UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549


FORM 10-Q
(Mark One)
þ
☑   Quarterly report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934


For the quarterly period ended September 30, 20172021
OR


o☐   Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934


For the transition period from _______ to ________


Commission file number: 001-12935
den-20210930_g1.jpg
DENBURY RESOURCES INC.
(Exact name of registrant as specified in its charter)


Delaware20-0467835
(State or other jurisdictionof incorporation or organization)
(I.R.S. EmployerIdentification No.)
Delaware20-0467835
(State or other jurisdictionof incorporation or organization)
5851 Legacy Circle,
(I.R.S. EmployerIdentification No.)
Plano,TX75024
5320 Legacy Drive,
Plano, TX
75024
(Address of principal executive offices)(Zip Code)

Registrant’s telephone number, including area code:(972)673-2000


Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class:Trading Symbol:Name of Each Exchange on Which Registered:
Common Stock $.001 Par ValueDENNew York Stock Exchange

Not applicable
(Former name, former address and former fiscal year, if changed since last report)


Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ☑  No o☐


Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ☑  No o☐


Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filerþ
☐
Accelerated filero
☑
Non-accelerated filero
☐
Smaller reporting companyo
☑
Emerging growth companyo☐
(Do not check if a smaller reporting company)


If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o☐


Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  Yes o☐  No þ☑


Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Section 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court.  Yes ☑   No ☐

The number of shares outstanding of each of the issuer’s classes of common stock,registrant’s Common Stock, $.001 par value, as of the latest practicable date.October 31, 2021, was 50,122,417.


ClassOutstanding at October 31, 2017
Common Stock, $.001 par value402,170,359






Denbury Resources Inc.



Table of Contents


Page
Page
Unaudited Condensed Consolidated Balance Sheets as of September 30, 2017 and December 31, 2016
3
Unaudited Condensed Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2017 and 2016
4
Unaudited Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2017 and 2016
56
Unaudited Condensed Consolidated Statements of Changes in Stockholders’ Equity
7
Notes to Unaudited Condensed Consolidated Financial Statements
68
1519
3238
3439
3540
3540
3641
3641
3641
3641
3742
3843





2


Table of Contents
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements

Denbury Resources Inc.
Unaudited Condensed Consolidated Balance Sheets
(In thousands, except par value and share data)
 September 30, December 31,Successor
 2017 2016September 30, 2021December 31, 2020
AssetsAssetsAssets
Current assets    Current assets  
Cash and cash equivalents $57

$1,606
Cash and cash equivalents$1,783 $518 
Restricted cashRestricted cash— 1,000 
Accrued production receivable 121,346

124,936
Accrued production receivable144,370 91,421 
Trade and other receivables, net 55,318

43,900
Trade and other receivables, net20,867 19,682 
Derivative assets 60

—
Derivative assets— 187 
Other current assets 10,811

10,684
PrepaidsPrepaids10,872 14,038 
Total current assets 187,592

181,126
Total current assets177,892 126,846 
Property and equipment  
  
Property and equipment  
Oil and natural gas properties (using full cost accounting)  
  
Oil and natural gas properties (using full cost accounting)  
Proved properties 10,694,674

10,419,827
Proved properties1,011,545 851,208 
Unevaluated properties 957,060

927,819
Unevaluated properties108,258 85,304 
CO2 properties
 1,190,190

1,188,467
CO2 properties
188,752 188,288 
Pipelines and plants 2,285,092

2,285,812
PipelinesPipelines193,669 133,485 
Other property and equipment 371,114

378,776
Other property and equipment94,763 86,610 
Less accumulated depletion, depreciation, amortization and impairment (11,350,956)
(11,212,327)Less accumulated depletion, depreciation, amortization and impairment(151,844)(41,095)
Net property and equipment 4,147,174

3,988,374
Net property and equipment1,445,143 1,303,800 
Operating lease right-of-use assetsOperating lease right-of-use assets18,253 20,342 
Intangible assets, netIntangible assets, net90,533 97,362 
Other assets 106,163

105,078
Other assets80,444 86,408 
Total assets $4,440,929

$4,274,578
Total assets$1,812,265 $1,634,758 
Liabilities and Stockholders’ EquityLiabilities and Stockholders’ EquityLiabilities and Stockholders’ Equity
Current liabilities  
  
Current liabilities  
Accounts payable and accrued liabilities $183,063

$200,266
Accounts payable and accrued liabilities$211,894 $112,671 
Oil and gas production payable 69,737

80,585
Oil and gas production payable69,717 49,165 
Derivative liabilities 16,746

69,279
Derivative liabilities193,015 53,865 
Current maturities of long-term debt (including future interest payable of $50,490 and $50,349, respectively – see Note 3) 85,002

83,366
Current maturities of long-term debtCurrent maturities of long-term debt17,332 68,008 
Operating lease liabilitiesOperating lease liabilities3,338 1,350 
Total current liabilities 354,548

433,496
Total current liabilities495,296 285,059 
Long-term liabilities  

 
Long-term liabilities  
Long-term debt, net of current portion (including future interest payable of $153,196 and $178,476, respectively – see Note 3) 3,057,439

2,909,732
Long-term debt, net of current portionLong-term debt, net of current portion— 70,000 
Asset retirement obligations 155,749

146,807
Asset retirement obligations243,184 179,338 
Derivative liabilities 4,263
 —
Derivative liabilities16,435 5,087 
Deferred tax liabilities, net 329,724

293,878
Deferred tax liabilities, net1,241 1,274 
Operating lease liabilitiesOperating lease liabilities17,362 19,460 
Other liabilities 21,759

22,217
Other liabilities25,954 20,872 
Total long-term liabilities 3,568,934

3,372,634
Total long-term liabilities304,176 296,031 
Commitments and contingencies (Note 7) 

 

Commitments and contingencies (Note 8)Commitments and contingencies (Note 8)00
Stockholders’ equity    Stockholders’ equity
Preferred stock, $.001 par value, 25,000,000 shares authorized, none issued and outstanding —

—
Common stock, $.001 par value, 600,000,000 shares authorized; 407,622,526 and 402,334,655 shares issued, respectively 408

402
Preferred stock, $.001 par value, 50,000,000 shares authorized, none issued and outstandingPreferred stock, $.001 par value, 50,000,000 shares authorized, none issued and outstanding— — 
Common stock, $.001 par value, 250,000,000 shares authorized; 50,120,895 and 49,999,999 shares issued, respectivelyCommon stock, $.001 par value, 250,000,000 shares authorized; 50,120,895 and 49,999,999 shares issued, respectively50 50 
Paid-in capital in excess of par 2,550,347

2,534,670
Paid-in capital in excess of par1,128,030 1,104,276 
Accumulated deficit (1,982,592)
(2,018,989)Accumulated deficit(115,287)(50,658)
Treasury stock, at cost, 5,382,584 and 3,906,877 shares, respectively (50,716)
(47,635)
Total stockholders’ equity
 517,447

468,448
Total stockholders’ equity
1,012,793 1,053,668 
Total liabilities and stockholders’ equity $4,440,929

$4,274,578
Total liabilities and stockholders’ equity$1,812,265 $1,634,758 
 
See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.



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Table of Contents
Denbury Resources Inc.
Unaudited Condensed Consolidated Statements of Operations
(In thousands, except per shareper-share data)

SuccessorPredecessor
Three Months Ended
Sept. 30, 2021		Period from Sept. 19, 2020 through
Sept. 30, 2020		Period from July 1, 2020 through
Sept. 18, 2020
Revenues and other income  
Oil, natural gas, and related product sales$308,454 $22,321 $153,090 
CO2 sales and transportation fees
12,237 967 6,517 
Oil marketing revenues12,593 151 3,332 
Other income10,451 94 7,097 
Total revenues and other income343,735 23,533 170,036 
Expenses  
Lease operating expenses116,536 11,484 59,708 
Transportation and marketing expenses5,985 1,344 8,155 
CO2 operating and discovery expenses
1,963 242 955 
Taxes other than income24,154 2,073 13,473 
Oil marketing purchases11,940 139 3,288 
General and administrative expenses15,388 1,735 15,013 
Interest, net of amounts capitalized of $1,249, $183 and $4,704, respectively669 334 7,704 
Depletion, depreciation, and amortization37,691 5,283 36,317 
Commodity derivatives expense (income)41,745 (4,035)4,609 
Write-down of oil and natural gas properties— — 261,677 
Reorganization items, net— — 849,980 
Other expenses4,553 2,164 22,084 
Total expenses260,624 20,763 1,282,963 
Income (loss) before income taxes83,111 2,770 (1,112,927)
Income tax provision (benefit)403 12 (303,807)
Net income (loss)$82,708 $2,758 $(809,120)
Net income (loss) per common share
Basic$1.62 $0.06 $(1.63)
Diluted$1.51 $0.06 $(1.63)
Weighted average common shares outstanding  
Basic51,094 50,000 497,398 
Diluted54,714 50,000 497,398 
  Three Months Ended September 30, Nine Months Ended September 30,
  2017 2016 2017 2016
Revenues and other income        
Oil, natural gas, and related product sales $259,030
 $239,930
 $776,088
 $674,401
CO2 sales and transportation fees
 6,590
 6,253
 18,533
 19,147
Interest income and other income 939
 7,802
 8,576
 10,429
Total revenues and other income 266,559
 253,985
 803,197
 703,977
Expenses  
  
  
  
Lease operating expenses 117,768
 106,522
 342,926
 308,988
Marketing and plant operating expenses 11,816
 14,452
 39,758
 40,645
CO2 discovery and operating expenses
 1,346
 861
 2,452
 2,539
Taxes other than income 20,233
 20,401
 62,848
 59,997
General and administrative expenses 27,273
 24,643
 81,303
 81,089
Interest, net of amounts capitalized of $9,416, $6,875, $22,217, and $18,944, respectively 24,546
 24,778
 75,785
 103,007
Depletion, depreciation, and amortization 52,101
 55,012
 154,448
 198,919
Commodity derivatives expense (income) 25,263
 (21,224) (9,712) 99,811
Gain on debt extinguishment —
 (7,826) —
 (115,095)
Write-down of oil and natural gas properties —
 75,521
 —
 810,921
Other expenses —
 —
 —
 36,232
Total expenses 280,346
 293,140
 749,808
 1,627,053
Income (loss) before income taxes (13,787) (39,155) 53,389
 (923,076)
Income tax provision (benefit) (14,229) (14,565) 17,018
 (332,625)
Net income (loss) $442
 $(24,590) $36,371
 $(590,451)
  

      
Net income (loss) per common share 

      
Basic $0.00
 $(0.06) $0.09
 $(1.60)
Diluted $0.00
 $(0.06) $0.09
 $(1.60)

 

 

 

 

Weighted average common shares outstanding  
  
  
  
Basic 392,013
 388,572
 390,448
 368,863
Diluted 393,023
 388,572
 392,625
 368,863


See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.



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Table of Contents
Denbury ResourcesInc.
Unaudited Condensed Consolidated Statements of Operations
(In thousands, except per-share data)
SuccessorPredecessor
Nine Months Ended
Sept. 30, 2021		Period from Sept. 19, 2020 through
Sept. 30, 2020		Period from Jan. 1, 2020 through
Sept. 18, 2020
Revenues and other income   
Oil, natural gas, and related product sales$826,607 $22,321 $492,101 
CO2 sales and transportation fees
31,599 967 21,049 
Oil marketing revenues26,538 151 8,543 
Other income11,518 94 8,419 
Total revenues and other income896,262 23,533 530,112 
Expenses   
Lease operating expenses308,731 11,484 250,271 
Transportation and marketing expenses22,304 1,344 27,164 
CO2 operating and discovery expenses
4,487 242 2,592 
Taxes other than income65,499 2,073 43,531 
Oil marketing purchases25,763 139 8,399 
General and administrative expenses62,821 1,735 48,522 
Interest, net of amounts capitalized of $3,500, $183 and $22,885, respectively3,457 334 48,267 
Depletion, depreciation, and amortization113,522 5,283 188,593 
Commodity derivatives expense (income)330,152 (4,035)(102,032)
Gain on debt extinguishment— — (18,994)
Write-down of oil and natural gas properties14,377 — 996,658 
Reorganization items, net— — 849,980 
Other expenses9,913 2,164 35,868 
Total expenses961,026 20,763 2,378,819 
Income (loss) before income taxes(64,764)2,770 (1,848,707)
Income tax provision (benefit)(135)12 (416,129)
Net income (loss)$(64,629)$2,758 $(1,432,578)
Net income (loss) per common share
Basic$(1.27)$0.06 $(2.89)
Diluted$(1.27)$0.06 $(2.89)
Weighted average common shares outstanding   
Basic50,807 50,000 495,560 
Diluted50,807 50,000 495,560 

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

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Table of Contents
Denbury Inc.
Unaudited Condensed Consolidated Statements of Cash Flows
(In thousands)

SuccessorPredecessor
 Nine Months Ended
Sept. 30, 2021		Period from Sept. 19, 2020 through
Sept. 30, 2020		Period from Jan. 1, 2020 through
Sept. 18, 2020
Cash flows from operating activities  
Net income (loss)$(64,629)$2,758 $(1,432,578)
Adjustments to reconcile net income (loss) to cash flows from operating activities 
Noncash reorganization items, net— — 810,909 
Depletion, depreciation, and amortization113,522 5,283 188,593 
Write-down of oil and natural gas properties14,377 — 996,658 
Deferred income taxes(34)6 (408,869)
Stock-based compensation22,788 — 4,111 
Commodity derivatives expense (income)330,152 (4,035)(102,032)
Receipt (payment) on settlements of commodity derivatives(179,466)6,660 81,396 
Gain on debt extinguishment— — (18,994)
Debt issuance costs and discounts2,055 114 11,571 
Gain from asset sales and other(7,026)— (6,723)
Other, net(2,448)589 7,162 
Changes in assets and liabilities, net of effects from acquisitions  
Accrued production receivable(52,948)38,537 26,575 
Trade and other receivables(1,809)1,366 (22,343)
Other current and long-term assets7,337 705 743 
Accounts payable and accrued liabilities47,484 (7,980)(16,102)
Oil and natural gas production payable23,168 (11,064)(6,792)
Other liabilities(4,966)(29)123 
Net cash provided by operating activities247,557 32,910 113,408 
Cash flows from investing activities  
Oil and natural gas capital expenditures(113,041)(2,125)(99,582)
Acquisitions of oil and natural gas properties(10,927)(1)— 
Pipelines and plants capital expenditures(19,123)(6)(11,601)
Net proceeds from sales of oil and natural gas properties and equipment19,053 880 41,322 
Other5,797 (308)12,747 
Net cash used in investing activities(118,241)(1,560)(57,114)
Cash flows from financing activities  
Bank repayments(697,000)(55,000)(551,000)
Bank borrowings627,000 — 691,000 
Interest payments treated as a reduction of debt— — (46,417)
Cash paid in conjunction with debt repurchases— — (14,171)
Costs of debt financing— — (12,482)
Pipeline financing repayments(50,676)(54)(51,792)
Other(2,426)— (9,363)
Net cash provided by (used in) financing activities(123,102)(55,054)5,775 
Net increase (decrease) in cash, cash equivalents, and restricted cash6,214 (23,704)62,069 
Cash, cash equivalents, and restricted cash at beginning of period42,248 95,114 33,045 
Cash, cash equivalents, and restricted cash at end of period$48,462 $71,410 $95,114 
  Nine Months Ended September 30,
  2017 2016
Cash flows from operating activities
   
Net income (loss)
$36,371
 $(590,451)
Adjustments to reconcile net income (loss) to cash flows from operating activities
   
Depletion, depreciation, and amortization
154,448
 198,919
Write-down of oil and natural gas properties
—
 810,921
Deferred income taxes
35,846
 (331,574)
Stock-based compensation
12,215
 9,682
Commodity derivatives expense (income)
(9,712) 99,811
Receipt (payment) on settlements of commodity derivatives
(38,618) 116,958
Gain on debt extinguishment
—
 (115,095)
Debt issuance costs and discounts
4,801
 15,541
Other, net
(112) (3,271)
Changes in assets and liabilities, net of effects from acquisitions
 
  
Accrued production receivable
3,590
 (2,207)
Trade and other receivables
(13,604) 35,911
Other current and long-term assets
(4,734) (8,434)
Accounts payable and accrued liabilities
(22,736) (57,830)
Oil and natural gas production payable
(10,848) (13,290)
Other liabilities
(4,048) (6,232)
Net cash provided by operating activities
142,859
 159,359


   
Cash flows from investing activities
 
  
Oil and natural gas capital expenditures
(197,982) (176,631)
Acquisitions of oil and natural gas properties
(91,124) (560)
Net proceeds from sales of oil and natural gas properties and equipment 1,412
 47,232
Other
(6,314) (4,048)
Net cash used in investing activities
(294,008) (134,007)


   
Cash flows from financing activities
 
  
Bank repayments
(1,188,000) (1,362,500)
Bank borrowings
1,382,000
 1,447,500
Interest payments on senior secured notes treated as a reduction of debt (25,139) —
Repurchases of senior subordinated notes
—
 (76,708)
Pipeline financing and capital lease debt repayments
(20,523) (21,510)
Other
1,262
 (11,673)
Net cash provided by (used in) financing activities
149,600
 (24,891)
Net increase (decrease) in cash and cash equivalents
(1,549) 461
Cash and cash equivalents at beginning of period
1,606
 2,812
Cash and cash equivalents at end of period
$57
 $3,273


See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.



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Table of Contents
Denbury ResourcesInc.
Unaudited Condensed Consolidated Statements of Changes in Stockholders' Equity
(Dollar amounts in thousands)
Common Stock
($.001 Par Value)		Paid-In
Capital in
Excess of
Par		Retained
Earnings (Accumulated Deficit)		Treasury Stock
(at cost)
SharesAmountSharesAmountTotal Equity
Balance – December 31, 2020 (Successor)49,999,999 $50 $1,104,276 $(50,658)— $— $1,053,668 
Stock-based compensation— — 19,172 — — — 19,172 
Tax withholding for stock compensation plans— — (1,467)— — — (1,467)
Issued pursuant to exercise of warrants5,620 0 195 — — — 195 
Net loss— — — (69,642)— — (69,642)
Balance – March 31, 2021 (Successor)50,005,619 50 1,122,176 (120,300)— — 1,001,926 
Stock-based compensation— — 2,682 — — — 2,682 
Tax withholding for stock compensation plans— — (7)— — — (7)
Issued pursuant to exercise of warrants11,872 0 292 — — — 292 
Net loss— — — (77,695)— — (77,695)
Balance – June 30, 2021 (Successor)50,017,491 50 1,125,143 (197,995)— — 927,198 
Stock-based compensation— — 2,686 — — — 2,686 
Issued pursuant to exercise of warrants103,404 0 201 — — — 201 
Net income— — — 82,708 — — 82,708 
Balance – September 30, 2021 (Successor)50,120,895 $50 $1,128,030 $(115,287)— $— $1,012,793 

Common Stock
($.001 Par Value)		Paid-In
Capital in
Excess of
Par		Retained
Earnings (Accumulated Deficit)		Treasury Stock
(at cost)
SharesAmountSharesAmountTotal Equity
Balance – December 31, 2019 (Predecessor)508,065,495 $508 $2,739,099 $(1,321,314)1,652,771 $(6,034)$1,412,259 
Issued pursuant to stock compensation plans312,516 — — — — — — 
Issued pursuant to directors’ compensation plan37,367 — — — — — — 
Stock-based compensation— — 3,204 — — — 3,204 
Tax withholding for stock compensation plans— — — — 175,673 (34)(34)
Net income— — — 74,016 — — 74,016 
Balance – March 31, 2020 (Predecessor)508,415,378 508 2,742,303 (1,247,298)1,828,444 (6,068)1,489,445 
Canceled pursuant to stock compensation plans(6,218,868)(6)6 — — — — 
Issued pursuant to notes conversion7,357,450 8 11,453 — — — 11,461 
Stock-based compensation— — 987 — — — 987 
Net loss— — — (697,474)— — (697,474)
Balance – June 30, 2020 (Predecessor)509,553,960 510 2,754,749 (1,944,772)1,828,444 (6,068)804,419 
Canceled pursuant to stock compensation plans(95,016)— — — — — — 
Issued pursuant to notes conversion14,800 — 40 — — — 40 
Stock-based compensation— — 10,126 — — — 10,126 
Tax withholding for stock compensation plans— — — — 567,189 (134)(134)
Net loss— — — (809,120)— — (809,120)
Cancellation of Predecessor equity(509,473,744)(510)(2,764,915)2,753,892 (2,395,633)6,202 (5,331)
Issuance of Successor equity49,999,999 50 1,095,369 — — — 1,095,419 
Balance – September 18, 2020 (Predecessor)49,999,999 $50 $1,095,369 $— — $— $1,095,419 
Balance – September 19, 2020 (Successor)49,999,999 $50 $1,095,369 $— — $— $1,095,419 
Net income— — — 2,758 — — 2,758 
Balance – September 30, 2020 (Successor)49,999,999 50 1,095,369 2,758 — — 1,098,177 
Stock-based compensation— — 8,907 — — — 8,907 
Net loss— — — (53,416)— — (53,416)
Balance – December 31, 2020 (Successor)49,999,999 $50 $1,104,276 $(50,658)— $— $1,053,668 

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

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Table of Contents
Denbury Inc.
Notes to Unaudited Condensed Consolidated Financial Statements



Note 1. Basis of Presentation


Organization and Nature of Operations


Denbury Resources Inc. (“Denbury,” “Company” or the “Successor”), a Delaware corporation, is an independent oil and natural gasenergy company with operations focused in two key operating areas: the Gulf Coast and Rocky Mountain regions. Our goalThe Company 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 todifferentiated by its focus on CO2 enhanced oil recovery (“EOR”) and the emerging carbon capture, use, and storage (“CCUS”) industry, supported by the Company’s CO2 EOR technical and operational expertise and its extensive CO2 pipeline infrastructure.The utilization of captured industrial-sourced CO2 in EOR significantly reduces the carbon footprint of the oil that Denbury produces, making the Company’s scope 1 and 2 CO2 emissions negative today, with a goal to also fully offset scope 3 CO2 emissions within this decade, primarily through increasing the amount of captured industrial-sourced CO2 used in its operations.


