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 March 31, 2023

OR

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

For the transition period from _______ to ________

Commission file number: 001-12935

DENBURY INC.

(Exact name of registrant as specified in its charter)

Delaware

20-0467835

(State or other jurisdiction of incorporation or organization)

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

5851 Legacy Circle,

Plano,

TX

75024

(Address of principal executive offices)

(Zip Code)

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

Securities registered pursuant to Section 12(b) of the Act:

Title of Each Class:			Trading Symbol:			Name of Each Exchange on Which Registered:
Common Stock $.001 Par Value			DEN			New York Stock Exchange

Not applicable

(Former name, former address and former fiscal year, if changed since last report)

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

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer

☑

Accelerated filer

☐

Non-accelerated filer

☐

Smaller reporting company

☐

Emerging growth company

☐

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 April 30, 2023, was 50,277,186.

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Denbury Inc.

Table of Contents

Page

PART I. FINANCIAL INFORMATION

Item 1.

Financial Statements

Unaudited Condensed Consolidated Balance Sheets

3

Unaudited Condensed Consolidated Statements of Operations

4

Unaudited Condensed Consolidated Statements of Cash Flows

5

Unaudited Condensed Consolidated Statements of Changes in Stockholders’ Equity

6

Notes to Unaudited Condensed Consolidated Financial Statements

7

Item 2.

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

16

Item 3.

Quantitative and Qualitative Disclosures about Market Risk

30

Item 4.

Controls and Procedures

32

PART II. OTHER INFORMATION

Item 1.

Legal Proceedings

33

Item 1A.

Risk Factors

33

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds

34

Item 3.

Defaults Upon Senior Securities

34

Item 4.

Mine Safety Disclosures

34

Item 5.

Other Information

34

Item 6.

Exhibits

35

Signatures

36

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Table of Contents

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

Denbury Inc.

Unaudited Condensed Consolidated Balance Sheets

(In thousands, except par value and share data)

						March 31, 2023						December 31, 2022
Assets
Current assets
Cash and cash equivalents						$	525					$	521
Accrued production receivable						143,484						144,277
Trade and other receivables, net						29,770						27,343
Derivative assets						23,554						15,517
Prepaids						14,803						18,572
Total current assets						212,136						206,230
Property and equipment
Oil and natural gas properties (using full cost accounting)
Proved properties						1,474,721						1,414,779
Unevaluated properties						284,584						240,435
CO2 properties						192,107						190,985
Pipelines						218,822						220,125
CCUS storage sites and related assets						85,059						64,971
Other property and equipment						111,265						107,133
Less accumulated depletion, depreciation, amortization and impairment						(340,312)						(306,743)
Net property and equipment						2,026,246						1,931,685
Operating lease right-of-use assets						16,768						18,017
Derivative assets						1,617						—
Intangible assets, net						76,849						79,128
Restricted cash for future asset retirement obligations						47,424						47,359
Other assets						51,023						45,080
Total assets						$	2,432,063					$	2,327,499
Liabilities and Stockholders’ Equity
Current liabilities
Accounts payable and accrued liabilities						$	215,291					$	248,800
Oil and gas production payable						77,507						80,368
Derivative liabilities						1,613						13,018
Current maturities of long-term debt						107						—
Operating lease liabilities						4,430						4,676
Total current liabilities						298,948						346,862
Long-term liabilities
Long-term debt, net of current portion						68,276						29,000
Asset retirement obligations						315,169						315,942
Deferred tax liabilities, net						97,031						71,120
Operating lease liabilities						14,407						15,431
Other liabilities						13,649						16,527
Total long-term liabilities						508,532						448,020
Commitments and contingencies (Note 8)
Stockholders’ equity
Preferred stock, $.001 par value, 50,000,000 shares authorized, none issued and outstanding						—						—
Common stock, $.001 par value, 250,000,000 shares authorized; 50,276,526 and 49,814,874 shares issued, respectively						50						50
Paid-in capital in excess of par						1,049,830						1,047,063
Retained earnings						574,703						485,504
Total stockholders’ equity						1,624,583						1,532,617
Total liabilities and stockholders’ equity						$	2,432,063					$	2,327,499

 

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

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Denbury Inc.

Unaudited Condensed Consolidated Statements of Operations

(In thousands, except per-share data)

						Three Months Ended March 31,
						2023						2022
Revenues and other income
Oil, natural gas, and related product sales						$	314,489					$	384,911
CO2 sales and transportation fees						10,686						13,422
Oil marketing revenues						14,548						13,276
Other income						1,295						250
Total revenues and other income						341,018						411,859
Expenses
Lease operating expenses						129,174						117,828
Transportation and marketing expenses						5,389						4,645
CO2 operating and discovery expenses						1,196						2,817
Taxes other than income						29,038						31,381
Oil marketing purchases						14,468						13,040
General and administrative expenses						22,977						18,692
Interest, net of amounts capitalized of $1,693 and $1,158, respectively						927						657
Depletion, depreciation, and amortization						42,032						35,345
Commodity derivatives expense (income)						(23,123)						192,719
Other expenses						1,491						2,112
Total expenses						223,569						419,236
Income (loss) before income taxes						117,449						(7,377)
Income tax provision (benefit)						28,250						(6,505)
Net income (loss)						$	89,199					$	(872)
Net income (loss) per common share
Basic						$	1.73					$	(0.02)
Diluted						$	1.66					$	(0.02)
Weighted average common shares outstanding
Basic						51,503						51,602
Diluted						53,763						51,602

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

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Denbury Inc.

Unaudited Condensed Consolidated Statements of Cash Flows

(In thousands)

						Three Months Ended March 31,
						2023						2022
Cash flows from operating activities
Net income (loss)						$	89,199					$	(872)
Adjustments to reconcile net income (loss) to cash flows from operating activities
Depletion, depreciation, and amortization						42,032						35,345
Deferred income taxes						25,912						(5,944)
Stock-based compensation						4,938						2,971
Commodity derivatives expense (income)						(23,123)						192,719
Receipt (payment) on settlements of commodity derivatives						2,065						(93,057)
Debt issuance costs						531						685
Other, net						(1,958)						(1,267)
Changes in assets and liabilities, net of effects from acquisitions
Accrued production receivable						793						(72,795)
Trade and other receivables						(2,425)						1,644
Other current and long-term assets						4,506						189
Accounts payable and accrued liabilities						(42,247)						11,410
Oil and natural gas production payable						(2,861)						23,348
Asset retirement obligations and other liabilities						(8,840)						(4,233)
Net cash provided by operating activities						88,522						90,143
Cash flows from investing activities
Oil and natural gas capital expenditures						(104,782)						(58,707)
CCUS storage sites and related capital expenditures						(14,645)						(14,900)
Acquisitions of oil and natural gas properties						(35)						—
Pipelines and plants capital expenditures						(623)						(15,204)
Equity investments						(7,108)						—
Other						(5,879)						(1,396)
Net cash used in investing activities						(133,072)						(90,207)
Cash flows from financing activities
Bank repayments						(319,000)						(274,000)
Bank borrowings						358,000						274,000
Other						5,619						(3,068)
Net cash provided by (used in) financing activities						44,619						(3,068)
Net increase (decrease) in cash, cash equivalents, and restricted cash						69						(3,132)
Cash, cash equivalents, and restricted cash at beginning of period						47,880						50,344
Cash, cash equivalents, and restricted cash at end of period						$	47,949					$	47,212

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

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Denbury Inc.

