Industrie De Nora

2019 | ANNUAL REPORT

OPERATING AREAS

ROCKY MOUNTAIN REGION

GULF COAST REGION

Denbury Operated CO2 Pipelines

Denbury Planned CO2 Pipelines

CO2 Pipelines Owned by Others

Denbury Owned Fields – Current CO2 Floods

Denbury Owned Fields – Potential CO2 Floods

Naturally-Occurring CO2 Source

Fields Owned by Others – CO2 EOR Candidates

Industrial CO2 Sources Owned or Contracted

 
 
 
 
 
(cid:3)

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(cid:3)

(cid:3)

(cid:3)

(cid:3)

(cid:3)

(cid:3)

(cid:3)

(cid:3)

(cid:3)

(cid:3)

(cid:3)

(cid:3)

(cid:3)

(cid:3)

(cid:3)

(cid:3)

(cid:3)

(cid:3)

(cid:3)

(cid:56)(cid:49)(cid:44)(cid:55)(cid:40)(cid:39)(cid:3)(cid:54)(cid:55)(cid:36)(cid:55)(cid:40)(cid:54)(cid:3)(cid:54)(cid:40)(cid:38)(cid:56)(cid:53)(cid:44)(cid:55)(cid:44)(cid:40)(cid:54)(cid:3)(cid:36)(cid:49)(cid:39)(cid:3)(cid:40)(cid:59)(cid:38)(cid:43)(cid:36)(cid:49)(cid:42)(cid:40)(cid:3)(cid:38)(cid:50)(cid:48)(cid:48)(cid:44)(cid:54)(cid:54)(cid:44)(cid:50)(cid:49)(cid:3)
(cid:58)(cid:68)(cid:86)(cid:75)(cid:76)(cid:81)(cid:74)(cid:87)(cid:82)(cid:81)(cid:15)(cid:3)(cid:39)(cid:17)(cid:38)(cid:17)(cid:3)(cid:21)(cid:19)(cid:24)(cid:23)(cid:28)(cid:3)

(cid:21)(cid:19)(cid:20)(cid:28)(cid:3)(cid:41)(cid:50)(cid:53)(cid:48)(cid:3)(cid:20)(cid:19)(cid:16)(cid:46)(cid:3)
(cid:11)(cid:48)(cid:68)(cid:85)(cid:78)(cid:3)(cid:50)(cid:81)(cid:72)(cid:12)(cid:3)
(cid:59)(cid:3)(cid:3)(cid:36)(cid:81)(cid:81)(cid:88)(cid:68)(cid:79)(cid:3)(cid:85)(cid:72)(cid:83)(cid:82)(cid:85)(cid:87)(cid:3)(cid:83)(cid:88)(cid:85)(cid:86)(cid:88)(cid:68)(cid:81)(cid:87)(cid:3)(cid:87)(cid:82)(cid:3)(cid:54)(cid:72)(cid:70)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:20)(cid:22)(cid:3)(cid:82)(cid:85)(cid:3)(cid:20)(cid:24)(cid:11)(cid:71)(cid:12)(cid:3)(cid:82)(cid:73)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:54)(cid:72)(cid:70)(cid:88)(cid:85)(cid:76)(cid:87)(cid:76)(cid:72)(cid:86)(cid:3)(cid:40)(cid:91)(cid:70)(cid:75)(cid:68)(cid:81)(cid:74)(cid:72)(cid:3)(cid:36)(cid:70)(cid:87)(cid:3)(cid:82)(cid:73)(cid:3)(cid:20)(cid:28)(cid:22)(cid:23)(cid:3)

For the fiscal year ended December 31, 2019(cid:3)
OR(cid:3)

(cid:133)(cid:3)(cid:3)(cid:55)(cid:85)(cid:68)(cid:81)(cid:86)(cid:76)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:85)(cid:72)(cid:83)(cid:82)(cid:85)(cid:87)(cid:3)(cid:83)(cid:88)(cid:85)(cid:86)(cid:88)(cid:68)(cid:81)(cid:87)(cid:3)(cid:87)(cid:82)(cid:3)(cid:54)(cid:72)(cid:70)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:20)(cid:22)(cid:3)(cid:82)(cid:85)(cid:3)(cid:20)(cid:24)(cid:11)(cid:71)(cid:12)(cid:3)(cid:82)(cid:73)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:54)(cid:72)(cid:70)(cid:88)(cid:85)(cid:76)(cid:87)(cid:76)(cid:72)(cid:86)(cid:3)(cid:40)(cid:91)(cid:70)(cid:75)(cid:68)(cid:81)(cid:74)(cid:72)(cid:3)(cid:36)(cid:70)(cid:87)(cid:3)(cid:82)(cid:73)(cid:3)(cid:20)(cid:28)(cid:22)(cid:23)(cid:3)

(cid:41)(cid:82)(cid:85)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:87)(cid:85)(cid:68)(cid:81)(cid:86)(cid:76)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:83)(cid:72)(cid:85)(cid:76)(cid:82)(cid:71)(cid:3)(cid:73)(cid:85)(cid:82)(cid:80)(cid:3)(cid:3)(cid:3)

(cid:3)(cid:87)(cid:82)(cid:3)(cid:3)

(cid:3)

(cid:38)(cid:82)(cid:80)(cid:80)(cid:76)(cid:86)(cid:86)(cid:76)(cid:82)(cid:81)(cid:3)(cid:73)(cid:76)(cid:79)(cid:72)(cid:3)(cid:81)(cid:88)(cid:80)(cid:69)(cid:72)(cid:85)(cid:29)(cid:3)(cid:19)(cid:19)(cid:20)(cid:16)(cid:20)(cid:21)(cid:28)(cid:22)(cid:24)(cid:3)

(cid:3)
(cid:39)(cid:40)(cid:49)(cid:37)(cid:56)(cid:53)(cid:60)(cid:3)(cid:53)(cid:40)(cid:54)(cid:50)(cid:56)(cid:53)(cid:38)(cid:40)(cid:54)(cid:3)(cid:44)(cid:49)(cid:38)(cid:17)(cid:3)
(Exact name of Registrant as specified in its charter)(cid:3)

(cid:39)(cid:72)(cid:79)(cid:68)(cid:90)(cid:68)(cid:85)(cid:72)(cid:3)
(State or other jurisdiction of incorporation or organization) 

(cid:21)(cid:19)(cid:16)(cid:19)(cid:23)(cid:25)(cid:26)(cid:27)(cid:22)(cid:24)(cid:3)
(I.R.S. Employer Identification No.)(cid:3)

(cid:24)(cid:22)(cid:21)(cid:19)(cid:3)(cid:47)(cid:72)(cid:74)(cid:68)(cid:70)(cid:92)(cid:3)(cid:39)(cid:85)(cid:76)(cid:89)(cid:72)(cid:15)(cid:3)

(cid:51)(cid:79)(cid:68)(cid:81)(cid:82)(cid:15)(cid:3)(cid:3)(cid:55)(cid:59)(cid:3)
(Address of principal executive offices) 

(cid:53)(cid:72)(cid:74)(cid:76)(cid:86)(cid:87)(cid:85)(cid:68)(cid:81)(cid:87)(cid:182)(cid:86)(cid:3)(cid:87)(cid:72)(cid:79)(cid:72)(cid:83)(cid:75)(cid:82)(cid:81)(cid:72)(cid:3)(cid:81)(cid:88)(cid:80)(cid:69)(cid:72)(cid:85)(cid:15)(cid:3)(cid:76)(cid:81)(cid:70)(cid:79)(cid:88)(cid:71)(cid:76)(cid:81)(cid:74)(cid:3)(cid:68)(cid:85)(cid:72)(cid:68)(cid:3)(cid:70)(cid:82)(cid:71)(cid:72)(cid:29)(cid:3)

(cid:26)(cid:24)(cid:19)(cid:21)(cid:23)(cid:3)
(Zip Code)(cid:3)

(cid:11)(cid:28)(cid:26)(cid:21)(cid:12)(cid:3)(cid:3)(cid:3)(cid:25)(cid:26)(cid:22)(cid:16)(cid:21)(cid:19)(cid:19)(cid:19)(cid:3)

(cid:54)(cid:72)(cid:70)(cid:88)(cid:85)(cid:76)(cid:87)(cid:76)(cid:72)(cid:86)(cid:3)(cid:85)(cid:72)(cid:74)(cid:76)(cid:86)(cid:87)(cid:72)(cid:85)(cid:72)(cid:71)(cid:3)(cid:83)(cid:88)(cid:85)(cid:86)(cid:88)(cid:68)(cid:81)(cid:87)(cid:3)(cid:87)(cid:82)(cid:3)(cid:54)(cid:72)(cid:70)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:20)(cid:21)(cid:11)(cid:69)(cid:12)(cid:3)(cid:82)(cid:73)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:36)(cid:70)(cid:87)(cid:29)(cid:3)

(cid:55)(cid:76)(cid:87)(cid:79)(cid:72)(cid:3)(cid:82)(cid:73)(cid:3)(cid:40)(cid:68)(cid:70)(cid:75)(cid:3)(cid:38)(cid:79)(cid:68)(cid:86)(cid:86)(cid:29)

(cid:38)(cid:82)(cid:80)(cid:80)(cid:82)(cid:81)(cid:3)(cid:54)(cid:87)(cid:82)(cid:70)(cid:78)(cid:3)(cid:7)(cid:17)(cid:19)(cid:19)(cid:20)(cid:3)(cid:51)(cid:68)(cid:85)(cid:3)(cid:57)(cid:68)(cid:79)(cid:88)(cid:72)(cid:3)

(cid:55)(cid:85)(cid:68)(cid:71)(cid:76)(cid:81)(cid:74) (cid:54)(cid:92)(cid:80)(cid:69)(cid:82)(cid:79)(cid:29)

(cid:49)(cid:68)(cid:80)(cid:72)(cid:3)(cid:82)(cid:73)(cid:3)(cid:40)(cid:68)(cid:70)(cid:75)(cid:3)(cid:40)(cid:91)(cid:70)(cid:75)(cid:68)(cid:81)(cid:74)(cid:72)(cid:3)(cid:82)(cid:81)(cid:3)(cid:58)(cid:75)(cid:76)(cid:70)(cid:75) (cid:53)(cid:72)(cid:74)(cid:76)(cid:86)(cid:87)(cid:72)(cid:85)(cid:72)(cid:71)(cid:29)

(cid:39)(cid:49)(cid:53)(cid:3)

(cid:49)(cid:72)(cid:90)(cid:3)(cid:60)(cid:82)(cid:85)(cid:78)(cid:3)(cid:54)(cid:87)(cid:82)(cid:70)(cid:78)(cid:3)(cid:40)(cid:91)(cid:70)(cid:75)(cid:68)(cid:81)(cid:74)(cid:72)(cid:3)

(cid:54)(cid:72)(cid:70)(cid:88)(cid:85)(cid:76)(cid:87)(cid:76)(cid:72)(cid:86)(cid:3)(cid:85)(cid:72)(cid:74)(cid:76)(cid:86)(cid:87)(cid:72)(cid:85)(cid:72)(cid:71)(cid:3)(cid:83)(cid:88)(cid:85)(cid:86)(cid:88)(cid:68)(cid:81)(cid:87)(cid:3)(cid:87)(cid:82)(cid:3)(cid:54)(cid:72)(cid:70)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:20)(cid:21)(cid:11)(cid:74)(cid:12)(cid:3)(cid:82)(cid:73)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:36)(cid:70)(cid:87)(cid:29)(cid:3)(cid:3)(cid:49)(cid:82)(cid:81)(cid:72)(cid:3)

(cid:44)(cid:81)(cid:71)(cid:76)(cid:70)(cid:68)(cid:87)(cid:72)(cid:3)(cid:69)(cid:92)(cid:3)(cid:70)(cid:75)(cid:72)(cid:70)(cid:78)(cid:3)(cid:80)(cid:68)(cid:85)(cid:78)(cid:3)(cid:76)(cid:73)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:85)(cid:72)(cid:74)(cid:76)(cid:86)(cid:87)(cid:85)(cid:68)(cid:81)(cid:87)(cid:3)(cid:76)(cid:86)(cid:3)(cid:68)(cid:3)(cid:90)(cid:72)(cid:79)(cid:79)(cid:16)(cid:78)(cid:81)(cid:82)(cid:90)(cid:81)(cid:3)(cid:86)(cid:72)(cid:68)(cid:86)(cid:82)(cid:81)(cid:72)(cid:71)(cid:3)(cid:76)(cid:86)(cid:86)(cid:88)(cid:72)(cid:85)(cid:15)(cid:3)(cid:68)(cid:86)(cid:3)(cid:71)(cid:72)(cid:73)(cid:76)(cid:81)(cid:72)(cid:71)(cid:3)(cid:76)(cid:81)(cid:3)(cid:53)(cid:88)(cid:79)(cid:72)(cid:3)(cid:23)(cid:19)(cid:24)(cid:3)(cid:82)(cid:73)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:54)(cid:72)(cid:70)(cid:88)(cid:85)(cid:76)(cid:87)(cid:76)(cid:72)(cid:86)(cid:3)(cid:36)(cid:70)(cid:87)(cid:17)(cid:3)(cid:3)(cid:60)(cid:72)(cid:86)(cid:3)(cid:59)(cid:3)(cid:3)(cid:3)(cid:49)(cid:82)(cid:3)(cid:133)(cid:3)

(cid:44)(cid:81)(cid:71)(cid:76)(cid:70)(cid:68)(cid:87)(cid:72)(cid:3)(cid:69)(cid:92)(cid:3)(cid:70)(cid:75)(cid:72)(cid:70)(cid:78)(cid:3)(cid:80)(cid:68)(cid:85)(cid:78)(cid:3)(cid:76)(cid:73)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:85)(cid:72)(cid:74)(cid:76)(cid:86)(cid:87)(cid:85)(cid:68)(cid:81)(cid:87)(cid:3)(cid:76)(cid:86)(cid:3)(cid:81)(cid:82)(cid:87)(cid:3)(cid:85)(cid:72)(cid:84)(cid:88)(cid:76)(cid:85)(cid:72)(cid:71)(cid:3)(cid:87)(cid:82)(cid:3)(cid:73)(cid:76)(cid:79)(cid:72)(cid:3)(cid:85)(cid:72)(cid:83)(cid:82)(cid:85)(cid:87)(cid:86)(cid:3)(cid:83)(cid:88)(cid:85)(cid:86)(cid:88)(cid:68)(cid:81)(cid:87)(cid:3)(cid:87)(cid:82)(cid:3)(cid:54)(cid:72)(cid:70)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:20)(cid:22)(cid:3)(cid:82)(cid:85)(cid:3)(cid:54)(cid:72)(cid:70)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:20)(cid:24)(cid:11)(cid:71)(cid:12)(cid:3)(cid:82)(cid:73)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:36)(cid:70)(cid:87)(cid:17)(cid:3)(cid:60)(cid:72)(cid:86)(cid:3)(cid:133)(cid:3)(cid:3)(cid:3)(cid:49)(cid:82)(cid:3)(cid:59)(cid:3)

(cid:44)(cid:81)(cid:71)(cid:76)(cid:70)(cid:68)(cid:87)(cid:72)(cid:3)(cid:69)(cid:92)(cid:3)(cid:70)(cid:75)(cid:72)(cid:70)(cid:78)(cid:3)(cid:80)(cid:68)(cid:85)(cid:78)(cid:3)(cid:90)(cid:75)(cid:72)(cid:87)(cid:75)(cid:72)(cid:85)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:85)(cid:72)(cid:74)(cid:76)(cid:86)(cid:87)(cid:85)(cid:68)(cid:81)(cid:87)(cid:3)(cid:11)(cid:20)(cid:12)(cid:3)(cid:75)(cid:68)(cid:86)(cid:3)(cid:73)(cid:76)(cid:79)(cid:72)(cid:71)(cid:3)(cid:68)(cid:79)(cid:79)(cid:3)(cid:85)(cid:72)(cid:83)(cid:82)(cid:85)(cid:87)(cid:86)(cid:3)(cid:85)(cid:72)(cid:84)(cid:88)(cid:76)(cid:85)(cid:72)(cid:71)(cid:3)(cid:87)(cid:82)(cid:3)(cid:69)(cid:72)(cid:3)(cid:73)(cid:76)(cid:79)(cid:72)(cid:71)(cid:3)(cid:69)(cid:92)(cid:3)(cid:54)(cid:72)(cid:70)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:20)(cid:22)(cid:3)(cid:82)(cid:85)(cid:3)(cid:20)(cid:24)(cid:11)(cid:71)(cid:12)(cid:3)(cid:82)(cid:73)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:54)(cid:72)(cid:70)(cid:88)(cid:85)(cid:76)(cid:87)(cid:76)(cid:72)(cid:86)(cid:3)(cid:40)(cid:91)(cid:70)(cid:75)(cid:68)(cid:81)(cid:74)(cid:72)(cid:3)(cid:36)(cid:70)(cid:87)(cid:3)(cid:82)(cid:73)(cid:3)(cid:20)(cid:28)(cid:22)(cid:23)(cid:3)
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(cid:79)(cid:68)(cid:86)(cid:87)(cid:3)(cid:69)(cid:88)(cid:86)(cid:76)(cid:81)(cid:72)(cid:86)(cid:86)(cid:3)(cid:71)(cid:68)(cid:92)(cid:3)(cid:82)(cid:73)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:85)(cid:72)(cid:74)(cid:76)(cid:86)(cid:87)(cid:85)(cid:68)(cid:81)(cid:87)(cid:182)(cid:86)(cid:3)(cid:80)(cid:82)(cid:86)(cid:87)(cid:3)(cid:85)(cid:72)(cid:70)(cid:72)(cid:81)(cid:87)(cid:79)(cid:92)(cid:3)(cid:70)(cid:82)(cid:80)(cid:83)(cid:79)(cid:72)(cid:87)(cid:72)(cid:71)(cid:3)(cid:86)(cid:72)(cid:70)(cid:82)(cid:81)(cid:71)(cid:3)(cid:73)(cid:76)(cid:86)(cid:70)(cid:68)(cid:79)(cid:3)(cid:84)(cid:88)(cid:68)(cid:85)(cid:87)(cid:72)(cid:85)(cid:3)(cid:90)(cid:68)(cid:86)(cid:3)(cid:7)(cid:24)(cid:25)(cid:24)(cid:15)(cid:22)(cid:21)(cid:28)(cid:15)(cid:23)(cid:27)(cid:19)(cid:17)(cid:3)

(cid:55)(cid:75)(cid:72)(cid:3)(cid:81)(cid:88)(cid:80)(cid:69)(cid:72)(cid:85)(cid:3)(cid:82)(cid:73)(cid:3)(cid:86)(cid:75)(cid:68)(cid:85)(cid:72)(cid:86)(cid:3)(cid:82)(cid:88)(cid:87)(cid:86)(cid:87)(cid:68)(cid:81)(cid:71)(cid:76)(cid:81)(cid:74)(cid:3)(cid:82)(cid:73)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:85)(cid:72)(cid:74)(cid:76)(cid:86)(cid:87)(cid:85)(cid:68)(cid:81)(cid:87)(cid:182)(cid:86)(cid:3)(cid:38)(cid:82)(cid:80)(cid:80)(cid:82)(cid:81)(cid:3)(cid:54)(cid:87)(cid:82)(cid:70)(cid:78)(cid:3)(cid:68)(cid:86)(cid:3)(cid:82)(cid:73)(cid:3)(cid:45)(cid:68)(cid:81)(cid:88)(cid:68)(cid:85)(cid:92)(cid:3)(cid:22)(cid:20)(cid:15)(cid:3)(cid:21)(cid:19)(cid:21)(cid:19)(cid:15)(cid:3)(cid:90)(cid:68)(cid:86)(cid:3)(cid:24)(cid:19)(cid:25)(cid:15)(cid:22)(cid:27)(cid:21)(cid:15)(cid:27)(cid:28)(cid:26)(cid:17)(cid:3)

(cid:39)(cid:50)(cid:38)(cid:56)(cid:48)(cid:40)(cid:49)(cid:55)(cid:54)(cid:3)(cid:44)(cid:49)(cid:38)(cid:50)(cid:53)(cid:51)(cid:50)(cid:53)(cid:36)(cid:55)(cid:40)(cid:39)(cid:3)(cid:37)(cid:60)(cid:3)(cid:53)(cid:40)(cid:41)(cid:40)(cid:53)(cid:40)(cid:49)(cid:38)(cid:40)(cid:3)

(cid:39)(cid:82)(cid:70)(cid:88)(cid:80)(cid:72)(cid:81)(cid:87)(cid:29)(cid:3)

(cid:44)(cid:81)(cid:70)(cid:82)(cid:85)(cid:83)(cid:82)(cid:85)(cid:68)(cid:87)(cid:72)(cid:71)(cid:3)(cid:68)(cid:86)(cid:3)(cid:87)(cid:82)(cid:29)(cid:3)

(cid:20)(cid:17)(cid:3)(cid:49)(cid:82)(cid:87)(cid:76)(cid:70)(cid:72)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:51)(cid:85)(cid:82)(cid:91)(cid:92)(cid:3)(cid:54)(cid:87)(cid:68)(cid:87)(cid:72)(cid:80)(cid:72)(cid:81)(cid:87)(cid:3)(cid:73)(cid:82)(cid:85)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:36)(cid:81)(cid:81)(cid:88)(cid:68)(cid:79)(cid:3)(cid:48)(cid:72)(cid:72)(cid:87)(cid:76)(cid:81)(cid:74)(cid:3)(cid:82)(cid:73)(cid:3)(cid:54)(cid:87)(cid:82)(cid:70)(cid:78)(cid:75)(cid:82)(cid:79)(cid:71)(cid:72)(cid:85)(cid:86)(cid:3)(cid:87)(cid:82)(cid:3)(cid:69)(cid:72)(cid:3)(cid:75)(cid:72)(cid:79)(cid:71)(cid:3)(cid:48)(cid:68)(cid:92)(cid:3)(cid:21)(cid:27)(cid:15)(cid:3)(cid:21)(cid:19)(cid:21)(cid:19)(cid:17)(cid:3)

(cid:20)(cid:17)(cid:3)(cid:3)(cid:51)(cid:68)(cid:85)(cid:87)(cid:3)(cid:44)(cid:44)(cid:44)(cid:15)(cid:3)(cid:44)(cid:87)(cid:72)(cid:80)(cid:86)(cid:3)(cid:20)(cid:19)(cid:15)(cid:3)(cid:20)(cid:20)(cid:15)(cid:3)(cid:20)(cid:21)(cid:15)(cid:3)(cid:20)(cid:22)(cid:15)(cid:3)(cid:20)(cid:23)(cid:3)

Denbury Resources Inc.

2019 Annual Report on Form 10-K
 Table of Contents 

Glossary and Selected Abbreviations

PART I

Business and Properties

Risk Factors

Unresolved Staff Comments

Properties

Legal Proceedings
  Mine Safety Disclosures

PART II

Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases
of Equity Securities
Selected Financial Data

  Management’s Discussion and Analysis of Financial Condition and Results of Operations

Item 1.

Item 1A.

Item 1B.

Item 2.

Item 3.

Item 4.

Item 5.

Item 6.

Item 7.

Item 7A.

Quantitative and Qualitative Disclosures About Market Risk

Item 8.

Item 9.

Item 9A.

Item 9B.

Item 10.

Item 11.
Item 12.

Item 13.

Item 14.

Item 15.

Item 16.

Financial Statements and Supplementary Information

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

Controls and Procedures

Other Information

PART III

Directors, Executive Officers and Corporate Governance

Executive Compensation

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder
Matters
Certain Relationships and Related Transactions, and Director Independence

Principal Accountant Fees and Services

PART IV

Exhibits and Financial Statement Schedules

Form 10-K Summary

Signatures

2

Page

3

5

26

33

33

34

34

35

37

39

63

63

108

108

108

109

109

109

109

109

110

116

117

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Denbury Resources Inc.

Glossary and Selected Abbreviations

Bbl

Bbls/d

Bcf

BOE

BOE/d

Btu

CO2

EOR

One stock tank barrel, of 42 U.S. gallons liquid volume, used herein in reference to crude oil or other 
liquid hydrocarbons.

Barrels of oil or other liquid hydrocarbons produced per day.

One billion cubic feet of natural gas or CO2.

One barrel of oil equivalent, using the ratio of one barrel of crude oil, condensate or natural gas liquids 
to 6 Mcf of natural gas.

BOEs produced per day.

British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water 
from 58.5 to 59.5 degrees Fahrenheit (°F).

Carbon dioxide.

Enhanced oil recovery.  In the context of our oil production, EOR is also referred to as tertiary recovery.  
Primary types of EOR include thermal, gas injection (such as natural gas, nitrogen, or CO2) and chemical 
injection (such as the use of polymers).

Finding and
development costs

The average cost per BOE to find and develop proved reserves during a given period. It is calculated 
by dividing (a) costs, which include the sum of (i) the total acquisition, exploration and development 
costs incurred during the period plus (ii) future development and abandonment costs related to the 
specified property or group of properties, by (b) the sum of (i) the change in total proved reserves during 
the period plus (ii) total production during that period.

GAAP

MBbls

MBOE

Mcf

Mcf/d

MMBbls

MMBOE

MMBtu

MMcf

MMcf/d

Accounting principles generally accepted in the United States of America.

One thousand barrels of crude oil or other liquid hydrocarbons.

One thousand BOEs.

One thousand cubic feet of natural gas or CO2 at a temperature base of 60 degrees Fahrenheit (°F) and 
at the legal pressure base (14.65 to 15.025 pounds per square inch absolute) of the state or area in which 
the reserves are located or sales are made.

One thousand cubic feet of natural gas or CO2 per day.

One million barrels of crude oil or other liquid hydrocarbons.

One million BOEs.

One million Btus.

One million cubic feet of natural gas or CO2.

One million cubic feet of natural gas or CO2 produced per day.

Noncash fair value 
gains (losses) on 
commodity 
derivatives

The net change during the period in the fair market value of commodity derivative positions.  Noncash 
fair value gains (losses) on commodity derivatives is a non-GAAP measure and makes up only a portion 
of “Commodity derivatives expense (income)” in the Consolidated Statements of Operations, which 
also includes the impact of settlements on commodity derivatives during the period.  Its use is further 
discussed in Management’s Discussion and Analysis of Financial Condition and Results of Operations 
– Results of Operations – Operating Results Table.

NYMEX

The New York Mercantile Exchange.  In the context of prices received for oil and natural gas, NYMEX 
prices represent the West Texas Intermediate benchmark price for crude oil and Henry Hub benchmark 
price for natural gas.

Probable
Reserves*

Reserves that are less certain to be recovered than proved reserves but which, together with proved 
reserves, are as likely as not to be recovered.

Proved Developed
Reserves*

Reserves  that  can  be  expected  to  be  recovered  through  existing  wells  with  existing  equipment  and 
operating methods.

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Denbury Resources Inc.

Proved Reserves* Reserves that geological and engineering data demonstrate with reasonable certainty to be recoverable 

in future years from known reservoirs under existing economic and operating conditions.

Proved
Undeveloped
Reserves*

PV-10 Value

Reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells, 
in each case where a relatively major expenditure is required.

The estimated future gross revenue to be generated from the production of proved reserves, net of 
estimated future production, development and abandonment costs, and before income taxes, discounted 
to a present value using an annual discount rate of 10%.  PV-10 Values were prepared using average 
hydrocarbon prices equal to the unweighted arithmetic average of hydrocarbon prices on the first day 
of each month within the 12-month period preceding the reporting date.  PV-10 Value is a non-GAAP 
measure and does not purport to represent the fair value of our oil and natural gas reserves; its use is 
further  discussed  in  Item  1,  Business  and  Properties  –  Non-GAAP  Financial  Measures  and 
Reconciliations.

Tcf

One trillion cubic feet of natural gas or CO2.

Tertiary Recovery A term used to represent techniques for extracting incremental oil out of existing oil fields (as opposed 
to primary and secondary recovery or “non-tertiary” recovery).  See also “EOR.” 

* This definition is an abbreviated version of the complete definition set forth in Rule 4-10(a) of Regulation S-X.  For the 
complete definition see: 
http://www.ecfr.gov/cgi-bin/text-idx?
SID=2d916841db86d079fa060fa63b08d34e&mc=true&node=se17.3.210_14_610&rgn=div8.

4

Denbury Resources Inc.

PART I

Item 1. Business and Properties

GENERAL

Denbury Resources Inc., a Delaware corporation, is an independent oil and natural gas company with 230.2 MMBOE of 
estimated proved oil and natural gas reserves as of December 31, 2019, of which 98% is oil.  Our operations are focused in 
two key operating areas: the Gulf Coast and Rocky Mountain regions.  Our goal is to increase the value of our properties 
through a combination of exploitation, drilling and proven engineering extraction practices, with the most significant emphasis 
relating to CO2 enhanced oil recovery operations.

As part of our corporate strategy, we are committed to strong financial discipline, efficient operations and creating long-

term value for our shareholders through the following key principles:

• 

• 

• 

target specific regions where we either have, or believe we can create, a competitive advantage as a result of our 
ownership or use of CO2 reserves, oil fields and CO2 infrastructure;
secure  properties  where  we  believe  additional  value  can  be  created  through  tertiary  recovery  operations  and  a 
combination of other exploitation, development, exploration and marketing techniques;
acquire  properties  that  give  us  a  majority  working  interest  and  operational  control  or  where  we  believe  we  can 
ultimately obtain it;

•  maximize  the  value  and  cash  flow  generated  from  our  operations  by  increasing  production  and  reserves  while 

controlling costs;
optimize the timing and allocation of capital among our investment opportunities to maximize the rates of return on 
our investments;
exercise financial discipline by attempting to balance our development capital expenditures with our cash flows from 
operations; and
attract and maintain a highly competitive team of experienced and incentivized personnel.

• 

• 

• 

Denbury has been publicly traded on the New York Stock Exchange since 1997.  Our corporate headquarters is located 
at 5320 Legacy Drive, Plano, Texas 75024, and our phone number is 972-673-2000.  At December 31, 2019, we had 806
employees, 451 of whom were employed in field operations or at our field offices.  We make our annual report on Form 10-
K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports, filed or furnished pursuant 
to  Section  13(a)  or  15(d)  of  the  Securities  Exchange Act  of  1934,  available  free  of  charge  on  or  through  our  website, 
www.denbury.com,  as  soon  as  reasonably  practicable  after  we  electronically  file  such  material  with,  or  furnish  it  to,  the 
SEC.  The SEC also maintains a website, http://www.sec.gov, which contains periodic reports on Forms 8-K, 10-Q and 10-
K  filed  with  the  SEC,  along  with  other  reports,  proxy  and  information  statements  and  other  information  filed  by 
Denbury.  Throughout this Annual Report on Form 10-K (“Form 10-K”) we use the terms “Denbury,” “Company,” “we,” 
“our” and “us” to refer to Denbury Resources Inc. and, as the context may require, its subsidiaries.

2019 BUSINESS DEVELOPMENTS

Since our production is 97% oil, oil prices generally constitute the single largest variable in our operating results.  Over 
the last several years, NYMEX oil prices have been extremely volatile, decreasing to a low of $26 in early 2016 and gradually 
improving to hit a three-year peak of $76 in October 2018, before retreating to the low $40s in late December 2018 and 
generally averaging in the low $50s to mid $60s range throughout 2019.  Throughout this time, we have focused primarily 
on  preservation  of  cash  and  liquidity,  together  with  cost  reductions  and  debt  management,  rather  than  concentration  on 
expansion and growth.  Our 2019 key accomplishments and business developments included the following:

•  Generated $494.1 million of cash flow from operations ($408.8 million after reducing for interest payments treated as 
debt reduction), significantly exceeding our $273.6 million of incurred development capital expenditures and capitalized 
interest in 2019.

•  Reduced our debt principal by $250.5 million and significantly improved our debt maturity profile, ending the year with 

no outstanding borrowings on the Company’s senior secured bank credit facility.

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Denbury Resources Inc.

•  Continued progress on the CO2 enhanced oil recovery development project at Cedar Creek Anticline (“CCA”), Denbury’s 
largest oil field, to access the potential for significant long-term oil production and cash flow from this key asset, with 
project activities and capital primarily related to procurement of the pipe and preparation for installation of the CO2
pipeline to CCA.

• 

Improved our leverage ratio to 3.7x during 2019 from 4.2x during 2018 (ratio of net debt (debt principal less cash) to 
Adjusted EBITDAX (a non-GAAP measure)) (see Non-GAAP Financial Measures and Reconciliations).

•  Reduced  general  and  administrative  expenses  (excluding  $18.6  million  of  severance  expense  related  to  a  voluntary 

separation program) by $7.1 million, a 10% reduction from 2018 amounts.

•  Continued  to  optimize  our  oil  and  natural  gas  asset  portfolio  through  the  following:  (1)  sold  Citronelle  Field  for 
approximately $10 million in July 2019 and (2) entered into an agreement in December 2019 to sell half of our nearly 
100% working interests in four conventional southeast Texas oil fields for $50 million and a carried interest in ten wells 
to be funded and drilled by the purchaser, which is currently expected to occur in March 2020 (the “Pending Gulf Coast 
Working Interests Sale”).

•  Continued the monetization of valuable surface land with no active oil and natural gas operations around Houston, Texas, 
including (1) the sale of multiple parcels primarily around Houston, Texas in transactions totaling $14 million in 2019 
and (2) entered into a contract to sell acreage around Houston, Texas for $32 million which provides for a substantial 
portion of the cash proceeds from such sale to be received no later than mid-2021 with the remaining portion of cash 
proceeds to be received by mid-2022, subject to certain conditions.  We are actively working with the buyer to potentially 
close the first portion of this sale before the end of 2020.

2020 BUSINESS OUTLOOK

Since the beginning of 2020, NYMEX oil prices have moved downward by over $10 per barrel (from the low $60s per 
barrel in early January to around $50 per barrel in mid-February 2020), due in part to concerns about the COVID-19 coronavirus 
and its real and potential impact on near-term worldwide oil demand.  In consideration of the current oil price environment 
and the Company’s desire to preserve ongoing liquidity, we have set our 2020 base capital budget at between $175 million 
and $185 million (excluding capitalized interest), which includes $10 million of capital dedicated to continuing near-term 
CO2 development activities at CCA as further discussed below.  This 2020 base capital budget is a $57 million (24%) reduction 
from our 2019 capital expenditure level.  We currently anticipate that our 2020 base capital budget of $175 million to $185 
million will be more than fully funded with cash flow from operations (assuming a $50 per barrel NYMEX oil price) and 
should result in the Company generating upwards of $100 million of cash in excess of our capital expenditures, without 
including  any  proceeds  from  the  Pending  Gulf  Coast  Working  Interests  Sale  (from  which  we  expect  net  proceeds  of 
approximately $40 million) or the impact of any other potential transactions.

An additional $140 million to $150 million of capital for the CCA CO2 tertiary flood development, most of which is 
scheduled to be spent in the second half of the year, is conditioned upon future Board approval.  The aggregate $155 million 
of planned 2020 CCA tertiary-related development capital consists of $105 million for the 105-mile extension of the Greencore 
Pipeline  to  CCA,  with  the  remainder  dedicated  to  facilities,  well  work  and  field  development.   The  Company  currently 
anticipates finalizing its 2020 capital plans related to CCA during the second quarter.

Based on our capital spending plans, we currently anticipate 2020 average daily production to be between 53,000 and 
56,000 BOE/d, after adjusting for the Pending Gulf Coast Working Interests Sale (see Management’s Discussion and Analysis 
of Financial Condition and Results of Operations – Overview – Pending Sale of Working Interests in Certain Texas Fields).  
The production associated with the Pending Gulf Coast Working Interests Sale averaged 1,170 BOE/d during the fourth quarter 
of 2019.  Our anticipated 2020 production level compares to 2019 average continuing production of 56,914 BOE/d, after 
reduction for 2019 property divestitures and production associated with the Pending Gulf Coast Working Interests Sale.

The Company is currently assessing various alternatives to improve the Company’s balance sheet and may engage in 
debt reduction and/or maturity extension transactions of various types, primarily focusing on our second lien debt maturing 
in 2021 and 2022, plus accessing the capital markets and/or generating capital from joint ventures or asset sales.  In addition, 
we continue to market for sale surface land with no active oil and gas operations in the Houston area and believe future land 

6

 
 
Denbury Resources Inc.

sales could generate an additional $30 million to $50 million of cash over the next few years beyond the $52 million we 
currently have under contract or have sold.

ESTIMATED NET QUANTITIES OF PROVED OIL AND NATURAL GAS RESERVES AND PRESENT VALUE 
OF ESTIMATED FUTURE NET REVENUES

Oil and Natural Gas Reserve Estimates

DeGolyer  and  MacNaughton  (“D&M”)  prepared  estimates  of  our  net  proved  oil  and  natural  gas  reserves  as  of 
December 31, 2019, 2018 and 2017 (see the summary of D&M’s report as of December 31, 2019, included as an exhibit to 
this Form 10-K).  These estimates of reserves were prepared using an average price equal to the unweighted arithmetic average 
of hydrocarbon prices on the first day of each month within the 12-month period in accordance with rules and regulations of 
the SEC.  These oil and natural gas reserve estimates do not include any value for probable or possible reserves that may exist, 
nor  do  they  include  any  value  for  undeveloped  acreage.  The  reserve  estimates  represent  our  net  revenue  interest  in  our 
properties.

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Denbury Resources Inc.

The following table provides estimated proved reserve information prepared by D&M as of December 31, 2019, 2018
and 2017, as well as PV-10 Values and Standardized Measures for each period.  There are numerous uncertainties inherent in 
estimating quantities of proved oil and natural gas reserves and their values, including many factors beyond our control, which 
are further discussed in Item 1A, Risk Factors – Estimating our reserves, production and future net cash flows is difficult to 
do with any certainty.  See also Oil and Natural Gas Operations – Field Summary Table and Supplemental Oil and Natural 
Gas Disclosures (Unaudited) to the Consolidated Financial Statements for further discussion of reserve inputs and changes 
between periods.

Estimated proved reserves

Oil (MBbls)

Natural gas (MMcf)

Oil equivalent (MBOE)
Reserve volumes categories

Proved developed producing

Oil (MBbls)

Natural gas (MMcf)

Oil equivalent (MBOE)

Proved developed non-producing

Oil (MBbls)

Natural gas (MMcf)

Oil equivalent (MBOE)

Proved undeveloped

Oil (MBbls)

Natural gas (MMcf)

Oil equivalent (MBOE)

Percentage of total MBOE

Proved developed producing

Proved developed non-producing

Proved undeveloped

Representative oil and natural gas prices(1)

Oil (NYMEX price per Bbl)

Natural gas (Henry Hub price per MMBtu)

Present values (in thousands)(2)

December 31,

2019

2018

2017

226,133

24,334

230,189

178,538

21,627

182,143

24,278

2,706

24,729

23,317

1

23,317

255,042

43,008

262,210

200,852

39,562

207,446

21,884

3,350

22,442

32,306

96

32,322

252,625

42,721

259,745

189,166

38,184

195,530

33,365

4,251

34,073

30,094

286

30,142

79%

11%

10%

79%

9%

12%

75%

13%

12%

$

55.69

$

65.56

$

2.58

3.10

51.34

2.98

Discounted estimated future net cash flows before income taxes 

(PV-10 Value)(3)

Standardized measure of discounted estimated future net cash flows

$ 2,615,668

$ 4,025,139

$ 2,533,798

after income taxes (“Standardized Measure”)

$ 2,261,039

$ 3,351,385

$ 2,232,429

(1)  The reference prices were based on the arithmetic average of the first-day-of-the-month NYMEX commodity prices for 
each month during the respective year.  These prices do not reflect adjustments for market differentials by field that are 
utilized in the preparation of our reserve report to arrive at the appropriate net price we receive.  See Item 7, Management’s 
Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – Operating Results 
Table for details of oil and natural gas prices received, both including and excluding the impact of derivative settlements.

(2)  Determined based on the average first-day-of-the-month prices for each month, adjusted to prices received by field in 
accordance with standards set forth in the Financial Accounting Standards Board Codification (“FASC”).  PV-10 Values 
and the Standardized Measure are significantly impacted by the oil prices we receive relative to NYMEX oil prices (our 

8

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Denbury Resources Inc.

NYMEX  oil  price  differential).    The  weighted-average  oil  price  differentials  utilized  were  $0.14  per  Bbl  below 
representative NYMEX oil prices as of December 31, 2019, compared to $0.24 per Bbl below NYMEX oil prices as of 
December 31, 2018, and $2.25 per Bbl below NYMEX oil prices as of December 31, 2017.

(3)  PV-10 Value is a non-GAAP measure and is different from the Standardized Measure in that PV-10 Value is a pre-tax 
number and the Standardized Measure is an after-tax number.  See Non-GAAP Financial Measures and Reconciliations
for further discussion.

Our proved developed non-producing reserves primarily consist of (1) reserves within a proved tertiary flood in areas 
that have not yet experienced a response from CO2 injection, (2) reserves that will be recovered from currently productive 
zones utilizing minor modifications to manage the flow of CO2 or water within the reservoir, and (3) reserves that will be 
recovered through recompletions to other intervals above or below the currently producing interval.

As  of  December 31,  2019,  our  estimated  proved  undeveloped  reserves  totaled  approximately  23.3  MMBOE,  or 
approximately 10% of our estimated total proved reserves.  Approximately 85% (19.8 MMBOE) of our proved undeveloped 
oil reserves relate to planned future development within our CO2 tertiary operating fields.  We generally consider the CO2
tertiary proved undeveloped reserves to be lower risk than other proved undeveloped reserves that require drilling at locations 
offsetting existing production, because all of these proved undeveloped reserves are associated with tertiary recovery operations 
in fields and reservoirs that historically produced substantial volumes of oil under primary production.  As of December 31, 
2019, 16.1 MMBOE of our total proved undeveloped reserves are not scheduled to be developed within five years of initial 
booking, all of which are part of CO2 EOR projects.  We believe these reserves satisfy the conditions to be included as proved 
reserves because (1) we have established and continue to follow the previously adopted development plan for each of these 
projects; (2) we have significant ongoing development activities in each of these CO2 EOR projects and (3) we have a historical 
record of completing the development of comparable long-term projects.

Our proved undeveloped reserves at December 31, 2019 were 9.0 MMBOE (28%) lower than at December 31, 2018.  
During 2019, we spent approximately $50 million to convert 9.5 MMBOE of proved undeveloped reserves to proved developed 
reserves, primarily related to continued tertiary development activities at Bell Creek and East Heidelberg fields.  Other changes 
in proved undeveloped reserves during 2019 included adding an additional 2.7 MMBOE primarily related to our tertiary 
operations at Oyster Bayou and Brookhaven fields and recognizing net downward revisions of our proved undeveloped reserves 
of  2.2  MMBOE,  primarily  the  result  of  reserves  that  were  reclassified  to  unproved  based  on  changes  in  our  waterflood 
development plans that would now extend beyond the five-year development timeframe.

During 2019, we provided oil and natural gas reserve estimates for 2018 to the United States Energy Information Agency 
that were substantially the same as the reserve estimates included in our Form 10-K for the year ended December 31, 2018.

Internal Controls Over Reserve Estimates

Reserve  information  in  this  report  is  based  on  estimates  prepared  by  D&M,  an  independent  petroleum  engineering 
consulting  firm  located  in  Dallas,  Texas,  utilizing  data  provided  by  our  internal  reservoir  engineering  team  and  is  the 
responsibility of management.  We rely on D&M’s expertise to ensure that our reserve estimates are prepared in compliance 
with SEC rules and regulations and that appropriate geologic, petroleum engineering, and evaluation principles and techniques 
are applied in accordance with practices generally recognized by the petroleum industry as presented in the publication of the 
Society  of  Petroleum  Engineers  entitled  “Standards  Pertaining  to  the  Estimating  and Auditing  of  Oil  and  Gas  Reserves 
Information (Revision as of February 19, 2007)”.  The person responsible for the preparation of the reserve report is a Senior 
Vice President at D&M; he is a Registered Professional Engineer in the State of Texas.  He received a Master of Science 
degree in Petroleum Engineering from the University of Texas in 1984, and he has in excess of 35 years of experience in oil 
and gas reservoir studies and evaluations.  Our Senior Vice President – Business Development and Technology is primarily 
responsible  for overseeing  the  independent  petroleum  engineering  firm  during  the  process.   Our  Senior Vice  President  – 
Business Development and Technology has a Bachelor of Science degree in Petroleum Engineering from the Colorado School 
of Mines and over 35 years of industry experience working with petroleum engineering and reserve estimates.  D&M relies 
on various data provided by our internal reservoir engineering team in preparing its reserve estimates, including such items 
as oil and natural gas prices, ownership interests, production information, operating costs, planned capital expenditures and 
other technical data.  Our internal reservoir engineering team consists of qualified petroleum engineers who maintain the 
Company’s  internal  evaluation  of  reserves  and  compare  the  Company’s  information  to  the  reserves  prepared  by  D&M.  

9

Denbury Resources Inc.

Management is responsible for designing the internal control procedures used in the preparation of our oil and gas reserves, 
which include verification of data input into reserve forecasting and economics evaluation software, as well as multi-discipline 
management  reviews.   The  internal  reservoir  engineering  team  reports  directly  to  our  Senior  Vice  President  –  Business 
Development and Technology.  In addition, our Board of Directors’ Reserves and Health, Safety and Environmental (“HSE”) 
Committee, on behalf of the Board of Directors, oversees the qualifications, independence, performance and hiring of our 
independent petroleum engineering firm and reviews the final report and subsequent reporting of our oil and natural gas reserve 
estimates.  The Chairman of the Reserves and HSE Committee holds a Ph.D. in Chemical Engineering from the Massachusetts 
Institute of Technology and bachelor’s degrees in Chemistry and Mathematics from Capital University in Ohio.  He has more 
than 35 years of industry experience, with responsibilities including reserves preparation and approval.

OIL AND NATURAL GAS OPERATIONS

Summary.  Our oil and natural gas properties are concentrated in the Gulf Coast and Rocky Mountain regions of the 
United States.  Currently our properties with proved and producing reserves in the Gulf Coast region are situated in Mississippi, 
Texas, and Louisiana, and in the Rocky Mountain region are situated in Montana, North Dakota and Wyoming.  Our primary 
focus is increasing the value of our properties through a combination of exploitation, drilling and proven engineering extraction 
practices, with the most significant emphasis relating to CO2 EOR operations.  Our current portfolio of CO2 EOR projects 
provides us significant oil production and reserve growth potential in the future, assuming crude oil prices are at levels that 
support the development of those projects.

We have been conducting and expanding EOR operations on our assets in the Gulf Coast region since 1999, and as a 
result, we currently have many more CO2 EOR projects in this region than in the Rocky Mountain region.  We began operations 
in the Rocky Mountain region in 2010 in connection with, and following, our merger with Encore Acquisition Company 
(“Encore”).  In 2012, as part of a significant sale and exchange transaction with Exxon Mobil Corporation (“ExxonMobil”), 
we sold to ExxonMobil our Bakken area assets in North Dakota and Montana in exchange for (1) $1.3 billion in cash, (2) 
operating interests in Hartzog Draw and Webster fields in Wyoming and Texas, respectively, and (3) an overriding royalty 
interest equivalent to an approximate one-third ownership interest in ExxonMobil’s CO2 reserves in LaBarge Field in Wyoming 
(the “Bakken Exchange Transaction”).  In the Gulf Coast region, we own what is, to our knowledge, the region’s only significant 
naturally occurring source of CO2, and these large volumes of naturally occurring CO2 give us a significant competitive 
advantage in this area.  In addition to this naturally occurring CO2 source, we utilize CO2 captured from industrial sources 
which would otherwise be released into the atmosphere (sometimes referred to as anthropogenic, man-made or industrial-
source CO2) in our tertiary operations, including CO2 from the LaBarge Field in Wyoming, which is captured in conjunction 
with processing helium from the LaBarge Field gas stream at ExxonMobil’s Shute Creek gas plant.  These industrial sources 
of  CO2 help  us  recover  additional  oil  from  mature  oil  fields  and,  we  believe,  also  provide  an  economical  way  to  reduce 
atmospheric CO2 emissions through the associated underground storage of CO2 which incidentally occurs as part of our oil-
producing EOR operations.

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Denbury Resources Inc.

Field Summary Table.  The following table provides a summary by field and region of selected proved oil and natural 
gas reserve information, including total proved reserve quantities as of December 31, 2019, and average daily production for 
2019,  all  based  on  Denbury’s  net  revenue  interest  (“NRI”).  The  reserve  estimates  presented  were  prepared  by  D&M, 
independent petroleum engineers located in Dallas, Texas.  We serve as operator of nearly all of our significant properties, in 
which we also own most of the interests, although typically less than a 100% working interest, and a lesser NRI due to royalties 
and other burdens.  For additional oil and natural gas reserves information, see Estimated Net Quantities of Proved Oil and 
Natural Gas Reserves and Present Value of Estimated Future Net Revenues above and Supplemental Oil and Natural Gas 
Disclosures (Unaudited) to the Consolidated Financial Statements.

