UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

☑   Quarterly report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the quarterly period ended September 30, 2021

OR

☐   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

DENBURY INC.

(Exact name of registrant as specified in its charter)

Delaware

20-0467835

(State or other jurisdiction of incorporation or organization)

(I.R.S. Employer Identification No.)

5851 Legacy Circle,

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 Value			DEN			New 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 ☑  No ☐

Indicate by check mark whether the registrant has submitted electronically 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 ☑  No ☐

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 filer

☐

Accelerated filer

☑

Non-accelerated filer

☐

Smaller reporting company

☑

Emerging growth company

☐

(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. ☐

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

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 the registrant’s Common Stock, $.001 par value, as of October 31, 2021, was 50,122,417.

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Denbury Inc.

Table of Contents

Page

PART I. FINANCIAL INFORMATION

Item 1.

Financial Statements

Unaudited Condensed Consolidated Balance Sheets

3

Unaudited Condensed Consolidated Statements of Operations

4

Unaudited Condensed Consolidated Statements of Cash Flows

6

Unaudited Condensed Consolidated Statements of Changes in Stockholders’ Equity

7

Notes to Unaudited Condensed Consolidated Financial Statements

8

Item 2.

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

19

Item 3.

Quantitative and Qualitative Disclosures about Market Risk

38

Item 4.

Controls and Procedures

39

PART II. OTHER INFORMATION

Item 1.

Legal Proceedings

40

Item 1A.

Risk Factors

40

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds

41

Item 3.

Defaults Upon Senior Securities

41

Item 4.

Mine Safety Disclosures

41

Item 5.

Other Information

41

Item 6.

Exhibits

42

Signatures

43

2

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Table of Contents

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

Denbury Inc.

Unaudited Condensed Consolidated Balance Sheets

(In thousands, except par value and share data)

						Successor
						September 30, 2021						December 31, 2020
Assets
Current assets
Cash and cash equivalents						$	1,783					$	518
Restricted cash						—						1,000
Accrued production receivable						144,370						91,421
Trade and other receivables, net						20,867						19,682
Derivative assets						—						187
Prepaids						10,872						14,038
Total current assets						177,892						126,846
Property and equipment
Oil and natural gas properties (using full cost accounting)
Proved properties						1,011,545						851,208
Unevaluated properties						108,258						85,304
CO2 properties						188,752						188,288
Pipelines						193,669						133,485
Other property and equipment						94,763						86,610
Less accumulated depletion, depreciation, amortization and impairment						(151,844)						(41,095)
Net property and equipment						1,445,143						1,303,800
Operating lease right-of-use assets						18,253						20,342
Intangible assets, net						90,533						97,362
Other assets						80,444						86,408
Total assets						$	1,812,265					$	1,634,758
Liabilities and Stockholders’ Equity
Current liabilities
Accounts payable and accrued liabilities						$	211,894					$	112,671
Oil and gas production payable						69,717						49,165
Derivative liabilities						193,015						53,865
Current maturities of long-term debt						17,332						68,008
Operating lease liabilities						3,338						1,350
Total current liabilities						495,296						285,059
Long-term liabilities
Long-term debt, net of current portion						—						70,000
Asset retirement obligations						243,184						179,338
Derivative liabilities						16,435						5,087
Deferred tax liabilities, net						1,241						1,274
Operating lease liabilities						17,362						19,460
Other liabilities						25,954						20,872
Total long-term liabilities						304,176						296,031
Commitments and contingencies (Note 8)
Stockholders’ equity
Preferred 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, respectively						50						50
Paid-in capital in excess of par						1,128,030						1,104,276
Accumulated deficit						(115,287)						(50,658)
Total stockholders’ equity						1,012,793						1,053,668
Total liabilities and stockholders’ equity						$	1,812,265					$	1,634,758

 

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

3

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Denbury Inc.

Unaudited Condensed Consolidated Statements of Operations

(In thousands, except per-share data)

						Successor															Predecessor
						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 revenues						12,593						151									3,332
Other income						10,451						94									7,097
Total revenues and other income						343,735						23,533									170,036
Expenses
Lease operating expenses						116,536						11,484									59,708
Transportation and marketing expenses						5,985						1,344									8,155
CO2 operating and discovery expenses						1,963						242									955
Taxes other than income						24,154						2,073									13,473
Oil marketing purchases						11,940						139									3,288
General and administrative expenses						15,388						1,735									15,013
Interest, net of amounts capitalized of $1,249, $183 and $4,704, respectively						669						334									7,704
Depletion, depreciation, and amortization						37,691						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 expenses						4,553						2,164									22,084
Total expenses						260,624						20,763									1,282,963
Income (loss) before income taxes						83,111						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
Basic						51,094						50,000									497,398
Diluted						54,714						50,000									497,398

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

4

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Denbury Inc.