Unaudited Condensed Consolidated Statements of Changes in Stockholders' Equity

(Dollar amounts in thousands)

			Common Stock ($.001 Par Value)												Paid-In Capital in Excess of Par						Retained Earnings
			Shares						Amount																														Total Equity
Balance – December 31, 2022			49,814,874						$	50					$	1,047,063					$	485,504																	$	1,532,617
Issued pursuant to stock compensation plans			268,748						—						—						—																		—
Stock-based compensation			—						—						5,320						—																		5,320
Tax withholding and retirement related to stock compensation plans			(16,281)						—						(2,683)						—																		(2,683)
Issued pursuant to exercise of warrants			209,185						—						130						—																		130
Net income			—						—						—						89,199																		89,199
Balance – March 31, 2023			50,276,526						$	50					$	1,049,830					$	574,703																	$	1,624,583

			Common Stock ($.001 Par Value)												Paid-In Capital in Excess of Par						Retained Earnings (Accumulated Deficit)
			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

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., a Delaware corporation, is an independent energy company with operations focused in the Gulf Coast and Rocky Mountain 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.

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, 2022 (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 March 31, 2023, our consolidated results of operations for the three months ended March 31, 2023 and 2022, our consolidated cash flows for the three months ended March 31, 2023 and 2022, and our consolidated statements of changes in stockholders’ equity for the three months ended March 31, 2023 and 2022.

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.

Cash, Cash Equivalents, and Restricted Cash

We consider all highly liquid investments to be cash equivalents if they have maturities of three months or less at the date of purchase. The following table provides a reconciliation of cash, cash equivalents, and restricted cash as reported within the 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:

In thousands						March 31, 2023						March 31, 2022
Cash and cash equivalents						$	525					$	517
Restricted cash for future asset retirement obligations						47,424						46,695
Total cash, cash equivalents, and restricted cash shown in the Unaudited Condensed Consolidated Statements of Cash Flows						$	47,949					$	47,212

Restricted cash for future asset retirement obligations in the table above consists of escrow accounts that are legally restricted for certain of our asset retirement 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

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Denbury Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

net income (loss) per common share.  Restricted stock units and performance stock units are also excluded from basic weighted average common shares outstanding until the vesting date. Basic weighted average common shares during the three months ended March 31, 2023 includes 1,775,182 performance-based and restricted stock units which are fully vested as of March 31, 2023; however, the shares underlying these awards 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 include restricted stock, restricted stock units, performance stock units, shares to be issued under the employee stock purchase plan (“ESPP”), and series A and series B warrants.

For each of the three months ended March 31, 2023 and 2022, there were no adjustments to net income (loss) for purposes of calculating basic and diluted net income (loss) per common share.

The following table sets forth the weighted average shares used for purposes of calculating basic and diluted net income (loss) per common share for the periods indicated:

						Three Months Ended
						March 31,
In thousands						2023						2022
Weighted average common shares outstanding – basic						51,503						51,602
Effect of potentially dilutive securities
Restricted stock, restricted stock units and performance stock units						360						—
Warrants						1,899						—
Employee Stock Purchase Program						1						—
Weighted average common shares outstanding – diluted						53,763						51,602

For the three months ended March 31, 2022, the weighted average common shares outstanding used to calculate basic earnings per share and diluted earnings per share were the same, since the Company recorded a net loss for the period. Assuming the Company had recorded net income during the three months ended March 31, 2022, the weighted average diluted shares outstanding would have been 55.0 million (including the impact of 0.6 million restricted stock units and 2.8 million shares with respect to warrants).

For purposes of calculating diluted weighted average common shares, unvested restricted stock units, unvested restricted stock, unvested performance stock units, ESPP shares and unexercised warrants are included in the diluted shares computation using the treasury stock method.

The following outstanding securities were excluded from the computation of diluted net income (loss) per share for the three months ended March 31, 2023 and March 31, 2022, as their effect would have been antidilutive, as of the respective dates:

						March 31,
In thousands						2023						2022
Restricted stock, restricted stock units and performance stock units						490						1,005
Warrants						—						5,162

At March 31, 2023, the Company had approximately 2.9 million warrants outstanding that can be exercised for shares of our common stock, at an exercise price of $32.59 per share for the 1.8 million Series A warrants outstanding and at an exercise price of $35.41 per share for the 1.1 million Series B warrants outstanding. The warrants may be exercised for cash or on a cashless basis. The Series A warrants are exercisable until September 18, 2025, and the Series B warrants are exercisable until

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Denbury Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

September 18, 2023, at which times the warrants expire. Through March 31, 2023, 0.9 million series A warrants and 1.8 million series B warrants were exercised for a total of 1.5 million shares, most of which were exercised on a cashless basis.

Oil and Natural Gas Properties

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

We did not record a ceiling test write-down during the three months ended March 31, 2023 or March 31, 2022.

CCUS Storage Sites and Other Assets

CCUS Investments. During the first quarter of 2023, we made two investments in carbon capture technology companies, including a $2 million equity investment in Aqualung Carbon Capture AS and a $5 million equity investment in ION Clean Energy, Inc. In April 2023, based on the achievement of certain milestones, we invested the remaining $10 million of our original $20 million commitment in Clean Hydrogen Works, the project development company of a planned blue hydrogen/ammonia multi-block facility for which we have signed a definitive agreement for the transportation and storage of CO2 for the first two blocks of the proposed plant. These investments are included in “Other assets” in the Unaudited Condensed Consolidated Balance Sheet as of March 31, 2023.

Note 2. Revenue Recognition

We record revenue in accordance with 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 one 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. In certain situations, the Company enters into marketing arrangements for the purchase and subsequent sale of crude oil from third parties. We recognize the revenue received and the associated expense incurred on these 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 table summarizes our revenues by product type for the three months ended March 31, 2023 and 2022:

						Three Months Ended
						March 31,
In thousands						2023						2022
Oil sales						$	312,572					$	381,242
Natural gas sales						1,917						3,669
CO2 sales and transportation fees						10,686						13,422
Oil marketing revenues						14,548						13,276
Total revenues						$	339,723					$	411,609

Note 3. Long-Term Debt

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

In thousands						March 31, 2023						December 31, 2022
Senior Secured Bank Credit Agreement						$	68,000					$	29,000
Capital lease obligations						383						—
Total debt principal balance						68,383						29,000
Less: current maturities of long-term debt						(107)						—
Long-term debt and capital lease obligations						$	68,276					$	29,000

Senior Secured Bank Credit Agreement

In September 2020, we entered into a credit agreement with JPMorgan Chase Bank, N.A., as administrative agent, and other lenders party thereto (as amended, the “Bank Credit Agreement”). The Bank Credit Agreement is a senior secured revolving credit facility with a maturity date of May 4, 2027. Under the Bank Credit Agreement, letters of credit are available in an aggregate amount not to exceed $100 million, and short-term swingline loans are available in an aggregate amount not to exceed $25 million, each subject to the available commitments under the Bank Credit Agreement. 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. 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. As part of our Spring 2023 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 November 1, 2023. The undrawn portion of the aggregate lender commitments under the Bank Credit Agreement is subject to a commitment fee of 0.5% per annum. As of March 31, 2023, we had $10.1 million of outstanding letters of credit.