Emergence from Voluntary Reorganization Under Chapter 11 of the Bankruptcy Code

On July 30, 2020 (the “Petition Date”), Denbury Resources Inc. (the “Predecessor”) and its subsidiaries filed petitions for reorganization in a “prepackaged” voluntary bankruptcy (the “Chapter 11 Restructuring”) under chapter 11 of the Bankruptcy Code in the United States Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”) under the caption “In re Denbury Resources Inc., et al., Case No. 20-33801”. On September 2, 2020, the Bankruptcy Court entered an order (the “Confirmation Order”) confirming the prepackaged joint plan of reorganization (the “Plan”) and approving the Disclosure Statement, and on September 18, 2020 (the “Emergence Date”), the Plan became effective in accordance with its terms and the Company emerged from Chapter 11 as the successor reporting company of Denbury Resources Inc. On April 23, 2021, the Bankruptcy Court entered a final decree closing the Chapter 11 case captioned “In re Denbury Resources Inc., et al., Case No. 20-33801”; therefore, we have no remaining obligations related to this reorganization.

Upon emergence from bankruptcy, we met the criteria and were required to adopt fresh start accounting in accordance with Financial Accounting Standards Board Codification (“FASC”) Topic 852, Reorganizations. Fresh start accounting requires that new fair values be established for the Company’s assets, liabilities and equity as of the Emergence Date, and therefore certain values and operational results of the condensed consolidated financial statements subsequent to September 18, 2020 are not comparable to those in the Company’s condensed consolidated financial statements prior to, and including September 18, 2020. The Emergence Date fair values of the Successor’s assets and liabilities differ materially from their recorded values as reflected on the historical balance sheets of the Predecessor contained in periodic reports previously filed with the Securities and Exchange Commission. References to “Successor” relate to the financial position and results of operations of the Company subsequent to September 18, 2020, and references to “Predecessor” relate to the financial position and results of operations of the Company prior to, and including, September 18, 2020.

Reorganization Items, Net

Reorganization items, net, include (i) expenses incurred during the Chapter 11 Restructuring subsequent to the Petition Date as a direct result of the Plan, (ii) gains or losses from liabilities settled and (iii) fresh start accounting adjustments and are recorded in “Reorganization items, net” in our Unaudited Condensed Consolidated Statements of Operations. Professional service provider charges associated with our restructuring that were incurred before the Petition Date and after the Emergence Date are recorded in “Other expenses” in our Unaudited Condensed Consolidated Statements of Operations.


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Denbury Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
The following table summarizes the losses (gains) on reorganization items, net:
Predecessor
In thousandsPeriod from July 1, 2020 through
Sept. 18, 2020
Gain on settlement of liabilities subject to compromise$(1,024,864)
Fresh start accounting adjustments1,834,423 
Professional service provider fees and other expenses11,267 
Success fees for professional service providers9,700 
Loss on rejected contracts and leases10,989 
Valuation adjustments to debt classified as subject to compromise757 
Debtor-in-possession credit agreement fees3,107 
Acceleration of Predecessor stock compensation expense4,601 
Total reorganization items, net$849,980 

Interim Financial Statements


The accompanying unaudited condensed consolidated financial statements of Denbury Resources Inc. and its subsidiaries have been prepared in accordance with the rules and regulations of the Securities and Exchange Commission (“SEC”) and do not include all of the information and footnotes required by accounting principles generally accepted in the United States for complete financial statements.  These financial statements and the notes thereto should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 20162020 (the “Form 10-K”).  Unless indicated otherwise or the context requires, the terms “we,” “our,” “us,” “Company” or “Denbury,” refer to Denbury Resources Inc. and its subsidiaries.


Accounting measurements at interim dates inherently involve greater reliance on estimates than at year end, and the results of operations for the interim periods shown in this report are not necessarily indicative of results to be expected for the year.  In management’s opinion, the accompanying unaudited condensed consolidated financial statements include all adjustments of a normal recurring nature necessary for a fair statementpresentation of our consolidated financial position as of September 30, 2017,2021 (Successor); our consolidated results of operations and consolidated statement of changes in stockholders’ equity for the three and nine months endedSeptember 30, 20172021 (Successor), for the period September 19, 2020 through September 30, 2020 (Successor), for the period July 1, 2020 through September 18, 2020 (Predecessor) and 2016,January 1, 2020 through September 18, 2020 (Predecessor); and our consolidated cash flows for the nine months ended September 30, 20172021 (Successor), for the period September 19, 2020 through September 30, 2020 (Successor) and 2016for the period January 1, 2020 through September 18, 2020 (Predecessor). Upon the adoption of fresh start accounting, the Company’s assets and liabilities were recorded at their fair values as of the fresh start reporting date. As a result of the adoption of fresh start accounting, certain values and operational results of the Company’s condensed consolidated financial statements subsequent to September 18, 2020 are not comparable to those in its condensed consolidated financial statements prior to, and including September 18, 2020.


Reclassifications


Certain prior period amounts have been reclassified to conform to the current year presentation. Such reclassifications had no impact on our reported net income (loss), current assets, total assets, current liabilities, total liabilities or stockholders’ equity.


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Denbury Inc.
Notes to Unaudited Condensed Consolidated Financial Statements

Cash, Cash Equivalents, and Restricted Cash

The following table provides a reconciliation of cash, cash equivalents, and restricted cash as reported within the Unaudited Condensed Consolidated Balance Sheets to “Cash, cash equivalents, and restricted cash at end of period” as reported within the Unaudited Condensed Consolidated Statements of Cash Flows:
Successor
In thousandsSeptember 30, 2021December 31, 2020
Cash and cash equivalents$1,783 $518 
Restricted cash, current— 1,000 
Restricted cash included in other assets46,679 40,730 
Total cash, cash equivalents, and restricted cash shown in the Unaudited Condensed Consolidated Statements of Cash Flows$48,462 $42,248 

Restricted cash included in other assets in the table above consists of escrow accounts that are legally restricted for certain of our asset retirement obligations, and are included in “Other assets” in the accompanying Unaudited Condensed Consolidated Balance Sheets.

Net Income (Loss) per Common Share


Basic net income (loss) per common share is computed by dividing the net income (loss) attributable to common stockholders by the weighted average number of shares of common stock outstanding during the period.  Diluted net income (loss) per common share is calculated in the same manner but includes the impact of potentially dilutive securities.  Potentially dilutive securities during the Successor periods consist of nonvested restricted stock units and outstanding series A and series B warrants, and during the Predecessor periods consisted of nonvested restricted stock, nonvested performance-based equity awards.awards, and convertible senior notes. For each of the three and nine months ended September 30, 20172021 and 2016,for the periods September 19, 2020 through September 30, 2020 (Successor), July 1, 2020 through September 18, 2020 (Predecessor) and January 1, 2020 through September 18, 2020 (Predecessor), there were no adjustments to net income (loss) for purposes of calculating basic and diluted net income (loss) per common share.


The following is a reconciliation oftable reconciles the weighted average shares used in the basic and diluted net income (loss) per common share calculations for the periods indicated:
SuccessorPredecessor
In thousandsThree Months Ended
Sept. 30, 2021		Period from Sept. 19, 2020 through
Sept. 30, 2020		Period from July 1, 2020 through
Sept. 18, 2020
Weighted average common shares outstanding – basic51,094 50,000 497,398 
Effect of potentially dilutive securities
Restricted stock units908 — — 
Warrants2,712 — — 
Weighted average common shares outstanding – diluted54,714 50,000 497,398 
  Three Months Ended Nine Months Ended
  September 30, September 30,
In thousands 2017 2016 2017 2016
Basic weighted average common shares outstanding 392,013
 388,572
 390,448
 368,863
Potentially dilutive securities  
  
  
  
Restricted stock and performance-based equity awards 1,010
 —
 2,177
 —
Diluted weighted average common shares outstanding 393,023
 388,572
 392,625
 368,863


BasicFor the nine months ended September 30, 2021 and for each of the periods from July 1, 2020 through September 18, 2020 (Predecessor) and from January 1, 2020 through September 18, 2020 (Predecessor), the 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 earnings per share and diluted earnings per share were the same, since the Company generated a net loss during those periods. The weighted average diluted shares outstanding would have been 53.4 million for the nine months ended September 30, 2021, 580.0 million for the period July 1, 2020 through September 18, 2020, and 584.4 million for the period January 1, 2020 through September 18, 2020 if the Company had recognized net income (loss) per common share (although time-vesting restricted stock is issued and outstanding upon grant). For purposes of calculating diluted weighted average common shares during those periods.




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Denbury Resources Inc.
Notes to Unaudited Condensed Consolidated Financial Statements

Basic weighted average common shares during the Successor periods includes 987,987 and 767,228 performance stock units during the three and nine months ended September 30, 2017,2021, respectively, with vesting parameters tied to the Company’s common stock trading prices and which became fully vested on March 3, 2021. Although the performance measures for vesting of these awards have been achieved, the shares underlying these awards are not currently outstanding as actual delivery of the shares is not scheduled to occur until after the end of the performance period, December 4, 2023. Basic weighted average common shares includes time-vesting restricted stock units during the Successor periods and restricted stock during the Predecessor periods that vested during the periods.

For purposes of calculating diluted weighted average common shares for the three months ended September 30, 2021, the nonvested restricted stock units and performance-based equity awardswarrants are included in the computation using the treasury stock method with the deemed proceeds equal to the average unrecognized compensation during the period.method.


The following outstanding securities could potentially dilute earnings per share in the future, but were excluded from the computation of diluted net income (loss)loss per share for the nine months ended September 30, 2021 and from diluted net income per share for the period September 19, 2020 to September 30, 2020, as their effect would have been antidilutive:antidilutive, as of the respective dates:
Successor
In thousandsSeptember 30, 2021September 30, 2020
Restricted stock units1,255 — 
Warrants5,314 5,526 
  Three Months Ended Nine Months Ended
  September 30, September 30,
In thousands 2017 2016 2017 2016
Stock appreciation rights 4,551
 6,091
 4,793
 6,590
Restricted stock and performance-based equity awards 9,891
 9,178
 6,259
 6,053


For the nine months ended September 30, 2021 Successor period, the Company’s restricted stock units and series A and series B warrants were antidilutive based on the Company’s net loss position for the period. Despite the Company’s net income position for the period September 19, 2020 to September 30, 2020, the Company’s series A and series B warrants were antidilutive because the Company’s stock price during the period was lower than the warrant exercise prices. At September 30, 2021, the Company had approximately 5.3 million warrants outstanding that can be exercised for shares of the Successor’s common stock, at an exercise price of $32.59 per share for the 2.6 million series A warrants outstanding and at an exercise price of $35.41 per share for the 2.7 million series B warrants outstanding. The series A warrants are exercisable until September 18, 2025, and the series B warrants are exercisable until September 18, 2023, at which time the warrants expire. The warrants were issued pursuant to the Plan to holders of the Predecessor’s convertible senior notes, senior subordinated notes, and equity. As of September 30, 2021, 8,390 series A warrants and 203,501 series B warrants had been exercised. The warrants may be exercised for cash or on a cashless basis. If warrants are exercised on a cashless basis, the amount of dilution will be less than 5.3 million shares.
2016
Oil and Natural Gas Properties

Unevaluated Costs. Under full cost accounting, 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 as these 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 development activities. In the first quarter of 2020 Predecessor period, given the significant declines in NYMEX oil prices in March and April 2020, we reassessed our development plans and transferred $244.9 million of our unevaluated costs to the full cost amortization base. Upon emergence from bankruptcy, the Company adopted fresh start accounting which resulted in our oil and natural gas properties, including unevaluated properties, being recorded at their fair values at the Emergence Date.

Write-Down of Oil and Natural Gas Properties

Properties.Under full cost accounting, rules, wethe net capitalized costs of oil and natural gas properties are required each quarterlimited to perform athe lower of unamortized cost or the cost center ceiling. The cost center ceiling test calculation. Under these rules,is defined as (1) the full cost ceilingpresent value is calculated usingof 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 CO2 capital 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

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Denbury Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
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 recognized a full cost pool ceiling test write-down of $14.4 million during the three months ended asMarch 31, 2021, with first-day-of-the-month NYMEX oil prices for the preceding 12 months averaging $36.40 per Bbl, after adjustments for market differentials and transportation expenses by field. The write-down was primarily a result of each quarterly reporting period. the March 2021 acquisition of Wyoming property interests (see Note 2, Acquisition and Divestitures) which was recorded based on a valuation that utilized NYMEX strip oil prices at the acquisition date, which were significantly higher than the average first-day-of-the-month NYMEX oil prices used to value the cost ceiling.

The falling prices in 2016, relative to 2015 prices, led to our recognizingPredecessor also recognized full cost pool ceiling test write-downs of $75.5$261.7 million $479.4 million, and $256.0during the period from July 1, 2020 through September 18, 2020, $662.4 million during the three months ended June 30, 2020 and $72.5 million during the three months ended March 31, 2020. We did not record any ceiling test write-downs during the Successor periods from September 19, 2020 through September 30, 2020, for the three months ended June 30, and March 31, 2016, respectively. We have not recorded a ceiling test write-down during2021, or for the first ninethree months of 2017.ended September 30, 2021.


Recent Accounting Pronouncements


Business Combinations.Recently Adopted

Income Taxes. In January 2017,December 2019, the Financial Accounting Standards Board (“FASB”) issued ASU 2019-12, Income Taxes (Topic 740) – Simplifying the Accounting Standards Update (“ASU”) 2017-01, Business Combinations: Clarifying the Definition of a Businessfor Income Taxes (“ASU 2017-01”2019-12”). ASU 2017-01 clarifies the definition of a business with theThe objective of adding guidanceASU 2019-12 is to assist entities with evaluating whether transactions should be accountedsimplify the accounting for as acquisitions (or disposals)income taxes by removing certain exceptions to the general principles in Topic 740 and to provide more consistent application to improve the comparability of assets or businesses.financial statements. Effective January 1, 2017,2021, we adopted ASU 2017-01. See Note 2, Asset Acquisition and Assets Held for Sale, for discussion2019-02. The implementation of the impact ASU 2017-01 had on our current period consolidated financial statements.

Cash Flows. In November 2016, the FASB issued ASU 2016-18, Statement of Cash Flows (“ASU 2016-18”). ASU 2016-18 addresses the diversity that exists in the classification and presentation of changes in restricted cash on the statement of cash flows, and requires that a statement of cash flows explain the change in total cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Therefore, entities will no longer present transfers between cash and cash equivalents and restricted cash and restricted cash equivalents in the statement of cash flows. This guidance is effective for fiscal years beginning after December 15, 2017, including interim periods within the year of adoption, with early adoption permitted. Management doesthis standard did not currently expect that the adoption of ASU 2016-18 will have a material impact on our consolidated financial statements other thanand related footnote disclosures.

Note 2. Acquisition and Divestitures

Acquisition of Wyoming CO2 EOR Fields

On March 3, 2021, we acquired a nearly 100% working interest (approximately 83% net revenue interest) in the inclusionBig Sand Draw and Beaver Creek EOR fields located in Wyoming from a subsidiary of restrictedDevon Energy Corporation for $10.9 million cash (after final closing adjustments), including surface facilities and a 46-mile CO2 transportation pipeline to the acquired fields. The acquisition agreement provides for us to make two contingent cash payments, one in January 2022 and one in January 2023, of $4 million each, conditioned on NYMEX WTI oil prices averaging at least $50 per Bbl during each of 2021 and 2022. The fair value of the contingent consideration on the acquisition date was $5.3 million, and as of September 30, 2021, the fair value of the contingent consideration recorded on our consolidated statementsUnaudited Condensed Consolidated Balance Sheets was $7.4 million. The $2.1 million increase at September 30, 2021 from the March 2021 acquisition date fair value was the result of cash flows.higher NYMEX WTI oil prices and was recorded to “Other expenses” in our Unaudited Condensed Consolidated Statements of Operations.


Leases. In February 2016, the FASB issued ASU 2016-02, Leases (“ASU 2016-02”). ASU 2016-02 amends the guidance for lease accountingThe fair values allocated to require leaseour assets acquired and liabilities assumed for the acquisition were based on significant inputs not observable in the market and considered level 3 inputs. The fair value of the assets acquired and liabilities assumed was finalized during the third quarter of 2021, after consideration of final closing adjustments and evaluation of reserves and

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Denbury Inc.
Notes to be recognizedUnaudited Condensed Consolidated Financial Statements
liabilities assumed. The following table presents a summary of the fair value of assets acquired and liabilities assumed in the acquisition:

In thousands
Consideration:
Cash consideration$10,906 
Less: Fair value of assets acquired and liabilities assumed:
Proved oil and natural gas properties60,101 
Other property and equipment1,685 
Asset retirement obligations(39,794)
Contingent consideration(5,320)
Other liabilities(5,766)
Fair value of net assets acquired$10,906 

Divestitures

Hartzog Draw Deep Mineral Rights

On June 30, 2021, we closed the sale of undeveloped, unconventional deep mineral rights in Hartzog Draw Field in Wyoming. The cash proceeds of $18 million were recorded to “Proved properties” in our Unaudited Condensed Consolidated Balance Sheets. The proceeds reduced our full cost pool; therefore, no gain or loss was recorded on the balance sheet, along with additional disclosures regarding key leasing arrangements. The amendments in this ASU are effective for fiscal years beginning after December 15, 2018,transaction, and interim periods within those fiscal years, and early adoption is permitted. Entities must adopt the standard using a modified retrospective transition and apply the guidance to the earliest comparative period presented, with certain practical expedients that entities may elect to apply. Management is currently assessing thesale had no impact the adoption of ASU 2016-02 will have on our consolidated financial statements.production or reserves.


Houston Area Land Sales

During the third quarter of 2021, we completed sales of a portion of certain non-producing surface acreage in the Houston area. We recognized cash proceeds of $11.8 million from the sales and recorded a $7.0 million gain to “Other income” in our Unaudited Condensed Consolidated Statements of Operations.

Note 3. Revenue Recognition. In May 2014, the FASB issued ASU 2014-09, Recognition

We record revenue in accordance with FASC Topic 606, Revenue from Contracts with Customers (“ASU 2014-09”). ASU 2014-09 amends the guidance for revenue recognition to replace numerous, industry-specific requirements. The core principle of the ASUFASC 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. The ASU implementsOnce 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 received within a five-step processmonth following product delivery, and for customer contractnatural gas and NGL contracts, payment is generally received within two months following delivery. Timing of revenue recognition that focusesmay differ from the timing of invoicing to customers; however, as the right to consideration after delivery is unconditional based on transferonly the passage of time before payment of the consideration is due, upon delivery we record a receivable in “Accrued production receivable” in our Unaudited Condensed Consolidated Balance Sheets. From time to time, the Company enters into marketing arrangements for the purchase and sale of crude oil for third parties. Revenues and expenses from these transactions are presented on a gross basis, as we act as a principal in the transaction by assuming control as opposedof the commodities purchased and responsibility to transfer of risk and rewards. The amendment also requires enhanced disclosures regardingdeliver the nature, amount, timing and uncertainty of revenues and cash flows arisingcommodities sold. Revenue is recognized when control transfers to the purchaser at the delivery point based on the price received from contracts withthe purchaser.




