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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 June 30, 2023

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

For the transition period from _______ to ________

Commission file number: 001-12935

DENBURY INC.

(Exact name of registrant as specified in its charter)

Delaware

20-0467835

(State or other jurisdiction of incorporation or organization)

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

5851 Legacy Circle,

Plano,

75024

(Address of principal executive offices)

(Zip Code)


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

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


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

Not applicable

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

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

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

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

Large accelerated filer

☑

Accelerated filer

☐

Non-accelerated filer

☐

Smaller reporting company

☐

Emerging growth company

☐

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 July 31, 2023, was 50,902,023.

Denbury Inc.

Table of Contents

Page

PART I. FINANCIAL INFORMATION

Item 1.

Financial Statements

Unaudited Condensed Consolidated Balance Sheets

Unaudited Condensed Consolidated Statements of Operations

Unaudited Condensed Consolidated Statements of Cash Flows

Unaudited Condensed Consolidated Statements of Changes in Stockholders’ Equity

Notes to Unaudited Condensed Consolidated Financial Statements

Item 2.

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

Item 3.

Quantitative and Qualitative Disclosures about Market Risk

Item 4.

Controls and Procedures

PART II. OTHER INFORMATION

Unregistered Sales of Equity Securities and Use of Proceeds

Item 3.

Defaults Upon Senior Securities

Item 4.

Mine Safety Disclosures

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

Denbury Inc.

Unaudited Condensed Consolidated Balance Sheets

(In thousands, except par value and share data)



	June 30, 2023		December 31, 2022
Assets
Current assets
Cash and cash equivalents	$	531	$	521
Accrued production receivable	131,422		144,277
Trade and other receivables, net	21,800		27,343
Derivative assets	36,809		15,517
Prepaids	20,117		18,572
Total current assets	210,679		206,230
Property and equipment
Oil and natural gas properties (using full cost accounting)
Proved properties	1,751,158		1,414,779
Unevaluated properties	114,320		240,435
CO2 properties	193,432		190,985
Pipelines	219,748		220,125
CCUS storage sites and related assets	114,190		64,971
Other property and equipment	115,086		107,133
Less accumulated depletion, depreciation, amortization and impairment	(382,591)		(306,743)
Net property and equipment	2,125,343		1,931,685
Operating lease right-of-use assets	19,425		18,017
Derivative assets	1,269		—

Intangible assets, net	74,571		79,128
Restricted cash for future asset retirement obligations	48,405		47,359
Other assets	61,927		45,080
Total assets	$	2,541,619	$	2,327,499
Liabilities and Stockholders’ Equity
Current liabilities
Accounts payable and accrued liabilities	$	221,173	$	248,800
Oil and gas production payable	70,455		80,368
Derivative liabilities	—		13,018

Operating lease liabilities	5,098		4,676
Total current liabilities	296,726		346,862
Long-term liabilities
Long-term debt, net of current portion	85,153		29,000
Asset retirement obligations	312,372		315,942

Deferred tax liabilities, net	118,171		71,120
Operating lease liabilities	16,075		15,431
Other liabilities	12,969		16,527
Total long-term liabilities	544,740		448,020
Commitments and contingencies (Note 9)
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; 50,473,001 and 49,814,874 shares issued, respectively	50		50
Paid-in capital in excess of par	1,058,119		1,047,063
Retained earnings	641,984		485,504

Total stockholders’ equity	1,700,153		1,532,617
Total liabilities and stockholders’ equity	$	2,541,619	$	2,327,499

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

Table of Contents

Denbury Inc.

Unaudited Condensed Consolidated Statements of Operations

(In thousands, except per-share data)


	Three Months Ended June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
Revenues and other income
Oil, natural gas, and related product sales	$	302,946	$	451,970	$	617,435	$	836,881
CO2 sales and transportation fees	11,164		12,610		21,850		26,032
Oil marketing revenues	13,983		16,786		28,531		30,062
Other income	890		790		2,185		1,040
Total revenues and other income	328,983		482,156		670,001		894,015
Expenses
Lease operating expenses	130,291		124,351		259,465		242,179
Transportation and marketing expenses	5,159		4,802		10,548		9,447
CO2 operating and discovery expenses	1,597		1,681		2,793		4,498
Taxes other than income	26,937		36,317		55,975		67,698
Oil marketing purchases	13,922		15,027		28,390		28,067
General and administrative expenses	26,895		19,235		49,872		37,927
Interest, net of amounts capitalized of $2,259, $975, $3,952 and $2,133, respectively	825		1,526		1,752		2,183
Depletion, depreciation, and amortization	49,767		35,400		91,799		70,745
Commodity derivatives expense (income)	(19,677)		56,854		(42,800)		249,573