On January 20, 2023, we entered into a Third Amendment to the Bank Credit Agreement, which among other things, provides us the ability to make and repay certain Secured Overnight Financing Rate (“SOFR”) loan borrowings on a weekly basis.

The Bank Credit Agreement 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.

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

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Denbury Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

agreements; (4) a pledge of deposit accounts, securities accounts and our commodity accounts of Denbury Inc. and such subsidiaries (as applicable); and (5) a security interest in substantially all other collateral that may be perfected by a Uniform Commercial Code filing, subject to certain exceptions.

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

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

•A requirement to maintain a current ratio (i.e., Consolidated Current Assets to Consolidated Current Liabilities) of 1.0.

For purposes of computing the current ratio per the Bank Credit Agreement, Consolidated Current Assets exclude the current portion of derivative assets but include available borrowing capacity under the Bank Credit Agreement, and Consolidated Current Liabilities exclude the current portion of derivative liabilities as well as the current portions of long-term indebtedness outstanding. The weighted average interest rate on borrowings outstanding as of March 31, 2023 under the Bank Credit Agreement was 8%. As of March 31, 2023, we were in compliance with all debt covenants under the Bank Credit Agreement.

The above description of our Bank Credit Agreement, including certain referenced defined terms, is a summary of certain principal terms and conditions contained in the Bank Credit Agreement and amendments thereto.

Note 4. 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 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 year ended December 31, 2022, we retired 1.6 million shares of existing treasury stock, with a carrying value of $100 million, acquired 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.

Tax Withholding and Treasury Stock Retirement in Connection with Stock Compensation Plans

During the three months ended March 31, 2023, employees surrendered 16,281 shares of common stock, with a carrying value of approximately $1.4 million, to cover employee tax withholdings upon vesting of restricted stock awards, which shares were concurrently retired. For restricted stock units (“RSUs”), when the awards are settled the Company issues the net shares of common stock, reduced by the units surrendered to cover tax withholding. For the three months ended March 31, 2023, we decreased additional paid in capital by $1.3 million for tax withholdings on RSUs.

Note 5. Income Taxes

We 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

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Notes to Unaudited Condensed Consolidated Financial Statements

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.

We assess the valuation allowance recorded on our deferred tax assets on a quarterly basis, which was $59.2 million at December 31, 2022. This valuation allowance relates primarily to our Louisiana net deferred tax assets of $55.4 million, as well as our Alabama net deferred tax assets and certain Mississippi tax credits totaling $3.8 million. We have concluded that the benefits of such deferred tax assets are not more likely than not to be realized due to lack of sufficient taxable income to fully realize the benefits of such deferred tax assets.

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 2023 and 2022. Our effective tax rate for the three months ended March 31, 2023 was slightly lower than our estimated statutory rate primarily due to excess stock compensation deductions that were recorded discretely in the quarter. Our effective tax rate for the three months ended March 31, 2022 was higher than our estimated statutory rate due to the release of a portion of the valuation allowance on our deferred tax assets combined with the net loss for the period.

Note 6. Commodity Derivative Contracts

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

Historically, we have entered into various oil and natural gas derivative contracts to provide an economic hedge of our exposure to commodity price risk associated with anticipated future oil and natural gas production and to provide more certainty to our future cash flows. We do not hold or issue derivative financial instruments for trading purposes. Generally, these contracts have consisted of various combinations of price floors, collars, three-way collars, fixed-price swaps, fixed-price swaps enhanced with a sold put, and basis swaps. The production that we hedge has varied from year to year depending on our levels of debt, financial strength and expectation of future commodity prices, and occasionally requirements under our bank credit facility.

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 March 31, 2023, 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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Notes to Unaudited Condensed Consolidated Financial Statements

The following table summarizes our commodity derivative contracts as of March 31, 2023, 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)
																		Weighted Average Price
																		Swap						Floor						Ceiling
Oil Contracts:
2023 Fixed-Price Swaps
Apr – June						NYMEX						9,500						$	76.65					$	—					$	—
July – Dec						NYMEX						14,000						78.46						—						—
2023 Collars
Apr – June						NYMEX						17,500						$	—					$	69.71					$	100.42
July – Dec						NYMEX						9,000						—						68.33						100.69
2024 Fixed-Price Swaps
Jan – June						NYMEX						2,000						$	75.21					$	—					$	—
July – Dec						NYMEX						1,000						75.12						—						—

Note 7. Fair Value Measurements

The FASC Fair Value Measurement topic defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (often referred to as the “exit price”). We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. We primarily apply the income approach for recurring fair value measurements 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. Our costless 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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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:
In thousands						Quoted Prices in Active Markets (Level 1)						Significant Other Observable Inputs (Level 2)						Significant Unobservable Inputs (Level 3)						Total
March 31, 2023
Assets
Oil derivative contracts – current						$	—					$	23,554					$	—					$	23,554
Oil derivative contracts – long-term						—						1,617						—						1,617
Total Assets						$	—					$	25,171					$	—					$	25,171
Liabilities
Oil derivative contracts – current						$	—					$	(1,613)					$	—					$	(1,613)
Total Liabilities						$	—					$	(1,613)					$	—					$	(1,613)
December 31, 2022
Assets
Oil derivative contracts – current						$	—					$	15,517					$	—					$	15,517
Total Assets						$	—					$	15,517					$	—					$	15,517
Liabilities
Oil derivative contracts – current						$	—					$	(13,018)					$	—					$	(13,018)
Total Liabilities						$	—					$	(13,018)					$	—					$	(13,018)

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 March 31, 2023 and December 31, 2022 was $68.0 million and $29.0 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. 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 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.

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Notes to Unaudited Condensed Consolidated Financial Statements

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 CO2 release from a pipeline failure near Satartia, Mississippi in our CO2 pipeline running between the Tinsley and Delhi fields, and assessed a preliminary civil penalty of $3.9 million, which the Company recorded in its financial statements in the second quarter of 2022. On March 24, 2023, Denbury and PHMSA entered into a final Consent Order and Consent Agreement that settled all of the allegations in the NOPV and also reduced the assessed penalty to $2.9 million. The $1.0 million reduction was reflected in “Other Expenses” in our Unaudited Condensed Consolidated Statement of Operations in the first quarter of 2023.

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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, 2022 (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.

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, utilization, and storage (“CCUS”) industry, supported by the Company’s CO2 EOR technical and operational expertise and its extensive CO2 pipeline infrastructure. The utilization of captured industrial-sourced CO2 in EOR significantly reduces the carbon footprint of the oil that Denbury produces, making the Company’s Scope 1 and 2 CO2e emissions negative today. We have set a target, within the decade, to reach Net Zero for our Scope 1, Scope 2 and those Scope 3 emissions that result from consumers’ use of the oil and natural gas we sell (defined as Category 11 emissions by the Greenhouse Gas Protocol).

Our CO2 EOR oil recovery operations result in associated underground storage of CO2. This means that Denbury’s activities are currently supporting and advancing the national energy transition through the increasing use of industrially sourced CO2 in EOR operations, and we are building out a dedicated CCUS platform for the transportation and permanent storage of captured industrial CO2 emissions at scale. During the three months ended March 31, 2023, approximately 40% of the CO2 utilized in our operated oil and gas operations was industrial-sourced CO2, compared to 36% of the CO2 utilized during the three months ended March 31, 2022. Our industrial-sourced CO2 usage in the first quarter of 2023 equates to an annualized average CO2 usage rate of over 4.6 million metric tons.