Unaudited Condensed Consolidated Statements of Operations

(In thousands, except per-share data)

						Successor															Predecessor
						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 revenues						26,538						151									8,543
Other income						11,518						94									8,419
Total revenues and other income						896,262						23,533									530,112
Expenses
Lease operating expenses						308,731						11,484									250,271
Transportation and marketing expenses						22,304						1,344									27,164
CO2 operating and discovery expenses						4,487						242									2,592
Taxes other than income						65,499						2,073									43,531
Oil marketing purchases						25,763						139									8,399
General and administrative expenses						62,821						1,735									48,522
Interest, net of amounts capitalized of $3,500, $183 and $22,885, respectively						3,457						334									48,267
Depletion, depreciation, and amortization						113,522						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 properties						14,377						—									996,658
Reorganization items, net						—						—									849,980
Other expenses						9,913						2,164									35,868
Total expenses						961,026						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
Basic						50,807						50,000									495,560
Diluted						50,807						50,000									495,560

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

5

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Denbury Inc.

Unaudited Condensed Consolidated Statements of Cash Flows

(In thousands)

						Successor															Predecessor
						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 amortization						113,522						5,283									188,593
Write-down of oil and natural gas properties						14,377						—									996,658
Deferred income taxes						(34)						6									(408,869)
Stock-based compensation						22,788						—									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 discounts						2,055						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 assets						7,337						705									743
Accounts payable and accrued liabilities						47,484						(7,980)									(16,102)
Oil and natural gas production payable						23,168						(11,064)									(6,792)
Other liabilities						(4,966)						(29)									123
Net cash provided by operating activities						247,557						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 equipment						19,053						880									41,322
Other						5,797						(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 borrowings						627,000						—									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 cash						6,214						(23,704)									62,069
Cash, cash equivalents, and restricted cash at beginning of period						42,248						95,114									33,045
Cash, cash equivalents, and restricted cash at end of period						$	48,462					$	71,410								$	95,114

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

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Denbury Inc.

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)
			Shares						Amount																		Shares						Amount						Total 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 warrants			5,620						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 warrants			11,872						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 warrants			103,404						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)
			Shares						Amount																		Shares						Amount						Total 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 plans			312,516						—						—						—						—						—						—
Issued pursuant to directors’ compensation plan			37,367						—						—						—						—						—						—
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 conversion			7,357,450						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 conversion			14,800						—						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 equity			49,999,999						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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Denbury Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

Note 1. Basis of Presentation

Organization and Nature of Operations

Denbury Inc. (“Denbury,” “Company” or the “Successor”), a Delaware corporation, is an independent energy company with operations focused in the Gulf Coast and Rocky Mountain regions. The Company is differentiated 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 thousands						Period from July 1, 2020 through Sept. 18, 2020
Gain on settlement of liabilities subject to compromise						$	(1,024,864)
Fresh start accounting adjustments						1,834,423
Professional service provider fees and other expenses						11,267
Success fees for professional service providers						9,700
Loss on rejected contracts and leases						10,989
Valuation adjustments to debt classified as subject to compromise						757
Debtor-in-possession credit agreement fees						3,107
Acceleration of Predecessor stock compensation expense						4,601
Total reorganization items, net						$	849,980

Interim Financial Statements

The accompanying unaudited condensed consolidated financial statements of Denbury 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, 2020 (the “Form 10-K”).  Unless indicated otherwise or the context requires, the terms “we,” “our,” “us,” “Company” or “Denbury,” refer to Denbury 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 presentation of our consolidated financial position as of September 30, 2021 (Successor); our consolidated results of operations and consolidated statement of changes in stockholders’ equity for the three and nine months ended September 30, 2021 (Successor), for the period September 19, 2020 through September 30, 2020 (Successor), for the period July 1, 2020 through September 18, 2020 (Predecessor) and January 1, 2020 through September 18, 2020 (Predecessor); and our consolidated cash flows for the nine months ended September 30, 2021 (Successor), for the period September 19, 2020 through September 30, 2020 (Successor) and for 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 thousands						September 30, 2021						December 31, 2020
Cash and cash equivalents						$	1,783					$	518
Restricted cash, current						—						1,000
Restricted cash included in other assets						46,679						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 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, and convertible senior notes. For each of the three and nine months ended September 30, 2021 and 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 table reconciles the weighted average shares used in the basic and diluted net income (loss) per common share calculations for the periods indicated:

						Successor															Predecessor
In thousands						Three 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 – basic						51,094						50,000									497,398
Effect of potentially dilutive securities
Restricted stock units						908						—									—
Warrants						2,712						—									—
Weighted average common shares outstanding – diluted						54,714						50,000									497,398

For 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 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 during those periods.

