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~~2022

☐ 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,

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,~~2022, was ~~50,122,417.~~49,800,113.

Denbury Inc.

Table of Contents

Page

PART I. FINANCIAL INFORMATION

Item 1.

Financial Statements

Unaudited Condensed Consolidated Balance Sheets

Unaudited Condensed Consolidated Statements of Operations

Unaudited Condensed Consolidated Statements of Cash Flows

Unaudited Condensed Consolidated Statements of Changes in Stockholders’ Equity

Notes to Unaudited Condensed Consolidated Financial Statements

Item 2.

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

1917

Item 3.

Quantitative and Qualitative Disclosures about Market Risk

3832

Item 4.

Controls and Procedures

3934

PART II. OTHER INFORMATION

Unregistered Sales of Equity Securities and Use of Proceeds

4136

Item 3.

Defaults Upon Senior Securities

4136

Item 4.

Mine Safety Disclosures

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			September 30, 2022		December 31, 2021
Assets	Assets					Assets
Current assets	Current assets					Current assets
Cash and cash equivalents	Cash and cash equivalents	$	1,783	$	518	Cash and cash equivalents	$	519	$	3,671
Restricted cash		—		1,000
Accrued production receivable	Accrued production receivable	144,370		91,421		Accrued production receivable	176,249		143,365
Trade and other receivables, net	Trade and other receivables, net	20,867		19,682		Trade and other receivables, net	19,035		19,270
Derivative assets	Derivative assets	—		187		Derivative assets	26,782		—
Prepaids	Prepaids	10,872		14,038		Prepaids	27,060		9,099
Total current assets	Total current assets	177,892		126,846		Total current assets	249,645		175,405
Property and equipment	Property and equipment					Property and equipment
Oil and natural gas properties (using full cost accounting)	Oil and natural gas properties (using full cost accounting)					Oil and natural gas properties (using full cost accounting)
Proved properties	Proved properties	1,011,545		851,208		Proved properties	1,325,866		1,109,011
Unevaluated properties	Unevaluated properties	108,258		85,304		Unevaluated properties	192,784		112,169
CO2 properties	CO2 properties	188,752		188,288		CO2 properties	187,690		183,369
Pipelines	Pipelines	193,669		133,485		Pipelines	219,090		224,394
CCUS storage sites and related assets						CCUS storage sites and related assets	32,348		—
Other property and equipment	Other property and equipment	94,763		86,610		Other property and equipment	102,627		93,950
Less accumulated depletion, depreciation, amortization and impairment	Less accumulated depletion, depreciation, amortization and impairment	(151,844)		(41,095)		Less accumulated depletion, depreciation, amortization and impairment	(270,593)		(181,393)
Net property and equipment	Net property and equipment	1,445,143		1,303,800		Net property and equipment	1,789,812		1,541,500
Operating lease right-of-use assets	Operating lease right-of-use assets	18,253		20,342		Operating lease right-of-use assets	17,065		19,502
Derivative assets						Derivative assets	9,048		—

Intangible assets, net	Intangible assets, net	90,533		97,362		Intangible assets, net	81,410		88,248
Restricted cash for future asset retirement obligations						Restricted cash for future asset retirement obligations	47,633		46,673
Other assets	Other assets	80,444		86,408		Other assets	48,718		31,625
Total assets	Total assets	$	1,812,265	$	1,634,758	Total assets	$	2,243,331	$	1,902,953
Liabilities and Stockholders’ Equity	Liabilities and Stockholders’ Equity					Liabilities and Stockholders’ Equity
Current liabilities	Current liabilities					Current liabilities
Accounts payable and accrued liabilities	Accounts payable and accrued liabilities	$	211,894	$	112,671	Accounts payable and accrued liabilities	$	259,015	$	191,598
Oil and gas production payable	Oil and gas production payable	69,717		49,165		Oil and gas production payable	89,311		75,899
Derivative liabilities	Derivative liabilities	193,015		53,865		Derivative liabilities	33,868		134,509
Current maturities of long-term debt		17,332		68,008

Operating lease liabilities	Operating lease liabilities	3,338		1,350		Operating lease liabilities	4,392		4,677
Total current liabilities	Total current liabilities	495,296		285,059		Total current liabilities	386,586		406,683
Long-term liabilities	Long-term liabilities					Long-term liabilities
Long-term debt, net of current portion	Long-term debt, net of current portion	—		70,000		Long-term debt, net of current portion	15,000		35,000
Asset retirement obligations	Asset retirement obligations	243,184		179,338		Asset retirement obligations	301,764		284,238
Derivative liabilities		16,435		5,087

Deferred tax liabilities, net	Deferred tax liabilities, net	1,241		1,274		Deferred tax liabilities, net	54,940		1,638
Operating lease liabilities	Operating lease liabilities	17,362		19,460		Operating lease liabilities	14,726		17,094
Other liabilities	Other liabilities	25,954		20,872		Other liabilities	17,438		22,910
Total long-term liabilities	Total long-term liabilities	304,176		296,031		Total long-term liabilities	403,868		360,880
Commitments and contingencies (Note 8)		0		0
Commitments and contingencies (Note 9)						Commitments and contingencies (Note 9)
Stockholders’ equity	Stockholders’ equity					Stockholders’ equity
Preferred stock, $.001 par value, 50,000,000 shares authorized, none issued and outstanding	Preferred stock, $.001 par value, 50,000,000 shares authorized, none issued and outstanding	—		—		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
Common stock, $.001 par value, 250,000,000 shares authorized; 49,793,270 and 50,193,656 shares issued, respectively						Common stock, $.001 par value, 250,000,000 shares authorized; 49,793,270 and 50,193,656 shares issued, respectively	50		50
Paid-in capital in excess of par	Paid-in capital in excess of par	1,128,030		1,104,276		Paid-in capital in excess of par	1,042,438		1,129,996
Accumulated deficit		(115,287)		(50,658)
Retained earnings						Retained earnings	410,389		5,344

Total stockholders’ equity	Total stockholders’ equity	1,012,793		1,053,668		Total stockholders’ equity	1,452,877		1,135,390
Total liabilities and stockholders’ equity	Total liabilities and stockholders’ equity	$	1,812,265	$	1,634,758	Total liabilities and stockholders’ equity	$	2,243,331	$	1,902,953

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

Table of Contents

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			Three Months Ended September 30,				Nine Months Ended September 30,
									2022		2021		2022		2021
Revenues and other income	Revenues and other income							Revenues and other income
Oil, natural gas, and related product sales	Oil, natural gas, and related product sales	$	308,454	$	22,321	$	153,090	Oil, natural gas, and related product sales	$	395,223	$	308,454	$	1,232,104	$	826,607
CO2 sales and transportation fees	CO2 sales and transportation fees	12,237		967		6,517		CO2 sales and transportation fees	18,586		12,237		44,618		31,599
Oil marketing revenues	Oil marketing revenues	12,593		151		3,332		Oil marketing revenues	17,663		12,593		47,725		26,538
Other income	Other income	10,451		94		7,097		Other income	8,015		10,451		9,055		11,518
Total revenues and other income	Total revenues and other income	343,735		23,533		170,036		Total revenues and other income	439,487		343,735		1,333,502		896,262
Expenses	Expenses							Expenses
Lease operating expenses	Lease operating expenses	116,536		11,484		59,708		Lease operating expenses	134,464		116,536		376,643		308,731
Transportation and marketing expenses	Transportation and marketing expenses	5,985		1,344		8,155		Transportation and marketing expenses	5,191		5,985		14,638		22,304
CO2 operating and discovery expenses	CO2 operating and discovery expenses	1,963		242		955		CO2 operating and discovery expenses	2,066		1,963		6,564		4,487
Taxes other than income	Taxes other than income	24,154		2,073		13,473		Taxes other than income	33,789		24,154		101,487		65,499
Oil marketing purchases	Oil marketing purchases	11,940		139		3,288		Oil marketing purchases	19,095		11,940		47,162		25,763
General and administrative expenses	General and administrative expenses	15,388		1,735		15,013		General and administrative expenses	21,071		15,388		58,998		62,821
Interest, net of amounts capitalized of $1,249, $183 and $4,704, respectively		669		334		7,704
Interest, net of amounts capitalized of $1,044, $1,249, $3,177 and $3,500, respectively								Interest, net of amounts capitalized of $1,044, $1,249, $3,177 and $3,500, respectively	909		669		3,092		3,457
Depletion, depreciation, and amortization	Depletion, depreciation, and amortization	37,691		5,283		36,317		Depletion, depreciation, and amortization	37,680		37,691		108,425		113,522
Commodity derivatives expense (income)	Commodity derivatives expense (income)	41,745		(4,035)		4,609		Commodity derivatives expense (income)	(109,248)		41,745		140,325		330,152

Write-down of oil and natural gas properties	Write-down of oil and natural gas properties	—		—		261,677		Write-down of oil and natural gas properties	—		—		—		14,377
Reorganization items, net		—		—		849,980
Other expenses	Other expenses	4,553		2,164		22,084		Other expenses	2,726		4,553		11,459		9,913
Total expenses	Total expenses	260,624		20,763		1,282,963		Total expenses	147,743		260,624		868,793		961,026
Income (loss) before income taxes	Income (loss) before income taxes	83,111		2,770		(1,112,927)		Income (loss) before income taxes	291,744		83,111		464,709		(64,764)
Income tax provision (benefit)	Income tax provision (benefit)	403		12		(303,807)		Income tax provision (benefit)	41,321		403		59,664		(135)
Net income (loss)	Net income (loss)	$	82,708	$	2,758	$	(809,120)	Net income (loss)	$	250,423	$	82,708	$	405,045	$	(64,629)

Net income (loss) per common share	Net income (loss) per common share							Net income (loss) per common share
Basic	Basic	$	1.62	$	0.06	$	(1.63)	Basic	$	4.89	$	1.62	$	7.86	$	(1.27)
Diluted	Diluted	$	1.51	$	0.06	$	(1.63)	Diluted	$	4.66	$	1.51	$	7.43	$	(1.27)

Weighted average common shares outstanding	Weighted average common shares outstanding							Weighted average common shares outstanding
Basic	Basic	51,094		50,000		497,398		Basic	51,182		51,094		51,512		50,807
Diluted	Diluted	54,714		50,000		497,398		Diluted	53,715		54,714		54,524		50,807

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

Table of Contents

Denbury Inc.

Unaudited Condensed Consolidated Statements of ~~Operations~~Cash Flows

(In ~~thousands, except per-share data)~~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
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


	Nine Months Ended September 30,
	2022		2021
Cash flows from operating activities
Net income (loss)	$	405,045	$	(64,629)
Adjustments to reconcile net income (loss) to cash flows from operating activities
Depletion, depreciation, and amortization	108,425		113,522
Write-down of oil and natural gas properties	—		14,377
Deferred income taxes	53,301		(34)
Stock-based compensation	11,491		22,788
Commodity derivatives expense	140,325		330,152
Payment on settlements of commodity derivatives	(276,796)		(179,466)
Debt issuance costs	2,465		2,055
Gain from asset sales and other	(1,119)		(7,026)
Other, net	(11,543)		(2,448)
Changes in assets and liabilities, net of effects from acquisitions
Accrued production receivable	(32,884)		(52,948)
Trade and other receivables	66		(1,809)
Other current and long-term assets	(21,729)		7,337
Accounts payable and accrued liabilities	28,359		47,484
Oil and natural gas production payable	13,412		23,168
Asset retirement obligations and other liabilities	(22,409)		(4,966)
Net cash provided by operating activities	396,409		247,557

Cash flows from investing activities
Oil and natural gas capital expenditures	(217,834)		(113,041)
CCUS storage sites and related capital expenditures	(27,518)		—
Acquisitions of oil and natural gas properties	(874)		(10,927)
Pipelines and plants capital expenditures	(22,259)		(19,123)
Net proceeds from sales of oil and natural gas properties and equipment	237		19,053
Equity investment	(10,000)		—
Other	(9,746)		5,797
Net cash used in investing activities	(287,994)		(118,241)

Cash flows from financing activities
Bank repayments	(808,000)		(697,000)
Bank borrowings	788,000		627,000


Pipeline financing repayments	—		(50,676)
Common stock repurchase program	(100,028)		—
Other	9,421		(2,426)
Net cash used in financing activities	(110,607)		(123,102)
Net increase (decrease) in cash, cash equivalents, and restricted cash	(2,192)		6,214
Cash, cash equivalents, and restricted cash at beginning of period	50,344		42,248
Cash, cash equivalents, and restricted cash at end of period	$	48,152	$	48,462

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

Table of Contents

Denbury Inc.

