated by reference
to Exhibit 10.25 to Registrant’s Form 10-K filed February 15, 2017; File No. 001-32318).*
Devon Energy Corporation Supplemental Retirement Income Plan (amended and restated effective
January 1, 2012) (incorporated by reference to Exhibit 10.19 to Registrant’s Form 10-K filed February
24, 2012; File No. 001-32318).*
Amendment 2014-1, executed March 7, 2014, to the Devon Energy Corporation Supplemental
Retirement Income Plan (amended and restated effective January 1, 2012) (incorporated by reference to
Exhibit 10.9 to Registrant’s Form 10-Q filed May 9, 2014; File No. 001-32318).*
Amendment 2016-1, executed October 20, 2016, to the Devon Energy Corporation Supplemental
Retirement Income Plan (amended and restated effective January 1, 2012) (incorporated by reference to
Exhibit 10.28 to Registrant’s Form 10-K filed February 15, 2017; File No. 001-32318).*
124
Exhibit No.
10.28
10.29
10.30
10.31
10.32
10.33
10.34
10.35
10.36
10.37
10.38
10.39
10.40
Description
Devon Energy Corporation Incentive Savings Plan (amended and restated effective January 1, 2018),
executed December 18, 2017.*
Amended and Restated Form of Employment Agreement between Registrant and certain executive
officers (incorporated by reference to Exhibit 10.19 to Registrant’s Form 10-K filed February 27, 2009;
File No. 001-32318).*
Form of Amendment No. 1 to the Amended and Restated Employment Agreement between Registrant
and certain executive officers (incorporated by reference to Exhibit 10.1 to Registrant’s Form 8-K filed
April 25, 2011; File No. 001-32318).*
Form of Employment Agreement between Registrant and certain executive officers (incorporated by
reference to Exhibit 10.22 to Registrant’s Form 10-K filed February 28, 2014; File No. 001-32318).*
Employment Agreement, dated April 19, 2017, by and between Registrant and Mr. Jeffrey L. Ritenour
(incorporated by reference to Exhibit 10.1 to Registrant’s Form 8-K, filed on April 20, 2017; File No.
001-32318).*
Form of Notice of Grant of Performance Restricted Stock Award and Award Agreement under the 2009
Long-Term Incentive Plan (as amended and restated June 6, 2012) between Registrant and executive
officers for performance based restricted stock awarded (incorporated by reference to Exhibit 10.25 to
Registrant’s Form 10-K filed February 28, 2014; File No. 001-32318).*
Form of Notice of Grant of Performance Restricted Stock Award and Award Agreement under the 2009
Long-Term Incentive Plan (as amended and restated June 6, 2012) between Registrant and executive
officers for performance based restricted stock awarded (incorporated by reference to Exhibit 10.29 to
Registrant’s Form 10-K filed February 20, 2015; File No. 001-32318).*
Form of Notice of Grant of Performance Restricted Stock Award and Award Agreement under the 2015
Long-Term Incentive Plan between Registrant and David A. Hager for performance based restricted
stock awarded (incorporated by reference to Exhibit 10.1 to Registrant’s Form 10-Q filed November 4,
2015; File No. 001-32318).*
Form of Notice of Grant of Performance Restricted Stock Award and Award Agreement under the 2015
Long-Term Incentive Plan between Registrant and executive officers for performance based restricted
stock awarded (incorporated by reference to Exhibit 10.2 to Registrant’s Form 10-Q filed May 4, 2016;
File No. 001-32318).*
2017 Form of Notice of Grant of Performance Restricted Stock Award and Award Agreement under the
2015 Long-Term Incentive Plan between Registrant and executive officers for performance based
restricted stock awarded (incorporated by reference to Exhibit 10.1 to Registrant’s Form 10-Q filed
May 3, 2017; File No. 001-32318).*
Form of Notice of Grant of Performance Share Unit Award and Award Agreement under the 2009
Long-Term Incentive Plan (as amended and restated June 6, 2012) between Registrant and executive
officers for performance based restricted share units awarded (incorporated by reference to Exhibit
10.32 to Registrant’s Form 10-K filed February 20, 2015; File No. 001-32318).*
Form of Notice of Grant of Performance Share Unit Award and Award Agreement under the 2015
Long-Term Incentive Plan between Registrant and executive officers for performance based restricted
share units awarded (incorporated by reference to Exhibit 10.3 to Registrant’s Form 10-Q filed May 4,
2016; File No. 001-32318).*
2017 Form of Notice of Grant of Performance Share Unit Award and Award Agreement under the 2015
Long-Term Incentive Plan between Registrant and executive officers for performance based restricted
share units awarded (incorporated by reference to Exhibit 10.2 to Registrant’s Form 10-Q filed May 3,
2017; File No. 001-32318).*
125
Exhibit No.