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Denbury 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, 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 warrants are included in the computation using the treasury stock method.

The following outstanding securities were excluded from the computation of diluted net 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, as of the respective dates:

						Successor
In thousands						September 30, 2021						September 30, 2020
Restricted stock units						1,255						—
Warrants						5,314						5,526

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.

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. Under full cost accounting, the net capitalized costs of oil and natural gas properties are limited to the lower of unamortized cost or the cost center ceiling. The cost center ceiling is defined as (1) the present value of estimated future net revenues from proved oil and natural gas reserves before future abandonment costs (discounted at 10%), based on the average first-day-of-the-month oil and natural gas price for each month during a 12-month rolling period prior to the end of a particular reporting period; plus (2) the cost of properties not being amortized; plus (3) the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any; less (4) related income tax effects. Our future net revenues from proved oil and natural gas reserves are not reduced for development costs related to the cost of drilling for and developing CO2 reserves nor those related to the cost of constructing CO2 pipelines, as we do not have to incur additional 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 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 write-down was primarily a result of 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 Predecessor also recognized full cost pool ceiling test write-downs of $261.7 million during 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, 2021, or for the three months ended September 30, 2021.

Recent Accounting Pronouncements

Recently Adopted

Income Taxes. In December 2019, the Financial Accounting Standards Board (“FASB”) issued ASU 2019-12, Income Taxes (Topic 740) – Simplifying the Accounting for Income Taxes (“ASU 2019-12”). The objective of ASU 2019-12 is to simplify the accounting for income taxes by removing certain exceptions to the general principles in Topic 740 and to provide more consistent application to improve the comparability of financial statements. Effective January 1, 2021, we adopted ASU 2019-02. The implementation of this standard did not have a material impact on our consolidated financial statements and 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 Big Sand Draw and Beaver Creek EOR fields 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. 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 Unaudited 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 higher NYMEX WTI oil prices and was recorded to “Other expenses” in our Unaudited Condensed Consolidated Statements of Operations.

The fair values allocated to our 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 Unaudited 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 properties						60,101
Other property and equipment						1,685
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 transaction, and the sale had no impact on our 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

We record revenue in accordance with FASC Topic 606, Revenue from Contracts with Customers. The core principle of FASC Topic 606 is that an entity should recognize revenue for the transfer of goods or services equal to the amount of consideration that it expects to be entitled to receive for those goods or services. Once we have delivered the volume of commodity to the delivery point and the customer takes delivery and possession, we are entitled to payment and we invoice the customer for such delivered production. Payment under most oil and CO2 contracts is received within a month following product delivery, and for natural gas and NGL contracts, payment is generally received within two months following delivery. Timing of revenue recognition may differ from the timing of invoicing to customers; however, as the right to consideration after delivery is unconditional based on only the passage of time before payment of the consideration is due, upon delivery we record a receivable in “Accrued production receivable” in our 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 of the commodities purchased and responsibility to deliver the commodities sold. Revenue is recognized when control transfers to the purchaser at the delivery point based on the price received from the purchaser.

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Denbury Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

Disaggregation of Revenue

The following tables summarize our revenues by product type for the periods indicated:

						Successor															Predecessor
In thousands						Three 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 sales						3,361						10									954
CO2 sales and transportation fees						12,237						967									6,517
Oil marketing revenues						12,593						151									3,332
Total revenues						$	333,284					$	23,439								$	162,939

						Successor															Predecessor
In thousands						Nine 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 sales						7,893						10									2,850
CO2 sales and transportation fees						31,599						967									21,049
Oil marketing revenues						26,538						151									8,543
Total revenues						$	884,744					$	23,439								$	521,693

Note 4. Long-Term Debt

The table below reflects long-term debt outstanding as of the dates indicated:

						Successor
In thousands						September 30, 2021						December 31, 2020
Senior Secured Bank Credit Agreement						$	—					$	70,000
Pipeline financings						17,332						68,008
Total debt principal balance						17,332						138,008
Less: current maturities of long-term debt						(17,332)						(68,008)
Long-term debt						$	—					$	70,000

Senior Secured Bank Credit Agreement

On the Emergence Date, we entered into a credit agreement with JPMorgan Chase Bank, N.A., as administrative agent, and other lenders party thereto (the “Bank Credit Agreement”). The Bank Credit Agreement is a senior secured revolving credit facility with a borrowing base and lender commitments of $575 million. Availability under the Bank Credit Agreement is 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 the 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 exceeds the then-effective borrowing base, we would be required to repay the excess amount over a period not to exceed six months. The Bank Credit Agreement matures on January 30, 2024. The undrawn portion of the aggregate lender commitments under the Bank Credit Agreement is subject to a commitment fee of 0.5% per annum.