Unaudited Condensed Consolidated Statements of ~~Cash Flows~~Changes in Stockholders' Equity

(InDollar amounts 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


	Common Stock ($.001 Par Value)			Paid-In Capital in Excess of Par		Retained Earnings		Treasury Stock (at cost)
	Shares	Amount						Shares	Amount		Total Equity
Balance – December 31, 2021	50,193,656	$	50	$	1,129,996	$	5,344	—	$	—	$	1,135,390
Issued pursuant to stock compensation plans	141,581	—		—		—		—	—		—
Stock-based compensation	—	—		3,142		—		—	—		3,142
Tax withholding for stock compensation plans	—	—		(58)		—		—	—		(58)
Issued pursuant to exercise of warrants	14,153	—		47		—		—	—		47
Net loss	—	—		—		(872)		—	—		(872)
Balance – March 31, 2022	50,349,390	50		1,133,127		4,472		—	—		1,137,649







Stock repurchase program	(457,549)	—		—		—		457,549	(28,751)		(28,751)
Forfeited pursuant to stock compensation plans	(3,264)	—		—		—		—	—		—
Stock-based compensation	—	—		4,400		—		—	—		4,400
Tax withholding for stock compensation plans	—	—		(5)		—		—	—		(5)
Issued pursuant to exercise of warrants	987,411	1		53		—		—	—		54
Net income	—	—		—		155,494		—	—		155,494
Balance – June 30, 2022	50,875,988	51		1,137,575		159,966		457,549	(28,751)		1,268,841
Stock repurchase program	(1,157,807)	—		—		—		1,157,807	(71,277)		(71,277)
Net issued pursuant to stock compensation plans	3,684	—		—		—		—	—		—
Stock-based compensation	—	—		4,691		—		—	—		4,691
Retired Treasury Shares	—	(1)		(100,029)		—		(1,615,391)	100,030		—
Tax withholding for stock compensation plans	(35)	—		—		—		35	(2)		(2)
Issued pursuant to exercise of warrants	71,440	—		201		—		—	—		201

Net income	—	—		—		250,423		—	—		250,423
Balance – September 30, 2022	49,793,270	$	50	$	1,042,438	$	410,389	—	$	—	$	1,452,877


	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	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	—		195		—		—	—		195
Net loss	—	—		—		(69,642)		—	—		(69,642)
Balance – March 31, 2021	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	—		292		—		—	—		292
Net loss	—	—		—		(77,695)		—	—		(77,695)
Balance – June 30, 2021	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	—		201		—		—	—		201
Net income	—	—		—		82,708		—	—		82,708
Balance – September 30, 2021	50,120,895	$	50	$	1,128,030	$	(115,287)	—	$	—	$	1,012,793

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

Table of Contents

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.~~regions of the United States. 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 CO~~2 ~~in EOR significantly reduces the carbon footprint of the oil that Denbury produces, making the Company’s scope 1 and 2 CO~~2 ~~emissions negative today, with a goal to also fully offset scope 3 CO~~2 ~~emissions within this decade, primarily through increasing the amount of captured industrial-sourced CO~~2 ~~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~~2021 (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);~~2022, our consolidated results of operations for the three and nine months ended September 30, 2022 and 2021, our consolidated ~~statement~~cash flows for the nine months ended September 30, 2022 and 2021, and our consolidated statements 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)~~2022 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, 2020.2021.

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	In thousands	September 30, 2021		December 31, 2020		In thousands	September 30, 2022		December 31, 2021
Cash and cash equivalents	Cash and cash equivalents	$	1,783	$	518	Cash and cash equivalents	$	519	$	3,671
Restricted cash, current		—		1,000
Restricted cash included in other assets		46,679		40,730

Restricted cash for future asset retirement obligations						Restricted cash for future asset retirement obligations	47,633		46,673
Total cash, cash equivalents, and restricted cash shown in the Unaudited Condensed Consolidated Statements of Cash Flows	Total cash, cash equivalents, and restricted cash shown in the Unaudited Condensed Consolidated Statements of Cash Flows	$	48,462	$	42,248	Total cash, cash equivalents, and restricted cash shown in the Unaudited Condensed Consolidated Statements of Cash Flows	$	48,152	$	50,344

Restricted cash ~~included in other assets~~for future asset retirement obligations 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.~~obligations.

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. Basic weighted average common shares exclude shares of nonvested restricted stock (although nonvested restricted stock is issued and outstanding upon grant). As these restricted shares vest, they will be included in the shares outstanding used to calculate basic net income (loss) per common share. Restricted stock units and performance stock units are also excluded from basic weighted

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Denbury Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

average common shares outstanding until the vesting date. Basic weighted average common shares during the three and nine months ended September 30, 2022 includes 1,404,649 performance-based and restricted stock units which are fully vested as of September 30, 2022; however, the shares underlying these stock units are not included in shares currently issued or outstanding as actual delivery of the shares is not scheduled to occur until December 4, 2023.

Diluted net income (loss) per common share is calculated in the same manner but includes the impact of all potentially dilutive securities. Potentially dilutive securities ~~during the Successor periods consist of nonvested~~include restricted stock, restricted stock units, performance stock units, shares to be issued under the employee stock purchase plan (“ESPP”), 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~~2022 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),~~2021, 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:


						Three Months Ended		Nine Months Ended
		Successor		Predecessor		September 30,		September 30,
In thousands	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	In thousands	2022	2021	2022	2021

Weighted average common shares outstanding – basic	Weighted average common shares outstanding – basic	51,094	50,000	497,398	Weighted average common shares outstanding – basic	51,182	51,094	51,512	50,807
Effect of potentially dilutive securities	Effect of potentially dilutive securities				Effect of potentially dilutive securities
Restricted stock units		908	—	—
Restricted stock, restricted stock units and performance stock units					Restricted stock, restricted stock units and performance stock units	664	908	615	—

Warrants	Warrants	2,712	—	—	Warrants	1,869	2,712	2,397	—

Weighted average common shares outstanding – diluted	Weighted average common shares outstanding – diluted	54,714	50,000	497,398	Weighted average common shares outstanding – diluted	53,715	54,714	54,524	50,807

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~~recorded a net loss for the period. Assuming the Company had recorded net income during ~~those periods. The~~the nine months ended September 30, 2021, the weighted average diluted shares outstanding would have been 53.4 million ~~for~~(including the ~~nine months ended September 30, 2021, 580.0~~impact of 0.8 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.~~1.8 million shares with respect to warrants).

The following outstanding securities could potentially dilute earnings per share in the future, but were excluded from the computation of diluted net ~~loss~~income (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			September 30,
In thousands	In thousands	September 30, 2021	September 30, 2020	In thousands	2022	2021
Restricted stock units		1,255	—
Restricted stock, restricted stock units and performance stock units				Restricted stock, restricted stock units and performance stock units	63	1,255

Warrants	Warrants	5,314	5,526	Warrants	—	5,314
Employee Stock Purchase Plan				Employee Stock Purchase Plan	8	—

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,~~2022, the Company had approximately ~~5.3~~3.2 million warrants outstanding that can be exercised for shares of ~~the Successor’s~~our common stock, at an exercise price of $32.59 per share for the ~~2.6~~1.8 million ~~series~~Series A warrants outstanding and at an exercise price of $35.41 per share for the ~~2.7~~1.4 million ~~series~~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. IfThe Series A warrants are exercisable until September 18, 2025, and the Series B warrants are exercisable until September 18, 2023, at which times the warrants expire. During the three and nine months ended September 30, 2022, 119,367 and 1,941,380 warrants were exercised for a total of 71,440 shares and 1,073,004 shares, respectively, most of which were exercised on a cashless ~~basis, the amount of dilution will be less than 5.3 million shares.~~basis.

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~~

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Denbury Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

(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.~~2021. The write-down was primarily a result of the March 2021 acquisition of Wyoming ~~property interests~~CO2 EOR properties (see Note 2, Acquisition and ~~Divestitures~~Divestiture) 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. We did not record a ceiling test write-down during the three or nine months ended September 30, 2022.

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, 2020CCUS Storage Sites 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~~Other Assets

~~Income Taxes.~~Capitalized Costs. ~~In December 2019,~~We capitalize costs that we incur to acquire and develop storage sites for the ~~Financial Accounting Standards Board (“FASB”) issued ASU 2019-12,~~ injection of CO~~Income Taxes (Topic 740) – Simplifying~~2. These costs generally include, or are expected to include, expenditures for acquiring surface and subsurface rights; third-party acquisition costs; permitting; drilling; facilities; environmental monitoring equipment for groundwater and storage site gas; engineering; capitalized interest; on-site road construction and other capital infrastructure costs. If it is determined that a storage site will no longer be pursued, developed or utilized, all previously capitalized costs associated with that site are expensed.

Amortization. Our CCUS storage sites are currently in the ~~Accounting for Income Taxes~~development stage and not yet operational. Accordingly, we currently have no amortization of capitalized costs. Amortization of these costs will begin when CO2 storage operations commence.

Investment in Project Development Company (“~~ASU 2019-12”~~Clean Hydrogen Works”). of Planned Louisiana Blue Hydrogen Ammonia Project. In September 2022, we made a $10.0 million investment in the project development company of a planned blue hydrogen/ammonia multi-block facility, while also signing a definitive agreement for the transportation and sequestration of CO2 for the first two blocks of the proposed plant. We have committed to invest another $10.0 million when certain project milestones are achieved. The ~~objective~~investment is included in “Other assets” in the Unaudited Condensed Consolidated Balance Sheet as 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.September 30, 2022.

Note 2. Acquisition and ~~Divestitures~~Divestiture

2021 Acquisition of Wyoming CO2 EOR ~~Fields~~Properties

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~~purchase price was $10.9 million (after final closing adjustments) plus two contingent $4 million cash payments ~~one in January 2022 and one in January 2023, of $4 million each, conditioned on~~if NYMEX WTI oil prices ~~averaging~~average at least $50 per Bbl during each of 2021 and 2022. ~~The fair value of~~We made the first contingent ~~consideration on~~payment in January 2022 and if the ~~acquisition date was $5.3~~price condition is met, the second $4 million ~~and as of September 30, 2021, the~~payment will be due in January 2023. The fair value of the contingent consideration recorded on our Unaudited Condensed Consolidated Balance Sheets was ~~$7.4 million. The $2.1~~$3.9 million ~~increase at~~as of 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.2022.

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~~inputs, were 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

final closing adjustments and evaluation of reserves and 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~~

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 proved 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~~Financial Accounting Standards Board (“FASB”) Codification (“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 aone 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,~~In certain situations, the Company enters into marketing arrangements for the purchase and subsequent sale of crude oil ~~for~~from third parties. ~~Revenues~~We recognize the revenues received and the associated expenses ~~from~~incurred on these ~~transactions are presented~~sales on a gross basis, as “Oil marketing revenues” and “Oil marketing purchases” in our Unaudited Condensed Consolidated Statements of Operations, since 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~~table summarizes our revenues by product type for the ~~periods indicated:~~three and nine months ended September 30, 2022 and 2021:

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


									Three Months Ended				Nine Months Ended
		Successor				Predecessor			September 30,				September 30,
In thousands	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		In thousands	2022		2021		2022		2021
Oil sales	Oil sales	$	818,714	$	22,311	$	489,251	Oil sales	$	389,543	$	305,093	$	1,217,377	$	818,714
Natural gas sales	Natural gas sales	7,893		10		2,850		Natural gas sales	5,680		3,361		14,727		7,893
CO2 sales and transportation fees	CO2 sales and transportation fees	31,599		967		21,049		CO2 sales and transportation fees	18,586		12,237		44,618		31,599
Oil marketing revenues	Oil marketing revenues	26,538		151		8,543		Oil marketing revenues	17,663		12,593		47,725		26,538
Total revenues	Total revenues	$	884,744	$	23,439	$	521,693	Total revenues	$	431,472	$	333,284	$	1,324,447	$	884,744

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,~~September 18, 2020, we entered into a $575 million credit agreement for a senior secured revolving credit facility 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.~~year. 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. Our outstanding borrowings under the Bank Credit Agreement, totaled $15.0 million and $35.0 million as of September 30, 2022 and December 31, 2021, respectively.