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Denbury Resources Inc.
Notes to Unaudited Condensed Consolidated Financial Statements

Disaggregation of Revenue
customers. In August 2015,
The following tables summarize our revenues by product type for the FASB issued ASU 2015-14, Revenue from Contracts with Customers (“ASU 2015-14”) which amends ASU 2014-09 and delays the effective date for public companies, such that the amendments in the ASU are effective for reporting periods beginning after December 15, 2017, and early adoption will be permitted for periods beginning after December 15, 2016. In March, April and May 2016, the FASB issued four additional ASUs which primarily clarified the implementation guidance on principal versus agent considerations, performance obligations and licensing, collectibility, presentation of sales taxes and other similar taxes collected from customers, and non-cash consideration. Entities can transition to the standard either retrospectively to each period presented or as a cumulative-effect adjustment as of the date of adoption. We expect to adopt this standard using the modified retrospective method upon its effective date. Management is currently finishing the evaluation of our various revenue contracts. However, based on the work performed to date, we do not believe this standard will have a material impact on our consolidated financial statements, but will require enhanced footnote disclosures.indicated:

SuccessorPredecessor
In thousandsThree Months Ended
Sept. 30, 2021		Period from Sept. 19, 2020 through
Sept. 30, 2020		Period from July 1, 2020 through
Sept. 18, 2020
Oil sales$305,093 $22,311 $152,136 
Natural gas sales3,361 10 954 
CO2 sales and transportation fees
12,237 967 6,517 
Oil marketing revenues12,593 151 3,332 
Total revenues$333,284 $23,439 $162,939 

SuccessorPredecessor
In thousandsNine Months Ended
Sept. 30, 2021		Period from Sept. 19, 2020 through
Sept. 30, 2020		Period from Jan. 1, 2020 through
Sept. 18, 2020
Oil sales$818,714 $22,311 $489,251 
Natural gas sales7,893 10 2,850 
CO2 sales and transportation fees
31,599 967 21,049 
Oil marketing revenues26,538 151 8,543 
Total revenues$884,744 $23,439 $521,693 

Note 2. Asset Acquisition and Assets Held for Sale

Asset Acquisition

On June 30, 2017, we acquired a 23% non-operated working interest in Salt Creek Field in Wyoming for cash consideration of approximately $71.5 million, before customary closing adjustments. The transaction was accounted for as an asset acquisition in accordance with ASU 2017-01. Therefore, the acquired interests were recorded based upon the cash consideration paid, with all value assigned to proved oil and natural gas properties.

Assets Held for Sale

We began actively marketing for sale certain non-productive surface acreage in the Houston area during July 2017, which we currently anticipate selling during 2018. As of September 30, 2017, the carrying value of the land held for sale was $33.1 million, which is included in “Other property and equipment” on our Unaudited Condensed Consolidated Balance Sheets.

Note 3.4. Long-Term Debt


The followingtable below reflects long-term debt and capital lease obligations were outstanding as of the dates indicated:
Successor
In thousandsSeptember 30, 2021December 31, 2020
Senior Secured Bank Credit Agreement$— $70,000 
Pipeline financings17,332 68,008 
Total debt principal balance17,332 138,008 
Less: current maturities of long-term debt(17,332)(68,008)
Long-term debt$— $70,000 
  September 30, December 31,
In thousands 2017 2016
Senior Secured Bank Credit Agreement $495,000
 $301,000
9% Senior Secured Second Lien Notes due 2021 614,919
 614,919
6⅜% Senior Subordinated Notes due 2021 215,144
 215,144
5½% Senior Subordinated Notes due 2022 772,912
 772,912
4⅝% Senior Subordinated Notes due 2023 622,297
 622,297
Other Subordinated Notes, including premium of $1 and $3, respectively 2,251
 2,253
Pipeline financings 195,258
 202,671
Capital lease obligations 34,542
 48,718
Total debt principal balance 2,952,323
 2,779,914
Future interest payable on 9% Senior Secured Second Lien Notes due 2021 (1)
 203,686
 228,825
Issuance costs on senior secured second lien and senior subordinated notes (13,568) (15,641)
Total debt, net of debt issuance costs 3,142,441
 2,993,098
Less: current maturities of long-term debt (1)
 (85,002) (83,366)
Long-term debt and capital lease obligations $3,057,439
 $2,909,732

(1)
Future interest payable on our 9% Senior Secured Second Lien Notes due 2021 (the “2021 Senior Secured Notes”) represents most of the interest due over the term of this obligation, which has been accounted for as debt in accordance with Financial Accounting Standards Board Codification (“FASC”) 470-60, Troubled Debt Restructuring by Debtors. Our current maturities of long-term debt as of September 30, 2017 include $50.5 million of future interest payable related to the 2021 Senior Secured Notes that is due within the next twelve months.



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Denbury Resources Inc.
Notes to Unaudited Condensed Consolidated Financial Statements

The ultimate parent company in our corporate structure, Denbury Resources Inc. (“DRI”), is the sole issuer of all of our outstanding 2021 Senior Secured Notes and our 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 FacilityAgreement


In December 2014,On the Emergence Date, we entered into an Amended and Restated Credit Agreementa credit agreement with JPMorgan Chase Bank, N.A., as administrative agent, and other lenders party thereto (as amended, the(the “Bank Credit Agreement”). The Bank Credit Agreement is a senior secured revolving credit facility with a maturity date of December 9, 2019 and semiannual borrowing base redeterminations in May and November of each year. As part of our fall 2017 semiannual borrowing base redetermination, the borrowing base and lender commitments for ourof $575 million. Availability under the Bank Credit Agreement were reaffirmedis subject to a borrowing base, which is redetermined semiannually on or around May 1 and November 1 of each year, with our next scheduled redetermination around May 1, 2022. The borrowing base is adjusted at $1.05 billion, with the next such redetermination scheduled for May 2018.lenders’ discretion and is based, in part, upon external factors over which we have no control. If our outstanding debt under the Bank Credit Agreement were to ever exceedexceeds the then-effective borrowing base, we would be required to repay the excess amount over a period not to exceed six months. The weighted average interest rate on borrowings outstanding under the Bank Credit Agreement was 4.3% as of Septembermatures on January 30, 2017. We incur a commitment fee of 0.50% on the2024. The undrawn portion of the aggregate lender commitments under the Bank Credit Agreement.Agreement is subject to a commitment fee of 0.5% per annum.


In May 2017, we entered into a Fourth Amendment

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Denbury Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
The Bank Credit Agreement limits our ability to pay dividends on our common stock or make other restricted payments in an amount not to exceed “Distributable Free Cash Flow”, but only if (1) no event of default or borrowing base deficiency exists; (2) our total leverage ratio is 2 to 1 or lower; and (3) availability under the Bank Credit Agreement pursuant to which the lenders agreed to amend certain terms and financial performance covenants through the remaining term of theis at least 20%. The Bank Credit Agreement also limits our ability to, among other things, incur and repay other indebtedness; grant liens; engage in ordercertain mergers, consolidations, liquidations and dissolutions; engage in sales of assets; make acquisitions and investments; make other restricted payments (including redeeming, repurchasing or retiring our common stock); and enter into commodity derivative agreements, in each case subject to provide more flexibility in managing the credit extended by our lenders, including eliminating the consolidated total net debt to EBITDAX financial performance covenants that were scheduled to go into effect starting in 2018. In addition, the amendment increased the applicable margin for ABR Loans and LIBOR Loans by 50 basis points, such that the margin for ABR Loans now ranges from 1.5% to 2.5% per annum and the margin for LIBOR Loans now ranges from 2.5% to 3.5% per annum. In November 2017, we entered into a Fifth Amendment to thecustomary exceptions.

The Bank Credit Agreement pursuantis secured by (1) our proved oil and natural gas properties, which are held through our restricted subsidiaries; (2) the pledge of equity interests of such subsidiaries; (3) a pledge of our commodity derivative agreements; (4) a pledge of deposit accounts, securities accounts and our commodity accounts; and (5) a security interest in substantially all other collateral that may be perfected by a Uniform Commercial Code filing, subject to which the lenders agreed to increase the amount of junior lien (i.e., second lien or third lien) debt we can incur from $1.0 billion to $1.2 billion outstanding in the aggregate at any one time.certain exceptions.


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


•A consolidated senior secured debtConsolidated Total Debt to consolidatedConsolidated EBITDAX covenant (as defined in the Bank Credit Agreement), with such ratio not to exceed 3.0 to 1.0 through the first quarter of 2018,3.5 times; and thereafter not to exceed 2.5 to 1.0. Currently, 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 available borrowing capacity under the Bank Credit Agreement, and Consolidated Current Liabilities exclude the current portion of derivative liabilities as well as the current portions of long-term indebtedness outstanding. As of September 30, 2021, we 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 andAgreement.

Pipeline Financing Transactions

During the amendments thereto, eachfirst nine months of which are filed as exhibits2021, Denbury paid $52.5 million to our periodic reports filedGenesis Energy, L.P. in accordance with the SEC.

2016 Senior Subordinated Notes Exchange

During May 2016, in privately negotiated transactions, we exchanged a totalOctober 2020 restructuring of $1,057.8 millionthe financing arrangements of our existing senior subordinated notes for $614.9NEJD CO2 pipeline system. The final quarterly installment of $17.5 million principal amountwas paid on October 29, 2021.

Note 5. Income Taxes

As of September 30, 2021, the tax basis of our 2021 Senior Secured Notes plus 40.7 million sharesassets, primarily our oil and gas properties, is in excess of Denbury common stock, resultingtheir carrying value, as adjusted for fresh start accounting on September 18, 2020; therefore, we are currently in a net reduction from these exchangesdeferred tax asset position. Based on all available evidence, both positive and negative, we continue to record a valuation allowance on our underlying deferred tax assets as of $442.9 million in our debt principal. As a result of this debt exchange, we recognized a gain of $12.0 million during the nine months ended September 30, 2016,2021, as we believe our deferred tax assets are not more-likely-than-not to be realized. We intend to maintain the valuation allowances on our deferred tax assets until there is sufficient evidence to support the reversal of all or some portion of the allowances, which is included in “Gainwill largely be determined based on debt extinguishment” inoil prices and the accompanying Consolidated Statements of Operations.Company’s ability to generate positive pre-tax income.

2016 Repurchases of Senior Subordinated Notes

During the first and third quarters of 2016, we repurchased a total of $181.9 million of our outstanding long-term indebtedness in open-market transactions for a total purchase price of $76.7 million, excluding accrued interest. In connection with these transactions, we recognized a $103.1 million gain on extinguishment, net of unamortized debt issuance costs written off, during the nine months ended September 30, 2016. As of November 6, 2017, under the Bank Credit Agreement, up to an additional $148.3 million may be spent on open market or other repurchases or redemptions of our senior subordinated notes.


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Denbury Resources Inc.
Notes to Unaudited Condensed Consolidated Financial Statements


Note 4. Income Taxes


We evaluate our estimated annual effective income tax rate based on current and forecasted business results and enacted tax laws on a quarterly basis and apply this tax rate to our ordinary income or loss to calculate our estimated tax liability or benefit. Our income taxes are based on an estimated combined federal and state statutory rate of approximately 38%25% in 20172021 and 2016.2020. Our effective tax raterates for the three and nine months ended September 30, 2017,2021 (Successor) differed from our estimated statutory rate primarily due toas the impact of recognizing adeferred tax benefit of $8.6 million inexpense generated by the current quarter for enhanced oil recovery income tax credits, which was offset in part by a stock-based compensation deduction shortfall (tax deduction less than book expense) of $2.1 million. With pre-taxoperating income for the three months ended September 30, 2017 being close to break-even,2021 and the netdeferred tax benefit generated from these items hadour operating loss for the nine months ended September 30, 2021 were offset by a significant impact on the current quarter’s effectivevaluation allowance applied to our underlying federal and state deferred tax rate.assets.



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Denbury Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
Note 5.6. 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 Unaudited Condensed 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 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.prices, and occasionally requirements under our bank credit facility. As of December 31, 2020, we were in compliance with the hedging requirements under our Bank Credit Agreement requiring certain minimum commodity hedge levels through July 31, 2022, and we do not have any additional hedging requirements under the Bank Credit Agreement.


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 September 30, 2017,2021, 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.




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Denbury Resources Inc.
Notes to Unaudited Condensed Consolidated Financial Statements

The following table summarizes our commodity derivative contracts as of September 30, 2017,2021, none of which are classified as hedging instruments in accordance with the FASC Derivatives and Hedging topic:
MonthsIndex PriceVolume (Barrels per day)Contract Prices ($/Bbl)
Range(1)
Weighted Average Price
SwapFloorCeiling
Oil Contracts:    
2021 Fixed-Price Swaps
Oct – DecNYMEX29,000$38.68 –56.00 $43.86 $— $— 
2021 Collars
Oct – DecNYMEX4,000$45.00 –59.30 $— $46.25 $53.04 
2022 Fixed-Price Swaps
Jan – JuneNYMEX15,500$42.65 –58.15 $49.01 $— $— 
July – DecNYMEX9,00050.13 –60.35 56.35 — — 
2022 Collars
Jan – JuneNYMEX11,000$47.50 –70.75 $— $49.77 $64.31 
July – DecNYMEX10,00047.50 –70.75 — 49.75 64.18 

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

Months Index Price Volume (Barrels per day) Contract Prices ($/Bbl)
Range (1)
 Weighted Average Price
Swap Sold Put Floor Ceiling
Oil Contracts:               
2017 Fixed-Price Swaps               
Oct – Dec NYMEX 12,000 $48.40–50.13
 $49.76
 $—
 $—
 $—
2017 Three-Way Collars (2)
               
Oct ��� Dec NYMEX 14,000 $40.00–70.20
 $—
 $31.07
 $41.07
 $65.79
Oct – Dec LLS 1,000  41.00–70.25
 —
 31.00
 41.00
 70.25
2017 Collars                 
Oct – Dec NYMEX 1,000 $40.00–70.00
 $—
 $—
 $40.00
 $70.00
2018 Fixed-Price Swaps               
Jan – Dec NYMEX 15,500 $50.00–50.40
 $50.13
 $—
 $—
 $—
2018 Three-Way Collars (2)
               
Jan – Dec NYMEX 15,000 $45.00–56.60
 $—
 $36.50
 $46.50
 $53.88
                  
                  
2017 Basis Swaps (3)
               
Dec Argus LLS 5,000 $4.15
–4.15
 $4.15
 $—
 $—
 $—
2018 Basis Swaps (3)
               
Jan – June Argus LLS 2,500 $3.13
–3.15
 $3.13
 $—
 $—
 $—

(1)Ranges presented for fixed-price swaps and basis swaps represent the lowest and highest fixed prices of all open contracts for the period presented. For collars and 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.
(3)The basis swap contracts establish a fixed amount for the differential between Argus WTI and Argus LLS prices on a trade-month basis for the period indicated.

Note 6.7. 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

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Denbury Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
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 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.




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Denbury Resources Inc.
Notes to Unaudited Condensed Consolidated Financial Statements

•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 basis 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. At September 30, 2017, instruments in this category include non-exchange-traded three-way collars that are based on regional pricing other than NYMEX (e.g., Light Louisiana Sweet). The valuation models utilized for costless collars and three-way collars are consistent with the methodologies described above; however, the implied volatilities utilized in the valuation of Level 3 instruments are developed using a benchmark, which is 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 $100 thousand in the fair value of these instruments as of September 30, 2017.


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.


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 the periods indicated:
 Fair Value Measurements Using:
In thousandsQuoted Prices
in Active
Markets
(Level 1)		Significant
Other
Observable
Inputs
(Level 2)		Significant
Unobservable
Inputs
(Level 3)		Total
September 30, 2021 
Liabilities
Oil derivative contracts – current$— $(193,015)$— $(193,015)
Oil derivative contracts – long-term— (16,435)— (16,435)
Total Liabilities$— $(209,450)$— $(209,450)
December 31, 2020    
Assets    
Oil derivative contracts – current$— $187 $— $187 
Total Assets$— $187 $— $187 
Liabilities
Oil derivative contracts – current$— $(53,865)$— $(53,865)
Oil derivative contracts – long-term— (5,087)— (5,087)
Total Liabilities$— $(58,952)$— $(58,952)


17
  Fair Value Measurements Using:
In thousands 
Quoted Prices
in Active
Markets
(Level 1)
 
Significant
Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs
(Level 3)
 Total
September 30, 2017        
Assets        
Oil derivative contracts – current $—
 $58
 $2
 $60
Total Assets $—
 $58
 $2
 $60
         
Liabilities        
Oil derivative contracts – current $—
 $(16,746) $—
 $(16,746)
Oil derivative contracts – long-term —
 (4,263) —
 (4,263)
Total Liabilities $—
 $(21,009) $—
 $(21,009)
         
December 31, 2016  
  
  
  
Liabilities  
  
  
  
Oil derivative contracts – current $—
 $(68,753) $(526) $(69,279)
Total Liabilities $—
 $(68,753) $(526) $(69,279)


Table of Contents
Denbury Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
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 Unaudited Condensed Consolidated Statements of Operations.



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Denbury Resources Inc.
Notes to Unaudited Condensed Consolidated Financial Statements

Level 3 Fair Value Measurements

The following table summarizes the changes in the fair value of our Level 3 assets and liabilities for the three and nine months ended September 30, 2017 and 2016:
  Three Months Ended Nine Months Ended
  September 30, September 30,
In thousands 2017 2016 2017 2016
Fair value of Level 3 instruments, beginning of period $99
 $240
 $(526) $52,834
Fair value gains (losses) on commodity derivatives (97) 2,402
 528
 (2,134)
Receipts on settlements of commodity derivatives —
 (3,167) —
 (51,225)
Fair value of Level 3 instruments, end of period $2
 $(525) $2
 $(525)
         
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 $(71) $891
 $54
 $(525)

We utilize an income approach to value our Level 3 costless collars and 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
9/30/2017
(in thousands)		 Valuation Technique Unobservable Input Volatility Range
Oil derivative contracts $2
 Discounted cash flow / Black-Scholes Volatility of Light Louisiana Sweet for settlement periods beginning after September 30, 2017 15.4% – 33.4%


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 2021 Senior Secured 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 September 30, 2017 and December 31, 2016,2020, excluding pipeline financing and capital lease obligations, was $1,996.6 million and $2,327.8 million, respectively.$70.0 million. 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 7.8. Commitments and Contingencies

Commitments

The Company has a CO2 offtake agreement with Mississippi Power Company (“MSPC”), providing for our purchase of CO2 generated as a byproduct of the gasification portion of their Kemper County energy facility. After receiving minor amounts of CO2 from the facility during the first half of 2017, in June 2017, MSPC announced the immediate and indefinite suspension of startup and operations activities of the lignite coal gasification portion of the Kemper County energy facility. As a result of this suspension, the Company is not expecting to receive any CO2 from this facility for the foreseeable future.



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Denbury Resources Inc.
Notes to Unaudited Condensed Consolidated Financial Statements


Litigation


We are involved in various lawsuits, claims and regulatory proceedings incidental to our businesses.  We are also 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. 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.  Although a single or multiple adverse rulings or settlements could possibly have a material adverse effect on our finances, we onlyWe 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, we assumed a 20-year helium supply contract under which we agreed to supply to a third-party purchaser the helium separated from the full well stream by operation of the gas processing facility.  The helium supply contract provides for the delivery of a minimum contracted quantity of helium, subject to adjustment after startup of the Riley Ridge gas processing facility, 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 $8.0 million per contract year and are capped at an aggregate of $46.0 million over the remaining term of the contract. As the gas processing facility has been shut-in since mid-2014, we have not been able to supply helium to the third-party purchaser under the helium supply contract.  In a case originally filed in November 2014 by APMTG Helium, LLC, the third-party helium purchaser, after a week of trial during February 2017 on the third-party purchaser’s claim for multiple years of liquidated damages for non-delivery of volumes of helium specified under the helium supply contract, and on our claim that the contractual obligation is excused by virtue of events that fall within the force majeure provisions in the helium supply contract, the trial was stayed until November 27, 2017. The Company plans to continue to vigorously defend its position and pursue its claim, but we are unable to predict at this time the outcome of this dispute.