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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 is at least 20%. The Bank Credit Agreement also limits our ability to, among other things, incur and repay other indebtedness; grant liens; engage in certain 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 customary exceptions.

The Bank Credit Agreement is 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 certain exceptions.

The Bank Credit Agreement contains certain financial performance covenants including the following:

•A Consolidated Total Debt to Consolidated EBITDAX covenant (as defined in the Bank Credit Agreement), with such ratio not to exceed 3.5 times; and

•A requirement to maintain a current ratio (i.e., Consolidated Current Assets to Consolidated Current Liabilities) of 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.

Pipeline Financing Transactions

During the first nine months of 2021, Denbury paid $52.5 million to Genesis Energy, L.P. in accordance with the October 2020 restructuring of the financing arrangements of our NEJD CO2 pipeline system. The final quarterly installment of $17.5 million was paid on October 29, 2021.

Note 5. Income Taxes

As of September 30, 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.

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 25% in 2021 and 2020. Our effective tax rates for the three and nine months ended September 30, 2021 (Successor) differed from our estimated statutory rate as the deferred tax expense generated by the operating income for the three months ended September 30, 2021 and the deferred tax benefit generated from our operating loss for the nine months ended September 30, 2021 were offset by a valuation allowance applied to our underlying federal and state deferred tax assets.

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Denbury Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

Note 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, expectation of future commodity 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, 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.

The following table summarizes our commodity derivative contracts as of September 30, 2021, none of which are classified as hedging instruments in accordance with the FASC Derivatives and Hedging topic:

Months						Index Price						Volume (Barrels per day)						Contract Prices ($/Bbl)
																		Range(1)															Weighted Average Price
																																	Swap						Floor						Ceiling
Oil Contracts:
2021 Fixed-Price Swaps
Oct – Dec						NYMEX						29,000						$			38.68			–			56.00						$	43.86					$	—					$	—
2021 Collars
Oct – Dec						NYMEX						4,000						$			45.00			–			59.30						$	—					$	46.25					$	53.04
2022 Fixed-Price Swaps
Jan – June						NYMEX						15,500						$			42.65			–			58.15						$	49.01					$	—					$	—
July – Dec						NYMEX						9,000									50.13			–			60.35						56.35						—						—
2022 Collars
Jan – June						NYMEX						11,000						$			47.50			–			70.75						$	—					$	49.77					$	64.31
July – Dec						NYMEX						10,000									47.50			–			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.

Note 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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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.

•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 and 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.

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 thousands						Quoted 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)

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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.

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. The estimated fair value of the principal amount of our debt as of December 31, 2020, excluding pipeline financing obligations, was $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 8. Commitments and Contingencies

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.  We accrue for losses from litigation and claims if we determine that a loss is probable and the amount can be reasonably estimated.

Note 9. Additional Balance Sheet Details

Accounts Payable and Accrued Liabilities

						Successor
In thousands						September 30, 2021						December 31, 2020
Accounts payable						$	38,578					$	18,629
Accrued compensation						33,961						7,512
Accrued derivative settlements						26,311						3,908
Accrued lease operating expenses						25,724						21,294
Accrued exploration and development costs						20,728						1,861
Taxes payable						14,468						17,221
Accrued general and administrative expenses						2,595						21,825
Other						49,529						20,421
Total						$	211,894					$	112,671

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Denbury 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, 2020 (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 energy company with operations focused in the Gulf Coast and Rocky Mountain regions. The Company is differentiated 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 sales volumes are oil. Changes in oil prices impact all aspects of our business; most notably our cash flows from operations, revenues, capital allocation and budgeting decisions, and oil and natural gas reserves volumes. The table below

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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:

						Three Months Ended
In thousands, except per-unit data						Sept. 30, 2021						June 30, 2021						March 31, 2021						Dec. 31, 2020						Sept. 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 settlements						51.35						50.10						47.00						43.94						43.23

NYMEX WTI oil prices strengthened from the mid-$40s per Bbl range in December 2020 to an average of approximately $71 per Bbl during the third quarter of 2021, 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 greater 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, or $1.51 per diluted common share, during the third quarter of 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:

•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 $15.4 million insurance reimbursement that reduced lease operating expenses in the 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 cash receipts upon contract settlements ($77.7 million in payments during the third quarter of 2021 compared to $17.8 million in receipts upon settlements during the third quarter of 2020), partially offset by a $54.3 million improvement in noncash fair value changes ($35.9 million of income in the current period compared to $18.4 million of expense in the prior-year period).

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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 further 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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$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 thousands						2021						2020
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 expenditures						125,279						68,374
CCA CO2 pipeline						48,542						9,192
Development capital expenditures						173,821						77,566
Acquisitions of oil and natural gas properties(3)						10,927						95
Capital expenditures, before capitalized interest						184,748						77,661
Capitalized interest						3,500						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 of goods and services and wages in our operations which could negatively impact our results of operations and cash flows in future periods.