On May 4, 2022, we entered into a Second Amendment to the Bank Credit Agreement, which among other things:

~~Table of Contents~~•Increased the borrowing base and lender commitments from $575 million to $750 million;

~~Denbury Inc.~~•Extended the maturity date from January 30, 2024 to May 4, 2027;

~~Notes to Unaudited Condensed Consolidated Financial Statements~~

~~The~~•Modified the interest provisions on loans under the Bank Credit Agreement ~~limits our ability~~to (1) reduce the applicable margin for alternate base rate loans from 2% to 3% per annum to 1.5% to 2.5% per annum and (2) replace provisions referencing LIBOR loans with Secured Overnight Financing Rate loans, with an applicable margin of 2.5% to 3.5% per annum; and

•Permitted us to pay dividends on our common stock orand make other unlimited restricted payments ~~in an amount not to exceed “Distributable Free Cash Flow”, but only if~~and investments so long as (1) no event of default or borrowing base deficiency exists; (2) our total leverage ratio is 21.5 to 1 or lower; and (3) availability under the Bank Credit Agreement is at least 20%. of the borrowing base.

As part of our Fall 2022 semiannual borrowing base redetermination, the borrowing base and lender commitments for our Bank Credit Agreement were reaffirmed at $750 million, with our next scheduled redetermination around May 1, 2023.

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.~~certain exceptions to such limitations, as specified in the Bank Credit Agreement. Our Bank Credit Agreement required certain minimum commodity hedge levels in connection with our emergence from bankruptcy; however, these conditions were met as of December 31, 2020, and we currently have no ongoing hedging requirements under the Bank Credit Agreement.

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.

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Notes to Unaudited Condensed Consolidated Financial Statements

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.

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 CO~~2 ~~pipeline system. The final quarterly installment of $17.5 million was paid on October 29, 2021.~~Agreement and amendments thereto.

Note 5. Stockholders’ Equity

Share Repurchase Program

In early May 2022, our Board of Directors authorized a common share repurchase program for up to $250 million of outstanding Denbury common stock. During June and July 2022, the Company repurchased 1,615,356 shares of Denbury common stock under this program for approximately $100 million, at an average price of $61.92 per share. In August 2022, the Board increased Denbury’s stock repurchase authorization by $100 million, thus a total of $250.0 million of common stock currently remains authorized for future repurchases under this program. The program has no pre-established ending date and may be suspended or discontinued at any time. The Company is not obligated to repurchase any dollar amount or specific number of shares of its common stock under the program.

Retirement of Treasury Stock

During the quarter ended September 30, 2022, we retired 1.6 million shares of existing treasury stock, with a carrying value of $100.0 million, acquired primarily through our stock repurchase program. Upon the retirement of treasury stock, we reduce common stock by the par value of common stock retired, and we reduce additional paid-in capital by the value of those shares in excess of par value.

Employee Stock Purchase Plan

On June 1, 2022, the Company’s stockholders approved the Denbury Inc. Employee Stock Purchase Plan authorizing the sale of up to 2,000,000 shares of common stock thereunder. In accordance with the ESPP, full-time employees may contribute up to 10% of their base salary, subject to certain limitations, to purchase previously unissued Denbury common stock. Participants in the ESPP may purchase common stock at a 15% discount to the fair market value of a share of common stock determined as the lower of the closing sales price on the first or last trading day of each offering period. The first offering period under the ESPP commenced on September 1, 2022 and will end on December 31, 2022. The plan is administered by the Compensation Committee of our Board of Directors.

Note 6. Income Taxes

AsWe make estimates and judgments in determining our income tax expense for financial reporting purposes. These estimates and judgments occur in the calculation of certain tax assets and liabilities that arise from differences in the timing and recognition of revenue and expense for tax and financial reporting purposes. Significant judgment is required in estimating valuation allowances, and in making this determination we consider all available positive and negative evidence and make certain assumptions. The realization of a deferred tax asset ultimately depends on the existence of sufficient taxable income in the applicable carryback or carryforward periods. In our assessment, we consider the nature, frequency, and severity of current and cumulative losses, as well as historical and forecasted financial results, the overall business environment, our industry’s historic cyclicality, the reversal of existing deferred tax assets and liabilities, and tax planning strategies.

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Denbury Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

We assess the valuation allowance recorded on our deferred tax assets, which was $125.5 million at December 31, 2021, on a quarterly basis. This valuation allowance on our federal and certain state deferred tax assets was recorded in September ~~30, 2021,~~2020 after the application of fresh start accounting, as (1) the tax basis of our assets, primarily our oil and gas properties, iswas in excess of ~~their~~the carrying value, as adjusted for fresh start accounting ~~on September 18, 2020; therefore,~~and (2) our historical pre-tax income reflected a three-year cumulative loss primarily due to ceiling test write-downs and reorganization items that were recorded in 2020. While we ~~are currently~~continued to be in a ~~net deferred tax asset position. Based on all available evidence, both positive and negative,~~cumulative three-year-loss position through the first quarter of 2022, we ~~continue to record a valuation allowance on our underlying deferred tax assets~~initially determined as of ~~September 30, 2021, as we believe~~March 31, 2022, that there was sufficient positive evidence, primarily related to a substantial increase in worldwide oil prices, to conclude that $64.9 million of our federal and certain state deferred tax assets are more likely than not ~~more-likely-than-not~~ to be realized. Accordingly, we reversed $5.9 million, $18.8 million and $29.2 million of this valuation allowance during the three months ended March 31, June 30, and September 30, 2022, respectively, and currently expect to reverse the remaining $11.0 million during the fourth quarter of 2022, resulting in a reduction to our annualized effective tax rate. We ~~intend~~continue to maintain ~~the~~a valuation ~~allowances on our deferred~~allowance of $60.6 million for certain state tax ~~assets until there is sufficient evidence~~benefits that we currently do not expect 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.~~realize before their expiration.

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~~2022 and ~~2020.~~2021. Our effective tax ~~rates~~rate for the three and nine months ended September 30, ~~2021 (Successor) differed from~~2022 was significantly lower than our estimated statutory rate asprimarily due to the ~~deferred tax expense generated by~~release of the ~~operating income for~~valuation allowance that was recorded in 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.~~2022.

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~~Denbury Inc.~~

~~Notes to Unaudited Condensed Consolidated Financial Statements~~

Note 6.7. 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, costless collars, three-way collars, fixed-price swaps, fixed-price swaps enhanced with a sold put, and basis swaps. The production that we hedge has varied from year to year depending on our levels of debt, financial strength and expectation of future commodity prices, 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.prices.

We manage and control market and counterparty credit risk through established internal control procedures that are reviewed on an ongoing basis. We attempt to minimize credit risk exposure to counterparties through formal credit policies, monitoring procedures and diversification, and all of our commodity derivative contracts are with parties that are lenders under our Bank Credit Agreement (or affiliates of such lenders). As of September 30, ~~2021,~~2022, all of our outstanding derivative contracts were subject to enforceable master netting arrangements whereby payables on those contracts can be offset against receivables from separate derivative contracts with the same counterparty. It is our policy to classify derivative assets and liabilities on a gross basis on our balance sheets, even if the contracts are subject to enforceable master netting arrangements.

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Denbury Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

The following table summarizes our commodity derivative contracts as of September 30, ~~2021,~~2022, 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.


Months	Index Price	Volume (Barrels per day)	Contract Prices ($/Bbl)
			Weighted Average Price
			Swap		Floor		Ceiling
Oil Contracts:
2022 Fixed-Price Swaps
Oct – Dec	NYMEX	9,500	$	57.52	$	—	$	—
2022 Costless Collars
Oct – Dec	NYMEX	11,500	$	—	$	52.39	$	67.29
2023 Fixed-Price Swaps
Jan – June	NYMEX	7,500	$	75.29	$	—	$	—
July – Dec	NYMEX	5,000	76.26		—		—
2023 Costless Collars
Jan – June	NYMEX	17,500	$	—	$	69.71	$	100.42
July – Dec	NYMEX	9,000	—		68.33		100.69

Note 7.8. Fair Value Measurements

The FASC Fair Value Measurement topic defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (often referred to as the “exit price”). We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. We primarily apply the income approach for recurring fair value measurements

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~~Denbury Inc.~~

~~Notes to Unaudited Condensed Consolidated Financial Statements~~

and endeavor to utilize the best available information. Accordingly, we utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. We are able to classify fair value balances based on the observability of those inputs. The FASC establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are as follows:

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

•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.

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Denbury Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

The following table sets forth, by level within the fair value hierarchy, our financial assets and liabilities that were accounted for at fair value on a recurring basis as of the periods indicated:


		Fair Value Measurements Using:									Fair Value Measurements Using:
In thousands	In thousands	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total		In thousands	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
September 30, 2021
September 30, 2022										September 30, 2022
Assets										Assets
Oil derivative contracts – current										Oil derivative contracts – current	$	—	$	26,782	$	—	$	26,782
Oil derivative contracts – long-term										Oil derivative contracts – long-term	—		9,048		—		9,048
Total Assets										Total Assets	$	—	$	35,830	$	—	$	35,830

Liabilities										Liabilities
Oil derivative contracts – current										Oil derivative contracts – current	$	—	$	(33,868)	$	—	$	(33,868)
Oil derivative contracts – long-term										Oil derivative contracts – long-term	—		—		—		—
Total Liabilities										Total Liabilities	$	—	$	(33,868)	$	—	$	(33,868)

December 31, 2021										December 31, 2021

Liabilities	Liabilities									Liabilities
Oil derivative contracts – current	Oil derivative contracts – current	$	—	$	(193,015)	$	—	$	(193,015)	Oil derivative contracts – current	$	—	$	(134,509)	$	—	$	(134,509)
Oil derivative contracts – long-term		—		(16,435)		—		(16,435)

Total Liabilities	Total Liabilities	$	—	$	(209,450)	$	—	$	(209,450)	Total Liabilities	$	—	$	(134,509)	$	—	$	(134,509)

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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~~Denbury Inc.~~

~~Notes to Unaudited Condensed Consolidated Financial Statements~~

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

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 September 30, 2022 and December 31, ~~2020, excluding pipeline financing obligations,~~2021 was ~~$70.0 million.~~$15.0 million and $35.0 million, respectively. We have other financial instruments consisting primarily of cash, cash equivalents, U.S. Treasury notes, short-term receivables and payables that approximate fair value due to the nature of the instrument and the relatively short maturities.

Note 8.9. Commitments and Contingencies

Litigation and Regulatory Proceedings

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 isand regulatory proceedings are 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.

On May 26, 2022, the Pipeline and Hazardous Materials Safety Administration (“PHMSA”) of the U.S. Department of Transportation issued a Notice of Probable Violation, Proposed Civil Penalty, and Proposed Compliance Order (“NOPV”) relating to the February 2020 pipeline failure near Satartia, Mississippi in our CO2 pipeline running between the Tinsley and Delhi fields. The NOPV proposed a preliminarily assessed civil penalty of $3.9 million in connection with the incident, which

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Denbury Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

we recorded in our second quarter of 2022 financial statements. We have responded to the NOPV and are pursuing discussions with PHMSA regarding the probable violations alleged in the NOPV, the proposed civil penalty, and the nature of the compliance order contained in the NOPV.

Note 9.10. 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


In thousands	September 30, 2022		December 31, 2021
Accounts payable	$	61,643	$	25,700
Accrued derivative settlements	13,378		27,336
Accrued lease operating expenses	32,507		27,901
Accrued asset retirement obligations – current	40,000		18,373
Accrued compensation	30,963		23,735
Taxes payable	18,823		14,453
Accrued exploration and development costs	18,418		18,936
Other	43,283		35,164
Total	$	259,015	$	191,598

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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~~2021 (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~~Scope 1 and 2 CO2 emissions negative today, with a goal to ~~also fully offset~~be net-zero on its ~~scope~~Scope 1, 2, and 3 CO2 emissions ~~within this decade,~~by 2030, primarily through increasing the amount of captured industrial-sourced CO2 used in its operations.

Carbon Capture, Use and Storage. CCUS is a process that captures CO2 from industrial sources and either reuses 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. During the nine months ended September 30, 2022, approximately 39% of the CO2 utilized in our oil and gas operations was industrial-sourced CO2, equivalent to an annualized average usage rate of over 4 million metric tons in 2022. This compares to 34% utilized during the nine months ended September 30, 2021, with the increase related to commencing CO2 injection in the first phase of our Cedar Creek Anticline (“CCA”) EOR project. 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 lead in the emerging CCUS industry, as the building of a permanent carbon capture and sequestration business by others requires both time and capital to build assets such as those we own and have been operating for years.