Other expenses	3,990		6,621		5,481		8,733
Total expenses	239,706		301,814		463,275		721,050
Income before income taxes	89,277		180,342		206,726		172,965
Income tax provision	21,996		24,848		50,246		18,343
Net income	$	67,281	$	155,494	$	156,480	$	154,622

Net income per common share
Basic	$	1.30	$	3.00	$	3.03	$	2.99
Diluted	$	1.25	$	2.83	$	2.90	$	2.81

Weighted average common shares outstanding
Basic	51,817		51,757		51,661		51,680
Diluted	53,999		54,886		53,882		54,931

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

Table of Contents

Denbury Inc.

Unaudited Condensed Consolidated Statements of Cash Flows

(In thousands)


	Six Months Ended June 30,
	2023		2022
Cash flows from operating activities
Net income	$	156,480	$	154,622
Adjustments to reconcile net income to cash flows from operating activities
Depletion, depreciation, and amortization	91,799		70,745

Deferred income taxes	47,051		15,992
Stock-based compensation	11,486		7,075
Commodity derivatives expense (income)	(42,800)		249,573
Receipt (payment) on settlements of commodity derivatives	7,222		(221,016)
Debt issuance cost amortization	1,063		1,934

Other, net	(4,176)		(3,155)
Changes in assets and liabilities, net of effects from acquisitions
Accrued production receivable	12,855		(85,786)
Trade and other receivables	5,545		(11,783)
Other current and long-term assets	(315)		(12,175)
Accounts payable and accrued liabilities	(25,623)		52,010
Oil and natural gas production payable	(9,914)		33,329
Asset retirement obligations and other liabilities	(19,660)		(11,257)

Net cash provided by operating activities	231,013		240,108

Cash flows from investing activities
Oil and natural gas capital expenditures	(210,418)		(139,522)
CCUS storage sites and related capital expenditures	(49,289)		(17,758)
Acquisitions of oil and natural gas properties	(42)		(374)
Pipelines and plants capital expenditures	(1,291)		(20,264)
Net proceeds from sales of oil and natural gas properties and equipment	—		237
Equity investments	(19,034)		—
Other	(13,631)		(5,623)
Net cash used in investing activities	(293,705)		(183,304)

Cash flows from financing activities
Bank repayments	(865,000)		(524,000)
Bank borrowings	921,000		489,000



Common stock repurchase program	—		(23,374)

Other	7,748		(1,388)
Net cash provided by (used in) financing activities	63,748		(59,762)
Net increase (decrease) in cash, cash equivalents, and restricted cash	1,056		(2,958)
Cash, cash equivalents, and restricted cash at beginning of period	47,880		50,344
Cash, cash equivalents, and restricted cash at end of period	$	48,936	$	47,386

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

Table of Contents

Denbury Inc.

Unaudited Condensed Consolidated Statements of Changes in Stockholders' Equity

(Dollar amounts in thousands)


	Common Stock ($.001 Par Value)			Paid-In Capital in Excess of Par		Retained Earnings		Treasury Stock (at cost)
	Shares	Amount						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 for 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








Forfeited pursuant to stock compensation plans	(1,013)	—		—		—		—	—		—
Stock-based compensation	—	—		7,246		—		—	—		7,246

Employee stock purchase plan	11,115	—		815		—		—	—		815
Issued pursuant to exercise of warrants	186,373	—		228		—		—	—		228
Net income	—	—		—		67,281		—	—		67,281
Balance – June 30, 2023	50,473,001	$	50	$	1,058,119	$	641,984	—	$	—	$	1,700,153