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Senior Secured Bank Credit Agreement. In September 2020, we entered into a bank credit agreement with JPMorgan Chase Bank, N.A., as administrative agent, and other lenders party thereto (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 2021 semiannual borrowing base redetermination, the borrowing base and lender commitments for our Bank Credit Agreement were reaffirmed at $575 million, with our next scheduled redetermination around May 1, 2022. The borrowing base is adjusted at the 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 exceeds the then-effective borrowing base, we would be required to repay the excess amount over a period not to exceed six months. The Bank Credit Agreement contains certain financial performance covenants including the following:

•A Consolidated Total Debt to Consolidated EBITDAX covenant (as defined in the Bank Credit Agreement), with such ratio not to exceed 3.5 times; and

•A requirement to maintain a current ratio (i.e., Consolidated Current Assets to Consolidated Current Liabilities) of 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. Under these financial performance covenant calculations, as of September 30, 2021, our ratio of consolidated total debt to consolidated EBITDAX was 0.05 to 1.0 (with a maximum permitted ratio of 3.5 to 1.0) and our current ratio was 2.60 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 3, 2021, and current oil commodity derivative futures prices, we currently anticipate continuing to be in compliance with our financial performance covenants during the foreseeable future.

The above description of our Bank Credit Agreement is qualified by the express language and defined terms contained in the Bank Credit Agreement, which is an exhibit to our Form 8-K Report filed with the SEC on September 18, 2020.

Commitments and Obligations. We have 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 office leases. Our purchase obligations represent future cash commitments primarily for purchase contracts for CO2 captured from industrial sources, CO2 processing fees, transportation agreements and well-related costs.

Our commitments and obligations consist of those detailed as of December 31, 2020, in our Form 10-K under Management’s Discussion and Analysis of Financial Condition and Results of Operations – Capital Resources and Liquidity – Commitments, Obligations and Off-Balance Sheet Arrangements. During the nine months ended September 30, 2021, 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 Divestitures).

Off-Balance Sheet Arrangements. Our off-balance sheet arrangements include obligations for various 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.

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RESULTS OF OPERATIONS

Certain of our financial results for our Successor and Predecessor periods are presented in the following tables:

						Successor															Predecessor
In thousands, except per-share and unit data						Three 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 activities						104,019						32,910									40,597

						Successor															Predecessor
In thousands, except per-share and unit data						Nine 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 activities						247,557						32,910									113,408

(1)Includes a pre-tax full cost pool ceiling test write-down of our oil and natural gas properties of $14.4 million during the first quarter of 2021, as compared to write-downs of $261.7 million and $996.7 million for the Predecessor periods July 1, 2020 through September 18, 2020 and 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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Certain of our operating results and statistics for the comparative three and nine months ended September 30, 2021 and 2020 are included in the following table:

						Three Months Ended												Nine Months Ended
						September 30												September 30
In thousands, except per-share and unit data						2021						2020						2021						2020
Average daily sales volumes
Bbls/d						48,145						48,334						47,276						50,619
Mcf/d						9,222						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 sales						3,361						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 derivatives						35,925						(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 Mcf						3.96						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 Mcf						3.96						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 expenses						5,985						9,499						22,304						28,508
Production and ad valorem taxes						23,464						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 expenses						25.50						15.57						23.21						18.39
Transportation and marketing expenses						1.31						2.08						1.68						2.00
Production and ad valorem taxes						5.13						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.

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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 Area						2021						2021						2021									2020						2020						2020						2020
Tertiary oil sales
Gulf Coast region
Delhi						2,925						2,931						2,859									3,813						3,529						3,208						3,132
Hastings						4,226						4,487						4,343									5,232						4,722						4,473						4,598
Heidelberg						4,054						3,942						3,895									4,371						4,366						4,256						4,198
Oyster Bayou						3,554						3,791						3,942									3,999						3,871						3,526						3,880
Tinsley						3,424						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 region						24,281						24,680						24,336									28,931						26,220						25,776						25,794
Rocky Mountain region
Bell Creek						4,614						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 region						7,187						8,772						9,033									7,930						7,108						7,718						7,086
Total tertiary oil sales						31,468						33,452						33,369									36,861						33,328						33,494						32,880
Non-tertiary oil and gas sales
Gulf Coast region
Total Gulf Coast region						3,621						3,415						3,763									4,173						3,805						3,728						3,523
Rocky Mountain region
Cedar Creek Anticline						11,150						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 region						12,268						12,266						12,550									14,151						13,057						12,464						12,402
Total non-tertiary sales						15,889						15,681						16,313									18,324						16,862						16,192						15,925
Total continuing sales						47,357						49,133						49,682									55,185						50,190						49,686						48,805
Property sales
Gulf Coast Working Interests Sale(3)						—						—						—									780						—						—						—
Total sales						47,357						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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Our sales volumes during the three and nine months ended September 30, 2021 were 97% oil, consistent with our sales during the same prior-year periods.