We have been seeking to build our CCUS business and pursue new CCUS opportunities on two fronts: first, we have been engaged with existing and potential third-party industrial CO2 emitters regarding CO2 transportation and storage solutions under long term agreements; second, we have been identifying and securing potential future sequestration sites for permanent storage. We continue to make material progress in both of these pursuits, and we currently have signed term sheets and definitive agreements for the potential future transportation and storage of up to 20 million tons of CO2 per annum from the planned capture of CO2 emissions from existing and proposed industrial plants. On the sequestration front, we have also signed agreements securing the rights to five future sequestration sites which we believe have the potential to store up to 1.5 billion metric tons of CO2.

While our use of CO2 in EOR is the only CCUS operation reflected in our historical financial and operational results (as a cost), we believe the incentives offered under Section 45Q of the Internal Revenue Code and the expansion of those incentives under the August 2022 Inflation Reduction Act will drive demand for CCUS and allow us to collect a fee for the transportation and storage of captured industrial-sourced CO2, including CO2 utilized in our EOR operations. Although we believe our first revenues associated with the sequestration of CO2 will likely occur in 2024 or 2025, we are currently incurring costs to develop and permit storage sites and will continue to advance those efforts over the next several years. During the nine months ended September 30, 2022, we capitalized $32.3 million in “CCUS storage sites and related assets” in our Unaudited Condensed Consolidated Balance Sheets, primarily consisting of acquisition costs associated with sequestration sites. In addition, during the third quarter we made a $10.0 million investment in the project development company (“Clean Hydrogen Works”) of a planned blue hydrogen/ammonia multi-block facility, while also signing a definitive agreement for the transportation and sequestration of CO2 for the first two blocks of the proposed plant. The investment is included in “Other assets” in the

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Denbury Inc.

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

Unaudited Condensed Consolidated Balance Sheet as of September 30, 2022. We have committed to invest another $10 million when certain project milestones are achieved.

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. Oil prices have historically been volatile and can fluctuate significantly over short periods of time. For example, average NYMEX WTI oil prices increased from the mid-$70s per Bbl range in the fourth quarter of 2021 to an average of approximately $109 per Bbl during the second quarter of 2022 before declining to an average of approximately $91 per Bbl during the third quarter of 2022. The ~~table below~~increases in oil prices from 2021 levels were due in part to worldwide oil supply disruptions associated with the Russian invasion of Ukraine.

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~~Denbury Inc.~~

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

The table below 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											Three Months Ended
In thousands, except per-unit data	In thousands, except per-unit data	Sept. 30, 2021		June 30, 2021		March 31, 2021		Dec. 31, 2020		Sept. 30, 2020		In thousands, except per-unit data	Sept. 30, 2022		June 30, 2022		March 31, 2022		Dec. 31, 2021		Sept. 30, 2021
Oil, natural gas, and related product sales	Oil, natural gas, and related product sales	$	308,454	$	282,708	$	235,445	$	178,787	$	175,411			Oil, natural gas, and related product sales	$	395,223	$	451,970	$	384,911	$	333,348	$	308,454
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
Payment on settlements of commodity derivatives														Payment on settlements of commodity derivatives	(55,780)		(127,959)		(93,057)		(97,774)		(77,670)
Oil, natural gas, and related product sales and commodity derivative settlements, combined														Oil, natural gas, and related product sales and commodity derivative settlements, combined	$	339,443	$	324,011	$	291,854	$	235,574	$	230,784

Average daily sales (BOE/d)	Average daily sales (BOE/d)	49,682		49,133		47,357		48,805		49,686				Average daily sales (BOE/d)	47,109		$	46,561	46,925		48,882		49,682

Average net realized oil prices	Average net realized oil prices													Average net realized oil prices
Oil price per Bbl - excluding impact of derivative settlements	Oil price per Bbl - excluding impact of derivative settlements	$	68.88	$	64.70	$	56.28	$	40.63	$	39.23			Oil price per Bbl - excluding impact of derivative settlements	$	92.77	$	108.81	$	93.17	$	75.68	$	68.88
Oil price per Bbl - including impact of derivative settlements	Oil price per Bbl - including impact of derivative settlements	51.35		50.10		47.00		43.94		43.23				Oil price per Bbl - including impact of derivative settlements	79.49		77.63		70.43		53.21		51.35

~~NYMEX WTI~~As shown in the table above, our oil and natural gas revenues have increased dramatically during 2022 due to the increase in oil prices. However, the benefit of the increase in revenues during the first half of 2022 was offset in part by the impact of higher cash payments on our commodity derivative contracts which were settled during that period. These contracts were largely required to be entered into during the fourth quarter of 2020 under the one-time requirement of our September 18, 2020 bank credit facility. During the third quarter of 2022, less of our production was hedged, and our hedges for the second half of 2022 are at more favorable prices ~~strengthened from~~and with a greater mix of collars, providing the ~~mid-$40s per Bbl range in December 2020~~potential for us to ~~an average~~realize a greater portion of ~~approximately $71 per Bbl~~increased oil prices. We paid $55.8 million 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 million2022 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~~remainder 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.2022.

Third Quarter ~~2021~~2022 Financial Results and Highlights. We recognized net income of $250.4 million, or $4.66 per diluted common share, during the third quarter of 2022, compared to a 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. Additionalprimary drivers of the comparative third quarter operating results include the following:

•Oil and natural gas revenues increased ~~$133.0~~$86.8 million ~~(76%~~(28%)~~, nearly entirely~~ due primarily to an increase in ~~commodity~~oil 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~~decreased by ~~$41.2~~$151.0 million consisting of a ~~$95.5~~$129.1 million ~~decrease~~increase in ~~cash receipts upon contract settlements~~noncash fair value changes ($~~77.7~~165.0 million ~~in payments~~gain during the third quarter of ~~2021~~2022 compared to ~~$17.8~~a $35.9 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 expensegain in the prior-year period)., and a $21.9 million decrease in cash payments upon derivative contract settlements;

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Denbury Inc.

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

•Lease operating expenses increased $17.9 million (15%), primarily due to higher power and fuel costs and workover costs; and

~~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.Income tax expense increased by $40.9 million.

Common Share Repurchase Program. In early May 2022, our Board of Directors authorized a common share repurchase program for up to $250 million of outstanding Denbury common stock. During June ~~2021 Divestiture~~and July 2022, the Company repurchased 1,615,356 shares of ~~Hartzog Draw Deep Mineral Rights.~~ ~~On June 30, 2021, we closed~~Denbury common stock under this program for approximately $100 million, at an average price of $61.92 per share. In August 2022, the ~~sale~~Board increased Denbury’s stock repurchase authorization by $100 million, thus a total of ~~undeveloped, unconventional deep mineral rights in Hartzog Draw Field in Wyoming.~~$250 million of common stock currently remains authorized for future repurchases under this program. The ~~cash proceeds~~program has no pre-established ending date and may be suspended or discontinued at any time. The Company is not obligated to repurchase any dollar amount or specific number 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~~shares of its common stock under the ~~transaction, and the sale had no impact on our production or reserves.~~program.

~~March 2021 Acquisition~~Commencement of ~~Wyoming~~Cedar Creek Anticline CO2 ~~EOR Fields.~~Injection. ~~On March 3, 2021,~~In early February 2022, 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-milecommenced CO2 ~~transportation pipeline~~injection in the first phase of our CCA EOR project. In order to stay ahead of potential supply chain delays, we have increased capital investment in the ~~acquired fields. The acquisition agreement provides for us~~second half of the year at CCA to ~~make two contingent cash payments, one~~accelerate our procurement of compression equipment and construction of CO2 recycle facilities to ensure facilities are 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 increaseplace to handle anticipated production from the ~~March 2021 acquisition date fair value. This $2.1 million increase~~field. We continue to expect tertiary oil production response from CCA in the second half of 2023. In addition, drilling and facility construction at ~~September 30, 2021 was~~ the ~~result~~Company’s Pennel CO2 pilot, in advance of ~~higher NYMEX WTI oil prices and was recorded to “Other expenses” in our Unaudited Condensed Consolidated Statements~~Phase 2 development of ~~Operations. Wind River Basin sales averaged approximately 3,015 BOE/d~~CCA, commenced during the third ~~quarter of 2021 and utilize 100% industrial-sourced CO~~2.quarter.

~~Carbon Capture, Use~~Warrant Exercises. In September 2020 we issued 2,631,579 Series A warrants with an exercise price of $32.59 per share and ~~Storage.~~ ~~CCUS is~~2,894,740 Series B warrants with an exercise price of $35.41 per share. The warrants may be exercised for cash or on a ~~process that captures CO~~2 ~~from industrial sources~~cashless basis. The Series A warrants are exercisable until September 18, 2025, and ~~reuses it or stores~~ the CO2 ~~in geologic formations in order to prevent its release into~~Series B warrants are exercisable until September 18, 2023, at which times the ~~atmosphere. We utilize CO~~2 ~~from industrial sources in our EOR operations, and our extensive CO~~2 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.warrants expire. During the three and nine months ended September 30, ~~2021,~~2022, 119,367 and 1,941,380 of Series A and B warrants were exercised for a total of 71,440 shares and 1,073,004 shares, respectively, most of which were exercised on a cashless basis. At September 30, 2022, the Company had approximately ~~34%~~3.2 million warrants outstanding, 1.8 million of Series A and 1.4 million of Series B, which represents approximately 58.7% of the CO2 ~~utilized~~aggregate Series A and B warrants issued in ~~our oil and gas operations was industrial-sourced CO~~2~~, and we anticipate this percentage could increase in the future as supportive U.S. government policy and public pressure on industrial CO~~2 ~~emitters will provide strong incentives for these entities to capture their CO~~2 ~~emissions.~~September 2020.

~~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 CO~~2 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~~oil and gas 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.

CCUS initiatives. As of September 30, ~~2021,~~2022, we had no$15.0 million of outstanding borrowings onand $11.4 million of outstanding letters of credit under our ~~$575~~$750 million senior secured bank credit facility, leaving us with ~~$563.2~~$723.6 million of borrowing base availability ~~after consideration of $11.8~~and approximately $724.1 million of ~~outstanding letters~~total liquidity including our cash position at September 30, 2022. This liquidity is more than adequate to meet our currently planned operating and capital needs.

Nine Months Ended September 2022 Sources and Uses of ~~credit. Our borrowing base availability, coupled with unrestricted~~Cash Flow. During the nine months ended September 30, 2022, we generated cash flows from operations of $396.4 million, while utilizing net cash of ~~$1.8~~$288.0 million ~~provides us total liquidity~~in investing activities, primarily related to oil and gas and CCUS, and utilizing net cash of $110.6 million in financing activities, $100.0 million of which was utilized for the repurchase of Denbury common stock under the Company’s stock repurchase program.

2022 Capital Expenditure Plans. Based on our most recent budget, our full-year 2022 estimate for oil and gas development capital spending, excluding capitalized acquisitions and capitalized interest, is approximately $360 million. In addition to our budgeted oil and natural gas capital investments, we have budgeted approximately $50 million in connection with our strategic CCUS priorities, with expenditures primarily focused on securing CO2 sequestration sites and drilling one or more stratigraphic test wells in those sequestration sites. Due to supply chain disruptions, the timing of certain of the Company’s oil and gas development activities has been delayed from when originally projected to later in the year.

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

~~$565.0 million as of September 30, 2021, which is more than adequate to meet our currently planned operating and capital needs.~~

~~2021 Capital Expenditures.~~ Capital expenditures during the first nine months of 2021 were $173.8 million. We continue to anticipate that our full-year 2021 development capital spending, excluding capitalized interest and acquisitions, will be in a range of $250 million to $270 million. Approximately 45% of our 2021 capital expenditures through September 30, 2021 have been focused on the previously announced development of the EOR CO2 ~~flood at Cedar Creek Anticline (“CCA”). The project is currently underway, with completion of the 105-mile extension of the Greencore CO~~2 ~~pipeline from Bell Creek to CCA expected before the end of November 2021, first CO~~2 ~~injection planned during the first quarter of 2022, and first tertiary production expected in the second half of 2023.~~

Capital Expenditure Summary. For purposes of tracking and comparing our capital budget to capital expenditure activity, we base those comparisons on when the capital expenditures are incurred, which is generally different than what is reported in our cash flow statements which reflects when cash is actually paid. The information included in the following table reflects incurred capital expenditures for the nine months ended September 30, ~~2021~~2022 and ~~2020:~~2021:

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


	Nine Months Ended
	September 30,
In thousands	2022		2021
Capital expenditure summary(1)
CCA EOR field expenditures(2)	$	73,825	$	19,091
CCA CO2 pipelines	1,728		59,545
CCA tertiary development	75,553		78,636
Non-CCA tertiary and non-tertiary fields	138,910		71,507
CO2 sources, other CO2 pipelines and other	6,124		1,039

Capitalized internal costs(3)	22,640		22,639
Oil and gas development capital expenditures	243,227		173,821
CCUS storage sites and related capital expenditures	32,100		—
Oil and gas and CCUS development capital expenditures	275,327		173,821
Capitalized interest	3,177		3,500
Acquisitions of oil and natural gas properties(4)	874		10,927

Investment in Clean Hydrogen Works	10,000		—
Total capital expenditures	$	289,378	$	188,248

(1)Capital expenditures in this summary are presented on an as-incurred basis (including accruals), and are ~~$45.2~~$7.2 million higher than the capital expenditures in the Unaudited Condensed Consolidated Statements of Cash Flows which are presented on a cash basis.