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 many different reasons, such as global supply and demand and geopolitical events. Average NYMEX WTI oil prices were approximately $76 per Bbl during the first quarter of 2023 as compared to $95 per Bbl in the first quarter of 2022.

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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
In thousands, except per-unit data						March 31, 2023						Dec. 31, 2022						Sept. 30, 2022						June 30, 2022						March 31, 2022
Oil, natural gas, and related product sales						$	314,489					$	346,578					$	395,223					$	451,970					$	384,911
Receipt (payment) on settlements of commodity derivatives						2,065						(38,956)						(55,780)						(127,959)						(93,057)
Oil, natural gas, and related product sales and commodity derivative settlements, combined						$	316,554					$	307,622					$	339,443					$	324,011					$	291,854
Average daily sales (BOE/d)						47,655						46,641						47,109						46,561						46,925
Average net realized oil prices
Oil price per Bbl - excluding impact of derivative settlements						$	74.87					$	82.54					$	92.77					$	108.81					$	93.17
Oil price per Bbl - including impact of derivative settlements						75.36						73.13						79.49						77.63						70.43
Average NYMEX oil differential per Bbl						$	(1.28)					$	0.03					$	0.82					$	0.09					$	(1.37)

As shown in the table above, our oil and natural gas revenues have decreased since 2022 primarily due to the decrease in oil prices. We received $2.1 million during the first quarter of 2023 related to the expiration of commodity derivative contracts. During 2022, the benefit of high oil prices during the first half of the year was offset in part by the impact of higher cash payments on our commodity derivative contracts, which contracts were generally put in place in late 2020 as a requirement under our bank credit facility shortly after we exited bankruptcy.

First Quarter 2023 Financial Results and Highlights. We recognized net income of $89.2 million, or $1.66 per diluted common share, during the first quarter of 2023, compared to a net loss of $0.9 million, or $0.02 per diluted common share, during the first quarter of 2022. Drivers of the comparative operating results between the first quarter of 2023 and 2022 include the following:

•Oil and natural gas revenues decreased by $70.4 million (18%) during the first quarter of 2023 due to lower oil prices;

•Commodity derivatives expense decreased by $215.8 million consisting of a $120.7 million improvement in noncash fair value changes between periods ($21.1 million gain during the first quarter of 2023 compared to a $99.7 million loss during the first quarter of 2022), and a $95.1 million decrease in cash payments upon derivative contract settlements ($2.1 million in cash receipts during the first quarter of 2023 compared to $93.1 million in payments during the first quarter of 2022);

•Lease operating expenses increased by $11.3 million (10%), primarily due to higher workover, repair and maintenance, labor, and CO2 purchase costs; and

•Income tax expense increased by $34.8 million, from a benefit of $6.5 million during the first quarter of 2022 to $28.3 million in expense during the first quarter of 2023, primarily due to the release in 2022 of a portion of the valuation allowance on our deferred tax assets.

Cedar Creek Anticline CO2 EOR Development. We allocated 40% of our first quarter oil & gas development capital to the CCA EOR project, primarily focused on the construction of four planned CO2 recycle facilities, well conversions, and drilling the Interlake Pennel CO2 pilot. Commissioning of the initial CO2 recycle facility within the Cedar Hills South field was completed late in the first quarter of 2023 as planned, and commissioning of the second facility is expected to be completed during the second quarter of 2023, with the remaining two recycle facilities currently expected to be complete during the third

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

quarter of 2023. We currently expect initial EOR production to commence during the second quarter of 2023, with incremental EOR production reaching 2,000 Bbls/d by the end of 2023 and 7,500 Bbls/d to 12,500 Bbls/d by the end of 2024.

Carbon Capture, Utilization and Storage Activities. We invested $19.7 million of development capital into CCUS assets during the first quarter of 2023, primarily for the development of dedicated CO2 sequestration sites, including the drilling of a stratigraphic test well in our Alabama sequestration site and incremental seismic and acreage across our sequestration portfolio. We also obtained the rights to develop a new sequestration site in Wyoming, located directly below our Greencore CO2 pipeline, with estimated CO2 storage potential of up to 40 million metric tons. In April 2023, we acquired the right to develop a 30,000 acre dedicated CO2 sequestration site in Matagorda County, Texas, approximately 60 miles southwest of the terminus of the Company’s Green CO2 pipeline, with estimated CO2 storage potential of more than 115 million metric tons. On the transportation and storage side of our CCUS business, we executed two new agreements with eFuels companies, HIF Global and Monarch Energy Development LLC, to source and transport up to 2.4 million metric tons of CO2 per year to planned projects in southeast Texas. To date, we have signed agreements covering the potential future transportation and storage of up to 22 Mmtpa from the planned capture of CO2 emissions from existing and proposed industrial plants. On the sequestration front, we have signed agreements securing the rights to nine future storage sites which we believe have the potential to store more than 2.1 billion metric tons of CO2.

In addition to our core CCUS development activities, during the first quarter of 2023, we made two investments in carbon capture technology companies including a $2 million equity investment in Aqualung Carbon Capture AS and a $5 million equity investment in ION Clean Energy, Inc. In April 2023, based on the achievement of certain milestones, we invested the remaining $10 million of our original $20 million commitment in Clean Hydrogen Works, the project development company of a planned blue hydrogen/ammonia multi-block facility for which we have signed a definitive agreement for the transportation and storage of CO2 for the first two blocks of the proposed plant. These investments are included in “Other assets” in the Unaudited Condensed Consolidated Balance Sheet as of March 31, 2023.

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 relate to our oil and gas development capital expenditures and CCUS initiatives. During the three months ended March 31, 2023, we generated $88.5 million in cash flow from operations, or $139.6 million before working capital changes, as the first quarter included $51.1 in cash outflows for working capital items primarily related to annual ad valorem tax payments and bonus payments. We invested cash of $133.1 million in oil and gas and CCUS activities during the first quarter of 2023 and financing activities supplemented our cash flow by $44.6 million, primarily from borrowings under our bank credit facility. As of March 31, 2023, we had $68.0 million of outstanding borrowings, up from $29.0 million at December 31, 2022, and $10.1 million of outstanding letters of credit under our $750 million senior secured bank credit facility, leaving us with $671.9 million of borrowing base availability. This liquidity is more than adequate to meet our currently planned operating and capital needs.

2023 Capital Expenditure Plans. We estimate that our total oil and natural gas development capital expenditures in 2023, excluding acquisitions and capitalized interest, will be in a range of $350 million to $370 million, and our CCUS capital expenditures will be in a range of $140 million to $160 million, for a total of $510 million at the combined midpoints. In addition to the Company’s budgeted capital expenditures, we expect to incur approximately $17 million for CCUS equity investments and approximately $36 million for plugging and abandonment costs. During the first quarter of 2023, we incurred $99.8 million of oil and natural gas development capital expenditures and $19.7 million of CCUS capital expenditures, or approximately 28% and 13% of our total annual budget, respectively.

Based on current projections, including estimated production costs, oil price differentials and other assumptions, we currently anticipate that our 2023 cash flows from operations, excluding working capital changes, will approximately meet or exceed our budgeted capital expenditures and planned asset retirement obligation activities for the year, assuming oil prices of approximately $75 per Bbl in 2023. Also, at March 31, 2023, we had $671.9 million of availability under our bank credit facility, which we believe is more than adequate to cover any near-term liquidity needs.