Note 8.9. Additional Balance Sheet Details


TradeAccounts Payable and Other Receivables, NetAccrued Liabilities
Successor
In thousandsSeptember 30, 2021December 31, 2020
Accounts payable$38,578 $18,629 
Accrued compensation33,961 7,512 
Accrued derivative settlements26,311 3,908 
Accrued lease operating expenses25,724 21,294 
Accrued exploration and development costs20,728 1,861 
Taxes payable14,468 17,221 
Accrued general and administrative expenses2,595 21,825 
Other49,529 20,421 
Total$211,894 $112,671 


18
  September 30, December 31,
In thousands 2017 2016
Trade accounts receivable, net $15,319
 $20,084
Federal income tax receivable 11,687
 —
Other receivables 28,312
 23,816
Total $55,318
 $43,900



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

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations


The following discussion and analysis should be read in conjunction with our Unaudited Condensed Consolidated Financial Statements and Notes thereto included herein and our Consolidated Financial Statements and Notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 20162020 (the “Form 10-K”), along with Management’s Discussion and Analysis of Financial Condition and Results of Operations contained in the Form 10-K.  Any terms used but not defined herein have the same meaning given to them in the Form 10-K.  

As a result of the Company’s emergence from bankruptcy and adoption of fresh start accounting on September 18, 2020 (the “Emergence Date”), certain values and operational results of the condensed consolidated financial statements subsequent to September 18, 2020 are not comparable to those in the Company’s condensed consolidated financial statements prior to, and including September 18, 2020. The Emergence Date fair values of the Successor’s assets and liabilities differ materially from their recorded values as reflected on the historical balance sheets of the Predecessor contained in periodic reports previously filed with the Securities and Exchange Commission. References to “Successor” relate to the financial position and results of operations of the Company subsequent to September 18, 2020, and references to “Predecessor” relate to the financial position and results of operations of the Company prior to, and including, September 18, 2020.

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 the 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 than our forward-looking statements.


OVERVIEW


Denbury is an independent oil and natural gasenergy company with operations focused in two key operating areas: the Gulf Coast and Rocky Mountain regions. Our goalThe Company 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 todifferentiated by its focus on CO2 enhanced oil recovery (“EOR”) and the emerging carbon capture, use, and storage (“CCUS”) industry, supported by the Company’s CO2 EOR technical and operational expertise and its extensive CO2 pipeline infrastructure.The utilization of captured industrial-sourced CO2 in EOR significantly reduces the carbon footprint of the oil that Denbury produces, making the Company’s scope 1 and 2 CO2 emissions negative today, with a goal to also fully offset its scope 1, 2, and 3 CO2 emissions within this decade, primarily through increasing the amount of captured industrial-sourced CO2 used in its operations.


Oil Price Impact on Our Business.  Our financial results are significantly impacted by changes in oil prices, as 97% of our production issales volumes are oil. Oil prices are highly impacted by worldwide oil supply and demand and have historically been subject to significant price changes over short periods of time, including the early November 2017 move of NYMEXChanges in oil prices over $57 per Bbl for the first time in over two years. Over the last few years, we have been in a periodimpact all aspects of lower oil prices during which oil prices have generally averaged in the $30-$50 per Bbl range, which is roughly 50% lower than the oil price range over the 2011 through 2014 period. As a result of the lower oil price environment and its impact on our business, our focus has primarily been on preservation of cash and liquidity, together with cost reductions, rather than concentration on expansion and growth. Early in 2017, when we set our development capital budget at $300 million, the forecasted oil price for 2017 was projected to average in the low-to-mid $50’s per Bbl. Given that prices during the first three quarters of 2017 were lower than originally projected, to protectbusiness; most notably our cash flows from operations, revenues, capital allocation and liquidity, in August 2017 we reduced our 2017 estimated development capital spending by $50 million from $300 million to $250 million (excluding acquisitionsbudgeting decisions, and capitalized interest).

Hurricane Harvey Impact. Due to conditions associated with Hurricane Harvey, in late-August the Company suspended operations and temporarily shut-in all production at its Houston area fields, representing net production of approximately 16,000 BOE/d. The impacted fields included Hastings, Oyster Bayou, Conroe, Thompson, Webster and Manvel.  Approximately 90% of the 16,000 BOE/d of net production shut-in as of August 27, 2017 had returned to production by September 6th, and the only field that remained partially shut-in was Thompson Field. Thompson Field had net production just prior to the storm of approximately 1,000 BOE/d, nearly all of which has now been returned to production. The impact of Hurricane Harvey on third quarter 2017 production was approximately 2,000 BOE/d, and there was no significant damage to any of the fields. The primary impacts of the storm to date include temporarily shut-in production and cleanup and repair costs. During the third quarter of 2017, we incurred approximately $2.6 million in cleanup and repair costs related to Hurricane Harvey, and we currently estimate that additional cleanup and repair costs of approximately $4 million will be recorded to lease operating expenses during the fourth quarter of 2017. See Results of Operations – Production for further discussion of production changes.

Operating Highlights. We recognized net income of $0.4 million, or $0.00 per diluted common share, during the third quarter of 2017, compared to a net loss of $24.6 million, or $0.06 per diluted common share, during the third quarter of 2016. The primary drivers of our change in operating results between the comparative third quarters of 2017 and 2016 were the following:

Third quarter of 2016 results included a $75.5 million ($48.4 million net of tax) full cost pool ceiling test write-down of our oil and natural gas properties, offset in part by a $7.8 million gain on debt extinguishment.
Oil and natural gas revenues improved by $19.1 million, or 8%, in the third quarter of 2017, principally driven by a 10% improvement in realized oil prices, offset in part by a 2% decrease in average daily productionreserves volumes. Net realized oil price differentials improved by $1.23 per Bbl from the prior-year period.
Commodity derivatives expense increased by $46.5 million ($25.3 million of expense in the current-year period compared to $21.2 million of income in the prior-year period). This increase in expense was the result of losses from noncash fair value adjustments between the periods of $53.9 million, offset in part by a $7.4 million reduction in payments on derivative settlements.
Lease operating expenses increased by $11.2 million, or 11%, from the third quarter of 2016.

The table below


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

outlines selected financial items and sales volumes, along with changes in our realized oil prices, before and after commodity derivative impacts, for our most recent comparative quarterly periods:
Tax benefits of $8.6 million recognized in the current-year quarter related to enhanced
Three Months Ended
In thousands, except per-unit dataSept. 30, 2021June 30, 2021March 31, 2021Dec. 31, 2020Sept. 30, 2020
Oil, natural gas, and related product sales$308,454 $282,708 $235,445 $178,787 $175,411 
Receipt (payment) on settlements of commodity derivatives(77,670)(63,343)(38,453)14,429 17,789 
Oil, natural gas, and related product sales and commodity settlements, combined$230,784 $219,365 $196,992 $193,216 $193,200 
Average daily sales (BOE/d)49,682 49,133 47,357 48,805 49,686 
Average net realized oil prices   
Oil price per Bbl - excluding impact of derivative settlements$68.88 $64.70 $56.28 $40.63 $39.23 
Oil price per Bbl - including impact of derivative settlements51.35 50.10 47.00 43.94 43.23 

NYMEX WTI oil recovery income tax credits.

We generated $65.7 million of cash flows from operating activities in the third quarter of 2017, a decrease of $30.8 millionprices strengthened from the third quartermid-$40s per Bbl range in December 2020 to an average of 2016 levels. The decrease in cash flows from operations was due primarily to working capital changes ($2.6 million outflowapproximately $71 per Bbl during the third quarter of 2017 compared2021, reaching highs of over $75 per Bbl in early-July 2021 and late-September 2021.

The benefit of the steady growth in our oil sales over the last four quarters due to rising oil prices has been offset in part by our payments on settlement of commodity derivative contracts, especially in the second and third quarters of 2021, principally due to the strike prices of our fixed-price swaps which were entered into in late 2020 based on the hedging requirements we were obligated to meet under our bank credit facility. During the first nine months of 2021, we paid $179.5 million related to the expiration of commodity derivative contracts and expect to make additional payments on the settlement of our contracts expiring during the fourth quarter of 2021.Our current hedging levels decrease significantly in 2022, and we are hedged at more favorable prices and with a $34.8greater mix of collars, allowing for additional upside. We do not have any additional hedging requirements under our bank credit facility.

Third Quarter 2021 Financial Results and Highlights. We recognized net income of $82.7 million, inflowor $1.51 per diluted common share, during the third quarter of 2016)2021. As a result of Denbury filing for bankruptcy and emerging from bankruptcy during the same quarter, our prior-year quarterly financial results are broken out between the predecessor period (July 1, 2020 through September 18, 2020) and the successor period (September 19, 2020 through September 30, 2020). For the predecessor period from July 1, 2020 through September 18, 2020, we recognized a net loss of $809.1 million, and for the successor period from September 19, 2020 through September 30, 2020, we recognized net income of $2.8 million. The principal determinant of our comparative third quarter results between 2020 and 2021 were (a) an $850.0 million charge for reorganization items, net, during the prior-year predecessor period, primarily consisting of fresh start accounting adjustments and (b) a $261.7 million full cost pool ceiling test write-down during the prior-year predecessor period. Additional drivers of the comparative operating results include the following:


Second Quarter 2017 Salt Creek Field Acquisition. On June 30, 2017, we acquired•Oil and natural gas revenues increased $133.0 million (76%), nearly entirely due to an increase in commodity prices;
•Lease operating expenses increased $45.3 million, primarily due to (a) a 23% non-operated working interest$15.4 million insurance reimbursement that reduced lease operating expenses in Salt Creek Fieldthe prior-year period, (b) an increase of $8.1 million related to the March 2021 Wind River Basin acquisition, and (c) higher expenses across all lease operating expense categories, largely driven by higher commodity prices and increased workover activity; and
•Commodity derivatives expense increased by $41.2 million consisting of a $95.5 million decrease in Wyoming for cash consideration of approximately $71.5receipts upon contract settlements ($77.7 million (before customary closing adjustments). Salt Creek Field is an ongoing CO2 flood, and tertiary production from the field was just over 2,200 Bbls/d, net to our interest,in payments during the third quarter of 2017. Production from Salt Creek Field is expected2021 compared to increase over the next several years with minimal capital spending. As of June 30, 2017, net to our interest, we estimated the field had proved oil reserves of approximately 17 MMBbls, including proved developed reserves of approximately 14 MMBbls.

First Quarter 2017 West Yellow Creek Field Acquisition. In March 2017, we acquired an approximate 48% non-operated working interest in West Yellow Creek Field in Mississippi for approximately $16 million (before closing adjustments). We estimate West Yellow Creek Field currently has approximately 2 MMBbls of proved oil reserves, net to our interest, but minimal production, as the operator is in the process of completing the conversion of the field to a CO2 EOR flood and has invested significant capital in that development. Having available CO2 was a primary factor in being able to enter into this transaction, in which we will sell CO2 to the operator. Based on current plans, we expect capital expenditures on this development to be less than $10$17.8 million in 2017, with first tertiary production expected from the field in late 2017 or early 2018.

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. For the first nine months of 2017, we generated cash flows from operations of $142.9 million, after giving affect to $52.4 million of negative cash flow due to working capital adjustments. We have been proactive in adjusting our capital spending in connection with the lower oil price environment over the past several years, and as discussed in the Overview above, in August 2017, we adjusted our anticipated full-year 2017 capital budget, excluding acquisitions and capitalized interest, from $300 million to $250 million. Based on our current forecasts and expected average oil prices in the mid-$50’s per Bbl for the remainder of 2017, we currently expect that our cash flow from operations would fund all but a modest amount of this development capital spending, after giving effect to interest accounted for as debt, but excluding acquisitions (see Capital Spending below for further discussion). If our cash flows from operations were to be less than our capital spending, we currently plan to fund those expenditures in the near term with incremental borrowings under our bank credit facility.

The preservation of cash and liquidity remains a significant priority for us in the current oil price environment. As of September 30, 2017, we had $495.0 million drawn on our $1.05 billion senior secured bank credit facility and $62.2 million of outstanding letters of credit, compared to $490.0 million outstanding as of June 30, 2017 and $301.0 million as of December 31, 2016.  The $194.0 million increase in bank debt since December 31, 2016 is primarily due to $91.1 million of oil and natural gas property acquisitions in the first nine months of 2017, $52.4 million of cash outflows for working capital changes, and repayments of other non-bank debt of $45.7 million. Assuming oil prices remain at current levels in the mid-$50’s per Bbl for the remainder of the year, we currently expect our senior secured bank credit facility borrowings will end the year in a projected range of between $450 million and $475 million. With this level of bank borrowings, we should have around $500 million of liquidity under our bank line, which, coupled with continuing cost savings and liquidity preservation measures, should be sufficient to cover any foreseeable cash flow shortfall between our cash flows from operations and capital spending. The Company may also raise funds through asset sales or joint ventures, issuance of notes and/or equity, which would enable us to reduce our outstanding borrowings on the credit facility and further increase our available liquidity.

Since we do not expect oil prices to return in the foreseeable future to recent historical highs of 2014, we have adjusted, and continue to adjust, our business through efficiencies and cost reductions. Most recently, we completed a reduction in force inreceipts upon settlements during the third quarter of 2017, resulting2020), partially offset by a $54.3 million improvement in a reductionnoncash fair value changes ($35.9 million of approximately 15%income in the current period compared to $18.4 million of expense in the Company’s workforce, principally comprised of personnel at the Company’s headquarters. With this reduction in force, coupled with other recently enacted or identified cost savings measures, we expect to exceed $50 million in cost reductions, many of which we are starting to see the benefits of now, and others that will be realized in 2018, and we continue to believe we have additional opportunities to reduce costs.


prior-year period).


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


Third Quarter 2021 Houston Area Land Sales. During the third quarter of 2021, we completed sales of a portion of certain non-producing surface acreage in the Houston area. We recognized cash proceeds of $11.8 million from the sales and recorded a $7.0 million gain to “Other income” in our Unaudited Condensed Consolidated Statements of Operations.

June 2021 Divestiture of Hartzog Draw Deep Mineral Rights. On June 30, 2021, we closed the sale of undeveloped, unconventional deep mineral rights in Hartzog Draw Field in Wyoming. The cash proceeds of $18 million were recorded to “Proved properties” in our Unaudited Condensed Consolidated Balance Sheets. The proceeds reduced our full cost pool; therefore, no gain or loss was recorded on the transaction, and the sale had no impact on our production or reserves.

March 2021 Acquisition of Wyoming CO2 EOR Fields. On March 3, 2021, we acquired a nearly 100% working interest (approximately 83% net revenue interest) in the Big Sand Draw and Beaver Creek EOR fields (collectively “Wind River Basin”) located in Wyoming from a subsidiary of Devon Energy Corporation for $10.9 million cash (after final closing adjustments), including surface facilities and a 46-mile CO2 transportation pipeline to the acquired fields. The acquisition agreement provides for us to make two contingent cash payments, one in January 2022 and one in January 2023, of $4 million each, conditioned on NYMEX WTI oil prices averaging at least $50 per Bbl during each of 2021 and 2022. As of September 30, 2021, the contingent consideration was recorded on our unaudited condensed consolidated balance sheets at its fair value of $7.4 million, a $2.1 million increase from the March 2021 acquisition date fair value. This $2.1 million increase at September 30, 2021 was the result of higher NYMEX WTI oil prices and was recorded to “Other expenses” in our Unaudited Condensed Consolidated Statements of Operations. Wind River Basin sales averaged approximately 3,015 BOE/d during the third quarter of 2021 and utilize 100% industrial-sourced CO2.

Carbon Capture, Use and Storage. CCUS is a process that captures CO2 from industrial sources and reuses it or stores the CO2 in geologic formations in order to prevent its release into the atmosphere. We utilize CO2 from industrial sources in our EOR operations, and our extensive CO2 pipeline infrastructure and operations, particularly in the Gulf Coast, are strategically located in close proximity to large sources of industrial emissions. We believe that the assets and technical expertise required for CCUS are highly aligned with our existing CO2 EOR operations, providing us with a significant advantage and opportunity to participate in the emerging CCUS industry, as the building of a permanent carbon sequestration business requires both time and capital to build assets such as those we own and have been operating for years. During the nine months ended September 30, 2021, approximately 34% of the CO2 utilized in our oil and gas operations was industrial-sourced CO2, and we anticipate this percentage could increase in the future as supportive U.S. government policy and public pressure on industrial CO2 emitters will provide strong incentives for these entities to capture their CO2 emissions.

As we seek to grow our CCUS business and pursue new CCUS opportunities, we have been engaged in discussions with existing and potential third-party industrial CO2 emitters regarding transportation and storage solutions, while also identifying potential future sequestration sites and landowners of those locations. We continue to make progress in these discussions and have recently executed several term sheets for the future transportation and sequestration of CO2. While EOR is the only CCUS operation reflected in our current and historical financial and operational results, and development of our permanent carbon sequestration business is likely to take several years, we believe Denbury is well positioned to leverage our existing CO2 pipeline infrastructure and EOR expertise to be a leader in this industry.

CAPITAL RESOURCES AND LIQUIDITY

Overview. Our cash flows from operations and availability under our senior secured bank credit facility are our primary sources of capital and liquidity. Our most significant cash capital outlays in 2021 relate to our budgeted development capital expenditures and payment of $70 million of pipeline financing obligations associated with the NEJD pipeline. Based on our current 2021 full-year projections using recent oil price futures, our cash flow from operations in 2021 should be more than adequate to cover our remaining budgeted development capital expenditures and also cover a significant portion of our $70 million repayment of pipeline financing obligations. In addition, $29.8 million of non-producing property sales in the first nine months of 2021 provided cash to reductionsfurther reduce our debt.

As of September 30, 2021, we had no outstanding borrowings on our $575 million senior secured bank credit facility, leaving us with $563.2 million of borrowing base availability after consideration of $11.8 million of outstanding letters of credit. Our borrowing base availability, coupled with unrestricted cash of $1.8 million provides us total liquidity of

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Management’s Discussion and Analysis of Financial Condition and Results of Operations
$565.0 million as of September 30, 2021, which is more than adequate to meet our currently planned operating and capital needs.

2021 Capital Expenditures. Capital expenditures during the first nine months of 2021 were $173.8 million. We continue to anticipate that our full-year 2021 development capital spending, excluding capitalized interest and acquisitions, will be in a range of $250 million to $270 million.  Approximately 45% of our 2021 capital expenditures through September 30, 2021 have been focused on the previously announced development of the EOR CO2 flood at Cedar Creek Anticline (“CCA”). The project is currently underway, with completion of the 105-mile extension of the Greencore CO2 pipeline from Bell Creek to CCA expected before the end of November 2021, first CO2 injection planned during the first quarter of 2022, and first tertiary production expected in the second half of 2023.

Capital Expenditure Summary. The following table reflects incurred capital expenditures for the nine months ended September 30, 2021 and 2020:
Nine Months Ended
September 30,
In thousands20212020
Capital expenditure summary(1)
 
Tertiary and non-tertiary fields$102,640 $41,679 
Capitalized internal costs(2)
22,639 26,695 
Oil and natural gas capital expenditures125,279 68,374 
CCA CO2 pipeline
48,542 9,192 
Development capital expenditures173,821 77,566 
Acquisitions of oil and natural gas properties(3)
10,927 95 
Capital expenditures, before capitalized interest184,748 77,661 
Capitalized interest3,500 23,068 
Capital expenditures, total$188,248 $100,729 

(1)Capital expenditures in this summary are presented on an as-incurred basis (including accruals), and are $45.2 million higher than the capital expenditures in the Unaudited Condensed Consolidated Statements of Cash Flows which are presented on a cash basis.
(2)Includes capitalized internal acquisition, exploration and development costs and pre-production tertiary startup costs.
(3)Primarily consists of working interest positions in the Wind River Basin enhanced oil recovery fields acquired on March 3, 2021.

Supply Chain Issues and Potential Cost Inflation. Recent worldwide and U.S. supply chain issues, together with rising commodity prices and tight labor markets in the U.S., could increase our costs in 2022 and future periods. Most of the cost inflation pressures we have experienced during 2021 have been tied to rising fuel and power costs in our operations; however, there is the potential for more significant increases in the cost structure, we have reduced our debt levels over the last few years primarily through opportunistic debt exchangesof goods and open market debt repurchases; however, given the current oil price environment we would like to achieve additional debt reductions. The flexibilityservices and wages in our capital structureoperations which could negatively impact our results of operations and movementscash flows in the market pricefuture periods.