Proved Reserves as of December 31, 2019(1)

2019 Average Daily
Production

Oil
(MBbls)

Natural 
Gas
(MMcf)

MBOEs

% of 
Company 
Total
MBOEs

Oil
(Bbls/d)

Natural 
Gas
(Mcf/d)

Average
2019 NRI

Tertiary oil and gas properties

Gulf Coast region

Delhi

Hastings

Heidelberg

Oyster Bayou

Tinsley

West Yellow Creek
Mature properties(2)

14,565

31,641

20,792

16,965

15,553

1,318

16,745

Total Gulf Coast region

117,579

Rocky Mountain region

Bell Creek

Salt Creek

Grieve

Total Rocky Mountain region

Total tertiary properties

Non-tertiary oil and gas properties

Gulf Coast region

Texas(3)
Mississippi and other

Total Gulf Coast region

Rocky Mountain region
Cedar Creek Anticline(4)
Other

Total Rocky Mountain region

Total non-tertiary properties

13,523

6,158

977

20,658

138,237

17,151

1,733

18,884

67,003

2,009

69,012

87,896

Total continuing properties

226,133

—

—

—

—

—

—
—
—

—

—

—

—

—

7,180

3,523

10,703

10,077

3,554

13,631

24,334

24,334

14,565

31,641

20,792

16,965

15,553

1,318

16,745

6.3%

13.7%

9.0%

7.4%

6.8%

0.6%

7.3%

4,324

5,403

4,195

4,345

4,608

640

6,422

117,579

51.1%

29,937

13,523

6,158

977

20,658

138,237

18,348

2,320

20,668

68,683

2,601

71,284

91,952

5.9%

2.7%

0.4%

9.0%

60.1%

8.0%

1.0%

9.0%

29.8%

1.1%

30.9%

39.9%

230,189

100.0%

5,228

2,143

53

7,424

37,361

3,865

609

4,474

13,818

805

14,623

19,097

56,458

Property sales

Property divestitures(5)
Company Total

—

—

—

—%

214

226,133

24,334

230,189

100.0%

56,672

—

—

—

—

—

—

—

—

—

—

—

—

—

2,672

2,203

4,875

1,632

2,739

4,371

9,246

9,246

—

9,246

58.1%

79.9%

81.3%

87.3%

82.2%

42.5%

80.2%

76.4%

84.9%

19.0%

20.5%

42.1%

66.4%

81.4%

13.5%

47.2%

80.1%

62.2%

78.8%

67.0%

66.6%

64.2%

66.6%

(1)  Reserve estimates were prepared in accordance with FASC Topic 932, Extractive Industries – Oil and Gas, using the 
arithmetic averages of the first-day-of-the-month NYMEX commodity price for each month during 2019, which were 
$55.69 per Bbl for crude oil and $2.58 per MMBtu for natural gas.

11

Denbury Resources Inc.

(2)  Mature properties include Brookhaven, Cranfield, Eucutta, Little Creek, Mallalieu, Martinville, McComb and Soso fields 

in Mississippi.

(3)  Texas non-tertiary production includes production associated with the Pending Gulf Coast Working Interests Sale (see 
Management’s Discussion and Analysis of Financial Condition and Results of Operations – Overview – Pending Sale of 
Working Interests in Certain Texas Fields).

(4)  The Cedar Creek Anticline consists of a series of 13 different operating areas.

(5)  Includes production from Citronelle Field sold in July 2019.

Enhanced Oil Recovery Overview.  CO2 used in EOR is one of the most efficient tertiary recovery mechanisms for 
producing crude oil.  When injected under pressure into underground, oil-bearing rock formations, CO2 acts somewhat like 
a solvent as it travels through the reservoir rock, mixing with and modifying the characteristics of the oil so it can be produced 
and sold.  The terms “tertiary flood,” “CO2 flood” and “CO2 EOR” are used interchangeably throughout this document.

While enhanced oil recovery projects utilizing CO2 have been successfully performed by numerous oil and gas companies 
in a wide range of oil-bearing reservoirs in different oil-producing basins, we believe our investments, experience and acquired 
knowledge give us a strategic and competitive advantage in the areas in which we operate.  We apply what we have learned 
and developed over the years to improve and increase sweep efficiency within the CO2 EOR projects we operate.

We began our CO2 operations in August 1999, when we acquired Little Creek Field, followed by our acquisition of Jackson 
Dome CO2 reserves and the NEJD pipeline in 2001.  Based upon our success at Little Creek and the ownership of the CO2
reserves, we began to transition our capital spending and acquisition efforts to focus more heavily on CO2 EOR and, over 
time, transformed our strategy to focus primarily on owning and operating oil fields that are well suited for CO2 EOR projects.  
Prior to tertiary flooding, we strive to maximize the currently sizeable primary and secondary production from our prospective 
tertiary fields and from fields in which tertiary floods have commenced but still contain significant non-tertiary production.  Our 
asset base today almost entirely consists of, or otherwise relates to, oil fields that we are currently flooding with CO2 or plan 
to flood with CO2 in the future, or assets that produce CO2.

Our tertiary operations have grown so that (1) 60% of our proved reserves at December 31, 2019 are proved tertiary oil 
reserves; (2) 64% of our 2019 total production was related to tertiary oil operations (on a BOE basis); and (3) 63% of our 
2019 capital expenditures (excluding acquisitions) were related to our tertiary oil operations.  At year-end 2019, the proved 
oil reserves in our tertiary recovery oil fields had an estimated PV-10 Value of approximately $1.8 billion, or 69% of our total 
PV-10 Value.  In addition, there are significant probable and possible reserves at several other fields for which tertiary operations 
are underway or planned.

Although the up-front cost of tertiary production infrastructure and time to construct pipelines and production facilities 
is greater than in primary oil recovery in most circumstances, we believe tertiary recovery has several favorable, offsetting 
and unique attributes, including (1) a lower exploration risk, as we are operating oil fields that have significant historical 
production  and  reservoir  and  geological  data,  (2)  lower  production  decline  rates  than  unconventional  development,  (3) 
reasonable return metrics at our anticipated long-term prices, (4) limited competition for this recovery method in our geographic 
regions and a strategic advantage due to our ownership of the CO2 reserves and CO2 pipeline infrastructure, (5) our EOR 
operations are generally less disruptive to new habitats in comparison to other oil and natural gas development because we 
further develop existing (as opposed to new) oil fields, and (6) through our oil-producing EOR operations, we concurrently 
store CO2 captured from industrial sources in the same underground formations that previously trapped and stored oil and 
natural gas.

12

Denbury Resources Inc.

Tertiary Oil Properties

Gulf Coast Region

CO2 Sources and Pipelines

Jackson Dome.  Our primary Gulf Coast CO2 source, Jackson Dome, located near Jackson, Mississippi, was discovered 
during the 1970s by oil and gas companies that were exploring for hydrocarbons.  This large and relatively pure source of 
naturally occurring CO2 (98% CO2) is, to our knowledge, the only significant underground deposit of CO2 in the United States 
east of the Mississippi River.  Together with the related CO2 pipeline infrastructure, Jackson Dome provides us a significant 
strategic advantage in the acquisition of properties in Mississippi, Louisiana and southeastern Texas that are well suited for 
CO2 EOR.

We acquired Jackson Dome in February 2001 in a purchase that also gave us ownership and control of the NEJD CO2
pipeline and provided us with a reliable supply of CO2 at a reasonable and predictable cost for our Gulf Coast CO2 tertiary 
recovery  operations.  Since  February  2001,  we  have  acquired  and  drilled  numerous  CO2-producing  wells,  significantly 
increasing our estimated proved Gulf Coast CO2 reserves from approximately 800 Bcf at the time of acquisition of Jackson 
Dome to approximately 4.8 Tcf as of December 31, 2019.  The proved CO2 reserve estimates are based on a gross (8/8ths) 
basis, of which our net revenue interest is approximately 3.8 Tcf, and is included in the evaluation of proved CO2 reserves 
prepared by D&M, an independent petroleum engineering consulting firm.  In discussing our available CO2 reserves, we make 
reference to the gross amount of proved and probable reserves, as this is the amount that is available both for our own tertiary 
recovery programs and for industrial users who are customers of Denbury and others, as we are responsible for distributing 
the entire CO2 production stream.

In addition to our proved reserves, we estimate that we have 910.1 Bcf, on a gross (8/8ths) basis, of probable CO2 reserves 
at Jackson Dome.  While the majority of these probable reserves are located in structures that have been drilled and tested, 
such reserves are still considered probable reserves because (1) the original well is plugged; (2) they are located in fault blocks 
that are immediately adjacent to fault blocks with proved reserves; or (3) they are reserves associated with increasing the 
ultimate recovery factor from our existing reservoirs with proved reserves.  In addition, a significant portion of these probable 
reserves at Jackson Dome are located in undrilled structures where we have sufficient subsurface and seismic data indicating 
geophysical attributes that, coupled with our historically high drilling success rate, provide a reasonably high degree of certainty 
that CO2 is present.

In addition to our drilling at Jackson Dome, we have the capability to expand our processing and dehydration capacities 
and install additional pipelines and/or pumping stations necessary to transport the CO2 through our controlled pipeline network.  
We expect our current proved reserves of CO2, coupled with a risked drilling program at Jackson Dome and CO2 expected to 
be captured from industrial sources, to provide sufficient quantities of CO2 for us to develop our proved and probable EOR 
reserves in the Gulf Coast region.  In the future, we believe that once a CO2 flood in a field reaches its productive economic 
limit, we could recycle a portion of the CO2 that remains in that field’s reservoir and utilize it for oil production in another 
field’s tertiary flood.

In the Gulf Coast region, approximately 84% of our average daily CO2 produced from Jackson Dome or captured from 
industrial sources in 2019 was used in our tertiary recovery operations, compared to 83% in 2018 and 87% in 2017, with the 
balance delivered to third-party industrial users.  During 2019, we used an average of 511 MMcf/d of CO2 (including CO2
captured from industrial sources) for our tertiary activities.

Gulf Coast CO2 Captured from Industrial Sources.  In addition to our natural source of CO2, we are currently party 
to two long-term contracts to purchase CO2 from industrial plants.  We have purchased CO2 from an industrial facility in Port 
Arthur, Texas since 2012 and from an industrial facility in Geismar, Louisiana since 2013, which supplied an average of 
approximately 53 MMcf/d of CO2 to our EOR operations during 2019.  Additionally, we are in ongoing discussions with other 
parties regarding plans to construct plants near the Green Pipeline.  In order to capture such volumes, we (or the plant owner) 
would need to install additional equipment, which includes, at a minimum, compression and dehydration facilities.

Gulf  Coast  CO2  Pipelines.    We  acquired  the  183-mile  NEJD  CO2  pipeline  that  runs  from  Jackson  Dome  to  near 
Donaldsonville, Louisiana, as part of the 2001 acquisition of our Jackson Dome CO2 source.  Since 2001, we have acquired 

13

Denbury Resources Inc.

or constructed nearly 750 miles of CO2 pipelines, and as of December 31, 2019, we have access to nearly 925 miles of CO2 
pipelines, which gives us the ability to deliver CO2 throughout the Gulf Coast region.  In addition to the NEJD CO2 pipeline, 
the major pipelines in the Gulf Coast region are the Free State Pipeline (90 miles), Delta Pipeline (110 miles), Green Pipeline 
Texas (120 miles), and Green Pipeline Louisiana (200 miles).

Completion of the Green Pipeline allowed for the first CO2 injection into Hastings Field, located near Houston, Texas, 
in 2010, and gives us the ability to deliver CO2 to oil fields all along the Gulf Coast from Baton Rouge, Louisiana, to Alvin, 
Texas.  At the present time, most of the CO2 flowing in the Green Pipeline is delivered from the Jackson Dome area, but also 
includes the CO2 we are receiving from the industrial facilities in Port Arthur, Texas and Geismar, Louisiana, and we are 
currently transporting a third party’s CO2 for a fee to the sales point at Hastings Field.  We currently have ample capacity 
within the Green Pipeline to handle additional volumes that may be required to develop our inventory of CO2 EOR projects 
in this area.

Tertiary Properties with Tertiary Production and Proved Tertiary Reserves at December 31, 2019

Delhi Field.  Delhi Field is located east of Monroe, Louisiana.  In May 2006, we purchased our initial interest in Delhi 
for $50 million.  We began well and facility development in 2008, began delivering CO2 to the field in 2009 via the Delta 
Pipeline, which runs from Tinsley Field to Delhi Field, and first tertiary production occurred at Delhi Field in 2010.  During 
2016, we completed construction of a natural gas liquids extraction plant, which provides us with the ability to sell natural 
gas liquids from the produced stream, improve the efficiency of the CO2 flood, and utilize extracted methane to power the 
plant and reduce field operating expenses.  Production from Delhi Field in the fourth quarter of 2019 averaged 4,085 Bbls/d, 
compared to 4,526 Bbls/d in the fourth quarter of 2018.  During 2020, we plan to perform conformance work at Delhi Field.

Hastings Field.  Hastings Field is located south of Houston, Texas.  We acquired a majority interest in this field in February 
2009 for $247 million.  We initiated CO2 injection in the West Hastings Unit during 2010 upon completion of the construction 
of the Green Pipeline.  Due to the large vertical oil column that exists in the field, we are developing the Frio reservoir using 
dedicated CO2 injection and producing wells for each of the major sand intervals.  We began producing oil from our EOR 
operations at Hastings Field in 2012, and we booked initial proved tertiary reserves for the West Hastings Unit in 2012.  The 
Company also has future plans for continued tertiary development of existing proved undeveloped reserves at the field.  During 
the fourth quarter of 2019, tertiary production from Hastings Field averaged 5,097 Bbls/d, compared to 5,480 Bbls/d in the 
fourth quarter of 2018.

Heidelberg Field.  Heidelberg Field is located in Mississippi off of the Free State Pipeline and consists of an East Unit 
and a West Unit.  Construction of the CO2 facility, connecting pipeline and well work commenced on the West Heidelberg 
Unit during 2008, with our first CO2 injections into the Eutaw zone.  Our first tertiary oil production occurred in 2009, and 
we began flooding the Christmas and Tuscaloosa zones in 2013 and 2014, respectively.  During 2019, we expanded our tertiary 
flood of the Christmas zone and invested in non-tertiary behind pipe projects.  During the fourth quarter of 2019, tertiary 
production at Heidelberg Field averaged 4,409 Bbls/d, compared to 4,269 Bbls/d in the fourth quarter of 2018.  Our 2020 
development plans for Heidelberg Field include conformance work, with future plans for continued tertiary development of 
existing proved undeveloped reserves at the field. 

Oyster Bayou Field.  We acquired a majority interest in Oyster Bayou Field in 2007.  The field is located in southeast 
Texas, east of Galveston Bay, and is somewhat unique when compared to our other CO2 EOR projects because the field covers 
a relatively small area of 3,912 acres.  We began CO2 injections into Oyster Bayou Field in 2010, commenced tertiary production 
in 2011 from the Frio A-1 zone, and booked initial proved tertiary reserves for the field in 2012.  In 2014, we completed 
development of the Frio A-2 zone.  During the fourth quarter of 2019, tertiary production at Oyster Bayou Field averaged 
4,261 Bbls/d, compared to 4,785 Bbls/d in the fourth quarter of 2018.  During 2020, we plan to invest in down-dip expansion 
of the Frio A-2 zone.

Tinsley Field.  We acquired Tinsley Field in 2006.  This Mississippi field was discovered and first developed in the 1930s 
and is separated by different fault blocks.  As is the case with the majority of fields in Mississippi, Tinsley Field produces 
from multiple reservoirs.  Our CO2 enhanced oil recovery operations at Tinsley Field have thus far targeted the Woodruff 
formation, although there is additional potential in the Perry sandstone and other smaller reservoirs.  We commenced tertiary 
oil  production  from  Tinsley  Field  in  2008  and  substantially  completed  development  of  the  Woodruff  formation  during 
2014.  During the fourth quarter of 2019, tertiary oil production from the field averaged 4,343 Bbls/d, compared to 5,033 

14

Denbury Resources Inc.

Bbls/d in the fourth quarter of 2018.  Although production from Tinsley Field is believed to have peaked in 2015 and is 
generally on decline, we continue to evaluate future potential investment opportunities in this field.

In addition to our tertiary operations at Tinsley Field, during 2018 and 2019, we conducted exploitation drilling in other 
oil-bearing formations in the field, and we continue to evaluate exploitation opportunities in additional horizons underlying 
the existing CO2 EOR flood.

West Yellow Creek Field.  We acquired an approximate 48% non-operated working interest in West Yellow Creek Field 
in Mississippi in March 2017 for approximately $16 million, a field in which the operator had previously invested significant 
capital converting the field to a CO2 EOR flood.  Under our arrangement with the operator, we supply CO2 to the field for a 
fee.  West Yellow Creek Field is in close proximity and analogous to Eucutta Field, a very successful CO2 flood that we 
developed and continue to operate.  We booked initial proved tertiary oil reserves at West Yellow Creek Field as of year-end 
2017 and commenced tertiary production in early 2018.  During the fourth quarter of 2019, tertiary oil production from the 
field averaged 807 Bbls/d compared to 375 Bbls/d in the fourth quarter of 2018.  Development of the field is ongoing, with 
future plans for continued tertiary development of the initial formation within the field.

Mature properties.  Mature properties include our longest-producing properties which are generally located along our 
NEJD CO2 pipeline in southwest Mississippi and Louisiana and our Free State Pipeline in east Mississippi.  This group of 
properties includes our initial CO2 field, Little Creek, as well as several other fields (Brookhaven, Cranfield, Eucutta, Mallalieu, 
Martinville,  McComb  and  Soso  fields).  These  fields  accounted  for  17%  of  our  total  2019  CO2  EOR  production  and 
approximately 7% of our year-end proved reserves.  These fields have been producing under CO2 flood for many years, in 
many cases more than a decade, and their production is generally declining, though we continue to evaluate future potential 
investment opportunities in these fields.

Future Tertiary Properties with No Tertiary Production or Proved Tertiary Reserves at December 31, 2019

Pending Sale of Working Interests in Certain Texas Fields.  In December 2019, we entered into a definitive agreement 
to sell half of our nearly 100% working interest positions in four conventional southeast Texas oil fields (consisting of Webster, 
Thompson, Manvel and East Hastings) for $50 million cash and a carried interest in ten wells to be drilled by the purchaser.  
The sale is currently expected to occur in early March 2020.  Under the agreement, the purchaser is committed to funding 
100% of the capital required to drill and complete an initial ten horizontal wells across the fields, with the first of the ten wells 
to be spud within six months of closing and with all ten wells to be completed within 18 months after closing.  On these initial 
ten wells, Denbury will receive a 6.25% overriding royalty interest prior to the combined payout of the wells in a specified 
field and subsequent to payout, Denbury will receive production revenues from, and bear the cost of, its 50% working interest 
in each well.  As part of the agreement, we will retain 100% ownership of the future Webster Unit CO2 flood, wherein (1) the 
purchaser may elect to participate in the future CO2 flood through reimbursement to Denbury of the purchaser’s working 
interest share of project costs incurred to date, or (2) if the purchaser declines to participate in the CO2 flood, we have the 
right to repurchase the purchaser’s working interest in Webster Field under a contractually agreed valuation mechanism.

Webster Field.  We acquired our interest in Webster Field in 2012 as part of the Bakken Exchange Transaction.  The 
field is located southeast of Houston, Texas, approximately eight miles northeast of our Hastings Field which we are currently 
flooding with CO2.  At December 31, 2019, Webster Field had estimated proved non-tertiary reserves of approximately 3.2 
MMBOE, net to our interest, all of which are proved developed.  During the fourth quarter of 2019, non-tertiary production 
at Webster Field, including production related to the Pending Gulf Coast Working Interests Sale (see Pending Sale of Working 
Interests in Certain Texas Fields above), averaged 923 BOE/d, compared to 841 BOE/d in the fourth quarter of 2018.  Webster 
Field is geologically similar to our Hastings Field, producing oil from the Frio zone at similar depths; as a result, we believe 
it is well suited for CO2 EOR.  In 2014, we completed a nine-mile lateral between the Green Pipeline and Webster Field, which 
we plan will eventually deliver CO2 to the field.  The timing of the development of a CO2 flood at Webster Field is primarily 
dependent upon capital availability and priorities and future oil prices.

Conroe Field.  Conroe Field, our largest potential tertiary flood in the Gulf Coast region, is located north of Houston, 
Texas.  We acquired a majority interest in this field in 2009 for $271 million in cash and 11.6 million shares of Denbury 
common  stock,  for  a  total  aggregate  value  of  $439  million.  Conroe  Field  had  estimated  proved  non-tertiary  reserves  of 
approximately 9.5 MMBOE at December 31, 2019, net to our interest, all of which are proved developed.  During the fourth 

15

Denbury Resources Inc.

quarter of 2019, non-tertiary production at Conroe Field averaged 1,861 BOE/d, compared to 1,970 BOE/d in the fourth 
quarter of 2018.

To initiate a CO2 flood at Conroe Field, a pipeline must be constructed so that CO2 can be delivered to the field.  This 
pipeline, which is planned as an extension of our Green Pipeline, is preliminarily estimated to cover approximately 90 miles 
at a cost of approximately $220 million.  Our current plan for initiating a CO2 flood at Conroe Field is scheduled several years 
from now, the timing of which may change depending on capital availability and priorities, future oil prices and pipeline 
construction.

In addition to the currently-producing oil-bearing formations at Conroe Field, we are evaluating exploitation opportunities 
in other formations.  We currently do not have any additional wells planned for 2020 but continue to evaluate additional 
opportunities and plan to de-risk other areas of the field in the future.

Thompson Field.  We acquired our interest in Thompson Field in June 2012 for $366 million.  The field is located in 
Texas, approximately 18 miles west of our Hastings Field.  Thompson Field had estimated proved non-tertiary reserves of 
approximately 4.3 MMBOE at December 31, 2019, net to our interest, all of which are proved developed.  During the fourth 
quarter of 2019, non-tertiary production at Thompson Field, including production related to the Pending Gulf Coast Working 
Interests Sale (see Pending Sale of Working Interests in Certain Texas Fields above), averaged 1,008 BOE/d, compared to 
942 BOE/d in the fourth quarter of 2018.  Thompson Field is geologically similar to Hastings Field, producing oil from the 
Frio zone at similar depths, and we therefore believe it has CO2 EOR potential.  Under the terms of the Thompson Field 
acquisition agreement, after the initiation of CO2 injection, the seller will retain approximately a 5% gross revenue interest 
(less severance taxes) once average monthly oil production exceeds 3,000 Bbls/d.  The timing of the development of a CO2
flood at Thompson Field is primarily dependent upon capital availability and priorities and future oil prices.

Rocky Mountain Region

CO2 Sources and Pipelines

LaBarge Field.  We acquired an overriding royalty interest equivalent to an approximate one-third ownership interest in 
ExxonMobil’s CO2 reserves in LaBarge Field in the fourth quarter of 2012 as part of the Bakken Exchange Transaction.  
LaBarge Field is located in southwestern Wyoming, and as of December 31, 2019, our interest in LaBarge Field consisted of 
approximately 1.1 Tcf of proved CO2 reserves.

During 2019, we received an average of approximately 97 MMcf/d of CO2 from the Shute Creek gas processing plant at 
LaBarge Field that we used in our Rocky Mountain region CO2 floods.  Based on current capacity, and subject to availability 
of CO2, we currently expect our CO2 volumes from Shute Creek to increase in future years.  We pay ExxonMobil a fee to 
process and deliver the CO2, which we use in our Rocky Mountain region CO2 floods.

Other Rocky Mountain CO2 Sources.  We currently receive all of the CO2 from the ConocoPhillips-operated Lost Cabin 
gas plant in central Wyoming, which we currently expect to provide us as much as 30 MMcf/d of CO2 for use in our Rocky 
Mountain region CO2 floods.  We currently estimate that our existing CO2 sources, plus additional CO2 from those or other 
CO2 sources in the region, are sufficient to carry out our base Rocky Mountain region EOR development plans.

Rocky Mountain CO2 Pipelines.  The 20-inch Greencore Pipeline in Wyoming is the first CO2 pipeline we constructed 
in  the  Rocky  Mountain  region.  We  plan  to  use  the  pipeline  as  our  trunk  line  in  the  Rocky  Mountain  region,  eventually 
connecting our various Rocky Mountain region CO2 sources to the Cedar Creek Anticline in eastern Montana and western 
North Dakota.  The 232-mile pipeline begins at the ConocoPhillips-operated Lost Cabin gas plant in Wyoming and terminates 
at Bell Creek Field in Montana.  We completed construction of the pipeline in 2012 and received our first CO2 deliveries from 
the ConocoPhillips-operated Lost Cabin gas plant during 2013.  During 2014, we completed construction of an interconnect 
between our Greencore Pipeline and an existing third-party CO2 pipeline in Wyoming, which enables us to transport CO2
from LaBarge Field to our Bell Creek Field.

In mid-2018, we sanctioned the CO2 enhanced oil recovery development project at Cedar Creek Anticline, which requires 
a 105-mile extension of the Greencore CO2 pipeline to CCA from Bell Creek Field.  The capital outlay for the pipeline is 

16

Denbury Resources Inc.

projected to be approximately $150 million, of which we have incurred approximately $45 million through December 31, 
2019 (see also Cedar Creek Anticline CO2 EOR Project below for further discussion).

Tertiary Properties with Tertiary Production and Proved Tertiary Reserves at December 31, 2019

Bell Creek Field.  We acquired our interest in Bell Creek Field in southeast Montana as part of the Encore merger in 
2010.  The oil-producing reservoir in Bell Creek Field is a sandstone reservoir with characteristics similar to those we have 
successfully flooded with CO2 in the Gulf Coast region.  During 2013, we began first CO2 injections into Bell Creek Field, 
recorded our first tertiary oil production, and booked initial proved tertiary reserves.  Tertiary production during the fourth 
quarter of 2019 averaged 5,618 Bbls/d of oil, compared to 4,421 Bbls/d in the fourth quarter of 2018.  During 2018, we 
completed  the  phase  five  expansion  at  the  field,  and  in April  2019  commenced  CO2 injection  into  phase  six  of  the  field 
development.  The initial production response from the phase six expansion of the flood occurred in early 2020, though 
production will slowly ramp up during 2020 as additional wells begin to respond.

Grieve Field.  Under a 2011 farm-in agreement, we obtained a 65% working interest in Grieve Field, located in Natrona 
County, Wyoming, in exchange for developing the Grieve Field CO2 flood.  During 2016, the Company and its joint venture 
partner in Grieve Field revised their development arrangement for the field so that our partner funded $55 million of the 
remaining estimated capital to complete development of the facility and fieldwork in exchange for a 14% higher working 
interest and a disproportionate sharing of revenue from the first 2 million barrels of production.  Thus, our working interest 
in the field was reduced from 65% to 51%, and our net revenue interest on the first million barrels of production is approximately 
20%.  We commenced tertiary production from Grieve Field during the fourth quarter of 2018 and booked initial proved 
tertiary reserves during 2019.  Tertiary production during the fourth quarter of 2019 averaged 60 Bbls/d of oil, compared to 
20 Bbls/d in the fourth quarter of 2018.

Salt Creek Field.  We acquired our 23% non-operated working interest in Salt Creek Field in Wyoming for approximately 
$72 million in June 2017.  Tertiary production during the fourth quarter of 2019 averaged 2,223 Bbls/d of oil, compared to 
2,107 Bbls/d in the fourth quarter of 2018.
Future Tertiary Properties with No Tertiary Production or Proved Tertiary Reserves at December 31, 2019

Cedar Creek Anticline.  CCA is the largest potential EOR property that we own and currently our largest producing 
property, contributing approximately 24% of our 2019 total production.  Historical production from the property has primarily 
been from the Red River interval.  The field is primarily located in Montana but extends over such a large area (approximately 
126 miles) that it also extends into North Dakota.  CCA is a series of 13 different operating areas on a common geological 
trend, each of which could be considered a field by itself.  We acquired our initial interest in CCA as part of the Encore merger 
in 2010 and acquired additional interests from a wholly-owned subsidiary of ConocoPhillips in 2013 for $1.0 billion, adding 
42.2 MMBOE of incremental proved reserves at that date.  Production from CCA averaged 13,730 BOE/d during the fourth 
quarter of 2019, compared to production during the fourth quarter of 2018 of 14,961 BOE/d.  The non-tertiary proved reserves 
associated with CCA were 68.7 MMBOE, net to our interest, as of December 31, 2019.

In addition to the Red River interval, CCA contains other oil-bearing intervals including Mission Canyon and Charles B.  
We began pursuing these additional exploitation opportunities in late 2017.  We have drilled nine successful Mission Canyon 
exploitation wells and a successful initial test well in Cabin Creek’s Charles B formation over the last few years.  We continue 
to evaluate the Charles B formation and believe it has characteristics that would make it a good candidate for secondary or 
tertiary flooding.

Cedar Creek Anticline CO2 EOR Project.  CCA is located approximately 110 miles north of Bell Creek Field, and our 
current plan is to connect this field to our Greencore Pipeline by the end of 2020.  In June 2018, we announced the sanctioning 
of the CO2 enhanced oil recovery development project at Cedar Creek Anticline.  The estimated capital outlay to first tertiary 
production includes $150 million for a 105-mile extension of the Greencore CO2 pipeline from Bell Creek Field discussed 
above and an additional $150 million for facilities, well work and field development in the Red River formation at East Lookout 
Butte and Cedar Hills South fields in CCA.  Approximately $50 million has been incurred through December 31, 2019, 
primarily related to purchase of pipe for the planned CO2 pipeline extension.  First tertiary production is currently expected 
in the second half of 2022 or early 2023, with additional phases of development expected to target the Interlake, Stony Mountain 
and Red River formations at Cabin Creek Field.  In light of the current oil price environment and the Company’s desire to 
preserve ongoing liquidity, the Company is continuing to evaluate the CCA tertiary development timeline, and in particular 

17

Denbury Resources Inc.

the construction of the pipeline in 2020, and currently anticipates finalizing its plans in the second quarter of 2020.  See further 
discussion of the Company’s 2020 capital plans at Management’s Discussion and Analysis of Financial Condition and Results 
of Operations – Capital Resources and Liquidity – 2020 Capital Budget.

Hartzog Draw Field.  We acquired our interest in Hartzog Draw Field in 2012 as part of the Bakken Exchange Transaction.  
The field is located in the Powder River Basin of northeastern Wyoming, approximately 12 miles from our Greencore Pipeline.  
Hartzog Draw Field had estimated proved reserves of approximately 2.6 MMBOE at December 31, 2019, net to our interest, 
0.6 MMBOE of which relate to the natural gas producing Big George coal zone.  During the fourth quarter of 2019, non-
tertiary production averaged 1,172 BOE/d, compared to 1,327 BOE/d in the fourth quarter of 2018.  Industry activity around 
this field has been increasing for the last several years, with several operators testing various formations such as the Turner, 
Niobrara, Shannon, Parkman and Mowry for potential development.  We believe the oil reservoir characteristics of Hartzog 
Draw Field make it well suited for CO2 EOR in the future.  The timing of development of a CO2 flood at Hartzog Draw Field 
is primarily dependent upon capital availability and priorities and future oil prices.

Other Non-Tertiary Oil Properties

Despite the majority of our oil and natural gas properties discussed above consisting of either existing or planned future 
tertiary floods, we also produce oil and natural gas either from fields in both our Gulf Coast and Rocky Mountain regions that 
are not amenable to EOR or from specific reservoirs (within an existing tertiary field) that are not amenable to EOR.  For 
example, at Heidelberg Field, we produce natural gas from the Selma Chalk reservoir, which is separate from the Christmas 
and Eutaw reservoirs currently being flooded with CO2.  Continuing production from these other non-tertiary properties totaled 
1,567 BOE/d during the fourth quarter of 2019, compared to 1,611 BOE/d during the fourth quarter of 2018.

OIL AND GAS ACREAGE, PRODUCTIVE WELLS AND DRILLING ACTIVITY

In the data below, “gross” represents the total acres or wells in which we own a working interest and “net” represents the 
gross acres or wells multiplied by our working interest percentage.  For the wells that produce both oil and gas, the well is 
typically classified as an oil or natural gas well based on the ratio of oil to natural gas production.

Oil and Gas Acreage

The following table sets forth our acreage position at December 31, 2019:

Gulf Coast region

Rocky Mountain region

Total

Developed

Undeveloped

Total

Gross

188,770

362,327

551,097

Net

155,270

315,029

470,299

Gross

286,922

122,321

409,243

Net

18,374

22,969

41,343

Gross

475,692

484,648

960,340

Net

173,644

337,998

511,642

The percentage of our net undeveloped acreage that is subject to expiration over the next three years, if not renewed, is 

approximately 4% in 2020, 11% in 2021 and 7% in 2022.

18

  
 
 
Productive Wells

Denbury Resources Inc.

The following table sets forth our gross and net productive oil and natural gas wells as of December 31, 2019:

Producing Oil Wells

Producing Natural Gas Wells

Total

Gross

Net

Gross

Net

Gross

Net

Operated wells

Gulf Coast region

Rocky Mountain region

Total

Non-operated wells

Gulf Coast region

Rocky Mountain region

Total
Total wells

Gulf Coast region

Rocky Mountain region

Total

Drilling Activity

1,111

965

2,076

43

591

634

1,154

1,556

2,710

1,045

919

1,964

18

132

150

1,063

1,051

2,114

128

268

396

—

2

2

128

270

398

120

174

294

—

1

1

120

175

295

1,239

1,233

2,472

43

593

636

1,282

1,826

3,108

1,165

1,093

2,258

18

133

151

1,183

1,226

2,409

The following table sets forth the results of our drilling activities over the last three years.  As of December 31, 2019, we 

did not have any wells in progress.

Exploratory wells(1)
Productive(2)
Non-productive(3)
Development wells(1)

Productive(2)
Non-productive(3)(4)

Total

2019

2018

2017

Gross

Net

Gross

Net

Gross

Net

Year Ended December 31,

1

—

19

—

20

1

—

18

—

19

2

—

14

3

19

2

—

12

3

17

—

—

2

—

2

—

—

2

—

2

(1)  An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be 
productive of oil or natural gas in another reservoir.  Generally, an exploratory well is any well that is not a development 
well, an extension well, a service well or a stratigraphic test well.  A development well is a well drilled within the proved 
area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

(2)  A productive well is an exploratory or development well drilled and completed during the year and found to be capable 

of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well.

(3)  A non-productive well is an exploratory or development well that is not a productive well.

(4)  During 2019, 2018 and 2017, an additional 7, 4 and 3 wells, respectively, were drilled for water or CO2 injection purposes.

19

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
The following table summarizes sales volumes, sales prices and production cost information for our net oil and natural 

gas production for the years ended December 31, 2019, 2018 and 2017:

Denbury Resources Inc.

Net sales volume

Gulf Coast region

Oil (MBbls)

Natural gas (MMcf)

Total Gulf Coast region (MBOE)

Rocky Mountain region

Oil (MBbls)

Natural gas (MMcf)

Total Rocky Mountain region (MBOE)

Total Company (MBOE)

Average sales prices – excluding impact of derivative settlements

Gulf Coast region

Oil (per Bbl)

Natural gas (per Mcf)

Rocky Mountain region

Oil (per Bbl)

Natural gas (per Mcf)

Total Company

Oil (per Bbl)

Natural gas (per Mcf)

Average production cost (per BOE sold)(1)

Gulf Coast region

Rocky Mountain region

Total Company

(1)  Excludes oil and natural gas ad valorem and production taxes.

PRODUCTION AND UNIT PRICES

Year Ended December 31,

2019

2018

2017

12,638

1,779

12,935

8,047

1,595

8,313

21,248

13,484

1,973

13,813

7,880

1,988

8,211

22,024

$

$

$

$

60.32

$

67.75

$

2.49

3.16

55.02

$

63.30

$

1.57

2.01

58.26

$

66.11

$

2.06

2.58

22.49

$

22.22

$

22.40
22.46

22.27
22.24

14,114

1,995

14,447

7,205

2,141

7,562

22,009

51.19

2.98

49.58

1.88

50.64

2.41

20.48

20.09
20.35

Further information regarding average production rates, unit sales prices and unit costs per BOE are set forth under Item 
7,  Management’s  Discussion  and  Analysis  of  Financial  Condition  and  Results  of  Operations  –  Results  of  Operations  – 
Operating Results Table, included herein.

TITLE TO PROPERTIES

As is customary in the oil and natural gas industry, Denbury conducts a limited title examination at the time of its acquisition 
of  properties  or  leasehold  interests  targeted  for  enhanced  recovery,  and  curative  work  is  performed  with  respect  to 
significant defects on higher-value properties of the greatest significance.  We believe that title to our oil and natural gas 

20

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Denbury Resources Inc.

properties is good and defensible, subject only to such exceptions that we believe do not materially interfere with the use of 
such properties, including encumbrances, easements, restrictions and royalty, overriding royalty and other similar interests.

SIGNIFICANT OIL AND GAS PURCHASERS AND PRODUCT MARKETING

Oil and natural gas sales are made on a day-to-day basis or under short-term contracts at the current area market price.  
We would not expect the loss of any single purchaser to have a material adverse effect upon our operations; however, the loss 
of a large single purchaser could potentially reduce the competition for our oil and natural gas production, which in turn could 
negatively impact the prices we receive.  For the year ended December 31, 2019, three purchasers accounted for 10% or more 
of our oil and natural gas revenues: Plains Marketing LP (32%), Hunt Crude Oil Supply Company (11%) and Sunoco Inc. 
(11%).  For the year ended December 31, 2018, two purchasers accounted for 10% or more of our oil and natural gas revenues: 
Plains  Marketing  LP  (24%)  and  Hunt  Crude  Oil  Supply  Company  (10%).    For  the  year  ended  December  31,  2017,  two 
purchasers accounted for 10% or more of our oil and natural gas revenues: Plains Marketing LP (22%) and Marathon Petroleum 
Company (10%).

Our ability to market oil and natural gas depends on many factors beyond our control, including the extent of domestic 
production and imports of oil and natural gas, the proximity of our oil and natural gas production to pipelines and corresponding 
markets, the available capacity in such pipelines, the demand for oil and natural gas, the effects of weather, and the effects of 
state and federal regulation.  As of December 31, 2019, we have not experienced significant difficulty in finding a market for 
all of our production as it becomes available or in transporting our production to those markets; however, there is no assurance 
that we will always be able to market all of our production or obtain favorable prices.

Oil Marketing

Prices received in a regional market fluctuate frequently and can differ from NYMEX pricing due to a variety of reasons, 
including supply and/or demand factors, crude oil quality and location differentials.  The oil differentials we received in the 
Gulf Coast and Rocky Mountain regions are discussed in further detail below.

Crude oil prices in the Gulf Coast region are generally positive to NYMEX and highly correlated to the changes in prices 
of crude oil sold under Light Louisiana Sweet.  Our average NYMEX oil differential in the Gulf Coast region was a positive 
$3.30 per Bbl during 2019, compared to a positive $2.94 per Bbl and a positive $0.22 per Bbl during 2018 and 2017, respectively.  
Our current markets at various sales points along the Gulf Coast have sufficient demand to accommodate our production, but 
there can be no assurance of future demand.

The marketing of our Rocky Mountain region oil production is dependent on transportation through local pipelines to 
market  centers  in  Guernsey,  Wyoming;  Clearbrook,  Minnesota;  Wood  River,  Illinois;  and  most  recently  Cushing, 
Oklahoma.  Shipments on some of the pipelines are at or near capacity and may be subject to apportionment.  We currently 
have access to, or have contracted for, sufficient pipeline capacity to move our oil production; however, there can be no 
assurance that we will be allocated sufficient pipeline capacity to move all of our oil production in the future.  Because local 
demand for production is small in comparison to current production levels, much of the production in the Rocky Mountain 
region is transported to markets outside of the region.  Therefore, prices in the Rocky Mountain region are further influenced 
by fluctuations in prices (primarily Brent and LLS) in coastal markets and by available pipeline capacity in the Midwest and 
Cushing markets.  For the year ended December 31, 2019, the discount for our oil production relative to NYMEX in the Rocky 
Mountain region averaged $2.01 per Bbl, compared to $1.50 per Bbl during 2018 and $1.39 per Bbl during 2017.

COMPETITION AND MARKETS

We face competition from other oil and natural gas companies in all aspects of our business, including acquisition of 
producing properties, oil and gas leases, drilling rights, and CO2 properties; marketing of oil and natural gas; and obtaining 
and  maintaining  goods,  services  and  labor.  Many  of  our  competitors  have  substantially  larger  financial  and  other 
resources.  Factors that affect our ability to acquire producing properties include available liquidity, available information 
about prospective properties and our expectations for earning a minimum projected return on our investments.  Because of 
the primary nature of our core assets (our tertiary operations) and our ownership of relatively uncommon significant natural 
sources of CO2 in the Gulf Coast and Rocky Mountain regions, we believe that we are effective in competing in the market 
and have less competition than our peers in certain aspects of our business.

21

Denbury Resources Inc.

The demand for qualified and experienced field personnel to drill wells and conduct field operations and for geologists, 
geophysicists, engineers and other professionals in the oil and gas industry can fluctuate significantly, often in correlation 
with commodity prices, causing periodic shortages in such personnel.  Prior to the downturn in oil prices, the competition for 
qualified technical personnel had been extensive, and our personnel costs escalated.  There were also periods with shortages 
of  drilling  rigs  and  other  equipment,  as  demand  for  rigs  and  equipment  increased  along  with  the  number  of  wells  being 
drilled.  These factors also cause significant increases in costs for equipment, services and personnel.  We cannot be certain 
when we will experience these issues, and these types of shortages or price increases could significantly decrease our profit 
margin, cash flow and operating results, and cause significant delays in our development operations.

FEDERAL AND STATE REGULATIONS

Numerous federal, state and local laws and regulations govern the oil and gas industry.  Additions or changes to these 
laws and regulations are often made in response to the current political or economic environment.  Compliance with the 
evolving regulatory landscape is often difficult, and substantial penalties may be incurred for noncompliance.  Additionally, 
the future annual cost of complying with all laws and regulations applicable to our operations is uncertain and will be ultimately 
determined by several factors, including future changes to legal and regulatory requirements.  Management believes that 
continued compliance with existing laws and regulations applicable to our operations and future compliance therewith will 
not have a materially adverse effect on our consolidated financial position, results of operations or cash flows, although such 
laws and regulations, and compliance therewith, could cause significant delays or otherwise impede operations, which may, 
among other things, cause our expected production rates and cash flows to be less than anticipated.

The following sections describe some specific laws and regulations that may affect us.  We cannot predict the cost or 

impact of these or other future legislative or regulatory initiatives.

Regulation of Oil and Gas Exploration and Production

Our operations are subject to various types of regulation at the federal, state and local levels.  Such regulation includes 
requiring permits for drilling wells; maintaining bonding requirements in order to drill or operate wells and regulating the 
location of wells; the method of drilling and casing wells; the surface use and restoration of properties upon which wells are 
drilled; the plugging and abandoning of wells; and the composition or disposal of chemicals and fluids used in connection 
with operations.  Our operations are also subject to various conservation laws and regulations.  These include regulation of 
the size of drilling, spacing or proration units and the density of wells that may be drilled in those units, and the unitization 
or pooling of oil and gas properties.  In addition, federal and state conservation laws, which establish maximum rates of 
production  from  oil  and  gas  wells,  generally  prohibit  or  restrict  the  venting  or  flaring  of  natural  gas  and  impose  certain 
requirements regarding the ratability of production.  The effect of these laws and regulations may limit the amount of oil and 
natural gas we can produce from our wells and may limit the number of wells or the locations at which we can drill.  Regulatory 
requirements and compliance relative to the oil and gas industry increase our costs of doing business and, consequently, affect 
our profitability.

Federal Regulation of Sales Prices and Transportation

The transportation of, and certain sales with respect to, natural gas in interstate commerce are heavily regulated by agencies 
of  the  U.S.  federal  government  and  are  affected  by,  among  other  things,  the  availability,  terms  and  cost  of 
transportation.  Notably, the price and terms of access to pipeline transportation are subject to extensive U.S. federal and state 
regulation.  The Federal Energy Regulatory Commission (“FERC”) is continually proposing and implementing new and/or 
modified rules and regulations affecting the natural gas industry, some of which may adversely affect the availability and 
reliability of interruptible transportation service on interstate pipelines.  While our sales of crude oil, condensate and natural 
gas liquids are not currently subject to FERC regulation, our ability to transport and sell such products is dependent on certain 
pipelines whose rates, terms and conditions of service are subject to FERC regulation.  Additional proposals and proceedings 
that might affect the natural gas industry are considered from time to time by Congress, FERC, state regulatory bodies and 
the courts, and we cannot predict when or if any such proposals or proceedings might become effective and their effect or 
impact, if any, on our operations.

22

Federal Energy and Climate Change Legislation and Regulation

Denbury Resources Inc.

The Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011, among other things, updated federal pipeline 
safety standards, increased penalties for violations of such standards, gave the Department of Transportation’s Pipeline and 
Hazardous Materials Safety Administration (the “PHMSA”) authority for new damage prevention and incident notification, 
and directed the PHMSA to prescribe new minimum safety standards for CO2 pipelines, which safety standards could affect 
our operations and the costs thereof.  While the PHMSA has adopted or proposed to adopt a number of new regulations to 
implement this act, no new minimum safety standards have been proposed or adopted for CO2 pipelines.

Both  federal  and  state  authorities  have  in  recent  years  proposed  new  regulations  to  limit  the  emission  of  pollutants, 
including greenhouse gas emissions, as part of climate change initiatives and the Clean Air Act.  For example, both the EPA 
and BLM have issued regulations for the control of methane emissions from the oil and gas industry.  The EPA has promulgated 
regulations  requiring  permitting  for  certain  sources  of  greenhouse  gas  emissions,  and  in  May  2016,  promulgated  final 
regulations to reduce methane and volatile organic compound emissions from the oil and gas sector.  In July 2017, a federal 
appeals court rejected an attempt by the EPA to delay implementation of the rule.  In September 2018, the EPA proposed 
amendments to the rule that are targeted at reducing regulatory requirements and streamlining the rule’s implementation.  In 
September 2019, the EPA also issued a notice of proposed rulemaking that, if finalized, would remove the methane specific 
regulations imposed by the 2016 final rule and remove certain other emission limitations placed on new or reconstructed 
transmission and storage facilities.  Enforcement of these regulations may impose additional costs related to compliance with 
new emission limits, as well as inspections and maintenance of several types of equipment used in our operations. 

Natural Gas Gathering Regulations

State and federal regulation of natural gas gathering facilities generally includes various safety, environmental and, in 
some circumstances, nondiscriminatory-take requirements.  With the increase in construction and operation of natural gas 
gathering lines in various states, natural gas gathering is receiving greater regulatory scrutiny from state and federal regulatory 
agencies, which is likely to continue in the future.

Federal, State or Indian Leases

Our operations on federal, state or Indian oil and gas leases, especially those in the Rocky Mountain region, are subject 
to numerous restrictions, including nondiscrimination statutes.  Such operations must be conducted pursuant to certain on-
site security regulations and other permits and authorizations issued by the Bureau of Land Management, the Bureau of Ocean 
Energy Management, the Bureau of Safety and Environmental Enforcement, the Bureau of Indian Affairs, and other federal 
and state stakeholder agencies.

Environmental Regulations

Our oil and natural gas production, saltwater disposal operations, injection of CO2, and the processing, handling and 
disposal of materials such as hydrocarbons and naturally occurring radioactive materials (“NORM”) are subject to stringent 
regulation.  We could incur significant costs, including cleanup costs resulting from a release of product, third-party claims 
for property damage and personal injuries, or penalties and other sanctions as a result of any violations or liabilities under 
environmental laws and regulations or other laws and regulations applicable to our operations.  Changes in, or more stringent 
enforcement of, environmental laws and other laws applicable to our operations could also result in delays or additional 
operating costs and capital expenditures.

Various  federal,  state  and  local  laws  and  regulations  controlling  the  discharge  of  materials  into  the  environment,  or 
otherwise  relating  to  the  protection  of  the  environment  and  human  health,  directly  impact  our  oil  and  gas  exploration, 
development and production operations.  These include, among others, (1) regulations adopted by the EPA and various state 
agencies regarding approved methods of disposal for certain hazardous and nonhazardous wastes; (2) the Comprehensive 
Environmental Response, Compensation, and Liability Act and analogous state laws that regulate the removal or remediation 
of previously disposed wastes (including wastes disposed of or released by prior owners or operators), property contamination 
(including groundwater contamination), and remedial plugging operations to prevent future contamination; (3) the Clean Air 
Act and comparable state and local requirements already applicable to our operations and new restrictions on air emissions 
from our operations, including greenhouse gas emissions and those that could discourage the production of fossil fuels that, 

23

Denbury Resources Inc.

when used, ultimately release CO2; (4) the Clean Water Act and comparable state and local requirements already applicable 
to our operations and new restrictions on wastewater discharges from our operations; (5) the Oil Pollution Act of 1990, which 
contains numerous requirements relating to the prevention of, and response to, oil spills into waters of the United States; (6) 
the Resource Conservation and Recovery Act, which is the principal federal statute governing the treatment, storage and 
disposal of hazardous wastes; (7) the Endangered Species Act and counterpart state legislation, which protects certain species 
(and their related habitats), including certain species that could be present on our leases, as threatened or endangered; and (8) 
state regulations and statutes governing the handling, treatment, storage and disposal of NORM and other wastes.

In the Rocky Mountain Region, federal agencies’ actions based upon their environmental review responsibilities under 
the National Environmental Policy Act can significantly impact the scope and timing of hydrocarbon development by slowing 
the timing of individual applications for permits to drill and requests for rights-of-way, and delaying large scale planning 
associated with region-level resource management plans and project-level master development plans.

Management believes that we are currently in substantial compliance with existing applicable environmental laws and 
regulations, and does not currently anticipate that future compliance will have a materially adverse effect on our consolidated 
financial position, results of operations or cash flows, although such laws and regulations, and compliance therewith, could 
cause significant delays or otherwise impede operations, which may, among other things, cause our expected production rates 
and cash flows to be less than anticipated.

Hydraulic Fracturing

During 2019, we fracture stimulated seven wells, primarily at Bell Creek Field utilizing water-based fluids.  We currently 
have plans to potentially hydraulically fracture up to ten wells during 2020, consisting primarily of small skin fractures that 
are utilized to remove contaminants caused by drilling muds and increase permeability near the wellbore.  We are familiar 
with the laws and regulations applicable to hydraulic fracturing operations and take steps to ensure compliance with these 
requirements.

NON-GAAP FINANCIAL MEASURES AND RECONCILIATIONS

Reconciliation of Standardized Measure to PV-10 Value

PV-10 Value is a non-GAAP measure and is different from the Standardized Measure in that PV-10 Value is a pre-tax 
number and the Standardized Measure is an after-tax number.  The information used to calculate PV-10 Value is derived 
directly from data determined in accordance with FASC Topic 932.  We believe that PV-10 Value is a useful supplemental 
disclosure to the Standardized Measure because the Standardized Measure can be impacted by a company’s unique tax situation, 
and it is not practical to calculate the Standardized Measure on a property-by-property basis.  Because of this, PV-10 Value 
is a widely used measure within the industry and is commonly used by securities analysts, banks and credit rating agencies 
to evaluate the estimated future net cash flows from proved reserves on a comparative basis across companies or specific 
properties.  PV-10 Value is commonly used by us and others in our industry to evaluate properties that are bought and sold, 
to assess the potential return on investment in our oil and natural gas properties, and to perform our impairment testing of oil 
and natural gas properties.  PV-10 Value is not a measure of financial or operating performance under GAAP, nor should it 
be considered in isolation or as a substitute for the Standardized Measure.  Our PV-10 Value and the Standardized Measure 
do not purport to represent the fair value of our oil and natural gas reserves.  See also Glossary and Selected Abbreviations
for the definition of “PV-10 Value” and Supplemental Oil and Natural Gas Disclosures (Unaudited) to the Consolidated 
Financial Statements for additional disclosures about the Standardized Measure.