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

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 our incurred capital expenditures:

						Three Months Ended
						March 31,
In thousands						2023						2022
Capital expenditure summary(1)
CCA EOR field expenditures(2)						$	40,038					$	17,722
CCA CO2 pipelines						523						2,191
CCA tertiary development						40,561						19,913
Non-CCA tertiary and non-tertiary fields						49,093						29,363
CO2 sources, other CO2 pipelines and other						1,563						730
Capitalized internal costs(3)						8,574						7,600
Oil and gas development capital expenditures						99,791						57,606
CCUS storage sites and related capital expenditures						19,688						20,949
Oil and gas and CCUS development capital expenditures						119,479						78,555
Capitalized interest						1,693						1,158
Acquisitions of oil and natural gas properties						35						371
Equity investments(4)						7,108						—
Total capital expenditures						$	128,315					$	80,084

(1)Capital expenditures in this summary are presented on an as-incurred basis (including accruals) and are $0.9 million and $10.0 million lower than the capital expenditures in the Unaudited Condensed Consolidated Statements of Cash Flows for the three months ended March 31, 2023 and 2022, respectively, which are presented on a cash basis.

(2)Includes pre-production CO2 costs associated with the CCA EOR development project totaling $5.2 million during the first quarter of 2023 and $2.8 million during the first quarter of 2022.

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

(4)Represents two investments made in carbon capture technology companies during the first quarter of 2023, including a $2 million equity investment in Aqualung Carbon Capture AS and a $5 million equity investment in ION Clean Energy, Inc. The investments are included in “Other assets” in the Unaudited Condensed Consolidated Balance Sheet as of March 31, 2023.

Supply Chain Issues and Potential Cost Inflation. Worldwide and U.S. supply chain issues, together with higher commodity prices, power costs, service costs and tight labor markets in the U.S., increased our costs throughout 2022 and continue to have ongoing impacts in 2023. Although the inflationary cost increases and supply chain issues have begun to level off in certain areas, we still expect additional cost and demand increases in certain categories of goods, services and wages in our operations during 2023, which could negatively impact our results of operations and cash flows in future periods. See Results of Operations – Production Expenses below for further discussion.

Senior Secured Bank Credit Agreement. In September 2020, we entered into a credit agreement with JPMorgan Chase Bank, N.A., as administrative agent, and other lenders party thereto (as amended, the “Bank Credit Agreement”). The Bank Credit Agreement is a senior secured revolving credit facility with a maturity date of May 4, 2027. Under the Bank Credit Agreement, letters of credit are available in an aggregate amount not to exceed $100 million, and short-term swingline loans are available in an aggregate amount not to exceed $25 million, each subject to the available commitments under the Bank Credit Agreement. 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. As part of our Spring 2023 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 November 1, 2023. The borrowing base is adjusted at the lenders’ discretion and is based, in

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

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 January 20, 2023, we entered into a Third Amendment to the Bank Credit Agreement, targeted at providing us the ability to elect to make interest payments on certain Secured Overnight Financing Rate (“SOFR”) loans on a weekly basis.

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 March 31, 2023, our ratio of consolidated total debt to consolidated EBITDAX was 0.11 to 1.0 (with a maximum permitted ratio of 3.5 to 1.0) and our current ratio was 2.89 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 May 1, 2023, and current oil commodity futures prices, we currently anticipate continuing to be in compliance with our financial performance covenants during the foreseeable future.

The above description of our Bank Credit Agreement, including certain referenced defined terms, is a summary of certain principal terms and conditions contained in the Bank Credit Agreement and amendments thereto, each of which is filed as an exhibit to our periodic reports filed with the Securities and Exchange Commission (“SEC”).

Commitments, Obligations and Off-Balance Sheet Arrangements. We incur numerous contractual commitments in the ordinary course of business including debt service requirements, operating 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 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.  During 2022 and 2023, we entered into storage contracts to secure rights to underground pore space in anticipation of future CCUS operations. Noncancelable commitments under those contracts total $2 million as of March 31, 2023.  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, 2022, 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

Financial and Operating Results Tables

Certain of our operating results and statistics for the comparative three months ended March 31, 2023 and 2022 are included in the following table:

						Three Months Ended
						March 31,
In thousands, except per-share and unit data						2023						2022
Financial results
Net income (loss)						$	89,199					$	(872)
Net income (loss) per common share – basic						1.73						(0.02)
Net income (loss) per common share – diluted						1.66						(0.02)
Net cash provided by operating activities						88,522						90,143
Average daily sales volumes
Bbls/d						46,389						45,466
Mcf/d						7,600						8,753
BOE/d(1)						47,655						46,925
Oil and natural gas sales
Oil sales						$	312,572					$	381,242
Natural gas sales						1,917						3,669
Total oil and natural gas sales						$	314,489					$	384,911
Commodity derivative contracts(2)
Receipt (payment) on settlements of commodity derivatives						$	2,065					$	(93,057)
Noncash fair value gains (losses) on commodity derivatives						21,058						(99,662)
Commodity derivatives income (expense)						$	23,123					$	(192,719)
Unit prices – excluding impact of derivative settlements
Oil price per Bbl						$	74.87					$	93.17
Natural gas price per Mcf						2.80						4.66
Unit prices – including impact of derivative settlements(2)
Oil price per Bbl						$	75.36					$	70.43
Natural gas price per Mcf						2.80						4.66
Oil and natural gas operating expenses
Lease operating expenses						$	129,174					$	117,828
Transportation and marketing expenses						5,389						4,645
Production and ad valorem taxes						28,263						30,443
Oil and natural gas operating revenues and expenses per BOE
Oil and natural gas revenues						$	73.32					$	91.14
Lease operating expenses						30.12						27.90
Transportation and marketing expenses						1.26						1.10
Production and ad valorem taxes						6.59						7.21
CO2 – revenues and expenses
CO2 sales and transportation fees						$	10,686					$	13,422
CO2 operating and discovery expenses						(1,196)						(2,817)
CO2 revenue and expenses, net						$	9,490					$	10,605

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

(2)See also Commodity Derivative Contracts below and Item 3. Quantitative and Qualitative Disclosures about Market Risk for information concerning our derivative transactions.

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

Sales Volumes

Average daily sales volumes by area for each of the four quarters of 2022 and for the first quarter of 2023 is shown below:

						Average Daily Sales Volumes (BOE/d)
						First Quarter																					Fourth Quarter						Third Quarter						Second Quarter						First Quarter
Operating Area						2023																					2022						2022						2022						2022
Tertiary oil sales volumes
Gulf Coast region
Delhi						2,514																					2,528						2,557						2,478						2,675
Hastings						4,450																					4,198						4,211						4,304						4,430
Heidelberg						3,539																					3,670						3,571						3,528						3,653
Oyster Bayou						3,832																					3,417						3,490						3,423						3,745
Tinsley						3,205																					2,248						3,133						3,050						3,015
Other(1)						5,585																					5,652						5,541						5,422						5,498
Total Gulf Coast region						23,125																					21,713						22,503						22,205						23,016
Rocky Mountain region
Bell Creek						3,808																					3,767						3,975						4,122						4,474
Wind River Basin						3,872																					3,726						3,121						2,703						2,517
Other(2)						2,744																					2,824						2,759						2,361						2,229
Total Rocky Mountain region						10,424																					10,317						9,855						9,186						9,220
Total tertiary oil sales volumes						33,549																					32,030						32,358						31,391						32,236
Non-tertiary oil and gas sales volumes
Gulf Coast region
Total Gulf Coast region						3,398																					3,666						3,727						3,566						3,630
Rocky Mountain region
Cedar Creek Anticline						9,316																					9,366						9,593						10,224						9,721
Other(3)						1,392																					1,579						1,431						1,380						1,338
Total Rocky Mountain region						10,708																					10,945						11,024						11,604						11,059
Total non-tertiary sales volumes						14,106																					14,611						14,751						15,170						14,689
Total sales volumes						47,655																					46,641						47,109						46,561						46,925

(1)Includes Brookhaven, Cranfield, Eucutta, Little Creek, Mallalieu, Martinville, McComb, Soso, and West Yellow Creek fields.