	Common Stock ($.001 Par Value)			Paid-In Capital in Excess of Par		Retained Earnings (Accumulated Deficit)		Treasury Stock (at cost)
	Shares	Amount						Shares	Amount		Total Equity
Balance – December 31, 2021	50,193,656	$	50	$	1,129,996	$	5,344	—	$	—	$	1,135,390
Issued pursuant to stock compensation plans	141,581	—		—		—		—	—		—
Stock-based compensation	—	—		3,142		—		—	—		3,142
Tax withholding for stock compensation plans	—	—		(58)		—		—	—		(58)
Issued pursuant to exercise of warrants	14,153	—		47		—		—	—		47
Net loss	—	—		—		(872)		—	—		(872)
Balance – March 31, 2022	50,349,390	$	50	$	1,133,127	$	4,472	—	$	—	$	1,137,649
Stock repurchase program	(457,549)	—		—		—		457,549	(28,751)		(28,751)
Forfeited pursuant to stock compensation plans	(3,264)	—		—		—		—	—		—
Stock-based compensation	—	—		4,400		—		—	—		4,400
Tax withholding for stock compensation plans	—	—		(5)		—		—	—		(5)
Issued pursuant to exercise of warrants	987,411	1		53		—		—	—		54
Net income	—	—		—		155,494		—	—		155,494
Balance – June 30, 2022	50,875,988	$	51	$	1,137,575	$	159,966	457,549	$	(28,751)	$	1,268,841

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

Table of Contents

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.

Proposed Merger of the Company with Exxon Mobil Corporation. On July 13, 2023, we entered into a definitive merger agreement (“Merger Agreement”) with Exxon Mobil Corporation (“ExxonMobil”), providing for Denbury to merge with a wholly owned subsidiary of ExxonMobil (the “Merger”) and survive as a wholly owned subsidiary of ExxonMobil. Under the terms of the Merger Agreement, each issued and outstanding share of our common stock (other than certain excluded shares held by us as treasury stock or owned by ExxonMobil or its merger subsidiary), par value $0.001 per share, will be converted into the right to receive 0.84 shares of ExxonMobil common stock, without par value (the “Exchange Ratio”).  Completion of the Merger remains subject to certain conditions, including the approval of the Merger by our stockholders, as well as certain governmental and regulatory approvals.  The Merger is currently expected to close in the fourth quarter of 2023; however, no assurance can be given as to when, or if, the Merger will occur.

In connection with the Merger, any Company restricted stock awards, deferred stock awards, and performance shares that are outstanding immediately prior to completion of the Merger will generally become vested and converted into the right to receive shares of ExxonMobil common stock based on the Exchange Ratio. Any unexercised Series A warrants remaining at the closing date will be canceled for no consideration in accordance with the terms of the underlying warrant agreements. In order for the shares of Denbury common stock underlying the warrants to be converted into the right to receive shares of ExxonMobil common stock in the Merger, the holders must exercise their warrants in accordance with the time periods and under the terms specified in the applicable warrant agreement to receive shares of Denbury common stock prior to the closing of the Merger.

The Merger Agreement contains termination rights for each of the Company and ExxonMobil, including, among others: (1) if the consummation of the Merger does not occur on or before July 13, 2024 (the “End Date”); except that if the effective time of the Merger has not occurred by July 13, 2024 due to the fact that all required applicable regulatory approvals have not been obtained on acceptable terms but all other conditions to closing have been satisfied (other than those conditions that by their terms are to be satisfied at the closing, each of which is capable of being satisfied) or (to the extent permitted by law) waived, the End Date may be extended by either party to January 13, 2025; (2) subject to certain conditions, if the Company wishes to terminate the Merger Agreement to enter into a definitive agreement with respect to a Superior Proposal; and (3) subject to certain conditions, if ExxonMobil wishes to terminate the Merger Agreement upon the occurrence of a Specified Pipeline Event. Upon termination of the Merger Agreement under specified circumstances, including, among others, the termination by ExxonMobil in the event of a change of recommendation by the Board of Directors of the Company or by the Company in order to enter into a definitive agreement with respect to a Superior Proposal, the Company would be required to pay ExxonMobil a termination fee of $144,000,000. In addition, upon termination of the Merger Agreement by ExxonMobil due to the occurrence of a Specified Pipeline Event, ExxonMobil would be required to pay the Company a reverse termination fee of $144,000,000.

The above description of the Merger Agreement and the transactions contemplated thereby, including certain referenced terms, is a summary of certain principal terms and conditions contained in the Merger Agreement.

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 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.