The following table provides a reconciliation of the Standardized Measure to PV-10 Value for the periods indicated:

In thousands

Standardized Measure (GAAP measure)

Discounted estimated future income tax

PV-10 Value (non-GAAP measure)

Year Ended December 31,

2019

2,261,039

354,629

2,615,668

$

$

2018

3,351,385

673,754

4,025,139

$

$

2017

2,232,429

301,369

2,533,798

$

$

24

 
Reconciliation of Net Income to Adjusted EBITDAX

Denbury Resources Inc.

Adjusted EBITDAX is a non-GAAP financial measure which management uses and is calculated based upon (but not 
identical to) a financial covenant related to “Consolidated EBITDAX” in our senior secured bank credit facility, which excludes 
certain items that are included in net income, the most directly comparable GAAP financial measure.  Items excluded include 
interest, income taxes, depletion, depreciation, and amortization, and items that the Company believes affect the comparability 
of  operating  results  such  as  items  whose  timing  and/or  amount  cannot  be  reasonably  estimated  or  are  non-recurring.  
Management  believes Adjusted  EBITDAX  may  be  helpful  to  investors  in  order  to  assess  our  operating  performance  as 
compared to that of other companies in our industry, without regard to financing methods, capital structure or historical costs 
basis.  It is also commonly used by third parties to assess the Company’s leverage and ability to incur and service debt and 
fund capital expenditures.  Adjusted EBITDAX should not be considered in isolation, as a substitute for, or more meaningful 
than, net income, cash flows from operations, or any other measure reported in accordance with GAAP.  The Company’s 
Adjusted EBITDAX may not be comparable to similarly titled measures of another company because all companies may not 
calculate Adjusted EBITDAX, EBITDAX, or EBITDA in the same manner.

The following table presents a reconciliation of our net income to Adjusted EBITDAX for the periods indicated:

Year Ended December 31,

2019

2018

$

216,959

$

322,698

81,632
104,352
233,816
93,684
12,470
(155,998)
18,627

—
—
1,589
607,131

$

69,688
87,233
216,449
(196,335)
11,951
—

—

49,373
17,805
5,504
584,366

In thousands
Net income (GAAP measure)
Adjustments to reconcile to Adjusted EBITDAX

Interest expense
Income tax expense
Depletion, depreciation, and amortization
Noncash fair value losses (gains) on commodity derivatives
Stock-based compensation
Gain on debt extinguishment

Severance-related expense

Accrued expense related to litigation over a helium supply contract
Impairment of loan receivable and related assets
Noncash, non-recurring and other

Adjusted EBITDAX (non-GAAP measure)

$

25

Item 1A.  Risk Factors

Denbury Resources Inc.

Oil and natural gas prices are volatile.  A sustained period of low of oil prices is likely to adversely affect our future 
financial condition, results of operations, cash flows and the carrying value of our oil and natural gas properties.

Oil prices are the most important determinant of our operational and financial success.  Oil prices are highly impacted 
by worldwide oil supply, demand and prices, and have historically been subject to significant price changes over short periods 
of time.  Over the last few years, NYMEX oil prices have been volatile, decreasing to a low of $43 in mid-2017 and gradually 
improving to hit a three-year peak of $76 in October 2018, before retreating to the low $40s in late December 2018 and 
generally averaging in the low $50s to mid $60s range throughout 2019.  Based on past commodity cycles, volatility will 
remain, and prices could move downward or upward on a rapid or repeated basis, which can make planning and budgeting, 
acquisition and divestiture transactions, capital raising, valuations and sustaining business strategies more difficult.  Our cash 
flow from operations is highly dependent on the prices that we receive for oil, as oil comprised approximately 97% of our 
2019 production and approximately 98% of our proved reserves at December 31, 2019.  The prices for oil and natural gas are 
subject to a variety of factors that are beyond our control.  These factors include:

• 

the level of worldwide consumer demand for oil and natural gas, which has recently been negatively affected by 
concerns about the impact of the COVID-19 coronavirus, and the domestic and foreign supply of oil and natural gas 
and levels of domestic oil and natural gas storage;
the degree to which members of the Organization of Petroleum Exporting Countries maintain oil price and production 
controls;
the degree to which domestic oil and natural gas production affects worldwide supply of crude oil or its price;
• 
•  worldwide political events, conditions and policies, including actions taken by foreign oil and natural gas producing 

• 

nations; and

•  worldwide economic conditions.

Negative movements in oil prices could harm us in a number of ways, including:

• 
• 

• 

lower cash flows from operations may require reduced levels of capital expenditures;
reduced levels of capital expenditures in turn could lower our present and future production levels, and lower the 
quantities and value of our oil and gas reserves, which constitute our major asset;
our lenders could reduce our borrowing base, and we may not be able to raise capital at attractive rates in the public 
markets;

•  we could have difficulty repaying or refinancing our indebtedness;
•  we could be forced to increase our level of indebtedness, issue additional equity, or sell assets;
•  we could be required to impair various assets, including a write-down of our oil and natural gas assets or the value 

• 

of other tangible or intangible assets; and/or
our potential cash flows from our commodity derivative contracts that include sold puts could be limited to the extent 
that oil prices are below the prices of those sold puts.

Furthermore, some or all of our tertiary projects could become or remain uneconomical.  We may also decide to suspend 
future expansion projects, and if prices were to drop below our operating cash break-even points for an extended period of 
time, we may decide to shut-in existing production, both of which could have a material adverse effect on our operations and 
financial condition and reduce our production.

We must refinance, extend or repurchase $1.18 billion principal amount of our indebtedness which matures between 
May 2021 and May 2022 in order to maintain our continuing financial viability.

As of December 31, 2019, of our total outstanding debt principal of $2.3 billion, almost 50% becomes due and payable 
within 17 to 29 months, with $614.9 million due in May 2021.  Our anticipated level of free cash flow during 2020, taken 
together with current borrowing capacity under our revolving credit facility, is not sufficient to repay all of our debt that is 
scheduled to mature in 2021 and 2022.

We are evaluating potential transactions to reduce, and/or extend maturities of, our long-term debt, focusing particularly 
on our second lien debt maturing in May 2021 and in March 2022.  In conjunction with our debt reduction and extension 

26

Denbury Resources Inc.

efforts, we may engage in transactions of various types, including public or private capital raising, debt exchange transactions, 
debt repurchases with proceeds from joint ventures or asset sales, or some combination of these methods.  However, our ability 
to restructure or refinance our long-term debt will depend on the condition of the capital markets and our financial condition 
at such time and could be affected by concentration in holdings of our long-term debt.  Any refinancing of our long-term debt 
could be at higher interest rates and may require us to comply with more onerous debt covenants, which could further restrict 
our business operations or financial flexibility.

Without long-term access to capital, continued funding from lenders or sufficient generation of cash flow from our business 
operations, there continues to be substantial risk that we may be unable to repay or refinance our long-term indebtedness that 
matures in 2021 and 2022.  Any failure to make timely payments of interest and principal when due on any of our outstanding 
long-term indebtedness could result in cross-defaults of all of our outstanding long-term indebtedness, which could then lead 
to  acceleration  of  the  maturities  of  such  indebtedness  and  enforcement  actions  by  the  holders  thereof  to  collect  such 
indebtedness.

We may be unable to access the equity or debt capital markets to raise sufficient capital to meet our obligations in light 
of recent trends affecting the financing of the exploration and production sector.

Recent reluctance of traditional capital sources to invest in the exploration and production sector based on market volatility, 
perceived underperformance and environmental, social and governance (ESG) trends, has raised concerns regarding capital 
availability for the sector.  The cost of obtaining money from the credit markets has increased as many lenders and institutional 
investors have increased interest rates, enacted tighter lending standards and reduced (and in some cases ceased to provide) 
funding to borrowers. If those markets are unavailable, or if we are unable to access them or alternative financing sources on 
acceptable terms, we may be unable to repay our long-term debt or carry out our business strategy, with an accompanying 
negative impact on our financial condition, results of operations and ability to service our indebtedness.

Constraints on liquidity could limit our operational flexibility and growth.

In recent years, we have been successful in managing our capital expenditures so that they do not exceed our cash flows.  
Although our liquidity has been, and in 2020 is expected to remain, sufficient to support our capital expenditures and service 
our  indebtedness,  liquidity  restrictions  coming  from  lower  oil  prices  and  restraints  on  traditional  capital  sources  for  the 
exploration and production industry could negatively affect our level of capital expenditures, and thus our maintenance of 
production and operational cash flow.  In the absence of sufficient cash flows and capital resources, we could face substantial 
liquidity pressure, and might be required to dispose of material assets at unfavorable prices.

If we cannot meet the “price criteria” for continued listing on the NYSE, the NYSE may delist our common stock, 
which could have an adverse impact on the trading volume, liquidity and market price of our common stock, or the 
trading prices of our 6 % Convertible Senior Notes due 2024.

If we do not maintain an average closing price of $1.00 or more for our common stock over any consecutive 30 trading-
day period, the NYSE may delist our common stock for a failure to maintain compliance with the NYSE price criteria listing 
standards.  As of February 25, 2020, the average closing price of our common stock over the immediately preceding 30 
consecutive trading day period was $1.04 per share, and our closing price was $0.84 per share on February 25, 2020.  Despite 
NYSE rules and processes that provide a period of time to cure non-compliance with this NYSE standard (during which time 
the issuer’s common stock generally continues to be traded on the NYSE), there is no assurance that trading prices of our 
common stock or other steps we take (such as a reverse stock split) would be successful in assuring our long-term listing on 
the NYSE.  A delisting of our common stock from the NYSE would likely reduce the liquidity and market price of our common 
stock and the trading prices of our 6 % Convertible Senior Notes due 2024, reduce the number of investors willing to hold 
or acquire our common stock, and negatively impact our ability to raise equity financing.

A financial downturn in one or more of the world’s major markets could negatively affect our business and financial 
condition.

In addition to the impact on the demand for oil, drops in domestic or foreign economic growth rates, regional or worldwide 
increases in tariffs or other trade restrictions, significant international currency fluctuations, evolving political and military 
tensions in the Middle East, a sustained credit crisis, or a worsening of the actual or anticipated future drop in worldwide oil 

27

 
Denbury Resources Inc.

demand due to the COVID-19 coronavirus, a severe economic contraction either regionally or worldwide or turmoil in the 
global financial system, could materially affect our business and financial condition or impact our ability to finance operations.  
Negative credit market conditions could inhibit our lenders from funding our senior secured bank credit facility or cause them 
to  restrict  our  borrowing  base  or  make  the  terms  of  our  senior  secured  bank  credit  facility  more  costly  and  more 
restrictive.  Negative economic conditions could also adversely affect the collectability of our trade receivables or performance 
by our suppliers or cause our commodity hedging arrangements to be ineffective if our counterparties are unable to perform 
their obligations.

Increases in interest rates could adversely affect our business.

Our business and operating results can be harmed by increases in interest rates.  These changes could cause our cost of 
doing business to increase, limit our ability to pursue acquisition opportunities, reduce cash flow, affect our interest costs 
under our senior secured bank credit facility, or increase the cost of any new debt financings.

Our bank credit facility maturity date “springs forward” to dates earlier than December 9, 2021 if certain conditions 
are not satisfied.

The Company’s senior secured bank credit facility provides for acceleration of its December 9, 2021 maturity date to 
earlier dates during 2021, keyed to the maturity dates during 2021 of our 9% Senior Secured Second Lien Notes due May 15, 
2021 (the “2021 Senior Secured Notes”) and our 6 % Senior Subordinated Notes due August 15, 2021 (the “2021 Senior 
Subordinated Notes”), as follows:

•  To February 12, 2021, if on that date the sum of the Company’s cash, cash equivalents and borrowing availability 
under the senior secured bank credit facility is less than 120% of the amount of the then outstanding 2021 Senior 
Secured Notes;

•  To May 14, 2021, if either (a) prior to that date the 2021 Senior Secured Notes have not been repaid or otherwise 
redeemed in full, or (b) on that date the sum of the Company’s cash, cash equivalents and borrowing availability 
under the senior secured bank credit facility is less than 120% of the amount of the then outstanding 2021 Senior 
Subordinated Notes; or

•  To August 13, 2021, if prior to that date the 2021 Senior Subordinated Notes have not been repaid or otherwise 

redeemed in full.

As of December 31, 2019, we had no outstanding borrowings and $87.2 million of letters of credit outstanding under our 
senior secured bank credit facility.  The average outstanding balance under the credit facility as of the last day of each month 
during 2019 was $40.6 million.  Our inability to repay amounts owing under our senior secured bank credit facility on any of 
the above springing maturity dates could trigger a cross-default under, and potentially an acceleration of, all of our other long-
term indebtedness then outstanding.  Based upon our use of the senior secured bank credit facility for short-term working 
capital purposes, we anticipate that any amounts outstanding from time to time under the credit facility during 2020 and 2021 
can be repaid using our then-available cash flow from operations.

Inability to meet financial performance covenants in our bank credit facility may require us to seek modification of 
covenants, force a reduction in our borrowing base, or cause repayment of amounts outstanding under our bank credit 
facility.

In August  2018,  we  extended  the  maturity  of  our  bank  credit  facility  to  December  2021  and  reset  certain  financial 
performance covenants based on projections and oil price expectations that existed at that time.  Oil prices subsequent to 
August 2018 have been volatile, and if oil and natural gas prices decrease for an extended period of time, we may not be able 
to  remain  in  compliance  with  our  senior  secured  bank  credit  facility’s  covenants.   As  such,  we  may  be  required  to  seek 
modifications of these covenants or a waiver at a significant cost to the Company, or the banks could force a reduction in our 
bank borrowing base and repayment of amounts outstanding under our bank credit facility.  As of December 31, 2019, we 
had no bank debt outstanding, but we did have $87.2 million of letters of credit outstanding.  If necessary, we may not be able 
to successfully modify these covenants or obtain a waiver of compliance with these covenants.  For more information on our 
senior secured bank credit facility, see Item 7, Management’s Discussion and Analysis of Financial Condition and Results of 
Operations – Capital Resources and Liquidity – Senior Secured Bank Credit Facility.

28

Denbury Resources Inc.

Our bank borrowing base is determined semiannually, and upon requested unscheduled special redeterminations, in each 
case at the banks’ discretion, and the amount is established and based, in part, upon certain external factors, such as commodity 
prices.  We do not know, nor can we control, the results of such redeterminations or the effect of then-current oil and natural 
gas prices on any such redetermination.  A future redetermination lowering our borrowing base could limit availability under 
our senior secured bank credit facility or require us to seek different forms of financing arrangements.  If the outstanding debt 
under our senior secured bank credit facility were to ever exceed the borrowing base, we would be required to repay the excess 
amount over a period not to exceed six months.

Certain of our operations may be limited during certain periods due to severe weather conditions and other regulations.

Our operations in the Gulf Coast region may be subjected to adverse weather conditions such as hurricanes, flooding and 
tropical storms in and around the Gulf of Mexico that can damage oil and natural gas facilities and delivery systems and 
disrupt operations, which can also increase costs and have a negative effect on our results of operations.  Certain of our 
operations in North Dakota, Montana and Wyoming, including the construction of CO2 pipelines, the drilling of new wells 
and production from existing wells, are conducted in areas subject to extreme weather conditions including severe cold, snow 
and rain, which conditions may cause such operations to be hindered or delayed, or otherwise require that they be conducted 
only during non-winter months, and depending on the severity of the weather, could have a negative effect on our results of 
operations in these areas.  Further, the potential impacts of climate change on our operations may include unusually intense 
rainfall and storm patterns, rising sea levels and increased high temperatures.  

Certain  of  our  operations  in  the  Rocky  Mountain  region  are  confined  to  certain  time  periods  due  to  environmental 
regulations, federal restrictions on when drilling can take place on federal lands, and lease stipulations designed to protect 
certain wildlife, which regulations, restrictions and limitations could slow down our operations, cause delays, increase costs 
and have a negative effect on our results of operations.  In addition, a number of governmental bodies have introduced or are 
contemplating regulatory changes in response to various climate change interest groups and the potential impact of climate 
change.  Legislation and increased regulation regarding climate change could impose significant costs on us.

Given the political uncertainty about proposals to combat climate change and how it should be dealt with, it is possible 
that legislation and regulations could affect our financial condition and operating performance.  However, even without such 
regulation, increased awareness and any adverse publicity in the global marketplace about potential impacts on climate change 
by our industry could harm our reputation and impact operations.

Oil and natural gas development and producing operations involve various risks.

Our operations are subject to all of the risks normally incident and inherent to the operation and development of oil and 
natural gas properties and the drilling of oil and natural gas wells, including, without limitation, pipe failure; fires; formations 
with  abnormal  pressures;  uncontrollable  flows  of  oil,  natural  gas,  brine  or  well  fluids;  release  of  contaminants  into  the 
environment and other environmental hazards and risks and well blowouts, cratering or explosions.  In addition, our operations 
are sometimes near populated commercial or residential areas, which adds additional risks.  The nature of these risks is such 
that some liabilities could exceed our insurance policy limits or otherwise be excluded from, or limited by, our insurance 
coverage, as in the case of environmental fines and penalties, for example, which are excluded from coverage as they cannot 
be insured.

We could incur significant costs related to these risks that could have a material adverse effect on our results of operations, 
financial condition and cash flows or could have an adverse effect upon the profitability of our operations.  Additionally, a 
portion  of  our  production  activities  involves  CO2  injections  into  fields  with  wells  plugged  and  abandoned  by  prior 
operators.  However, it is often difficult (or impracticable) to determine whether a well has been properly plugged prior to 
commencing injections and pressuring the oil reservoirs.  We may incur significant costs in connection with remedial plugging 
operations to prevent environmental contamination and to otherwise comply with federal, state and local regulations relative 
to the plugging and abandoning of our oil, natural gas and CO2 wells.  In addition to the increased costs, if wells have not 
been properly plugged, modification to those wells may delay our operations and reduce our production.

Development activities are subject to many risks, including the risk that we will not recover all or any portion of our 
investment in such wells.  Drilling for oil and natural gas may involve unprofitable efforts, not only from dry wells, but also 
from wells that are productive but do not produce sufficient net reserves to return a profit after deducting drilling, operating 

29

Denbury Resources Inc.

and other costs.  The cost of drilling, completing and operating a well is often uncertain, and cost factors can adversely affect 
the economics of a project.  Further, our drilling operations may be curtailed, delayed or canceled as a result of numerous 
factors, including:

• 
• 
• 
• 

• 
• 
• 

unexpected drilling conditions;
pressure or irregularities in formations;
equipment failures or accidents;
adverse weather conditions, including hurricanes and tropical storms in and around the Gulf of Mexico that can 
damage oil and natural gas facilities and delivery systems and disrupt operations, and winter conditions and forest 
fires in the Rocky Mountain region that can delay or impede operations;
compliance with environmental and other governmental requirements;
the cost of, or shortages or delays in the availability of, drilling rigs, equipment, pipelines and services; and
title problems.

Estimating our reserves, production and future net cash flows is difficult to do with any certainty.

Estimating quantities of proved oil and natural gas reserves is a complex process.  It requires interpretations of available 
technical data and various assumptions, including future production rates, production costs, severance and excise taxes, capital 
expenditures and workover and remedial costs, and the assumed effect of governmental rules and regulations.  There are 
numerous  uncertainties  about  when  a  property  may  have  proved  reserves  as  compared  to  potential  or  probable  reserves, 
particularly relating to our tertiary recovery operations.  Forecasting the amount of oil reserves recoverable from tertiary 
operations, and the production rates anticipated therefrom, requires estimates, one of the most significant being the oil recovery 
factor.  Actual results most likely will vary from our estimates.  Also, the use of a 10% discount factor for reporting purposes, 
as prescribed by the SEC, may not necessarily represent the most appropriate discount factor, given actual interest rates and 
risks to which our business, and the oil and natural gas industry in general, are subject.  Any significant inaccuracies in these 
interpretations or assumptions, or changes of conditions, could result in a revision of the quantities and net present value of 
our reserves.

The  reserves  data  included  in  documents  incorporated  by  reference  represents  estimates  only.  Quantities  of  proved 
reserves are estimated based on economic conditions, including first-day-of-the-month average oil and natural gas prices for 
the 12-month period preceding the date of the assessment.  The representative oil and natural gas prices used in estimating 
our December 31, 2019 reserves were $55.69 per Bbl for crude oil and $2.58 per MMBtu for natural gas, both of which were 
adjusted for market differentials by field.  Our reserves and future cash flows may be subject to revisions based upon changes 
in economic conditions, including oil and natural gas prices, as well as due to production results, results of future development, 
operating and development costs, and other factors.  Downward revisions of our reserves could have an adverse effect on our 
financial condition and operating results.  Actual future prices and costs may be materially higher or lower than the prices and 
costs used in our estimates.

As  of  December 31,  2019,  approximately  10%  of  our  estimated  proved  reserves  were  undeveloped.  Recovery  of 
undeveloped reserves requires significant capital expenditures and may require successful drilling operations.  The reserves 
data assumes that we can and will make these expenditures and conduct these operations successfully, but these assumptions 
may not be accurate, and these expenditures and operations may not occur.

If commodity prices decline appreciably, we may be required to write down the carrying value of our oil and natural 
gas properties.

Under full cost accounting rules related to our oil and natural gas properties, we are required each quarter to perform a 
ceiling test calculation, with the net capitalized costs of our oil and natural gas properties limited to the lower of unamortized 
cost or the cost center ceiling.  The present value of estimated future net revenues from proved oil and natural gas reserves 
included in the cost center ceiling is based on the average first-day-of-the-month oil and natural gas price for each month 
during a 12-month rolling period prior to the end of a particular reporting period.  Future material write-downs of our oil and 
natural gas properties, as well as future impairment of other long-lived assets, could significantly reduce earnings during the 
period in which such write-down and/or impairment occurs and would result in a corresponding reduction to long-lived assets 
and equity.  See Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations – Critical 
Accounting Policies and Estimates.

30

Denbury Resources Inc.

Our planned tertiary operations and the related construction of necessary CO2 pipelines could be delayed by difficulties 
in obtaining pipeline rights-of-way and/or permits, and/or by the listing of certain species as threatened or endangered.

The production of crude oil from our planned tertiary operations is dependent upon having access to pipelines to transport 
available CO2 to our oil fields at a cost that is economically viable.  Our future construction of CO2 pipelines will require us 
to  obtain  rights-of-way  from  private  landowners,  state  and  local  governments  and  the  federal  government  in  certain 
areas.  Certain states where we operate have considered or may again consider the adoption of laws or regulations that could 
limit or eliminate the ability of a pipeline owner or of a state, state’s legislature or its administrative agencies to exercise 
eminent domain over private property, in addition to possible judicially imposed constraints on, and additional requirements 
for, the exercise of eminent domain.  We also conduct operations on federal and other oil and natural gas leases inhabited by 
species that could be listed as threatened or endangered under the Endangered Species Act, which listing could lead to tighter 
restrictions as to federal land use and other land use where federal approvals are required.  These laws and regulations, together 
with any other changes in law related to the use of eminent domain or the listing of certain species as threatened or endangered, 
could inhibit or eliminate our ability to secure rights-of-way or otherwise access land for current or future pipeline construction 
projects and may require additional regulatory and environmental compliance, and increased costs in connection therewith, 
which could delay our CO2 pipeline construction schedule and initiation of our pipeline operations, and/or increase the costs 
of constructing our pipelines.

The ultimate cost of our planned 105-mile CCA pipeline extension may exceed our estimates, and there may be limited 
availability of capital for its construction.  We may not be successful in entering into a joint venture for the extension and may 
be unable to raise third-party funds for our CCA pipeline extension spend in 2020.  In addition, while we anticipate completion 
of the CCA pipeline extension by the end of 2020, the actual date of completion may be later due to, among other factors, 
capital constraints and the regulatory issues discussed above.  

Our future performance depends upon our ability to effectively develop our existing oil and natural gas reserves and 
find or acquire additional oil and natural gas reserves that are economically recoverable.

Unless we can successfully develop our existing reserves and/or replace the reserves that we produce, our reserves will 
decline,  resulting  eventually  in  a  decrease  in  oil  and  natural  gas  production  and  lower  revenues  and  cash  flows  from 
operations.  We  have  historically  replaced  reserves  through  both  acquisitions  and  internal  organic  growth  activities.  For 
internal organic growth activities, the magnitude of proved reserves that we can book in any given year depends on our progress 
with new floods and the timing of the production response, as well as the success of exploitation projects.  In the future, we 
may not be able to continue to replace reserves at acceptable costs.  The business of exploring for, developing or acquiring 
reserves is capital intensive.  We may not be able to make the necessary capital investment to maintain or expand our oil and 
natural gas reserves if our cash flows from operations are reduced, whether due to current oil or natural gas prices or otherwise, 
or if external sources of capital become limited or unavailable.  Further, the process of using CO2 for tertiary recovery, and 
the related infrastructure, requires significant capital investment prior to any resulting and associated production and cash 
flows from these projects, heightening potential capital constraints.  If our capital expenditures are restricted, or if outside 
capital resources become limited, we will not be able to maintain our current production levels.

Commodity derivative contracts may expose us to potential financial loss.

To reduce our exposure to fluctuations in the prices of oil and natural gas, we enter into commodity derivative contracts 
in order to economically hedge a portion of our forecasted oil and natural gas production.  As of February 24, 2020, we have 
oil derivative contracts in place covering 39,500 Bbls/d for the first half of 2020 and 35,500 Bbls/d for the second half of 
2020.  Such derivative contracts expose us to risk of financial loss in some circumstances, including when there is a change 
in the expected differential between the underlying price in the hedging agreement and actual prices received, when the cash 
benefit from hedges including a sold put is limited to the extent oil prices fall below the price of our sold puts, or when the 
counterparty to the derivative contract is financially constrained and defaults on its contractual obligations.  In addition, these 
derivative contracts may limit the benefit we would otherwise receive from increases in the prices for oil and natural gas.

31

Denbury Resources Inc.

Shortages of or delays in the availability of oil field equipment, services and qualified personnel could reduce our cash 
flow and adversely affect results of operations.

The demand for qualified and experienced field personnel, geologists, geophysicists, engineers and other professionals 
in the oil and natural gas industry can fluctuate significantly, causing periodic shortages in such personnel.  In the past, there 
have been shortages of oil field and other necessary equipment, including drilling rigs, along with increased prices for such 
equipment, services and associated personnel.  These types of shortages or price increases could significantly decrease our 
profit margin, cash flow and operating results and/or restrict or delay our ability to drill wells and conduct our operations, 
possibly causing us to miss our forecasts and projections.

The marketability of our production is dependent upon transportation lines and other facilities, certain of which we 
do not control.  When these facilities are unavailable, our operations can be interrupted and our revenues reduced.

The marketability of our oil and natural gas production depends, in part, upon the availability, proximity and capacity of 
transportation lines owned by third parties.  In general, we do not control these transportation facilities, and our access to them 
may be limited or denied.  A significant disruption in the availability of, and access to, these transportation lines or other 
production facilities could adversely impact our ability to deliver to market or produce our oil and thereby cause a significant 
interruption in our operations.

Our production will decline if our access to sufficient amounts of carbon dioxide is limited.

Our long-term strategy is primarily focused on our CO2 tertiary recovery operations.  The crude oil production from our 
tertiary recovery projects depends, in large part, on having access to sufficient amounts of naturally occurring and industrial-
sourced CO2.  Our ability to produce oil from these projects would be hindered if our supply of CO2 was limited due to, among 
other things, problems with our current CO2 producing wells and facilities, including compression equipment, catastrophic 
pipeline failure or our ability to economically purchase CO2 from industrial sources.  This could have a material adverse effect 
on our financial condition, results of operations and cash flows.  Our anticipated future crude oil production from tertiary 
operations is also dependent on the timing, volumes and location of CO2 injections and, in particular, on our ability to increase 
our combined purchased and produced volumes of CO2 and inject adequate amounts of CO2 into the proper formation and 
area within each of our tertiary oil fields.

The development of our naturally occurring CO2 sources involves the drilling of wells to increase and extend the CO2
reserves available for use in our tertiary fields.  These drilling activities are subject to many of the same drilling and geological 
risks of drilling and producing oil and gas wells (see Oil and natural gas development and producing operations involve 
various risks above).  Furthermore, recent market conditions may cause the delay or cancellation of construction of plants 
that produce industrial-source CO2 as a byproduct that we can purchase, thus limiting the amount of industrial-source CO2
available for our use in our tertiary operations.

A cyber incident could occur and result in information theft, data corruption, operational disruption, and/or financial 
loss.

Our business has become increasingly dependent on digital technologies to conduct day-to-day operations, including 
certain of our exploration, development and production activities.  We depend on digital technology, among other things, to 
process and record financial and operating data; analyze seismic and drilling information; monitor and control pipeline and 
plant equipment; and process and store personally identifiable information of our employees and royalty owners.  Cyber 
attacks on businesses have escalated in recent years.  Our technologies, systems and networks may become the target of cyber 
attacks or information security breaches that could compromise our process control networks or other critical systems and 
infrastructure, resulting in disruptions to our business operations, harm to the environment or our assets, disruptions in access 
to our financial reporting systems, or loss, misuse or corruption of our critical data and proprietary information, including our 
business information and that of our employees, partners and other third parties.  Any of the foregoing may be exacerbated 
by a delay or failure to detect a cyber incident.  Cyber attacks could result in significant financial losses, legal or regulatory 
violations, reputational harm, and legal liability and could ultimately have a material adverse effect on our business and results 
of operations.

32

Denbury Resources Inc.

Although we utilize various procedures and controls to monitor and protect against these threats and to mitigate our 
exposure to such threats, there can be no assurance that these procedures and controls will be sufficient in preventing security 
threats from materializing and causing us to suffer such losses in the future.  As cyber threats continue to evolve in magnitude 
and  sophistication,  we  may  be  required  to  expend  significant  additional  resources  to  continue  to  modify  or  enhance  our 
procedures and controls or to investigate and remediate any digital and operational systems, related infrastructure, technologies 
and network security vulnerabilities, which could increase our costs.

We may lose key executive officers or specialized technical employees, which could endanger the future success of our 
operations.

Our  success  depends  to  a  significant  degree  upon  the  continued  contributions  of  our  executive  officers,  other  key 
management and specialized technical personnel.  Our employees, including our executive officers, are employed at will and 
do not have employment agreements.  We believe that our future success depends, in large part, upon our ability to hire and 
retain highly skilled personnel.

Environmental laws and regulations are costly and stringent.

Our exploration, production, and marketing operations are subject to complex and stringent federal, state, and local laws 
and regulations governing, among other things, the discharge of substances into the environment or otherwise relating to the 
protection of human health and the protection of endangered species.  These laws and regulations and related public policy 
considerations affect the costs, manner, and feasibility of our operations and require us to make significant expenditures in 
order to comply.  Failure to comply with these laws and regulations may result in the assessment of administrative, civil, and 
criminal penalties, the imposition of investigatory and remedial obligations, and the issuance of injunctions that could limit 
or prohibit our operations.  Some of these laws and regulations may impose joint and several, strict liability for contamination 
resulting from spills, discharges, and releases of substances, including petroleum hydrocarbons and other wastes, without 
regard to fault, or the legality of the original conduct.  Under such laws and regulations, we could be required to remove or 
remediate previously disposed substances and property contamination, including wastes disposed or released by prior owners 
or operators.

Enactment of executive, legislative or regulatory proposals under consideration could negatively affect our business.

Although  the  current Administration  has  moved  away  from  the  trend  of  proposing  stricter  standards  and  increasing 
oversight and regulation over the exploration and production industry at the federal level, it is possible that other proposals 
affecting the oil and gas industry could be enacted or adopted in the future, including state or local regulations, any of which 
could result in increased costs or additional operating restrictions that could have an effect on demand for oil and natural gas 
or prices at which it can be sold.

The loss of one or more of our large oil and natural gas purchasers could have an adverse effect on our operations.

For the year ended December 31, 2019, three purchasers individually accounted for 10% or more of our oil and natural 
gas revenues and, in the aggregate, for 54% of such revenues.  The loss of a large single purchaser could adversely impact 
the prices we receive or the transportation costs we incur.

Item 1B.  Unresolved Staff Comments

There  are  no  unresolved  written  SEC  staff  comments  regarding  our  periodic  or  current  reports  under  the  Securities 
Exchange Act of 1934 received 180 days or more before the end of the fiscal year to which this annual report on Form 10-K 
relates.

Item 2.  Properties

Information regarding the Company’s properties called for by this item is included in Item 1, Business and Properties – 
Oil and Natural Gas Operations.  We also have various operating leases for rental of office space, office and field equipment, 
and vehicles.  See Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations – Capital 

33

Resources and Liquidity – Off-Balance Sheet Arrangements, and Note 3, Leases, to the Consolidated Financial Statements 
for the future minimum rental payments.  Such information is incorporated herein by reference.

Denbury Resources Inc.

Item 3.  Legal Proceedings

We are involved in various lawsuits, claims and regulatory proceedings incidental to our businesses.  While we currently 
believe that the ultimate outcome of these proceedings, individually and in the aggregate, will not have a material adverse 
effect on our business or finances, litigation is subject to inherent uncertainties.  We accrue for losses from litigation and 
claims if we determine that a loss is probable and the amount can be reasonably estimated.

Riley Ridge Helium Supply Contract Claim

As part of our 2010 and 2011 acquisitions of the Riley Ridge Unit and associated gas processing facility that was under 
construction, the Company assumed a 20-year helium supply contract under which we agreed to supply the helium separated 
from  the  full  well  stream  by  operation  of  the  gas  processing  facility  to  a  third-party  purchaser, APMTG  Helium,  LLC 
(“APMTG”).  The helium supply contract provides for the delivery of a minimum contracted quantity of helium, with liquidated 
damages payable if specified quantities of helium are not supplied in accordance with the terms of the contract.  The liquidated 
damages are capped at an aggregate of $46.0 million over the term of the contract.

As the gas processing facility has been shut-in since mid-2014 due to significant technical issues, we have not been able 
to supply helium under the helium supply contract.  In a case filed in November 2014 in the Ninth Judicial District Court of 
Sublette County, Wyoming, APMTG claimed multiple years of liquidated damages for non-delivery of volumes of helium 
specified under the helium supply contract.  The Company claimed that its contractual obligations were excused by virtue of 
events that fall within the force majeure provisions in the helium supply contract.

On March 11, 2019, the trial court entered a final judgment that a force majeure condition did exist, but the Company’s 
performance was excused by the force majeure provisions of the contract for only a 35-day period in 2014, and as a result the 
Company should pay APMTG liquidated damages and interest thereon for those time periods from contract commencement 
to the close of evidence (November 29, 2017).  The Company’s position continues to be that its contractual obligations have 
been and continue to be excused by events that fall within the force majeure provisions of the helium supply contract, so the 
Company has appealed the trial court’s ruling to the Wyoming Supreme Court.  Briefing for the appeal by the Company and 
APMTG is currently expected to be completed in late May or early June, after which oral arguments will be scheduled and 
heard prior to the Wyoming Supreme Court entering its judgment on the appeal.  The timing and outcome of this appeal 
process is currently unpredictable, but at this time is anticipated to extend over the next nine to twelve months.

Absent reversal of the trial court’s ruling on appeal, the Company anticipates total liquidated damages would equal the 
$46.0 million aggregate cap under the helium supply contract plus $5.2 million of associated costs (through December 31, 
2019), for a total of $51.2 million, which is included in “Other liabilities” in our Consolidated Balance Sheets as of December 
31, 2019, and $49.4 million of which was accrued in the fourth quarter of 2018.  The Company currently has a $32.8 million 
letter of credit posted as security in this case as part of the appeal process.

Item 4.  Mine Safety Disclosures

Not applicable.

34

Denbury Resources Inc.

PART II

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

Market Information and Holders of Record

Denbury’s common stock is listed on the New York Stock Exchange under the symbol “DNR.”  As of January 31, 2020, 
based on information from the Company’s transfer agent, Broadridge Stock Transfer Agent, the number of holders of record 
of Denbury’s common stock was 1,169.

Dividends

We have not paid dividends on our common stock since the fourth quarter of 2015 and have no current plans to resume 
common  stock  dividends.    Our  Bank  Credit Agreement  and  senior  secured  second  lien,  convertible  senior,  and  senior 
subordinated note indentures require us to meet certain financial covenants at the time dividend payments are made.  For 
further discussion, see Note 6, Long-Term Debt, to the Consolidated Financial Statements.

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

Month

October 2019

November 2019

December 2019

Total

Total Number
of Shares 
Purchased(1)

Average Price
Paid per Share

20,102

$

1,884

—

21,986

1.13

1.12

—

Total Number of Shares
Purchased as Part of
Publicly Announced
Plans or Programs

Approximate Dollar 
Value of Shares that May 
Yet Be Purchased Under 
the Plans or Programs
 (in millions)(2)

— $

—

—

—

210.1

210.1

210.1

(1)  Shares purchased during the fourth quarter of 2019 were made in connection with the surrender of shares by our employees 

to satisfy their tax withholding requirements related to the vesting of restricted shares.

(2)  In October 2011, we commenced a common share repurchase program, which has been approved for up to an aggregate 
of $1.162 billion of Denbury common shares by the Company’s Board of Directors.  This program has effectively been 
suspended and we do not anticipate repurchasing shares of our common stock in the near future.  The program has no 
pre-established ending date and may be suspended or discontinued at any time.  We are not obligated to repurchase any 
dollar amount or specific number of shares of our common stock under the program.

35

Stock Performance Graph

Denbury Resources Inc.

The following Performance Graph and related information shall not be deemed “soliciting material” or to be “filed” 
with the SEC, nor shall such information be incorporated by reference into any future filings under the Securities Act of 1933 
or Securities Exchange Act of 1934, each as amended, except to the extent that the Company specifically incorporates it by 
reference into such filings.

The  following  graph  illustrates  changes  over  the  five-year  period  ended  December 31,  2019,  in  cumulative  total 
stockholder return on our common stock as measured against the cumulative total return of the S&P 500 Index and the Dow 
Jones U.S. Exploration and Production Index.  The graph tracks the performance of a $100 investment in our common stock 
and in each index (with the reinvestment of all dividends for the index securities) from December 31, 2014, to December 31, 
2019.

COMPARISON OF 5-YEAR CUMULATIVE TOTAL RETURN

2014

2015

2016

2017

2018

2019

December 31,

Denbury Resources Inc.

$

S&P 500

Dow Jones U.S. Exploration & Production

100

100

100

$

26

$

47

$

28

$

22

$

101

76

114

95

138

96

132

79

18

174

88

36

 
 
Item 6. Selected Financial Data

Denbury Resources Inc.

In thousands, except per-share data or otherwise noted

2019

2018

2017

2016

2015

Year Ended December 31,

Consolidated Statements of Operations data

Revenues and other income

Oil, natural gas, and related product sales

Other

Total revenues and other income

Net income (loss)(1)

Net income (loss) per common share

Basic(1)
Diluted(1)

Dividends declared per common share(2)

Weighted average number of common shares outstanding

Basic

Diluted

Consolidated Statements of Cash Flows data

$

$

1,212,020

62,863

1,274,883

216,959

$

$

1,422,589

51,036

1,473,625

322,698

$

$

1,089,666

40,120

1,129,786

163,152

$

$

935,751

39,845

975,596

$

$

1,213,026

44,534

1,257,560

(976,177)

(4,385,448)

0.47

0.45

—

0.75

0.71

—

0.42

0.41

—

(2.61)

(2.61)

—

459,524

510,341

432,483

456,169

390,928

395,921

373,859

373,859

(12.57)

(12.57)

0.1875

348,802

348,802

Cash provided by (used in)

Operating activities
Investing activities(3)

Financing activities

Production (average daily)

Oil (Bbls)

Natural gas (Mcf)

BOE (6:1)

$

494,143

$

529,685

$

267,143

$

219,223

$

864,304

(269,692)

(246,355)

(333,276)

(157,452)

(356,814)

88,613

(204,663)

(15,012)

(549,730)

(334,460)

56,672

9,246

58,213

58,532

10,854

60,341

58,410

11,329

60,298

61,440

15,378

64,003

Unit sales prices – excluding impact of derivative settlements

Oil (per Bbl)

Natural gas (per Mcf)

$

58.26

$

66.11

$

50.64

$

41.12

$

2.06

2.58

2.41

1.98

Unit sales prices – including impact of derivative settlements

Oil (per Bbl)

Natural gas (per Mcf)

Costs per BOE

Lease operating expenses(4)

Taxes other than income

General and administrative expenses
Depletion, depreciation, and amortization(5)

Proved oil and natural gas reserves

$

$

Oil (MBbls)

Natural gas (MMcf)

MBOE (6:1)

Proved carbon dioxide reserves
Gulf Coast region (MMcf)(6)
Rocky Mountain region (MMcf)(7)

Consolidated Balance Sheets data

Total assets

Total long-term liabilities

Stockholders’ equity

59.40

$

57.91

$

48.40

$

44.86

$

2.06

2.58

2.41

1.98

22.46

$

22.24

$

20.35

$

17.71

$

4.41

3.91

11.00

226,133

24,334

230,189

4.75

3.25

9.83

255,042

43,008

262,210

3.96

4.63

9.44

252,625

42,721

259,745

3.33

4.69

36.12

247,103

44,315

254,489

4,786,881

1,120,060

4,982,440

1,155,538

5,164,741

1,187,787

5,332,576

1,214,428

5,501,175

1,237,603

$

4,691,867

$

4,723,222

$

4,471,299

$

4,274,578

$

5,885,533

2,915,366

1,412,259

3,216,652

1,141,777

3,365,077

648,165

3,372,634

468,448

4,263,606

1,248,912

37

69,165

22,172

72,861

47.30

2.35

67.41

2.83

19.37

4.13

5.44

19.99

282,250

38,305

288,634

 
Denbury Resources Inc.

(1)  Includes pre-tax impairments of assets of $810.9 million and $6.2 billion for the years ended December 31, 2016 and 
2015, respectively, and an accelerated depreciation charge of $591.0 million related to the Riley Ridge gas processing 
facility and related assets for the year ended December 31, 2016.

(2)  In September 2015, in light of the low oil price environment and our desire to maintain our financial strength and flexibility, 

the Company’s Board of Directors suspended our quarterly cash dividend.

(3)  Reflects  the  adoption  of  Financial Accounting  Standards  Board  (“FASB”) Accounting  Standards  Update  (“ASU”) 
2016-18,  Statement  of  Cash  Flows  (“ASU  2016-18”),  whereby  changes  in  restricted  cash  are  now  included  in  the 
consolidated  statements  of  cash  flows.    We  adopted ASU  2016-18  effective  January  1,  2018,  which  was  applied 
retrospectively to all periods presented.

(4)  Lease operating expenses reported in this table for 2015 include certain special items comprised of (1) lease operating 
expenses and related insurance recoveries recorded to remediate an area of Delhi Field, (2) a reimbursement for a retroactive 
utility rate adjustment, and (3) other insurance recoveries.  If these special items are excluded, lease operating expenses 
would have totaled $528.8 million, or $19.88 per BOE, for the year ended December 31, 2015.

(5)  Depletion, depreciation, and amortization during the year ended December 31, 2016 includes an accelerated depreciation 
charge of $591.0 million, or $25.23 per BOE, associated with the Riley Ridge gas processing facility and related assets.

(6)  Proved CO2 reserves in the Gulf Coast region consist of reserves from our reservoirs at Jackson Dome and are presented 
on a gross or 8/8ths working interest basis, of which our net revenue interest was approximately 3.8 Tcf, 4.0 Tcf, 4.1 Tcf, 
4.2 Tcf and 4.4 Tcf at December 31, 2019, 2018, 2017, 2016 and 2015, respectively, and include reserves dedicated to 
volumetric production payments of 3.1 Bcf, 7.6 Bcf, 12.3 Bcf and 25.3 Bcf at December 31, 2018, 2017, 2016 and 2015, 
respectively (see Supplemental CO2 Disclosures (Unaudited) to the Consolidated Financial Statements).

(7)  Proved CO2 reserves in the Rocky Mountain region consist of our overriding royalty interest in LaBarge Field, of which 
our net revenue interest was approximately 1.1 Tcf, 1.2 Tcf, 1.2 Tcf, 1.2 Tcf and 1.2 Tcf at December 31, 2019, 2018, 
2017,  2016  and  2015,  respectively  (see  Supplemental  CO2  Disclosures  (Unaudited)  to  the  Consolidated  Financial 
Statements).

38

Denbury Resources Inc. 
Management’s Discussion and Analysis of Financial Condition and Results of Operations

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis should be read in conjunction with our Consolidated Financial Statements and 
Notes thereto included in Item 8, Financial Statements and Supplementary Information.  Our discussion and analysis includes 
forward-looking information that involves risks and uncertainties and should be read in conjunction with Risk Factors under 
Item 1A of this Form 10-K, along with Forward-Looking Information at the end of this section for information on the risks 
and uncertainties that could cause our actual results to be materially different from our forward-looking statements.  For a 
discussion of the financial results for the fiscal year ended December 31, 2017, see Part II, Item 7, Management’s Discussion 
and Analysis of Financial Condition and Results of Operations, of our Annual Report on Form 10-K for the fiscal year ended 
December 31, 2018, as filed with the SEC on March 1, 2019.

OVERVIEW

Denbury is an independent oil and natural gas company with operations focused in two key operating areas: the Gulf 
Coast and Rocky Mountain regions.  Our goal is to increase the value of our properties through a combination of exploitation, 
drilling and proven engineering extraction practices, with the most significant emphasis relating to CO2 enhanced oil recovery 
operations.

Oil Price Impact on Our Business.  Our financial results are significantly impacted by changes in oil prices, as 97% of 
our production is oil.  Changes in oil prices impact all aspects of our business, most notably our cash flows from operations, 
revenues, and capital allocation and budgeting decisions.  The table below outlines changes in our realized oil prices over the 
last three years, before and after commodity hedging impacts:

Year Ended December 31,

2019

2018

2017

Average net realized prices

Oil price per Bbl - excluding impact of derivative settlements

$

58.26

$

66.11

$

Oil price per Bbl - including impact of derivative settlements

59.40

57.91

50.64

48.40

We remained disciplined with our capital spending throughout 2019 despite oil prices averaging higher than the $50 per 
Bbl NYMEX oil price used in preparing our 2019 capital budget.  Our 2019 capital expenditure level of $236.9 million was 
below the low end of our budgeted range of $240 million to $260 million, and we generated approximately $165 million of 
cash flow in excess of capital expenditures and capitalized interest (excluding working capital changes and severance-related 
expense, but including interest payments treated as repayment of debt in our financial statements).

Comparative Financial Results and Highlights.   During 2019, we recognized net income of $217.0 million, or $0.45
per diluted common share, compared to net income of $322.7 million, or $0.71 per diluted common share, during 2018.  The 
primary drivers of our change in operating results and per diluted share amounts between 2018 and 2019 were the following:

•  Oil and natural gas revenues decreased by $210.6 million (15%), with 11% of the decrease due to lower commodity prices 
and 4% of the decrease due to lower production, offset in part by an improvement in derivative commodity settlements 
of $198.8 million from the prior year;

•  Commodity  derivative  expense  increased  by  $91.2  million,  resulting  from  a  $198.8  million  improvement  in  cash 
settlements ($175.2 million of cash payments in 2018 compared to $23.6 million of cash receipts in 2019) which was 
more than offset by $290.0 million of expense for noncash fair value changes in commodity derivatives between 2018 
and 2019;

•  A noncash gain on debt extinguishment of $156.0 million in 2019 (see 2019 Debt Reduction Transactions below);
• 

$18.6  million  of  severance  expense  in  2019  associated  with  our  voluntary  separation  program  (see  December  2019
Voluntary Separation Program below);

•  A $73.1 million reduction in other expense, as 2018 included $49.4 million of litigation expense and a $17.8 million asset 

impairment; and

•  Our diluted per share net income in 2019 was affected by the inclusion of an additional 90.9 million shares of the Company’s 
common stock issuable upon conversion of our convertible senior notes which were issued in June 2019, increasing our 

39

 
 
 
 
Denbury Resources Inc. 
Management’s Discussion and Analysis of Financial Condition and Results of Operations

diluted share count by those shares for the portion of the year the notes were outstanding (see Note 1, Nature of Operations 
and  Summary  of  Significant  Accounting  Policies  –  Net  Income  per  Common  Share,  to  the  Consolidated  Financial 
Statements).

2019 Debt Reduction Transactions.  During 2019, we completed a series of debt exchanges and repurchases to extend 

the maturities of our outstanding long-term debt and reduce our debt principal as described below:

•  During June 2019, through a series of debt exchanges, we extended the maturities of $348.4 million of our outstanding 
long-term debt to 2024 and reduced our debt principal by $120.0 million, with holders exchanging $468.4 million aggregate 
principal amount of our subordinated notes for:
– 

$245.5 million aggregate principal amount of our new 6 % Convertible Senior Notes due 2024 (the “2024 Convertible 
Senior Notes”);
$102.6 million aggregate principal amount of new 7¾% Senior Secured Second Lien Notes due 2024 (the “7¾% 
Senior Secured Notes”); and
$120.0 million of cash.

– 

– 

•  During June and July 2019, as part of creating a more liquid series of secured second lien debt due in 2024, we also 
exchanged $429.2 million aggregate principal amount of 7¾% Senior Secured Notes for $429.4 million of previously 
outstanding 7½% Senior Secured Second Lien Notes due 2024.  As a result of all of the above June and July note exchanges, 
we recognized a gain on debt extinguishment, net of transaction costs, totaling $100.5 million for the year ended December 
31, 2019, in our Consolidated Statements of Operations.

•  Between August  and  November  2019,  we  repurchased  $112.1  million  (approximately  31%)  of  our  $357.8  million 
aggregate principal amount of senior subordinated notes outstanding as of June 30, 2019 for $16.4 million of cash and 
issuance of 38.3 million shares of the Company’s common stock.  In connection with these transactions, we recognized 
a $55.5 million gain on debt extinguishment, net of unamortized debt issuance costs written off, during the year ended 
December 31, 2019, in our Consolidated Statements of Operations.