(2)Includes tertiary sales volumes related to our working interest positions in the Salt Creek and Grieve fields.

(3)Includes non-tertiary sales volumes from Wind River Basin, as well as Hartzog Draw and Bell Creek fields.

Total sales volumes during the first quarter of 2023 averaged 47,655 BOE/d, up approximately 2% from the fourth quarter of 2022 and the first quarter of 2022. Compared to fourth quarter of 2022, the increase in sales volumes was primarily driven by the recovery of production lost due to the late-December 2022 winter storms, which mostly impacted CCA and Hastings fields, coupled with higher production at Oyster Bayou and an increase in sales at Tinsley Field, primarily due to the sale of inventory built in the fourth quarter of 2022 as a result of the timing of barge loadings. Curtailments stemming from the CO2 development activities at CCA were just over 500 Bbls/d during the first quarter, up slightly from the prior year fourth quarter. On a year-over-year basis, the sales volumes increase compared to sales levels in the first quarter of 2022 was primarily attributable to enhancements and additional development of the CO2 floods at Soso Rodessa Phase 1 and Wind River Basin.

Our sales volumes during the three months ended March 31, 2023 were 97% oil, consistent with our sales during the comparable prior-year periods.

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Denbury Inc.

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

Oil and Natural Gas Revenues

Our oil and natural gas revenues during the three months ended March 31, 2023 decreased 18% compared to these revenues for the same period in 2022.  The changes in our oil and natural gas revenues are due to lower realized commodity prices (excluding any impact of our commodity derivative contracts), as reflected in the following table:

						Three Months Ended
						March 31,
						2023 vs. 2022
In thousands						Increase (Decrease) in Revenues						Percentage Increase (Decrease) in Revenues
Change in oil and natural gas revenues due to:
Increase in sales volumes						$	5,989					2		%
Decrease in realized commodity prices						(76,411)						(20)		%
Total decrease in oil and natural gas revenues						$	(70,422)					(18)		%

Excluding any impact of our commodity derivative contracts, our average net realized commodity prices and NYMEX differentials were as follows during each of the three months ended March 31, 2023 and 2022:

						Three Months Ended
						March 31,
						2023						2022
Average net realized prices
Oil price per Bbl						$	74.87					$	93.17
Natural gas price per Mcf						2.80						4.66
Price per BOE						73.32						91.14
Average NYMEX differentials
Gulf Coast region
Oil per Bbl						$	(1.29)					$	(1.37)
Natural gas per Mcf						(0.05)						0.16
Rocky Mountain region
Oil per Bbl						$	(1.28)					$	(1.38)
Natural gas per Mcf						0.04						0.08
Total Company
Oil per Bbl						$	(1.28)					$	(1.37)
Natural gas per Mcf						0.01						0.11

Prices received in a regional market fluctuate frequently and can differ from NYMEX pricing due to a variety of reasons, including supply and/or demand factors, crude oil quality, and location differentials.

•Gulf Coast Region. Our average NYMEX oil differential in the Gulf Coast region was a negative $1.29 per Bbl during the first quarter of 2023, a slight improvement from a negative $1.37 per Bbl during the first quarter of 2022 and a decrease from a negative $0.40 per Bbl during the fourth quarter of 2022.

•Rocky Mountain Region. Our average NYMEX oil differentials in the Rocky Mountain region was a negative $1.28 per Bbl during the first quarter of 2023, compared to a negative $1.38 per Bbl below NYMEX during the first quarter of 2022 and a positive $0.56 per Bbl during the fourth quarter of 2022.

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

CO2 Revenues and Expenses

We sell a portion of the CO2 we produce from Jackson Dome to third-party industrial users at various contracted prices primarily under long-term contracts. We recognize the revenue received on these CO2 sales as “CO2 sales and transportation fees” with the corresponding costs recognized as “CO2 operating and discovery expenses” in our Unaudited Condensed Consolidated Statements of Operations. CO2 sales and transportation fees were $10.7 million during the three months ended March 31, 2023, compared to $13.4 million during the three months ended March 31, 2022. The decrease in CO2 sales and transportation fees from the prior-year period is primarily due to a short-term sales contract in place during the first quarter of 2022 as well as unplanned downtime of third-party purchasers.

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

We have routinely entered into oil derivative contracts to provide an economic hedge of our exposure to commodity price risk associated with anticipated future oil production and to provide more certainty to our future cash flows.  These contracts currently consist of fixed-price swaps and costless collars. The following table summarizes the impact our crude oil derivative contracts had on our operating results for the three months ended March 31, 2023 and 2022:

						Three Months Ended
						March 31,
In thousands						2023						2022
Receipt (payment) on settlements of commodity derivatives						$	2,065					$	(93,057)
Noncash fair value gains (losses) on commodity derivatives						21,058						(99,662)
Total income (expense)						$	23,123					$	(192,719)

Commodity derivatives income (expense) is comprised of (1) payments or receipts on settlements of commodity derivatives and (2) noncash changes in the fair values of commodity derivatives. Changes in the fair values of commodity derivatives are due to changes in oil futures prices since the prior period or subsequent to entering into new derivative agreements. During the first three months of 2023, we received $2.1 million upon expiration of commodity derivative contracts, compared to cash payments upon settlement of $93.1 million during the first three months of 2022.

In order to provide a level of price protection to our oil production, we have hedged a portion of our estimated oil production through 2024 using NYMEX fixed-price swaps and costless collars. Upon emergence from bankruptcy in September 2020, we were required to hedge through mid-2022 at certain levels of estimated production under our post-emergence bank credit facility. Those hedges resulted in significant cash losses to us during 2022 as oil prices subsequently improved beyond our hedged prices. We no longer have any hedging requirements under our bank credit facility; however, we plan to continue to hedge a portion of our production in order to provide a level of certainty in our cash flows. See Note 6, Commodity Derivative Contracts, to the Unaudited Condensed Consolidated Financial Statements for additional details of our outstanding commodity derivative contracts as of March 31, 2023, and Item 3, Quantitative and Qualitative Disclosures about

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

Market Risk below for additional discussion. In addition, the following table summarizes our commodity derivative contracts as of May 1, 2023:

									2Q 2023						2H 2023						1H 2024						2H 2024
WTI NYMEX			Volumes Hedged (Bbls/d)						9,500						18,000						5,000						1,000
Fixed-Price Swaps			Weighted Average Swap Price						$76.65						$78.51						$75.34						$75.12
WTI NYMEX			Volumes Hedged (Bbls/d)						17,500						9,000						—						—
Collars			Weighted Average Floor / Ceiling Price						$69.71 / $100.42						$68.33 / $100.69						—						—
			Total Volumes Hedged (Bbls/d)						27,000						27,000						5,000						1,000

Based on current contracts in place and NYMEX oil futures prices as of May 1, 2023, which averaged approximately $74 per Bbl for the remainder of 2023, we currently expect that we would receive cash receipts of approximately $15 million during 2023 upon settlement of these contracts, the amount of which is primarily dependent upon fluctuations in future NYMEX oil prices in relation to the prices of our 2023 fixed-price swaps (which have a weighted average NYMEX oil price of $78.12 per Bbl). Changes in commodity prices, expiration of contracts, and new commodity contracts entered into cause fluctuations in the estimated fair value of our oil derivative contracts. Because we do not utilize hedge accounting for our commodity derivative contracts, the period-to-period changes in the fair value of these contracts, as outlined above, are recognized in our statements of operations.