(2)Includes pre-production CO2 costs associated with the CCA EOR development project totaling $17.9 million during the first nine months of 2022.

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

~~(3)~~(4)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~~have increased our costs during late 2021 and thus far in ~~2022~~2022. Based on cost increases and ~~future periods. Most of~~shortages experienced across the ~~cost inflation pressures we have experienced during 2021 have been tied to rising~~industry and higher fuel and power costs thus far in ~~our operations; however, there is the potential for more significant~~2022, we anticipate additional increases in the cost of, and demand for, goods and services and wages in our operations during the remainder of 2022 which could negatively impact our results of operations and cash flows in future periods. See Results of Operations - Production Expenses below for further discussion.

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~~Denbury Inc.~~

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

Senior Secured Bank Credit Agreement. In September 2020, we entered into a $575 million bank credit agreement for a senior secured revolving credit facility with JPMorgan Chase Bank, N.A., as administrative agent, and other lenders party thereto (the “Bank Credit Agreement”). ~~The~~Availability under the Bank Credit Agreement is subject to 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~~which is redetermined semiannually on or around May 1 ~~2022.~~and November 1 of each year. 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.

On May 4, 2022, we entered into a Second Amendment to the Bank Credit Agreement, which among other things:

•Increased the borrowing base and lender commitments from $575 million to $750 million;

•Extended the maturity date from January 30, 2024 to May 4, 2027;

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Denbury Inc.

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

•Modified the interest provisions on loans under the Bank Credit Agreement to (1) reduce the applicable margin for alternate base rate loans from 2% to 3% per annum to 1.5% to 2.5% per annum and (2) replace provisions referencing LIBOR loans with Secured Overnight Financing Rate loans, with an applicable margin of 2.5% to 3.5% per annum; and

•Permitted us to pay dividends on our common stock and make other unlimited restricted payments and investments so long as (1) no event of default or borrowing base deficiency exists; (2) our total leverage ratio is 1.5 to 1 or lower; and (3) availability under the Bank Credit Agreement is at least 20% of the borrowing base.

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 certain exceptions to such limitations, as specified in the Bank Credit Agreement. Our Bank Credit Agreement required certain minimum commodity hedge levels in connection with our emergence from bankruptcy; however, these conditions were met as of December 31, 2020, and we currently have no ongoing hedging requirements under the Bank Credit Agreement.

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,~~2022, our ratio of consolidated total debt to consolidated EBITDAX was ~~0.05~~0.03 to 1.0 (with a maximum permitted ratio of 3.5 to 1.0) and our current ratio was ~~2.60~~2.68 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,~~2, 2022, 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 and amendments thereto, each of which is filed as an exhibit to our ~~Form 8-K Report~~periodic reports filed with the ~~SEC~~Securities and Exchange Commission (“SEC”). The Second Amendment to the Credit Agreement, which is attached as Exhibit 10(d) to the Form 10-Q filed on ~~September 18, 2020.~~May 6, 2022, contains the full text of the current version of the Bank Credit Agreement inclusive of all changes made by virtue of both the First and Second Amendments thereto.

Commitments, Obligations and ~~Obligations.~~Off-Balance Sheet Arrangements. 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 oil and natural gas or CCUS 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.

Our commitments, obligations and off-balance sheet arrangements as of December 31, 2021, are detailed 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.

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

RESULTS OF OPERATIONS

Certain of our ~~financial~~operating results and statistics for ~~our Successor~~the comparative three and ~~Predecessor periods~~nine months ended September 30, 2022 and 2021 are ~~presented~~included in the following ~~tables:~~table:

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


									Three Months Ended				Nine Months Ended
		Successor				Predecessor			September 30,				September 30
In thousands, except per-share and unit data	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		In thousands, except per-share and unit data	2022		2021		2022		2021
Operating results
Financial results								Financial results
Net income (loss)(1)	Net income (loss)(1)	$	(64,629)	$	2,758	$	(1,432,578)	Net income (loss)(1)	$	250,423	$	82,708	$	405,045	$	(64,629)
Net income (loss) per common share – basic(1)	Net income (loss) per common share – basic(1)	(1.27)		0.06		(2.89)		Net income (loss) per common share – basic(1)	4.89		1.62		7.86		(1.27)
Net income (loss) per common share – diluted(1)	Net income (loss) per common share – diluted(1)	(1.27)		0.06		(2.89)		Net income (loss) per common share – diluted(1)	4.66		1.51		7.43		(1.27)
Net cash provided by operating activities	Net cash provided by operating activities	247,557		32,910		113,408		Net cash provided by operating activities	156,301		104,019		396,409		247,557

Average daily sales volumes								Average daily sales volumes
Bbls/d								Bbls/d	45,639		48,145		45,404		47,276
Mcf/d								Mcf/d	8,815		9,222		8,770		8,739
BOE/d(2)								BOE/d(2)	47,109		49,682		46,866		48,732
Oil and natural gas sales								Oil and natural gas sales
Oil sales								Oil sales	$	389,543	$	305,093	$	1,217,377	$	818,714
Natural gas sales								Natural gas sales	5,680		3,361		14,727		7,893
Total oil and natural gas sales								Total oil and natural gas sales	$	395,223	$	308,454	$	1,232,104	$	826,607
Commodity derivative contracts(3)								Commodity derivative contracts(3)
Payment on settlements of commodity derivatives								Payment on settlements of commodity derivatives	$	(55,780)	$	(77,670)	$	(276,796)	$	(179,466)
Noncash fair value gains (losses) on commodity derivatives								Noncash fair value gains (losses) on commodity derivatives	165,028		35,925		136,471		(150,686)
Commodity derivatives income (expense)								Commodity derivatives income (expense)	$	109,248	$	(41,745)	$	(140,325)	$	(330,152)
Unit prices – excluding impact of derivative settlements								Unit prices – excluding impact of derivative settlements
Oil price per Bbl								Oil price per Bbl	$	92.77	$	68.88	$	98.21	$	63.44
Natural gas price per Mcf								Natural gas price per Mcf	7.00		3.96		6.15		3.31
Unit prices – including impact of derivative settlements(3)								Unit prices – including impact of derivative settlements(3)
Oil price per Bbl								Oil price per Bbl	$	79.49	$	51.35	$	75.88	$	49.53
Natural gas price per Mcf								Natural gas price per Mcf	7.00		3.96		6.15		3.31
Oil and natural gas operating expenses								Oil and natural gas operating expenses
Lease operating expenses								Lease operating expenses	$	134,464	$	116,536	$	376,643	$	308,731
Transportation and marketing expenses								Transportation and marketing expenses	5,191		5,985		14,638		22,304
Production and ad valorem taxes								Production and ad valorem taxes	33,080		23,464		99,093		63,195
Oil and natural gas operating revenues and expenses per BOE								Oil and natural gas operating revenues and expenses per BOE
Oil and natural gas revenues								Oil and natural gas revenues	$	91.19	$	67.48	$	96.30	$	62.13
Lease operating expenses								Lease operating expenses	31.03		25.50		29.44		23.21
Transportation and marketing expenses								Transportation and marketing expenses	1.20		1.31		1.14		1.68
Production and ad valorem taxes								Production and ad valorem taxes	7.63		5.13		7.75		4.75
CO2 – revenues and expenses								CO2 – revenues and expenses
CO2 sales and transportation fees								CO2 sales and transportation fees	$	18,586	$	12,237	$	44,618	$	31,599
CO2 operating and discovery expenses								CO2 operating and discovery expenses	(2,066)		(1,963)		(6,564)		(4,487)
CO2 revenue and expenses, net								CO2 revenue and expenses, net	$	16,520	$	10,274	$	38,054	$	27,112

(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.

2021.

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~~Denbury Inc.~~

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

~~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)~~(2)Barrel of oil equivalent using the ratio of one barrel of oil to six Mcf of natural gas (“BOE”).

~~(2)~~(3)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~~2021 and for the first three quarters of ~~2021~~2022 is shown below:


		Average Daily Sales Volumes (BOE/d)								Average Daily Sales Volumes (BOE/d)
		First Quarter	Second Quarter	Third Quarter	First Quarter	Second Quarter	Third Quarter	Fourth Quarter		Third Quarter	Second Quarter	First Quarter	Fourth Quarter	Third Quarter	Second Quarter	First Quarter
Operating Area	Operating Area	2021	2021	2021	2020	2020	2020	2020	Operating Area	2022	2022	2022	2021	2021	2021	2021
Tertiary oil sales
Tertiary oil sales volumes									Tertiary oil sales volumes
Gulf Coast region	Gulf Coast region								Gulf Coast region
Delhi	Delhi	2,925	2,931	2,859	3,813	3,529	3,208	3,132	Delhi	2,557	2,478	2,675	2,731	2,859	2,931	2,925
Hastings	Hastings	4,226	4,487	4,343	5,232	4,722	4,473	4,598	Hastings	4,211	4,304	4,430	4,212	4,343	4,487	4,226
Heidelberg	Heidelberg	4,054	3,942	3,895	4,371	4,366	4,256	4,198	Heidelberg	3,571	3,528	3,653	3,797	3,895	3,942	4,054
Oyster Bayou	Oyster Bayou	3,554	3,791	3,942	3,999	3,871	3,526	3,880	Oyster Bayou	3,490	3,423	3,745	4,039	3,942	3,791	3,554
Tinsley	Tinsley	3,424	3,455	3,390	4,355	3,788	4,042	3,654	Tinsley	3,133	3,050	3,015	3,353	3,390	3,455	3,424
Other(1)	Other(1)	6,098	6,074	5,907	7,161	5,944	6,271	6,332	Other(1)	5,541	5,422	5,498	5,801	5,907	6,074	6,098
Total Gulf Coast region	Total Gulf Coast region	24,281	24,680	24,336	28,931	26,220	25,776	25,794	Total Gulf Coast region	22,503	22,205	23,016	23,933	24,336	24,680	24,281
Rocky Mountain region	Rocky Mountain region								Rocky Mountain region
Bell Creek	Bell Creek	4,614	4,394	4,330	5,731	5,715	5,551	5,079	Bell Creek	3,975	4,122	4,474	4,331	4,330	4,394	4,614
Wind River Basin									Wind River Basin	3,121	2,703	2,517	2,452	2,581	2,326	691
Other(2)	Other(2)	2,573	4,378	4,703	2,199	1,393	2,167	2,007	Other(2)	2,759	2,361	2,229	2,099	2,122	2,052	1,882
Total Rocky Mountain region	Total Rocky Mountain region	7,187	8,772	9,033	7,930	7,108	7,718	7,086	Total Rocky Mountain region	9,855	9,186	9,220	8,882	9,033	8,772	7,187
Total tertiary oil sales		31,468	33,452	33,369	36,861	33,328	33,494	32,880
Non-tertiary oil and gas sales
Total tertiary oil sales volumes									Total tertiary oil sales volumes	32,358	31,391	32,236	32,815	33,369	33,452	31,468
Non-tertiary oil and gas sales volumes									Non-tertiary oil and gas sales volumes
Gulf Coast region	Gulf Coast region								Gulf Coast region
Total Gulf Coast region	Total Gulf Coast region	3,621	3,415	3,763	4,173	3,805	3,728	3,523	Total Gulf Coast region	3,727	3,566	3,630	3,929	3,763	3,415	3,621
Rocky Mountain region	Rocky Mountain region								Rocky Mountain region
Cedar Creek Anticline	Cedar Creek Anticline	11,150	10,918	11,182	13,046	11,988	11,485	11,433	Cedar Creek Anticline	9,593	10,224	9,721	10,784	11,182	10,918	11,150
Other(2)		1,118	1,348	1,368	1,105	1,069	979	969
Other(3)									Other(3)	1,431	1,380	1,338	1,354	1,368	1,348	1,118
Total Rocky Mountain region	Total Rocky Mountain region	12,268	12,266	12,550	14,151	13,057	12,464	12,402	Total Rocky Mountain region	11,024	11,604	11,059	12,138	12,550	12,266	12,268
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
Total non-tertiary sales volumes									Total non-tertiary sales volumes	14,751	15,170	14,689	16,067	16,313	15,681	15,889

Total sales volumes									Total sales volumes	47,109	46,561	46,925	48,882	49,682	49,133	47,357

(1)Includes ~~our mature properties (Brookhaven,~~Brookhaven, Cranfield, Eucutta, Little Creek, Mallalieu, Martinville, McComb, ~~and~~ Soso, ~~fields)~~ and West Yellow Creek ~~Field.~~fields.