The table below details the changes in our debt principal balances from December 31, 2018 to December 31, 2019:

In thousands
Senior Secured Bank Credit Agreement
9% Senior Secured Second Lien Notes due 2021
9¼% Senior Secured Second Lien Notes due 2022
7¾% Senior Secured Second Lien Notes due 2024
7½% Senior Secured Second Lien Notes due 2024
6 % Convertible Senior Notes due 2024

5½% Senior Subordinated Notes due 2022

Pipeline financings
Capital lease obligations

Total debt principal balance

December 31,
2018

$

— $

614,919
455,668
—
450,000
—
203,545
314,662
307,978
180,073
5,362
2,532,207

$

$

Change

December 31,
2019

— $
—
—
531,821
(429,359)
245,548
(152,241)
(256,236)
(172,018)
(12,634)
(5,362)
(250,481) $

—
614,919
455,668
531,821
20,641
245,548
51,304
58,426
135,960
167,439
—
2,281,726

July 2019 Citronelle Field Divestiture.  On July 1, 2019, we closed the sale of one of our mature Gulf Coast fields, 

Citronelle Field, for $10 million.

December 2019 Voluntary Separation Program.  During December 2019, we made a voluntary separation program 
(“VSP”) offer to certain eligible employees as part of the Company’s ongoing efforts to reduce costs.  One hundred employees 
(approximately 12% of our workforce) voluntarily chose to participate in the VSP, comprising employees both in corporate 
headquarters and in the field, with most of the impacted employees terminating employment by the end of January 2020.  We 

40

Denbury Resources Inc. 
Management’s Discussion and Analysis of Financial Condition and Results of Operations

recognized  expense  of  $18.6  million  in  “General  and  administrative  expenses”  in  our  2019  Consolidated  Statements  of 
Operations for severance and related costs.  We estimate ongoing annual savings associated with the reduction in force to be 
approximately  $21  million  (starting  in  2020),  with  such  savings  allocated  across  general  and  administrative  expense 
(approximately 45%), lease operating expense (approximately 25%) and capitalized costs (approximately 30%).

Pending Sale of Working Interests in Certain Texas Fields.  On December 20, 2019, we entered into a definitive 
agreement to sell half of our nearly 100% working interest positions in four conventional southeast Texas oil fields (consisting 
of Webster, Thompson, Manvel, and East Hastings) for $50 million cash and a carried interest in ten wells to be drilled by the 
purchaser (the “Pending Gulf Coast Working Interests Sale”).  The sale is currently expected to occur in early March 2020.  
Under the agreement, the purchaser is committed to funding 100% of the capital required to drill and complete an initial ten 
horizontal wells across the fields, with the first of the ten wells to be spud within six months of closing and with all ten wells 
to be completed within 18 months after closing.  On these initial ten wells, Denbury will receive a 6.25% overriding royalty 
interest prior to the combined payout of the wells in a specified field and subsequent to payout, Denbury will receive production 
revenues from, and bear the cost of, its 50% working interest in each well.  As part of the agreement, we will retain 100% 
ownership of the future Webster Unit CO2 flood, wherein (1) the purchaser may elect to participate in the future CO2 flood 
through reimbursement to Denbury of the purchaser’s working interest share of project costs incurred to date, or (2) if the 
purchaser declines to participate in the CO2 flood, we have the right to repurchase the purchaser’s working interest in Webster 
Field under a contractually agreed valuation mechanism.

CAPITAL RESOURCES AND LIQUIDITY

Overview.  Our primary sources of capital and liquidity are our cash flows from operations and availability of borrowing 
capacity  under  our  senior  secured  bank  credit  facility,  which  has  been  supplemented  periodically  by  asset  sale  proceeds 
associated with sales of surface land with no active oil and natural gas operations and minor producing asset sales as discussed 
above.  During 2019, we generated cash flows from operations of $494.1 million, while incurring capital expenditures of 
$236.9 million and capitalized interest of $36.7 million, resulting in approximately $165 million of cash flow in excess of 
capital expenditures (excluding working capital changes and severance-related expense, but including $85.3 million of interest 
payments  treated  as  repayment  of  debt  in  our  financial  statements).   As  of  December 31,  2019,  we  had  no  outstanding 
borrowings on our $615 million senior secured bank credit facility, consistent with December 31, 2018, leaving us with $527.8 
million of borrowing base availability after consideration of $87.2 million of letters of credit outstanding.

Over the last several years of generally lower oil prices and high volatility, we have remained focused on our disciplined 
approach of spending within cash flow and preserving liquidity under our bank line.  During this time, we have also remained 
keenly focused on reducing leverage and improving the Company’s financial position, resulting in a $250.5 million reduction 
in our debt principal during 2019, which is on top of a $243.2 million reduction in our debt principal in 2018.  In total, we 
reduced our outstanding debt principal by nearly $1.3 billion between December 31, 2014 and December 31, 2019, primarily 
through debt exchanges, opportunistic open market debt repurchases, and the conversion in the second quarter of 2018 of all 
of our then outstanding convertible senior notes into common stock.  Our leverage metrics have improved considerably over 
the last several years, due primarily to our cost reduction efforts and our overall reduction in debt.  

In 2019, we completed a series of debt exchanges and repurchases to extend the maturities of a portion of our long-term 
debt  and  reduce  our  debt  principal  (see  Overview  –  2019  Debt  Reduction  Transactions).   Additionally,  these  exchange 
transactions could further contribute to debt reduction of up to $245.5 million if all of the 2024 Convertible Senior Notes 
convert to Company common stock at some time in the future, including automatic conversion into shares of common stock 
if the volume weighted average trading price of the Company’s common stock equals or exceeds $2.43 per share for 10 trading 
days in any period of 15 consecutive trading days. 

Although we have no significant maturities of debt in 2020, we have $614.9 million of 9% Senior Secured Second Lien 
Notes maturing on May 15, 2021 (the “2021 Senior Secured Notes”) and $455.7 million of 9¼% Senior Secured Second Lien 
Notes due 2022 maturing on March 31, 2022 (the “2022 Senior Secured Notes”).  In relation to the 2021 Senior Secured 
Notes, our bank credit agreement contains a springing maturity if such notes are not refinanced or their maturity is not extended 
by mid-February 2021 (see Risk Factors – Our bank credit facility maturity date “springs forward” to dates earlier than 
December 9, 2021 if certain conditions are not satisfied).  We are actively evaluating options to reduce or extend the maturities 
of our long-term debt, with focus on our second lien debt maturing between May 2021 and March 2022.  In conjunction with 

41

Denbury Resources Inc. 
Management’s Discussion and Analysis of Financial Condition and Results of Operations

our debt reduction and extension efforts, we may engage in transactions of various types, including public or private capital 
raising, debt exchange transactions, debt repurchases with proceeds from joint ventures or asset sales, or some combination 
of these methods.

2020 Capital Budget.  Since the beginning of 2020, NYMEX oil prices have moved downward by over $10 per barrel 
(from the low $60s per barrel in early January to around $50 per barrel in mid-February 2020), due in part to concerns about 
the COVID-19 coronavirus and its real and potential impact on near-term worldwide oil demand.  In consideration of the 
current oil price environment and the Company’s desire to preserve ongoing liquidity, we have set our 2020 base capital budget 
at between $175 million and $185 million (excluding capitalized interest), which includes $10 million of capital dedicated to 
continuing near-term CO2 development activities at Cedar Creek Anticline (“CCA”) as further discussed below.  This 2020 
base capital budget is a $57 million (24%) reduction from our 2019 actual capital expenditure level.  We currently anticipate 
that our 2020 base capital budget of $175 million to $185 million will be more than fully funded with cash flow from operations 
(assuming a $50 per barrel NYMEX oil price) and should result in the Company generating upwards of $100 million of cash 
in excess of our capital expenditures, without including the proceeds from the Pending Gulf Coast Working Interests Sale 
(from which we expect net proceeds of approximately $40 million) or the impact of any other potential transactions.  We also 
have oil price hedges on approximately 70% of our estimated 2020 production in order to protect against downward oil price 
volatility and to provide a degree of certainty in our 2020 estimated cash flow.

An additional $140 million to $150 million of capital for the CCA CO2 tertiary flood development, most of which is 
scheduled to be spent in the second half of the year, is subject to the Company’s ongoing assessment and evaluation of all 
relevant  factors,  including  oil  price  changes  and  expectations,  and  the  Company’s  capital  resources  and  liquidity,  and  is 
conditioned upon future Board approval.  The aggregate $155 million of planned 2020 CCA tertiary-related development 
capital consists of $105 million for the 105-mile extension of the Greencore Pipeline to CCA, with the remainder dedicated 
to facilities, well work and field development.  The Company currently anticipates finalizing its 2020 capital plans for CCA 
during the second quarter.

Based on our capital spending plans, we currently anticipate 2020 average daily production to be between 53,000 and 
56,000 BOE/d, after adjusting for the Pending Gulf Coast Working Interests Sale (see Overview – Pending Sale of Working 
Interests in Certain Texas Fields).  The production associated with the Pending Gulf Coast Working Interests Sale averaged 
1,170 BOE/d during the fourth quarter of 2019.  Our anticipated 2020 production level compares to 2019 average continuing 
production of 56,914 BOE/d, after reduction for 2019 property divestitures and production associated with the Pending Gulf 
Coast Working Interests Sale.

Senior Secured Bank Credit Facility.  In December 2014, we entered into an Amended and Restated Credit Agreement 
with JPMorgan Chase Bank, N.A., as administrative agent, and other lenders party thereto (as amended, the “Bank Credit 
Agreement”), which has been amended periodically since that time.  The Bank Credit Agreement is a senior secured revolving 
credit facility with a maturity date of December 9, 2021, provided that the maturity date may occur earlier (February 12, 2021, 
May 14, 2021 or August 13, 2021) if our 2021 Senior Secured Notes or 6 % Senior Subordinated Notes due in August 2021, 
respectively, are not repaid or refinanced by each of their respective maturity dates (see Risk Factors – Our bank credit facility 
maturity date “springs forward” to dates earlier than December 9, 2021 if certain conditions are not satisfied).  The Bank 
Credit Agreement contains certain financial performance covenants through the maturity of the facility, including the following:

•  A Consolidated Total Debt to Consolidated EBITDAX financial maintenance covenant, with such ratio not to exceed 

5.25 to 1.0 through December 31, 2020 and 4.50 to 1.0 thereafter;

•  A consolidated senior secured debt to consolidated EBITDAX covenant, with such ratio not to exceed 2.5 to 1.0.  Only 

debt under our Bank Credit Agreement is considered consolidated senior secured debt for purposes of this ratio;

•  A minimum permitted ratio of consolidated EBITDAX to consolidated interest charges of 1.25 to 1.0; and
•  A requirement to maintain a current ratio (i.e., Consolidated Current Assets to Consolidated Current Liabilities) of 1.0 to 

1.0.

For purposes of computing the current ratio per the Bank Credit Agreement, Consolidated Current Assets exclude the 
current portion of derivative assets but include borrowing base availability under the senior secured bank credit facility, and 
Consolidated Current Liabilities exclude the current portion of derivative liabilities as well as the current portions of long-
term indebtedness outstanding.  

42

Denbury Resources Inc. 
Management’s Discussion and Analysis of Financial Condition and Results of Operations

Under these financial performance covenant calculations, as of December 31, 2019, our ratio of consolidated total debt 
to consolidated EBITDAX was 3.74 to 1.0 (with a maximum permitted ratio of 5.25 to 1.0), our ratio of consolidated senior 
secured debt to consolidated EBITDAX was 0.00 to 1.0 (with a maximum permitted ratio of 2.5 to 1.0), our ratio of consolidated 
EBITDAX to consolidated interest charges was 3.17 to 1.0 (with a required ratio of not less than 1.25 to 1.0), and our current 
ratio was 2.75 to 1.0 (with a required ratio of not less than 1.0 to 1.0).  Based upon our currently forecasted levels of production 
and costs, hedges in place as of February 24, 2020, and current oil commodity futures prices, we currently anticipate continuing 
to be in compliance with our financial performance covenants during the foreseeable future.

The above description of our Bank Credit Agreement is qualified by the express language and defined terms contained 
in the Bank Credit Agreement and the amendments thereto, which are filed as exhibits to our periodic reports filed with the 
SEC.

2020 Capital Budget Allocation and Estimated Cash Flows.  We have established a base 2020 capital expenditure 
budget, excluding capitalized interest and acquisitions, of between $175 million and $185 million, roughly a 24% decrease 
from 2019 capital spending levels of $236.9 million, with an additional $140 million to $150 million of capital for the CCA 
CO2 tertiary flood development conditioned upon future Board approval (see 2020 Capital Budget).  Capitalized interest is 
currently estimated at approximately $40 million to $45 million for 2020.  The 2020 capital budget, excluding capitalized 
interest and acquisitions, provides for approximate spending as follows:

• 
• 
• 
• 

$75 million allocated for tertiary oil field expenditures;
$55 million allocated for other areas, primarily non-tertiary oil field expenditures including exploitation;
$10 million to be spent on CO2 sources and pipelines; and 
$40 million for other capital items such as capitalized internal acquisition, exploration and development costs and 
pre-production tertiary startup costs.

An additional $140 million to $150 million of CCA CO2 tertiary flood development capital is subject to Board approval.  
The aggregate planned 2020 CCA tertiary-related development capital consists of approximately $105 million for the 105-
mile extension of the Greencore Pipeline to CCA, with the remainder dedicated to facilities, well work and field development.

Based upon our currently forecasted levels of production and costs, commodity hedges in place, and assuming a $50 
NYMEX oil price in 2020, we expect that our cash flow from operations should significantly exceed our base 2020 capital 
expenditure budget of $175 million to $185 million, by upwards of $100 million.  Assuming the additional $140 million to 
$150 million of CCA capital spending is approved, we would expect that our capital expenditures would be relatively equal 
to our cash resources (inclusive of cash flow from operations and $40 million of anticipated cash proceeds from the Pending 
Gulf Coast Working Interests Sale) before considering any other potential land sales.  If prices were to decrease or changes 
in operating results were to cause a reduction in anticipated 2020 cash flows significantly below our currently forecasted 
operating cash flows, we would likely reduce our capital expenditures.  Any sizeable reduction in our capital spending due to 
lower cash flows would likely lower our anticipated production levels in future years.

43

Denbury Resources Inc. 
Management’s Discussion and Analysis of Financial Condition and Results of Operations

Capital Expenditure Summary.  The following table reflects incurred capital expenditures (including accrued capital) 

for the years ended December 31, 2019, 2018 and 2017:

In thousands

Capital expenditures by project

Tertiary oil fields

Non-tertiary fields
Capitalized internal costs(1)

Oil and natural gas capital expenditures

CO2 pipelines, sources and other
Capital expenditures, before acquisitions and capitalized interest

Acquisitions of oil and natural gas properties

Capital expenditures, before capitalized interest

Capitalized interest

Capital expenditures, total

Year Ended December 31,

2019

2018

2017

$

93,331

$

142,560

$

129,458

71,014

46,031

210,376

26,545

236,921

284

237,205
36,671

104,811

46,599

293,970

28,700

322,670

541

323,211
37,079

$

273,876

$

360,290

$

53,647

52,616

235,721

5,105

240,826

88,777

329,603
30,762

360,365

(1)  Includes capitalized internal acquisition, exploration and development costs and pre-production tertiary startup costs.

Commitments and Obligations.  A summary of our obligations at December 31, 2019, is presented in the following 

table:

In thousands

Contractual obligations

Payments Due by Period

2020

2021 and
2022

2023 and
2024

Thereafter

Total

Estimated interest payments on senior secured bank credit
facility, senior secured second lien notes, convertible senior
notes, and subordinated debt

Senior secured debt (principal balance)

Convertible senior notes (principal balance)

Subordinated debt (principal balance)

Operating lease obligations

Pipeline obligations including interest component
Other obligations(1)
Commodity derivative liabilities(2)
Asset retirement obligations(3)

$

171,321

$

211,661

$

82,823

$

— $

465,805

—

—

—

9,934

27,822

60,836

8,346

4,652

1,070,587

—

109,730

20,315

55,380

93,600

—

—

552,462

245,548

135,960

20,617

53,806

65,469

—

51,727

—

—

—

8,287

88,951

89,615

—

744,729

1,623,049

245,548

245,690

59,153

225,959

309,520

8,346

801,108

Total contractual obligations

$

282,911

$

1,561,273

$

1,208,412

$

931,582

$

3,984,178

(1)  Represents future cash commitments under contracts in place as of December 31, 2019, primarily for purchase contracts 
for CO2 captured from industrial sources, transportation agreements and well-related costs, but excludes any potential 
payments related to the APMTG litigation being appealed.  As is common in our industry, we commit to make certain 
expenditures  on  a  regular  basis  as  part  of  our  ongoing  development  and  exploration  program.  These  commitments 
generally relate to projects that occur during the subsequent several months and are usually part of our normal operating 
expenses or part of our capital budget (see 2020 Capital Budget Allocation and Estimated Cash Flows above).  We also 
have recurring expenditures for such things as accounting, engineering and legal fees; software maintenance; subscriptions; 
and other overhead-type items.  Normally these expenditures do not change materially on an aggregate basis from year 
to year and are part of our general and administrative expenses.  We have not attempted to estimate the amounts of these 
types of recurring expenditures in this table, as most could be quickly canceled with regard to any specific vendor, even 
though the expense itself may be required for our ongoing normal operations.  For further discussion of our long-term 

44

 
 
 
 
 
 
 
 
 
Denbury Resources Inc. 
Management’s Discussion and Analysis of Financial Condition and Results of Operations

commitments  to  purchase  CO2  and  any  payments  related  to  the  APMTG  litigation  being  appealed,  see  Note  12, 
Commitments and Contingencies, to the Consolidated Financial Statements.

(2)  Commodity derivative liabilities represent the fair value of our commodity derivatives presented as liabilities in our 
Consolidated Balance Sheets as of December 31, 2019.  The ultimate settlement amounts of our derivative obligations 
are  unknown  because  they  are  subject  to  continuing  market  fluctuations.    See  further  discussion  of  our  commodity 
derivative  contracts  and  their  market  price  sensitivities  in  Market  Risk  Management  below  in  this  Management’s 
Discussion  and Analysis  of  Financial  Condition  and  Results  of  Operations,  and  in  Note  10,  Commodity  Derivative 
Contracts, to the Consolidated Financial Statements.

(3)  Represents the estimated future asset retirement obligations on an undiscounted basis.  The present value of the discounted 
asset retirement obligation is $181.8 million, as determined under the Asset Retirement and Environmental Obligations 
topic of the Financial Accounting Standards Board Codification (“FASC”), and is further discussed in Note 4, Asset 
Retirement Obligations, to the Consolidated Financial Statements.

Off-Balance  Sheet Arrangements.   As  of  December  31,  2019,  we  had  a  total  of  $87.2  million of  letters  of  credit 
outstanding under our senior secured bank credit facility, which outstanding total increased during 2019 principally due to 
posting of a $32.8 million letter of credit as part of the appeal process in the APMTG litigation in Wyoming.  Additionally, 
we have obligations for development and exploratory expenditures that arise from our normal capital expenditure program 
or from other transactions common to our industry, none of which are recorded on our balance sheet.  These obligations are 
further described in Commitments and Obligations above.  In addition, in order to recover our undeveloped proved reserves, 
we must also fund the associated future development costs estimated in our proved reserve reports, which are only included 
in  the  table  above  to  the  extent  we  have  firm  contracts.  For  a  further  discussion  of  our  future  development  costs,  see 
Supplemental Oil and Natural Gas Disclosures (Unaudited) to the Consolidated Financial Statements.

FINANCIAL OVERVIEW OF TERTIARY OPERATIONS

As discussed in Item 1, Business and Properties – Oil and Natural Gas Operations – Enhanced Oil Recovery Overview , 
our tertiary operations represent a significant portion of our overall operations and have become our primary strategic focus.  
The economics of a tertiary field and the related impact on our financial statements differ from a conventional oil and gas 
play and are explained further below.

While it is difficult to accurately forecast future production, we believe our tertiary recovery operations provide significant 
long-term production growth potential at reasonable return metrics, with relatively low risk, assuming crude oil prices are at 
levels that support the development of those projects.  We have been developing tertiary oil properties for over 20 years, and 
the financial impact of such operations is reflected in our historical financial statements.  The summary below highlights our 
observations regarding how tertiary operations have impacted our financial statements.

Finding and Development Costs.  We currently expect finding and development costs (including future development 
and  abandonment  costs  but  excluding  CO2  pipeline  infrastructure  capital  expenditures)  over  the  life  of  each  field  to  be 
competitive with the industry average costs for other oil properties.  See the definition of finding and development costs in 
the Glossary and Selected Abbreviations.

Timing of Capital Costs.  When initiating a new tertiary flood, there generally is a delay between the initial capital 
expenditures and the resulting production increases.  We must build facilities, and often a CO2 pipeline to the field, before 
CO2 flooding can commence, and it usually takes six to twelve months before the field responds to the injection of CO2 (i.e., 
oil production commences).  Further, we may spend significant amounts of capital before we can recognize any proved reserves 
from fields we flood and, even after a field has proved reserves, significant amounts of additional capital will usually be 
required to fully develop the field.

Recognition of Proved Reserves.  In order to recognize proved tertiary oil reserves, we must either demonstrate production 
resulting from the tertiary process or the field must be analogous to an existing tertiary flood.  The magnitude of proved 
reserves that we can book in any given year will depend on our progress with new floods, the timing of the production response 

45

 
Denbury Resources Inc. 
Management’s Discussion and Analysis of Financial Condition and Results of Operations

from new floods and the performance of our existing floods.  Typically, a high percentage of the potential reserves for a tertiary 
field are recognized when a production response is initially observed, and generally only modest changes are made thereafter.

Production Rates.  The production rate at a tertiary flood can vary from quarter to quarter, as a tertiary field’s production 
may increase rapidly when wells respond to the CO2, plateau temporarily, and then resume growth as additional areas of the 
field are developed.  During a tertiary flood life cycle, facility capacity is increased from time to time, which occasionally 
requires temporary shutdowns during installation, thereby causing temporary declines in production.  We also find it difficult 
to precisely predict when any given well will respond to the injected CO2, as the CO2 seldom travels through the rock consistently 
due to heterogeneity in the oil-bearing formations.  With the lower level of oil prices over the past several years, our pace of 
development has generally slowed, thereby reducing our Company-wide production rates.  We find all of these fluctuations 
to be normal and generally expect oil production at a tertiary field to increase over time until the field is fully developed, albeit 
sometimes in inconsistent patterns.  

Operating Costs.  Tertiary projects may be more expensive to operate than traditional industry operations because of the 
cost of injecting and recycling the CO2 (primarily due to the cost of the CO2 and the significant energy requirements to re-
compress the CO2 back into a near-liquid state for re-injection purposes).  The costs of our CO2 and the electricity required 
to recycle and inject this CO2 comprise nearly half of our typical tertiary operating expenses.  Since these costs vary along 
with commodity and commercial electricity prices, they are highly variable and will increase in a high-commodity-price 
environment and decrease in a low-price environment.  The cost of purchasing and/or producing CO2 for use in tertiary floods 
is allocated to our tertiary oil fields and recorded as lease operating expenses (following the commencement of tertiary oil 
production) at the time the CO2 is injected.  These costs have historically represented approximately 20% to 25% of the total 
operating costs for our tertiary operations.  Since we expense all of the operating costs to produce and inject our CO2 (following 
the commencement of tertiary oil production), operating costs per barrel for a new flood will be higher at the inception of 
CO2 injection projects because of minimal related oil production at that time.

46

Denbury Resources Inc. 
Management’s Discussion and Analysis of Financial Condition and Results of Operations

RESULTS OF OPERATIONS

Operating Results Table

Certain of our operating results and statistics for each of the last three years are included in the following table.

In thousands, except per share and unit data

Operating results

Net income

Net income per common share – basic

Net income per common share – diluted

Net cash provided by operating activities

Average daily production volumes

Bbls/d

Mcf/d

BOE/d

Operating revenues

Oil sales

Natural gas sales

Total oil and natural gas sales
Commodity derivative contracts(1)

Receipt (payment) on settlements of commodity derivatives
Noncash fair value gains (losses) on commodity derivatives(2)

Commodity derivatives income (expense)

Unit prices – excluding impact of derivative settlements

Oil price per Bbl

Natural gas price per Mcf

Unit prices – including impact of derivative settlements(1)

Oil price per Bbl

Natural gas price per Mcf

Oil and natural gas operating expenses

Lease operating expenses

Transportation and marketing expenses

Production and ad valorem taxes

Oil and natural gas operating revenues and expenses per BOE

Oil and natural gas revenues

Lease operating expenses

Transportation and marketing expenses

Production and ad valorem taxes

CO2 sources – revenues and expenses
CO2 sales and transportation fees
CO2 discovery and operating expenses
CO2 revenue and expenses, net

Year Ended December 31,

2019

2018

2017

$

216,959

$

322,698

$

163,152

0.47

0.45

0.75

0.71

0.42

0.41

494,143

529,685

267,143

56,672

9,246

58,213

58,532

10,854

60,341

58,410

11,329

60,298

$

$

$

$

$

$

$

$

$

$

1,205,083

6,937

1,212,020

23,606

(93,684)

$

$

$

(70,078) $

58.26

$

2.06

1,412,358

10,231

1,422,589

$

$

1,079,703

9,963

1,089,666

(175,248) $

196,335

21,087

66.11

2.58

$

$

(47,795)

(29,781)

(77,576)

50.64

2.41

48.40

2.41

59.40

$

57.91

$

2.06

2.58

477,220

$

489,720

$

447,799

41,810

86,820

43,942

96,589

57.04

$

64.59

$

22.46

1.97

4.09

22.24

2.00

4.39

34,142

(2,922)

31,220

$

$

31,145

(2,816)

28,329

$

$

44,064

79,198

49.51

20.35

2.00

3.60

26,182

(3,099)

23,083

(1)  See also Commodity Derivative Contracts below and Market Risk Management for information concerning our commodity 

derivative transactions.

47

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Denbury Resources Inc. 
Management’s Discussion and Analysis of Financial Condition and Results of Operations

(2)  Noncash fair value gains (losses) on commodity derivatives is a non-GAAP measure and is different from “Commodity 
derivatives expense (income)” in the Consolidated Statements of Operations in that the noncash fair value gains (losses) 
on commodity derivatives represent only the net changes between periods of the fair market values of commodity derivative 
positions, and exclude the impact of settlements on commodity derivatives during the period, which were receipts on 
settlements of $23.6 million for the year ended December 31, 2019 and payments on settlements of $175.2 million and 
$47.8 million for the years ended December 31, 2018 and 2017, respectively.  We believe that noncash fair value gains 
(losses) on commodity derivatives is a useful supplemental disclosure to “Commodity derivatives expense (income)” in 
order to differentiate noncash fair market value adjustments from receipts or payments upon settlements on commodity 
derivatives during the period.  This supplemental disclosure is widely used within the industry and by securities analysts, 
banks and credit rating agencies in calculating EBITDA and in adjusting net income (loss) to present those measures on 
a comparative basis across companies, as well as to assess compliance with certain debt covenants.  Noncash fair value 
gains (losses) on commodity derivatives is not a measure of financial or operating performance under GAAP, nor should 
it  be  considered  in  isolation  or  as  a  substitute  for  “Commodity  derivatives  expense  (income)”  in  the  Consolidated 
Statements of Operations.  See also the Glossary and Selected Abbreviations for the definition of noncash fair value gains 
(losses) on commodity derivatives.

48

Denbury Resources Inc. 
Management’s Discussion and Analysis of Financial Condition and Results of Operations

Production 

Average daily production by area for 2019, 2018 and 2017, and for each of the quarters of 2019, is shown below:

Average Daily Production (BOE/d)

2019 Quarters

Year Ended December 31,

First
Quarter

Second
Quarter

Third
Quarter

Fourth
Quarter

2019

2018

2017

Operating Area

Tertiary oil production

Gulf Coast region

Delhi 

Hastings

Heidelberg

Oyster Bayou

Tinsley

West Yellow Creek
Mature properties(1)

4,474

5,539

3,987

4,740

4,659

436

6,479

4,486

5,466

4,082

4,394

4,891

586

6,448

4,256

5,513

4,297

3,995

4,541

728

6,415

4,085

5,097

4,409

4,261

4,343

807

6,347

4,324

5,403

4,195

4,345

4,608

640

6,422

4,368

5,596

4,355

4,843

5,530

205

6,702

Total Gulf Coast region

30,314

30,353

29,745

29,349

29,937

31,599

Rocky Mountain region

Bell Creek
Salt Creek(2) 
Grieve

Total Rocky Mountain region

Total tertiary oil production

Non-tertiary oil and gas production

Gulf Coast region

Mississippi
Texas(3)
Other

Total Gulf Coast region

Rocky Mountain region

Cedar Creek Anticline

Other

Total Rocky Mountain region

Total non-tertiary production

Total continuing production

Property sales

Property divestitures(4)

Total production

4,650

2,057

52

6,759

37,073

1,034

4,345

10

5,389

14,987

1,313

16,300

21,689

58,762

456

59,218

5,951

2,078

41

8,070

38,423

1,025

4,243

6

5,274

14,311

1,305

15,616

20,890

59,313

406

59,719

4,686

2,213

58

6,957

36,702

873

4,268

6

5,147

13,354

1,238

14,592

19,739

56,441

5,618

2,223

60

7,901

37,250

952

4,382

5

5,339

13,730

1,192

14,922

20,261

57,511

—

—

56,441

57,511

5,228

2,143

53

7,424

37,361

970

4,310

6

5,286

14,090

1,262

15,352

20,638

57,999

214

58,213

4,113

2,109

7

6,229

37,828

960

4,546

13

5,519

14,837

1,431

16,268

21,787

59,615

726

60,341

4,869

4,830

4,851

5,007

6,430

13

7,078

33,078

3,313

1,115

—

4,428

37,506

981

4,493

81

5,555

14,754

1,537

16,291

21,846

59,352

946

60,298

(1)  Mature properties include Brookhaven, Cranfield, Eucutta, Little Creek, Mallalieu, Martinville, McComb and Soso fields.

(2)  Represents production related to the acquisition of a 23% non-operated working interest in Salt Creek Field in Wyoming, 

which closed on June 30, 2017.

(3)  Includes non-tertiary production related to the sale of 50% of our working interests in Webster, Thompson, Manvel, and 
East Hastings fields, which is expected to close in March 2020 and averaged 1,170 BOE/d and 1,085 BOE/d for the three 
and twelve months ended December 31, 2019, respectively.

(4)  Includes production from Citronelle Field sold in July 2019 and Lockhart Crossing Field sold in the third quarter of 2018.

49

 
 
Denbury Resources Inc. 
Management’s Discussion and Analysis of Financial Condition and Results of Operations

Total Production

Total continuing production during 2019 averaged 57,999 BOE/d, including 37,361 Bbls/d from tertiary properties and 
20,638 BOE/d from non-tertiary properties.  Total continuing production excludes production from Citronelle Field sold in 
July 2019 and, for prior-year periods, excludes production from Lockhart Crossing Field sold in the third quarter of 2018.  
Our  2019  total  continuing  production  level  represents  a  decrease  of  1,616  BOE/d  (3%)  compared  to  2018  levels,  most 
significantly attributable to lower tertiary production at Tinsley Field primarily due to planned downtime and preventative 
maintenance and lower non-tertiary production at CCA, partially offset by production increases from Bell Creek Field’s phase 
5 development.  Our production during 2019 was 97% oil, consistent with 2018 and 2017.

Oil and Natural Gas Revenues 

Oil and natural gas revenues decreased 15% between 2018 and 2019 and increased 31% between 2017 and 2018.  The 
changes in our oil and natural gas revenues are due to changes in production quantities and realized commodity prices (excluding 
any impact of our commodity derivative contracts), as reflected in the following table:

In thousands

Change in oil and natural gas revenues due to:

Increase (decrease) in production

Increase (decrease) in commodity prices

Total increase (decrease) in oil and natural gas
revenues

Year Ended December 31,
2019 vs. 2018

Year Ended December 31,
2018 vs. 2017

Decrease in
Revenues

Percentage
Decrease in
Revenues

Increase in
Revenues

Percentage
Increase in
Revenues

$

$

(50,163)
(160,406)

(4)% $

765

(11)%

332,158

(210,569)

(15)% $

332,923

0%

31%

31%

Excluding any impact of our commodity derivative contracts, our average net realized commodity prices and NYMEX 

differentials were as follows during 2019, 2018 and 2017:

Average net realized prices

Oil price per Bbl

Natural gas price per Mcf

Price per BOE

Average NYMEX differentials

Gulf Coast region

      Oil per Bbl

Natural gas per Mcf

 Rocky Mountain region

Oil per Bbl

      Natural gas per Mcf

Total Company

Oil per Bbl

Natural gas per Mcf

Year Ended December 31,

2019

2018

2017

$

58.26

$

66.11

$

2.06

57.04

2.58

64.59

$

$

$

$

3.30
(0.04)

(2.01) $
(0.96)

$

1.23
(0.47)

$

2.94

0.09

(1.50) $
(1.06)

$

1.30
(0.49)

50.64

2.41

49.51

0.22
(0.04)

(1.39)
(1.15)

(0.32)
(0.61)

Prices received in a regional market fluctuate frequently and can differ from NYMEX pricing due to a variety of reasons, 

including supply and/or demand factors, crude oil quality, and location differentials.

50

 
 
 
 
 
 
 
 
 
 
 
 
Denbury Resources Inc. 
Management’s Discussion and Analysis of Financial Condition and Results of Operations

•  Gulf Coast Region.  Our average NYMEX oil differential in the Gulf Coast region was a positive $3.30 per Bbl and 
a positive $2.94 per Bbl during 2019 and 2018, respectively.  Generally, our Gulf Coast region differentials are 
positive to NYMEX and highly correlated to the changes in prices of Light Louisiana Sweet crude oil, which have 
generally strengthened over the past year, although Gulf Coast region differentials softened in the second half of 
2019.

•  Rocky Mountain Region.  NYMEX oil differentials in the Rocky Mountain region averaged $2.01 per Bbl below 
NYMEX during 2019, compared to an average differential of $1.50 per Bbl below NYMEX in 2018.  Differentials 
in the Rocky Mountain region can fluctuate significantly on a month-to-month basis due to weather, refinery or 
transportation issues, and Canadian and U.S. crude oil price index volatility.

CO2 Revenues and Expenses

We sell approximately 15% to 20% of our produced CO2 from Jackson Dome to third-party industrial users at various 
contracted prices primarily under long-term contracts.  We recognize the revenue received on these CO2 sales as “CO2 sales 
and  transportation  fees”  with  the  corresponding  costs  recognized  as  “CO2 discovery  and  operating  expenses”  in  our 
Consolidated Statements of Operations.

Purchased Oil Revenues and Expenses

From time to time, we market third-party production for sale in exchange for a fee.  We recognize the revenue received 
on these oil sales as “Purchased oil sales” and the expenses incurred to market and transport the oil as “Purchased oil expenses” 
in our Consolidated Statements of Operations.

Commodity Derivative Contracts 

We routinely enter into oil derivative contracts to provide an economic hedge of our exposure to commodity price risk 
associated with anticipated future oil production and to provide more certainty to our future cash flows.  These contracts have 
historically consisted of price floors, collars, three-way collars, fixed-price swaps, fixed-price swaps enhanced with a sold 
put, and basis swaps.

The following table summarizes the impact our commodity derivative contracts had on our operating results for 2019, 

2018 and 2017:

In thousands

2019

Receipt (payment) on settlements of commodity derivatives
Noncash fair value gains (losses) on commodity derivatives(1)

Commodity derivatives income (expense)

2018

Payment on settlements of commodity derivatives
Noncash fair value gains (losses) on commodity derivatives(1)

Commodity derivatives income (expense)

2017

Receipt (payment) on settlements of commodity derivatives
Noncash fair value gains (losses) on commodity derivatives(1)

Commodity derivatives income (expense)

$

$

$

$

$

$

Three Months Ended

March 31

June 30

September 30

December 31

Full Year

8,206

$

(1,549) $

(91,583)

26,309

(83,377) $

24,760

$

8,057

35,098

43,155

$

$

8,892

$

23,606

(63,508)

(54,616) $

(93,684)

(70,078)

(33,357) $

(54,770) $

(61,611) $

(25,510) $

(175,248)

(15,468)

(41,429)

17,034

236,198

(48,825) $

(96,199) $

(44,577) $

210,688

$

(26,940) $

(11,767) $

89

$

(9,177) $

51,542

22,140

(25,352)

(78,111)

24,602

$

10,373

$

(25,263) $

(87,288) $

196,335

21,087

(47,795)

(29,781)

(77,576)

51

Denbury Resources Inc. 
Management’s Discussion and Analysis of Financial Condition and Results of Operations

(1)  Noncash fair value gains (losses) on commodity derivatives is a non-GAAP measure.  See Operating Results Table above 
for a discussion of the reconciliation between noncash fair value gains (losses) on commodity derivatives to “Commodity 
derivatives  expense  (income)”  in  the  Consolidated  Statements  of  Operations.    See  also  the  Glossary  and  Selected 
Abbreviations for the definition of noncash fair value gains (losses) on commodity derivatives.

In order to provide a level of price protection to a portion of our oil production, we have hedged a portion of our estimated 
oil production in 2020 using both NYMEX and LLS fixed-price swaps and three-way collars.  See Note 10, Commodity 
Derivative Contracts, to the Consolidated Financial Statements for additional details of our outstanding commodity derivative 
contracts as of December 31, 2019, and Market Risk Management below for additional discussion.  In addition, the following 
table summarizes our oil derivative contracts as of February 24, 2020:

WTI NYMEX

Volumes Hedged (Bbls/d)

Fixed-Price Swaps Swap Price(1)

Argus LLS

Volumes Hedged (Bbls/d)

Fixed-Price Swaps Swap Price(1)

WTI NYMEX

3-Way Collars

Volumes Hedged (Bbls/d)
Sold Put Price / Floor / Ceiling Price(1)(2)

Argus LLS

3-Way Collars

Volumes Hedged (Bbls/d)
Sold Put Price / Floor / Ceiling Price(1)(2)

1H 2020

2,000

$60.59

4,500

$62.29

23,000

2H 2020

2,000

$60.59

4,500

$62.29

21,000

$48.25 / $56.95 / $62.83

$48.26 / $56.85 / $62.68

10,000

8,000

$52.85 / $61.52 / $68.21

$52.75 / $61.08 / $68.39

Total Volumes Hedged (Bbls/d)

39,500

35,500

(1)  Averages are volume weighted.
(2)  If oil prices were to average less than the sold put price, receipts on settlement would be limited to the difference between 

the floor price and the sold put price.

Commodity derivative contracts in place for 2020 include fixed-price swaps and three-way collars.  Based on current 
contracts in place and NYMEX oil futures prices as of February 24, 2020, which average approximately $52 per Bbl for the 
remainder of 2020, we currently expect that we would receive cash payments of approximately $80 million during 2020 upon 
settlement of these contracts, the amount of which is dependent upon fluctuations in future NYMEX oil prices in relation to 
the prices of our 2020 fixed-price swaps which have weighted average prices of $60.59 per Bbl and $62.29 per Bbl for NYMEX 
and LLS hedges, respectively, and weighted average floor prices of our 2020 three-way collars of $56.90 per Bbl and $61.32 
per Bbl for NYMEX and LLS hedges, respectively.  The cash flows from our three-way collars could be limited to the extent 
that oil prices fall below the prices of our sold puts, which generally range between $45 per Bbl and $50 per Bbl for NYMEX 
hedges and $51 per Bbl and $55 per Bbl for LLS hedges.  See Note 10, Commodity Derivative Contracts, to the Consolidated 
Financial Statements for further discussion of the sold puts.  Changes in commodity prices, expiration of contracts, and new 
commodity contracts entered into cause fluctuations in the estimated fair value of our oil derivative contracts.  Because we 
do not utilize hedge accounting for our commodity derivative contracts, the period-to-period changes in the fair value of these 
contracts, as outlined above, are recognized in our statements of operations.

Production Expenses

Lease Operating Expenses

In thousands, except per-BOE data

Total lease operating expenses

Total lease operating expenses per BOE

Year Ended December 31,

2019

477,220

22.46

$

$

$

$

2018

489,720

22.24

$

$

2017

447,799

20.35

Total lease operating expense during 2019 decreased $12.5 million (3%) on an absolute-dollar basis, but slightly increased 
$0.22 (1%) on a per-BOE basis, compared to 2018.  The decrease on an absolute-dollar basis was primarily due to lower 

52

Denbury Resources Inc. 
Management’s Discussion and Analysis of Financial Condition and Results of Operations

workover expense, lower power and fuel costs, and lower CO2 expense due to lower CO2 volumes delivered during planned 
maintenance at our primary CO2 source in the Rocky Mountain region during the third quarter of 2019, partially offset by 
higher contract labor costs.

Currently, our CO2 expense comprises approximately 20% of our typical tertiary lease operating expenses, and for the 
CO2 reserves we already own, consists of CO2 production expenses, and for the CO2 reserves we do not own, consists of our 
purchase of CO2 from royalty and working interest owners and industrial sources.  During the year ended December 31, 2019, 
approximately 56% of the CO2 utilized in our CO2 floods consisted of CO2 owned and produced by us (our net revenue 
interest).  The price we pay others for CO2 varies by source and is generally indexed to oil prices.  When combining the 
production  cost  of  the  CO2  we  own  with  what  we  pay  third  parties  for  CO2,  our  average  cost  of  CO2  during  2019  was 
approximately $0.29 per Mcf, including taxes paid on CO2 production but excluding depletion, depreciation and amortization 
of capital expended at our CO2 source fields and industrial sources.  This per-Mcf CO2 cost during 2019 was lower than the 
$0.42 per Mcf comparable measure during 2018 due primarily to lower utilization of industrial-source CO2, which has a higher 
average cost than our naturally occurring CO2 sources. 

Transportation and Marketing Expenses

Transportation and marketing expenses primarily consist of amounts incurred related to the transportation, marketing, 
and processing of oil and natural gas production.  Transportation and marketing expenses were $41.8 million and $43.9 million 
during 2019 and 2018, respectively.

Taxes Other than Income

Taxes other than income includes production, ad valorem and franchise taxes.  Taxes other than income decreased $10.9 
million (10%) between 2018 and 2019, due primarily to a decrease in production taxes resulting from lower oil and natural 
gas revenues.

General and Administrative Expenses (“G&A”)

In thousands, except per-BOE data and employees

2019

2018

2017

Gross cash compensation and administrative costs

$

209,408

$

220,127

$

244,477

Year Ended December 31,

Gross stock-based compensation

Severance-related costs

Operator labor and overhead recovery charges

Capitalized exploration and development costs

Net G&A expense

G&A per BOE

Net cash administrative costs

Net stock-based compensation

Severance-related costs

Net G&A expense

Employees as of December 31

16,488

18,627
(121,677)
(39,817)
83,029

2.44

0.59

0.88

3.91

806

$

$

$

15,438

—
(126,570)
(37,500)
71,495

2.70

0.55

—

$

$

3.25

$

847

19,721

6,226
(127,425)
(41,193)
101,806

3.66

0.69

0.28

4.63

879

$

$

$

Our gross G&A expenses, which include our field operations employee costs, on an absolute-dollar basis increased $9.0 
million (4%) between 2018 and 2019 due to $18.6 million of severance-related expense associated with our voluntary separation 
program,  the  majority  of  which  will  be  paid  out  in  the  first  quarter  of  2020  (see  Overview  –  December  2019  Voluntary 

53

 
 
 
 
 
Denbury Resources Inc. 
Management’s Discussion and Analysis of Financial Condition and Results of Operations

Separation Program).  Excluding the severance expense, net G&A expense was down $7.1 million primarily due to our 
continued focus on cost reduction efforts and reduction in performance-based compensation.

Our well operating agreements allow us, when we are the operator, to charge a well with a specified overhead rate during 
the drilling phase and also to charge a monthly fixed overhead rate for each producing well.  In addition, salaries associated 
with field personnel are initially recorded as gross cash compensation and administrative costs and subsequently reclassified 
to lease operating expenses or capitalized to field development costs to the extent those individuals are dedicated to oil and 
natural gas production, exploration, and development activities.

Interest and Financing Expenses 

In thousands, except per-BOE data and interest rates
Cash interest(1)
Less: interest not reflected as expense for financial reporting 
purposes(1)
Noncash interest expense
Amortization of debt discount(2)
Less: capitalized interest

Interest expense, net

Interest expense, net per BOE
Average debt principal outstanding(3)
Average interest rate(4)

Year Ended December 31,

2019

2018

2017

$

191,454

$

186,632

$

176,307

(85,454)
4,554

7,749
(36,671)
81,632

3.84

$

$

(86,111)
6,246

—
(37,079)
69,688

3.16

$

$

(52,473)
6,191

—
(30,762)
99,263

4.51

$

$

$ 2,433,245

$ 2,593,035

$ 2,892,785

7.9%

7.2%

6.1%

(1)  Cash interest includes the portion of interest on certain debt instruments accounted for as a reduction of debt for GAAP 
financial reporting purposes in accordance with Financial Accounting Standards Board Codification (“FASC”) 470-60, 
Troubled Debt Restructuring by Debtors.  The portion of interest treated as a reduction of debt relates to our 2021 Senior 
Secured Notes, 2022 Senior Secured Notes, and our previously outstanding 3½% Convertible Senior Notes due 2024 and 
5% Convertible Senior Notes due 2023 (the “2023 Convertible Senior Notes”).  See below for further discussion.
(2)  Represents amortization of debt discounts of $2.6 million related to the 7¾% Senior Secured Notes and $5.1 million 

related to the 2024 Convertible Senior Notes during the year ended December 31, 2019.

(3)  Excludes debt discounts related to our 7¾% Senior Secured Notes and 2024 Convertible Senior Notes.
(4)  Includes commitment fees but excludes debt issue costs and amortization of discount.

As reflected in the table above, cash interest expense during 2019 increased when compared to 2018 due primarily to an 

increase in our weighted-average interest rate.

Future interest payable related to our 2021 Senior Secured Notes, 2022 Senior Secured Notes, and previously outstanding 
2023 Convertible Senior Notes and 3½% Convertible Senior Notes due 2024 is accounted for in accordance with FASC 
470-60, Troubled Debt Restructuring by Debtors, whereby most of the future interest was recorded as debt as of the transaction 
date, which will be reduced as semiannual interest payments are made.  Future interest payable recorded as debt totaled $164.9 
million and $250.2 million as of December 31, 2019 and 2018, respectively.  Therefore, interest expense reflected in our 
Consolidated Statements of Operations will be approximately $86 million lower annually than the actual cash interest payments 
on our 2021 Senior Secured Notes and 2022 Senior Secured Notes.

As more fully described in Note 6, Long-Term Debt, to the Consolidated Financial Statements, the June 2019 debt exchange 
transactions were accounted for in accordance with FASC 470-50, Modifications and Extinguishments, whereby our new 7¾
% Senior Secured Notes and new 2024 Convertible Senior Notes were recorded on our balance sheet at discounts to their 
principal amounts of $29.6 million and $79.9 million, respectively.  These debt discounts will be amortized as interest expense 
over the terms of the notes; therefore, future interest expense reflected in our Consolidated Statements of Operations will be 

54

 
Denbury Resources Inc. 
Management’s Discussion and Analysis of Financial Condition and Results of Operations

higher than the actual cash interest payments on our new 7¾% Senior Secured Notes and new 2024 Convertible Senior Notes 
by approximately $16 million in 2020, $19 million in 2021, $21 million in 2022, $25 million in 2023 and $21 million in 2024.

Depletion, Depreciation, and Amortization (“DD&A”)

In thousands, except per-BOE data

Oil and natural gas properties
CO2 properties, pipelines, plants and other property and equipment

Total DD&A

DD&A per BOE

Oil and natural gas properties
CO2 properties, pipelines, plants and other property and equipment

Total DD&A per BOE

Year Ended December 31,

2019

2018

2017

159,478

74,338

233,816

7.51

3.49

11.00

$

$

$

$

134,486

81,963

216,449

6.11

3.72

9.83

$

$

$

$

118,792

88,921

207,713

5.40

4.04

9.44

$

$

$

$

The increase in our oil and natural gas properties depletion during 2019, when compared to 2018, was primarily due to 
an increase in depletable costs resulting from increases in our capitalized costs and future development costs associated with 
our reserves base and a decrease in proved oil and natural gas reserve quantities.  Our oil and natural gas properties depletion 
rate was $8.17 per BOE during the fourth quarter of 2019.

Other Expenses  

Other expenses totaled $11.2 million and $84.3 million during 2019 and 2018, respectively.  Other expenses during 2019 
includes $1.9 million of impairment expense, $1.8 million of costs associated with the Riley Ridge helium supply contract 
ruling (see Note 12, Commitments and Contingencies – Litigation, to the Consolidated Financial Statements), and $1.6 million 
of transaction costs associated with our privately negotiated debt exchanges.  The 2018 amounts are primarily comprised of 
$49.4 million of expense related to the Riley Ridge helium supply contract ruling and a $17.8 million impairment for an 
investment related to a proposed plant in the Gulf Coast that would potentially supply CO2 to Denbury, due to uncertainties 
of the project achieving financial close.

Income Taxes

In thousands, except per-BOE amounts and tax rates

Current income tax expense (benefit)

Deferred income tax expense (benefit)

Total income tax expense (benefit)

Average income tax expense (benefit) per BOE

Effective tax rate

Total net deferred tax liability

Year Ended December 31,

2019

3,881

100,471

104,352

4.91

32.5%

410,230

$

$

$

$

2018
(16,001)
103,234

$

2017
(20,873)

(95,779)

87,233

$ (116,652)

3.96

21.3%

309,758

$

$

(5.30)

(250.9)%

198,099

$

$

$

$

Our income tax provisions were based on an estimated statutory rate of approximately 25% for 2019 and 2018 and 38% 
for 2017.  The Tax Cut and Jobs Act (the “Act”) enacted in December 2017 resulted in a reduction of the federal income tax 
rate from 35% to 21% effective for calendar year 2018.  Our effective tax rate for 2019 was higher than our estimated statutory 
rate primarily due to the establishment of a valuation allowance against a portion of our business interest expense deduction 
that we estimate will be disallowed.  Our 2018 and 2017 effective tax rates were lower than our estimated statutory rate 
primarily due to tax benefits resulting from enhanced oil recovery income tax credits and a one-time deferred income tax 
benefit of $132.2 million reflecting a re-measurement of our deferred income tax assets and liabilities associated with the 
federal income tax rate reduction, respectively.  As of December 31, 2019, we had a tax valuation allowance totaling $77.2 

55

 
 
 
 
 
Denbury Resources Inc. 
Management’s Discussion and Analysis of Financial Condition and Results of Operations

million to reduce the carrying value of deferred tax assets related to our disallowed business interest expense and state deferred 
tax assets.  The valuation allowances will remain until the realization of future deferred tax benefits are more likely than not 
to become utilized.