Production Expenses

Lease Operating Expenses

						Three Months Ended
						March 31,
In thousands, except per-BOE data						2023						2022
Total lease operating expenses						$	129,174					117,828
Total lease operating expenses per BOE						$	30.12					$	27.90

When comparing the first three months of 2023 and 2022, total lease operating expenses increased by $11.3 million (10%) on an absolute-dollar basis, or $2.22 (8%) on a per-BOE basis. Inflation and higher activity levels resulted in higher labor costs ($2.5 million), repair and maintenance ($2.4 million) and workover costs ($2.2 million) and CO2 costs increased primarily due to an industrial CO2 contract change ($1.3 million).

Compared to the fourth quarter of 2022, lease operating expenses in the most recent quarter increased $3.4 million (3%) on an absolute-dollar basis and $0.81 (3%) on a per-BOE basis, due primarily to higher repair and maintenance and workover costs.

Transportation and Marketing Expenses

Transportation and marketing expenses primarily consist of amounts incurred related to the transportation, marketing, and processing of oil and natural gas production. Transportation and marketing expenses were $5.4 million and $4.6 million for the three months ended March 31, 2023 and 2022, respectively. The increase was primarily due to a change in certain of our sales contracts.

Taxes Other Than Income

Taxes other than income includes production, ad valorem and franchise taxes. Taxes other than income decreased $2.3 million (7%) during the three months ended March 31, 2023, compared to the same prior-year period, due primarily to a decrease in production taxes resulting from lower oil and natural gas revenues.

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

General and Administrative Expenses (“G&A”)

						Three Months Ended
						March 31,
In thousands, except per-BOE data and employees						2023						2022
Cash G&A costs						$	18,039					$	15,721
Stock-based compensation						4,938						2,971
G&A expense						$	22,977					$	18,692
G&A per BOE
Cash G&A costs						$	4.21					$	3.72
Stock-based compensation						1.15						0.71
G&A expenses						$	5.36					$	4.43
Employees as of period end						774						724

Our G&A expense on an absolute-dollar basis was $23.0 million during the three months ended March 31, 2023, an increase of $4.3 million from the same prior-year period, with the increase primarily due to higher employee-related costs, including salaries and stock compensation expense.

Interest and Financing Expenses

						Three Months Ended
						March 31,
In thousands, except per-BOE data and interest rates						2023						2022
Cash interest(1)						$	2,089					$	1,130
Noncash interest expense						531						685
Less: capitalized interest						(1,693)						(1,158)
Interest expense, net						$	927					$	657
Interest expense, net per BOE						$	0.22					$	0.16
Average debt principal outstanding						$	62,346					$	34,278
Average cash interest rate(2)						8.0		%				5.5		%

(1)Includes commitment fees paid on the Company’s bank credit facility but excludes debt issue costs.

(2)Excludes commitment fees paid on the 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

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

						Three Months Ended
						March 31,
In thousands, except per-BOE data						2023						2022
Oil and natural gas properties						$	34,199					$	28,668
CO2 properties, pipelines, plants and other property and equipment						6,716						6,677
Accelerated depreciation charge						1,117						—
Total DD&A						$	42,032					$	35,345
DD&A per BOE
Oil and natural gas properties						$	7.97					$	6.79
CO2 properties, pipelines, plants and other property and equipment						1.57						1.58
Accelerated depreciation charge						0.26						—
Total DD&A cost per BOE						$	9.80					$	8.37

DD&A expense during the three months ended March 31, 2023 increased $6.7 million compared to the three months ended March 31, 2022, primarily due to higher depletable costs for our oil and gas properties, accelerated depreciation in the current period and an increase in accretion expense on our asset retirement obligations. We expect DD&A expense will be higher subsequent to the initial booking of proved reserves at our new CCA CO2 flood, which we currently expect will occur in the second quarter of 2023.

Other Expenses

Other expenses during the three months ended March 31, 2023 totaled $1.5 million, compared to $2.1 million during the three months ended March 31, 2022. Other expenses during the three months ended March 31, 2023 primarily includes $1.3 million in CCUS-related expenses and $1.0 million of plant operating expense, partially offset by an approximate $1.0 million reversal of the second quarter 2022 accrual for the Delta Pipeline CO2 release incident costs resulting from a negotiated settlement. Other expenses during the three months ended March 31, 2022 included $1.0 million in plant operating expenses, $0.3 million in expenses related to the Delta Pipeline incident, $0.3 million in CCUS expenses, and a $0.2 million contingent consideration adjustment related to a previous acquisition.

Income Taxes

						Three Months Ended
						March 31,
In thousands, except per-BOE amounts and tax rates						2023						2022
Current income tax expense (benefit)						$	2,338					$	(561)
Deferred income tax expense (benefit)						25,912						(5,944)
Total income tax expense (benefit)						$	28,250					$	(6,505)
Average income tax expense (benefit) per BOE						$	6.59					$	(1.54)
Effective tax rate						24.1		%				88.2		%
Total net deferred tax liability						$	97,031					$	4,306

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 2023 and 2022. Our effective tax rate for the three months ended March 31, 2023 was slightly lower than our estimated statutory rate primarily due to excess stock compensation deductions that were recorded discretely in the quarter. Our effective tax rate for the three months ended March 31, 2022 was higher than our estimated statutory rate due to the release of a portion of the

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

valuation allowance on our deferred tax assets combined with the net loss for the period. Our annualized effective tax rate including any discrete items for the year ended December 31, 2023 is currently estimated to be approximately 24%.

We 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.

We assess the valuation allowance recorded on our deferred tax assets on a quarterly basis, which was $59.2 million at December 31, 2022. This valuation allowance relates primarily to our Louisiana net deferred tax assets of $55.4 million, as well as our Alabama net deferred tax assets and certain Mississippi tax credits totaling $3.8 million. We have concluded that the benefits of such deferred tax assets are not more likely than not to be realized due to lack of sufficient taxable income to fully realize the benefits of such deferred tax assets.

During the three months ended March 31, 2023, we received $0.6 million of refundable alternative minimum tax credits under the Tax Cut and Jobs Act, which amount was recorded as a receivable on the balance sheet at December 31, 2022. We have state net operating loss carryforwards that expire in various years, starting in 2025. Our Louisiana net operating loss carryforwards may be carried forward indefinitely.