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Denbury Inc.
Management’s Discussion and equity securities may provide opportunities for debt refinancing or additional debt reduction over time,Analysis of Financial Condition and we continue to explore and have discussions with bondholders from time to time regarding potential debt reduction transactions. Potential transactions could include purchasesResults of our subordinated debt in the open market, cash tenders for our debt, or public or privately negotiated debt exchanges, including debt for equity exchanges and/or convertible debt issuances, or future potential debt reduction with proceeds of issuances of equity, asset sales, joint ventures and other cash-generating activities. Any equity that we issue could lead to dilution of our current stockholders and affect our common stock price.Operations

Senior Secured Bank Credit Facility. Agreement. In December 2014,September 2020, we entered into an Amended and Restated Credit Agreementa bank credit agreement with JPMorgan Chase Bank, N.A., as administrative agent, and other lenders party thereto (as amended, the(the “Bank Credit Agreement”). The Bank Credit Agreement is a senior secured revolving credit facility with a maturity date of January 30, 2024. As part of our fall 20172021 semiannual borrowing base redetermination, the borrowing base and lender commitments for our Bank Credit Agreement were reaffirmed at $1.05 billion,$575 million, with our next scheduled redetermination around May 1, 2022. The borrowing base is adjusted at the next such redetermination scheduled for May 2018. As of September 30, 2017,lenders’ discretion and is based, in part, upon external factors over which we had $495.0 million ofhave no control. If our outstanding debt outstanding and $62.2 million in letters of credit on the senior secured bank credit facility, leaving us with significant liquidity.

In May 2017, we entered into a Fourth Amendment tounder the Bank Credit Agreement pursuantexceeds the then-effective borrowing base, we would be required to whichrepay the lenders agreedexcess amount over a period not to amend certain terms and financial performance covenants through the remaining term of the Bank Credit Agreement in order to provide more flexibility in managing the credit extended by our lenders, including eliminating the consolidated total net debt to EBITDAX financial performance covenants that were scheduled to go into effect starting in 2018. In addition, the amendment increased the applicable margin for ABR Loans and LIBOR Loans by 50 basis points, such that the margin for ABR Loans now ranges from 1.5% to 2.5% per annum and the margin for LIBOR Loans now ranges from 2.5% to 3.5% per annum. In November 2017, we entered into a Fifth Amendment to the Bank Credit Agreement, pursuant to which the lenders agreed to increase the amount of junior lien (i.e., second lien or third lien) debt we can incur from $1.0 billion to $1.2 billion outstanding in the aggregate at any one time.

exceed six months. The Bank Credit Agreement contains certain financial performance covenants through the maturity of the facility, including the following:


•A consolidated senior secured debtConsolidated Total Debt to consolidatedConsolidated EBITDAX covenant (as defined in the Bank Credit Agreement), with such ratio not to exceed 3.0 to 1.0 through the first quarter of 2018,3.5 times; and thereafter not to exceed 2.5 to 1.0. Currently, 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 ourpurposes of computing the current ratio per the Bank Credit Agreement, Consolidated Current Assets exclude the current portion of derivative assets but include available borrowing capacity under the Bank Credit Agreement, and Consolidated Current Liabilities exclude the current portion of derivative liabilities as well as the current portions of long-term indebtedness outstanding. Under these financial performance covenant calculations, as of September 30, 2017,2021, our ratio of consolidated senior securedtotal debt to consolidated EBITDAX was 1.440.05 to 1.0 (with a maximum permitted ratio of 3.03.5 to 1.0), our ratio of consolidated EBITDAX to consolidated interest charges was 2.01 to 1.0 (with a required ratio of not less than 1.25 to 1.0), and our current ratio was 2.692.60 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 November 6, 2017,3, 2021, and current oil commodity derivative futures prices, we currently anticipate continuing to be in compliance with our bankfinancial 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, each of which are filed as exhibitsis an exhibit to our periodic reportsForm 8-K Report filed with the SEC.SEC on September 18, 2020.


Capital Spending. Commitments and Obligations.We currently anticipate thathave numerous contractual commitments in the ordinary course of business including debt service requirements, operating and finance leases, purchase obligations, and asset retirement obligations. Our operating leases primarily consist of our full-year 2017 capital budget, excluding capitalized interestoffice leases. Our purchase obligations represent future cash commitments primarily for purchase contracts for CO2 captured from industrial sources, CO2 processing fees, transportation agreements and acquisitions, will be approximately $250 million, which includes approximately $55 millionwell-related costs.

Our commitments and obligations consist of those detailed as of December 31, 2020, in capitalized internal acquisition, exploration and development costs and pre-production tertiary startup costs.  This combined 2017 capital budget amount, excluding capitalized interest and acquisitions, is comprised of the following:

$135 million allocated for tertiary oil field expenditures;
$50 million allocated for other areas, primarily non-tertiary oil field expenditures;
•
$10 million to be spent on CO2 sources and pipelines; and


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our Form 10-K under Management’s Discussion and Analysis of Financial Condition and Results of Operations

$55 million for other capital items such as capitalized internal acquisition, exploration – Capital Resources and development costsLiquidity – Commitments, Obligations and pre-production tertiary startup costs.

Capital Expenditure Summary. The following table reflects incurred capital expenditures (including accrued capital) forOff-Balance Sheet Arrangements. During the nine months ended September 30, 20172021, our long-term asset retirement obligations increased by $63.8 million, primarily related to our acquisition of working interest positions in Wyoming CO2 EOR fields (see Note 2, Acquisition and 2016:Divestitures).

  Nine Months Ended
  September 30,
In thousands 2017 2016
Capital expenditures by project    
Tertiary oil fields $98,797
 $90,392
Non-tertiary fields 41,023
 19,142
Capitalized internal costs (1)
 37,732
 35,516
Oil and natural gas capital expenditures 177,552
 145,050
CO2 pipelines, sources and other
 3,246
 828
Capital expenditures, before acquisitions and capitalized interest 180,798
 145,878
Acquisitions of oil and natural gas properties 91,015
 10,888
Capital expenditures, before capitalized interest 271,813
 156,766
Capitalized interest 22,217
 18,944
Capital expenditures, total $294,030
 $175,710

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

For the nine months ended September 30, 2017, our capital expenditures and property acquisitions were funded with $142.9 million of cash flows from operations, with additional funds provided by borrowings on our Bank Credit Agreement. For the nine months ended September 30, 2016, our capital expenditures and property acquisitions were primarily funded with cash flows from operations, with additional funds provided by asset sales and borrowings on our Bank Credit Agreement.

Off-Balance Sheet Arrangements. Our off-balance sheet arrangements include operating leasesobligations for office space and various 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.  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.

The Company has a CO2 offtake agreement with Mississippi Power Company (“MSPC��), providing for our purchase of CO2 generated as a byproduct of the gasification portion of their Kemper County energy facility. After receiving minor amounts of CO2 from the facility during the first half of 2017, in June 2017, MSPC announced the immediate and indefinite suspension of startup and operations activities of the lignite coal gasification portion of the Kemper County energy facility. As a result of this suspension, the Company is not expecting to receive any CO2 from this facility for the foreseeable future. Given our Jackson Dome CO2 reserves and the increased efficiency of our CO2 usage, we do not anticipate any material impact upon our tertiary production from a lengthy or permanent absence of offtake CO2 volumes from the MSPC plant.

Our commitments and obligations consist of those detailed as of December 31, 2016, in our Form 10-K under Management’s Discussion and Analysis of Financial Condition and Results of Operations – Capital Resources and Liquidity – Commitments and Obligations.




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RESULTS OF OPERATIONS


Our tertiary operations represent a significant portionCertain of our overall operationsfinancial results for our Successor and Predecessor periods are our primary long-term strategic focus. The economicspresented in the following tables:
SuccessorPredecessor
In thousands, except per-share and unit dataThree Months Ended
Sept. 30, 2021		Period from Sept. 19, 2020 through
Sept. 30, 2020		Period from July 1, 2020 through
Sept. 18, 2020
Operating results  
Net income (loss)(1)
$82,708 $2,758 $(809,120)
Net income (loss) per common share – basic(1)
1.62 0.06 (1.63)
Net income (loss) per common share – diluted(1)
1.51 0.06 (1.63)
Net cash provided by operating activities104,019 32,910 40,597 

SuccessorPredecessor
In thousands, except per-share and unit dataNine Months Ended
Sept. 30, 2021		Period from Sept. 19, 2020 through
Sept. 30, 2020		Period from Jan. 1, 2020 through
Sept. 18, 2020
Operating results   
Net income (loss)(1)
$(64,629)$2,758 $(1,432,578)
Net income (loss) per common share – basic(1)
(1.27)0.06 (2.89)
Net income (loss) per common share – diluted(1)
(1.27)0.06 (2.89)
Net cash provided by operating activities247,557 32,910 113,408 

(1)Includes a pre-tax full cost pool ceiling test write-down of a tertiary field and the related impact on our financial statements differ from a conventional oil and natural gas play,properties of $14.4 million during the first quarter of 2021, as compared to write-downs of $261.7 million and we have outlined certain of these differences in our Form 10-K$996.7 million for the Predecessor periods July 1, 2020 through September 18, 2020 and other public disclosures. Our focus on these types of operations impacts certain trends in both current and long-term operating results. Please refer to Management’s Discussion and Analysis of Financial Condition and Results of Operations – Financial Overview of Tertiary Operations in our Form 10-K for further information regarding these matters.

January 1, 2020 through September 18, 2020, respectively. In addition, includes reorganization adjustments, net totaling $850.0 million during the 2020 Predecessor periods.


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Operating Results Table

Certain of our operating results and statistics for the comparative three and nine months endedSeptember 30, 20172021 and 20162020 are included in the following table:
Three Months EndedNine Months Ended
September 30September 30
In thousands, except per-share and unit data2021202020212020
Average daily sales volumes   
Bbls/d48,145 48,334 47,276 50,619 
Mcf/d9,222 8,110 8,739 7,916 
BOE/d(1)
49,682 49,686 48,732 51,939 
Oil and natural gas sales   
Oil sales$305,093 $174,447 $818,714 $511,562 
Natural gas sales3,361 964 7,893 2,860 
Total oil and natural gas sales$308,454 $175,411 $826,607 $514,422 
Commodity derivative contracts(2)
   
Receipt (payment) on settlements of commodity derivatives$(77,670)$17,789 $(179,466)$88,056 
Noncash fair value gains (losses) on commodity derivatives35,925 (18,363)(150,686)18,011 
Commodity derivatives income (expense)$(41,745)$(574)$(330,152)$106,067 
Unit prices – excluding impact of derivative settlements   
Oil price per Bbl$68.88 $39.23 $63.44 $36.88 
Natural gas price per Mcf3.96 1.29 3.31 1.32 
Unit prices – including impact of derivative settlements(2)
 
Oil price per Bbl$51.35 $43.23 $49.53 $43.23 
Natural gas price per Mcf3.96 1.29 3.31 1.32 
Oil and natural gas operating expenses  
Lease operating expenses$116,536 $71,192 $308,731 $261,755 
Transportation and marketing expenses5,985 9,499 22,304 28,508 
Production and ad valorem taxes23,464 13,697 63,195 40,450 
Oil and natural gas operating revenues and expenses per BOE  
Oil and natural gas revenues$67.48 $38.37 $62.13 $36.15 
Lease operating expenses25.50 15.57 23.21 18.39 
Transportation and marketing expenses1.31 2.08 1.68 2.00 
Production and ad valorem taxes5.13 3.00 4.75 2.84 
CO2 – revenues and expenses
   
CO2 sales and transportation fees
$12,237 $7,484 $31,599 $22,016 
CO2 operating and discovery expenses
(1,963)(1,197)(4,487)(2,834)
CO2 revenue and expenses, net
$10,274 $6,287 $27,112 $19,182 

(1)Barrel of oil equivalent using the ratio of one barrel of oil to six Mcf of natural gas (“BOE”).
(2)See also Commodity Derivative Contracts below and Item 3. Quantitative and Qualitative Disclosures about Market Risk for information concerning our derivative transactions.




  Three Months Ended Nine Months Ended
  September 30, September 30,
In thousands, except per-share and unit data 2017 2016 2017 2016
Operating results        
Net income (loss) (1)
 $442
 $(24,590) $36,371
 $(590,451)
Net income (loss) per common share – basic (1)
 0.00
 (0.06) 0.09
 (1.60)
Net income (loss) per common share – diluted (1)
 0.00
 (0.06) 0.09
 (1.60)
Net cash provided by operating activities 65,651
 96,415
 142,859
 159,359
Average daily production volumes  
  
  
  
Bbls/d 58,376
 59,297
 58,182
 62,451
Mcf/d 11,710
 13,416
 10,985
 15,995
BOE/d (2)
 60,328
 61,533
 60,013
 65,117
Operating revenues  
  
  
  
Oil sales $256,621
 $237,053
 $768,912
 $666,441
Natural gas sales 2,409
 2,877
 7,176
 7,960
Total oil and natural gas sales $259,030
 $239,930
 $776,088
 $674,401
Commodity derivative contracts (3)
  
  
  
  
Receipt (payment) on settlements of commodity derivatives $89
 $(7,295) $(38,618) $116,958
Noncash fair value gains (losses) on commodity derivatives (4)
 (25,352) 28,519
 48,330
 (216,769)
Commodity derivatives income (expense) $(25,263) $21,224
 $9,712
 $(99,811)
Unit prices – excluding impact of derivative settlements  
  
  
  
Oil price per Bbl $47.78
 $43.45
 $48.41
 $38.95
Natural gas price per Mcf 2.24
 2.33
 2.39
 1.82
Unit prices – including impact of derivative settlements (3)
    
  
  
Oil price per Bbl $47.80
 $42.12
 $45.98
 $45.78
Natural gas price per Mcf 2.24
 2.33
 2.39
 1.82
Oil and natural gas operating expenses    
  
  
Lease operating expenses $117,768
 $106,522
 $342,926
 $308,988
Marketing expenses, net of third-party purchases, and plant operating expenses 9,706
 11,225
 29,758
 33,707
Production and ad valorem taxes 18,418
 17,983
 57,548
 52,201
Oil and natural gas operating revenues and expenses per BOE    
  
  
Oil and natural gas revenues $46.67
 $42.38
 $47.37
 $37.80
Lease operating expenses 21.22
 18.82
 20.93
 17.32
Marketing expenses, net of third-party purchases, and plant operating expenses 1.75
 1.99
 1.82
 1.89
Production and ad valorem taxes 3.32
 3.18
 3.51
 2.93
CO2 sources – revenues and expenses
  
  
  
  
CO2 sales and transportation fees
 $6,590
 $6,253
 $18,533
 $19,147
CO2 discovery and operating expenses
 (1,346) (861) (2,452) (2,539)
CO2 revenue and expenses, net
 $5,244
 $5,392
 $16,081
 $16,608
25

(1)Includes a pre-tax full cost pool ceiling test write-down of our oil and natural gas properties of $75.5 million and $810.9 million for the three and nine months ended September 30, 2016, respectively.


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

(2)Barrel of oil equivalent using the ratio of one barrel of oil to six Mcf of natural gas (“BOE”).
(3)
See also Commodity Derivative Contracts below and Item 3. Quantitative and Qualitative Disclosures about Market Risk for information concerning our derivative transactions.
(4)
Noncash fair value gains (losses) on commodity derivatives is a non-GAAP measure and is different from “Commodity derivatives expense (income)” in the Unaudited Condensed 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 $0.1 million for the three months ended September 30, 2017 and payments on settlements of $38.6 million for the nine months ended September 30, 2017, compared to payments on settlements of $7.3 million for the three months ended September 30, 2016 and receipts on settlements of $117.0 million for the nine months ended September 30, 2016. 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 Unaudited Condensed Consolidated Statements of Operations.

Sales Volumes


Average daily sales volumes by area for each of the four quarters of 2020 and for the first three quarters of 2021 is shown below:
 Average Daily Sales Volumes (BOE/d)
First
Quarter		Second
Quarter		Third
Quarter		First
Quarter		Second
Quarter		Third
Quarter		Fourth
Quarter
Operating Area2021202120212020202020202020
Tertiary oil sales    
Gulf Coast region
Delhi2,925 2,931 2,859 3,813 3,529 3,208 3,132 
Hastings4,226 4,487 4,343 5,232 4,722 4,473 4,598 
Heidelberg4,054 3,942 3,895 4,371 4,366 4,256 4,198 
Oyster Bayou3,554 3,791 3,942 3,999 3,871 3,526 3,880 
Tinsley3,424 3,455 3,390 4,355 3,788 4,042 3,654 
Other(1)
6,098 6,074 5,907 7,161 5,944 6,271 6,332 
Total Gulf Coast region24,281 24,680 24,336 28,931 26,220 25,776 25,794 
Rocky Mountain region
Bell Creek4,614 4,394 4,330 5,731 5,715 5,551 5,079 
Other(2)
2,573 4,378 4,703 2,199 1,393 2,167 2,007 
Total Rocky Mountain region7,187 8,772 9,033 7,930 7,108 7,718 7,086 
Total tertiary oil sales31,468 33,452 33,369 36,861 33,328 33,494 32,880 
Non-tertiary oil and gas sales
Gulf Coast region
Total Gulf Coast region3,621 3,415 3,763 4,173 3,805 3,728 3,523 
Rocky Mountain region
Cedar Creek Anticline11,150 10,918 11,182 13,046 11,988 11,485 11,433 
Other(2)
1,118 1,348 1,368 1,105 1,069 979 969 
Total Rocky Mountain region12,268 12,266 12,550 14,151 13,057 12,464 12,402 
Total non-tertiary sales15,889 15,681 16,313 18,324 16,862 16,192 15,925 
Total continuing sales47,357 49,133 49,682 55,185 50,190 49,686 48,805 
Property sales
Gulf Coast Working Interests Sale(3)
— — —��780 — — — 
Total sales47,357 49,133 49,682 55,965 50,190 49,686 48,805 

(1)Includes our mature properties (Brookhaven, Cranfield, Eucutta, Little Creek, Mallalieu, Martinville, McComb and Soso fields) and West Yellow Creek Field.
(2)Includes sales volumes related to our working interest positions in the Big Sand Draw and Beaver Creek fields acquired on March 3, 2021.
(3)Includes non-tertiary sales related to the March 2020 sale of 50% of our working interests in Webster, Thompson, Manvel, and East Hastings fields (the “Gulf Coast Working Interests Sale”).

Total sales volumes during the third quarter of 2021 averaged 49,682 BOE/d, including 33,369 Bbls/d from tertiary properties and 16,313 BOE/d from non-tertiary properties. This sales volume represents a slight increase of 549 BOE/d (1%) compared to sales levels in the second quarter of 2021 and was essentially flat with third quarter of 2020 sales volumes. The increase on a sequential-quarter basis was primarily attributable to higher sales volumes at our Wind River Basin properties acquired in March 2021 and sales of non-tertiary production at Conroe Field in our Gulf Coast region.