The  current  income  tax  benefit  recorded  in  2018  primarily  represents  the  estimated  receivable  associated  with  our 

refundable alternative minimum tax credits.

As of December 31, 2019, we had no federal net operating loss carryforwards (“NOLs”), tax effected business interest 
expense carryforward totaling $24.5 million (before provision for valuation allowance), state NOLs and tax credits totaling 
$52.9 million (before provision for valuation allowance), an estimated $49.9 million of enhanced oil recovery credits to carry 
forward related to our tertiary operations and $21.6 million of research and development credits that can be utilized to reduce 
our current income taxes during 2020 or future years.  We also have $6.0 million of alternative minimum tax credits, which 
under the Act will be fully refundable by 2021 and are recorded as a receivable on the balance sheet.  Our business interest 
expense carryforward does not expire.  Our state NOLs expire in various years, starting in 2020, although most do not begin 
to expire until 2025.  Our enhanced oil recovery credits and research and development credits do not begin to expire until 
2025 and 2031, respectively.  The statutes of limitation for our income tax returns for tax years ending prior to 2016 have 
lapsed and therefore are not subject to examination by respective taxing authorities.

Per-BOE Data

The  following  table  summarizes  our  cash  flow  and  results  of  operations  on  a  per-BOE  basis  for  the  comparative 

periods.  Each of the individual components is discussed above.

Per-BOE data
Oil and natural gas revenues

Receipt (payment) on settlements of commodity derivatives

Lease operating expenses

Production and ad valorem taxes

Transportation and marketing expenses

Production netback

CO2 sales, net of operating and exploration expenses
General and administrative expenses(1)
Interest expense, net

Other
Changes in assets and liabilities relating to operations

Cash flows from operations

DD&A

Deferred income taxes

Gain on early extinguishment of debt
Noncash fair value gains (losses) on commodity derivatives(2)
Other noncash items

Net income

$

Year Ended December 31,
2018

2017

2019

$

57.04

$

1.11
(22.46)
(4.09)
(1.97)
29.63

1.47
(3.91)
(3.84)
0.43
(0.52)
23.26
(11.00)
(4.73)
7.34
(4.41)
(0.25)
10.21

$

64.59
(7.96)
(22.24)
(4.39)
(2.00)
28.00

1.28
(3.25)
(3.16)
(2.01)
3.19

24.05
(9.83)
(4.69)
—

8.92
(3.80)
14.65

$

$

49.51
(2.17)
(20.35)
(3.60)
(2.00)
21.39

1.05
(4.63)
(4.51)
1.67
(2.83)
12.14
(9.44)
4.35

—
(1.35)
1.71

7.41

(1)  General and administrative expenses includes an accrual for severance-related costs of $18.6 million associated with our 
voluntary separation program for the year ended December 31, 2019 and payments of $6.2 million related to an involuntary 
workforce reduction for the year ended December 31, 2017, which if excluded, would have averaged $3.03 per BOE and 
$4.35 per BOE for the years ended December 31, 2019 and 2017, respectively.

56

 
Denbury Resources Inc. 
Management’s Discussion and Analysis of Financial Condition and Results of Operations

(2)  Noncash fair value gains (losses) on commodity derivatives is a non-GAAP measure.  See Operating Results Table above 
for a discussion of the reconciliation between noncash fair value gains (losses) on commodity derivatives to “Commodity 
derivatives  expense  (income)”  in  the  Consolidated  Statements  of  Operations.    See  also  the  Glossary  and  Selected 
Abbreviations for the definition of noncash fair value gains (losses) on commodity derivatives.

MARKET RISK MANAGEMENT

Debt and Interest Rate Sensitivity

At December 31, 2019, we had $2.1 billion of fixed-rate long-term debt and no outstanding borrowings on our variable-
rate senior secured bank credit facility.  None of our existing debt has any triggers or covenants regarding our debt ratings 
with rating agencies, although under the NEJD financing lease, in light of credit downgrades in February 2016, we were 
required to provide a $41.3 million letter of credit to the lessor, which we provided on March 4, 2016.  The letter of credit 
may be drawn upon in the event we fail to make a payment due under the pipeline financing lease agreement or upon other 
specified defaults set out in the pipeline financing lease agreement (filed as Exhibit 99.1 to the Form 8-K filed with the SEC 
on June 5, 2008).  The fair values of our senior secured second lien notes, convertible senior notes, and senior subordinated 
notes are based on quoted market prices.  The following table presents the principal and fair values of our outstanding debt 
at December 31, 2019:

In thousands

Fixed rate debt

2021

2022

2023

2024

Total

Fair
Value

9% Senior Secured Second Lien Notes due 2021

$

614,919

$

— $

— $

— $

614,919

$

599,546

9¼% Senior Secured Second Lien Notes due 2022

7¾% Senior Secured Second Lien Notes due 2024

7½% Senior Secured Second Lien Notes due 2024

5½% Senior Subordinated Notes due 2022

Commodity Derivative Contracts

—

—

—

—

51,304

—

—

455,668

—

—

—

—

58,426

—

—

—

—

—

—

—

135,960

—

531,821

20,641

245,548

—

—

—

455,668

531,821

20,641

245,548

51,304

58,426

135,960

428,328

468,002

17,132

158,450

41,171

36,224

84,295

We enter into oil derivative contracts to provide an economic hedge of our exposure to commodity price risk associated 
with anticipated future oil production and to provide more certainty to our future cash flows.  We do not hold or issue derivative 
financial instruments for trading purposes.  Generally, these contracts have consisted of various combinations of price floors, 
collars, three-way collars, fixed-price swaps, fixed-price swaps enhanced with a sold put, and basis swaps.  The production 
that we hedge has varied from year to year depending on our levels of debt, financial strength, and expectation of future 
commodity prices.  In order to provide a level of price protection to a portion of our oil production, we have hedged a portion 
of our estimated oil production in 2020 using both NYMEX and LLS fixed-price swaps and three-way collars.  Depending 
on market conditions, we may continue to add to our existing 2020 hedges or enter into hedges for 2021.  See also Note 10, 
Commodity  Derivative  Contracts,  and  Note  11,  Fair  Value  Measurements,  to  the  Consolidated  Financial  Statements  for 
additional information regarding our commodity derivative contracts.

All of the mark-to-market valuations used for our commodity derivatives are provided by external sources.  We manage 
and control market and counterparty credit risk through established internal control procedures that are reviewed on an ongoing 
basis.  We attempt to minimize credit risk exposure to counterparties through formal credit policies, monitoring procedures 
and diversification.  All of our commodity derivative contracts are with parties that are lenders under our senior secured bank 
credit facility (or affiliates of such lenders).  We have included an estimate of nonperformance risk in the fair value measurement 
of our commodity derivative contracts, which we have measured for nonperformance risk based upon credit default swaps or 
credit spreads. 

57

 
 
 
Denbury Resources Inc. 
Management’s Discussion and Analysis of Financial Condition and Results of Operations

For accounting purposes, we do not apply hedge accounting to our commodity derivative contracts.  This means that any 
changes in the fair value of these commodity derivative contracts will be charged to earnings instead of charging the effective 
portion to other comprehensive income and the ineffective portion to earnings.

At December 31, 2019, our commodity derivative contracts were recorded at their fair value, which was a net asset of 
$3.6 million, a $93.7 million decrease from the $97.3 million net asset recorded at December 31, 2018.  This change is primarily 
related to the expiration of commodity derivative contracts during 2019, new commodity derivative contracts entered into 
during 2019 for future periods, and changes in oil futures prices between December 31, 2018 and 2019.

Commodity Derivative Sensitivity Analysis

Based on NYMEX and LLS crude oil futures prices as of December 31, 2019, and assuming both a 10% increase and 
decrease thereon, we would expect to receive payments on our crude oil derivative contracts as shown in the following table:

In thousands

Based on:

Futures prices as of December 31, 2019

$

10% increase in prices

10% decrease in prices

Receipt / (Payment)

6,962
(43,601)
67,752

Our commodity derivative contracts are used as an economic hedge of our exposure to commodity price risk associated 
with anticipated future production.  As a result, changes in receipts or payments of our commodity derivative contracts due 
to changes in commodity prices, as reflected in the above table, would be mostly offset by a corresponding increase or decrease 
in the cash receipts on sales of our oil and natural gas production to which those commodity derivative contracts relate.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

The preparation of financial statements in accordance with generally accepted accounting principles requires that we 
select certain accounting policies and make certain estimates and judgments regarding the application of those policies.  Our 
significant accounting policies are included in Note 1, Nature of Operations and Summary of Significant Accounting Policies, 
to  the  Consolidated  Financial  Statements.  These  policies,  along  with  the  underlying  assumptions  and  judgments  by  our 
management in their application, have a significant impact on our consolidated financial statements.  Following is a discussion 
of our most critical accounting estimates, judgments and uncertainties that are inherent in the preparation of our financial 
statements.

Full Cost Method of Accounting, Depletion and Depreciation and Oil and Natural Gas Properties

Businesses involved in the production of oil and natural gas are required to follow accounting rules that are unique to the 
oil and gas industry.  We apply the full cost method of accounting for our oil and natural gas properties.  Another acceptable 
method of accounting for oil and natural gas production activities is the successful efforts method of accounting.  In general, 
the  primary  differences  between  the  two  methods  are  related  to  the  capitalization  of  costs  and  the  evaluation  for  asset 
impairment.  Under the full cost method, all geological and geophysical costs, exploratory dry holes and delay rentals are 
capitalized to the full cost pool, whereas under the successful efforts method such costs are expensed as incurred.  In the 
assessment of impairment of oil and natural gas properties, the successful efforts method follows the Accounting for the 
Impairment or Disposal of Long-Lived Assets topic of the FASC, under which the net book value of assets is measured for 
impairment  against  the  undiscounted  future  cash  flows  using  commodity  prices  consistent  with  management 
expectations.  Under the full cost method, the full cost pool (net book value of oil and natural gas properties) is measured 
against future cash flows discounted at 10% using the average first-day-of-the-month oil and natural gas price for each month 
during a 12-month rolling period through the end of each quarterly reporting period.  The financial results for a given period 
could be substantially different depending on the method of accounting that an oil and gas entity applies.  Further, we do not 
designate our oil and natural gas derivative contracts as hedging instruments for accounting purposes under the Derivatives 
and Hedging topic of the FASC (see below), and as a result, these contracts are not considered in the full cost ceiling test.

58

 
Denbury Resources Inc. 
Management’s Discussion and Analysis of Financial Condition and Results of Operations

We make significant estimates at the end of each period related to accruals for oil and natural gas revenues, production, 
capitalized costs and operating expenses.  We calculate these estimates with our best available data, which includes, among 
other things, production reports, price posting, information compiled from daily drilling reports and other internal tracking 
devices, and analysis of historical results and trends.  While management is not aware of any required revisions to its estimates, 
there will likely be future adjustments resulting from such things as revisions in estimated oil and natural gas volumes, changes 
in ownership interests, payouts, joint venture audits, re-allocations by the purchasers or pipelines, or other corrections and 
adjustments common in the oil and gas industry, many of which will require retroactive application.  These types of adjustments 
cannot be currently estimated or determined and will be recorded in the period during which the adjustment occurs.

Under full cost accounting, the estimated quantities of proved oil and natural gas reserves used to compute depletion and 
the related present value of estimated future net cash flows therefrom used to perform the full cost ceiling test have a significant 
impact on the underlying financial statements.  The process of estimating oil and natural gas reserves is very complex, requiring 
significant decisions in the evaluation of all available geological, geophysical, engineering and economic data.  The data for 
a given field may also change substantially over time as a result of numerous factors, including additional development activity, 
evolving production history and continued reassessment of the viability of production under varying economic conditions.  As 
a result, material revisions to existing reserve estimates may occur from time to time.  Although every reasonable effort is 
made  to  ensure  the  reported  reserve  estimates  represent  the  most  accurate  assessments  possible,  including  the  hiring  of 
independent engineers to prepare reported estimates, the subjective decisions and variances in available data for various fields 
make these estimates generally less precise than other estimates included in our financial statement disclosures.  Over the last 
four years, annual revisions to our reserve estimates, excluding any revisions related to changes in commodity prices, have 
averaged approximately 2.0% of the previous year’s estimates and have been both positive and negative.

Changes in commodity prices also affect our reserve quantities.  These changes in quantities affect our DD&A rate, and 
the combined effect of changes in quantities and commodity prices impacts our full cost ceiling test calculation.  For example, 
we estimate that a 5% increase in our estimate of proved reserve quantities would have lowered our fourth quarter 2019 oil 
and natural gas property DD&A rate from $8.17 per BOE to approximately $7.82 per BOE, and a 5% decrease in our proved 
reserve quantities would have increased our DD&A rate to approximately $8.56 per BOE.  Also, reserve quantities and their 
ultimate values, determined solely by our lenders, are the primary factors in determining the maximum borrowing base under 
our senior secured bank credit facility, particularly quantities and values of our proved developed producing reserves.

Under full cost accounting rules, we are required each quarter to perform a ceiling test calculation.  The net capitalized 
costs of oil and natural gas properties are limited to the lower of unamortized cost or the cost center ceiling.  The cost center 
ceiling is defined as (1) the present value of estimated future net revenues from proved oil and natural gas reserves before 
future abandonment costs (discounted at 10%), based on the average first-day-of-the-month oil and natural gas price for each 
month during a 12-month rolling period prior to the end of a particular reporting period; plus (2) the cost of properties not 
being amortized; plus (3) the lower of cost or estimated fair value of unproved properties included in the costs being amortized, 
if any; less (4) related income tax effects.  Our future net revenues from proved oil and natural gas reserves are not reduced 
for development costs related to the cost of drilling for and developing CO2 reserves nor those related to the cost of constructing 
CO2 pipelines, as we do not have to incur additional costs to develop the proved oil and natural gas reserves.  Therefore, we 
include in the ceiling test, as a reduction of future net revenues, that portion of our capitalized CO2 costs related to CO2 reserves 
and CO2 pipelines that we estimate will be consumed in the process of producing our proved oil and natural gas reserves.  The 
fair value of our oil and natural gas derivative contracts is not included in the ceiling test, as we do not designate these contracts 
as hedging instruments for accounting purposes.  The cost center ceiling test is prepared quarterly.  We did not record any 
ceiling test write-downs during 2017, 2018 or 2019.

We exclude certain unevaluated costs from the amortization base and full cost ceiling test pending the determination of 
whether proved reserves can be assigned to such properties.  These costs are transferred to the full cost amortization base in 
the course of these properties being developed, tested and evaluated.  At least annually, we test these assets for impairment 
based on an evaluation of management’s expectations of future pricing, evaluation of lease expiration terms, and planned 
project development activities.  As a result of this analysis, we recognized impairments of our unevaluated costs totaling $18.2 
million  and  $21.4  million  during  the  years  ended  December  31,  2019  and  2017,  respectively,  whereby  these  costs  were 
transferred to the full cost amortization base.  We did not record any impairments of our unevaluated costs during the year 
ended December 31, 2018.

59

Denbury Resources Inc. 
Management’s Discussion and Analysis of Financial Condition and Results of Operations

Tertiary Injection Costs

Our tertiary operations are conducted in reservoirs that have already produced significant amounts of oil over many years; 
however, in accordance with the rules for recording proved reserves, we cannot recognize proved reserves associated with 
enhanced recovery techniques such as CO2 injection until we can demonstrate production resulting from the tertiary process 
or unless the field is analogous to an existing flood.  Our costs associated with the CO2 we produce (or acquire) and inject are 
principally our cash out-of-pocket costs of production, transportation and acquisition, and to pay royalties.

We capitalize, as a development cost, injection costs in fields that are in their development stage, which means we have 
not yet seen incremental oil production due to the CO2 injections (i.e., a production response).  These capitalized development 
costs will be included in our unevaluated property costs if there are not already proved tertiary reserves in that field.  After 
we see a production response to the CO2 injections (i.e., the production stage), injection costs will be expensed as incurred, 
and any previously deferred unevaluated development costs will become subject to depletion upon recognition of proved 
tertiary reserves.  During 2019, 2018 and 2017, we capitalized $19.1 million, $24.5 million and $25.0 million, respectively, 
of tertiary injection costs associated with our tertiary projects.

Income Taxes

We make certain estimates and judgments in determining our income tax expense for financial reporting purposes.  These 
estimates and judgments occur in the calculation of certain tax assets and liabilities that arise from differences in the timing 
and recognition of revenue and expense for tax and financial reporting purposes.  Our federal and state income tax returns are 
generally not prepared or filed before the consolidated financial statements are prepared; therefore, we estimate the tax basis 
of our assets and liabilities at the end of each period as well as the effects of tax rate changes, tax credits and net operating 
loss carryforwards.  Adjustments related to these estimates are recorded in our tax provision in the period in which we finalize 
our income tax returns.  Further, we must assess the likelihood that we will be able to recover or utilize our deferred tax assets 
(primarily  our  enhanced  oil  recovery  credits,  business  interest  expense  carryforward,  and  state  net  operating  loss 
carryforwards).  If recovery is not likely, we must record a valuation allowance against such deferred tax assets for the amount 
we would not expect to recover, which would result in an increase to our income tax expense.  As of December 31, 2019, we 
had tax valuation allowances totaling $77.2 million to reduce the carrying value of deferred tax assets related to our disallowed 
business interest expense and state deferred tax assets.  As of December 31, 2018 and 2017, we had tax valuation allowances 
totaling $51.1 million to reduce the carrying value of our state deferred income tax assets.  The valuation allowances will 
remain until the realization of future deferred tax benefits are more likely than not to become utilized.  A 1% increase in our 
statutory tax rate would have increased our calculated income tax expense by approximately $3.2 million, $4.1 million and 
$0.5  million  for  the  years  ended  December  31,  2019,  2018  and  2017,  respectively.  See  Note  7,  Income  Taxes,  to  the 
Consolidated Financial Statements and Results of Operations – Income Taxes above for further information concerning our 
income taxes.

Fair Value Estimates

The FASC defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value 
measurements.  It does not require us to make any new fair value measurements, but rather establishes a fair value hierarchy 
that prioritizes the inputs to the valuation techniques used to measure fair value.  Level 1 inputs are given the highest priority 
in the fair value hierarchy, as they represent observable inputs that reflect unadjusted quoted prices for identical assets or 
liabilities in active markets as of the reporting date, while Level 3 inputs are given the lowest priority, as they represent 
unobservable inputs that are not corroborated by market data.  Valuation techniques that maximize the use of observable inputs 
are favored.  See Note 11, Fair Value Measurements, to the Consolidated Financial Statements for disclosures regarding our 
recurring fair value measurements.

Significant uses of fair value measurements include:

• 
• 

assessment of impairment of long-lived assets; and
recorded value of commodity derivative instruments.

60

Denbury Resources Inc. 
Management’s Discussion and Analysis of Financial Condition and Results of Operations

Impairment Assessment of Long-Lived Assets

We test long-lived assets that are not subject to our quarterly full cost pool ceiling test for impairment, including a portion 
of our capitalized CO2 properties and pipelines, whenever events or changes in circumstances indicate that the carrying value 
may not be recoverable.  The factors we assess to determine if a long-lived asset impairment test is necessary include, among 
other factors, a significant adverse change in the business climate that could affect the value of a long-lived asset, a significant 
decrease in the market price of an asset group, a significant adverse change in the extent or manner in which a long-lived asset 
(asset group) is being used or in its physical condition, or a current-period operating or cash flow loss combined with a history 
of operating or cash flow losses or a projection or forecast that demonstrates continuing losses associated with the use of a 
long-lived asset (asset group).

We perform our long-lived asset impairment test by comparing the net carrying costs of our long-lived asset groups to 
the  respective  expected  future  undiscounted  net  cash  flows  that  are  supported  by  these  long-lived  assets  which  include 
production of our probable and possible oil and natural gas reserves.  If the undiscounted net cash flows are below the net 
carrying costs for an asset group, we must record an impairment loss by the amount, if any, that net carrying costs exceed the 
fair value of the long-lived asset group.  Management assumptions impacting expected future undiscounted net cash flows 
include market estimates of future commodity prices, projections of estimated reserve quantities, projections of future rates 
of production, timing and amount of future development and operating costs, projected availability and cost of CO2, projected 
recovery factors of tertiary reserves and risk-adjustment factors applied to the net cash flows.  We did not record an impairment 
of long-lived assets during the year ended December 31, 2019.

Commodity Derivative Contracts

Historically, we have entered into oil and natural gas derivative contracts to provide an economic hedge of our exposure 
to commodity price risk associated with anticipated future oil and natural gas production and to provide more certainty to our 
future cash flows.  We do not hold or issue derivative financial instruments for trading purposes.  Generally, these contracts 
have  consisted  of  various  combinations  of  price  floors,  collars,  three-way  collars,  fixed-price  swaps,  fixed-price  swaps 
enhanced with a sold put, and basis swaps.  Our derivative financial instruments are recorded on the balance sheet as either 
an asset or liability measured at fair value.  The valuation methods used to measure the fair values of these assets and liabilities 
require considerable management judgment and estimates to derive the inputs necessary to determine fair value estimates, 
such as forward prices for commodities, interest rates, volatility factors and credit worthiness, as well as other relevant economic 
measures.  We do not apply hedge accounting to our commodity derivative contracts under the FASC Derivatives and Hedging
topic; accordingly, changes in the fair value of these instruments are recognized in earnings instead of charging the effective 
portion to other comprehensive income and the ineffective portion to earnings.  While we may experience more volatility in 
our net income (loss) than if we were to apply hedge accounting treatment as permitted by the FASC Derivatives and Hedging
topic, we believe that for us, the benefits associated with applying hedge accounting do not outweigh the cost, time and effort 
to comply with hedge accounting.

Environmental and Litigation Contingencies

The Company makes judgments and estimates in recording liabilities for contingencies such as environmental remediation 
or ongoing litigation.  Liabilities are recorded when it is both probable that a loss has been incurred and such loss is reasonably 
estimable.  Assessments of liabilities are based on information obtained from independent and in-house experts, loss experience 
in similar situations, actual costs incurred, and other case-by-case factors.  Actual costs can vary from such estimates for a 
variety of reasons.  The costs of environmental remediation or litigation can vary from estimates due to new developments 
regarding  the  facts  and  circumstances  of  each  event,  including  in  the  case  of  environmental  remediation,  the  timing  of 
remediation, our understanding of the environmental impact, remediation methods available, and regulatory requirements, 
and in the case of litigation, differing interpretations of laws and facts and assessments of damages asserted and/or incurred.

Use of Estimates

See  Note  1,  Nature  of  Operations  and  Summary  of  Significant  Accounting  Policies,  to  the  Consolidated  Financial 

Statements for a discussion of our use of estimates.

61

Denbury Resources Inc. 
Management’s Discussion and Analysis of Financial Condition and Results of Operations

Recent Accounting Pronouncements

See  Note  1,  Nature  of  Operations  and  Summary  of  Significant  Accounting  Policies,  to  the  Consolidated  Financial 

Statements for a discussion of recent accounting pronouncements.

FORWARD-LOOKING INFORMATION

The data and/or statements contained in this Annual Report on Form 10-K that are not historical facts, including, but not 
limited to, statements found in the sections entitled “Business and Properties” and “Management’s Discussion and Analysis 
of Financial Condition and Results of Operations,” are forward-looking statements, as that term is defined in Section 21E of 
the Securities Exchange Act of 1934, as amended (the “Exchange Act”), that involve a number of risks and uncertainties.  Such 
forward-looking statements may be or may concern, among other things, financial forecasts, future hydrocarbon prices and 
their volatility, current or future liquidity sources or their adequacy to support our anticipated future activities, our ability to 
refinance or extend the maturities of our long-term indebtedness which matures in 2021 and 2022, possible future write-downs 
of oil and natural gas reserves, together with assumptions based on current and projected production levels, oil and gas prices 
and oilfield costs, current or future expectations or estimations of our cash flows or the impact of changes in commodity prices 
on cash flows, availability of capital, borrowing capacity, price and availability of advantageous commodity derivative contracts 
or the predicted cash flow benefits therefrom, forecasted capital expenditures, drilling activity or methods, including the timing 
and location thereof, the nature of any future asset purchases or sales or the timing or proceeds thereof, estimated timing of 
commencement of CO2 flooding of particular fields or areas, including Cedar Creek Anticline (“CCA”), or the availability of 
capital for CCA pipeline construction, or its ultimate cost or date of completion, timing of CO2 injections and initial production 
responses in tertiary flooding projects, development activities, finding costs, anticipated future cost savings, capital budgets, 
interpretation  or  prediction  of  formation  details,  production  rates  and  volumes  or  forecasts  thereof,  hydrocarbon  reserve 
quantities and values, CO2 reserves and supply and their availability, potential reserves, barrels or percentages of recoverable 
original oil in place, levels of tariffs or other trade restrictions, the likelihood, timing and impact of increased interest rates, 
the impact of regulatory rulings or changes, outcomes of pending litigation, prospective legislation affecting the oil and gas 
industry, environmental regulations, mark-to-market values, the actual or anticipated future drop in worldwide oil demand 
due to the COVID-19 coronavirus, competition, rates of return, estimated costs, changes in costs, future capital expenditures 
and  overall  economics,  worldwide  economic  conditions,  the  likelihood  and  extent  of  an  economic  slowdown,  and  other 
variables surrounding operations and future plans.  Such forward-looking statements generally are accompanied by words 
such  as  “plan,”  “estimate,”  “expect,”  “predict,”  “forecast,”  “to  our  knowledge,”  “anticipate,”  “projected,”  “preliminary,” 
“should,” “assume,” “believe,” “may” or other words that convey, or are intended to convey, the uncertainty of future events 
or  outcomes.  Such  forward-looking  information  is  based  upon  management’s  current  plans,  expectations,  estimates,  and 
assumptions and is subject to a number of risks and uncertainties that could significantly and adversely affect current plans, 
anticipated actions, the timing of such actions and our financial condition and results of operations.  As a consequence, actual 
results may differ materially from expectations, estimates or assumptions expressed in or implied by any forward-looking 
statements made by us or on our behalf.  Among the factors that could cause actual results to differ materially are fluctuations 
in worldwide oil prices or in U.S. oil prices and consequently in the prices received or demand for our oil and natural gas; 
evolving political and military tensions in the Middle East; decisions as to production levels and/or pricing by OPEC or 
production levels by U.S. shale producers in future periods; levels of future capital expenditures; trade disputes and resulting 
tariffs or international economic sanctions; effects and maturity dates of our indebtedness; success of our risk management 
techniques; accuracy of our cost estimates; access to and terms of credit in the commercial banking or other debt markets; 
fluctuations in the prices of goods and services; the uncertainty of drilling results and reserve estimates; operating hazards 
and remediation costs; disruption of operations and damages from well incidents, hurricanes, tropical storms, forest fires, or 
other natural occurrences; acquisition risks; requirements for capital or its availability; conditions in the worldwide financial, 
trade and credit markets; general economic conditions; competition; government regulations, including changes in tax or 
environmental laws or regulations; and unexpected delays, as well as the risks and uncertainties inherent in oil and gas drilling 
and production activities or that are otherwise discussed in this annual report, including, without limitation, the portions 
referenced above, and the uncertainties set forth from time to time in our other public reports, filings and public statements.

62

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Denbury Resources Inc.

The information required by Item 7A is set forth under Market Risk Management in Item 7, Management’s Discussion 

and Analysis of Financial Condition and Results of Operations.

Item 8. Financial Statements and Supplementary Information

  Nature of Operations and Summary of Significant Accounting Policies

Revenue Recognition
Leases

Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets
Consolidated Statements of Operations
Consolidated Statements of Cash Flows
Consolidated Statements of Changes in Stockholders’ Equity
Notes to Consolidated Financial Statements
1.
2.
3.
4.
5.
6.
7.
8.
9.
10.
11.
12.
13.
14.
Supplemental Oil and Natural Gas Disclosures (Unaudited)
Supplemental CO2 Disclosures (Unaudited)
Unaudited Quarterly Information

  Asset Retirement Obligations
  Unevaluated Property
Long-Term Debt
Income Taxes
Stockholders’ Equity
Stock Compensation

  Commitments and Contingencies
Additional Balance Sheet Details
Supplemental Cash Flow Information

  Commodity Derivative Contracts

Fair Value Measurements

Page

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63

 
 
 
 
 
 
 
 
 
 
 
 
 
 
Report of Independent Registered Public Accounting Firm 

To the Board of Directors and Stockholders of Denbury Resources Inc.

Opinions on the Financial Statements and Internal Control over Financial Reporting

We have audited the accompanying consolidated balance sheets of Denbury Resources Inc. and its subsidiaries (the “Company”) 
as of December 31, 2019 and 2018, and the related consolidated statements of operations, of changes in stockholders’ equity 
and of cash flows for each of the three years in the period ended December 31, 2019, including the related notes (collectively 
referred to as the “consolidated financial statements”).  We also have audited the Company’s internal control over financial 
reporting as of December 31, 2019, based on criteria established in Internal Control - Integrated Framework (2013) issued 
by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).  

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial 
position of the Company as of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of 
the three years in the period ended December 31, 2019 in conformity with accounting principles generally accepted in the 
United States of America.  Also in our opinion, the Company maintained, in all material respects, effective internal control 
over financial reporting as of December 31, 2019, based on criteria established in Internal Control - Integrated Framework 
(2013) issued by the COSO.

Change in Accounting Principle

As discussed in Note 1 to the consolidated financial statements, the Company has changed the manner in which it accounts 
for leases in 2019.

Basis for Opinions

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 Management’s Report on Internal Control over Financial Reporting appearing under Item 9A.  Our responsibility is to 
express opinions on the Company’s consolidated financial statements and 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.

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 

64

accepted accounting principles.  A company’s internal control over financial reporting includes those policies and procedures 
that  (i) pertain  to  the  maintenance  of  records  that,  in  reasonable  detail,  accurately  and  fairly  reflect  the  transactions  and 
dispositions of the assets of the company; (ii) 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 (iii) 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.

Critical Audit Matters

The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial 
statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or 
disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, 
or complex judgments.  The communication of critical audit matters does not alter in any way our opinion on the consolidated 
financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate 
opinion on the critical audit matter or on the accounts or disclosures to which it relates.

The Impact of Proved Oil and Natural Gas Reserves on Net Proved Oil and Natural Gas Properties

The Company’s net properties and equipment balance was $4.4 billion as of December 31, 2019, and depreciation, depletion 
and amortization (DD&A) expense for the year ended December 31, 2019 was $234 million, both of which include proved 
oil and natural gas properties.  As described in Note 1, the Company follows the full cost method of accounting, under which 
capitalized costs, including production equipment and future development costs, are depleted or depreciated using the unit-
of-production  method  based  on  proved  oil  and  natural  gas  reserves  as  determined  by  independent  petroleum  engineers 
(management’s specialists).  As disclosed by management, on a quarterly basis, management performs a full cost ceiling 
impairment test on proved oil and natural gas properties.  In 2019, the Company did not have any ceiling test impairments 
on its proved oil and natural gas properties.  Under the ceiling test, the net capitalized costs of oil and natural gas properties 
are limited to the lower of unamortized cost or the cost center ceiling.  The cost center ceiling is defined as (1) the present 
value of estimated future net revenues from proved oil and natural gas reserves before future abandonment costs (discounted 
at 10%), based on the average first-day-of-the-month oil and natural gas price for each month during a 12-month rolling 
period prior to the end of a particular reporting period; plus (2) the cost of properties not being amortized; plus (3) the lower 
of cost or estimated fair value of unproved properties included in the costs being amortized, if any; less (4) related income 
tax effects.  Estimating quantities of proved oil and natural gas reserves is a complex process.  It requires interpretations of 
available technical data and various assumptions, including future production rates, production costs, severance and excise 
taxes, capital expenditures and workover and remedial costs, and the assumed effect of governmental rules and regulations.

The principal considerations for our determination that performing procedures relating to the impact of proved oil and natural 
gas reserves on net proved oil and natural gas properties is a critical audit matter are there was significant judgment by 
management, including the use of specialists, when developing the estimates of proved oil and natural gas reserves.  This in 
turn led to a high degree of auditor judgment, subjectivity and effort in performing procedures and evaluating audit evidence 
related to the significant assumptions used in developing those estimates of proved oil and natural gas reserves, including 
future production rates and capital expenditures.

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall 
opinion on the consolidated financial statements.  These procedures included testing the effectiveness of controls relating to 
management’s estimates of proved oil and natural gas reserves, the full cost ceiling impairment test, and depletion, depreciation 
and amortization expense.  These procedures also included, among others (i) evaluating the significant assumptions used by 
management in developing the estimates of proved oil and natural gas reserves, including future production rates and capital 
expenditures, (ii) testing the full cost ceiling impairment test calculation, and (iii) testing the unit-of-production rate used to 
calculate DD&A expense.  The work of management’s specialists was used in performing the procedures to evaluate the 

65

reasonableness  of  the  estimates  of  proved  oil  and  natural  gas  reserves.   As  a  basis  for  using  this  work,  the  specialists’ 
qualifications and objectivity were understood, as well as the methods and assumptions used by the specialists.  The procedures 
performed also included tests of the data used by the specialists and an evaluation of the specialist’s findings.  Evaluating 
the significant assumptions relating to the estimates of proved oil and natural gas reserves also involved obtaining evidence 
to support the reasonableness of the assumptions, including whether the assumptions used were reasonable considering the 
past performance of the Company, and whether they were consistent with evidence obtained in other areas of the audit.

/s/ PricewaterhouseCoopers LLP
Dallas, Texas
February 26, 2020

We have served as the Company’s auditor since 2004. 

66

Denbury Resources Inc.
Consolidated Balance Sheets
(In thousands, except par value and share data)

Assets

Current assets

Cash and cash equivalents

Accrued production receivable

Trade and other receivables, net

Derivative assets

Other current assets

Total current assets
Property and equipment

Oil and natural gas properties (using full cost accounting)

Proved properties

Unevaluated properties

CO2 properties
Pipelines and plants
Other property and equipment

Less accumulated depletion, depreciation, amortization and impairment

Net property and equipment

Operating lease right-of-use assets

Derivative assets

Other assets

Total assets

Current liabilities

Accounts payable and accrued liabilities

Oil and gas production payable

Derivative liabilities

Liabilities and Stockholders’ Equity

Current maturities of long-term debt (including future interest payable of $86,054 and $85,303,
respectively – see Note 6)

Operating lease liabilities

Total current liabilities

Long-term liabilities

December 31,

2019

2018

$

516

$

139,407

18,318

11,936

10,434

180,611

38,560

125,788

26,970

93,080

11,896

296,294

11,447,680

11,072,209

872,910
1,198,846

2,329,078
212,334

996,700
1,196,795

2,302,817
250,279

(11,688,020)

(11,500,190)

4,372,828

4,318,610

34,099

—

104,329

4,691,867

$

—

4,195

104,123

4,723,222

183,832

$

62,869

8,346

102,294

6,901

364,242

198,380

61,288

—

105,125

—

364,793

$

$

Long-term debt, net of current portion (including future interest payable of $78,860 and $164,914,
respectively – see Note 6)

2,232,570

2,664,211

Asset retirement obligations

Deferred tax liabilities, net

Operating lease liabilities

Other liabilities

Total long-term liabilities

Commitments and contingencies (Note 12)

Stockholders’ equity

Preferred stock, $.001 par value, 25,000,000 shares authorized, none issued and outstanding

Common stock, $.001 par value, 750,000,000 shares authorized; 508,065,495 and 462,355,725 shares

issued, respectively

Paid-in capital in excess of par

Accumulated deficit

Treasury stock, at cost, 1,652,771 and 1,941,749 shares, respectively

Total stockholders’ equity
Total liabilities and stockholders’ equity

177,108

410,230

41,932

53,526

174,470

309,758

—

68,213

2,915,366

3,216,652

—

508

2,739,099

(1,321,314)

(6,034)
1,412,259

$

4,691,867

$

—

462

2,685,211

(1,533,112)

(10,784)
1,141,777

4,723,222

See accompanying Notes to Consolidated Financial Statements.

67

 
 
 
 
 
 
 
 
 
 
 
 
 
 
Denbury Resources Inc.
Consolidated Statements of Operations
(In thousands, except per share data)

Revenues and other income

Oil, natural gas, and related product sales

CO2 sales and transportation fees

Purchased oil sales

Other income

Year Ended December 31,

2019

2018

2017

$

1,212,020

$

1,422,589

$

1,089,666

34,142

14,198

14,523

31,145

1,921

17,970

26,182

3,718

10,220

Total revenues and other income

1,274,883

1,473,625

1,129,786

Expenses

Lease operating expenses

Transportation and marketing expenses

CO2 discovery and operating expenses

Taxes other than income

Purchased oil expenses

General and administrative expenses

Interest, net of amounts capitalized of $36,671, $37,079 and $30,762, respectively

Depletion, depreciation, and amortization

Commodity derivatives expense (income)

Gain on debt extinguishment

Other expenses

Total expenses

Income before income taxes

Income tax provision (benefit)

Net income

Net income per common share

Basic

Diluted

Weighted average common shares outstanding

Basic

Diluted

477,220

41,810

2,922

93,752

14,124

83,029

81,632

233,816

70,078

(155,998)

11,187

953,572

321,311

104,352

489,720

43,942

2,816

104,670

1,676

71,495

69,688

216,449

(21,087)

—

84,325

1,063,694

409,931

87,233

216,959

$

322,698

$

447,799

44,064

3,099

87,207

3,304

101,806

99,263

207,713

77,576

—

11,455

1,083,286

46,500

(116,652)

163,152

0.47

0.45

$

$

0.75

0.71

$

$

0.42

0.41

459,524

510,341

432,483

456,169

390,928

395,921

$

$

$

See accompanying Notes to Consolidated Financial Statements.

68

 
 
 
 
 
 
 
 
 
 
 
Denbury Resources Inc.
Consolidated Statements of Cash Flows
(In thousands)

Cash flows from operating activities

Net income

Adjustments to reconcile net income to cash flows from operating activities

Depletion, depreciation, and amortization

Deferred income taxes

Stock-based compensation

Commodity derivatives expense (income)

Receipt (payment) on settlements of commodity derivatives

Gain on debt extinguishment

Debt issuance costs and discounts

Other, net

Changes in assets and liabilities, net of effects from acquisitions

Accrued production receivable

Trade and other receivables

Other current and long-term assets

Accounts payable and accrued liabilities

Oil and natural gas production payable

Other liabilities

Net cash provided by operating activities

Cash flows from investing activities

Oil and natural gas capital expenditures

Acquisitions of oil and natural gas properties

CO2 capital expenditures

Pipelines and plants capital expenditures

Net proceeds from sales of oil and natural gas properties and equipment

Other

Net cash used in investing activities

Cash flows from financing activities

Bank repayments

Bank borrowings

Interest payments treated as a reduction of debt

Proceeds from issuance of senior secured notes

Cash paid in conjunction with debt exchange

Repayment or repurchases of senior subordinated notes

Costs of debt financing

Pipeline financing and capital lease debt repayments

Other

Net cash provided by (used in) financing activities

Net increase (decrease) in cash, cash equivalents, and restricted cash

Cash, cash equivalents, and restricted cash at beginning of year

Year Ended December 31,

2019

2018

2017

$

216,959

$

322,698

$

163,152

233,816

100,471

12,470

70,078

23,606

(155,998)

12,303

(8,596)

(13,619)

9,379

7,629

(3,275)

2,170

(13,250)

494,143

(262,005)

(79)

(3,154)

(27,319)

10,196

12,669

216,449

103,234

11,951

(21,087)

(175,248)

—

6,246

(4,725)

20,547

16,094

(6,827)

13,008

(15,300)

42,645

529,685

(316,647)

(541)

(5,878)

(23,108)

7,762

5,136

207,713

(95,779)

15,154

77,576

(47,795)

—

6,191

3,112

(21,398)

(4,421)

(1,722)

(24,710)

(3,997)

(5,933)

267,143

(262,867)

(88,886)

(2,159)

(2,540)

1,696

(2,058)

(269,692)

(333,276)

(356,814)

(925,791)

925,791

(85,303)

—

(136,427)

—

(11,065)

(13,908)

348

(246,355)

(21,904)

54,949

(1,982,653)

1,507,653

(79,606)

450,000

—

—

(16,060)

(23,300)

(13,486)

(157,452)

38,957

15,992

(1,589,000)

1,763,000

(50,349)

—

—

(2,503)

(6,289)

(27,462)

1,216

88,613

(1,058)

17,050

15,992

Cash, cash equivalents, and restricted cash at end of year

$

33,045

$

54,949

$

 See accompanying Notes to Consolidated Financial Statements.

69

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Denbury Resources Inc.
Consolidated Statements of Changes in Stockholders’ Equity
(Dollar amounts in thousands)

Common Stock
($.001 Par Value)

Shares

Amount

Paid-In
Capital in
Excess of
Par

Retained
Earnings 
(Accumulated 
Deficit)

Treasury Stock
(at cost)

Shares

Amount

Total Equity

Balance – December 31, 2016

402,334,655

$

402

$

2,534,670

$

(2,018,989)

3,906,877

$

(47,635)

$

468,448

Issued or purchased pursuant to stock
compensation plans

Issued pursuant to directors’ compensation
plan

Stock-based compensation

Tax withholding – stock compensation

5,201,854

12,837

—

—

Retirement of treasury stock

(5,000,000)

Dividends adjustments

Net income

—

—

6

—

—

—

(5)

—

—

(6)

—

19,721

—

(46,557)

—

—

—

—

—

—

—

27

163,152

—

—

—

1,550,164

(5,000,000)

—

—

—

—

—

(3,183)

46,562

—

—

Balance – December 31, 2017

402,549,346

403

2,507,828

(1,855,810)

457,041

(4,256)

Issued or purchased pursuant to stock
compensation plans

Issued pursuant to notes conversion

Stock-based compensation

Tax withholding – stock compensation

Net income

4,556,424

55,249,955

—

—

—

4

55

—

—

—

(4)

161,949

15,438

—

—

—

—

—

—

322,698

—

—

—

1,484,708

—

—

—

—

(6,528)

—

—

—

19,721

(3,183)

—

27

163,152

648,165

—

162,004

15,438

(6,528)

322,698

Balance – December 31, 2018

462,355,725

462

2,685,211

(1,533,112)

1,941,749

(10,784)

1,141,777

Issued or purchased pursuant to stock
compensation plans

Issued pursuant to directors’ compensation
plan

Issued pursuant to senior subordinated notes
exchanges

Stock-based compensation

Tax withholding – stock compensation

Net income

9,315,016

97,537

36,297,217

—

—

—

9

—

37

—

—

—

(9)

—

37,409

16,488

—

—

—

—

—

—

(5,161)

(1,990,000)

—

—

216,959

—

1,701,022

—

—

—

7,270

—

(2,520)

—

—

—

39,555

16,488

(2,520)

216,959

Balance – December 31, 2019

508,065,495

$

508

$

2,739,099

$

(1,321,314)

1,652,771

$

(6,034)

$

1,412,259

 See accompanying Notes to Consolidated Financial Statements.

70

 
Denbury Resources Inc. 
Notes to Consolidated Financial Statements

Note 1. Nature of Operations and Summary of Significant Accounting Policies

Organization and Nature of Operations

Denbury Resources Inc., a Delaware corporation, is an independent oil and natural gas company with operations focused 
in two key operating areas: the Gulf Coast and Rocky Mountain regions.  Our goal is to increase the value of our properties 
through a combination of exploitation, drilling and proven engineering extraction practices, with the most significant emphasis 
relating to CO2 enhanced oil recovery operations.

Principles of Reporting and Consolidation

The consolidated financial statements herein have been prepared in accordance with accounting principles generally 
accepted in the United States (“GAAP”) and include the accounts of Denbury and entities in which we hold a controlling 
financial interest.  Undivided interests in oil and gas joint ventures are consolidated on a proportionate basis.  All intercompany 
balances and transactions have been eliminated.

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions 
that affect the reported amount of certain assets and liabilities, disclosure of contingent assets and liabilities at the date of the 
financial statements, and the reported amounts of revenues and expenses during each reporting period.  Management believes 
its estimates and assumptions are reasonable; however, such estimates and assumptions are subject to a number of risks and 
uncertainties that may cause actual results to differ materially from such estimates.  Significant estimates underlying these 
financial statements include (1) the fair value of financial derivative instruments; (2) the estimated quantities of proved oil 
and natural gas reserves used to compute depletion of oil and natural gas properties, the related present value of estimated 
future net cash flows therefrom and the ceiling test; (3) future net cash flow estimates used in the impairment assessment of 
long-lived assets; (4) the estimated quantities of proved and probable CO2 reserves used to compute depletion of CO2 properties; 
(5) estimated useful lives used to compute depreciation and amortization of long-lived assets; (6) accruals related to oil and 
natural gas sales volumes and revenues, capital expenditures and lease operating expenses; (7) the estimated costs and timing 
of future asset retirement obligations; and (8) estimates made in the calculation of income taxes.  While management is not 
aware of any significant revisions to any of its current year-end estimates, there will likely be future revisions to its estimates 
resulting from matters such as revisions in estimated oil and natural gas volumes, changes in ownership interests, payouts, 
joint venture audits, re-allocations by purchasers or pipelines, or other corrections and adjustments common in the oil and 
natural gas industry, many of which require retroactive application.  These types of adjustments cannot be currently estimated 
and will be recorded in the period in which the adjustment occurs. 

Reclassifications

Certain prior period amounts have been reclassified to conform to the current year presentation.  On the Consolidated 
Statements of Operations for the years ended December 31, 2018 and 2017, “Purchased oil sales” is a new line item and 
includes sales related to purchases of oil from third-parties, which were reclassified from “Other income,” “Purchased oil 
expenses” is a new line item and includes expenses related to purchases of oil from third-parties, which were reclassified from 
“Marketing and plant operating expenses” used in prior reports, and “Transportation and marketing expenses” is a new line 
item, previously captioned “Marketing and plant operating expenses,” but adjusted to exclude both expenses related to plant 
operating  expenses,  which  were  reclassified  to  “Other  expenses,”  and  also  purchases  of  oil  from  third  parties.    Such 
reclassifications  had  no  impact  on  our  reported  total  revenues,  expenses,  net  income,  current  assets,  total  assets,  current 
liabilities, total liabilities or stockholders’ equity.

71

Denbury Resources Inc. 
Notes to Consolidated Financial Statements

Cash, Cash Equivalents, and Restricted Cash 

We consider all highly liquid investments to be cash equivalents if they have maturities of three months or less at the date 
of purchase.  The following table provides a reconciliation of cash, cash equivalents, and restricted cash as reported within 
the  Consolidated  Balance  Sheets  to  “Cash,  cash  equivalents,  and  restricted  cash  at  end  of  year”  as  reported  within  the 
Consolidated Statements of Cash Flows:

In thousands

Cash and cash equivalents

Restricted cash included in other assets

Total cash, cash equivalents, and restricted cash shown in the Consolidated
Statements of Cash Flows

December 31,

2019

2018

$

$

516

$

32,529

38,560

16,389

33,045

$

54,949

Amounts included in restricted cash included in “Other assets” in the accompanying Consolidated Balance Sheets represent 

escrow accounts that are legally restricted for certain of our asset retirement obligations.

Oil and Natural Gas Properties

Capitalized Costs.  We follow the full cost method of accounting for oil and natural gas properties.  Under this method, 
all costs related to the acquisition, exploration and development of oil and natural gas reserves are capitalized and accumulated 
in a single cost center representing our activities, which are undertaken exclusively in the United States.  Such costs include 
lease acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties, costs of drilling 
both productive and nonproductive wells, capitalized interest on qualifying projects, and general and administrative expenses 
directly related to exploration and development activities, and do not include any costs related to production, general corporate 
overhead  or  similar  activities.  We  assign  the  purchase  price  of  oil  and  natural  gas  properties  we  acquire  to  proved  and 
unevaluated properties based on the estimated fair values as defined in the Financial Accounting Standards Board Codification 
(“FASC”) Fair Value Measurement topic.  Proceeds received from disposals are credited against accumulated costs except 
when the sale represents a significant disposal of reserves, in which case a gain or loss would be recognized.  A disposal of 
25% or more of our proved reserves would be considered significant. 

Depletion and Depreciation.  The costs capitalized, including production equipment and future development costs, are 
depleted or depreciated using the unit-of-production method, based on proved oil and natural gas reserves as determined by 
independent petroleum engineers.  Oil and natural gas reserves are converted to equivalent units on a basis of 6,000 cubic feet 
of natural gas to one barrel of crude oil.

Under full cost accounting, we may exclude certain unevaluated costs from the amortization base pending determination 
of whether proved reserves can be assigned to such properties.  The costs classified as unevaluated are transferred to the full 
cost  amortization  base  as  the  properties  are  developed,  tested  and  evaluated.   At  least  annually,  we  test  these  assets  for 
impairment based on an evaluation of management’s expectations of future pricing, evaluation of lease expiration terms, and 
planned project development activities.  As a result of this analysis, we recognized impairments of our unevaluated costs 
totaling $18.2 million  and $21.4 million during the years ended December 31, 2019 and 2017, respectively, whereby these 
costs were transferred to the full cost amortization base.  We did not record any impairments of our unevaluated costs during 
the year ended December 31, 2018.