(2)Includes tertiary sales volumes related to our working interest positions in the ~~Big Sand Draw~~Salt Creek and ~~Beaver Creek fields acquired on March 3, 2021.~~Grieve fields.

(3)Includes non-tertiary sales ~~related to the March 2020 sale of 50% of our working interests in Webster, Thompson, Manvel,~~volumes from Wind River Basin, as well as Hartzog Draw and ~~East Hastings fields (the “Gulf Coast Working Interests Sale”).~~Bell Creek fields.

Total sales volumes during the third quarter of ~~2021~~2022 averaged ~~49,682~~47,109 BOE/d, including ~~33,369~~32,358 Bbls/d from tertiary properties and ~~16,313~~14,751 BOE/d from non-tertiary properties. This sales volume ~~represents~~was relatively flat with second quarter of 2022 sales volumes as sales volume increases at Wind River Basin (437 BOE/d increase) and Grieve fields (410 BOE/d increase) in the Rocky Mountain region were offset by lower production across various fields, most notably at CCA due in part to downtime associated with installation of the new CO2 flood. On a ~~slight increase of 549~~year-over-year basis, sales volumes decreased 2,573 BOE/d ~~(1%~~(5%) compared to sales levels in the ~~second~~third 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~~low levels of capital investment and development spending in recent years (excluding the new EOR development at CCA). We currently expect sales volumes ~~at our Wind River Basin properties acquired~~to increase modestly during the fourth quarter of 2022, as a result of incremental production increases from development projects completed in ~~March 2021 and sales of non-tertiary production at Conroe Field in our Gulf Coast region.~~2022.

Our sales volumes during the three and nine months ended September 30, 2022 were 97% oil, consistent with our sales during the comparable prior-year periods.

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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~~2022 increased ~~76%~~28% and ~~61%~~49%, respectively, compared to these revenues for the same periods in ~~2020.~~2021. 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					Three Months Ended				Nine Months Ended
		September 30,				September 30,					September 30,				September 30,
		2021 vs. 2020				2021 vs. 2020					2022 vs. 2021				2022 vs. 2021
In thousands	In thousands	Increase (Decrease) in Revenues		Percentage Increase in Revenues		Increase (Decrease) in Revenues		Percentage Increase (Decrease) in Revenues		In thousands	Increase (Decrease) in Revenues		Percentage Increase (Decrease) in Revenues		Increase (Decrease) in Revenues		Percentage Increase (Decrease) in Revenues
Change in oil and natural gas revenues due to:	Change in oil and natural gas revenues due to:									Change in oil and natural gas revenues due to:
Decrease in sales volumes	Decrease in sales volumes	$	(14)	0	%	$	(33,517)	(6)	%	Decrease in sales volumes	$	(15,975)	(5)	%	$	(31,664)	(4)	%
Increase in realized commodity prices	Increase in realized commodity prices	133,057		76	%	345,702		67	%	Increase in realized commodity prices	102,744		33	%	437,161		53	%
Total increase in oil and natural gas revenues	Total increase in oil and natural gas revenues	$	133,043	76	%	$	312,185	61	%	Total increase in oil and natural gas revenues	$	86,769	28	%	$	405,497	49	%

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~~2022 and ~~2020:~~2021:


		Three Months Ended												Nine Months Ended					Three Months Ended												Nine Months Ended
		March 31,				June 30,				September 30,				September 30,					March 31,				June 30,				September 30,				September 30,
		2021		2020		2021		2020		2021		2020		2021		2020			2022		2021		2022		2021		2022		2021		2022		2021
Average net realized prices	Average net realized prices																	Average net realized prices
Oil price per Bbl	Oil price per Bbl	$	56.28	$	45.96	$	64.70	$	24.39	$	68.88	$	39.23	$	63.44	$	36.88	Oil price per Bbl	$	93.17	$	56.28	$	108.81	$	64.70	$	92.77	$	68.88	$	98.21	$	63.44
Natural gas price per Mcf	Natural gas price per Mcf	3.29		1.46		2.64		1.21		3.96		1.29		3.31		1.32		Natural gas price per Mcf	4.66		3.29		6.76		2.64		7.00		3.96		6.15		3.31
Price per BOE	Price per BOE	55.24		45.09		63.23		23.95		67.48		38.37		62.13		36.15		Price per BOE	91.14		55.24		106.67		63.23		91.19		67.48		96.30		62.13
Average NYMEX differentials	Average NYMEX differentials																	Average NYMEX differentials
Gulf Coast region	Gulf Coast region																	Gulf Coast region
Oil per Bbl	Oil per Bbl	$	(1.37)	$	1.18	$	(1.13)	$	(3.59)	$	(1.77)	$	(1.38)	$	(1.40)	$	(0.86)	Oil per Bbl	$	(1.37)	$	(1.37)	$	0.16	$	(1.13)	$	0.66	$	(1.77)	$	(0.26)	$	(1.40)
Natural gas per Mcf	Natural gas per Mcf	0.68		(0.06)		(0.11)		(0.09)		0.16		(0.06)		0.26		(0.07)		Natural gas per Mcf	0.16		0.68		0.02		(0.11)		0.37		0.16		0.10		0.26
Rocky Mountain region	Rocky Mountain region																	Rocky Mountain region
Oil per Bbl	Oil per Bbl	$	(1.80)	$	(2.78)	$	(1.59)	$	(4.68)	$	(1.72)	$	(2.03)	$	(1.49)	$	(2.89)	Oil per Bbl	$	(1.38)	$	(1.80)	$	0.01	$	(1.59)	$	1.02	$	(1.72)	$	(0.08)	$	(1.49)
Natural gas per Mcf	Natural gas per Mcf	0.49		(0.91)		(0.47)		(1.04)		(0.65)		(1.74)		(0.22)		(1.25)		Natural gas per Mcf	0.08		0.49		(1.12)		(0.47)		(1.59)		(0.65)		(0.86)		(0.22)
Total Company	Total Company																	Total Company
Oil per Bbl	Oil per Bbl	$	(1.54)	$	(0.38)	$	(1.32)	$	(4.03)	$	(1.75)	$	(1.64)	$	(1.44)	$	(1.67)	Oil per Bbl	$	(1.37)	$	(1.54)	$	0.09	$	(1.32)	$	0.82	$	(1.75)	$	(0.18)	$	(1.44)
Natural gas per Mcf	Natural gas per Mcf	0.58		(0.41)		(0.33)		(0.54)		(0.33)		(0.83)		(0.02)		(0.60)		Natural gas per Mcf	0.11		0.58		(0.71)		(0.33)		(0.90)		(0.33)		(0.51)		(0.02)

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 positive $0.66 per Bbl during the third quarter of 2022, an improvement compared to a negative $1.77 per Bbl during the third quarter of 2021 ~~compared~~and a positive $0.16 per Bbl during the second quarter of 2022. During the third quarter of 2022, the Company benefited from improved pricing for its Gulf Coast grades relative to NYMEX WTI prices.

•Rocky Mountain Region. Our average NYMEX oil differentials in the Rocky Mountain region was a ~~negative $1.38~~positive $1.02 per Bbl during the third quarter of ~~2020 and a negative $1.13~~2022, compared to $1.72 per Bbl ~~during the second quarter of 2021.~~below 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~~2021

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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~~essentially flat with NYMEX WTI during the second quarter of ~~2021.~~

•~~Rocky Mountain Region. NYMEX oil~~2022. Our 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 andimproved as demand ~~trends and can fluctuate significantly on~~for this crude remained robust while also benefiting from being sold under a ~~month-to-month basis due to weather, refinery or transportation issues, and Canadian and U.S. crude oil~~Cushing related price ~~index volatility.~~index.

CO2 Revenues and Expenses

We sell a portion of the CO2 ~~produced from Jackson Dome~~we own 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~~$18.6 million and ~~$31.6~~$44.6 million during the three and nine months ended September 30, ~~2021,~~2022, respectively, compared to ~~$7.5~~$12.2 million and ~~$22.0~~$31.6 million during ~~the combined Predecessor and Successor periods included within~~ the three and nine-month periods ended September 30, ~~2020,~~2021, respectively. The ~~increases from the prior-year periods were primarily due to an~~ increase in CO2 sales ~~volumes~~and transportation fees from the prior-year periods is primarily due to ~~our industrial CO~~2 ~~customers.~~revenues received pursuant to a short-term contractual agreement that we expect to end during the fourth quarter of 2022.

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~~table summarizes the impact our crude oil derivative contracts had on our operating results for the three and nine months ended September 30, ~~2021~~2022 and ~~2020:~~2021:

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)


									Three Months Ended				Nine Months Ended
		Successor				Predecessor			September 30,				September 30,
In thousands	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		In thousands	2022		2021		2022		2021
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
Payment on settlements of commodity derivatives								Payment on settlements of commodity derivatives	$	(55,780)	$	(77,670)	$	(276,796)	$	(179,466)
Noncash fair value gains (losses) on commodity derivatives								Noncash fair value gains (losses) on commodity derivatives	165,028		35,925		136,471		(150,686)
Total income (expense)	Total income (expense)	$	(330,152)	$	4,035	$	102,032	Total income (expense)	$	109,248	$	(41,745)	$	(140,325)	$	(330,152)

Changes in our commodity derivatives expense ~~were primarily~~are 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 reporting dates, and new commodity derivative contract commitments for future periods. During the ~~third quarters~~first nine months of ~~2020 and 2021. The period-to-period changes reflect~~2022, we paid $276.8 million upon settlement of commodity derivative contracts, corresponding with the ~~very~~ large ~~fluctuations~~increase in oil prices ~~between March 2020 ($30.45 per barrel), when worldwide financial markets were first beginning to absorb~~and the ~~potential impact of a global pandemic,~~

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~~Denbury Inc.~~

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

~~and September 2021~~Company’s oil ~~prices ($71.54 per barrel) as prospects for increased economic activity and oil demand showed improvement.~~revenues during that same period.

~~Largely based on the hedging requirements that we were obligated~~In order to ~~meet under~~provide a level of price protection to a portion of our ~~bank credit facility, which required certain minimum commodity hedge levels through July 31, 2022,~~oil production, we have ~~oil commodity hedges in place for~~hedged a portion of our estimated oil production through ~~2022~~2023 using NYMEX fixed-price swaps and costless collars. ~~We do not have any additional hedging requirements under our Bank Credit Agreement.~~ See Note 6,7, Commodity Derivative Contracts, to the Unaudited Condensed Consolidated Financial Statements for additional details of our outstanding commodity derivative contracts as of September 30, ~~2021,~~2022, 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:~~2, 2022:

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.~~


		4Q 2022	1H 2023	2H 2023
WTI NYMEX	Volumes Hedged (Bbls/d)	9,500	8,500	9,000
Fixed-Price Swaps	Weighted Average Swap Price	$57.52	$75.84	$77.60
WTI NYMEX	Volumes Hedged (Bbls/d)	11,500	17,500	9,000
Collars	Weighted Average Floor / Ceiling Price	$52.39 / $67.29	$69.71 / $100.42	$68.33 / $100.69
	Total Volumes Hedged (Bbls/d)	21,000	26,000	18,000

Based on current contracts in place and NYMEX oil futures prices as of November ~~3, 2021,~~2, 2022, which averaged approximately ~~$81~~$89 per Bbl, we currently expect that we would make cash payments of approximately ~~$110~~$49 million upon settlement of our October through December ~~2021~~2022 contracts, the amount of which is primarily dependent upon fluctuations in future NYMEX oil

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Denbury Inc.