10.41
10.42
10.43
10.44
10.45
10.46
10.47
10.48
10.49
10.50
12
21
23.1
23.2
23.3
Description
Form of Notice of Grant of Incentive Stock Options and Award Agreement under the 2009 Long-Term
Incentive Plan between Registrant and certain employees and executive officers for incentive stock
options granted (incorporated by reference to Exhibit 10.15 to Registrant’s Form 10-K filed February
25, 2011; File No. 001-32318).*
Form of Notice of Grant of Nonqualified Stock Options and Award Agreement under the 2009 Long-
Term Incentive Plan between Registrant and certain employees and executive officers for nonqualified
stock options granted (incorporated by reference to Exhibit 10.16 to Registrant’s Form 10-K filed
February 25, 2011; File No. 001-32318).*
Form of Non-Management Director Nonqualified Stock Option Award Agreement under the Devon
Energy Corporation 2009 Long-Term Incentive Plan between Registrant and all non-management
directors for nonqualified stock options granted (incorporated by reference to Exhibit 10.20 to
Registrant’s Form 10-K filed on February 25, 2010; File No. 001-32318).*
Form of Notice of Grant of Restricted Stock Award and Award Agreement under the 2009 Long-Term
Incentive Plan between Registrant and Thomas L. Mitchell for restricted stock awarded (incorporated
by reference to Exhibit 10.18 to Registrant’s Form 10-K filed February 25, 2011; File No. 001-
32318).*
Form of Notice of Grant of Restricted Stock Award and Award Agreement under the 2015 Long-Term
Incentive Plan between Registrant and all non-management directors for restricted stock awarded
(incorporated by reference to Exhibit 10.1 to Registrant’s Form 10-Q filed August 5, 2015; File No.
001-32318).*
2017 Form of Notice of Grant of Restricted Stock Award and Award Agreement under the 2017 Long-
Term Incentive Plan between Devon and all non-management directors for restricted stock awarded
(incorporated by reference to Exhibit 10.1 to Registrant’s Form 10-Q filed August 2, 2017; File
No. 001-32318).*
Form of Letter Agreement amending the restricted stock award agreements and nonqualified stock
option agreements under the 2009 Long-Term Incentive Plan and the 2005 Long-Term Incentive Plan
between Registrant and John Richels (incorporated by reference to Exhibit 10.22 to Registrant’s Form
10-K filed February 25, 2011; File No. 001-32318).*
Form of Amendment to Incentive Stock Option Award Agreements between Registrant and post-
retirement eligible executives relating to incentive stock options under the 2009 Long-Term Incentive
Plan (incorporated by reference to Exhibit 10.24 to Registrant’s Form 10-K filed February 21, 2013;
File No. 001-32318).*
Amendment to Performance Share Unit Award Agreement dated effective September 16, 2015,
between Registrant and John Richels to Performance Share Unit Award Agreement dated February 10,
2015 (incorporated by reference to Exhibit 10.43 to Registrant’s Form 10-K filed February 17, 2016;
File No. 001-32318).*
Amendment to Performance Restricted Stock Award Agreement dated effective September 16, 2015,
between Registrant and John Richels to Performance Restricted Stock Award Agreement dated
February 10, 2015 (incorporated by reference to Exhibit 10.44 to Registrant’s Form 10-K filed
February 17, 2016; File No. 001-32318).*
Statement of computations of ratios of earnings to fixed charges.
List of Subsidiaries.
Consent of KPMG LLP.
Consent of LaRoche Petroleum Consultants, Ltd.
Consent of Deloitte LLP.
126
Exhibit No.
Description
31.1
31.2
32.1
32.2
99.1
99.2
Certification of principal executive officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
Certification of principal financial officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
Certification of principal executive officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
Certification of principal financial officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
Report of LaRoche Petroleum Consultants, Ltd.
Report of Deloitte LLP.
101.INS XBRL Instance Document.
101.SCH XBRL Taxonomy Extension Schema Document.
101.CAL XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB XBRL Taxonomy Extension Labels Linkbase Document.
101.PRE XBRL Taxonomy Extension Presentation Linkbase Document.
†
*
As of December 31, 2017, the aggregate amount of debt issued under the EnLink Indenture, as supplemented,
exceeded ten percent of Devon’s consolidated total assets. Devon has not filed any other instruments defining
the rights of holders of long-term indebtedness of EnLink, as such instruments do not represent debt
exceeding ten percent of the total assets of Devon and its subsidiaries on a consolidated basis. Devon hereby
agrees to furnish a copy of any such agreements to the SEC upon request.
Indicates management contract or compensatory plan or arrangement.