Write-Down of Oil and Natural Gas Properties.  The net capitalized costs of oil and natural gas properties are limited 
to the lower of unamortized cost or the cost center ceiling.  The cost center ceiling is defined as (1) the present value of 
estimated future net revenues from proved oil and natural gas reserves before future abandonment costs (discounted at 10%), 
based on the average first-day-of-the-month oil and natural gas price for each month during a 12-month rolling period prior 
to the end of a particular reporting period; plus (2) the cost of properties not being amortized; plus (3) the lower of cost or 
estimated fair value of unproved properties included in the costs being amortized, if any; less (4) related income tax effects.  Our 
future net revenues from proved oil and natural gas reserves are not reduced for development costs related to the cost of drilling 
for and developing CO2 reserves nor those related to the cost of constructing CO2 pipelines, as we do not have to incur additional 

72

 
Denbury Resources Inc. 
Notes to Consolidated Financial Statements

costs to develop the proved oil and natural gas reserves.  Therefore, we include in the ceiling test, as a reduction of future net 
revenues, that portion of our capitalized CO2 costs related to CO2 reserves and CO2 pipelines that we estimate will be consumed 
in the process of producing our proved oil and natural gas reserves.  The fair value of our oil and natural gas derivative contracts 
is not included in the ceiling test, as we do not designate these contracts as hedge instruments for accounting purposes.  The 
cost center ceiling test is prepared quarterly.  We did not record any ceiling test write-downs during 2017, 2018 or 2019.

Joint Interest Operations.  Substantially all of our oil and natural gas exploration and production activities are conducted 
jointly with others.  These financial statements reflect only our proportionate interest in such activities, and any amounts due 
from other partners are included in trade receivables.

Tertiary Injection Costs.  Our tertiary operations are conducted in reservoirs that have already produced significant 
amounts of oil over many years; however, in accordance with the Securities and Exchange Commission (“SEC”) rules and 
regulations for recording proved reserves, we cannot recognize proved reserves associated with enhanced recovery techniques, 
such as CO2 injection, until we can demonstrate production resulting from the tertiary process or unless the field is analogous 
to an existing flood.  

We capitalize, as a development cost, injection costs in fields that are in their development stage, which means we have 
not yet seen incremental oil production due to the CO2 injections (i.e., a production response).  These capitalized development 
costs are included in our unevaluated property costs if there are not already proved tertiary reserves in that field.  After we 
see a production response to the CO2 injections (i.e., the production stage), injection costs are expensed as incurred, and once 
proved reserves are recognized, previously deferred unevaluated development costs become subject to depletion.

CO2 Properties

We own and produce CO2 reserves, a non-hydrocarbon resource, that are used in our tertiary oil recovery operations on 
our own behalf and on behalf of other interest owners in enhanced recovery fields, with a portion sold to third-party industrial 
users.  We record revenue from our sales of CO2 to third parties when it is produced and sold.  Expenses related to the production 
of CO2 are allocated between volumes sold to third parties and volumes consumed internally that are directly related to our 
tertiary production.  The expenses related to third-party sales are recorded in “CO2 discovery and operating expenses,” and 
the expenses related to internal use are recorded in “Lease operating expenses” in the Consolidated Statements of Operations 
or are capitalized as oil and natural gas properties in our Consolidated Balance Sheets, depending on the stage of the tertiary 
flood that is receiving the CO2 (see Tertiary Injection Costs above for further discussion).

Costs incurred to search for CO2 are expensed as incurred until proved or probable reserves are established.  Once proved 
or probable reserves are established, costs incurred to obtain those reserves are capitalized and classified as “CO2 properties” 
on our Consolidated Balance Sheets.  Capitalized CO2 costs are aggregated by geologic formation and depleted on a unit-of-
production basis over proved and probable reserves.

Pipelines and Plants

CO2 used in our tertiary floods is transported to our fields through CO2 pipelines.  Costs of CO2 pipelines under construction 
are not depreciated until the pipelines are placed into service.  Pipelines are depreciated on a straight-line basis over their 
estimated useful lives, which range from 20 to 50 years.  Capitalized costs include $117.6 million of CO2 pipelines as of 
December 31, 2019, that were either under construction or had not been placed into service and therefore, were not subject 
to depreciation during 2019.

Property and Equipment – Other

Other property and equipment, which includes furniture and fixtures, vehicles, and computer equipment and software, is 
depreciated principally on a straight-line basis over each asset’s estimated useful life.  Vehicles and furniture and fixtures are 
generally depreciated over a useful life of five to ten years, and computer equipment and software are generally depreciated 
over a useful life of three to five years.  Leasehold improvements are amortized over the shorter of the estimated useful life 
or the remaining lease term.

73

 
Denbury Resources Inc. 
Notes to Consolidated Financial Statements

Maintenance and repair costs that do not extend the useful life of the property or equipment are charged to expense as 

incurred.

Intangible Assets

Our intangible assets subject to amortization primarily consist of amounts assigned in purchase accounting to a CO2
purchase contract with ConocoPhillips to offtake CO2 from the Lost Cabin gas plant in Wyoming and are included in our 
Consolidated Balance Sheets under the caption “Other assets.”  We amortize the CO2 contract intangible asset on a straight-
line basis over the contract term.  Total amortization expense for our intangible assets was $2.4 million, $2.4 million and $2.4 
million during the years ended December 31, 2019, 2018 and 2017.  The following table summarizes the carrying value of 
our intangible assets as of December 31, 2019 and 2018:

In thousands

Intangible asset value

Accumulated amortization

Net book value

December 31,

2019

2018

$

$

37,608
(15,502)
22,106

$

$

37,848
(13,074)
24,774

As of December 31, 2019, our estimated amortization expense for our intangible assets subject to amortization over the 

next five years is as follows:

In thousands

2020

2021

2022

2023

2024

$

2,420

2,420

2,420

2,420
2,420  

Impairment Assessment of Long-Lived Assets

The portion of our capitalized CO2 costs related to CO2 reserves and CO2 pipelines that we estimate will be consumed 
in the process of producing our proved oil and natural gas reserves is included in the full cost pool ceiling test as a reduction 
to future net revenues.  The remaining net capitalized costs that are not included in the full cost pool ceiling test, and related 
intangible assets, are subject to long-lived asset impairment testing whenever events or changes in circumstances indicate that 
the carrying value may not be recoverable.

We perform our long-lived asset impairment test by comparing the net carrying costs of our long-lived asset groups to 
the  respective  expected  future  undiscounted  net  cash  flows  that  are  supported  by  these  long-lived  assets  which  include 
production of our probable and possible oil and natural gas reserves.  If the undiscounted net cash flows are below the net 
carrying costs for an asset group, we must record an impairment loss by the amount, if any, that net carrying costs exceed the 
fair value of the long-lived asset group.  We did not record an impairment of long-lived assets during the year ended December 
31, 2019.

Asset Retirement Obligations

In general, our future asset retirement obligations relate to future costs associated with plugging and abandoning our oil, 
natural  gas  and  CO2  wells,  removing  equipment  and  facilities  from  leased  acreage,  and  returning  land  to  its  original 
condition.  The fair value of a liability for an asset retirement obligation is recorded in the period in which it is incurred, 
discounted to its present value using our credit-adjusted-risk-free interest rate, and a corresponding amount capitalized by 
increasing the carrying amount of the related long-lived asset.  The liability is accreted each period, and the capitalized cost 
is depreciated over the useful life of the related asset.  Revisions to estimated retirement obligations will result in an adjustment 

74

 
Denbury Resources Inc. 
Notes to Consolidated Financial Statements

to the related capitalized asset and corresponding liability.  If the liability for an oil or natural gas well is settled for an amount 
other than the recorded amount, the difference is recorded to the full cost pool, unless significant.

Asset retirement obligations are estimated at the present value of expected future net cash flows.  We utilize unobservable 
inputs in the estimation of asset retirement obligations that include, but are not limited to, costs of labor and materials, profits 
on costs of labor and materials, the effect of inflation on estimated costs, and the discount rate.  Accordingly, asset retirement 
obligations are considered a Level 3 measurement under the FASC Fair Value Measurement topic.

Commodity Derivative Contracts

We utilize oil and natural gas derivative contracts to mitigate our exposure to commodity price risk associated with our 
future oil and natural gas production.  These derivative contracts have historically consisted of options, in the form of price 
floors,  collars,  three-way  collars,  fixed-price  swaps,  fixed-price  swaps  enhanced  with  a  sold  put,  and  basis  swaps.  Our 
derivative financial instruments, other than any derivative instruments that are designated under the “normal purchase normal 
sale” exclusion, are recorded on the balance sheet as either an asset or a liability measured at fair value.  We do not apply 
hedge  accounting  to  our  commodity  derivative  contracts;  accordingly,  changes  in  the  fair  value  of  these  instruments  are 
recognized in “Commodity derivatives expense (income)” in our Consolidated Statements of Operations in the period of 
change.

Concentrations of Credit Risk

Our financial instruments that are exposed to concentrations of credit risk consist primarily of cash equivalents, trade and 
accrued production receivables, and the derivative instruments discussed above.  Our cash equivalents represent high-quality 
securities placed with various investment-grade institutions.  This investment practice limits our exposure to concentrations 
of credit risk.  Our trade and accrued production receivables are dispersed among various customers and purchasers; therefore, 
concentrations of credit risk are limited.  We evaluate the credit ratings of our purchasers, and if customers are considered a 
credit risk, letters of credit are the primary security obtained to support lines of credit.  We attempt to minimize our credit risk 
exposure  to  the  counterparties  of  our  oil  and  natural  gas  derivative  contracts  through  formal  credit  policies,  monitoring 
procedures and diversification.  All of our derivative contracts are with parties that are lenders under our senior secured bank 
credit  facility  (or  affiliates  of  such  lenders).  There  are  no  margin  requirements  with  the  counterparties  of  our  derivative 
contracts.

Oil and natural gas sales are made on a day-to-day basis or under short-term contracts at the current area market price.  We 
would  not  expect  the  loss  of  any  purchaser  to  have  a  material  adverse  effect  upon  our  operations.  For  the  year  ended 
December 31, 2019, three purchasers accounted for 10% or more of our oil and natural gas revenues: Plains Marketing LP 
(32%), Hunt Crude Oil Supply Company (11%) and Sunoco Inc. (11%).  For the year ended December 31, 2018, two purchasers 
accounted for 10% or more of our oil and natural gas revenues: Plains Marketing LP (24%) and Hunt Crude Oil Supply 
Company (10%).  For the year ended December 31, 2017, two purchasers accounted for 10% or more of our oil and natural 
gas revenues: Plains Marketing LP (22%) and Marathon Petroleum Company (10%).

Other Receivables

During 2018, we recorded a $16.9 million impairment of a loan related to a proposed plant in the Gulf Coast that would 
potentially supply CO2 to Denbury, due to uncertainties of the project achieving financial close.  The impairment was included 
within “Other expenses” in our Consolidated Statements of Operations for the year ended December 31, 2018.

Income Taxes 

Income taxes are accounted for using the asset and liability method, under which deferred income taxes are recognized 
for the future tax effects of temporary differences between the financial statement carrying amounts and the tax basis of existing 
assets and liabilities using the enacted statutory tax rates in effect at year end.  The effect on deferred taxes for a change in 
tax rates is recognized in income in the period that includes the enactment date.  A valuation allowance for deferred tax assets 
is recorded when it is more likely than not that the benefit from the deferred tax asset will not be realized.

75

Denbury Resources Inc. 
Notes to Consolidated Financial Statements

We recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be 
sustained upon examination by the taxing authorities, based on the technical merits of the position.  The tax benefits recognized 
in the financial statements from such a position are measured based on the largest benefit that has a greater than 50% likelihood 
of being realized upon ultimate settlement.

Net Income per Common Share 

Basic net income per common share is computed by dividing the net income attributable to common stockholders by the 
weighted average number of shares of common stock outstanding during the period.  Diluted net income per common share
is calculated in the same manner, but includes the impact of potentially dilutive securities.  Potentially dilutive securities 
consist of nonvested restricted stock, nonvested performance-based equity awards, and shares into which our convertible 
senior notes are convertible.

The following table sets forth the reconciliations of net income and weighted average shares used for purposes of calculating 

basic and diluted net income per common share for the periods indicated:

In thousands
Numerator

Net income – basic

Effect of potentially dilutive securities

Interest expensed on convertible senior notes including
amortization of discount, net of tax

Net income – diluted

Denominator

Year Ended December 31,
2018

2017

2019

$

216,959

$

322,698

$

163,152

14,134

539

49

$

231,093

$

323,237

$

163,201

Weighted average common shares outstanding – basic

459,524

432,483

390,928

Effect of potentially dilutive securities

Restricted stock and performance-based equity awards
Convertible senior notes(1)

Weighted average common shares outstanding – diluted

2,396

48,421

510,341

6,500

17,186

456,169

2,242

2,751

395,921

(1)  For the year ended December 31, 2019, shares shown under “convertible senior notes” represent the prorated portion of 
the approximately 90.9 million shares of the Company’s common stock issuable upon full conversion of our convertible 
senior notes which were issued on June 19, 2019 (see Note 6, Long-Term Debt – 2019 Debt Reduction Transactions).

Basic weighted average common shares exclude shares of nonvested restricted stock.  As these restricted shares vest, 
they will be included in the shares outstanding used to calculate basic net income per common share (although time-vesting 
restricted stock is issued and outstanding upon grant).  For purposes of calculating diluted weighted average common shares, 
the nonvested restricted stock and performance-based equity awards are included in the computation using the treasury stock 
method, with the deemed proceeds equal to the average unrecognized compensation during the period, and for the shares 
underlying the convertible senior notes as if the convertible senior notes were converted at the earliest date outstanding during 
the respective periods.  In April and May 2018, all of the then outstanding 3½% Convertible Senior Notes due 2024 and 5% 
Convertible Senior Notes due 2023 (the “2023 Convertible Senior Notes”) converted into shares of Denbury common stock, 
resulting in the issuance of 55.2 million shares of our common stock upon conversion.  These shares have been included in 
basic weighted average common shares outstanding beginning on the date of conversion.  See Note 6, Long-Term Debt, for 
further discussion. 

76

 
 
 
Denbury Resources Inc. 
Notes to Consolidated Financial Statements

The following securities could potentially dilute earnings per share in the future, but were excluded from the computation 

of diluted net income per share, as their effect would have been antidilutive:

In thousands
Stock appreciation rights

Restricted stock and performance-based equity awards

Environmental and Litigation Contingencies

Year Ended December 31,
2018

2017

2019

2,027

5,505

2,743

1,234

4,512

5,645

The Company makes judgments and estimates in recording liabilities for contingencies such as environmental remediation 
or ongoing litigation.  Liabilities are recorded when it is both probable that a loss has been incurred and such loss is reasonably 
estimable.  Assessments of liabilities are based on information obtained from independent and in-house experts, loss experience 
in similar situations, actual costs incurred, and other case-by-case factors.  Any related insurance recoveries are recognized 
in our financial statements during the period received or at the time receipt is determined to be virtually certain.

Recent Accounting Pronouncements

Recently Adopted

Leases.  Effective January 1, 2019, we adopted Financial Accounting Standards Board (“FASB”) Accounting Standards 
Update  (“ASU”)  2016-02,  Leases  (“ASU  2016-02”),  and ASU  2018-01, Leases  (Topic  842)  –  Land  Easement  Practical 
Expedient for Transition to Topic 842, using the modified retrospective method with an application date of January 1, 2019.  
ASU 2016-02 does not apply to mineral leases or leases that convey the right to explore for or use the land on which oil, 
natural gas, and similar natural resources are contained.  We elected the practical expedients provided in the new ASUs that 
allow historical lease classification of existing leases, allow lease and non-lease components to be combined, and carry forward 
our accounting treatment for existing land easement agreements.  The adoption of the new standards resulted in the recognition 
of $39.1 million of lease right-of-use assets and $55.8 million of operating lease liabilities ($16.7 million of which related to 
previously-existing lease obligations) as of January 1, 2019, in our Consolidated Balance Sheets, but did not materially impact 
our results of operations and had no impact on our cash flows.  The additional lease right-of-use assets and operating lease 
liabilities recorded on our balance sheet primarily related to our leases for office space, as the accounting for our financing 
leases and pipeline financings was relatively unchanged.

Not Yet Adopted

Financial Instruments – Credit Losses.  In June 2016, the FASB issued ASU 2016-13, Financial Instruments – Credit 
Losses (“ASU 2016-13”).  ASU 2016-13 changes the impairment model for most financial assets and certain other instruments, 
including trade and other receivables, and requires the use of a new forward-looking expected loss model that will result in 
the earlier recognition of allowances for losses.  The amendments in this ASU are effective for fiscal years beginning after 
December 15, 2019, and interim periods within those fiscal years, and early adoption is permitted.  Entities must adopt the 
amendment using a modified retrospective approach to the first reporting period in which the guidance is effective.  We intend 
to adopt the standard using a modified retrospective approach with an application date of January 1, 2020.  The adoption of 
ASU 2016-13 is not expected to have a material effect on our consolidated financial statements.

Fair Value Measurement.  In August 2018, the FASB issued ASU 2018-13, Fair Value Measurement (Topic 820) –
Disclosure Framework – Changes to the Disclosure Requirements for Fair Value Measurements (“ASU 2018-13”).  ASU 
2018-13 adds, modifies, or removes certain disclosure requirements for recurring and nonrecurring fair value measurements 
based on the FASB’s consideration of costs and benefits.  The amendments in this ASU are effective for fiscal years beginning 
after December 15, 2019, and interim periods within those fiscal years, and early adoption is permitted.  Entities must adopt 
the amendments on changes in unrealized gains and losses for Level 3 fair value measurements, the range and weighted 
average of significant unobservable inputs used to develop Level 3 fair value measurements, and the narrative description of 
measurement uncertainty prospectively, and all other amendments should be applied retrospectively to all periods presented.  

77

 
Denbury Resources Inc. 
Notes to Consolidated Financial Statements

We plan to adopt the standard with an application date of January 1, 2020.  The adoption of ASU 2018-13 is not expected to 
have a material effect on our consolidated financial statements but may require enhanced footnote disclosures.

Note 2. Revenue Recognition 

We record revenue in accordance with FASC Topic 606, Revenue from Contracts with Customers.  The core principle of 
FASC Topic  606  is  that  an  entity  should  recognize  revenue  for  the  transfer  of  goods  or  services  equal  to  the  amount  of 
consideration that it expects to be entitled to receive for those goods or services.  This principle is achieved through applying 
a five-step process for customer contract revenue recognition:

• 

Identify the contract or contracts with a customer – We derive the majority of our revenues from oil and natural gas 
sales contracts and CO2 sales and transportation contracts.  The contracts specify each party’s rights regarding the goods or 
services to be transferred and contain commercial substance as they impact our financial statements.  A high percentage of 
our receivables balance is current, and we have not historically entered into contracts with counterparties that pose a credit 
risk without requiring adequate economic protection to ensure collection.

• 

Identify the performance obligations in the contract – Each of our revenue contracts specify a volume per day, or 
production from a lease designated in the contract (a distinct good), to be delivered at the delivery point over the term of the 
contract (the identified performance obligation).  The customer takes delivery and physical possession of the product at the 
delivery point, which generally is also the point at which title transfers and the customer obtains the risks and rewards of 
ownership (the identified performance obligation is satisfied).

•  Determine the transaction price – Typically, our oil and natural gas contracts define the price as a formula price based 
on the average market price, as specified on set dates each month, for the specific commodity during the month of delivery.  
Certain of our CO2 contracts define the price as a fixed contractual price adjusted to an inflation index to reflect market pricing.  
Given the industry practice to invoice customers the month following the month of delivery and our high probability of 
collection of payment, no significant financing component is included in our contracts.

•  Allocate the transaction price to the performance obligations in the contract – The majority of our revenue contracts 
are short-term, with terms of one year or less, to which we have applied the practical expedient permitted under the standard 
eliminating  the  requirement  to  disclose  the  transaction  price  allocated  to  remaining  performance  obligations.    In  limited 
instances, we have revenue contracts with terms greater than one year; however, the future delivery volumes are wholly 
unsatisfied as they represent separate performance obligations with variable consideration.  We utilized the practical expedient 
which eliminates the requirement to disclose the transaction price allocated to remaining performance obligations if the variable 
consideration is allocated entirely to wholly unsatisfied performance obligations.  As there is only one performance obligation 
associated with our contracts, no allocation of the transaction price is necessary.

•  Recognize  revenue  when,  or  as,  we  satisfy  a  performance  obligation  –  Once  we  have  delivered  the  volume  of 
commodity to the delivery point and the customer takes delivery and possession, we are entitled to payment and we invoice 
the customer for such delivered production.  Payment under most oil and CO2 contracts is made within a month following 
product delivery and for natural gas and NGL contracts is generally made within two months following delivery.  Timing of 
revenue recognition may differ from the timing of invoicing to customers; however, as the right to consideration after delivery 
is unconditional based on only the passage of time before payment of the consideration is due, upon delivery we record a 
receivable in “Accrued production receivable” in our Consolidated Balance Sheets, which was $139.4 million and $125.8 
million as of December 31, 2019 and December 31, 2018, respectively.  

In addition to revenues from oil and natural gas sales contracts and CO2 sales and transportation contracts, the Company 
enters into purchase transactions with third parties and separate sale transactions with third parties in the Gulf Coast region.  
Revenues and expenses from these transactions are presented on a gross basis, as we act as a principal in the transaction by 
assuming control of the commodities purchased and the responsibility to deliver the commodities sold.  Revenue is recognized 
when control transfers to the purchaser at the delivery point based on the price received from the purchaser.

78

Denbury Resources Inc. 
Notes to Consolidated Financial Statements

Disaggregation of Revenue

The following table summarizes our revenues by product type for the years ended December 31, 2019, 2018 and 2017:

In thousands

Oil sales

Natural gas sales
CO2 sales and transportation fees
Purchased oil sales

Total revenues

Note 3. Leases

Year Ended December 31,

2019

2018

2017

$

1,205,083

$

1,412,358

$

1,079,703

6,937

34,142

14,198

10,231

31,145

1,921

9,963

26,182

3,718

$

1,260,360

$

1,455,655

$

1,119,566

We evaluate contracts for leasing arrangements at inception.  We lease office space, equipment, and vehicles that have 
non-cancelable lease terms.  Currently, our outstanding leases have remaining terms up to 6 years, with certain land leases 
having remaining terms up to 50 years.  Leases with a term of 12 months or less are not recorded on our balance sheet.  During 
the third quarter of 2019, we exercised the early buyout option on our remaining finance leases.  The table below reflects our 
operating lease right-of-use assets and operating lease liabilities, which primarily consists of our office leases:

In thousands

Operating leases

Operating lease right-of-use assets

Operating lease liabilities - current

Operating lease liabilities - long-term

Total operating lease liabilities

December 31,

2019

$

$

$

34,099

6,901

41,932

48,833

The majority of our leases contain renewal options, typically exercisable at our sole discretion.  We record right-of-use 
assets and liabilities based on the present value of lease payments over the initial lease term, unless the option to extend the 
lease  is  reasonably  certain,  and  utilize  our  incremental  borrowing  rate  based  on  information  available  at  the  lease 
commencement date.  The following weighted average remaining lease terms and discount rates related to our outstanding 
operating leases: 

Weighted average remaining lease term

Weighted average discount rate

December 31,

2019

5.7 years

6.7%

79

Denbury Resources Inc. 
Notes to Consolidated Financial Statements

Lease costs for operating leases or leases with a term of 12 months or less are recognized on a straight-line basis over the 
lease term.  For finance leases, interest on the lease liability and the amortization of the right-of-use asset are recognized 
separately, with the depreciable life reflective of the expected lease term.  We have subleased part of the office space included 
in our operating leases.  We expect to receive a total of approximately $10.4 million for 2020 through 2025 under our sublease 
agreements.  The following table summarizes the components of lease costs and sublease income:

In thousands

Operating lease cost

Finance lease cost

Amortization of right-of-use assets
Interest on lease liabilities

Total finance lease cost

Income Statement

General and administrative expenses

Lease operating expenses
CO2 discovery and operating expenses

Depletion, depreciation, and amortization
Interest expense

Sublease income

General and administrative expenses

Our statement of cash flows included the following activity related to our operating and finance leases:

In thousands

Cash paid for amounts included in the measurement of lease liabilities

Operating cash flows from operating leases

Operating cash flows from interest on finance leases

Financing cash flows from finance leases

Right-of-use assets obtained in exchange for lease obligations

Operating leases

Finance leases

Year Ended

December 31,
2019

$

$

$

$

$

8,924

58

5

8,987

1,188
40

1,228

4,127

Year Ended

December 31,
2019

$

10,995

40

1,275

415

—

80

Denbury Resources Inc. 
Notes to Consolidated Financial Statements

The following table summarizes by year the maturities of our minimum lease payments as of December 31, 2019, but 

excludes future sublease receipts associated with sublease contracts we have for a portion of these operating leases:

In thousands

2020

2021

2022

2023

2024

Thereafter

Total minimum lease payments

Less: Amount representing interest

Present value of minimum lease payments

Operating

Leases

9,934

10,056

10,259

10,300

10,317

8,287

59,153
(10,320)
48,833

$

$

The following table summarizes by year the remaining non-cancelable future payments under our leases, as accounted 

for under previous accounting guidance under FASC Topic 840, Leases, as of December 31, 2018:

In thousands

2019

2020

2021

2022

2023

Thereafter

Total minimum lease payments

 Note 4. Asset Retirement Obligations

Operating

Leases

$

$

10,690

9,776

10,007

10,223

10,262

18,169

69,127

The following table summarizes the changes in our asset retirement obligations for the years ended December 31, 2019

and 2018:

In thousands
Beginning asset retirement obligations

Liabilities incurred and assumed during period

Revisions in estimated retirement obligations

Liabilities settled and sold during period

Accretion expense

Ending asset retirement obligations

Less: current asset retirement obligations(1)

Long-term asset retirement obligations

Year Ended December 31,

2019

2018

$

176,585

$

166,310

4,354

9,206
(24,342)
15,957

181,760
(4,652)
177,108

$

2,201

2,298
(9,481)
15,257

176,585
(2,115)
174,470

$

(1)  Included in “Accounts payable and accrued liabilities” in our Consolidated Balance Sheets.

Liabilities assumed relate to minor acquisitions, with liabilities incurred generally relating to wells and facilities.

81

 
Denbury Resources Inc. 
Notes to Consolidated Financial Statements

We have escrow accounts that are legally restricted for certain of our asset retirement obligations.  The balances of these 
escrow accounts were $53.4 million and $42.1 million as of December 31, 2019 and 2018, respectively.  These balances are 
primarily invested in U.S. Treasury bonds, recorded at amortized cost, and money market accounts, which investments are 
included in “Other assets” in our Consolidated Balance Sheets.  A portion of these investments are included in cash, cash 
equivalents, and restricted cash balances on our Consolidated Statements of Cash Flows (see Note 1, Nature of Operations 
and Summary of Significant Accounting Policies – Cash, Cash Equivalents, and Restricted Cash).  The carrying value of these 
investments approximates their estimated fair market value as of December 31, 2019 and 2018.

Note 5. Unevaluated Property

A summary of the unevaluated property costs excluded from oil and natural gas properties being amortized at December 31, 

2019, and the year in which the costs were incurred follows:

December 31, 2019

Costs Incurred During:

In thousands

2019

2018

2017

Property acquisition costs

Exploration and development

Capitalized interest

Total

$

$

— $

— $

3,522

31,489

1,862

27,013

8,527

3,175

23,134

2016 and Prior
572,930
$

$

108,268

92,990

Total

581,457

116,827

174,626

872,910

35,011

$

28,875

$

34,836

$

774,188

$

Our property acquisition costs for 2016 and prior were primarily related to the fair value allocated to the purchase of 
interests in the Cedar Creek Anticline (“CCA”) and Hartzog Draw, as well as CO2 tertiary potential at Conroe Field.  Exploration 
and development costs shown as unevaluated properties are primarily associated with our tertiary oil fields that are under 
development but did not have proved reserves at December 31, 2019.  The most significant development costs incurred during 
each period relate to development in preparation for the CO2 floods at Webster, Conroe, and CCA fields.  We have not yet 
recognized proved tertiary reserves in these fields.

Costs  are  transferred  into  the  amortization  base  on  an  ongoing  basis  as  projects  are  evaluated  and  proved  reserves 
established or impairment determined.  We review the excluded properties for impairment at least annually.  We currently 
estimate that evaluation of the majority of these properties and the inclusion of their costs in the amortization base is expected 
to be completed within five to ten years.  Until we are able to determine whether there are any proved reserves attributable to 
the above costs, we are not able to assess the future impact on the amortization rate of the full cost pool.

82

 
 
 
Denbury Resources Inc. 
Notes to Consolidated Financial Statements

Note 6. Long-Term Debt

The table below reflects long-term debt and capital lease obligations outstanding as of December 31, 2019 and 2018:

In thousands
Senior Secured Bank Credit Agreement

9% Senior Secured Second Lien Notes due 2021

9¼% Senior Secured Second Lien Notes due 2022
7¾% Senior Secured Second Lien Notes due 2024
7½% Senior Secured Second Lien Notes due 2024

5½% Senior Subordinated Notes due 2022

Pipeline financings

Capital lease obligations

Total debt principal balance

Debt discount(1)
Future interest payable(2)
Debt issuance costs

Total debt, net of debt issuance costs and discount

Less: current maturities of long-term debt(3)

Long-term debt and capital lease obligations

December 31,

2019

2018

$

— $

614,919

455,668
531,821
20,641
245,548

51,304

58,426

135,960

167,439

—

—

614,919

455,668
—
450,000
—

203,545

314,662

307,978

180,073

5,362

2,281,726
(101,767)
164,914
(10,009)
2,334,864
(102,294)
2,232,570

$

2,532,207

—

250,218
(13,089)
2,769,336
(105,125)
2,664,211

$

(1)  Consists of discounts related to the issuance during June 2019 of our new 7¾% Senior Secured Second Lien Notes due 
2024 (the “7¾% Senior Secured Notes”) and new 6 % Convertible Senior Notes due 2024 (the “2024 Convertible Senior 
Notes”) of $27.0 million and $74.8 million, respectively (see 2019 Debt Reduction Transactions below) as of December 31, 
2019.

(2)  Future interest payable represents most of the interest due over the terms of our 9% Senior Secured Second Lien Notes 
due 2021 (the “2021 Senior Secured Notes”) and 9¼% Senior Secured Second Lien Notes due 2022 (the “2022 Senior 
Secured Notes”) and has been accounted for as debt in accordance with FASC 470-60, Troubled Debt Restructuring by 
Debtors.

(3)  Our current maturities of long-term debt as of December 31, 2019 include $86.1 million of future interest payable related 

to the 2021 Senior Secured Notes and 2022 Senior Secured Notes that is due within the next twelve months.

The ultimate parent company in our corporate structure, Denbury Resources Inc. (“DRI”), is the sole issuer of all our 
outstanding  senior  secured,  convertible  senior,  and  senior  subordinated  notes.  DRI  has  no  independent  assets  or 
operations.  Each of the subsidiary guarantors of such notes is 100% owned, directly or indirectly, by DRI, and the guarantees 
of the notes are full and unconditional and joint and several; any subsidiaries of DRI that are not subsidiary guarantors of such 
notes are minor subsidiaries.

Senior Secured Bank Credit Facility

In December 2014, we entered into an Amended and Restated Credit Agreement with JPMorgan Chase Bank, N.A., as 
administrative agent, and other lenders party thereto (as amended, the “Bank Credit Agreement”).  The Bank Credit Agreement 
is a senior secured revolving credit facility with a maturity date of December 9, 2021, provided that the maturity date may 
occur earlier (February 12, 2021, May 14, 2021 or August 13, 2021) if the 2021 Senior Secured Notes due in May 2021 or 
6 % Senior Subordinated Notes due in August 2021 (the “2021 Senior Subordinated Notes”), respectively, are not repaid or 

83

 
Denbury Resources Inc. 
Notes to Consolidated Financial Statements

refinanced by each of their respective maturity dates.  As of December 31, 2019, the borrowing base and lender commitments 
for  the  revolving  credit  facility  were  $615  million,  and  scheduled  redeterminations  of  the  borrowing  base  are  to  occur 
semiannually in May and November of each year, with the next such redetermination being scheduled for May 2020.  If our 
outstanding debt under the Bank Credit Agreement were to ever exceed the borrowing base, we would be required to repay 
the excess amount over a period not to exceed six months.  Under the Bank Credit Agreement, letters of credit are available 
in an aggregate amount not to exceed $100 million, which may be increased at the sole discretion of the administrative agent, 
and short-term swingline loans are available in an aggregate amount not to exceed $25 million, each subject to the available 
commitments under the Bank Credit Agreement.  The Bank Credit Agreement is guaranteed jointly and severally by each 
subsidiary of DRI that is 100% owned, directly or indirectly, by DRI and is secured by (1) a significant portion of our proved 
oil and natural gas properties held through DRI’s restricted subsidiaries; (2) the pledge of equity interests of such subsidiaries; 
(3) a pledge of commodity derivative agreements of DRI and such subsidiaries (as applicable); and (4) a pledge of deposit 
accounts, securities accounts and commodity accounts of DRI and such subsidiaries (as applicable).

The Bank Credit Agreement limits our ability to, among other things, incur and repay indebtedness; grant liens; engage 
in certain mergers, consolidations, liquidations and dissolutions; engage in sales of assets; make acquisitions and investments; 
make  distributions  and  dividends;  and  enter  into  commodity  derivative  agreements,  in  each  case  subject  to  customary 
exceptions.

The Bank Credit Agreement contains certain financial performance covenants through the maturity of the facility, 

including the following:

•  A Consolidated Total Debt to Consolidated EBITDAX financial maintenance covenant, with such ratio not to exceed 

5.25 to 1.0 through December 31, 2020 and 4.50 to 1.0 thereafter;

•  A consolidated senior secured debt to consolidated EBITDAX covenant, with such ratio not to exceed 2.5 to 1.0.  
Only debt under our Bank Credit Agreement is considered consolidated senior secured debt for purposes of this ratio;

•  A minimum permitted ratio of consolidated EBITDAX to consolidated interest charges of 1.25 to 1.0; and
•  A requirement to maintain a current ratio (i.e., Consolidated Current Assets to Consolidated Current Liabilities) of 

1.0 to 1.0.

For purposes of computing the current ratio per the Bank Credit Agreement, Consolidated Current Assets exclude the 
current portion of derivative assets but include borrowing base availability under the senior secured bank credit facility, and 
Consolidated Current Liabilities exclude the current portion of derivative liabilities as well as the current portions of long-
term indebtedness outstanding.  

As of December 31, 2019, (1) loans under the Bank Credit Agreement were subject to varying rates of interest based on 
either (a) for ABR Loans, a base rate determined under the Bank Credit Agreement (the “ABR”) plus an applicable margin 
ranging from 1.75% to 2.75% per annum, or (b) for LIBOR Loans, the LIBOR rate plus an applicable margin ranging from 
2.75% to 3.75% per annum (capitalized terms as defined in the Bank Credit Agreement) and (2) the undrawn portion of the 
aggregate lender commitments under the Bank Credit Agreement was subject to a commitment fee of 0.50%.  As of December 
31, 2019, we had no outstanding borrowings, $87.2 million of letters of credit outstanding and were in compliance with all 
debt covenants under the Bank Credit Agreement.

The above description of our Bank Credit Agreement is qualified by the express language and defined terms contained 
in the Bank Credit Agreement and the amendments thereto, each of which are filed as exhibits to our periodic reports filed 
with the SEC.

2019 Debt Reduction Transactions

During the third quarter of 2019, we repurchased $11.0 million in aggregate principal amount of our then outstanding 
5½% Senior Subordinated Notes due 2022 (the “2022 Senior Subordinated Notes”) in open market transactions for a total 
purchase price of $5.3 million, excluding accrued interest.  Additionally, during the fourth quarter of 2019, we repurchased 
principally through exchanges an additional $25.3 million in aggregate principal amount of our then outstanding 2022 Senior 
Subordinated Notes and $75.7 million in aggregate principal amount of our then outstanding 4 % Senior Subordinated Notes 
due 2023 (the “2023 Senior Subordinated Notes”) for $11.2 million in cash and issuance of 38.3 million shares of the Company’s 

84

Denbury Resources Inc. 
Notes to Consolidated Financial Statements

common stock.  In connection with these transactions, we recognized a $55.5 million gain on debt extinguishment, net of 
unamortized debt issuance costs written off, during the year ended December 31, 2019, in our Consolidated Statements of 
Operations.

During June 2019, in a series of debt exchanges, we extended the maturities of our outstanding long-term debt and reduced 
the amount of our outstanding debt principal.  As part of these transactions, holders exchanged a total of $468.4 million
aggregate principal amount of our then outstanding senior subordinated notes for $102.6 million aggregate principal amount 
of new 7¾% Senior Secured Notes, $245.5 million aggregate principal amount of new 2024 Convertible Senior Notes and 
$120.0 million of cash.  The exchanged senior subordinated notes consisted of $152.2 million aggregate principal amount of 
our 2021 Senior Subordinated Notes, $219.9 million aggregate principal amount of our 2022 Senior Subordinated Notes and 
$96.3 million aggregate principal amount of our 2023 Senior Subordinated Notes.  In addition, holders also exchanged $425.4 
million of 7½% Senior Secured Second Lien Notes due 2024 (the “7½% Senior Secured Notes”) for $425.4 million aggregate 
principal amount of 7¾% Senior Secured Notes.  In July 2019, holders exchanged an additional $4.0 million aggregate principal 
amount of 7½% Senior Secured Notes for $3.8 million aggregate principal amount of 7¾% Senior Secured Notes.  As a result, 
we recognized a noncash gain on debt extinguishment, net of transaction costs, totaling $100.5 million for the year ended 
December 31, 2019, in our Consolidated Statements of Operations.  

In accordance with FASC 470-50, Modifications and Extinguishments, the June 2019 exchange of our existing senior 
subordinated notes was accounted for as a debt extinguishment.  Therefore, our new 7¾% Senior Secured Notes and new 
2024 Convertible Senior Notes were recorded on our balance sheet at fair market value based upon initial trading prices 
following their issuance, resulting in a discount to their principal amount of $22.6 million and $79.9 million, respectively.  
These debt discounts will be amortized as interest expense over the terms of these notes.

Separately, the June 2019 exchange of our existing senior secured second lien notes was accounted for as a modification 
of those notes.  Therefore, no gain or loss was recognized, and previously deferred debt issuance costs of $6.9 million were 
treated as a discount to the principal amount of the new 7¾% Senior Secured Notes, which discount will be amortized as 
interest expense over the term of these notes.

January 2018 Senior Subordinated Note Exchanges

During January 2018, we closed transactions to exchange a total of $174.3 million aggregate principal amount of our 
then existing senior subordinated notes for $74.1 million aggregate principal amount of new 2022 Senior Secured Notes and 
$59.4 million aggregate principal amount of our previously outstanding 2023 Convertible Senior Notes, resulting in a net 
reduction  in  our  debt  principal  from  these  exchanges  of  $40.8  million.   The  exchanged  notes  consisted  of  $11.6  million
aggregate principal amount of our 2021 Senior Subordinated Notes, $94.2 million aggregate principal amount of our 2022 
Senior Subordinated Notes and $68.5 million aggregate principal amount of our 2023 Senior Subordinated Notes.  In May 
2018, the debt principal balance and future interest applicable to the 2023 Convertible Senior Notes were reclassified to “Paid-
in capital in excess of par” and “Common stock” in our Consolidated Balance Sheets following the conversion of the notes 
into shares of Denbury common stock (see Conversions of 2023 and 2024 Convertible Senior Notes into Common Stock in 
April and May 2018 below for further discussion).

2017 Senior Subordinated Note Exchanges

During December 2017, we entered into privately negotiated agreements to exchange a total of $609.8 million aggregate 
principal amount of our existing senior subordinated notes for $381.6 million aggregate principal amount of new 2022 Senior 
Secured Notes and $84.7 million aggregate principal amount of 3½% Convertible Senior Notes due 2024, resulting in a net 
reduction in our debt principal from these exchanges of $143.6 million.  The exchanged notes consisted of $364.0 million
aggregate principal amount of our 2022 Senior Subordinated Notes and $245.8 million aggregate principal amount of our 
2023 Senior Subordinated Notes.

Conversions of 2023 and 2024 Convertible Senior Notes into Common Stock in April and May 2018

During  the  second  quarter  of  2018,  holders  of  all $59.4  million aggregate  principal  amount  outstanding  of  our  2023 
Convertible Senior Notes and $84.7 million aggregate principal amount outstanding of our 3½% Convertible Senior Notes 

85

Denbury Resources Inc. 
Notes to Consolidated Financial Statements

due 2024 converted their notes into shares of Denbury common stock, at the rates specified in the indentures for these notes, 
resulting in the issuance of 55.2 million shares of our common stock upon conversion.  The debt principal balances and future 
interest  treated  as  debt  applicable  to  the  2023  Convertible  Senior  Notes  and  3½%  Convertible  Senior  Notes  due  2024, 
totaling $162.0 million, were reclassified to “Paid-in capital in excess of par” and “Common stock” in our Consolidated 
Balance Sheets upon the conversion of the notes into shares of Denbury common stock.  As of April 18, 2018 and May 30, 
2018, there were no remaining 3½% Convertible Senior Notes due 2024 and 2023 Convertible Senior Notes outstanding, 
respectively.

Senior Secured Second Lien Notes

9% Senior Secured Second Lien Notes due 2021.  In May 2016, we issued $614.9 million of 2021 Senior Secured 
Notes.  The 2021 Senior Secured Notes, which bear interest at a rate of 9% per annum, were issued at par in connection with 
privately negotiated exchanges with a limited number of holders of existing senior subordinated notes.  The 2021 Senior 
Secured Notes mature on May 15, 2021, and interest is payable semiannually in arrears on May 15 and November 15 of each 
year.  At any time prior to December 15, 2020, we may redeem the 2021 Senior Secured Notes in whole or in part at our 
option, at a redemption price of 104.50% of the principal amount, and at par thereafter, as specified in the indenture.  The 
2021 Senior Secured Notes are not subject to any sinking fund requirements.

The 2021 Senior Secured Notes are guaranteed jointly and severally by our subsidiaries representing substantially all of 
our assets, operations and income and are secured by second-priority liens on substantially all of the assets that secure the 
Bank  Credit Agreement,  which  second-priority  liens  are  contractually  subordinated  to  liens  that  secure  our  Bank  Credit 
Agreement and any future additional priority lien debt.

9¼% Senior Secured Second Lien Notes due 2022.  In December 2017 and January 2018, we issued $381.6 million 
and $74.1 million, respectively, of 2022 Senior Secured Notes.  The 2022 Senior Secured Notes, which bear interest at a rate 
of 9.25% per annum, were issued at par in connection with exchanges with a limited number of holders of existing senior 
subordinated notes (see January 2018 Senior Subordinated Note Exchanges and 2017 Senior Subordinated Note Exchanges 
above).  The 2022 Senior Secured Notes mature on March 31, 2022, and interest is payable semiannually in arrears on March 
31 and September 30 of each year.  We may redeem the 2022 Senior Secured Notes in whole or in part at our option, at a 
redemption price of 109.25% of the principal amount at any time prior to March 31, 2020, 104.625% of the principal amount 
prior to March 31, 2021, and at par thereafter.  The 2022 Senior Secured Notes are not subject to any sinking fund requirements.

The 2022 Senior Secured Notes are guaranteed jointly and severally by our subsidiaries representing substantially all of 
our assets, operations and income and are secured by second-priority liens on substantially all of the assets that secure the 
Bank  Credit Agreement,  which  second-priority  liens  are  contractually  subordinated  to  liens  that  secure  our  Bank  Credit 
Agreement and any future additional priority lien debt.

7¾% Senior Secured Second Lien Notes due 2024.  In June 2019, we issued $528.0 million of 7¾% Senior Secured 
Notes in connection with exchanges with certain holders of the Company’s outstanding senior subordinated notes and existing 
7½% Senior Secured Notes (see 2019 Debt Reduction Transactions above).  The 7¾% Senior Secured Notes, which carry a 
stated interest rate of 7.75% per annum, were recorded at approximately 94% of their principal amount in accordance with 
FASC 470-50, Modifications and Extinguishments, which equates to an effective yield to maturity of approximately 9.39%.  
In July 2019, we issued an additional $3.8 million of 7¾% Senior Secured Notes in exchange for $4.0 million of 7½% Senior 
Secured Notes, which were recorded at par.  The 7¾% Senior Secured Notes mature on February 15, 2024, and interest is 
payable semiannually in arrears on February 15 and August 15 of each year.  We may redeem the 7¾% Senior Secured Notes 
in whole or in part at our option beginning August 15, 2020, at a redemption price of 103.875% of the principal amount, and 
at declining redemption prices thereafter, as specified in the indenture governing the 7¾% Senior Secured Notes.  Prior to 
August 15, 2020, we may at our option redeem up to an aggregate of 35% of the principal amount of the 7¾% Senior Secured 
Notes at a price of 107.75% of par with the proceeds of certain equity offerings.  In addition, at any time prior to August 15, 
2020, we may redeem the 7¾% Senior Secured Notes in whole or in part at a price equal to 100% of the principal amount 
plus a “make-whole” premium and accrued and unpaid interest.  The 7¾% Senior Secured Notes are not subject to any sinking 
fund requirements.

86

Denbury Resources Inc. 
Notes to Consolidated Financial Statements

The 7¾% Senior Secured Notes are guaranteed jointly and severally by our subsidiaries representing substantially all of 
our assets, operations and income and are secured by second-priority liens on substantially all of the assets that secure the 
Bank  Credit Agreement,  which  second-priority  liens  are  contractually  subordinated  to  liens  that  secure  our  Bank  Credit 
Agreement and any future additional priority lien debt.

7½% Senior Secured Second Lien Notes due 2024.  In August 2018, we issued $450.0 million of 7½% Senior Secured 
Notes. The 7½% Senior Secured Notes, which bear interest at a rate of 7.50% per annum, were issued at par to repay outstanding 
borrowings on our Bank Credit Agreement, with additional proceeds used for general corporate purposes.  After note exchanges 
completed in June and July of 2019, $20.6 million principal amount of the 7½% Senior Secured Notes remained outstanding 
as of December 31, 2019.  The 7½% Senior Secured Notes mature on February 15, 2024, and interest is payable semiannually 
in arrears on February 15 and August 15 of each year.  We may redeem the 7½% Senior Secured Notes in whole or in part at 
our option beginning August 15, 2020, at a redemption price of 103.75% of the principal amount, and at declining redemption 
prices thereafter, as specified in the indenture governing the 7½% Senior Secured Notes.  Prior to August 15, 2020, we may 
at  our  option  redeem  up  to  an  aggregate  of 35% of  the  principal  amount  of  the  7½%  Senior  Secured  Notes  at  a  price 
of 107.50% of par with the proceeds of certain equity offerings.  In addition, at any time prior to August 15, 2020, we may 
redeem the 7½% Senior Secured Notes in whole or in part at a price equal to 100% of the principal amount plus a “make-
whole”  premium  and  accrued  and  unpaid  interest.   The  7½%  Senior  Secured  Notes  are  not  subject  to  any  sinking  fund 
requirements.

The 7½% Senior Secured Notes are guaranteed jointly and severally by our subsidiaries representing substantially all of 
our assets, operations and income and are secured by second-priority liens on substantially all of the assets that secure the 
Bank  Credit Agreement,  which  second-priority  liens  are  contractually  subordinated  to  liens  that  secure  our  Bank  Credit 
Agreement and any future additional priority lien debt.

Restrictive Covenants in Indentures for Senior Secured Second Lien Notes.  Each of the indentures for the 2021 
Senior Secured Notes, 2022 Senior Secured Notes, 7¾% Senior Secured Notes and 7½% Senior Secured Notes contains 
customary covenants that are generally consistent and that restrict our ability and the ability of our restricted subsidiaries to 
(1) incur additional debt; (2) make investments; (3) create liens on our assets or the assets of our restricted subsidiaries; (4) 
create limitations on the ability of our restricted subsidiaries to pay dividends or make other payments to DRI or other restricted 
subsidiaries; (5) engage in transactions with our affiliates; (6) transfer or sell assets or subsidiary stock; (7) consolidate, merge 
or transfer all or substantially all of our assets and the assets of our restricted subsidiaries; and (8) make restricted payments 
(which includes paying dividends on our common stock or redeeming, repurchasing or retiring such stock or subordinated 
debt (including existing senior subordinated notes)), provided that in certain circumstances we may make unlimited restricted 
payments so long as we maintain a Leverage Ratio (as defined in the indentures) not to exceed 2.5 to 1.0 (both before and 
after giving effect to any restricted payment).  As of December 31, 2019, we were in compliance with all debt covenants under 
the indentures related to our senior secured second lien notes.

Convertible Senior Notes

6 % Convertible Senior Notes due 2024.  In June 2019, we issued $245.5 million of 2024 Convertible Senior Notes 
in connection with exchanges with certain holders of the Company’s outstanding senior subordinated notes (see 2019 Debt 
Reduction Transactions above).  The 2024 Convertible Senior Notes, which carry a stated interest rate of 6.375% per annum, 
were  recorded  at  approximately  67%  of  their  principal  amount  in  accordance  with  FASC  470-50,  Modifications  and 
Extinguishments, which equates to an effective yield to maturity of approximately 15.31%.  Interest on the 2024 Convertible 
Senior Notes is payable semiannually in arrears on June 30 and December 30 of each year and mature on December 31, 2024.  
We do not have the right to redeem the 2024 Convertible Senior Notes prior to their maturity.  The 2024 Convertible Senior 
Notes are convertible into shares of our common stock at any time, at the option of the holders, at a rate of 370 shares of 
common stock per $1,000 principal amount of 2024 Convertible Senior Notes, which is equivalent to approximately 90.9 
million shares of the Company’s common stock, subject to customary adjustments to the conversion rate and threshold price 
with respect to, among other things, stock dividends and distributions, mergers and reclassifications.  The 2024 Convertible 
Senior Notes will be automatically converted into shares of common stock at this rate if the volume weighted average trading 
price of the Company’s common stock equals or exceeds the threshold price, which is $2.43 per share, for 10 trading days in 
any period of 15 consecutive trading days, subject to satisfaction of certain other conditions.  Additionally, the Company may, 
based on a determination of its Board of Directors that such changes are in the best interests of the Company, and subject to 

87

Denbury Resources Inc. 
Notes to Consolidated Financial Statements

certain limitations, increase the conversion rate.  Any such conversion rate increase would cause a proportional decrease in 
the threshold price for mandatory conversions, and thereby would enable the Company to require a mandatory conversion 
into common stock at a lower price.