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Production

Average daily production by area for each of the four quarters of 2016 and for the first, second, and third quarters of 2017 is shown below:
  Average Daily Production (BOE/d)

 
First
Quarter
 
Second
Quarter

Third
Quarter

Fourth
Quarter
  
First
Quarter

Second
Quarter
 
Third
Quarter
Operating Area 2016 2016
2016
2016  2017
2017 2017
Tertiary oil production               
Gulf Coast region               
Mature properties (1)
 9,666
 9,415

8,653

8,440
  8,111
 7,737
 7,450
Delhi 3,971
 3,996

4,262

4,387
  4,991
 4,965
 4,619
Hastings 5,068
 4,972

4,729

4,552
  4,288
 4,400
 4,867
Heidelberg 5,346
 5,246

5,000

4,924
  4,730
 4,996
 4,927
Oyster Bayou 5,494
 5,088

4,767

4,988
  5,075
 5,217
 4,870
Tinsley 7,899
 7,335

6,756

6,786
  6,666
 6,311
 6,506
Total Gulf Coast region 37,444

36,052

34,167

34,077
 
33,861
 33,626
 33,239
Rocky Mountain region 
 




  
 

  
Bell Creek 3,020
 3,160

3,032

3,269
  3,209
 3,060
 3,406
Salt Creek (2)
 —
 —
 —
 —
  —
 23
 2,228
Total Rocky Mountain region 3,020
 3,160

3,032

3,269
  3,209
 3,083
 5,634
Total tertiary oil production 40,464
 39,212

37,199

37,346
  37,070
 36,709
 38,873
Non-tertiary oil and gas production 

        

 

  
Gulf Coast region 

        

 

  
Mississippi 673
 1,017
 963
 745
  1,342
 1,004
 867
Texas 6,148
 4,104
 4,234
 5,143
  4,333
 5,002
 4,024
Other 549
 456
 538
 569
  495
 460
 515
Total Gulf Coast region 7,370
 5,577

5,735

6,457
  6,170

6,466
 5,406
Rocky Mountain region 
        
 
  
Cedar Creek Anticline 17,778
 16,325

16,017

15,186
  15,067

15,124
 14,535
Other 2,070
 1,862

1,763

1,696
  1,626

1,475
 1,514
Total Rocky Mountain region 19,848
 18,187

17,780

16,882
  16,693

16,599
 16,049
Total non-tertiary production 27,218
 23,764

23,515

23,339
 
22,863

23,065
 21,455
Total continuing production 67,682
 62,976

60,714

60,685
  59,933

59,774
 60,328
Property sales 
        
 
  
2016 property divestitures (3)
 1,669
 1,530
 819
 —
  —
 —
 —
Total production 69,351
 64,506
 61,533
 60,685
  59,933
 59,774
 60,328

(1)Mature properties include Brookhaven, Cranfield, Eucutta, Little Creek, Lockhart Crossing, 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 in the Rocky Mountain region related to the sale of remaining non-core assets in the Williston Basin of North Dakota and Montana, which closed in the third quarter of 2016, and other minor property divestitures.




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Total Production

Total continuing production during the third quarter of 2017 averaged 60,328 BOE/d, including 38,873 Bbls/d from tertiary properties and 21,455 BOE/d from non-tertiary properties. Total continuing production during 2016 excludes production from the Williston Assets that were sold during the third quarter of 2016 and other minor property divestitures, which production totaled 819 BOE/d during the third quarter of 2016. This total continuing production level was a slight increase of 554 BOE/d (1%) compared to second quarter of 2017 production levels of 59,774 BOE/d and represents a slight decrease of 386 BOE/d (1%) compared to third quarter of 2016 production levels. Due to conditions associated with Hurricane Harvey, the Company suspended operations and temporarily shut-in all production at its Houston area fields for an approximate 10-day period beginning August 27, 2017, representing net production of approximately 16,000 BOE/d. The impacted fields included Hastings, Oyster Bayou, Conroe, Thompson, Webster and Manvel.  Approximately 90% of the 16,000 BOE/d of net production shut-in had returned to production by September 6th, and the only field that remained partially shut-in was Thompson Field. Thompson Field had net production just prior to the storm of approximately 1,000 BOE/d, nearly all of which has now been returned to production. The impact of Hurricane Harvey on third quarter 2017 production was approximately 2,000 BOE/d, and the full-year impact on 2017 production is expected to be between 500 and 700 BOE/d.

Our productionsales volumes during the three and nine months ended September 30, 2017 was2021 were 97% oil, slightly higher thanconsistent with our 96% oil productionsales during the three and nine months ended September 30, 2016.same prior-year periods.

Tertiary Production

Oil production from our tertiary operations during the third quarter of 2017 increased 2,164 Bbls/d (6%) when comparing the second and third quarters of 2017 and increased 1,674 Bbls/d (5%) compared to the same period in 2016. The sequential and year-over-year increases in production were primarily due to the acquisition of a 23% non-operated working interest in Salt Creek Field during the second quarter of 2017, as well as the CO2 enhanced oil recovery response from phase 5 development at Bell Creek Field and the redevelopment project at Hastings Field. The increases were slightly offset by natural production declines at our mature fields in the Gulf Coast region and the weather-related downtime at our Houston area fields resulting from Hurricane Harvey, as noted above.

Non-Tertiary Production

Continuing production from our non-tertiary operations averaged 21,455 BOE/d during the third quarter of 2017, a decrease of 1,610 BOE/d (7%) compared to the second quarter of 2017 and a decrease of 2,060 BOE/d (9%) compared to the third quarter of 2016 levels. The sequential and year-over-year decreases were primarily due to natural production declines at Cedar Creek Anticline and the weather-related downtime at our Houston area fields resulting from Hurricane Harvey, as noted above.


Oil and Natural Gas Revenues


Our oil and natural gas revenues during the three and nine months ended September 30, 20172021 increased 8%76% and 15%61%, respectively, compared to these revenues for the same periods in 2016.2020.  The changes in our oil and natural gas revenues are due primarily to changes in production quantities andhigher realized commodity prices (excluding any impact of our commodity derivative contracts), with the change during the nine months ended September 30, 2021 offset somewhat by changes in sales volumes, as reflected in the following table:
Three Months EndedNine Months Ended
September 30,September 30,
2021 vs. 20202021 vs. 2020
In thousandsIncrease (Decrease) in RevenuesPercentage Increase in RevenuesIncrease (Decrease) in RevenuesPercentage Increase (Decrease) in Revenues
Change in oil and natural gas revenues due to:    
Decrease in sales volumes$(14)0 %$(33,517)(6)%
Increase in realized commodity prices133,057 76 %345,702 67 %
Total increase in oil and natural gas revenues$133,043 76 %$312,185 61 %
  Three Months Ended Nine Months Ended
  September 30, September 30,
  2017 vs. 2016 2017 vs. 2016
In thousands Increase (Decrease) in Revenues Percentage Increase (Decrease) in Revenues Increase (Decrease) in Revenues Percentage Increase (Decrease) in Revenues
Change in oil and natural gas revenues due to:        
Decrease in production $(4,700) (2)% $(55,128) (8)%
Increase in commodity prices 23,800
 10 % 156,815
 23 %
Total increase in oil and natural gas revenues $19,100
 8 % $101,687
 15 %


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



Excluding any impact of our commodity derivative contracts, our average net realized commodity prices and NYMEX differentials were as follows during each of the first quarters, second quarters, thirdthree quarters and nine months ended September 30, 20172021 and 2016:2020:
Three Months EndedNine Months Ended
March 31,June 30,September 30,September 30,
 20212020202120202021202020212020
Average net realized prices      
Oil price per Bbl$56.28 $45.96 $64.70 $24.39 $68.88 $39.23 $63.44 $36.88 
Natural gas price per Mcf3.29 1.46 2.64 1.21 3.96 1.29 3.31 1.32 
Price per BOE55.24 45.09 63.23 23.95 67.48 38.37 62.13 36.15 
Average NYMEX differentials     
Gulf Coast region
Oil per Bbl$(1.37)$1.18 $(1.13)$(3.59)$(1.77)$(1.38)$(1.40)$(0.86)
Natural gas per Mcf0.68 (0.06)(0.11)(0.09)0.16 (0.06)0.26 (0.07)
Rocky Mountain region
Oil per Bbl$(1.80)$(2.78)$(1.59)$(4.68)$(1.72)$(2.03)$(1.49)$(2.89)
Natural gas per Mcf0.49 (0.91)(0.47)(1.04)(0.65)(1.74)(0.22)(1.25)
Total Company
Oil per Bbl$(1.54)$(0.38)$(1.32)$(4.03)$(1.75)$(1.64)$(1.44)$(1.67)
Natural gas per Mcf0.58 (0.41)(0.33)(0.54)(0.33)(0.83)(0.02)(0.60)
  Three Months Ended Nine Months Ended
  March 31, June 30, September 30, September 30,
  2017 2016 2017 2016 2017 2016 2017 2016
Average net realized prices:                
Oil price per Bbl $50.31
 $30.71
 $47.16
 $43.38
 $47.78
 $43.45
 $48.41
 $38.95
Natural gas price per Mcf 2.50
 1.70
 2.46
 1.50
 2.24
 2.33
 2.39
 1.82
Price per BOE 49.35
 29.76
 46.12
 42.02
 46.67
 42.38
 47.37
 37.80
Average NYMEX differentials:  
  
  
  
  
  
  
  
Oil per Bbl $(1.64) $(3.02) $(1.16) $(2.18) $(0.34) $(1.57) $(1.04) $(2.51)
Natural gas per Mcf (0.57) (0.29) (0.69) (0.73) (0.72) (0.47) (0.67) (0.53)


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. Our corporate-wide oil differential during the third quarter of 2017 was $0.34 per Bbl below NYMEX prices, which represents the best differential we have realized since the third quarter of 2013. Additional information about our oil differentials in the

•Gulf Coast and Rocky Mountain regions are discussed in further detail below.

Region. Our average NYMEX oil differential in the Gulf Coast region was a positive $0.01 per Bbl and a negative $0.77$1.77 per Bbl during the third quartersquarter of 2017 and 2016, respectively,2021, compared to a negative $1.38 per Bbl during the third quarter of 2020 and a negative $0.78$1.13 per Bbl during the second quarter of 2017. These differentials are impacted significantly by2021. NYMEX WTI oil prices continued to strengthen during the changes in prices receivedthird quarter of 2021; however, the pricing for our Gulf Coast grades weakened relative to NYMEX WTI index prices. For

27

Denbury Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
our crude oil sold under LLSLight Louisiana Sweet (“LLS”) index prices, relative to the change in NYMEX prices, as well as various other price adjustments such as those noted above.  The quarterly average LLS-to-NYMEX differential (onaveraged a positive $0.98 per Bbl on a trade-month basis) wasbasis for the third quarter of 2021, compared to a positive $2.37$1.52 per Bbl differential in the third quarter of 2017, an increase from the2020 and a positive $1.73 per Bbl in the third quarter of 2016 and positive $1.95$2.10 per Bbl in the second quarter of 2017. During the third quarter of 2017, we sold approximately 65% of our crude oil at prices based on, or partially tied to, the LLS index price, and the balance at prices based on various other indexes tied to NYMEX prices, primarily in the 2021.

•Rocky Mountain region.

Region. NYMEX oil differentials in the Rocky Mountain region averaged $0.98$1.72 per Bbl and $3.08$2.03 per Bbl below NYMEX during the third quarters of 20172021 and 2016,2020, respectively, and $1.96$1.59 per Bbl below NYMEX during the second quarter of 2017.2021. Differentials in the Rocky Mountain region tend to fluctuate with regional supply and demand trends and 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 CO2 produced 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 operating and discovery expenses” in our Unaudited Condensed Consolidated Statements of Operations. CO2 sales and transportation fees were $12.2 million and $31.6 million during the three and nine months ended September 30, 2021, respectively, compared to $7.5 million and $22.0 million during the combined Predecessor and Successor periods included within the three and nine-month periods ended September 30, 2020, respectively. The increases from the prior-year periods were primarily due to an increase in CO2 sales volumes to our industrial CO2 customers.

Oil Marketing Revenues and Purchases

In certain situations, we purchase and subsequently sell oil from third parties. We recognize the revenue received and the associated expenses incurred on these sales on a gross basis as “Oil marketing revenues” and “Oil marketing purchases” in our Unaudited Condensed Consolidated Statements of Operations.

Commodity Derivative Contracts


The following table summarizestables summarize the impact our crude oil derivative contracts had on our operating results for the three and nine months endedSeptember 30, 20172021 and 2016:2020:
SuccessorPredecessor
In thousandsThree Months Ended
Sept. 30, 2021		Period from Sept. 19, 2020 through
Sept. 30, 2020		Period from July 1, 2020 through
Sept. 18, 2020
Receipt (payment) on settlements of commodity derivatives$(77,670)$6,660 $11,129 
Noncash fair value gains (losses) on commodity derivatives35,925 (2,625)(15,738)
Total income (expense)$(41,745)$4,035 $(4,609)

SuccessorPredecessor
In thousandsNine Months Ended
Sept. 30, 2021		Period from Sept. 19, 2020 through
Sept. 30, 2020		Period from Jan. 1, 2020 through
Sept. 18, 2020
Receipt (payment) on settlements of commodity derivatives$(179,466)$6,660 $81,396 
Noncash fair value gains (losses) on commodity derivatives(1)
(150,686)(2,625)20,636 
Total income (expense)$(330,152)$4,035 $102,032 

Changes in our commodity derivatives expense were primarily related to the expiration of commodity derivative contracts, new commodity derivative contracts entered into for future periods, and to the changes in oil futures prices between the third quarters of 2020 and 2021. The period-to-period changes reflect the very large fluctuations in oil prices between March 2020 ($30.45 per barrel), when worldwide financial markets were first beginning to absorb the potential impact of a global pandemic,

  Three Months Ended Nine months ended
  September 30, September 30,
In thousands 2017 2016 2017 2016
Receipt (payment) on settlements of commodity derivatives $89
 $(7,295) $(38,618) $116,958
Noncash fair value gains (losses) on commodity derivatives (1)
 (25,352) 28,519
 48,330
 (216,769)
Total income (expense) $(25,263) $21,224
 $9,712
 $(99,811)
28



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Denbury Resources Inc.
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(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 Unaudited Condensed Consolidated Statements of Operations.

and September 2021 oil prices ($71.54 per barrel) as prospects for increased economic activity and oil demand showed improvement.


Largely based on the hedging requirements that we were obligated to meet under our bank credit facility, which required certain minimum commodity hedge levels through July 31, 2022, we have oil commodity hedges in place for a portion of our estimated oil production through 2022 using NYMEX fixed-price swaps and costless collars. We do not have any additional hedging requirements under our Bank Credit Agreement. See Note 6, Commodity Derivative Contracts, to the Unaudited Condensed Consolidated Financial Statements for additional details of our outstanding commodity derivative contracts as of September 30, 2021, and Item 3, Quantitative and Qualitative Disclosures about Market Risk below for additional discussion. In addition, the following table summarizes our commodity derivative contracts as of November 3, 2021:
4Q 20211H 20222H 2022
WTI NYMEXVolumes Hedged (Bbls/d)29,00015,5009,000
Fixed-Price Swaps
Swap Price(1)
$43.86$49.01$56.35
WTI NYMEXVolumes Hedged (Bbls/d)4,00011,00010,000
Collars
Floor / Ceiling Price(1)
$46.25 / $53.04$49.77 / $64.31$49.75 / $64.18
Total Volumes Hedged (Bbls/d)33,00026,50019,000

(1)Averages are volume weighted.

Based on current contracts in place and NYMEX oil futures prices as of November 3, 2021, which averaged approximately $81 per Bbl, we currently expect that we would make cash payments of approximately $110 million upon settlement of our October through December 2021 contracts, the amount of which is primarily dependent upon fluctuations in future NYMEX oil prices in relation to the prices of our remaining 2021 fixed-price swaps which have a weighted average NYMEX oil price of $43.86 per Bbl. 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
SuccessorPredecessor
In thousands, except per-BOE dataThree Months Ended
Sept. 30, 2021		Period from Sept. 19, 2020 through
Sept. 30, 2020		Period from July 1, 2020 through
Sept. 18, 2020
Total lease operating expenses$116,536 $11,484 $59,708 
Total lease operating expenses per BOE$25.50 $19.20 $15.03 

SuccessorPredecessor
In thousands, except per-BOE dataNine Months Ended
Sept. 30, 2021		Period from Sept. 19, 2020 through
Sept. 30, 2020		Period from Jan. 1, 2020 through
Sept. 18, 2020
Total lease operating expenses$308,731 $11,484 $250,271 
Total lease operating expenses per BOE$23.21 $19.20 $18.36 



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In order to provide a level of price protection to a portion of our oil production, we have entered into a combination of oil swaps, basis swaps, collars, and three-way collars for the fourth quarter of 2017 and throughout 2018. The following table summarizes our commodity derivative contracts as of November 6, 2017:
  Oct - 17Nov - 17Dec - 171H 20182H 2018
WTI NYMEXVolumes Hedged (Bbls/d)12,00012,00012,00015,50015,500
Fixed-Price Swaps
Swap Price (1)
$49.76$49.76$49.76$50.13$50.13
WTI NYMEXVolumes Hedged (Bbls/d)1,0001,0001,000——
Collars
Ceiling Price / Floor (1)
$70 / $40$70 / $40$70 / $40——
WTI NYMEXVolumes Hedged (Bbls/d)14,00014,00014,00015,00015,000
3-Way Collars
Ceiling Price / Floor / Sold Put Price (1)(2)
$65.79 / $41.07 / $31.07$65.79 / $41.07 / $31.07$65.79 / $41.07 / $31.07$53.88 / $46.50 / $36.50$53.88 / $46.50 / $36.50
Argus LLSVolumes Hedged (Bbls/d)1,0001,0001,000——
3-Way Collars
Ceiling Price / Floor / Sold Put Price (1)(2)
$70.25 / $41 / $31$70.25 / $41 / $31$70.25 / $41 / $31——
 Total Volumes Hedged (Bbls/d)28,00028,00028,00030,50030,500
       
Argus LLSVolumes Hedged (Bbls/d)——20,00020,000—
Basis Swaps (3)
Swap Price (1)
——$4.16$4.17—

(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.
(3)The basis swap contracts establish a fixed amount for the differential between Argus WTI and Argus LLS prices on a trade-month basis for the periods indicated.
Commodity derivative contracts in place for the fourth quarter of 2017 include swaps, basis swaps, collars and three-way collars. Based on current contracts in place and NYMEX oil futures prices as of November 6, 2017, which average in the mid-$50’s per Bbl for the remainder of 2017, limited settlements are currently expected during the fourth quarter of 2017. The details of our outstanding commodity derivative contracts at September 30, 2017, are included in Note 5, Commodity Derivative Contracts, to the Unaudited Condensed Consolidated Financial Statements. Additionally, with the recent improvement in the basis differential between LLS and WTI pricing, we entered into basis swap contracts to lock-in that differential for a portion of our estimated oil production beginning December 2017 through the first half of 2018. Currently, our hedges in place for 2018 represent roughly half of our third quarter 2017 production levels. Depending on market conditions, we may continue to add to our existing 2018 hedges, and we may start to layer in hedges for 2019. Also, see Item 3, Quantitative and Qualitative Disclosures about Market Risk below for additional discussion on our commodity derivative contracts.

Production Expenses

Lease Operating Expenses
  Three Months Ended Nine Months Ended
  September 30, September 30,
In thousands, except per-BOE data 2017 2016 2017 2016
Total lease operating expenses $117,768
 $106,522
 $342,926
 $308,988
         
Total lease operating expenses per BOE $21.22
 $18.82
 $20.93
 $17.32

Total lease operating expenses increased $11.2were $116.5 million, (11%)or $25.50 per BOE, during the three months ended September 30, 2021, compared to $71.2 million, or $15.57 per BOE, for the combined Predecessor and $33.9Successor periods included within the three months ended September 30, 2020. Total lease operating expenses were $308.7 million, (11%)or $23.21 per BOE, during the nine months ended September 30, 2021, compared to $261.8 million, or $18.39, for the combined Predecessor and Successor periods included within the nine months ended September 30, 2020. The increases on an absolute-dollar basis or $2.40 (13%) and$3.61 (21%) on per-BOE basis were primarily due to (a) an insurance reimbursement totaling $15.4 million recorded in the third quarter of 2020 for previously-incurred well control costs, cleanup costs, and damages associated with a per-BOE basis,2013 incident at Delhi Field (b) $8.1 million and $17.0 million of expense during the three and nine months ended September 30, 2017,2021, respectively, compared to levels in the same periods in 2016. Our lease operating expenses during the comparative third quarter periods were primarily impacted by operating expenses related to the Wind River Basin acquisition in March 2021, as these properties have higher operating costs than our non-operated working interestother fields (c) higher expenses across nearly all expense categories as our costs are correlated to varying degrees with changes in Salt Creek Field, which was acquired on June 30, 2017,oil prices (reflecting rising oil prices in 2021) and (d) 2020 period reduced spending and shut-in production in response to a lesser degree by additional expenses related to Hurricane Harveysignificantly lower oil prices in the third quarter of 20172020. Lease operating expenses for the nine months ended September 30, 2021 were offset by a $7.6 million reduction in power and higher CO2 expense due tofuel costs. The significant reduction in power and fuel costs was associated with the severe winter storm in February 2021 which created widespread power outages in Texas and disrupted the Company’s operations. Under certain of the Company’s power agreements the Company is compensated for its reduced power usage, which resulted in a CO2 well workover during the third quarter of 2017. Offsetting these increases were lower expenses across various


26

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

categories, a portion of which is duebenefit to the downtime associated with fields impacted by Hurricane Harvey. The increase during the comparative nine-month periods was further impacted by increased workoverCompany of approximately $16.1 million; as of September 30, 2021; $10.3 million of these savings were included in “Trade and other repair activity at certain fields, as workover activity was significantly curtailed during 2016 duereceivables, net” and $1.7 million included in “Other assets” in our Unaudited Condensed Consolidated Balance Sheets. Compared to the lower oil price environment. Onsecond quarter of 2021, lease operating expenses in the most recent quarter increased $6.3 million (6%) on an absolute-dollar basis and $0.85 (3%) on a per-BOE basis, our lease operating expenses have been impacted given lower production due primarily to Hurricane Harveyhigher power and the acquisition of Salt Creek Field, which has a higher operating cost than our corporate average.fuel costs and contract labor.