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
						March 31,
Per-BOE data						2023						2022
Oil and natural gas revenues						$	73.32					$	91.14
Receipt (payment) on settlements of commodity derivatives						0.49						(22.03)
Lease operating expenses						(30.12)						(27.90)
Production and ad valorem taxes						(6.59)						(7.21)
Transportation and marketing expenses						(1.26)						(1.10)
Production netback						35.84						32.90
CO2 sales, net of operating and discovery expenses						2.21						2.51
General and administrative expenses						(5.36)						(4.43)
Interest expense, net						(0.22)						(0.16)
Stock compensation and other						0.08						0.09
Changes in assets and liabilities relating to operations						(11.91)						(9.57)
Cash flows from operations						20.64						21.34
DD&A						(9.54)						(8.37)
DD&A – accelerated depreciation charge						(0.26)						—
Deferred income taxes						(6.04)						1.41
Noncash fair value gains (losses) on commodity derivatives						4.90						(23.60)
Other noncash items						11.10						9.01
Net income (loss)						$	20.80					$	(0.21)

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

CRITICAL ACCOUNTING POLICIES

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

FORWARD-LOOKING INFORMATION

The data and/or statements contained in this Quarterly Report on Form 10-Q, particularly statements found in “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” that are not historical facts, 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, and include, but are not limited to: possible or assumed future results of operations, cash flows, production and capital expenditures; goals and predictions as to the Company’s future carbon capture, use and storage (“CCUS”) activities; and assumptions as to oil markets or general economic conditions.

Such forward-looking statements may be or may concern, among other things, the level and volatility of posted or realized oil prices; the adequacy of our liquidity sources to support our future activities; statements or predictions related to the ultimate timing and financial impact of our proposed CCUS arrangements, including the estimated emissions storage capacity of storage sites, predictions of long-term cumulative capital investments in CCUS, the volumes of CO2 emissions we estimate can be transported and stored, along with the timing of receipt of first revenues from storage of CO2; our projected production levels, oil and natural gas revenues or oilfield costs, the impact of supply chain issues and inflation on our results of operations; current or future expectations or estimations of our cash flows or the impact of changes in commodity prices on cash flows; availability, terms and financial statement and cash settlement impact of commodity derivative contracts or their predicted downside cash flow protection; forecasted drilling activity or methods, including the timing and location thereof; anticipated timing of initial production responses in tertiary flooding projects in particular fields or areas; other development activities, finding costs, interpretation or prediction of formation details, hydrocarbon reserve quantities and values, CO2 reserves and supply and their availability, potential reserves, barrels or percentages of recoverable original oil in place; the impact of changes or proposed changes in Federal or state tax or environmental laws or regulations or in any future regulation of CO2 pipelines; the outcomes of any pending litigation or 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 that could significantly and adversely be affected by various factors discussed below, along with currently unknowable events beyond our control.  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 from current projections are fluctuations in worldwide or U.S. oil prices, especially in light of existing economic uncertainties or geopolitical events such as the war in Ukraine; widespread inflation in economies across the world; future decisions or actions as to production levels and/or pricing by OPEC; as to our CCUS activities, the successful completion of technical and feasibility evaluations, the raising of funds sufficient to build and operate add-on or new facilities, the pace of finalization of CCUS arrangements; and the receipt of required regulatory approval or classifications; success of our risk management techniques; 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, or other natural occurrences; conditions in the worldwide financial, trade currency and credit markets; the risks and uncertainties inherent in oil and gas drilling and production activities; and the risks and uncertainties set forth from time to time in this or our other periodic public reports, other 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.  Over the last few years, these contracts have consisted of costless collars and fixed-price 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 March 31, 2023, we do not have any 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 2024 using NYMEX fixed-price swaps and costless collars. Depending on market conditions, we may continue to add to our existing 2023 and 2024 hedges. See also Note 6, Commodity Derivative Contracts, and Note 7, Fair Value Measurements, to the Unaudited Condensed Consolidated Financial Statements for additional information regarding our commodity derivative contracts.

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

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

At March 31, 2023, our commodity derivative contracts were recorded at their fair value, which was a net asset of $23.6 million, a $21.1 million change from the $2.5 million net asset recorded at December 31, 2022.  This change is related to the expiration of commodity derivative contracts during the three months ended March 31, 2023, new commodity derivative contracts entered during 2023 for future periods, and to the changes in oil futures prices between December 31, 2022 and March 31, 2023.

Commodity Derivative Sensitivity Analysis

Based on NYMEX crude oil futures prices and derivative contracts in place as of March 31, 2023, and assuming both a 10% increase and decrease thereon, we would expect to make payments on our crude oil derivative contracts as shown in the following table:

In thousands						Receipt / (Payment)
Based on:
Futures prices as of March 31, 2023						$	17,016
10% increase in prices						(15,190)
10% decrease in prices						53,717

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 on 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 March 31, 2023, we had $68.0 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 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 March 31, 2023:

In thousands						2023 - 2026						2027						Total						Fair Value
Variable rate debt:
Senior Secured Bank Credit Facility (weighted average interest rate of 8.14% at March 31, 2023)						$	—					$	68,000					$	68,000					$	68,000

See Note 3, 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 March 31, 2023, 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 first quarter of fiscal 2023, 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.

Notice of Probable Violation from Pipeline and Hazardous Materials Safety Administration (“PHMSA”) Regarding Delta-Tinsley CO2 Pipeline Failure

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 CO2 release from a pipeline failure in our CO2 pipeline in Yazoo County, Mississippi running between our Tinsley and Delhi fields, and assessed a preliminary civil penalty of $3.9 million, which the Company recorded in its financial statements in the second quarter of 2022. Over the ensuing 10 months, the Company has engaged in settlement discussions with PHMSA related to the nature and extent of the alleged probable violation and civil penalty and the future actions required in connection with the operation of the Company’s CO2 pipeline.

On March 24, 2023, Denbury and PHMSA entered into a final Consent Order and Consent Agreement that settled all of the allegations in the NOPV and also reduced the assessed penalty to $2.9 million. The $1.0 million reduction was reflected in “Other Expenses” in our Unaudited Condensed Consolidated Statement of Operations in the first quarter of 2023. Under the Consent Agreement, the Company has agreed to take numerous preventative and mitigative steps related to geohazard risks of its pipeline operations and related safety and community informational issues.

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, 2022. 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, 2022.

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

Issuer Purchases of Equity Securities

First Quarter Purchases of Equity Securities by the Issuer and Affiliated Purchasers

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
January 2023						—						$	—					—						$	250,000,000
February 2023						—						—						—						$	250,000,000
March 2023						16,281						83.98						—						$	250,000,000
Total						16,281												—

(1)    Represents shares surrendered by employees to the Company to satisfy their tax withholding requirements upon vesting of restricted shares.

Share Repurchase Program

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, at an average price of $61.92 per share. In August 2022, our Board of Directors increased the common share repurchase program by $100 million, leaving $250 million authorized for future repurchases, as no repurchases have subsequently been made 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.

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)*						2023 Form of Restricted Stock Award under the 2020 Omnibus Stock and Incentive Plan for Denbury Inc.
10(b)*						2023 Form of Deferred Stock Unit Award under the 2020 Omnibus Stock and Incentive Plan for Denbury Inc.
10(c)*						2023 Form of TSR Performance Award under the 2020 Omnibus Stock and Incentive Plan for Denbury Inc.
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 March 31, 2023, 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.
May 4, 2023						/s/ Mark C. Allen
						Mark C. Allen Executive Vice President and Chief Financial Officer
May 4, 2023						/s/ Nicole Jennings
						Nicole Jennings Vice President and Chief Accounting Officer

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