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

prices in relation to the prices of our remaining ~~2021~~2022 fixed-price swaps which have a weighted average NYMEX oil price of ~~$43.86~~$57.52 per Bbl and weighted average ceiling prices of our 2022 collars of $67.29 per Bbl. Changes in commodity prices, expiration of contracts, and new commodity ~~contracts entered into~~contract commitments 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


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
In thousands, except per-BOE data	2022		2021		2022		2021
Total lease operating expenses	$	134,464	$	116,536	$	376,643	$	308,731

Total lease operating expenses per BOE	$	31.03	$	25.50	$	29.44	$	23.21

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~~Denbury Inc.~~

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

TCompared to the prior year third quarter, 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~~third quarter of 2022 increased $17.9 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~~(15%) on an absolute-dollar basis, ~~and~~or $5.53 (22%) on a per-BOE basis. The increase on an absolute-dollar basis ~~were~~was 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 ($9.3 million), higher workover costs ($5.6 million), and higher labor costs ($2.1 million). These cost increases were partially inflation driven and partially activity driven, with higher power costs primarily impacted by higher natural gas prices and higher workover and labor costs impacted by both inflation and higher activity levels. The percentage increase on a per-BOE basis was ~~associated with~~further impacted by the lower production in the current year period as compared to the prior year period.

When comparing the first nine months of 2022 and 2021, total lease operating expenses increased from the prior year period by $67.9 million (22%) on an absolute-dollar basis, or $6.23 (27%) on a per-BOE basis. The increase on an absolute-dollar basis was primarily due to higher power and fuel costs ($17.7 million), higher workover costs ($13.2 million), higher labor costs ($5.0 million), and higher CO2 purchase costs ($3.3 million). In addition, the nine-month period comparison was further impacted by (a) a 2021 period benefit of $16.1 million resulting from compensation under the Company’s power agreements for power interruption during the severe winter storm in February 2021 which ~~created widespread~~related to power outages in Texas and disrupted the Company’s ~~operations. Under certain~~operations and (b) in the 2022 period, an additional $10.6 million of expense reflecting an entire nine months’ worth of lease operating expenses from our March 2021 acquisition of Wind River Basin properties. Absent these two factors, lease operating expenses for 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~~nine months ended September 30, ~~2021;~~ ~~$10.3 million of~~2022 increased 13% on an absolute-dollar basis from the same period in 2021. Consistent with the quarterly comparison cost increases, these ~~savings were included~~increases are related to both inflation and higher activity levels, and the percentage increase on a per-BOE basis was further impacted by lower production in ~~“Trade and other receivables, net” and $1.7 million included in “Other assets” in our Unaudited Condensed Consolidated Balance Sheets.~~ the current year period.

Compared to the second quarter of ~~2021~~2022, lease operating expenses in the most recent quarter increased ~~$6.3~~$10.1 million ~~(6%~~(8%) on an absolute-dollar basis and ~~$0.85 (3%~~$1.68 (6%) on a per-BOE basis, due primarily to higher workover, and power and fuel costs, ~~and contract labor.~~as well as absence in the third quarter of 2022 of the benefit for an insurance reimbursement totaling $6.7 million for property damage costs incurred during 2013 at Delhi Field.

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 $5.2 million and $6.0 million for the three months ended September 30, 2022 and 2021, ~~compared to $9.5~~respectively, and $14.6 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, 2022 and 2021, ~~compared to $28.5 million for the combined Predecessor and Successor periods included within the nine months ended September 30, 2020.~~respectively. The ~~decrease~~decreases during the most recent comparative ~~three-month~~three and nine-month periods ~~was~~were primarily due to ~~changes to~~ a ~~portion~~change in the sales contracts of certain of our production, which reduced 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.expense.

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

Taxes Other Than Income

Taxes other than income includes production, ad valorem and franchise taxes. Taxes other than income increased $9.6 million (40%) and $36.0 million (55%) during the three and nine months ended September 30, 2022, respectively, compared to the same prior-year periods, due primarily to an increase in production taxes resulting from higher oil and natural gas revenues.

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			Three Months Ended				Nine Months Ended
									September 30,				September 30,
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
In thousands, except per-BOE data and employees								In thousands, except per-BOE data and employees	2022		2021		2022		2021
Cash G&A costs	Cash G&A costs	$	40,033	$	1,735	$	44,411	Cash G&A costs	$	16,655	$	12,832	$	47,507	$	40,033
Stock-based compensation	Stock-based compensation	22,788		—		4,111		Stock-based compensation	4,416		2,556		11,491		22,788
G&A expense	G&A expense	$	62,821	$	1,735	$	48,522	G&A expense	$	21,071	$	15,388	$	58,998	$	62,821

G&A per BOE	G&A per BOE							G&A per BOE
Cash G&A costs	Cash G&A costs	$	3.01	$	2.90	$	3.26	Cash G&A costs	$	3.84	$	2.81	$	3.71	$	3.01
Stock-based compensation	Stock-based compensation	1.71		—		0.30		Stock-based compensation	1.02		0.56		0.90		1.71
G&A expenses	G&A expenses	$	4.72	$	2.90	$	3.56	G&A expenses	$	4.86	$	3.37	$	4.61	$	4.72

Employees as of period end								Employees as of period end	756		698

Our G&A expense on an absolute-dollar basis was ~~$15.4~~$21.1 million during the three months ended September 30, ~~2021, a decrease~~2022, an increase of ~~$1.4~~$5.7 million ~~(8%)~~ from the ~~combined Predecessor~~same prior-year period, with the increase primarily due to higher employee-related costs (including $1.9 million for stock-based compensation) and ~~Successor periods included within~~higher professional service fees. During the ~~three~~nine months ended September 30, ~~2020. The decrease in~~2022, our G&A expense ~~during the three months ended September 30, 2021 compared to 2020, was~~decreased $3.8 million, primarily due to ~~higher operator labor and overhead recovery charges~~a decrease 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~~stock-based compensation as 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 toincluded $15.3 million of stock-based compensation expense in the first quarter of 2021 resulting from the ~~full~~accelerated performance achievement and vesting of performance-based equity awards ~~with vesting parameters tied to the Company’s common stock trading prices,~~granted in late 2020, partially offset by higher ~~operator labor~~employee-related costs and ~~overhead recovery charges. The shares underlying these awards are not currently outstanding as actual delivery of~~professional service fees.

Interest and Financing Expenses


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
In thousands, except per-BOE data and interest rates	2022			2021			2022			2021
Cash interest(1)	$	1,422		$	1,233		$	3,804		$	4,902

Noncash interest expense	531			685			2,465			2,055

Less: capitalized interest	(1,044)			(1,249)			(3,177)			(3,500)
Interest expense, net	$	909		$	669		$	3,092		$	3,457
Interest expense, net per BOE	$	0.21		$	0.15		$	0.24		$	0.26
Average debt principal outstanding	$	30,152		$	55,667		$	31,158		$	99,243
Average cash interest rate(2)	6.9		%	8.9		%	6.1		%	6.6		%

(1)Includes commitment fees paid on the ~~shares is not scheduled to occur until after~~Company’s bank credit facility but excludes debt issue costs.

(2)Excludes commitment fees paid on the ~~end of the performance period, December 4, 2023.~~Company’s bank credit facility and debt issue costs.

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

~~Interest~~Depletion, Depreciation, and ~~Financing Expenses~~Amortization (“DD&A”)

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 %


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
In thousands, except per-BOE data	2022		2021		2022		2021
Oil and natural gas properties	$	31,188	$	29,269	$	88,940	$	89,834
CO2 properties, pipelines, plants and other property and equipment	6,492		8,422		19,485		23,688

Total DD&A	$	37,680	$	37,691	$	108,425	$	113,522

DD&A per BOE
Oil and natural gas properties	$	7.20	$	6.40	$	6.95	$	6.75
CO2 properties, pipelines, plants and other property and equipment	1.49		1.85		1.52		1.78

Total DD&A cost per BOE	$	8.69	$	8.25	$	8.47	$	8.53

Write-down of oil and natural gas properties	$	—	$	—	$	—	$	14,377

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~~DD&A expense during the three months ended September 30, ~~2021,~~2022, was essentially flat when compared to ~~$18.1 million~~the same period in 2021, primarily due to higher depletable costs for ~~the combined Predecessor~~our oil and ~~Successor periods included within the three months ended September 30, 2020. Cash interest was $4.9~~gas properties and an increase in accretion expense on our asset retirement obligations, offset by lower depreciation on other fixed assets and CO2 sources. DD&A expense decreased $5.1 million during the nine months ended September 30, ~~2021,~~2022, when 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~~same prior-year period, primarily due to a ~~decrease~~lower depletion rate as a result of an increase in our estimate of proved reserves between 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,~~based on higher commodity pricing and ~~senior subordinated notes~~lower depreciation 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.

~~Table of Contents~~

~~Denbury Inc.~~

~~Management’s Discussion~~other fixed assets and ~~Analysis of Financial Condition and Results of Operations~~

~~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)~~CO~~Represents an accelerated depreciation charge related to capitalized amounts associated with unevaluated properties that were transferred to the full cost pool.~~2 sources.

~~DD&A expense was $37.7 million during the three months ended September 30,~~First Quarter 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-

~~Table of Contents~~

~~Denbury Inc.~~

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

~~year decrease further impacted by accelerated depreciation of $37.4 million in the first quarter of 2020 related to unevaluated properties that were transferred to the full cost pool.~~

Full Cost Pool Ceiling Test ~~Write-Downs~~Write-Down

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.~~2021. 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~~properties (see Note 2, Acquisition and Divestiture) 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~~a 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~~nine months ended September 30, ~~2021.~~2022.

~~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 during the three and nine months ended September 30, 2022 totaled $2.7 million and $11.5 million, respectively. Other expense during the nine months ended September 30, 2022, includes a $3.9 million accrual for a preliminarily assessed civil penalty proposed by the Pipeline and Hazardous Materials Safety Administration of the U.S. Department of Transportation in a Notice of Probable Violation (see Item 1, Legal Proceedings – Notice of Probable Violation from Pipeline and Hazardous Materials Safety Administration (“PHMSA”) Regarding Delta-Tinsley CO2 Pipeline Failure). 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 CO~~respectively.

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

Income Taxes


		Successor						Predecessor					Three Months Ended							Nine Months Ended
											September 30,					September 30,
In thousands, except per-BOE amounts and tax rates	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				In thousands, except per-BOE amounts and tax rates	2022				2021			2022			2021
Current income tax expense (benefit)	Current income tax expense (benefit)	$	350		$	6		$	(1,451)			Current income tax expense (benefit)	$	4,012			$	350		$	6,363		$	(101)
Deferred income tax expense (benefit)	Deferred income tax expense (benefit)	53			6			(302,356)				Deferred income tax expense (benefit)	37,309				53			53,301			(34)
Total income tax expense (benefit)	Total income tax expense (benefit)	$	403		$	12		$	(303,807)			Total income tax expense (benefit)	$	41,321			$	403		$	59,664		$	(135)
Average income tax expense (benefit) per BOE	Average income tax expense (benefit) per BOE	$	0.09		$	0.02		$	(76.47)			Average income tax expense (benefit) per BOE	$	9.54			$	(0.09)		$	4.67		$	(0.01)
Effective tax rate	Effective tax rate	0.5		%	0.4		%	27.3		%		Effective tax rate	14.2		%		0.5		%	12.8		%	0.2		%
Total net deferred tax liability	Total net deferred tax liability	$	1,241		$	3,836						Total net deferred tax liability	$	54,940			$	1,241

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~~2022 and ~~2020.~~2021. Our effective tax ~~rates~~rate for the ~~Successor~~ three and nine months ended September 30, ~~2021 were~~2022 was significantly lower than our estimated statutory rate primarily due to ~~our overall deferred tax asset position and~~the release of the valuation allowance ~~offsetting those assets. As we had a pre-tax loss for~~that was recorded in the three and nine months ended September 30, ~~2021,~~2022. Our annualized effective tax rate for the ~~income tax benefit resulting from these losses~~year ended December 31, 2022 is ~~fully offset by~~currently estimated to be approximately 15%, as it includes the ~~change in~~impact of the release of an additional $11.0 million of valuation ~~allowance, resulting in essentially no tax provision.~~allowances during the fourth quarter of 2022. This rate could move higher or lower based on our ultimate level of income.