Restrictive Covenants in Indentures for Convertible Senior Notes.  The indenture for the 2024 Convertible Senior 
Notes contains certain covenants that restrict our ability and the ability of our restricted subsidiaries to take or permit certain 
actions, including restrictions on our ability and the ability of our restricted subsidiaries to (1) incur additional debt; (2) make 
investments; (3) create liens on our assets or the assets of our restricted subsidiaries; (4) create restrictions on the ability of 
our restricted subsidiaries to pay dividends or make other payments to DRI or other restricted subsidiaries; (5) engage in 
transactions with our affiliates; (6) transfer or sell assets or subsidiary stock; (7) consolidate, merge or transfer all or substantially 
all of our assets and the assets of our restricted subsidiaries; and (8) make restricted payments (which includes paying dividends 
on  our  common  stock  or  redeeming,  repurchasing  or  retiring  such  stock  or  subordinated  debt),  provided  that  in  certain 
circumstances we may make unlimited restricted payments so long as we maintain a Leverage Ratio (both as defined in the 
indenture) not to exceed 2.5 to 1.0 (both before and after giving effect to any restricted payment).  As of December 31, 2019, 
we were in compliance with all debt covenants under the indenture related to our convertible senior notes.

Senior Subordinated Notes

6 % Senior Subordinated Notes due 2021.  In February 2011, we issued $400 million of 2021 Senior Subordinated 
Notes.  The 2021 Senior Subordinated Notes, which bear interest at a rate of 6.375% per annum, were sold at par.  After note 
repurchases in open market transactions and exchange transactions completed over the last four years, $51.3 million principal 
amount of the 2021 Senior Subordinated Notes remained outstanding as of December 31, 2019.  The 2021 Senior Subordinated 
Notes mature on August 15, 2021, and interest is payable on February 15 and August 15 of each year.  We may redeem the 
2021 Senior Subordinated Notes in whole or in part at our option at a redemption price of 100% of the principal amount.

5½% Senior Subordinated Notes due 2022.  In April 2014, we issued $1.25 billion of 2022 Senior Subordinated Notes.  
The 2022 Senior Subordinated Notes, which bear interest at a rate of 5.5% per annum, were sold at par.  After note repurchases 
in open market transactions and exchange transactions completed over the last four years, $58.4 million principal amount of 
the 2022 Senior Subordinated Notes remained outstanding as of December 31, 2019.  The 2022 Senior Subordinated Notes 
mature on May 1, 2022, and interest is payable on May 1 and November 1 of each year.  At any time prior to May 1, 2020, 
we may redeem the 2022 Senior Subordinated Notes in whole or in part at our option, at a redemption price of 101.375% of 
the principal amount, and at par thereafter, as specified in the indenture.  The 2022 Senior Subordinated Notes are not subject 
to any sinking fund requirements.

4 % Senior Subordinated Notes due 2023.  In February 2013, we issued $1.2 billion of 2023 Senior Subordinated 
Notes.  The 2023 Senior Subordinated Notes, which bear interest at a rate of 4.625% per annum, were sold at par.  After note 
repurchases in open market transactions and exchange transactions completed over the last four years, $136.0 million principal 
amount of the 2023 Senior Subordinated Notes remained outstanding as of December 31, 2019.  The 2023 Senior Subordinated 
Notes mature on July 15, 2023, and interest is payable on January 15 and July 15 of each year.  At any time prior to January 
15, 2021, we may redeem the 2023 Senior Subordinated Notes in whole or in part at our option at a redemption price of 
100.771% of the principal amount, and at par thereafter, as specified in the indenture.  The 2023 Senior Subordinated Notes 
are not subject to any sinking fund requirements.

Restrictive Covenants in Indentures for Senior Subordinated Notes.  Each of the indentures for the 2021 Senior 
Subordinated Notes, 2022 Senior Subordinated Notes and 2023 Senior Subordinated Notes contains certain covenants that 
are generally consistent and that restrict our ability and the ability of our restricted subsidiaries to take or permit certain actions, 
including  restrictions  on  our  ability  and  the  ability  of  our  restricted  subsidiaries  to  (1)  incur  additional  debt;  (2)  make 
investments; (3) create liens on our assets or the assets of our restricted subsidiaries; (4) create restrictions on the ability of 
our restricted subsidiaries to pay dividends or make other payments to DRI or other restricted subsidiaries; (5) engage in 
transactions with our affiliates; (6) transfer or sell assets or subsidiary stock; (7) consolidate, merge or transfer all or substantially 
all of our assets and the assets of our restricted subsidiaries; and (8) make restricted payments (which includes paying dividends 
on our common stock or redeeming, repurchasing or retiring such stock or subordinated debt), provided that the restricted 
payments covenant in the indentures for the 2022 Senior Subordinated Notes and 2023 Senior Subordinated Notes permits 
us in certain circumstances to make unlimited restricted payments so long as we maintain a Leverage Ratio (both as defined 

88

Denbury Resources Inc. 
Notes to Consolidated Financial Statements

in the 2022 Senior Subordinated Notes and 2023 Senior Subordinated Notes Indentures) not to exceed 2.5 to 1.0 (both before 
and after giving effect to any restricted payment), although we will not be able to realize the practical benefit of the restricted 
payment covenant flexibility in the 2022 Senior Subordinated Notes and 2023 Senior Subordinated Notes Indentures until 
the 2021 Senior Subordinated Notes have been redeemed or retired.  As of December 31, 2019, we were in compliance with 
all debt covenants under the indentures related to our senior subordinated notes.

Pipeline Financings

In May 2008, we closed two transactions with Genesis Energy, L.P. (“Genesis”) involving two of our pipelines.  The 
NEJD Pipeline system included a 20-year financing, and the Free State Pipeline included a long-term transportation service 
agreement.  These transactions are both accounted for as financing arrangements under FASC Topic 840, Leases.

Debt Issuance Costs

In connection with the issuance of our outstanding long-term debt, we have incurred debt issuance costs, which are being 
amortized to interest expense using the straight line or effective interest method over the term of each related facility or 
borrowing.  Remaining unamortized debt issuance costs were $14.0 million and $19.1 million at December 31, 2019 and 
2018,  respectively.  Issuance  costs  associated  with  our  Bank  Credit  Agreement  are  included  in  “Other  assets”  in  our 
Consolidated Balance Sheets, and issuance costs associated with our senior secured second lien notes, convertible senior 
notes, and senior subordinated notes are included as a reduction of “Long-term debt, net of current portion” in our Consolidated 
Balance Sheets.

Indebtedness Repayment Schedule

At December 31, 2019, our indebtedness, including our financing lease obligations but excluding future interest payable 
treated as debt in accordance with FASC 470-60, Troubled Debt Restructuring by Debtors, is payable over the next five years 
and thereafter as follows (assuming our 2024 Convertible Senior Notes do not convert into shares of our common stock prior 
to maturity):

In thousands

2020

2021

2022

2023

2024

Thereafter

Total indebtedness

$

$

15,323

683,562

532,157

155,293

817,297

78,094
2,281,726  

89

 
Denbury Resources Inc. 
Notes to Consolidated Financial Statements

Note 7. Income Taxes

Our income tax provision (benefit) is as follows:

In thousands
Current income tax expense (benefit)

Federal

State

Total current income tax expense (benefit)

Deferred income tax expense (benefit)

Federal

State

Year Ended December 31,
2018

2017

2019

$

2,645

$

1,236

3,881

(17,885) $
1,884
(16,001)

(19,485)
(1,388)
(20,873)

89,950

10,521

100,471
104,352

$

93,395

9,839

103,234
87,233

$

(113,863)
18,084
(95,779)
(116,652)

Total deferred income tax expense (benefit)

Total income tax expense (benefit)

$

At  December 31,  2019,  we  had  no  federal  net  operating  loss  carryforwards  (“NOLs”),  tax  effected  business  interest 
expense carryforward totaling $24.5 million (before provision for valuation allowance), state NOLs and tax credits totaling 
$52.9 million (before provision for valuation allowance), an estimated $49.9 million of enhanced oil recovery credits to carry 
forward related to our tertiary operations, an estimated $21.6 million of research and development credits, and $6.0 million
of alternative minimum tax credits.  Under the Tax Cut and Jobs Act (“the Act”) enacted in December 2017, all of our alternative 
minimum tax credits are fully refundable by 2021 and are recorded as a receivable on the balance sheet.  We considered our 
assessment of the recorded tax benefit associated with the impacts of the Act to be substantially complete as of December 31, 
2018, which is reflected in the table reconciling income tax expense below.  Federal and state regulatory guidance of the Act 
are continuing to be issued and could result in further tax effects but are not expected to be material to our financial statements.  
In addition, the Tax Cut and Jobs Act revised the rules regarding the deductibility of business interest expense by limiting that 
deduction to 30% of adjusted taxable income (as defined), with disallowed amounts being carried forward to future taxable 
years.  Based on our evaluation, using information existing as of the balance sheet date, of the near-term ability to utilize the 
tax benefits associated with our 2019 and 2018 disallowed business interest expense, we have established a valuation allowance 
of $24.5 million for that portion of our business interest expense that is currently expected to exceed the allowed limitation 
under the Act.  Our business interest expense carryforward does not expire.  Our state NOLs expire in various years, starting 
in 2020, although most do not begin to expire until 2025.  Our enhanced oil recovery credits and research and development 
credits begin to expire in 2025 and 2031, respectively.

Deferred income taxes reflect the available tax carryforwards and the temporary differences based on tax laws and statutory 
rates in effect at the December 31, 2019 and 2018 balance sheet dates.  As of December 31, 2019, we had $52.7 million of 
deferred tax assets associated with State of Louisiana, Mississippi and Alabama net operating losses and tax credits.  A tax 
valuation allowance was recorded in 2015 to reduce the carrying value of our Louisiana deferred tax assets as the result of a 
tax law enacted in the State of Louisiana, which limits a company’s utilization of certain deductions, including our net operating 
loss carryforwards.  As of December 31, 2019, tax valuation allowances totaling $41.3 million were recorded for our State of 
Louisiana deferred tax assets.  Based on losses from falling commodity prices and lower future forecasted income related to 
our Mississippi deferred tax assets, we concluded it was not more likely than not that the deferred tax assets would be realized.  
Accordingly, we recorded a valuation allowance against our Mississippi deferred tax assets in 2017.  As of December 31, 
2019, tax valuation allowances totaling $10.6 million were recorded for our State of Mississippi deferred tax assets.  During 
2019, we recorded a valuation allowance against our Alabama deferred tax assets totaling $0.8 million.  After closing on the 
sale of our Citronelle Field in 2019, our ability to utilize our Alabama net operating losses will be limited, and we concluded 
it was not more likely than not that the deferred tax assets would be realized.  The valuation allowances will remain until the 
realization of future deferred tax benefits are more likely than not to become utilized.  

90

 
 
 
 
 
 
 
Denbury Resources Inc. 
Notes to Consolidated Financial Statements

The  changes  in  our  valuation  allowance  established  for  our  state  net  operating  losses  and  business  interest  expense 

carryforward for 2019, 2018, and 2017 are detailed below:

In thousands
Balance at beginning of year

Federal

State

Balance at end of year

Year Ended December 31,
2018

2017

2019

$

$

51,093

$

51,134

$

36,510

23,124

2,998

77,215

$

—
(41)
51,093

$

—

14,624

51,134

As of December 31, 2019, we had an unrecognized tax benefit of $5.4 million related to an uncertain tax position.  The 
unrecognized tax benefit was recorded during 2015 as a direct reduction of the associated deferred tax asset and, if recognized, 
would not materially affect our annual effective tax rate.  The tax benefit from an uncertain tax position will only be recognized 
if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities, based upon the 
technical merits of the position.  We currently do not expect a material change to the uncertain tax position within the next 12 
months.  Our policy is to recognize penalties and interest related to uncertain tax positions in income tax expense; however, 
no such amounts were accrued related to the uncertain tax position as of December 31, 2019.

Significant components of our deferred tax assets and liabilities as of December 31, 2019 and 2018 are as follows:

In thousands
Deferred tax assets

Loss and tax credit carryforwards – state

Business interest expense carryforward

Business credit carryforwards

Unrecognized gain and original issue discount on debt exchange

Accrued liabilities and other reserves

Other

Valuation allowances

Total deferred tax assets

Deferred tax liabilities

Property and equipment

Derivative contracts

Other

Total deferred tax liabilities

Total net deferred tax liability

December 31,

2019

2018

$

52,917

$

24,513

71,555

41,556

29,788

18,725
(77,215)
161,839

52,366

9,049

79,528

73,937

25,231

23,208
(51,093)
212,226

(569,254)
(1,120)
(1,695)
(572,069)
(410,230) $

(492,214)
(23,127)
(6,643)
(521,984)
(309,758)

$

91

 
 
 
 
 
 
Denbury Resources Inc. 
Notes to Consolidated Financial Statements

Our reconciliation of income tax expense computed by applying the U.S. federal statutory rate and the reported effective 

tax rate on income from continuing operations is as follows:

In thousands
Income tax provision calculated using the federal statutory income tax
rate

State income taxes, net of federal income tax benefit

Tax shortfall (windfall) on stock-based compensation deduction

Valuation allowance

Enhanced oil recovery tax credits generated

Re-measurement of deferreds related to federal tax rate change

Other

Year Ended December 31,
2018

2017

2019

$

67,475

$

86,086

$

16,275

7,435

1,912

26,122

—

—

1,408

11,968
(1,565)
(42)
(10,818)
—

1,604

2,764

5,567

5,562
(11,307)
(132,224)
(3,289)
(116,652)

Total income tax expense (benefit)

$

104,352

$

87,233

$

We file consolidated and separate income tax returns in the U.S. federal jurisdiction and in many state jurisdictions.  The 
statutes of limitation for our income tax returns for tax years ending prior to 2016 have lapsed and therefore are not subject 
to examination by respective taxing authorities.  We have not paid any significant interest or penalties associated with our 
income taxes.

Note 8. Stockholders’ Equity

401(k) Plan

We offer a 401(k) plan to which employees may contribute earnings subject to IRS limitations.  We match 100% of an 
employee’s contribution, up to 6% of compensation, as defined by the plan, which is vested immediately.  During 2019, 2018
and 2017, our matching contributions to the 401(k) plan were approximately $6.3 million, $6.2 million and $7.1 million, 
respectively.

Note 9. Stock Compensation

The Amended and Restated 2004 Omnibus Stock and Incentive Plan, amended and restated as of March 28, 2019 (the 
“2004 Plan”), is an incentive plan that provides for the issuance of incentive and non-qualified stock options, restricted stock 
awards, restricted stock units, stock appreciation rights (“SARs”) settled in stock, and performance-based awards to officers, 
employees and directors.  Since the 2004 Plan’s inception, awards covering a total of 61.4 million shares of common stock 
have been authorized for issuance pursuant to the 2004 Plan.  As of December 31, 2019, 13.6 million shares were available 
under the 2004 Plan for future issuance of awards, all of which could be issued in the form of restricted stock or performance-
based  awards.  Our  incentive  compensation  program  is  administered  by  the  Compensation  Committee  of  our  Board  of 
Directors.  The 2004 Plan was last approved by our stockholders in May 2019 and will expire in May 2029.

Stock-based compensation expense is included in “General and administrative expenses” in the Consolidated Statements 
of Operations.  Stock-based compensation associated with our employees involved in exploration and drilling activities is 
capitalized as part of “Oil and natural gas properties” in the Consolidated Balance Sheets.  Our accounting policy is to account 
for forfeitures as they occur.

92

 
 
Denbury Resources Inc. 
Notes to Consolidated Financial Statements

Stock-based compensation costs for the years ended December 31, 2019, 2018 and 2017, are as follows:

In thousands
Stock-based compensation expense included in G&A

Stock-based compensation capitalized

Total cost of stock-based compensation arrangements

Income tax benefit recognized for stock-based compensation
arrangements

SARs

Year Ended December 31,
2018

2017

2019

12,470

4,018

16,488

$

$

11,951

3,487

15,438

$

$

15,154

4,567

19,721

3,118

$

2,988

$

5,759

$

$

$

Prior to January 1, 2016, we granted SARs settled in stock to our employees.  The SARs generally become exercisable 
over  a  three-year  vesting  period,  with  the  specific  terms  of  vesting  determined  at  the  time  of  grant  based  on  guidelines 
established by the Compensation Committee of the Board of Directors.  The SARs expire over terms not to exceed 7 years
from the date of grant, 90 days after termination of employment, 90 days or one year after permanent disability, depending 
on the award, or one year after the death of the optionee.  The SARs were granted with a strike price equal to the fair market 
value at the time of grant, which is generally defined as the closing price on the NYSE on the date of grant.

The following is a summary of our SAR activity:

Number
of Awards

Weighted
Average
Exercise Price

Weighted Average
Remaining
Contractual Life
(in years)

Aggregate
Intrinsic Value
(in thousands)

Outstanding at December 31, 2018

2,500,885

$

10.41

Granted

Exercised

Forfeited

Expired

Outstanding at December 31, 2019

—

—

—
(519,729)
1,981,156

—

—

—

15.29

9.12

Exercisable at end of period

1,981,156

$

9.12

1.5

$

1.5

$

—

—

The following is a summary of the total intrinsic value of SARs exercised and grant-date fair value of SARs vested:

In thousands

Intrinsic value of SARs exercised

Grant-date fair value of SARs vested

Year Ended December 31,

2019

2018

2017

$

— $

—

— $

1,095

—

1,818

As of December 31, 2018, all SARs vested and there was no remaining compensation cost to be recognized in future 
periods related to nonvested share-based SAR compensation arrangements.  There were no exercises of SARs for the years 
ended December 31, 2019, 2018 or 2017.

Restricted Stock 

We  grant  non-performance-based  restricted  stock  to  employees  and  directors  as  part  of  our  long-term  compensation 
program.  Holders of non-performance-based restricted stock awards have the rights of owning non-restricted stock (including 

93

 
 
Denbury Resources Inc. 
Notes to Consolidated Financial Statements

voting  rights)  except  that  the  holders  are  not  entitled  to  delivery  of  a  portion  thereof  until  certain  requirements  are 
met.  Beginning  in  2014,  non-performance-based  restricted  stock  awards  provide  the  holders  with  forfeitable  dividend 
equivalent rights which vests with the underlying shares.  Non-performance-based restricted stock vests over a three-year 
vesting period, with the specific terms of vesting determined at the time of grant.

As of December 31, 2019, there was $17.4 million of unrecognized compensation expense related to nonvested non-
performance-based restricted stock grants.  This unrecognized compensation cost is expected to be recognized over a weighted-
average period of 2.0 years.  The following is a summary of the total vesting date fair value of non-performance-based restricted 
stock:

In thousands

Year Ended December 31,

2019

2018

2017

Fair value of restricted stock vested

$

5,743

$

23,060

$

9,325

A summary of the status of our nonvested non-performance-based restricted stock grants issued, and the changes during 

the year ended December 31, 2019, is presented below:

Nonvested at December 31, 2018

Granted

Vested

Forfeited

Nonvested at December 31, 2019

Performance-Based Equity Awards

Number
of Shares

8,990,578

$

9,630,155
(4,612,265)
(1,601,032)
12,407,436

Weighted
Average
Grant-Date
Fair Value

3.40

1.15

3.20

2.05

1.91

Annually, the Compensation Committee of the Board of Directors grants performance-based equity awards to Denbury’s 
officers.  Performance-based awards generally vest over 1.25 to 3.25 years for awards granted in 2017 and over 3.25 years 
for awards granted in 2018 and 2019.  The number of performance-based shares earned (and eligible to vest) during the 
performance  period  will  depend  upon:  (1)  our  level  of  success  in  achieving  specifically  identified  performance  targets 
(“Performance-Based Operational Awards”) and (2) performance of our stock relative to that of a designated peer group 
(“Performance-Based TSR Awards”).  Generally, one-half of the maximum number of shares that could be earned under the 
performance-based awards will be earned for performance at the designated target levels (100% target vesting levels) or upon 
any earlier change of control, and twice the target number of shares will be earned if the maximum target levels are met (200%
of target vesting levels).  With respect to the performance-based equity awards, any amounts earned above the 100% target 
levels will be payable in cash, rather than in shares of Denbury stock, in order to conserve available shares under the Plan.  If 
performance  is  below  the  designated  minimum  levels,  no  performance-based  shares  will  be  earned.  Performance-Based 
Operational Awards are valued using the fair market value of Denbury stock, and Performance-Based TSR Awards are valued 
using a Monte Carlo simulation.

94

Denbury Resources Inc. 
Notes to Consolidated Financial Statements

As  of  December 31,  2019,  there  was  $5.7  million  of  unrecognized  compensation  expense  related  to  nonvested 
performance-based equity awards.  This unrecognized compensation cost is expected to be recognized over a weighted-average 
period of 1.9 years.  The range of assumptions used in the Monte Carlo simulation valuation approach for Performance-Based 
TSR Awards (presented at the target level) are as follows:

Weighted average fair value of Performance-Based TSR Awards
granted

$

Risk-free interest rate

Expected life

Expected volatility

Dividend yield

Year Ended December 31,

2019

2018

2017

1.95

$

2.27%

2.29

$

2.37%

3.42

1.49%

3.0 years

3.0 years

3.0 years

77.2%

—%

102.9%

—%

94.7%

—%

A summary of the status of the nonvested performance-based equity awards (presented at the target level) during the year 

ended December 31, 2019, is as follows:

Nonvested at December 31, 2018
Granted(1)
Vested(2)
Forfeited

Nonvested at December 31, 2019

Performance-Based
Operational Awards

Performance-Based
TSR Awards

Number
of Awards

Weighted
Average
Grant-Date Fair
Value

Number
of Awards

Weighted
Average
Grant-Date Fair
Value

857,812

$

980,772

—

—

1,838,584

2.43

2.13

—

—

2.27

3,806,116

$

2,027,660
(1,357,778)
—

4,475,998

2.71

1.95

1.78

—

2.65

(1)  Amounts granted reflect the number of performance units granted.  The actual payout of the shares may be between 0%
and 200%, with any amounts earned above the 100% target levels payable in cash, rather than in shares of Denbury stock, 
in order to conserve available shares under the Plan.

(2)  During 2019, the service period lapsed on these TSR performance unit awards.  The lapsed units earned a weighted 
average of 100% of target for each vested TSR performance-based award, representing 1,357,778 aggregate shares of 
common stock issued.  There were no vestings related to Operational performance-based awards during 2019.

The following is a summary of the total vesting date fair value of performance-based equity awards:

In thousands

Year Ended December 31,

2019

2018

2017

Vesting date fair value of Performance-Based Operational Awards

$

— $

Vesting date fair value of Performance-Based TSR Awards

2,783

$

595

542

1,079

227

Note 10. Commodity Derivative Contracts

We do not apply hedge accounting treatment to our oil and natural gas derivative contracts; therefore, the changes in the 
fair values of these instruments are recognized in income in the period of change.  These fair value changes, along with the 
settlements of expired contracts, are shown under “Commodity derivatives expense (income)” in our Consolidated Statements 
of Operations.

Historically, we have entered into various oil and natural gas derivative contracts to provide an economic hedge of our 
exposure to commodity price risk associated with anticipated future oil and natural gas production and to provide more certainty 

95

 
Denbury Resources Inc. 
Notes to Consolidated Financial Statements

to our future cash flows.  We do not hold or issue derivative financial instruments for trading purposes.  Generally, these 
contracts have consisted of various combinations of price floors, collars, three-way collars, fixed-price swaps, fixed-price 
swaps enhanced with a sold put, and basis swaps.  The production that we hedge has varied from year to year depending on 
our levels of debt, financial strength and expectation of future commodity prices.

We  manage  and  control  market  and  counterparty  credit  risk  through  established  internal  control  procedures  that  are 
reviewed on an ongoing basis.  We attempt to minimize credit risk exposure to counterparties through formal credit policies, 
monitoring procedures and diversification, and all of our commodity derivative contracts are with parties that are lenders 
under our Bank Credit Agreement (or affiliates of such lenders).  As of December 31, 2019, all of our outstanding derivative 
contracts were subject to enforceable master netting arrangements whereby payables on those contracts can be offset against 
receivables from separate derivative contracts with the same counterparty.  It is our policy to classify derivative assets and 
liabilities on a gross basis on our balance sheets, even if the contracts are subject to enforceable master netting arrangements.

The following table summarizes our commodity derivative contracts as of December 31, 2019, none of which are classified 

as hedging instruments in accordance with the FASC Derivatives and Hedging topic:

Months

Index Price

Oil Contracts:
2020 Fixed-Price Swaps

Jan – Dec

NYMEX

Argus LLS
Jan – Dec
2020 Three-Way Collars(2)
Jan – June

NYMEX

Jan – June

Argus LLS

July – Dec

NYMEX

July – Dec

Argus LLS

Volume
(Barrels per
day)

$

$

2,000

4,500

23,000

10,000

21,000

8,000

Contract Prices ($/Bbl)

Weighted Average Price

Range(1)

Swap

Sold Put

Floor

Ceiling

60.00 –

60.72 –

61.00

$

60.59

$

64.26

62.29

— $

—

— $

—

—

—

55.00 –

58.00 –

55.00 –

58.00 –

82.65

$

— $

48.25

$

56.95

$

87.10

82.65

87.10

—

—

—

52.85

48.26

52.75

61.52

56.85

61.08

62.83

68.21

62.68

68.39

(1)  Ranges presented for fixed-price swaps represent the lowest and highest fixed prices of all open contracts for the period 
presented.  For three-way collars, ranges represent the lowest floor price and highest ceiling price for all open contracts 
for the period presented.

(2)  A three-way collar is a costless collar contract combined with a sold put feature (at a lower price) with the same counterparty.  
The value received for the sold put is used to enhance the contracted floor and ceiling price of the related collar.  At the 
contract settlement date, (1) if the index price is higher than the ceiling price, we pay the counterparty the difference 
between the index price and ceiling price for the contracted volumes, (2) if the index price is between the floor and ceiling 
price, no settlements occur, (3) if the index price is lower than the floor price but at or above the sold put price, the 
counterparty pays us the difference between the index price and the floor price for the contracted volumes and (4) if the 
index price is lower than the sold put price, the counterparty pays us the difference between the floor price and the sold 
put price for the contracted volumes.

Note 11. Fair Value Measurements

The FASC Fair Value Measurement topic defines fair value as the price that would be received to sell an asset or paid to 
transfer a liability in an orderly transaction between market participants at the measurement date (often referred to as the “exit 
price”).  We utilize market data or assumptions that market participants would use in pricing the asset or liability, including 
assumptions about risk and the risks inherent in the inputs to the valuation technique.  These inputs can be readily observable, 
market corroborated or generally unobservable.  We primarily apply the income approach for recurring fair value measurements 
and endeavor to utilize the best available information.  Accordingly, we utilize valuation techniques that maximize the use of 
observable inputs and minimize the use of unobservable inputs.  We are able to classify fair value balances based on the 
observability of those inputs.  The FASC establishes a fair value hierarchy that prioritizes the inputs used to measure fair 

96

 
Denbury Resources Inc. 
Notes to Consolidated Financial Statements

value.  The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities 
(Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement).  The three levels of the fair 
value hierarchy are as follows:

•  Level 1 – Quoted prices in active markets for identical assets or liabilities as of the reporting date.

•  Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly 
or indirectly observable as of the reported date.  Level 2 includes those financial instruments that are valued using 
models or other valuation methodologies.  Instruments in this category include non-exchange-traded oil derivatives 
that are based on NYMEX pricing and fixed-price swaps that are based on regional pricing other than NYMEX (e.g., 
Light Louisiana Sweet).  Our costless collars and the sold put features of our three-way collars are valued using the 
Black-Scholes model, an industry standard option valuation model that takes into account inputs such as contractual 
prices for the underlying instruments, maturity, quoted forward prices for commodities, interest rates, volatility factors 
and  credit  worthiness,  as  well  as  other  relevant  economic  measures.  Substantially  all  of  these  assumptions  are 
observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are 
supported by observable levels at which transactions are executed in the marketplace.

•  Level 3 – Pricing inputs include significant inputs that are generally less observable.  These inputs may be used with 
internally developed methodologies that result in management’s best estimate of fair value.  As of December 31, 
2019, instruments in this category included non-exchange-traded three-way collars that were based on regional pricing 
other than NYMEX (e.g., Light Louisiana Sweet).  The valuation models utilized for costless collars and three-way 
collars were consistent with the methodologies described above; however, the implied volatilities utilized in the 
valuation of Level 3 instruments were developed using a benchmark, which was considered a significant unobservable 
input. An increase or decrease of 100 basis points in the implied volatility inputs utilized in our fair value measurement 
would result in a change of approximately $300 thousand in the fair value of these instruments as of December 31, 
2019. 

We adjust the valuations from the valuation model for nonperformance risk, using our estimate of the counterparty’s 
credit quality for asset positions and our credit quality for liability positions.  We use multiple sources of third-party credit 
data in determining counterparty nonperformance risk, including credit default swaps.

97

Denbury Resources Inc. 
Notes to Consolidated Financial Statements

The following table sets forth, by level within the fair value hierarchy, our financial assets and liabilities that were accounted 

for at fair value on a recurring basis as of December 31, 2019 and 2018:

In thousands
December 31, 2019

Assets

Oil derivative contracts – current

Total Assets

Liabilities

Oil derivative contracts – current

Total Liabilities

December 31, 2018

Assets

Oil derivative contracts – current

Oil derivative contracts – long-term

Total Assets

Fair Value Measurements Using:

Quoted Prices
in Active
Markets
(Level 1)

Significant
Other
Observable
Inputs
(Level 2)

Significant
Unobservable
Inputs
(Level 3)

Total

$

$

$

$

$

$

— $

— $

8,503

8,503

$

$

3,433

3,433

$

$

11,936

11,936

— $

— $

(6,522) $
(6,522) $

(1,824) $
(1,824) $

(8,346)
(8,346)

— $

—

— $

81,621

2,030

83,651

$

$

11,459

2,165

13,624

$

$

93,080

4,195

97,275

Since we do not apply hedge accounting for our commodity derivative contracts, any gains and losses on our assets and 
liabilities  are  included  in  “Commodity  derivatives  expense  (income)”  in  the  accompanying  Consolidated  Statements  of 
Operations.

Level 3 Fair Value Measurements

The following table summarizes the changes in the fair value of our Level 3 assets and liabilities for the years ended 

December 31, 2019 and 2018:

In thousands

Fair value of Level 3 instruments, beginning of year

Fair value adjustments on commodity derivatives

Receipt on settlements of commodity derivatives

Fair value of Level 3 instruments, end of year

The amount of total gains (losses) for the period included in earnings attributable to the
change in unrealized gains (losses) relating to assets or liabilities still held at the
reporting date

Year Ended December 31,

2019

2018

13,624
(8,205)
(3,810)
1,609

$

$

—

13,624

—

13,624

(556) $

13,624

$

$

$

98

 
 
 
 
 
 
 
 
 
Denbury Resources Inc. 
Notes to Consolidated Financial Statements

We utilize an income approach to value our Level 3 three-way collars.  We obtain and ensure the appropriateness of the 
significant inputs to the calculation, including contractual prices for the underlying instruments, maturity, forward prices for 
commodities, interest rates, volatility factors and credit worthiness, and the fair value estimate is prepared and reviewed on 
a quarterly basis.  The following table details fair value inputs related to implied volatilities utilized in the valuation of our 
Level 3 oil derivative contracts:

Fair Value at
12/31/2019
(in thousands)

Valuation
Technique

Unobservable Input

Volatility Range

Oil derivative
contracts

$

1,609

Discounted
cash flow /
Black-Scholes

Volatility of Light Louisiana Sweet for
settlement periods beginning after December
31, 2019

12.6% – 34.5%

Other Fair Value Measurements

The carrying value of our loans under our Bank Credit Agreement approximate fair value, as they are subject to short-
term floating interest rates that approximate the rates available to us for those periods.  We use a market approach to determine 
the fair value of our fixed-rate long-term debt using observable market data.  The fair values of our senior secured second lien 
notes, convertible senior notes, and senior subordinated notes are based on quoted market prices, which are considered Level 
1 measurements under the fair value hierarchy.  The estimated fair value of the principal amount of our debt as of December 31, 
2019  and  2018,  excluding  pipeline  financing  and  capital  lease  obligations,  was  $1,833.1  million  and  $1,886.1  million, 
respectively.  We have other financial instruments consisting primarily of cash, cash equivalents, U.S. Treasury notes, short-
term receivables and payables that approximate fair value due to the nature of the instrument and the relatively short maturities.

Note 12. Commitments and Contingencies

Commitments

We have entered into long-term commitments to purchase CO2 that are either non-cancelable or cancelable only upon 
the occurrence of specified future events.  The commitments continue for up to 9 years.  The price we will pay for CO2 generally 
varies depending on the amount of CO2 delivered and the price of oil.  Once all commitments have commenced, our annual 
commitment under these contracts could range from $14 million to $33 million per year, assuming a $60 per Bbl NYMEX 
oil price.

We are party to long-term contracts that require us to deliver CO2 to our industrial CO2 customers at various contracted 
prices.    Based  upon  the  maximum  amounts  deliverable  as  stated  in  the  industrial  contracts,  we  estimate  that  we  may  be 
obligated to deliver up to 770 Bcf of CO2 to these customers over the next 15 years.  The maximum volume required in any 
given year is approximately 257 MMcf/d, which we judge to be minor given the size of our Jackson Dome proved CO2 reserves 
at December 31, 2019, our current production capabilities and our projected levels of CO2 usage for our own tertiary flooding 
program.

Litigation

We are involved in various lawsuits, claims and regulatory proceedings incidental to our businesses.  While we currently 
believe that the ultimate outcome of these proceedings, individually and in the aggregate, will not have a material adverse 
effect on our financial position, results of operations or cash flows, litigation is subject to inherent uncertainties.  We accrue 
for losses from litigation and claims if we determine that a loss is probable and the amount can be reasonably estimated.

Riley Ridge Helium Supply Contract Claim

As part of our 2010 and 2011 acquisitions of the Riley Ridge Unit and associated gas processing facility that was under 
construction, the Company assumed a 20-year helium supply contract under which we agreed to supply the helium separated 
from  the  full  well  stream  by  operation  of  the  gas  processing  facility  to  a  third-party  purchaser, APMTG  Helium,  LLC 

99

Denbury Resources Inc. 
Notes to Consolidated Financial Statements

(“APMTG”).  The helium supply contract provides for the delivery of a minimum contracted quantity of helium, with liquidated 
damages payable if specified quantities of helium are not supplied in accordance with the terms of the contract.  The liquidated 
damages are capped at an aggregate of $46.0 million over the term of the contract. 

As the gas processing facility has been shut-in since mid-2014 due to significant technical issues, we have not been able 
to supply helium under the helium supply contract.  In a case filed in November 2014 in the Ninth Judicial District Court of 
Sublette County, Wyoming, APMTG claimed multiple years of liquidated damages for non-delivery of volumes of helium 
specified under the helium supply contract.  The Company claimed that its contractual obligations were excused by virtue of 
events that fall within the force majeure provisions in the helium supply contract.

On March 11, 2019, the trial court entered a final judgment that a force majeure condition did exist, but the Company’s 
performance was excused by the force majeure provisions of the contract for only a 35-day period in 2014, and as a result the 
Company should pay APMTG liquidated damages and interest thereon for those time periods from contract commencement 
to the close of evidence (November 29, 2017).  The Company’s position continues to be that its contractual obligations have 
been and continue to be excused by events that fall within the force majeure provisions of the helium supply contract, so the 
Company has appealed the trial court’s ruling to the Wyoming Supreme Court.  Briefing for the appeal by the Company and 
APMTG is currently expected to be completed in late May or early June, after which oral arguments will be scheduled and 
heard prior to the Wyoming Supreme Court entering its judgment on the appeal.  The timing and outcome of this appeal 
process is currently unpredictable, but at this time is anticipated to extend over the next nine to twelve months.

Absent reversal of the trial court’s ruling on appeal, the Company anticipates total liquidated damages would equal the 
$46.0 million aggregate cap under the helium supply contract plus $5.2 million of associated costs (through December 31, 
2019), for a total of $51.2 million, which is included in “Other liabilities” in our Consolidated Balance Sheets as of December 
31, 2019, and $49.4 million of which was accrued in the fourth quarter of 2018.  The Company currently has a $32.8 million
letter of credit posted as security in this case as part of the appeal process.

Other Contingencies

We are subject to audits for various taxes (income, sales and use, and severance) in the various states in which we operate, 
and from time to time receive assessments for potential taxes that we may owe.  In the past, settlement of these matters has 
not had a material adverse financial impact on us, and currently we have no material assessments for potential taxes.

We are subject to various possible contingencies that arise primarily from interpretation of federal and state laws and 
regulations affecting the oil and natural gas industry.  Such contingencies include differing interpretations as to the prices at 
which oil and natural gas sales may be made, the prices at which royalty owners may be paid for production from their leases, 
environmental issues and other matters.  Although we believe that we have complied with the various laws and regulations, 
administrative rulings and interpretations thereof, adjustments could be required as new interpretations and regulations are 
issued.  In addition, production rates, marketing and environmental matters are subject to regulation by various federal and 
state agencies.

Note 13. Additional Balance Sheet Details

Trade and Other Receivables, Net

In thousands
Trade accounts receivable, net

Federal income tax receivable, net

Commodity derivative settlement receivables

Other receivables

Total

100

December 31,

2019

2018

12,630

$

11,643

2,987

675

2,026

9,037

2,390

3,900

18,318

$

26,970

$

$

Denbury Resources Inc. 
Notes to Consolidated Financial Statements

Note 14. Supplemental Cash Flow Information

Supplemental Cash Flow Information

In thousands
Supplemental cash flow information

Cash paid for interest, expensed

Cash paid for interest, capitalized

Cash paid for interest, treated as a reduction of debt

Cash paid for income taxes

Cash received from income tax refunds

Noncash investing and financing activities

Increase in asset retirement obligations

Increase (decrease) in liabilities for capital expenditures
Conversion of convertible senior notes into common stock

Retirement of treasury stock

Year Ended December 31,
2018

2017

2019

$

72,842

$

50,076

$

36,671

85,303

2,361

9,820

13,560
(17,740)
—

—

37,079

79,606

492

8,280

4,499

14,600
162,004

—

98,261

30,762

50,349

450

13,323

9,565

3,930
—

46,562

101

 
 
 
 
 
 
Denbury Resources Inc. 
Unaudited Supplementary Information

SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES (UNAUDITED)

Costs Incurred

The following table summarizes costs incurred and capitalized in oil and natural gas property acquisition, exploration 
and development activities.  Property acquisition costs are those costs incurred to purchase, lease or otherwise acquire property, 
including both undeveloped leasehold and the purchase of reserves in place.  Exploration costs include costs of identifying 
areas that may warrant examination and examining specific areas that are considered to have prospects containing oil and 
natural gas reserves, including costs of drilling exploratory wells, geological and geophysical costs, and carrying costs on 
undeveloped properties.  Development costs are incurred to obtain access to proved reserves, including the cost of drilling 
development wells, and to provide facilities for extracting, treating, gathering and storing the oil and natural gas, and the cost 
of improved recovery systems.

We capitalize interest on unevaluated oil and natural gas properties that have ongoing development activities.  Included 
in costs incurred in the table below is capitalized interest of $34.1 million, $36.5 million and $30.8 million during the years 
ended  December  31,  2019,  2018  and  2017,  respectively.  Costs  incurred  also  include  new  asset  retirement  obligations 
established, as well as changes to asset retirement obligations resulting from revisions in cost estimates or abandonment 
dates.  Asset retirement obligations included in the table below were $15.2 million, $6.8 million and $5.6 million during the 
years  ended  December  31,  2019,  2018  and  2017,  respectively.  See  Note  4,  Asset  Retirement  Obligations,  for  additional 
information.

Costs incurred in oil and natural gas activities were as follows:

In thousands
Property acquisitions

Proved

Unevaluated

Exploration

Development

Total costs incurred(1)

Year Ended December 31,
2018

2017

2019

$

1,542

$

2,030

$

—

2,575

—

1,030

259,641

338,203

$

263,758

$

341,263

$

75,086

15,748

297

274,325

365,456

(1)  Capitalized general and administrative costs that directly relate to exploration and development activities were $39.5 

million, $37.2 million and $41.1 million for the years ended December 31, 2019, 2018 and 2017, respectively.

102

 
 
 
 
Denbury Resources Inc. 
Unaudited Supplementary Information

Oil and Natural Gas Operating Results

Results of operations from oil and natural gas producing activities, excluding corporate overhead and interest costs, were 

as follows:

In thousands, except per-BOE data
Oil, natural gas, and related product sales

Lease operating expenses

Transportation and marketing expenses

Production and ad valorem taxes

Depletion, depreciation, and amortization
CO2 properties and pipelines depletion and depreciation(1)
Commodity derivatives expense (income)

Net operating income

Income tax provision

Results of operations from oil and natural gas producing activities

Depletion, depreciation, and amortization per BOE

$

$

$

Year Ended December 31,
2018
1,422,589

$

$

2019
1,212,020

477,220

41,810

86,820

161,400
53,120

70,078

321,572
80,393

241,179

10.10

$

$

489,720

43,942

96,589

144,423
48,792
(21,087)
620,210
155,053

465,157

8.77

$

$

2017
1,089,666

447,799

44,064

79,198

134,721
49,241

77,576

257,067
97,685

159,382

8.36

(1)  Represents an allocation of the depletion and depreciation of our CO2 properties and pipelines associated with our tertiary 

oil producing activities.

Oil and Natural Gas Reserves

Net proved oil and natural gas reserve estimates for all years presented were prepared by DeGolyer and MacNaughton, 
independent petroleum engineers located in Dallas, Texas.  These oil and natural gas reserve estimates do not include any 
value for probable or possible reserves that may exist, nor do they include any value for undeveloped acreage.  The reserve 
estimates represent our net revenue interest in our properties.  See Standardized Measure of Discounted Future Net Cash 
Flows and Changes Therein Relating to Proved Oil and Natural Gas Reserves below for a discussion of the effect of the 
different prices on reserve quantities and values.  Operating costs, production and ad valorem taxes, and future development 
costs were based on current costs as of December 31, 2019.

There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting the future rates 
of production and timing of development expenditures.  The following reserve data represents estimates only and should not 
be construed as being exact.  Moreover, the present values should not be construed as the current market value of our oil and 
natural gas reserves or the costs that would be incurred to obtain equivalent reserves.  Estimates of reserves as of year-end 
2019, 2018 and 2017 were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices 
received on a field-by-field basis on the first day of each month within the applicable fiscal 12-month period.  All of our 
reserves are located in the United States.

103

 
Denbury Resources Inc. 
Unaudited Supplementary Information

Estimated Quantities of Proved Reserves

Year Ended December 31,

Oil
(MBbl)

2019

Gas
(MMcf)

Total
(MBOE)

Oil
(MBbl)

2018

Gas
(MMcf)

Total
(MBOE)

Oil
(MBbl)

2017

Gas
(MMcf)

Total
(MBOE)

255,042

43,008

262,210

252,625

42,721

259,745

247,103

44,315

254,489

(6,799)

(15,299)

(9,348)

21,658

977

—

977

2,314

6,115

(157)

22,677

2,288

14,352

1,936

2,541

—

14,775

1,936

(20,685)

(3,375)

(21,248)

(21,364)

(3,962)

(22,024)

(21,320)

(4,135)

(22,009)

—

(2,402)

—

—

—

—

—

—

10,554

(2,402)

(191)

(1,709)

(476)

—

—

—

10,554

—

Balance at beginning
of year

Revisions of previous
estimates
Improved recovery(1)
Production

Acquisition of
minerals in place

Sales of minerals in
place

Balance at end of year

226,133

24,334

230,189

255,042

43,008

262,210

252,625

42,721

259,745

Proved Developed
Reserves – end of year

Proved Undeveloped
Reserves – end of year

202,816

24,333

206,872

222,736

42,912

229,888

222,531

42,435

229,603

23,317

1

23,317

32,306

96

32,322

30,094

286

30,142

(1)  Improved recovery reflects reserve additions that result from the application of secondary recovery methods such as water 
flooding or tertiary recovery methods such as CO2 flooding.  In order to recognize proved tertiary oil reserves, we must 
either have an oil production response to CO2 injections or the field must be analogous to an existing tertiary flood.  The 
magnitude of proved reserves that we can book in any given year will depend on our progress with new floods and the 
timing of the production response.  

Revisions of previous estimates during 2019, 2018, and 2017 primarily reflect changes in commodity prices between 

December 31, 2016 and 2019.

There were no significant additions, excluding acquisitions of minerals in place in 2017, to our oil and natural gas reserves, 
as the magnitude of proved reserves that we can book in any given year depends on our progress with new floods and the 
timing of the production response, and we initiated no new floods in 2019, 2018 or 2017.  Acquisitions of minerals in place 
during 2017 were primarily related to our non-operated working interest acquisitions in Salt Creek and West Yellow Creek 
fields.

Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Natural 
Gas Reserves

The Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Natural 
Gas  Reserves  (“Standardized  Measure”)  does  not  purport  to  present  the  fair  market  value  of  our  oil  and  natural  gas 
properties.  An estimate of such value should consider, among other factors, anticipated future prices of oil and natural gas, 
the probability of recoveries in excess of existing proved reserves, the value of probable reserves and acreage prospects, and 
perhaps different discount rates.  It should be noted that estimates of reserve quantities, especially from new discoveries, are 
inherently imprecise and subject to substantial revision.

Under the Standardized Measure, future cash inflows were estimated by applying a first-day-of-the-month 12-month 
average price to the estimated future production of year-end proved reserves.  These prices have a significant impact on both 
the quantities and value of the proved reserves, as reductions in oil and natural gas prices can cause wells to reach the end of 
their economic life much sooner and can make certain proved undeveloped locations uneconomical, both of which reduce the 

104

 
 
Denbury Resources Inc. 
Unaudited Supplementary Information

reserves.  The following representative oil and natural gas prices were used in the Standardized Measure.  These prices were 
adjusted by field to arrive at the appropriate corporate net price.

Oil (NYMEX price per Bbl)

Natural Gas (Henry Hub price per MMBtu)

2019

December 31,
2018

$

55.69

$

65.56

$

2.58

3.10

2017

51.34

2.98

The changes in the Standardized Measure of discounted future net cash flows in the tables that follow were significantly 
impacted by the movement in first-day-of-the-month average NYMEX oil prices between 2017 and 2019.  The weighted-
average oil prices we receive relative to NYMEX oil prices (our NYMEX oil price differential) utilized were $0.14 per Bbl 
below representative NYMEX oil prices as of December 31, 2019, compared to $0.24 per Bbl below representative NYMEX 
oil prices as of December 31, 2018, and $2.25 per Bbl below representative NYMEX oil prices as of December 31, 2017.

Future cash inflows were reduced by estimated future production, development and abandonment costs based on current 
cost, with no escalation to determine pre-tax cash inflows.  Our future net inflows do not include a reduction for cash previously 
expended on our capitalized CO2 assets that will be consumed in the production of proved tertiary reserves.  Future income 
taxes were computed by applying the statutory tax rate to the excess of net cash inflows over our tax basis in the associated 
proved oil and natural gas properties.  Tax credits and net operating loss carryforwards were also considered in the future 
income tax calculation.  Future net cash inflows after income taxes were discounted using a 10% annual discount rate to arrive 
at the Standardized Measure.

In thousands
Future cash inflows

Future production costs

Future development costs

Future income taxes

Future net cash flows

10% annual discount for estimated timing of cash flows

Standardized measure of discounted future net cash flows

2019
$ 12,494,358
(6,813,610)
(1,434,934)
(586,441)
3,659,373
(1,398,334)
2,261,039

$

December 31,
2018
$ 16,657,988
(8,000,884)
(1,524,476)
(1,186,769)
5,945,859
(2,594,474)
3,351,385

$

2017
$ 12,421,620
(6,623,563)
(1,433,900)
(528,767)
3,835,390
(1,602,961)
2,232,429

$

105

 
 
 
 
Denbury Resources Inc. 
Unaudited Supplementary Information

The following table sets forth an analysis of changes in the Standardized Measure of Discounted Future Net Cash 

Flows from proved oil and natural gas reserves:

In thousands
Beginning of year

$

Sales of oil and natural gas produced, net of production costs

Net changes in prices and production costs
Improved recovery(1)
Previously estimated development costs incurred

Change in future development costs

Revisions due to timing and other

Accretion of discount

Acquisition of minerals in place

Sales of minerals in place

Net change in income taxes

End of year

Year Ended December 31,
2018
2,232,429
(797,132)
1,963,333

$

$

2019
3,351,385
(608,060)
(1,244,859)
5,785

11,536

109,214
(42,240)
10,915

234,434

—

81,024
(35,624)
41,841

367,313

—
(16,892)
319,126

$

2,261,039

$

2017
1,399,217
(523,049)
1,231,649

6,119

89,238

39,926
(71,141)
142,007

77,366

1,281
(372,385)
3,351,385

$

—
(158,903)
2,232,429

(1)  Improved recovery additions result from the application of secondary recovery methods such as water flooding or tertiary 

recovery methods such as CO2 flooding.

SUPPLEMENTAL CO2 DISCLOSURES (UNAUDITED)

Based on engineering reports prepared by DeGolyer and MacNaughton, proved CO2 reserves were estimated as follows:

In MMcf
CO2 reserves

Gulf Coast region(1)
Rocky Mountain region(2)

Year Ended December 31,
2018

2017

2019

4,786,881

1,120,060

4,982,440

1,155,538

5,164,741

1,187,787

(1)  Proved CO2 reserves in the Gulf Coast region consist of reserves from our reservoirs at Jackson Dome and are presented 
on a gross (8/8ths) basis, of which our net revenue interest was approximately 3.8 Tcf, 4.0 Tcf and 4.1 Tcf at December 31, 
2019, 2018 and 2017, respectively, and include reserves dedicated to volumetric production payments of 3.1 Bcf and 7.6 
Bcf at December 31, 2018 and 2017, respectively.

(2)  Proved CO2 reserves in the Rocky Mountain region consist of our overriding royalty interest in LaBarge Field, of which 
our net revenue interest was approximately 1.1 Tcf, 1.2 Tcf and 1.2 Tcf at December 31, 2019, 2018 and 2017, respectively. 