Table of Contents

Denbury Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

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 June 30, 2023, our consolidated results of operations for the three and six months ended June 30, 2023 and 2022, our consolidated cash flows for the six months ended June 30, 2023 and 2022, and our consolidated statements of changes in stockholders’ equity for the three and six months ended June 30, 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	June 30, 2023		June 30, 2022
Cash and cash equivalents	$	531	$	517

Restricted cash for future asset retirement obligations	48,405		46,869
Total cash, cash equivalents, and restricted cash shown in the Unaudited Condensed Consolidated Statements of Cash Flows	$	48,936	$	47,386

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 per Common Share

Basic net income per common share is computed by dividing the net income attributable to common stockholders by the weighted average number of shares of common stock outstanding during the period. Basic weighted average common shares exclude shares of nonvested restricted stock (although nonvested restricted stock is issued and outstanding upon grant). As these restricted shares vest, they will be included in the shares outstanding used to calculate basic net income 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 and six months ended June 30, 2023 includes 1,775,182 performance-based and restricted stock units which are fully vested as of June 30, 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 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 and six months ended June 30, 2023 and 2022, there were no adjustments to net income for purposes of calculating basic and diluted net income per common share.

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Notes to Unaudited Condensed Consolidated Financial Statements

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


	Three Months Ended		Six Months Ended
	June 30,		June 30,
In thousands	2023	2022	2023	2022







Weighted average common shares outstanding – basic	51,817	51,757	51,661	51,680
Effect of potentially dilutive securities
Restricted stock, restricted stock units and performance stock units	475	603	418	591

Warrants	1,706	2,526	1,802	2,660
Employee Stock Purchase Plan	1	—	1	—
Weighted average common shares outstanding – diluted	53,999	54,886	53,882	54,931

For purposes of calculating diluted weighted average common shares, unvested restricted stock units, unvested restricted stock, unvested performance stock units, unissued 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 per share for the six months ended June 30, 2023 and June 30, 2022, as their effect would have been antidilutive, as of the respective dates:


	June 30,
In thousands	2023	2022
Restricted stock, restricted stock units and performance stock units (1)	5	191

(1) Antidilutive shares for the six-month periods ended June 30, 2023 and 2022 reflect total shares excluded from the computation of diluted net income per share that are potentially dilutive in the future, assuming performance stock units at the target level. Shares disclosed for the period ended June 30, 2022 have been revised to be consistent with the current year presentation.

At June 30, 2023, the Company had 2.6 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 0.8 million Series B warrants outstanding. The warrants may be exercised for cash or on a cashless basis. The Series A warrants are exercisable until the earliest of (1) September 18, 2025, (2) the date of consummation of a Sale Transaction (as defined in the applicable warrant agreement), and (3) a Winding Up (as defined in the applicable warrant agreement), at which time the Series A warrants expire. The Series B warrants are exercisable until the earliest of (1) September 18, 2023, (2) the date of consummation of a Sale Transaction (as defined in the applicable warrant agreement), and (3) a Winding Up (as defined in the applicable warrant agreement), at which times the Series B warrants expire. Through June 30, 2023, a total of 0.9 million Series A warrants and a total of 2.1 million Series B warrants have been exercised for a total of 1.7 million shares, most of which were exercised on a cashless basis. During July 2023, 0.6 million Series A warrants were exercised resulting in the issuance of 0.4 million shares, leaving 1.2 million Series A warrants outstanding as of July 31, 2023. If the Merger with ExxonMobil is consummated, any unexercised warrants remaining at the closing date will be canceled for no consideration in accordance with the terms of the underlying warrant agreements. In order for the shares of Denbury common stock underlying the warrants to be converted into the right to receive shares of ExxonMobil common stock in the Merger, the holders must exercise their warrants in accordance with the time periods and under the terms specified in the applicable warrant agreement to receive shares of Denbury common stock prior to the closing of the Merger.

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

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Denbury Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

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 or six months ended June 30, 2023 or June 30, 2022.

Equity Method Investments

In accordance with equity method accounting, we record our initial equity investments at cost and periodically adjust the value of the investment balance to recognize (1) the proportionate share of the investee’s net income or losses after the date of investment, (2) additional contributions made and dividends or distributions received, and (3) impairment losses resulting from adjustments to net realizable value. The investments are included in “Other assets” in the Unaudited Condensed Consolidated Balance Sheet as of June 30, 2023. We evaluate our equity method investments for other-than temporary impairment on a periodic basis.

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.