We assess the valuation allowance recorded on our deferred tax assets, which was $125.5 million at December 31, 2021, on a quarterly basis. This valuation allowance on our federal and certain state deferred tax assets was recorded in September ~~30, 2021,~~2020 after the application of fresh start accounting, as (1) the tax basis of our assets, primarily our oil and gas properties, iswas in excess of ~~their~~the carrying value, as adjusted for fresh start accounting ~~on September 18, 2020; therefore,~~and (2) our historical pre-tax income reflected a three-year cumulative loss primarily due to ceiling test write-downs and reorganization items that were recorded in 2020. While we ~~are currently~~continued to be in a ~~net deferred tax asset position. Based on all available~~cumulative three-year-loss position during the first quarter of 2022, we initially determined, at that time, that there was sufficient positive evidence, ~~both positive~~primarily related to a substantial increase in worldwide oil prices, to conclude that $64.9 million of our federal and ~~negative, we continue to record a valuation allowance on our underlying deferred tax assets as of September 30, 2021, as we believe our~~certain state deferred tax assets are more likely than not ~~more-likely-than-not~~ to be realized. Accordingly, we reversed $5.9 million, $18.8 million, and $29.2 million of this valuation allowance during the three months ended March 31, June 30, and September 30, 2022, respectively, and currently expect to reverse the remaining $11.0 million in December 31, 2022, resulting in a reduction to our annualized effective tax rate. We ~~intend~~will continue to maintain ~~the~~a valuation ~~allowances on our deferred tax assets until there is sufficient evidence to support the reversal~~allowance 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~~$60.6 million 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.~~benefits that we currently do not expect to realize before their expiration.

As of September 30, ~~2021,~~2022, we had $0.6 million of alternative minimum tax credits, which under the Tax Cut and Jobs Act will be ~~refunded in 2021~~refundable by 2022 and are recorded as a receivable on the balance sheet. Our significant state net operating loss carryforwards expire in various years, starting in 2025.

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Denbury Inc.

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

Per-BOE Data

The following table summarizes our cash flow and results of operations on a per-BOE basis for the comparative periods. Each of the significant individual components is discussed above.


		Three Months Ended				Nine Months Ended					Three Months Ended				Nine Months Ended
		September 30,				September 30,					September 30,				September 30,
Per-BOE data	Per-BOE data	2021		2020		2021		2020		Per-BOE data	2022		2021		2022		2021
Oil and natural gas revenues	Oil and natural gas revenues	$	67.48	$	38.37	$	62.13	$	36.15	Oil and natural gas revenues	$	91.19	$	67.48	$	96.30	$	62.13
Receipt (payment) on settlements of commodity derivatives		(16.99)		3.90		(13.49)		6.19
Payment on settlements of commodity derivatives										Payment on settlements of commodity derivatives	(12.87)		(16.99)		(21.63)		(13.49)
Lease operating expenses	Lease operating expenses	(25.50)		(15.57)		(23.21)		(18.39)		Lease operating expenses	(31.03)		(25.50)		(29.44)		(23.21)
Production and ad valorem taxes	Production and ad valorem taxes	(5.13)		(3.00)		(4.75)		(2.84)		Production and ad valorem taxes	(7.63)		(5.13)		(7.75)		(4.75)
Transportation and marketing expenses	Transportation and marketing expenses	(1.31)		(2.08)		(1.68)		(2.00)		Transportation and marketing expenses	(1.20)		(1.31)		(1.14)		(1.68)
Production netback	Production netback	18.55		21.62		19.00		19.11		Production netback	38.46		18.55		36.34		19.00
CO2 sales, net of operating and discovery expenses	CO2 sales, net of operating and discovery expenses	2.25		1.38		2.04		1.35		CO2 sales, net of operating and discovery expenses	3.81		2.25		2.98		2.04
General and administrative expenses(1)	General and administrative expenses(1)	(3.37)		(3.66)		(4.72)		(3.53)		General and administrative expenses(1)	(4.86)		(3.37)		(4.61)		(4.72)
Interest expense, net	Interest expense, net	(0.15)		(1.76)		(0.26)		(3.42)		Interest expense, net	(0.21)		(0.15)		(0.24)		(0.26)
Reorganization items settled in cash		—		(8.55)		—		(2.75)
Stock compensation and other	Stock compensation and other	(0.31)		(2.72)		1.18		(0.74)		Stock compensation and other	(1.25)		(0.31)		(0.74)		1.18
Changes in assets and liabilities relating to operations	Changes in assets and liabilities relating to operations	5.79		9.77		1.37		0.26		Changes in assets and liabilities relating to operations	0.11		5.79		(2.75)		1.37
Cash flows from operations	Cash flows from operations	22.76		16.08		18.61		10.28		Cash flows from operations	36.06		22.76		30.98		18.61
DD&A – excluding accelerated depreciation charge		(8.25)		(8.71)		(8.53)		(10.87)
DD&A – accelerated depreciation charge(2)		—		(0.39)		—		(2.75)
DD&A										DD&A	(8.69)		(8.25)		(8.47)		(8.53)

Write-down of oil and natural gas properties	Write-down of oil and natural gas properties	—		(57.25)		(1.08)		(70.03)		Write-down of oil and natural gas properties	—		—		—		(1.08)
Deferred income taxes	Deferred income taxes	(0.01)		66.14		—		28.73		Deferred income taxes	(8.61)		(0.01)		(4.17)		—
Gain on extinguishment of debt		—		—		—		1.33

Noncash fair value gains (losses) on commodity derivatives	Noncash fair value gains (losses) on commodity derivatives	7.86		(4.03)		(11.33)		1.26		Noncash fair value gains (losses) on commodity derivatives	38.08		7.86		10.66		(11.33)
Noncash reorganization items, net		—		(177.40)		—		(56.98)
Other noncash items	Other noncash items	(4.26)		(10.85)		(2.53)		(1.44)		Other noncash items	0.94		(4.26)		2.66		(2.53)
Net income (loss)	Net income (loss)	$	18.10	$	(176.41)	$	(4.86)	$	(100.47)	Net income (loss)	$	57.78	$	18.10	$	31.66	$	(4.86)

(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, such as those related to our CCUS storage sites and related assets, 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 oil markets or 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~~higher worldwide oil ~~prices from their COVID-19 coronavirus caused downturn, financial forecasts,~~prices; the extent of future oil price ~~volatility,~~volatility; current or future liquidity sources or their adequacy to support our

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

anticipated future ~~activities,~~activities; statements or predictions related to the ultimate ~~nature,~~ timing and ~~economic aspects~~financial impact of our current or proposed carbon capture, use and storage ~~industry arrangements, possible future write-downs of~~arrangements; our projected production levels, oil and natural gas ~~reserves, together with assumptions based on current and projected production levels,~~revenues, oil and gas prices and oilfield costs, the impact of current supply chain and ~~inflationary pressures or expectations~~inflation on our ~~operational or other assets,~~results of operations; current or future expectations or estimations of our cash flows or the impact of changes in commodity prices on cash ~~flows, borrowing capacity, price~~flows; availability, terms and ~~availability~~financial statement and cash settlement impact of ~~advantageous~~ commodity derivative contracts or their predicted downside cash flow ~~protection or cash settlement payments required, mark-to-market commodity derivative values,~~protection; 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,~~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,~~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,~~place; the impact of changes or proposed changes in Federal or state tax or environmental laws or regulations; the outcomes of any pending litigation ~~prospective legislation, orders~~ or ~~regulations affecting the oil and gas industry or environmental regulations, competition, rates of return,~~regulatory proceedings; 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,~~outcomes, 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, especially in light of existing geopolitical and ~~consequently~~economic events, such as the war in ~~the prices received or demand for our oil produced;~~Ukraine and ensuing energy supply uncertainties in Western Europe; decisions as to production levels and/or pricing by ~~OPEC+~~OPEC or ~~production levels by~~ U.S. producers in future periods; the impact of COVID-19 or other viral outbreaks on economic activity levels and ultimately oil prices; the pace and terms of agreements reached with third parties for the capture, transportation, use and ultimate permanent sequestration of CO2; the timing and success of CCUS projects that, while undertaken by third parties, are related to our CCUS efforts; 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 currency 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,~~activities; and the ~~portions referenced above,~~risks and ~~the~~ uncertainties set forth from time to time in this or 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,September 30, 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~~2023 using NYMEX fixed-price swaps and costless collars. Depending on market conditions, we may continue to add to our existing 2022 and 2023 hedges. See also Note 6, ~~Commodity Derivative Contracts~~Income Taxes, and Note 78, 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,~~2022, the fair value of our commodity derivative contracts ~~were recorded at their fair value, which~~ was a net ~~liability~~asset of ~~$209.5~~$2.0 million, a ~~$35.9~~$165.1 million ~~decrease~~increase from the ~~$245.4~~$163.1 million net liability recorded at June 30, ~~2021,~~2022 and a ~~$150.7~~$136.5 million increase from the ~~$58.8~~$134.5 million net liability recorded at December 31, ~~2020. These~~2021. The 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~~2022, changes in oil futures prices ~~from period to period.~~between December 31, 2021 and September 30, 2022, and new commodity derivative contract commitments during 2022 for future periods.

Commodity Derivative Sensitivity Analysis

Based on NYMEX crude oil futures prices and derivative contracts in place as of September 30, ~~2021,~~2022, 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~~2022	$	~~(197,214)~~(17,475)
10% increase in prices	~~(277,213)~~(53,553)
10% decrease in prices	~~(125,537)~~28,694

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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Debt and Interest Rate Sensitivity

As of September 30, 2022, we had $15.0 million of outstanding borrowings under our Bank Credit Agreement. At this level of variable-rate debt, an increase or decrease of 10% in interest rates would not have an immaterial effect on our interest expense. Our Bank Credit Agreement does not have any triggers or covenants regarding our debt ratings with rating agencies. The following table presents the principal and fair values of our outstanding debt as of September 30, 2022:


In thousands	2022 - 2026		2027		Total		Fair Value
Variable rate debt:
Senior Secured Bank Credit Facility (weighted average interest rate of 7.75% at September 30, 2022)	$	—	$	15,000	$	15,000	$	15,000

See Note 4, Long-Term Debt, to the Unaudited Condensed Consolidated Financial Statements for details regarding our long-term debt.

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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,~~2022, 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,~~2022, there were no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings

We are involved in various lawsuits, claims and regulatory proceedings incidental to our businesses. While we currently believe that the ultimate outcome of these proceedings, individually and in the aggregate, will not have a material adverse effect on our financial position, results of operations or cash flows, litigation and regulatory proceedings are 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.

~~The information under Note 8,~~

Notice of Probable Violation from Pipeline and Hazardous Materials Safety Administration (“PHMSA”) Regarding Delta-Tinsley CO~~Commitments~~2 Pipeline Failure

On May 26, 2022, the PHMSA of the U.S. Department of Transportation issued a Notice of Probable Violation, Proposed Civil Penalty, and ~~Contingencies~~,Proposed Compliance Order (“NOPV”) relating to the ~~Unaudited Condensed Consolidated Financial Statements is incorporated herein by reference.~~February 2020 pipeline failure near Satartia, Mississippi in our CO2 pipeline running between the Tinsley and Delhi fields. The NOPV proposed a preliminarily assessed civil penalty of $3.9 million in connection with the incident, which we accrued during the second quarter of 2022. We have responded to the NOPV and are pursuing discussions with PHMSA regarding the probable violations alleged in the NOPV, the proposed civil penalty, and the nature of the compliance order contained in the NOPV.

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.~~2021. 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.~~2021.

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

~~None.~~Issuer Purchases of Equity Securities

The following table summarizes purchases of our common stock during the third quarter of 2022:


Month	Total Number of Shares Purchased(1)	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Approximate Dollar Value of Shares that May Yet Be Purchased Under Plans or Programs (2)
July 2022	1,157,842	$	61.56	1,157,807	$	150,000,000
August 2022	—	—		—	$	250,000,000
September 2022	—	—		—	$	250,000,000
Total	1,157,842			1,157,807

(1)Includes 35 shares repurchased in connection with the surrender of shares by our employees to satisfy their tax withholding requirements related to share-based awards that vested during the period.

(2)In early May 2022, our Board of Directors approved a common share repurchase program authorizing the repurchase of up to an aggregate $250 million of Denbury common shares. During June and July 2022, we purchased a total of 1,615,356 shares of Denbury common stock for $100 million under the program. In August 2022, our Board of Directors increased the common share repurchase program by $100 million, leaving $250 million authorized for future repurchases under the program. We are not obligated to repurchase any dollar amount or specified number of shares of our common stock under the program. The stock repurchase program has no pre-established ending date and may be modified, suspended, or discontinued at any time by the board of directors. See further discussion of this program under Overview – Common Share Repurchase Program.

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~~ B o ~~rrower,~~ ~~JPMorgan Chase Bank, N.A., as~~ A ~~dministrative~~ A ~~gent, and the~~ L ~~enders~~ ~~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,~~2022, 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~~3, 2022						/s/ Mark C. Allen
						Mark C. Allen Executive Vice President and Chief Financial Officer

November ~~4, 2021~~3, 2022						/s/ Nicole Jennings
						Nicole Jennings Vice President and Chief Accounting Officer

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	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


		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