Item 16. Form 10-K Summary
Not applicable.
127
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has
duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
SIGNATURES
DEVON ENERGY CORPORATION
By:
/s/ JEFFREY L. RITENOUR
Jeffrey L. Ritenour
Executive Vice President and
Chief Financial Officer
February 21, 2018
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the
following persons on behalf of the Registrant and in the capacities and on the dates indicated.
/s/ DAVID A. HAGER
David A. Hager
/s/ JEFFREY L. RITENOUR
Jeffrey L. Ritenour
/s/ JEREMY D. HUMPHERS
Jeremy D. Humphers
/s/ JOHN RICHELS
John Richels
/s/ BARBARA M. BAUMANN
Barbara M. Baumann
/s/ JOHN E. BETHANCOURT
John E. Bethancourt
/s/ ROBERT H. HENRY
Robert H. Henry
/s/ MICHAEL M. KANOVSKY
Michael M. Kanovsky
/s/ ROBERT A. MOSBACHER, JR.
Robert A. Mosbacher, Jr.
/s/ DUANE C. RADTKE
Duane C. Radtke
/s/ MARY P. RICCIARDELLO
Mary P. Ricciardello
President, Chief Executive Officer and
Director (Principal executive officer)
February 21, 2018
Executive Vice President
and Chief Financial Officer
(Principal financial officer)
Senior Vice President
and Chief Accounting Officer
(Principal accounting officer)
February 21, 2018
February 21, 2018
Chairman of the Board
February 21, 2018
February 21, 2018
February 21, 2018
February 21, 2018
February 21, 2018
February 21, 2018
February 21, 2018
February 21, 2018
Director
Director
Director
Director
Director
Director
Director
128
Directors
John Richels
Chairman
Barbara M. Baumann (1) (3)
John E. Bethancourt (2) (3) (4)
David A. Hager
Robert H. Henry (1) (3)
Michael M. Kanovsky (1) (4)
Chairman of Reserves Committee
Robert A. Mosbacher Jr. (2) (3)
Lead Director
Chairman of Governance Committee
Duane C. Radtke (2) (4)
Chairman of Compensation Committee
Mary P. Ricciardello (1) (3)
Chairman of Audit Committee
(1) Audit Committee
(2) Compensation Committee
(3) Governance Committee
(4) Reserves Committee
Other Executives
Tana K. Cashion
Senior Vice President, Human Resources
Rob Dutton
Senior Vice President, Canadian Operations
and President of Devon Canada
Rick A. Gideon
Senior Vice President, Exploration and Production
David G. Harris
Senior Vice President, Exploration and Production
Jeremy D. Humphers
Senior Vice President and Chief Accounting
Officer
Wade Hutchings
Senior Vice President, Exploration and Production
Kevin D. Lafferty
Senior Vice President, Exploration and Production
Other Information
Investor Relations Contacts
E-mail: investor.relations@dvn.com
Royalty Owner Assistance
Telephone: (405) 228-4800
E-mail: DevonDirect@dvn.com
Annual Meeting
Our annual shareholders’ meeting will be held at
8 a.m. Central Time on Wednesday, June 6, 2018,
at the Devon Energy Center Auditorium, 333 W.
Sheridan Avenue, Oklahoma City, OK.
Independent Auditors
KPMG LLP
Oklahoma City, OK
Stock Trading Data
Devon Energy Corporation’s common stock is
traded on the New York Stock Exchange (symbol:
DVN). There are approximately 7,400 shareholders
of record.
Additional Information
This report, Devon’s Corporate Social Responsibility
Report and other information about the company
are available at www.devonenergy.com.
Forward-Looking Statements
See information regarding forward-looking
statements on page five of this report.
Senior Executives
Scott Coody, Vice President, Investor Relations
Telephone: (405) 552-4735
David A. Hager
President and Chief Executive Officer
Chris Carr, Supervisor, Investor Relations
Telephone: (405) 228-2496
Tony D. Vaughn
Chief Operating Officer
Jeff L. Ritenour
Executive Vice President and Chief Financial
Officer
R. Alan Marcum
Executive Vice President, Administration
Lyndon C. Taylor
Executive Vice President and General Counsel
Media Contact
John Porretto, Director, Corporate Communications
Telephone: (405) 228-7506
Shareholder Assistance
For information about transfer or exchange of
shares, dividends, address changes, account
consolidation, multiple mailings, lost certificates
and Form 1099, contact:
Computershare Trust Company, N.A.
PO Box 43078
Providence, RI 02940-3078
Toll free: (877) 860-5820
Website: www.computershare.com/investor
Devon Energy Corporation
333 West Sheridan Avenue
Oklahoma City, OK 73102
devonenergy.com
@DevonEnergy