Oil and Natural Gas Revenues

Our oil and natural gas revenues during the three and nine months ended September 30, 2021 increased 76% and 61%, respectively, compared to these revenues for the same periods in 2020.  The changes in our oil and natural gas revenues are due primarily to higher 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 Ended												Nine Months Ended
						September 30,												September 30,
						2021 vs. 2020												2021 vs. 2020
In thousands						Increase (Decrease) in Revenues						Percentage Increase in Revenues						Increase (Decrease) in Revenues						Percentage 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 prices						133,057						76		%				345,702						67		%
Total increase in oil and natural gas revenues						$	133,043					76		%				$	312,185					61		%

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 three quarters and nine months ended September 30, 2021 and 2020:

						Three Months Ended																																				Nine Months Ended
						March 31,												June 30,												September 30,												September 30,
						2021						2020						2021						2020						2021						2020						2021						2020
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 Mcf						3.29						1.46						2.64						1.21						3.96						1.29						3.31						1.32
Price per BOE						55.24						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 Mcf						0.68						(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 Mcf						0.49						(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 Mcf						0.58						(0.41)						(0.33)						(0.54)						(0.33)						(0.83)						(0.02)						(0.60)

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.

•Gulf Coast Region. Our average NYMEX oil differential in the Gulf Coast region was a negative $1.77 per Bbl during the third quarter of 2021, compared to a negative $1.38 per Bbl during the third quarter of 2020 and a negative $1.13 per Bbl during the second quarter of 2021. NYMEX WTI oil prices continued to strengthen during the third quarter of 2021; however, the pricing for our Gulf Coast grades weakened relative to NYMEX WTI index prices. For

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our crude oil sold under Light Louisiana Sweet (“LLS”) index prices, the LLS-to-NYMEX differential averaged a positive $0.98 per Bbl on a trade-month basis for the third quarter of 2021, compared to a positive $1.52 per Bbl differential in the third quarter of 2020 and a positive $2.10 per Bbl in the second quarter of 2021.

•Rocky Mountain Region. NYMEX oil differentials in the Rocky Mountain region averaged $1.72 per Bbl and $2.03 per Bbl below NYMEX during the third quarters of 2021 and 2020, respectively, and $1.59 per Bbl below NYMEX during the second quarter of 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 tables summarize the impact our crude oil derivative contracts had on our operating results for the three and nine months ended September 30, 2021 and 2020:

						Successor															Predecessor
In thousands						Three 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 derivatives						35,925						(2,625)									(15,738)
Total income (expense)						$	(41,745)					$	4,035								$	(4,609)

						Successor															Predecessor
In thousands						Nine 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,

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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 2021						1H 2022						2H 2022
WTI NYMEX			Volumes Hedged (Bbls/d)						29,000						15,500						9,000
Fixed-Price Swaps			Swap Price(1)						$43.86						$49.01						$56.35
WTI NYMEX			Volumes Hedged (Bbls/d)						4,000						11,000						10,000
Collars			Floor / Ceiling Price(1)						$46.25 / $53.04						$49.77 / $64.31						$49.75 / $64.18
			Total Volumes Hedged (Bbls/d)						33,000						26,500						19,000

(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

						Successor															Predecessor
In thousands, except per-BOE data						Three 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

    

						Successor															Predecessor
In thousands, except per-BOE data						Nine 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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Total lease operating expenses were $116.5 million, 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 Successor periods included within the three months ended September 30, 2020. Total lease operating expenses were $308.7 million, 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 and 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 2013 incident at Delhi Field (b) $8.1 million and $17.0 million of expense during the three and nine months ended September 30, 2021, respectively, related to the Wind River Basin acquisition in March 2021, as these properties have higher operating costs than our other fields (c) higher expenses across nearly all expense categories as our costs are correlated to varying degrees with changes in oil prices (reflecting rising oil prices in 2021) and (d) 2020 period reduced spending and shut-in production in response to significantly lower oil prices in the third quarter of 2020. Lease operating expenses for the nine months ended September 30, 2021 were offset by a $7.6 million reduction in power and fuel 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 benefit to the Company of approximately $16.1 million; as of September 30, 2021; $10.3 million of these savings were included in “Trade and other receivables, net” and $1.7 million included in “Other assets” in our Unaudited Condensed Consolidated Balance Sheets. Compared to the second 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, due primarily to higher power and fuel costs and contract labor.