Disaggregation of Revenue

The following table summarizes our revenues by product type for the three and six months ended June 30, 2023 and 2022:


	Three Months Ended				Six Months Ended
	June 30,				June 30,
In thousands	2023		2022		2023		2022
Oil sales	$	301,543	$	446,592	$	614,115	$	827,834
Natural gas sales	1,403		5,378		3,320		9,047
CO2 sales and transportation fees	11,164		12,610		21,850		26,032
Oil marketing revenues	13,983		16,786		28,531		30,062
Total revenues	$	328,093	$	481,366	$	667,816	$	892,975

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Notes to Unaudited Condensed Consolidated Financial Statements

Note 3. Long-Term Debt

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


In thousands	June 30, 2023		December 31, 2022
Senior Secured Bank Credit Agreement	$	85,000	$	29,000

Capital lease obligations	153		—


Long-term debt and capital lease obligations	$	85,153	$	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 June 30, 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 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.

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Notes to Unaudited Condensed Consolidated Financial Statements

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. Investments

Equity Method Investments

Our equity-method investments and their book value balances consisted of the following:


In thousands	June 30, 2023		December 31, 2022
Equity method investments (1)
Clean Hydrogen Works, LA-1, L.L.C.	$	20,218	$	10,218
Libra, CO2 Storage Solutions, LLC	1,927		—
Total equity method investments	22,145		10,218

(1) The investment balances in this table include capitalized transaction costs.

Clean Hydrogen Works. In April 2023, based on the achievement of certain milestones, we invested the remaining $10 million of our total $20 million commitment to invest in Clean Hydrogen Works (“CHW”), 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. We account for the investment in CHW under the equity method of accounting.

When an entity makes an investment that qualifies for the equity method of accounting, there may be a difference in the cost basis of the investment and the proportional interest in the underlying equity in the net assets of the investee (“basis difference”). At the acquisition date, the Company identified a basis difference of $17.7 million associated with its investment in CHW. The basis difference was allocated to finite lived intangible assets identified and equity method goodwill. The Company will amortize the basis differences attributable to finite lived intangible assets and record the amortization as a reduction of earnings from equity method investments, net in the accompanying Condensed Consolidated Statements of Operations.

Libra, CO2 Storage Solutions, LLC. During the second quarter, we invested $1.5 million in Libra CO2 Storage Solutions, LLC in connection with a joint venture related to a CO2 sequestration project in St. Charles Parish, Louisiana.

Other Investments

During the first quarter of 2023, we made two investments in carbon capture technology companies, including a $2 million investment in Aqualung Carbon Capture AS and a $5 million investment in ION Clean Energy, Inc.

All investments are included in “Other assets” in the Unaudited Condensed Consolidated Balance Sheet as of June 30, 2023.

Note 5. Stockholders’ Equity

2022 Share Repurchases

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. No share repurchases have been made under this program since that time. In August 2022, the Board increased Denbury’s stock repurchase authorization by $100 million to a total of $250 million for future repurchases under the program. With limited exceptions, the Merger Agreement precludes the Company from any future repurchases or acquisition of shares of its capital stock, including under a repurchase program, without ExxonMobil’s consent.

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Denbury Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

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 six months ended June 30, 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 six months ended June 30, 2023, we decreased additional paid in capital by $1.3 million for tax withholdings on RSUs.

Note 6. 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 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 June 30, 2023 was in line with our estimated statutory rate and our effective tax rate for the six months ended June 30, 2023 was slightly lower than our estimated statutory rate primarily due to excess stock compensation deductions that were recorded discretely in the first quarter. Our effective tax rate for the three and six months ended June 30, 2022 was significantly lower than our estimated statutory rate due to the release of a portion of the valuation allowance on our deferred tax assets.

Note 7. Commodity Derivative Contracts

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

Historically, we have entered into various oil and natural gas derivative contracts to provide an economic hedge of our exposure to commodity price risk associated with anticipated future oil and natural gas production and to provide more certainty to our future cash flows. We do not hold or issue derivative financial instruments for trading purposes. Over the last few years these contracts have consisted of fixed-price swaps and costless collars. The production 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 currently have no hedging requirements under our bank credit facility.

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Notes to Unaudited Condensed Consolidated Financial Statements

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 June 30, 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.