106

 
 
 
 
 
54,616

220,234

23,079

0.05

0.05

150,565
(55,114)
(95,453)

338,355
(210,688)
326,398

174,479

0.39

0.38

136,155
(116,544)
(47,645)

Denbury Resources Inc. 
Unaudited Supplementary Information

UNAUDITED QUARTERLY INFORMATION

In thousands, except per-share data
2019

Revenues and other income

Commodity derivatives expense (income)

Other expenses

Net income (loss)

Net income (loss) per common share:

Basic

Diluted

Cash flow provided by operating activities

Cash flow used in investing activities

Cash flow used in financing activities

2018

March 31

June 30

September 30

December 31

$

310,613

$

305,452

$

83,377

258,508
(25,674)

(0.06)
(0.06)
64,366
(91,801)
(5,207)

$

343,365
(24,760)
156,056

146,692

0.32

0.32

148,634
(67,338)
(81,064)

315,453
(43,155)
248,696

72,862

0.16

0.14

130,578
(55,439)
(64,631)

Revenues and other income

$

353,234

$

387,063

$

394,973

$

Commodity derivatives expense (income)

Other expenses

Net income

Net income per common share:

Basic

Diluted

Cash flow provided by operating activities

Cash flow used in investing activities

Cash flow provided by (used in) financing activities

48,825

250,811

39,578

0.10

0.09

91,627
(51,376)
(40,578)

96,199

251,211

30,222

0.07

0.07

153,999
(83,522)
(69,908)

44,577

256,361

78,419

0.17

0.17

147,904
(81,834)
679

107

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

Denbury Resources Inc.

None.

Item 9A. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

As of the end of the period covered by this report, an evaluation of the effectiveness of the design and operation of our 
disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act) was performed under the supervision 
and with the participation of management, including our Chief Executive Officer and our Chief Financial Officer.  Based on 
that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures 
were effective as of December 31, 2019, to ensure that information that is required to be disclosed in the reports the Company 
files and submits under the Securities Exchange Act of 1934 is recorded; that it is processed, summarized and reported within 
the time periods specified in the SEC’s rules and forms; and that information that is required to be disclosed under the Exchange 
Act is accumulated and communicated to management, including our Chief Executive Officer and our Chief Financial Officer, 
as appropriate to allow timely decisions regarding required disclosure.

Evaluation of Changes in Internal Control over Financial Reporting

Under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief 
Financial Officer, we have determined that, during the fourth quarter of fiscal 2019, there were no changes in our internal 
control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control 
over financial reporting.

Management’s Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting as 
defined in Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934, as amended.  Under the supervision and 
with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer, we assessed 
the effectiveness of our internal control over financial reporting as of the end of the period covered by this report based on 
the framework in “Internal Control – Integrated Framework” (2013) issued by the Committee of Sponsoring Organizations 
of  the  Treadway  Commission.  Based  on  that  assessment,  our  Chief  Executive  Officer  and  our  Chief  Financial  Officer 
concluded  that  our  internal  control  over  financial  reporting  was  effective  to  provide  reasonable  assurance  regarding  the 
reliability of our financial reporting and the preparation of our financial statements for external purposes in accordance with 
U.S. generally accepted accounting principles.

The  effectiveness  of  our  internal  control  over  financial  reporting  as  of  December 31,  2019,  has  been  audited  by 

PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in the report that appears herein.

Important Considerations

The effectiveness of our disclosure controls and procedures and our internal control over financial reporting is subject to 
various inherent limitations, including cost limitations, judgments used in decision making, assumptions about the likelihood 
of future events, the soundness of our systems, the possibility of human error, and the risk of fraud.  Moreover, projections 
of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of 
changes in conditions and the risk that the degree of compliance with policies or procedures may deteriorate over time.  Because 
of these limitations, there can be no assurance that any system of disclosure controls and procedures or internal control over 
financial reporting will be successful in preventing all errors or fraud or in making all material information known in a timely 
manner to the appropriate levels of management.

Item 9B. Other Information

None.

108

 
Denbury Resources Inc.

PART III

Item 10. Directors, Executive Officers and Corporate Governance

Except as disclosed below, information as to Item 10 will be set forth in the Proxy Statement (“Proxy Statement”) for the 
2020 Annual Meeting of Shareholders to be held May 28, 2020 (“Annual Meeting”) and is incorporated herein by reference.

Code of Ethics

We have adopted a Code of Ethics for Senior Financial Officers.  This Code of Ethics, including any amendments or 

waivers, is posted on our website at www.denbury.com.

Item 11. Executive Compensation

Information as to Item 11 will be set forth in the Proxy Statement for the Annual Meeting and is incorporated herein by 

reference.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

Information as to Item 12 will be set forth in the Proxy Statement for the Annual Meeting and is incorporated herein by 

reference.

Item 13. Certain Relationships and Related Transactions, and Director Independence

Information as to Item 13 will be set forth in the Proxy Statement for the Annual Meeting and is incorporated herein by 

reference.

Item 14. Principal Accountant Fees and Services

Information as to Item 14 will be set forth in the Proxy Statement for the Annual Meeting and is incorporated herein by 

reference.

109

Denbury Resources Inc.

PART IV

Item 15. Exhibits and Financial Statement Schedules

Financial Statements and Schedules.  Financial statements and schedules filed as a part of this report are presented on page 
63.  All financial statement schedules have been omitted because they are not applicable, or the required information is presented 
in the financial statements or the notes to consolidated financial statements.

Exhibits.  The following exhibits are included as part of this report.

Exhibit No.
3(a)

Exhibit
Second Restated Certificate of Incorporation of Denbury Resources Inc. filed with the Delaware Secretary 
of State on October 30, 2014 (incorporated by reference to Exhibit 3(a) of Form 10-Q filed by the Company 
on November 7, 2014, File No. 001-12935).

3(b)

3(c)

4(a)

4(b)

4(c)

4(d)

4(e)

4(f)

4(g)

Second Amended and Restated Bylaws of Denbury Resources Inc. as of November 4, 2014 (incorporated 
by reference to Exhibit 3(b) of Form 10-Q filed by the Company on November 7, 2014, File No. 001-12935).

Certificate of Amendment of Second Restated Certificate of Incorporation of Denbury Resources, Inc., 
filed with the Delaware Secretary of State on May 22, 2019 (incorporated by reference to Exhibit 3.1 on 
Form 8-K filed by the Company on May 28, 2019, File No. 001-12935).

Indenture for 6 % Senior Subordinated Notes due 2021, dated as of February 17, 2011, by and among 
Denbury Resources Inc., certain of its subsidiaries, and Wells Fargo Bank, National Association, as Trustee 
(incorporated by reference to Exhibit 4.1 of Form 8-K filed by the Company on February 22, 2011, File 
No. 001-12935).

First Supplemental Indenture for 6 % Senior Subordinated Notes due 2021, dated as of December 31, 
2014, by and among Denbury Resources Inc., certain of its subsidiaries, and Wells Fargo Bank, National 
Association, as Trustee (incorporated by reference to Exhibit 4(x) of Form 10-K filed by the Company on 
February 27, 2015, File No. 001-12935).

Second Supplemental Indenture for 6 % Senior Subordinated Notes due 2021, dated as of September 8, 
2017, by and among Denbury Resources Inc., certain of its subsidiaries, and Wilmington Trust, National 
Association, as Trustee (incorporated by reference to Exhibit 4(a) of Form 10-Q filed by the Company on 
November 7, 2017, File No. 001-12935).

Indenture for 4 % Senior Subordinated Notes due 2023, dated as of February 5, 2013, by and among 
Denbury Resources Inc., certain of its subsidiaries, and Wells Fargo Bank, National Association, as Trustee 
(incorporated by reference to Exhibit 4.1 of Form 8-K filed by the Company on February 5, 2013, File No. 
001-12935).

First Supplemental Indenture for 4 % Senior Subordinated Notes due 2023, dated as of December 31, 
2014, by and among Denbury Resources Inc., certain of its subsidiaries, and Wells Fargo Bank, National 
Association, as Trustee (incorporated by reference to Exhibit 4(z) of Form 10-K filed by the Company on 
February 27, 2015, File No. 001-12935).

Second Supplemental Indenture for 4 % Senior Subordinated Notes due 2023, dated as of September 8, 
2017, by and among Denbury Resources Inc., certain of its subsidiaries, and Wilmington Trust, National 
Association, as Trustee (incorporated by reference to Exhibit 4(b) of Form 10-Q filed by the Company on 
November 7, 2017, File No. 001-12935).

Indenture for 5½% Senior Subordinated Notes due 2022, dated as of April 30, 2014, by and among Denbury 
Resources  Inc.,  certain  of  its  subsidiaries,  and  Wells  Fargo  Bank,  National  Association,  as  Trustee 
(incorporated by reference to Exhibit 4.1 of Form 8-K filed by the Company on May 1, 2014, File No. 
001-12935).

110

Denbury Resources Inc.

Exhibit No.
4(h)

Exhibit
First Supplemental Indenture for 5½% Senior Subordinated Notes due 2022, dated as of December 31, 
2014, by and among Denbury Resources Inc., certain of its subsidiaries, and Wells Fargo Bank, National 
Association, as Trustee (incorporated by reference to Exhibit 4(bb) of Form 10-K filed by the Company on 
February 27, 2015, File No. 001-12935).

4(i)

4(j)

4(k)

4(l)

4(m)

4(n)

4(o)

4(p)

4(q)

4(r)*

10(a)

Second Supplemental Indenture for 5½% Senior Subordinated Notes due 2022, dated as of September 8, 
2017, by and among Denbury Resources Inc., certain of its subsidiaries, and Wilmington Trust, National 
Association, as Trustee (incorporated by reference to Exhibit 4(c) of Form 10-Q filed by the Company on 
November 7, 2017, File No. 001-12935).

Indenture for 9% Senior Secured Second Lien Notes due 2021, dated as of May 10, 2016, by and among 
Denbury Resources Inc., certain of its subsidiaries, and Wilmington Trust, National Association, as Trustee 
and Collateral Trustee (incorporated by reference to Exhibit 4.1 of Form 8-K filed by the Company on May 
11, 2016, File No. 001-12935).

First Supplemental Indenture for 9% Senior Subordinated Notes due 2021, dated as of September 8, 2017, 
by  and  among  Denbury  Resources  Inc.,  certain  of  its  subsidiaries,  and  Wilmington  Trust,  National 
Association, as Trustee and Collateral Trustee (incorporated by reference to Exhibit 4(d) of Form 10-Q 
filed by the Company on November 7, 2017, File No. 001-12935).

Indenture for 9¼% Senior Secured Second Lien Notes due 2022, dated as of December 6, 2017, by and 
among Denbury Resources Inc., certain of its subsidiaries, and Wilmington Trust, National Association, as 
Trustee and Collateral Trustee (incorporated by reference to Exhibit 4.1 of Form 8-K filed by the Company 
on December 12, 2017, File No. 001-12935).

Indenture for 3½% Convertible Senior Notes due 2024, dated as of December 6, 2017, by and among 
Denbury Resources Inc., certain of its subsidiaries, and Wilmington Trust, National Association, as Trustee 
(incorporated by reference to Exhibit 4.3 of Form 8-K filed by the Company on December 12, 2017, File 
No. 001-12935).

Indenture, dated as of January 9, 2018, among the Company, the Subsidiary Guarantors named therein, and 
Wilmington Trust, National Association, as Trustee, with respect to $59,439,000 aggregate principal amount 
of 5% Convertible Senior Notes due 2023 (incorporated by reference to Exhibit 4.1 of Form 8-K filed by 
the Company on January 11, 2018, File No. 001-12935).

Indenture, dated as of August 21, 2018, among the Company, the Subsidiary Guarantors named therein, 
and Wilmington Trust, National Association, as Trustee and Collateral Trustee, with respect to $450,000,000 
aggregate principal amount of 7½% Senior Secured Second Lien Notes due 2024 (incorporated by reference 
to Exhibit 4.1 of Form 8-K filed by the Company on August 22, 2018, File No. 001-12935).

Indenture, dated as of June 19, 2019, among the Company, the Subsidiary Guarantors named therein, and 
Wilmington Trust, National Association, as Trustee and Collateral Trustee, with respect to $528,026,000 
aggregate principal amount of 7¾% Senior Secured Second Lien Notes due 2024 (incorporated by reference 
to Exhibit 4.1 of Form 8-K filed by the Company on June 24, 2019, File No. 001-12935).

Indenture, dated as of June 19, 2019, among the Company, the Subsidiary Guarantors named therein, and 
Wilmington  Trust,  National Association,  as  Trustee,  with  respect  to  $245,548,000  aggregate  principal 
amount of 6 % Convertible Senior Notes due 2024 (incorporated by reference to Exhibit 4.3 of Form 8-
K filed by the Company on June 24, 2019, File No. 001-12935).

Description  of  Denbury  Resources  Inc.  equity  securities  registered  under  Section  12  of  the  Securities 
Exchange Act of 1934, as amended.

Amended and Restated Credit Agreement, dated as of December 9, 2014, by and among Denbury Resources 
Inc., as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent, and the lending institutions party 
thereto (incorporated by reference to Exhibit 10.1 of Form 8-K filed by the Company on December 15, 
2014, File No. 001-12935).

111

Denbury Resources Inc.

Exhibit No.
10(b)

Exhibit
First Amendment to Amended and Restated Credit Agreement, dated as of May 4, 2015, by and among 
Denbury  Resources  Inc.,  as  Borrower,  JPMorgan  Chase  Bank,  N.A.,  as Administrative Agent,  and  the 
financial institutions party thereto (incorporated by reference to Exhibit 10(a) of Form 10-Q filed by the 
Company on May 6, 2015, File No. 001-12935).

10(c)

10(d)

10(e)

10(f)

10(g)

10(h)

10(i)

10(j)

10(k)

10(l)

10(m)

Second Amendment to Amended and Restated Credit Agreement, dated as of February 17, 2016, by and 
among Denbury Resources Inc., as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent, and 
the financial institutions party thereto (incorporated by reference to Exhibit 10.1 of Form 8-K filed by the 
Company on February 23, 2016, File No. 001-12935).

Third Amendment to Amended and Restated Credit Agreement, dated as of April 18, 2016, by and among 
Denbury  Resources  Inc.,  as  Borrower,  JPMorgan  Chase  Bank,  N.A.,  as Administrative Agent,  and  the 
financial institutions party thereto (incorporated by reference to Exhibit 10.1 of Form 8-K filed by the 
Company on April 20, 2016, File No. 001-12935).

Fourth Amendment to Amended and Restated Credit Agreement, dated as of May 3, 2017, by and among 
Denbury  Resources  Inc.,  as  Borrower,  JPMorgan  Chase  Bank,  N.A.,  as Administrative Agent,  and  the 
financial institutions party thereto (incorporated by reference to Exhibit 10.1 of Form 8-K filed by the 
Company on May 4, 2017, File No. 001-12935).

Fifth Amendment to Amended and Restated Credit Agreement, dated as of November 6, 2017, by and 
among Denbury Resources Inc., as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent, and 
the financial institutions party thereto (incorporated by reference to Exhibit 10(b) of Form 10-Q filed by 
the Company on November 7, 2017, File No. 001-12935).

Sixth Amendment to Amended and Restated Credit Agreement, dated as of August 13, 2018, by and among 
Denbury  Resources  Inc.,  as  Borrower,  JPMorgan  Chase  Bank,  N.A.,  as Administrative Agent,  and  the 
financial institutions party thereto (incorporated by reference to Exhibit 10.1 of Form 8-K filed by the 
Company on August 14, 2018, File No. 001-12935).

Seventh Amendment to Amended and Restated Credit Agreement, dated as of May 3, 2019, by and among 
Denbury  Resources  Inc.,  as  Borrower,  JPMorgan  Chase  Bank,  N.A.,  as Administrative Agent,  and  the 
financial institutions party thereto (incorporated by reference to Exhibit 10(a) on Form 10-Q filed by the 
Company on May 9, 2019, File No. 001-12935).

Collateral Trust Agreement, dated as of May 10, 2016, by and among Denbury Resources Inc., certain of 
its subsidiaries, and Wilmington Trust, National Association, as Trustee and Collateral Trustee (incorporated 
by reference to Exhibit 10.1 of Form 8-K filed by the Company on May 11, 2016, File No. 001-12935).

Collateral Trust Joinder, dated as of December 6, 2017, by and among Denbury Resources Inc., certain of 
its subsidiaries, and Wilmington Trust, National Association, as Trustee and Collateral Trustee (incorporated 
by reference to Exhibit 10.1 of Form 8-K filed by the Company on December 12, 2017, File No. 001-12935).

Collateral Trust Joinder, dated as of January 9, 2018, among the Company, the Subsidiary Guarantors named 
therein, Wilmington Trust, National Association, as Trustee, the other parity lien representatives from time 
to time party thereto and Wilmington Trust, National Association, as Collateral Trustee (incorporated by 
reference to Exhibit 10.1 of Form 8-K filed by the Company on January 11, 2018, File No. 001-12935).

Collateral Trust Joinder, dated as of August 21, 2018, between Wilmington Trust, National Association, as 
Trustee, and Wilmington Trust, National Association, as Collateral Trustee (incorporated by reference to 
Exhibit 10.1 of Form 8-K filed by the Company on August 22, 2018, File No. 001-12935).

Intercreditor Agreement, dated as of May 10, 2016, by and between JPMorgan Chase Bank, N.A., as Priority 
Lien Agent, and Wilmington Trust, National Association, as Collateral Trustee (incorporated by reference 
to Exhibit 10.2 of Form 8-K filed by the Company on May 11, 2016, File No. 001-12935).

112

Denbury Resources Inc.

Exhibit No.
10(n)

Exhibit
Priority Confirmation Joinder, dated as of December 6, 2017, by and between JPMorgan Chase Bank, N.A., 
as Priority Lien Agent, and Wilmington Trust, National Association, as Collateral Trustee (incorporated by 
reference to Exhibit 10.2 of Form 8-K filed by the Company on December 12, 2017, File No. 001-12935).

10(o)

10(p)

10(q)

10(r)

10(s)

10(t)

10(u)

10(v)

10(w)**

10(x)**

10(y)**

10(z)**

10(aa)**

Priority Confirmation Joinder, dated as of August 21, 2018, by and between JPMorgan Chase Bank, N.A., 
as Priority Lien Agent, and Wilmington Trust, National Association, as Collateral Trustee (incorporated by 
reference to Exhibit 10.2 of Form 8-K filed by the Company on August 22, 2018, File No. 001-12935).

Priority Confirmation Joinder, dated as of June 19, 2019, by and between JPMorgan Chase Bank, N.A., as 
Priority Lien Agent, and Wilmington Trust, National Association, as Collateral Trustee (incorporated by 
reference to Exhibit 10.2 on Form 8-K filed by the Company on June 24, 2019, File No. 001-12935).

Priority Confirmation Joinder, dated as of July 1, 2019, by and between JPMorgan Chase Bank, N.A., as 
Priority Lien Agent, and Wilmington Trust, National Association, as Collateral Trustee (incorporated by 
reference to Exhibit 10.2 of Form 8-K filed by the Company on July 2, 2019, File No. 001-12935).

Collateral Trust Joinder, dated as of January 9, 2018, among the Company, the Subsidiary Guarantors named 
therein, Wilmington Trust, National Association, as Trustee, the other parity lien representatives from time 
to time party thereto and Wilmington Trust, National Association, as Collateral Trustee (incorporated by 
reference to Exhibit 10.1 of Form 8-K filed by the Company on January 11, 2018, File No. 001-12935).

Collateral Trust Joinder, dated as of June 19, 2019, by and between Wilmington Trust, National Association, 
as Trustee, and Wilmington Trust, National Association, as Collateral Trustee (incorporated by reference 
to Exhibit 10.1 of Form 8-K filed by the Company on June 24, 2019, File No. 001-12935).

Collateral Trust Joinder, dated as of July 1, 2019, by and between Wilmington Trust, National Association, 
as Trustee, and Wilmington Trust, National Association, as Collateral Trustee (incorporated by reference 
to Exhibit 10.1 of Form 8-K filed by the Company on July 2, 2019, File No. 001-12935).

Pipeline Financing Lease Agreement, dated as of May 30, 2008, by and between Genesis NEJD Pipeline, 
LLC, as Lessor, and Denbury Onshore, LLC, as Lessee (incorporated by reference to Exhibit 99.1 of Form 
8-K filed by the Company on June 5, 2008, File No. 001-12935).

Transportation Services Agreement, dated as of May 30, 2008, by and between Genesis Free State Pipeline, 
LLC and Denbury Onshore, LLC (incorporated by reference to Exhibit 99.2 of Form 8-K filed by the 
Company on June 5, 2008, File No. 001-12935).

Form of Indemnification Agreement, by and between Denbury Resources Inc. and its officers and directors 
(incorporated by reference to Exhibit 10(a) of Form 10-Q filed by the Company on November 7, 2017, File 
No. 001-12935).

Denbury Resources Inc. Director Deferred Compensation Plan, as amended and restated effective as of 
December 16, 2015 (incorporated by reference to Exhibit 10(i) of Form 10-K filed by the Company on 
February 26, 2016, File No. 001-12935).

Denbury Resources Inc. Severance Protection Plan, as amended and restated effective as of March 29, 2018 
(incorporated by reference to Exhibit 10(a) of Form 10-Q filed by the Company on May 10, 2018, File No. 
001-12935).

Denbury Resources Inc. 2004 Omnibus Stock and Incentive Plan, as amended and restated effective as of 
March 29, 2018 (incorporated by reference to Exhibit 10(b) of Form 10-Q filed by the Company on May 
10, 2018, File No. 001-12935).

Denbury Resource Inc. 2004 Omnibus Stock and Incentive Plan, as amended and restated effective as of 
March 28, 2019 (incorporate by reference to Exhibit 10.1 on Form 8-K filed by the Company on May 28, 
2019, File No. 001-12935).

113

Denbury Resources Inc.

Exhibit No.
10(bb)**

Exhibit
2004 Form of Restricted Stock Award that vests on retirement for grants to officers pursuant to the 2004 
Omnibus Stock and Incentive Plan for Denbury Resources Inc. (incorporated by reference to Exhibit 10(l) 
of Form 10-K filed by the Company on March 15, 2005, File No. 001-12935).

10(cc)**

10(dd)**

10(ee)**

10(ff)**

10(gg)**

10(hh)**

10(ii)**

10(jj)**

10(kk)**

10(ll)**

2016  Form  of TSR  Performance Award-Equity  under  the  2004  Omnibus  Stock  and  Incentive  Plan  for 
Denbury Resources Inc. (incorporated by reference to Exhibit 10(a) of Form 10-Q filed by the Company 
on May 6, 2016, File No. 001-12935).

2016 Form of TSR Performance Award-Cash under the 2004 Omnibus Stock and Incentive Plan for Denbury 
Resources Inc. (incorporated by reference to Exhibit 10(b) of Form 10-Q filed by the Company on May 6, 
2016, File No. 001-12935).

2016 Form of EBITDAX Performance Award-Equity under the 2004 Omnibus Stock and Incentive Plan 
for  Denbury  Resources  Inc.  (incorporated  by  reference  to  Exhibit  10(mm)  of  Form  10-K  filed  by  the 
Company on March 1, 2017, File No. 001-12935).

2016 Form of EBITDAX Performance Award-Cash under the 2004 Omnibus Stock and Incentive Plan for 
Denbury Resources Inc. (incorporated by reference to Exhibit 10(nn) of Form 10-K filed by the Company 
on March 1, 2017, File No. 001-12935).

2016 Form of Oil Price Change vs. TSR Performance Award, under the 2004 Omnibus Stock and Incentive 
Plan for Denbury Resources Inc. (incorporated by reference to Exhibit 10(e) of Form 10-Q filed by the 
Company on May 6, 2016, File No. 001-12935).

2016 Form of Restricted Share Award to officers pursuant to the 2004 Omnibus Stock and Incentive Plan 
for Denbury Resources Inc. (incorporated by reference to Exhibit 10(pp) of Form 10-K filed by the Company 
on March 1, 2017, File No. 001-12935).

2016 Form of Restricted Stock Award to non-employee directors pursuant to the 2004 Omnibus Stock and 
Incentive Plan for Denbury Resources Inc. (incorporated by reference to Exhibit 10(qq) of Form 10-K filed 
by the Company on March 1, 2017, File No. 001-12935).

2016  Form  of  Deferred  Stock  Unit Award  pursuant  to  the  Director  Deferred  Compensation  Plan  (with 
respect to deferred long-term incentive awards) (incorporated by reference to Exhibit 10(rr) of Form 10-K 
filed by the Company on March 1, 2017, File No. 001-12935).

Standalone Restricted Share New Hire Inducement Award Agreement between Denbury Resources Inc. 
and Christian S. Kendall, dated September 8, 2015 (incorporated by reference to Exhibit 10.1 of Form 8-
K filed by the Company on September 8, 2015, File No. 001-12935).

Restricted Stock Officer Promotion Award pursuant to the 2004 Omnibus Stock and Incentive Plan for 
Denbury Resources Inc. (incorporated by reference to Exhibit 10(tt) of Form 10-K filed by the Company 
on March 1, 2017, File No. 001-12935).

10(mm)**

2017  Form  of TSR  Performance Award-Equity  under  the  2004  Omnibus  Stock  and  Incentive  Plan  for 
Denbury Resources Inc. (incorporated by reference to Exhibit 10(a) of Form 10-Q filed by the Company 
on May 5, 2017, File No. 001-12935).

10(nn)**

10(oo)**

2017 Form of TSR Performance Award-Cash under the 2004 Omnibus Stock and Incentive Plan for Denbury 
Resources Inc. (incorporated by reference to Exhibit 10(b) of Form 10-Q filed by the Company on May 5, 
2017, File No. 001-12935).

2017 Form of EBITDAX Performance Award-Equity under the 2004 Omnibus Stock and Incentive Plan 
for Denbury Resources Inc. (incorporated by reference to Exhibit 10(c) of Form 10-Q filed by the Company 
on May 5, 2017, File No. 001-12935).

114

Denbury Resources Inc.

Exhibit No.
10(pp)**

Exhibit
2017 Form of EBITDAX Performance Award-Cash under the 2004 Omnibus Stock and Incentive Plan for 
Denbury Resources Inc. (incorporated by reference to Exhibit 10(d) of Form 10-Q filed by the Company 
on May 5, 2017, File No. 001-12935).

10(qq)**

10(rr)**

10(ss)**

10(tt)**

10(uu)**

10(vv)**

2017 Form of Oil Change vs. TSR Performance Award under the 2004 Omnibus Stock and Incentive Plan 
for Denbury Resources Inc. (incorporated by reference to Exhibit 10(e) of Form 10-Q filed by the Company 
on May 5, 2017, File No. 001-12935).

2017 Form of Restricted Share Award to officers pursuant to the 2004 Omnibus Stock and Incentive Plan 
for Denbury Resources Inc. (incorporated by reference to Exhibit 10(b) of Form 10-Q filed by the Company 
on August 8, 2017, File No. 001-12935).

2017 Form of Restricted Share Award to non-employee directors pursuant to the 2004 Omnibus Stock and 
Incentive Plan for Denbury Resources Inc. (incorporated by reference to Exhibit 10(c) of Form 10-Q filed 
by the Company on August 8, 2017, File No. 001-12935).

2018 Form of TSR Performance Award-Cash under the 2004 Omnibus Stock and Incentive Plan for Denbury 
Resources Inc. (incorporated by reference to Exhibit 10(c) of Form 10-Q filed by the Company on May 
10, 2018, File No. 001-12935).

2019 Form of TSR Performance Award-Cash under the 2004 Omnibus Stock and Incentive Plan for Denbury 
Resources Inc. (incorporated by reference to Exhibit 10(b) of Form 10-Q filed by the Company on May 9, 
2019, File No. 001-12935).

2018  Form  of TSR  Performance Award-Equity  under  the  2004  Omnibus  Stock  and  Incentive  Plan  for 
Denbury Resources Inc. (incorporated by reference to Exhibit 10(d) of Form 10-Q filed by the Company 
on May 10, 2018, File No. 001-12935).

10(ww)**

2019  Form  of TSR  Performance Award-Equity  under  the  2004  Omnibus  Stock  and  Incentive  Plan  for 
Denbury Resources Inc. (incorporated by reference to Exhibit 10(c) of Form 10-Q filed by the Company 
on May 9, 2019, File No. 001-12935).

10(xx)**

10(yy)**

10(zz)**

10(aaa)**

10(bbb)**

10(ccc)**

2018 Form of Debt-Adjusted Reserves Growth Per Share Performance Award-Cash under the 2004 Omnibus 
Stock and Incentive Plan for Denbury Resources Inc. (incorporated by reference to Exhibit 10(e) of Form 
10-Q filed by the Company on May 10, 2018, File No. 001-12935).

2019 Form of Debt-Adjusted Reserves Growth Per Share Performance Award-Cash under the 2004 Omnibus 
Stock and Incentive Plan for Denbury Resources Inc. (incorporated by reference to Exhibit 10(d) of Form 
10-Q filed by the Company on May 9, 2019, File No. 001-12935).

2018  Form  of  Debt-Adjusted  Reserves  Growth  Per  Share  Performance Award-Equity  under  the  2004 
Omnibus Stock and Incentive Plan for Denbury Resources Inc. (incorporated by reference to Exhibit 10(f) 
of Form 10-Q filed by the Company on May 10, 2018, File No. 001-12935).

2019  Form  of  Debt-Adjusted  Reserves  Growth  Per  Share  Performance Award-Equity  under  the  2004 
Omnibus Stock and Incentive Plan for Denbury Resources Inc. (incorporated by reference to Exhibit 10(e) 
of Form 10-Q filed by the Company on May 9, 2019, File No. 001-12935).

2018 Form of Restricted Share Award to officers pursuant to the 2004 Omnibus Stock and Incentive Plan 
for Denbury Resources Inc. (incorporated by reference to Exhibit 10(a) of Form 10-Q filed by the Company 
on August 9, 2018, File No. 001-12935).

2019 Form of Restricted Stock Unit Award to officers pursuant to the 2004 Omnibus Stock and Incentive 
Plan for Denbury Resources Inc. (incorporated by reference to Exhibit 10(c) of Form 10-Q filed by the 
Company on November 8, 2019, File No. 001-12935).

115

Denbury Resources Inc.

Exhibit No.
10(ddd)**

Exhibit
2018 Form of Restricted Share Award to non-employee directors pursuant to the 2004 Omnibus Stock and 
Incentive Plan for Denbury Resources Inc. (incorporated by reference to Exhibit 10(b) of Form 10-Q filed 
by the Company on August 9, 2018, File No. 001-12935).

21*

23(a)*

23(b)*

31(a)*

31(b)*

32*

99*

List of subsidiaries of Denbury Resources Inc.

Consent of PricewaterhouseCoopers LLP.

Consent of DeGolyer and MacNaughton.

Certification of Chief Executive Officer Pursuant to Section 302 of Sarbanes-Oxley Act of 2002.

Certification of Chief Financial Officer Pursuant to Section 302 of Sarbanes-Oxley Act of 2002.

Certification of Chief Executive Officer and Chief Financial Officer Pursuant to Section 906 of the Sarbanes-
Oxley Act of 2002.

The summary of DeGolyer and MacNaughton’s Report as of December 31, 2019, on oil and gas reserves 
(SEC Case) dated February 14, 2020.

101.INS*

Inline  XBRL  Instance  Document  -  the  instance  document  does  not  appear  in  the  Interactive  Data  File 
because its XBRL tags are embedded within the Inline XBRL document.

101.SCH*

Inline XBRL Taxonomy Extension Schema Document.

101.CAL*

Inline XBRL Taxonomy Extension Calculation Linkbase Document.

101.DEF*

Inline XBRL Taxonomy Extension Definition Linkbase Document.

101.LAB*

Inline XBRL Document Label Linkbase Document.

101.PRE*

Inline XBRL Taxonomy Extension Presentation Linkbase Document.

104

Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).

*   Included herewith.
** Compensation arrangements.

Item 16. Form 10-K Summary

None.

116

Denbury Resources Inc.

SIGNATURES 

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, Denbury Resources Inc. has 

duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

February 26, 2020

/s/ Mark C. Allen

DENBURY RESOURCES INC.

Mark C. Allen
Executive Vice President and Chief Financial Officer

February 26, 2020

/s/ Alan Rhoades

Alan Rhoades
Vice President and Chief Accounting Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following 

persons on behalf of Denbury Resources Inc. and in the capacities and on the dates indicated.

February 26, 2020

/s/ Christian S. Kendall

Christian S. Kendall
Director, President and Chief Executive Officer
(Principal Executive Officer)

February 26, 2020

/s/ Mark C. Allen

Mark C. Allen
Executive Vice President and Chief Financial Officer
(Principal Financial Officer)

February 26, 2020

/s/ Alan Rhoades

Alan Rhoades
Vice President and Chief Accounting Officer
(Principal Accounting Officer)

February 26, 2020

February 26, 2020

February 26, 2020

February 26, 2020

/s/ John P. Dielwart

John P. Dielwart
Director

/s/ Michael B. Decker

Michael B. Decker
Director

/s/ Gregory L. McMichael

Gregory L. McMichael
Director

/s/ Kevin O. Meyers

Kevin O. Meyers
Director

117

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
February 26, 2020

February 26, 2020

February 26, 2020

Denbury Resources Inc.

/s/ Lynn A. Peterson

Lynn A. Peterson
Director

/s/ Randy Stein

Randy Stein
Director

/s/ Mary M. VanDeWeghe

Mary M. VanDeWeghe
Director

118

DESCRIPTION OF CAPITAL STOCK

Exhibit 4r

General

As of January 31, 2020, we are authorized to issue up to 775,000,000 shares of stock, including up to 750,000,000 shares 
of common stock, par value $.001 per share, and up to 25,000,000 shares of preferred stock, par value $.001 per share.  As 
of January 31, 2020, we had 506,382,897 shares of common stock and no shares of preferred stock outstanding.

The following is a summary of the key terms and provisions of our equity securities.  You should refer to the applicable 
provisions of our Second Restated Certificate of Incorporation, bylaws and the Delaware General Corporation Law for a 
complete statement of the terms and rights of our capital stock.

Common Stock

Voting rights.  Each holder of common stock is entitled to one vote per share on each matter submitted to a vote of 
shareholders.  Subject to the rights, if any, of the holders of any series of preferred stock pursuant to applicable law or the 
provision of the certificate of designation creating that series, all voting rights are vested in the holders of shares of common 
stock.  Holders of shares of common stock have non-cumulative voting rights, which means that the holders of more than 
50% of the shares voting for the election of directors can elect 100% of the directors, and the holders of the remaining shares 
voting for the election of directors will not be able to elect any directors.

Dividends.  Dividends may be paid to holders of common stock when, as and if declared by the board of directors (the 
“Board”) out of funds legally available for their payment, subject to the rights of holders of any preferred stock.  We have not 
paid dividends on our common stock since the fourth quarter of 2015 and have no current plans to resume common stock 
dividends.

Rights upon liquidation.  In the event of our voluntary or involuntary liquidation, dissolution or winding up, holders of 
our common stock will be entitled to share equally, in proportion to the number of shares of common stock held by them, in 
any of our assets available for distribution after the payment in full of all debts and distributions and after holders of all series 
of outstanding preferred stock, if any, have received their liquidation preferences in full.

Non-assessable.  All outstanding shares of common stock are fully paid and non-assessable.

Other rights and preferences.  Holders of common stock are not entitled to preemptive, conversion or exchange rights.  
Our common stock has no sinking fund or redemption provisions.  Holders of common stock may act by unanimous written 
consent.

Listing.  Our outstanding shares of common stock are listed on the New York Stock Exchange under the trading symbol 

“DNR.”

Preferred Stock

The  following  description  of  the  terms  of  the  preferred  stock  sets  forth  certain  general  terms  and  provisions  of  our 
authorized preferred stock.  If we offer preferred stock, a description will be filed with the Securities and Exchange Commission 
and the specific designations and rights, as determined by the Board, will be described in such filing, including the following 
terms:

• 
• 
• 

• 
• 

the series, the number of shares offered and the liquidation value of the preferred stock;
the price at which the preferred stock will be issued;
the dividend rate, the dates on which the dividends will be payable and other terms relating to the payment of dividends 
on the preferred stock;
the liquidation preference of the preferred stock;
the voting rights of the preferred stock, if any;

•  whether the preferred stock is redeemable or subject to a sinking fund, and the terms of any such redemption or 

sinking fund;

•  whether  the  preferred  stock  is  convertible  or  exchangeable  for  any  other  securities,  and  the  terms  of  any  such 

conversion; and
any additional rights, preferences, qualifications, limitations and restrictions of the preferred stock.

• 

Except where otherwise set forth in a resolution of the Board providing for the issuance of any series of preferred stock, 
the  number  of  shares  comprising  such  series  may  be  increased  or  decreased  (but  not  below  the  number  of  shares  then 
outstanding) from time to time by like action of the Board.  The shares of preferred stock of any one series shall be identical 
with the other shares in the same series in all respects except as to the dates from and after which dividends thereon shall 
cumulate, if cumulative.

The description of the terms of the preferred stock to be set forth in the applicable filing will not be complete and will be 
subject to and qualified in its entirety by reference to the certificate of designation relating to the applicable series of preferred 
stock.

Undesignated preferred stock may enable the Board to render more difficult or to discourage an attempt to obtain control 
of us by means of a tender offer, proxy contest, merger or otherwise, and to thereby protect the continuity of our management.  
The issuance of shares of preferred stock may adversely affect the rights of holders of our common stock.  For example, any 
preferred stock issued may rank prior to our common stock as to dividend rights, liquidation preference or both, may have 
full or limited voting rights and may be convertible into shares of common stock.  As a result, the issuance of shares of preferred 
stock may discourage bids for our common stock or may otherwise adversely affect the market price of our common stock 
or any existing preferred stock.

Any preferred stock will, when issued, be fully paid and non-assessable.

LIST OF SUBSIDIARIES

Exhibit 21

Name of Subsidiary

Jurisdiction of Organization

Denbury Operating Company

Denbury Onshore, LLC

Denbury Pipeline Holdings, LLC

Denbury Holdings, Inc.

Denbury Green Pipeline – Texas, LLC

Greencore Pipeline Company, LLC

Denbury Gulf Coast Pipelines, LLC

Delaware

Delaware

Delaware

Delaware

Delaware

Delaware

Delaware

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We  hereby  consent  to  the  incorporation  by  reference  in  the  Registration  Statements  on  Form  S-8  (Nos.  333-01006, 
333-27995, 333-55999, 333-70485, 333-39172, 333-39218, 333-39224, 333-63198, 333-90398, 333-106253, 333-116249, 
333-143848, 333-160178, 333-167480, 333-175273, 333-189438, 333-206320, 333-206808, 333-212402, 333-218941 and 
333-232166), Form S-3 (No. 333-222066) and Form S-4 (No. 333-228935) of Denbury Resources Inc. of our report dated 
February 26, 2020 relating to the financial statements and the effectiveness of internal control over financial reporting, which 
appears in this Form 10-K.

Exhibit 23(a)

/s/ PricewaterhouseCoopers LLP

Dallas, Texas

February 26, 2020

Exhibit 23(b)

DeGolyer and MacNaughton
5001 Spring Valley Road
Suite 800 East
Dallas, Texas 75244

February 25, 2020

Denbury Resources Inc.
5320 Legacy Drive
Plano, Texas 75024

Ladies and Gentlemen:

We hereby consent to the use of the name DeGolyer and MacNaughton, to references to DeGolyer and MacNaughton, 
to the inclusion of our report of third party dated February 14, 2020, regarding the proved reserves of Denbury Resources 
Inc., and to the inclusion of information taken from our reports entitled “Report as of December 31, 2019 on Reserves and 
Revenue of Certain Properties with interests attributable to Denbury Resources Inc.,” “Report as of December 31, 2018 on 
Reserves and Revenue of Certain Properties with interests attributable to Denbury Resources Inc. SEC Case,” and “Report 
as of December 31, 2017 on Reserves and Revenue of Certain Properties owned by Denbury Resources Inc. SEC Case” in 
the Annual Report on Form 10-K of Denbury Resources Inc. for the year ended December 31, 2019.

Very truly yours,

/s/ DeGolyer and MacNaughton

DeGolyer and MacNaughton

Texas Registered Engineering Firm F-716

Exhibit 31(a) 

CERTIFICATION UNDER SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Christian S. Kendall, certify that:

1. 

I have reviewed this report on Form 10-K of Denbury Resources Inc. (the registrant);

2.  Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material 
fact necessary to make the statements made, in light of the circumstances under which such statements were made, not 
misleading with respect to the period covered by this report;

3.  Based on my knowledge, the financial statements, and other financial information included in this report, fairly present 
in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the 
periods presented in this report;

4.  The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and 
procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as 
defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)  Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed 
under  our  supervision,  to  ensure  that  material  information  relating  to  the  registrant,  including  its  consolidated 
subsidiaries, is made known to us by others within those entities, particularly during the period in which this report 
is being prepared;

(b)  Designed such internal control over financial reporting, or caused such internal control over financial reporting to 
be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting 
and the preparation of financial statements for external purposes in accordance with generally accepted accounting 
principles;

(c)  Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our 
conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by 
this report based on such evaluation; and

(d)  Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during 
the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that 
has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial 
reporting; and

5.  The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control 
over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or 
persons performing the equivalent functions):

(a)  All significant deficiencies and material weaknesses in the design or operation of internal control over financial 
reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and 
report financial information; and

(b)   Any fraud, whether or not material, that involves management or other employees who have a significant role in the 

registrant’s internal control over financial reporting.

February 26, 2020

/s/ Christian S. Kendall

Christian S. Kendall

Director, President and Chief Executive Officer

Exhibit 31(b) 

CERTIFICATION UNDER SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002 

I, Mark C. Allen, certify that:

1. 

I have reviewed this report on Form 10-K of Denbury Resources Inc. (the registrant);

2.  Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material 
fact necessary to make the statements made, in light of the circumstances under which such statements were made, not 
misleading with respect to the period covered by this report;

3.  Based on my knowledge, the financial statements, and other financial information included in this report, fairly present 
in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the 
periods presented in this report;

4.  The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and 
procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as 
defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)  Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed 
under  our  supervision,  to  ensure  that  material  information  relating  to  the  registrant,  including  its  consolidated 
subsidiaries, is made known to us by others within those entities, particularly during the period in which this report 
is being prepared;

(b)  Designed such internal control over financial reporting, or caused such internal control over financial reporting to 
be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting 
and the preparation of financial statements for external purposes in accordance with generally accepted accounting 
principles;

(c)  Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our 
conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by 
this report based on such evaluation; and

(d)  Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during 
the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that 
has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial 
reporting; and

5.  The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control 
over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or 
persons performing the equivalent functions):

(a)  All significant deficiencies and material weaknesses in the design or operation of internal control over financial 
reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and 
report financial information; and

(b)   Any fraud, whether or not material, that involves management or other employees who have a significant role in the 

registrant’s internal control over financial reporting.

February 26, 2020

/s/ Mark C. Allen

Mark C. Allen

Executive Vice President, Chief Financial Officer,
Treasurer, and Assistant Secretary

Certification of Chief Executive Officer and Chief Financial Officer
Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

Exhibit 32

In connection with the accompanying Annual Report on Form 10-K for the year ended December 31, 2019 (the Report) of 
Denbury Resources Inc. (Denbury) as filed with the Securities and Exchange Commission, each of the undersigned, in his 
capacity as an officer of Denbury, hereby certifies pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of 
the Sarbanes-Oxley Act of 2002, that to his knowledge:

1.  The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as 

amended; and

2. 

information contained in the Report fairly presents, in all material respects, the financial condition and results of operations 
of Denbury.

Dated: February 26, 2020

  /s/ Christian S. Kendall

Dated: February 26, 2020

  Christian S. Kendall
  Director, President and Chief Executive Officer

  /s/ Mark C. Allen

Mark C. Allen

Executive Vice President, Chief Financial Officer,
Treasurer, and Assistant Secretary

 
 
 
 
 
[THIS PAGE INTENTIONALLY LEFT BLANK]

[THIS PAGE INTENTIONALLY LEFT BLANK]

CORPORATE INFORMATION

BOARD OF DIRECTORS

STOCK EXCHANGE LISTING

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(cid:48)(cid:69)(cid:63)(cid:71)(cid:65)(cid:78)(cid:3)(cid:47)(cid:85)(cid:73)(cid:62)(cid:75)(cid:72)(cid:22)(cid:3)(cid:32)(cid:42)(cid:46)

CORPORATE HEADQUARTERS 

Denbury Resources Inc. 

5320 Legacy Drive 

Plano, Texas 75024 

972. 673. 2000 

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STOCK TRANSFER AGENT  
& REGISTRAR

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(cid:63)(cid:65)(cid:78)(cid:80)(cid:69)(cid:152)(cid:63)(cid:61)(cid:80)(cid:65)(cid:79)(cid:8)(cid:3)(cid:80)(cid:78)(cid:61)(cid:74)(cid:79)(cid:66)(cid:65)(cid:78)(cid:3)(cid:76)(cid:78)(cid:75)(cid:63)(cid:65)(cid:64)(cid:81)(cid:78)(cid:65)(cid:79)(cid:3)(cid:75)(cid:78)(cid:3) 
address changes, please contact:

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(cid:44)(cid:10)(cid:43)(cid:10)(cid:3)(cid:30)(cid:75)(cid:84)(cid:3)(cid:13)(cid:15)(cid:16)(cid:14)(cid:8)(cid:3)(cid:30)(cid:78)(cid:65)(cid:74)(cid:80)(cid:83)(cid:75)(cid:75)(cid:64)(cid:8)(cid:3)(cid:42)(cid:53)(cid:3)(cid:13)(cid:13)(cid:19)(cid:13)(cid:19)(cid:3)
866.804.4482 
Email: shareholder@broadridge.com 

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INVESTOR INQUIRIES

(cid:41)(cid:61)(cid:78)(cid:71)(cid:3)(cid:29)(cid:72)(cid:72)(cid:65)(cid:74)
Executive Vice President, Chief Financial

Officer, Treasurer and Assistant Secretary

972. 673. 2000

John Mayer
Director of Investor Relations

972. 673. 2383

Email: john.mayer@denbury.com

ANNUAL CERTIFICATIONS

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(cid:63)(cid:65)(cid:78)(cid:80)(cid:69)(cid:152)(cid:65)(cid:64)(cid:3)(cid:80)(cid:75)(cid:3)(cid:80)(cid:68)(cid:65)(cid:3)(cid:42)(cid:53)(cid:47)(cid:33)(cid:3)(cid:80)(cid:68)(cid:61)(cid:80)(cid:3)(cid:68)(cid:65)(cid:3)(cid:69)(cid:79)(cid:3)(cid:74)(cid:75)(cid:80)(cid:3)(cid:61)(cid:83)(cid:61)(cid:78)(cid:65)(cid:3) 
of any violation by the Company of the 

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standards.

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Chairman of the Board 

Vice-Chairman

ARC Financial Corp.

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Partner

Wingate Partners

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President and 

Chief Executive Officer

Denbury Resources Inc.

Gregory L. McMichael
Independent Consultant

Kevin O. Meyers
Independent Consultant

Lynn A. Peterson
Independent Consultant

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Independent Consultant

Mary M. VanDeWeghe 
Chief Executive Officer and President

Forte Consulting, Inc.

CONTACTING BOARD MEMBERS

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addressing a letter to Denbury Resources 
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by email to secretary@denbury.com

EXECUTIVE OFFICERS

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President and

Chief Executive Officer

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Executive Vice President, Chief Financial

Officer, Treasurer and Assistant Secretary

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Executive Vice President,

Chief Administrative Officer, General

Counsel and Secretary

*

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(cid:258)(cid:374)(cid:374)(cid:381)(cid:437)(cid:374)(cid:272)(cid:286)(cid:3)(cid:410)(cid:346)(cid:286)(cid:3)(cid:282)(cid:286)(cid:272)(cid:349)(cid:400)(cid:349)(cid:381)(cid:374)(cid:3)(cid:410)(cid:381)(cid:3)(cid:282)(cid:381)(cid:3)(cid:400)(cid:381)(cid:3)(cid:349)(cid:374)(cid:3)(cid:258)(cid:282)(cid:448)(cid:258)(cid:374)(cid:272)(cid:286)(cid:853)(cid:3)(cid:258)(cid:367)(cid:381)(cid:374)(cid:336)(cid:3)(cid:449)(cid:349)(cid:410)(cid:346)(cid:3)(cid:282)(cid:286)(cid:410)(cid:258)(cid:349)(cid:367)(cid:400)(cid:3)(cid:381)(cid:374)(cid:3)(cid:346)(cid:381)(cid:449)(cid:3)(cid:410)(cid:381)(cid:3)(cid:393)(cid:258)(cid:396)(cid:415)(cid:272)(cid:349)(cid:393)(cid:258)(cid:410)(cid:286)(cid:856)

FINANCIAL INFORMATION 
REQUESTS

For additional information and to receive 
additional copies of the Annual Report on 

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(cid:33)(cid:84)(cid:63)(cid:68)(cid:61)(cid:74)(cid:67)(cid:65)(cid:3)(cid:31)(cid:75)(cid:73)(cid:73)(cid:69)(cid:79)(cid:79)(cid:69)(cid:75)(cid:74)(cid:3)(cid:4)(cid:140)(cid:47)(cid:33)(cid:31)(cid:141)(cid:5)(cid:3)(cid:75)(cid:78)(cid:3)(cid:80)(cid:75)(cid:3) 
obtain other Denbury public documents,  
please contact:

Denbury Resources Inc.  
Investor Relations 
5320 Legacy Drive  
Plano, Texas 75024 
972.673.2000 
Email: ir@denbury.com

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herein, excluding all exhibits other than our 

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Form 10-K exhibits and any of our corporate 

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upon request. These documents are also 
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ANNUAL MEETING

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be held on Thursday, May 28, 2020, at  
8:00 A.M. CDT at Denbury’s Corporate  
Headquarters, located at 5320 Legacy  
Drive, Plano, Texas 75024*.

LEGAL COUNSEL

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BANKERS

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INDEPENDENT REGISTERED  
PUBLIC ACCOUNTING FIRM

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RESERVE ENGINEERS

DeGolyer and MacNaughton

 
Denbury Resources Inc.
5320 Legacy Drive
Plano, Texas 75024
972.673.2000
www.denbury.com