Transportation and Marketing Expenses

Transportation and marketing expenses primarily consist of amounts incurred relating to the transportation, marketing, and processing of oil and natural gas production. Transportation and marketing expenses were $6.0 million for the three months ended September 30, 2021, compared to $9.5 million for the combined Predecessor and Successor periods included within the three months ended September 30, 2020. Transportation and marketing expenses were $22.3 million for the nine months ended September 30, 2021, compared to $28.5 million for the combined Predecessor and 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 were $24.2 million during the three months ended September 30, 2021, compared to $15.5 million for the combined Predecessor and Successor periods included within the three months ended September 30, 2020. Taxes other than income were $65.5 million during the nine months ended September 30, 2021, compared to $45.6 million for the combined Predecessor and Successor periods included within the nine months ended September 30, 2020. The increases in both periods when compared to 2020 were due primarily to an increase in production taxes resulting from higher oil and natural gas revenues.

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General and Administrative Expenses (“G&A”)

						Successor															Predecessor
In thousands, except per-BOE data and employees						Three 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 compensation						2,556						—									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 compensation						0.56						—									0.14
G&A expenses						$	3.37					$	2.90								$	3.78
Employees as of period end						698						663									662

						Successor															Predecessor
In thousands, except per-BOE data						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 G&A costs						$	40,033					$	1,735								$	44,411
Stock-based compensation						22,788						—									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 compensation						1.71						—									0.30
G&A expenses						$	4.72					$	2.90								$	3.56

Our G&A expense on an absolute-dollar basis was $15.4 million during the three months ended September 30, 2021, a decrease of $1.4 million (8%) from 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 current period, partially offset by higher long-term incentives for employees. Our G&A expenses on an absolute-dollar basis were $62.8 million during the nine months ended September 30, 2021, an increase of $12.6 million (25%) from the combined Predecessor and Successor periods within the nine months ended September 30, 2020. The increase in our G&A expenses during the nine months ended September 30, 2021 was primarily due to $15.3 million of stock-based compensation expense in the first quarter of 2021 resulting from the full vesting of performance-based equity awards with vesting parameters tied to the Company’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 occur until after the end of the performance period, December 4, 2023.

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Interest and Financing Expenses

						Successor															Predecessor
In thousands, except per-BOE data and interest rates						Three 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 expense						685						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		%

						Successor															Predecessor
In thousands, except per-BOE data and interest rates						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 interest(1)						$	4,902					$	403								$	108,824
Less: interest not reflected as expense for financial reporting purposes(1)						—						—									(49,243)
Noncash interest expense						2,055						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.

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

						Successor															Predecessor
In thousands, except per-BOE data						Three 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

						Successor															Predecessor
In thousands, except per-BOE data						Nine 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

(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 Successor periods included within the three months ended September 30, 2020. DD&A expense was $113.5 million during the nine months ended September 30, 2021, 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 comparable 2020 periods were primarily due to lower depletable costs due to the step down in book value resulting from fresh start accounting as of September 18, 2020, with the year-over-

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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.

Full Cost Pool Ceiling Test Write-Downs

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 prior to the end of a 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 write-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 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 Predecessor also recognized full cost pool ceiling test write-downs of $261.7 million during 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-down during the Successor 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 thousands						Period from July 1, 2020 through Sept. 18, 2020
Gain on settlement of liabilities subject to compromise						$	(1,024,864)
Fresh start accounting adjustments						1,834,423
Professional service provider fees and other expenses						11,267
Success fees for professional service providers						9,700
Loss on rejected contracts and leases						10,989
Valuation adjustments to debt classified as subject to compromise						757
Debtor-in-possession credit agreement fees						3,107
Acceleration of Predecessor stock compensation expense						4,601
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 $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.

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Income Taxes

						Successor															Predecessor
In thousands, except per-BOE amounts and tax rates						Three 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 rate						0.5		%				0.4		%							27.3		%
Total net deferred tax liability						$	1,241					$	3,836

						Successor															Predecessor
In thousands, except per-BOE amounts and tax rates						Nine 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 rate						0.2		%				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 25% in 2021 and 2020. Our effective tax rates for the Successor three and nine months ended September 30, 2021 were significantly lower than our estimated statutory rate, primarily due to our overall deferred tax asset position and the valuation allowance offsetting those assets. As we had a pre-tax loss for the nine months ended September 30, 2021, the income tax benefit resulting from these losses is fully offset by the change in valuation allowance, resulting in essentially no tax provision.

As of September 30, 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 $0.6 million of alternative minimum tax credits, which 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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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 Ended												Nine Months Ended
						September 30,												September 30,
Per-BOE data						2021						2020						2021						2020
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 netback						18.55						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 operations						5.79						9.77						1.37						0.26
Cash flows from operations						22.76						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 derivatives						7.86						(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)

(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.