Currently, our CO2 expense comprises approximately 20% of our typical tertiary lease operating expenses,Transportation 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 third quarters of 2017 and 2016, approximately 55% and 57%, respectively, 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, including taxes paid on CO2 production but excluding depletion, depreciation and amortization of capital expended at our CO2 source fields and industrial sources, our average cost of CO2 was approximately $0.46 per Mcf during the third quarter of 2017, compared to $0.38 per Mcf during the third quarter of 2016 and the second quarter of 2017. These increases were primarily attributable to a CO2 well workover completed during the third quarter of 2017.

Marketing and Plant Operating Expenses


MarketingTransportation and plant operatingmarketing expenses primarily consist of amounts incurred relating to the transportation, marketing, processing, and transportationprocessing of oil and natural gas production,production. Transportation and to a lesser extent expenses related to our Riley Ridge gas processing facility. Marketing and plant operatingmarketing expenses were $11.8 million and $14.5$6.0 million for the three months ended September 30, 20172021, compared to $9.5 million for the combined Predecessor and 2016, respectively,Successor periods included within the three months ended September 30, 2020. Transportation and $39.8 million and $40.6marketing expenses were $22.3 million for the nine months ended September 30, 20172021, compared to $28.5 million for the combined Predecessor and 2016, respectively.Successor periods included within the nine months ended September 30, 2020. The decrease during the comparative three-month periods was primarily due to changes to a portion of our transportation agreements in the Rocky Mountain region during the third quarter of 2021 to begin selling our production at Guernsey, Wyoming versus Cushing, Oklahoma. The decrease between the comparative nine-month periods was primarily due to lower sales volumes during 2021.


Taxes Other Than Income


Taxes other than income includes production, ad valorem and franchise taxes. Taxes other than income was relatively unchangedwere $24.2 million during the three months ended September 30, 20172021, compared to $15.5 million for the same prior-year periodcombined Predecessor and increased $2.9Successor periods included within the three months ended September 30, 2020. Taxes other than income were $65.5 million (5%) during the nine months ended September 30, 20172021, compared to $45.6 million for the same periodcombined Predecessor and Successor periods included within the nine months ended September 30, 2020. The increases in 2016,both periods when compared to 2020 were due primarily to an increase in production taxes resulting from higher oil and natural gas revenues.

General and Administrative Expenses (“G&A”)

  Three Months Ended Nine Months Ended
  September 30, September 30,
In thousands, except per-BOE data and employees 2017 2016 2017 2016
Gross cash compensation and administrative costs $64,104
 $60,532
 $193,853
 $202,012
Gross stock-based compensation 4,252
 7,034
 15,684
 14,159
Operator labor and overhead recovery charges (32,211) (32,180) (96,319) (100,178)
Capitalized exploration and development costs (8,872) (10,743) (31,915) (34,904)
Net G&A expense $27,273
 $24,643
 $81,303
 $81,089
         
G&A per BOE:  
  
  
  
Net administrative costs $4.32
 $3.37
 $4.22
 $4.04
Net stock-based compensation 0.59
 0.98
 0.74
 0.50
Net G&A expenses $4.91
 $4.35
 $4.96
 $4.54
         
Employees as of September 30 897
 1,050
    
30

Our gross G&A expenses on an absolute-dollar basis were relatively flat during the three months ended September 30, 2017 and decreased $6.6 million (3%) during the nine months ended September 30, 2017 compared to the same periods in 2016, respectively. As part of our continued efforts to reduce overhead and operating costs, we reduced our employee headcount through


27


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


involuntary workforce reductions in each of the last three years, which contributed to an overall headcount reduction of approximately 40% from year-end 2014 levels. The severance-related payments associated with the workforce reductions were approximately $6.8 million for 2017, recognized in the third quarter of 2017,General and $9.3 million for 2016, recognized in the first quarter of 2016. The nine-month period ended September 30, 2017 was further impacted by lower professional services fees, partially offset by compensation associated with the retirement of our chief executive officer.Administrative Expenses (“G&A”)

SuccessorPredecessor
In thousands, except per-BOE data and employeesThree Months Ended
Sept. 30, 2021		Period from Sept. 19, 2020 through
Sept. 30, 2020		Period from July 1, 2020 through
Sept. 18, 2020
Cash G&A costs$12,832 $1,735 $14,442 
Stock-based compensation2,556 — 571 
G&A expense$15,388 $1,735 $15,013 
G&A per BOE  
Cash G&A costs$2.81 $2.90 $3.64 
Stock-based compensation0.56 — 0.14 
G&A expenses$3.37 $2.90 $3.78 
Employees as of period end698663 662 
Net
SuccessorPredecessor
In thousands, except per-BOE dataNine Months Ended
Sept. 30, 2021		Period from Sept. 19, 2020 through
Sept. 30, 2020		Period from Jan. 1, 2020 through
Sept. 18, 2020
Cash G&A costs$40,033 $1,735 $44,411 
Stock-based compensation22,788 — 4,111 
G&A expense$62,821 $1,735 $48,522 
G&A per BOE   
Cash G&A costs$3.01 $2.90 $3.26 
Stock-based compensation1.71 — 0.30 
G&A expenses$4.72 $2.90 $3.56 

Our G&A expense on a per-BOEan absolute-dollar basis increased 13% and 9% during the three and nine months ended September 30, 2017, respectively, compared to levels in the same periods in 2016 due to lower capitalized exploration and development costs and lower production volumes during the 2017 periods, partially offset by the items previously mentioned impacting gross G&A. The three-month period was further impacted by the severance-related payments noted above.

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 gas production, exploration, and development activities.

Interest and Financing Expenses
  Three Months Ended Nine Months Ended
  September 30, September 30,
In thousands, except per-BOE data and interest rates 2017 2016 2017 2016
Cash interest (1)
 $45,110
 $42,718
 $130,962
 $130,511
Less: interest on 2021 Senior Secured Notes not reflected as interest for financial reporting purposes (1)
 (12,604) (12,533) (37,761) (19,569)
Noncash interest expense 1,456
 1,468
 4,801
 11,009
Less: capitalized interest (9,416) (6,875) (22,217) (18,944)
Interest expense, net $24,546
 $24,778
 $75,785
 $103,007
Interest expense, net per BOE $4.42
 $4.38
 $4.63
 $5.77
Average debt principal outstanding $2,971,205
 $2,798,660
 $2,887,010
 $3,042,807
Average interest rate (2)
 6.1% 6.1% 6.0% 5.7%

(1)
Cash interest is presented on an accrual basis, and includes the portion of interest on our 2021 Senior Secured Notes (interest on which is to be paid semiannually May 15 and November 15 of each year) versus the GAAP financial statement presentation in which interest on these notes is accounted for as debt and not reflected as interest for financial reporting purposes in accordance with Financial Accounting Standards Board Codification 470-60, Troubled Debt Restructuring by Debtors.
(2)Includes commitment fees but excludes debt issue costs and amortization of discount or premium.

As reflected in the table above, cash interest$15.4 million during the three months ended September 30, 2017 increased $2.42021, a decrease of $1.4 million (6%(8%) whenfrom the combined Predecessor and Successor periods included within the three months ended September 30, 2020. The decrease in G&A expense during the three months ended September 30, 2021 compared to 2020, was primarily due to higher operator labor and overhead recovery charges in the prior-yearcurrent period, due primarily to apartially offset by higher average interest rate and higher borrowingslong-term incentives for employees. Our G&A expenses on our senior secured bank credit facility during the 2017 period. Interest on 2021 Senior Secured Notes not reflected as interest for financial reporting purposes increasedan absolute-dollar basis were $62.8 million during the nine months ended September 30, 2017 when compared to2021, an increase of $12.6 million (25%) from the 2016 period, ascombined Predecessor and Successor periods within the exchange transactions were completed during May 2016; therefore, the 2016 period does not include a full year of future interest on the 2021 Senior Secured Notes. Noncash interest expensenine months ended September 30, 2020. The increase in our G&A expenses during the nine months ended September 30, 2017 decreased when compared to the same prior-year period2021 was primarily due to $15.3 million of stock-based compensation expense in the 2016 period including a $5.5 million write-offfirst quarter of debt issuance costs. Capitalized interest during2021 resulting from the three and nine months ended September 30, 2017 increased $2.5 million (37%) and $3.3 million (17%), respectively, comparedfull vesting of performance-based equity awards with vesting parameters tied to the same periods in 2016, primarily dueCompany’s common stock trading prices, partially offset by higher operator labor and overhead recovery charges. The shares underlying these awards are not currently outstanding as actual delivery of the shares is not scheduled to an increase inoccur until after the numberend of projects that qualify for interest capitalization.the performance period, December 4, 2023.





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

Interest and Financing Expenses
 SuccessorPredecessor
In thousands, except per-BOE data and interest ratesThree Months Ended
Sept. 30, 2021		Period from Sept. 19, 2020 through
Sept. 30, 2020		Period from July 1, 2020 through
Sept. 18, 2020
Cash interest(1)
$1,233 $403 $17,734 
Less: interest not reflected as expense for financial reporting purposes(1)
— — (6,976)
Noncash interest expense685 114 347 
Amortization of debt discount(2)
— — 1,303 
Less: capitalized interest(1,249)(183)(4,704)
Interest expense, net$669 $334 $7,704 
Interest expense, net per BOE$0.15 $0.56 $1.94 
Average debt principal outstanding(3)
$55,667 $185,877 $815,025 
Average cash interest rate(4)
8.9 %6.6 %10.0 %

 SuccessorPredecessor
In thousands, except per-BOE data and interest ratesNine Months Ended
Sept. 30, 2021		Period from Sept. 19, 2020 through
Sept. 30, 2020		Period from Jan. 1, 2020 through
Sept. 18, 2020
Cash interest(1)
$4,902 $403 $108,824 
Less: interest not reflected as expense for financial reporting purposes(1)
— — (49,243)
Noncash interest expense2,055 114 2,439 
Amortization of debt discount(2)
— — 9,132 
Less: capitalized interest(3,500)(183)(22,885)
Interest expense, net$3,457 $334 $48,267 
Interest expense, net per BOE$0.26 $0.56 $3.54 
Average debt principal outstanding(3)
$99,243 $185,877 $1,767,605 
Average cash interest rate(4)
6.6 %6.6 %8.6 %
(1)Cash interest during the Predecessor periods includes the portion of interest on certain debt instruments accounted for as a reduction of debt for GAAP financial reporting purposes in accordance with FASC 470-60, Troubled Debt Restructuring by Debtors. The portion of interest treated as a reduction of debt related to the Predecessor’s 9% Senior Secured Second Lien Notes due 2021 (the “2021 Notes”) and 9¼% Senior Secured Second Lien Notes due 2022 (the “2022 Notes”). Amounts related to the 2021 Notes and 2022 Notes remaining in future interest payable were written-off on July 30, 2020 (the “Petition Date”).
(2)Represents amortization of debt discounts during the Predecessor periods related to the 7¾% Senior Secured Second Lien Notes due 2024 (the “7¾% Senior Secured Notes”) and 6⅜% Convertible Senior Notes due 2024 (the “2024 Convertible Senior Notes”). Remaining debt discounts were written-off on the Petition Date.
(3)Excludes debt discounts related to the Predecessor’s 7¾% Senior Secured Notes and 2024 Convertible Senior Notes.
(4)Includes commitment fees but excludes debt issue costs and amortization of discount.

Cash interest was $1.2 million during the three months ended September 30, 2021, compared to $18.1 million for the combined Predecessor and Successor periods included within the three months ended September 30, 2020. Cash interest was $4.9 million during the nine months ended September 30, 2021, compared to $109.2 million for the combined Predecessor and Successor periods included within the nine months ended September 30, 2020. The decreases between periods were primarily due to a decrease in the average debt principal outstanding, with the Successor periods reflecting the full extinguishment of all outstanding obligations under our previously outstanding senior secured second lien notes, convertible senior notes, and senior subordinated notes on the Emergence Date, pursuant to the terms of the prepackaged joint plan of reorganization, relieving us of approximately $2.1 billion of debt by issuing equity and/or warrants in the Successor period to the holders of that debt.

32

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

Depletion, Depreciation, and Amortization (“DD&A”)
 SuccessorPredecessor
In thousands, except per-BOE dataThree Months Ended
Sept. 30, 2021		Period from Sept. 19, 2020 through
Sept. 30, 2020		Period from July 1, 2020 through
Sept. 18, 2020
Oil and natural gas properties$29,269 $4,105 $21,636 
CO2 properties, pipelines, plants and other property and equipment
8,422 1,178 12,890 
Accelerated depreciation charge(1)
— — 1,791 
Total DD&A$37,691 $5,283 $36,317 
DD&A per BOE  
Oil and natural gas properties$6.40 $6.86 $5.45 
CO2 properties, pipelines, plants and other property and equipment
1.85 1.97 3.24 
Accelerated depreciation charge(1)
— — 0.45 
Total DD&A cost per BOE$8.25 $8.83 $9.14 
Write-down of oil and natural gas properties$— $— $261,677 
  Three Months Ended Nine Months Ended
  September 30, September 30,
In thousands, except per-BOE data 2017 2016 2017 2016
Oil and natural gas properties $29,990
 $29,353
 $86,973
 $120,174
CO2 properties, pipelines, plants and other property and equipment
 22,111
 25,659
 67,475
 78,745
Total DD&A $52,101
 $55,012
 $154,448
 $198,919
         
DD&A per BOE:  
  
  
  
Oil and natural gas properties $5.40
 $5.24
 $5.31
 $6.79
CO2 properties, pipelines, plants and other property and equipment
 3.99
 4.48
 4.12
 4.36
Total DD&A cost per BOE $9.39
 $9.72
 $9.43
 $11.15
         
Write-down of oil and natural gas properties $—
 $75,521
 $—
 $810,921


 SuccessorPredecessor
In thousands, except per-BOE dataNine Months Ended
Sept. 30, 2021		Period from Sept. 19, 2020 through
Sept. 30, 2020		Period from Jan. 1, 2020 through
Sept. 18, 2020
Oil and natural gas properties$89,834 $4,105 $104,495 
CO2 properties, pipelines, plants and other property and equipment
23,688 1,178 44,939 
Accelerated depreciation charge(1)
— — 39,159 
Total DD&A$113,522 $5,283 $188,593 
DD&A per BOE   
Oil and natural gas properties$6.75 $6.86 $7.66 
CO2 properties, pipelines, plants and other property and equipment
1.78 1.97 3.30 
Accelerated depreciation charge(1)
— — 2.87 
Total DD&A cost per BOE$8.53 $8.83 $13.83 
Write-down of oil and natural gas properties$14,377 $— $996,658 
The decrease in our oil
(1)Represents an accelerated depreciation charge related to capitalized amounts associated with unevaluated properties that were transferred to the full cost pool.

DD&A expense was $37.7 million during the three months ended September 30, 2021, compared to $41.6 million for the combined Predecessor and natural gas properties depletionSuccessor periods included within the three months ended September 30, 2020. DD&A expense was $113.5 million during the nine months ended September 30, 2017 when2021, compared to $193.9 million for the combined Predecessor and Successor periods within the nine months ended September 30, 2020. The decreases during the three and nine-month periods ended September 30, 2021 compared to the same period in 2016 wascomparable 2020 periods were primarily due to a reduction inlower depletable costs associateddue to the step down in book value resulting from fresh start accounting as of September 18, 2020, with our reserves base resulting fromthe year-over-

33

Denbury Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
year decrease further impacted by accelerated depreciation of $37.4 million in the first quarter of 2020 related to unevaluated properties that were transferred to the full cost pool ceiling test write-downs recognized during 2016 and an overall reduction in future development costs, partially offset by reductions in proved oil and natural gas reserve quantities. The per-BOE decrease was also partially offset by a decrease in production volumes during 2017 when compared to production in the 2016 period.pool.


The decrease in depletion and depreciation of our CO2 properties, pipelines, plants and other property and equipment was primarily due to a decrease in plant depreciation due to the accelerated depreciation charge at the Riley Ridge gas processing facility during the fourth quarter of 2016.Full Cost Pool Ceiling Test Write-Downs


2016 Write-Down of Oil and Natural Gas Properties

Under full cost accounting rules, we are required each quarter to perform a ceiling test calculation. Under these rules, the full cost ceiling value is calculated using the average first-day-of-the-month oil and natural gas price for each month during a 12-month rolling period ended asprior to the end of each quarterlya particular reporting period. We recognized a full cost pool ceiling test write-down of $14.4 million during the three months ended March 31, 2021, with first-day-of-the-month NYMEX oil prices for the preceding 12 months averaging $36.40 per Bbl, after adjustments for market differentials and transportation expenses by field. The fallingwrite-down was primarily a result of the March 2021 acquisition of Wyoming property interests (see Overview – March 2021 Acquisition of Wyoming CO2 EOR Fields) which was recorded based on a valuation that utilized NYMEX strip oil prices in 2016, relativeat the acquisition date, which were significantly higher than the average first-day-of-the-month NYMEX oil prices used to 2015 prices, led to our recognizingvalue the cost ceiling. The Predecessor also recognized full cost pool ceiling test write-downs of $75.5$261.7 million $479.4 million and $256.0during the period from July 1, 2020 through September 18, 2020, $662.4 million during the three months ended September 30, June 30, 2020 and $72.5 million during the three months ended March 31, 2016, respectively.2020. We havedid not recorded a full cost poolrecord any ceiling test write-down during the firstSuccessor periods from September 19, 2020 through September 30, 2020, for the three months ended June 30, 2021, or the three months ended September 30, 2021.

Reorganization Items, Net

Reorganization items, net, include (i) expenses incurred during the Company’s “prepackaged” voluntary bankruptcy subsequent to the Petition Date as a direct result of the Plan, (ii) gains or losses from liabilities settled and (iii) fresh start accounting adjustments and are recorded in “Reorganization items, net” in our Unaudited Condensed Consolidated Statements of Operations. Professional service provider charges associated with our restructuring that were incurred before the Petition Date and after the Emergence Date are recorded in “Other expenses” in our Unaudited Condensed Consolidated Statements of Operations. The following table summarizes the losses (gains) on reorganization items, net:
Predecessor
In thousandsPeriod from July 1, 2020 through
Sept. 18, 2020
Gain on settlement of liabilities subject to compromise$(1,024,864)
Fresh start accounting adjustments1,834,423 
Professional service provider fees and other expenses11,267 
Success fees for professional service providers9,700 
Loss on rejected contracts and leases10,989 
Valuation adjustments to debt classified as subject to compromise757 
Debtor-in-possession credit agreement fees3,107 
Acceleration of Predecessor stock compensation expense4,601 
Total reorganization items, net$849,980 

Other Expenses

Other expenses totaled $4.6 million and $9.9 million during the three and nine months ended September 30, 2021. Other expenses during 2021 periods primarily include litigation accruals and noncash fair value adjustments for contingent consideration payments related to our March 2021 Wind River Basin CO2 EOR field acquisition. Other expenses totaled $24.2 million for the combined Predecessor and Successor periods included within the three months ended September 30, 2020, and $38.0 million for the combined Predecessor and Successor periods included within the nine months ended September 30, 2020. Other expenses during 2020 primarily are comprised of 2017.

Income Taxes$24.1 million of professional fees associated with restructuring activities, $4.2 million of write-off of certain trade receivables, $3.8 million of costs associated with the Delta-Tinsley CO2 pipeline incident, and $1.6 million of costs associated with the APMTG Helium, LLC helium supply contract ruling.

  Three Months Ended Nine Months Ended
  September 30, September 30,
In thousands, except per-BOE amounts and tax rates 2017 2016 2017 2016
Current income tax expense (benefit) $1,072
 $(1,046) $(18,828) $(1,051)
Deferred income tax expense (benefit) (15,301) (13,519) 35,846
 (331,574)
Total income tax expense (benefit) $(14,229) $(14,565) $17,018
 $(332,625)
Average income tax benefit per BOE $(2.57) $(2.57) $1.04
 $(18.64)
Effective tax rate 103.2% 37.2% 31.9% 36.0%
Total net deferred tax liability $329,724

$505,689
    
34



29


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


Income Taxes
 SuccessorPredecessor
In thousands, except per-BOE amounts and tax ratesThree Months Ended
Sept. 30, 2021		Period from Sept. 19, 2020 through
Sept. 30, 2020		Period from July 1, 2020 through
Sept. 18, 2020
Current income tax expense (benefit)$350 $6 $(1,451)
Deferred income tax expense (benefit)53 6 (302,356)
Total income tax expense (benefit)$403 $12 $(303,807)
Average income tax expense (benefit) per BOE$0.09 $0.02 $(76.47)
Effective tax rate0.5 %0.4 %27.3 %
Total net deferred tax liability$1,241 $3,836 

 SuccessorPredecessor
In thousands, except per-BOE amounts and tax ratesNine Months Ended
Sept. 30, 2021		Period from Sept. 19, 2020 through
Sept. 30, 2020		Period from Jan. 1, 2020 through
Sept. 18, 2020
Current income tax expense (benefit)$(101)$6 $(7,260)
Deferred income tax expense (benefit)(34)6 (408,869)
Total income tax expense (benefit)$(135)$12 $(416,129)
Average income tax expense (benefit) per BOE$(0.01)$0.02 $(30.52)
Effective tax rate0.2 %0.4 %22.5 %

We evaluate our estimated annual effective income tax rate based on current and forecasted business results and enacted tax laws on a quarterly basis and apply this tax rate to our ordinary income or loss to calculate our estimated tax liability or benefit. Our income taxes are based on an estimated combined federal and state statutory rate of approximately 38%25% in 20172021 and 2016.2020. Our effective tax raterates for the Successor three and nine months ended September 30, 2017, differed from2021 were significantly lower than our estimated statutory rate, primarily due to our overall deferred tax asset position and the impact of recognizing a tax benefit of $8.6 million in the current quarter for enhanced oil recovery income tax credits, which was offset in part by a stock-based compensation deduction shortfall (tax deduction less than book expense) of $2.1 million. With pre-tax income for the three months ended September 30, 2017 being close to break-even, the net tax benefit from these itemsvaluation allowance offsetting those assets. As we had a significant impact on the current quarter’s effective tax rate.

The current income tax benefitpre-tax loss for the nine months ended September 30, 2017, represents2021, the estimated receivable associated with tax planning strategies that will allow us to recover alternative minimum tax credits. The deferred income tax benefits duringbenefit resulting from these losses is fully offset by the three and nine months ended September 30, 2016, were primarily due to the impact of the write-down of our oil and natural gas properties during the periods.change in valuation allowance, resulting in essentially no tax provision.


As of September 30, 2017,2021, the tax basis of our assets, primarily our oil and gas properties, is in excess of their carrying value, as adjusted for fresh start accounting on September 18, 2020; therefore, we are currently in a net deferred tax asset position. Based on all available evidence, both positive and negative, we continue to record a valuation allowance on our underlying deferred tax assets as of September 30, 2021, as we believe our deferred tax assets are not more-likely-than-not to be realized. We intend to maintain the valuation allowances on our deferred tax assets until there is sufficient evidence to support the reversal of all or some portion of the allowances, which will largely be determined based on oil prices and the Company’s ability to generate positive pre-tax income.

The current income tax benefits for the Predecessor period ended September 18, 2020 represent amounts estimated to be receivable resulting from alternative minimum tax credits and certain state tax obligations.

As of September 30, 2021, we had an estimated $49.2 million of enhanced oil recovery credits to carry forward related to our tertiary operations, $21.6 million of research and development credits, and $20.3$0.6 million of alternative minimum tax credits, (netwhich under the Tax Cut and Jobs Act will be refunded in 2021 and are recorded as a receivable on the balance sheet. Our state net operating loss carryforwards expire in various years, starting in 2025.


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Denbury Inc.
Management’s Discussion and $8.8 million related to the estimated credits applied,Analysis of Financial Condition and to be applied to our 2016 and 2017 tax returns, respectively) that can be utilized to reduce our current income taxes during 2017 or future years.  The enhanced oil recovery credits and research and development credits do not begin to expire until 2024 and 2031, respectively.Results of Operations

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 significant individual components is discussed above.
Three Months EndedNine Months Ended
September 30,September 30,
Per-BOE data2021202020212020
Oil and natural gas revenues$67.48 $38.37 $62.13 $36.15 
Receipt (payment) on settlements of commodity derivatives(16.99)3.90 (13.49)6.19 
Lease operating expenses(25.50)(15.57)(23.21)(18.39)
Production and ad valorem taxes(5.13)(3.00)(4.75)(2.84)
Transportation and marketing expenses(1.31)(2.08)(1.68)(2.00)
Production netback18.55 21.62 19.00 19.11 
CO2 sales, net of operating and discovery expenses
2.25 1.38 2.04 1.35 
General and administrative expenses(1)
(3.37)(3.66)(4.72)(3.53)
Interest expense, net(0.15)(1.76)(0.26)(3.42)
Reorganization items settled in cash— (8.55)— (2.75)
Stock compensation and other(0.31)(2.72)1.18 (0.74)
Changes in assets and liabilities relating to operations5.79 9.77 1.37 0.26 
Cash flows from operations22.76 16.08 18.61 10.28 
DD&A – excluding accelerated depreciation charge(8.25)(8.71)(8.53)(10.87)
DD&A – accelerated depreciation charge(2)
— (0.39)— (2.75)
Write-down of oil and natural gas properties— (57.25)(1.08)(70.03)
Deferred income taxes(0.01)66.14 — 28.73 
Gain on extinguishment of debt— — — 1.33 
Noncash fair value gains (losses) on commodity derivatives7.86 (4.03)(11.33)1.26 
Noncash reorganization items, net— (177.40)— (56.98)
Other noncash items(4.26)(10.85)(2.53)(1.44)
Net income (loss)$18.10 $(176.41)$(4.86)$(100.47)
  Three Months Ended Nine Months Ended
  September 30, September 30,
Per-BOE data 2017 2016 2017 2016
Oil and natural gas revenues $46.67
 $42.38
 $47.37
 $37.80
Receipt (payment) on settlements of commodity derivatives 0.02
 (1.29) (2.36) 6.55
Lease operating expenses (21.22) (18.82) (20.93) (17.32)
Production and ad valorem taxes (3.32) (3.18) (3.51) (2.93)
Marketing expenses, net of third-party purchases, and plant operating expenses (1.75) (1.99) (1.82) (1.89)
Production netback 20.40
 17.10
 18.75
 22.21
CO2 sales, net of operating and exploration expenses
 0.95
 0.95
 0.98
 0.93
General and administrative expenses (4.91) (4.35) (4.96) (4.54)
Interest expense, net (4.42) (4.38) (4.63) (5.77)
Other 0.27
 1.56
 1.78
 (0.98)
Changes in assets and liabilities relating to operations (0.46) 6.15
 (3.20) (2.92)
Cash flows from operations 11.83
 17.03
 8.72
 8.93
DD&A (9.39) (9.72) (9.43) (11.15)
Write-down of oil and natural gas properties —
 (13.34) —
 (45.45)
Deferred income taxes 2.76
 2.39
 (2.19) 18.58
Gain on debt extinguishment —
 1.38
 —
 6.45
Noncash fair value gains (losses) on commodity derivatives (1)
 (4.57) 5.04
 2.95
 (12.14)
Other noncash items (0.55) (7.12) 2.17
 1.69
Net income (loss) $0.08
 $(4.34) $2.22
 $(33.09)


(1)General and administrative expenses include $15.3 million of performance stock-based compensation related to the full vesting of outstanding performance awards during the nine months ended September 30, 2021, resulting in a significant non-recurring expense, which if excluded, would have caused these expenses to average $3.58 per BOE.

(2)Represents an accelerated depreciation charge related to impaired unevaluated properties that were transferred to the full cost pool.
30


TableCRITICAL ACCOUNTING POLICIES

For additional discussion of Contents
Denbury Resources Inc.
our critical accounting policies, see 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 Unaudited Condensed Consolidated Statements of Operations.

CRITICAL ACCOUNTING POLICIES

For additional discussion of our critical accounting policies, which remain unchanged, see Management’s Discussion and Analysis of Financial Condition and Results of Operations in our Form 10-K. Any new accounting policies or updates to existing accounting policies as a result of new accounting pronouncements have been included in the notes to the Company’s Unaudited Condensed Consolidated Financial Statements contained in this Quarterly Report on Form 10-Q.


FORWARD-LOOKING INFORMATION


The data and/or statements contained in this Quarterly Report on Form 10-Q that are not historical facts, including, but not limited to, statements found in the section Management’s Discussion and Analysis of Financial Condition and Results of Operations, regarding possible or assumed future results of operations, cash flows, production and capital expenditures, and

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Denbury Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
other plans and objectives for the future operations of Denbury, projections or assumptions as to general economic conditions and the economics of a carbon capture, use and storage industry (“CCUS”), and anticipated effects of COVID-19 on U.S. and global oil demand, 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, the level and sustainability of the recent increases in worldwide oil prices from their COVID-19 coronavirus caused downturn, financial forecasts, future hydrocarbon prices and timing and degree of anyoil price recovery versus the length or severity of the current commodity price downturn,volatility, current or future liquidity sources or their adequacy to support our anticipated future activities, our abilitystatements or predictions related to further reduce our debt levels,the ultimate nature, timing and economic aspects of proposed carbon capture, use and storage industry arrangements, 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, the impact of current supply chain and inflationary pressures or expectations on our operational or other assets, current or future expectations or estimations of our cash flows availabilityor the impact of capital,changes in commodity prices on cash flows, borrowing capacity, future interest rates,price and availability of advantageous commodity derivative contracts or thetheir predicted downside cash flow benefits therefrom,protection or cash settlement payments required, mark-to-market commodity derivative values, forecasted capital expenditures, drilling activity or methods, including the timing and location thereof, closingthe nature of proposedany future asset purchases or sales or the timing or proceeds thereof, estimated timing of commencement of CO2 flooding of injections in particular fields or areas, likelihood of completion of to-be-constructed industrial plants and the initial date of capture of CO2 from such plants, timing of CO2 injections andincluding Cedar Creek Anticline (“CCA”), or initial production responses in tertiary flooding projects, acquisition plans and proposals and dispositions,other 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, potential increases in regional or worldwide tariffs or other trade restrictions, the likelihood, timing and impact of increased interest rates, the impact of regulatory rulingschanges or proposed changes anticipatedin Federal or state laws or outcomes of any pending litigation, prospective legislation, orders or regulations affecting the oil and gas industry or environmental regulations, mark-to-market values, competition, long-term forecasts of production, rates of return, estimated costs, changes in costs, future capital expenditures and overall economics, worldwide or U.S. economic conditions, and other variables surrounding our estimated original oil in place, 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;produced; decisions as to production levels and/or pricing by OPECOPEC+ or production levels by U.S. producers in future periods; levels of future capital expenditures; effects of our indebtedness; success of our risk management techniques; accuracy of our cost estimates; availabilityaccess to and terms of credit in the commercial banking market;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 cybersecurity breaches, or from well incidents, climate events such as hurricanes, tropical storms, floods, 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;regulations and consequent 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 quarterly 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 including, without limitation, the Company’s most recent Form 10-K.





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Item 3. Quantitative and Qualitative Disclosures about Market Risk

Debt and Interest Rate Sensitivity

We finance some of our acquisitions and other expenditures with fixed and variable rate debt.  These debt agreements expose us to market risk related to changes in interest rates. As of September 30, 2017, we had $495.0 million of debt outstanding on our senior secured bank credit facility. At this level of variable-rate debt, an increase or decrease of 10% in interest rates would have an immaterial effect on our interest expense. 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 2021 Senior Secured Notes and senior subordinated notes are based on quoted market prices.  The following table presents the principal cash flows and fair values of our outstanding debt as of September 30, 2017:

In thousands 2017 2019 2021 2022 2023 Total Fair Value
Variable rate debt:              
Senior Secured Bank Credit Facility (weighted average interest rate of 4.3% at September 30, 2017) $—
 $495,000
 $—
 $—
 $—
 $495,000
 $495,000
Fixed rate debt:  
  
  
  
      
9% Senior Secured Second Lien Notes due 2021 —
 —
 614,919
 —
 —
 614,919
 600,345
6⅜% Senior Subordinated Notes due 2021
 —
 —
 215,144
 —
 —
 215,144
 128,828
5½% Senior Subordinated Notes due 2022 —
 —
 —
 772,912
 —
 772,912
 440,328
4⅝% Senior Subordinated Notes due 2023
 —
 —
 —
 —
 622,297
 622,297
 329,817
Other Subordinated Notes 2,250
 —
 —
 —
 —
 2,250
 2,250

See Note 3, Long-Term Debt, to the Unaudited Condensed Consolidated Financial Statements for details regarding our long-term debt.


Commodity Derivative Contracts


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.prices, and occasionally requirements under our bank credit facility.  As of December 31, 2020, we were in compliance with hedging requirements under our Bank Credit Agreement requiring certain non-recurring minimum commodity hedge levels covering anticipated crude oil production through July 31, 2022, and we do not have any additional hedging requirements under our Bank Credit Agreement. 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 through 20182022 using both NYMEX and LLS fixed-price swaps collars and three-waycostless collars. Additionally, with the recent improvement in the basis differential between LLS and WTI pricing, we entered into basis swap contracts to lock-in that differential for a portion of our estimated oil production beginning December 2017 through the first half of 2018. Currently, our hedges in place for 2018 represent roughly half of our third quarter 2017 production levels. Depending on market conditions, we may continue to add to our existing 2018 hedges, and we may start to layer in hedges for 2019.2022 hedges. See also Note 5, 6, Commodity Derivative Contracts, and Note 67, Fair Value Measurements, to the Unaudited Condensed 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.



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For accounting purposes, we do not apply hedge accounting treatment 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 September 30, 2017,2021, our commodity derivative contracts were recorded at their fair value, which was a net liability of $20.9$209.5 million, a $25.3$35.9 million decrease from the $4.4$245.4 million net assetliability recorded at June 30, 2017,2021, and a $48.4$150.7 million decreaseincrease from the $69.3$58.8 million net liability recorded at December 31, 2016.  Changes in this value2020.  These changes are comprised ofprimarily related to the expiration of commodity derivative contracts during the three and nine months ended September 30, 2017,2021, new commodity derivative contracts entered into during 20172021 for future periods, and to the changes in oil futures prices between December 31, 2016 and September 30, 2017.from period to period.


Commodity Derivative Sensitivity Analysis


Based on NYMEX and LLS crude oil futures prices as of September 30, 2017,2021, and assuming both a 10% increase and decrease thereon, we would expect to make payments on our crude oil derivative contracts outstanding at September 30, 2021 as shown in the following table:
In thousandsReceipt / (Payment)
Based on:
Futures prices as of September 30, 2021$(197,214)
10% increase in prices(277,213)
10% decrease in prices(125,537)
  Receipt / (Payment)
In thousands Crude Oil Derivative Contracts
Based on:  
Futures prices as of September 30, 2017 $(12,685)
10% increase in prices (66,466)
10% decrease in prices 25,696


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 production to which those commodity derivative contracts relate.



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Item 4. 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 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 September 30, 2017,2021, 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 disclosures.


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 third quarter of fiscal 2017,2021, 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.





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PART II. OTHER INFORMATION


Item 1. Legal Proceedings


We are involved in various lawsuits, claimsThe information under Note 8, Commitments 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. Although a single or multiple adverse rulings or settlements could possibly have a material adverse effect on our business or finances, we only 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, we assumed a 20-year helium supply contract under which we agreed to supply to a third-party purchaser the helium separated from the full well stream by operation of the gas processing facility.  The helium supply contract provides for the delivery of a minimum contracted quantity of helium, subject to adjustment after startup of the Riley Ridge gas processing facility, 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 $8.0 million per contract year and are capped at an aggregate of $46.0 million over the remaining term of the contract. As the gas processing facility has been shut-in since mid-2014, we have not been able to supply heliumContingencies, to the third-party purchaser under the helium supply contract.  In a case originally filed in November 2014Unaudited Condensed Consolidated Financial Statements is incorporated herein by APMTG Helium, LLC, the third-party helium purchaser, in the Ninth Judicial District Court of Sublette County, Wyoming, after a week of trial during February 2017 on the third-party purchaser’s claim for multiple years of liquidated damages for non-delivery of volumes of helium specified under the helium supply contract, and on our claim that the contractual obligation is excused by virtue of events that fall within the force majeure provisions in the helium supply contract, the trial was stayed until November 27, 2017. The Company plans to continue to vigorously defend its position and pursue its claim, but we are unable to predict at this time the outcome of this dispute.reference.


Item 1A. Risk Factors


Information with respectPlease refer to the Company’s risk factors has been incorporated by reference toPart I, Item 1A of the Company’s Annual Report on Form 10-K.10-K for the fiscal year ended December 31, 2020. There have been no material changes to theour risk factors contained in theour Annual Report on Form 10-K since its filing.


for the year ended December 31, 2020.


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Item 2. Unregistered Sales of Equity Securities and Use of Proceeds


Issuer Purchases of Equity SecuritiesNone.


The following table summarizes purchases of our common stock during the third quarter of 2017:
Month 
Total Number of Shares Purchased (1)
 Average Price Paid per Share 
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)
July 2017 926,368
 $1.52
 —
 $210.1
August 2017 6,085
 1.16
 —
 210.1
September 2017 44,576
 1.10
 —
 210.1
Total 977,029
  
—
 


(1)
Shares purchased during the third quarter of 2017 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 as long as industry commodity pricing and general economic conditions persist. 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.

Between early October 2011, when we announced commencement of a common share repurchase program, and October 2015, we repurchased 64.4 million shares of Denbury common stock (approximately 16.0% of our outstanding shares of common stock at September 30, 2011) for $951.8 million, with no repurchases made since October 2015.

Item 3. Defaults Upon Senior Securities


None.


Item 4. Mine Safety Disclosures


None.


Item 5. Other Information


None.





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Item 6. Exhibits


Exhibit No.Exhibit
4(a)10(a)*
Second Supplemental Indenture for 6⅜% 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.

4(b)*
Second Supplemental Indenture for 4⅝% 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.

4(c)*
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.

4(d)*
First Supplemental Indenture for 9% Senior Secured Second Lien 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.

10(a)*
Form of Indemnification Agreement, dated as of September 1, 2017, by and between Denbury Resources Inc. and its officers and directors.

10(b)*
Fifth Amendment to Amended and Restated Credit Agreement, dated as of November 6, 2017, 3, 2021, by and among Denbury Resources Inc., as Borrower, Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent,Administrative Agent, and the financial institutions Lenders party thereto.thereto.

31(a)*
Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31(b)*
Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32**
Certification of Chief Executive Officer and Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101*101.INS*
Inline XBRL Instance Document - the instance document does not appear in the Interactive Data Files.

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 Taxonomy Extension Label Linkbase Document
101.PRE*Inline XBRL Taxonomy Extension Presentation Linkbase Document
104The cover page from the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2021, has been formatted in Inline XBRL.


*Included herewith.

*    Included herewith.
**    Furnished herewith in accordance with Item 601(b)(32) of Regulation S-K.


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SIGNATURES


Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


DENBURY INC.
November 4, 2021DENBURY RESOURCES INC.
November 7, 2017/s/ Mark C. Allen
Mark C. Allen

Executive Vice President and Chief Financial Officer
November 7, 2017/s/ Alan Rhoades
Alan Rhoades
Vice President and Chief Accounting Officer



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INDEX TO EXHIBITS

Exhibit No.November 4, 2021Exhibit/s/ Nicole Jennings
4(a)
Second Supplemental Indenture for 6⅜% 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.
4(b)
Second Supplemental Indenture for 4⅝% 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.
4(c)
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.
4(d)
First Supplemental Indenture for 9% Senior Secured Second Lien 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.
10(a)
Form of Indemnification Agreement, dated as of September 1, 2017, by and between Denbury Resources Inc. and its officers and directors.
10(b)
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.
31(a)
Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31(b)
Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32
Certification of Chief Executive OfficerNicole Jennings
Vice President and Chief FinancialAccounting Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101Interactive Data Files.





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