CRITICAL ACCOUNTING POLICIES

For additional discussion of our critical accounting policies, 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, oil price volatility, current or future liquidity sources or their adequacy to support our anticipated future activities, statements or predictions related to 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 or the impact of changes in commodity prices on cash flows, borrowing capacity, price and availability of advantageous commodity derivative contracts or their predicted downside cash flow protection or cash settlement payments required, mark-to-market commodity derivative values, forecasted drilling activity or methods, including the timing and location thereof, the nature of any future asset purchases or sales or the timing or proceeds thereof, estimated timing of commencement of CO2 injections in particular fields or areas, including Cedar Creek Anticline (“CCA”), or initial production responses in tertiary flooding projects, other development activities, finding costs, interpretation or prediction of formation details, hydrocarbon reserve quantities and values, CO2 reserves and supply and their availability, potential reserves, barrels or percentages of recoverable original oil in place, the impact of changes or proposed changes in Federal or state laws or outcomes of any pending litigation, prospective legislation, orders or regulations affecting the oil and gas industry or environmental regulations, competition, rates of return, and overall worldwide or U.S. economic conditions, and other variables surrounding operations and future plans.  Such forward-looking statements generally are accompanied by words such as “plan,” “estimate,” “expect,” “predict,” “forecast,” “to our knowledge,” “anticipate,” “projected,” “preliminary,” “should,” “assume,” “believe,” “may” or other words that convey, or are intended to convey, the uncertainty of future events or outcomes.  Such forward-looking information is based upon management’s current plans, expectations, estimates, and assumptions and is subject to a number of risks and uncertainties that could significantly and adversely affect current plans, anticipated actions, the timing of such actions and our financial condition and results of operations.  As a consequence, actual results may differ materially from expectations, estimates or assumptions expressed in or implied by any forward-looking statements made by us or on our behalf.  Among the factors that could cause actual results to differ materially are fluctuations in worldwide oil prices or in U.S. oil prices and consequently in the prices received or demand for our oil produced; decisions as to production levels and/or pricing by OPEC+ or production levels by U.S. producers in future periods; success of our risk management techniques; access to and terms of credit in the commercial banking or other debt markets; fluctuations in the prices of goods and services; the uncertainty of drilling results and reserve estimates; operating hazards and remediation costs; disruption of operations and damages from cybersecurity breaches, or from well incidents, climate events such as hurricanes, tropical storms, floods, forest fires, or other natural occurrences; conditions in the worldwide financial, trade and credit markets; general economic conditions; competition; government regulations, including changes in tax or environmental laws or regulations and 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

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, expectation of future commodity 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 2022 using NYMEX fixed-price swaps and costless collars. Depending on market conditions, we may continue to add to our existing 2022 hedges. See also Note 6, Commodity Derivative Contracts, and Note 7, 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.

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, 2021, our commodity derivative contracts were recorded at their fair value, which was a net liability of $209.5 million, a $35.9 million decrease from the $245.4 million net liability recorded at June 30, 2021, and a $150.7 million increase from the $58.8 million net liability recorded at December 31, 2020.  These changes are primarily related to the expiration of commodity derivative contracts during the three and nine months ended September 30, 2021, new commodity derivative contracts entered into during 2021 for future periods, and to the changes in oil futures prices from period to period.

Commodity Derivative Sensitivity Analysis

Based on NYMEX crude oil futures prices as of September 30, 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 thousands						Receipt / (Payment)
Based on:
Futures prices as of September 30, 2021						$	(197,214)
10% increase in prices						(277,213)
10% decrease in prices						(125,537)

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, 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 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

The information under Note 8, Commitments and Contingencies, to the Unaudited Condensed Consolidated Financial Statements is incorporated herein by reference.

Item 1A. Risk Factors

Please refer to Part I, Item 1A of the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2020. There have been no material changes to our risk factors contained in our Annual Report on Form 10-K for the year ended December 31, 2020.

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

None.

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
10(a)*						First Amendment to Credit Agreement, dated as of November 3, 2021, by and among Denbury Inc., as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent, and the Lenders 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 Officer and Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS*						Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document
101.SCH*						Inline XBRL Taxonomy Extension Schema Document
101.CAL*						Inline XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF*						Inline XBRL Taxonomy Extension Definition Linkbase Document
101.LAB*						Inline XBRL Taxonomy Extension Label Linkbase Document
101.PRE*						Inline XBRL Taxonomy Extension Presentation Linkbase Document
104						The 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.

**    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, 2021						/s/ Mark C. Allen
						Mark C. Allen Executive Vice President and Chief Financial Officer
November 4, 2021						/s/ Nicole Jennings
						Nicole Jennings Vice President and Chief Accounting Officer

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