The following table summarizes our commodity derivative contracts as of June 30, 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
July – Dec	NYMEX	18,000	$	78.51	$	—	$	—
2023 Collars
July – Dec	NYMEX	9,000	$	—	$	68.33	$	100.69
2024 Fixed-Price Swaps
Jan – June	NYMEX	5,000	$	75.34	$	—	$	—
July – Dec	NYMEX	1,000	75.12		—		—

Note 8. Fair Value Measurements

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

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Notes to Unaudited Condensed Consolidated Financial Statements

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

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


	Fair Value Measurements Using:
In thousands	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
June 30, 2023
Assets
Oil derivative contracts – current	$	—	$	36,809	$	—	$	36,809
Oil derivative contracts – long-term	—		1,269		—		1,269
Total Assets	$	—	$	38,078	$	—	$	38,078






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 June 30, 2023 and December 31, 2022 was $85.0 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 9. Commitments and Contingencies

Litigation and Regulatory Proceedings

We are involved in various lawsuits, claims and regulatory proceedings incidental to our businesses. We are also subject to audits for various taxes (income, sales and use, and severance) in the various states in which we operate, and from time to time receive assessments for potential taxes that we may owe. While we currently believe that the ultimate outcome of these proceedings, individually and in the aggregate, will not have a material adverse effect on our financial position, results of operations or cash flows, litigation 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.

Proposed Merger of the Company with Exxon Mobil Corporation. On July 13, 2023, we entered into a definitive merger agreement (“Merger Agreement”) with Exxon Mobil Corporation (“ExxonMobil”), providing for Denbury to merge with a wholly owned subsidiary of ExxonMobil (the “Merger”) and survive as a wholly owned subsidiary of ExxonMobil.  Under the terms of the Merger Agreement, each issued and outstanding share of our common stock (other than certain excluded shares held by us as treasury stock or owned by ExxonMobil or its merger subsidiary), par value $0.001 per share, will be converted into the right to receive 0.84 shares of ExxonMobil common stock, without par value.  Completion of the Merger remains subject to certain conditions, including the approval of the Merger Agreement by our stockholders, as well as certain governmental and regulatory approvals.  The Merger is currently expected to close in the fourth quarter of 2023; however, no assurance can be given as to when, or if, the Merger will occur.

The foregoing summary of the Merger Agreement and the transactions contemplated thereby does not purport to be complete and is qualified in its entirety by reference to the terms and conditions of the Merger Agreement, a copy of which is attached as Exhibit 2.1 to the Company’s Current Report on Form 8-K, filed with the Securities and Exchange Commission (“SEC”) on July 14, 2023, as amended by the Form 8-K/A, filed with the SEC on July 31, 2023.

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 six months ended June 30, 2023, approximately 41% of the CO2 utilized in our operated oil and gas operations was industrial-sourced CO2, compared to 39% of the CO2 utilized during the six months ended June 30, 2022. Our industrial-sourced CO2 usage in the first half of 2023 equates to an annualized average CO2 usage rate of over 4.5 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 $74 per Bbl during the second quarter of 2023, a slight decrease from $76 per Bbl in the first quarter of 2023, and a decrease from $109 per Bbl during the second 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	June 30, 2023		March 31, 2023		Dec. 31, 2022		Sept. 30, 2022		June 30, 2022
Oil, natural gas, and related product sales	$	302,946	$	314,489	$	346,578	$	395,223	$	451,970
Receipt (payment) on settlements of commodity derivatives	5,157		2,065		(38,956)		(55,780)		(127,959)
Oil, natural gas, and related product sales and commodity derivative settlements, combined	$	308,103	$	316,554	$	307,622	$	339,443	$	324,011

Average daily sales (BOE/d)	46,982		47,655		46,641		47,109		46,561

Average net realized oil prices
Oil price per Bbl - excluding impact of derivative settlements	$	72.59	$	74.87	$	82.54	$	92.77	$	108.81
Oil price per Bbl - including impact of derivative settlements	73.83		75.36		73.13		79.49		77.63

Average NYMEX oil differential per Bbl	(1.14)		$	(1.28)	$	0.03	$	0.82	$	0.09

As shown in the table above, our oil and natural gas revenues have decreased since 2022 primarily due to the decrease in oil prices. 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.

Second Quarter 2023 Financial Results and Highlights. We recognized net income of $67.3 million, or $1.25 per diluted common share, during the second quarter of 2023, compared to a net income of $155.5 million, or $2.83 per diluted common share, during the second quarter of 2022. Drivers of the comparative operating results between the second quarter of 2023 and 2022 include the following:

•Oil and natural gas revenues decreased by $149.0 million (33%) during the second quarter of 2023 due to lower oil prices;

•Commodity derivatives expense decreased by $76.5 million consisting of a $133.1 million decrease in cash payments upon derivative contract settlements ($5.2 million in cash receipts during the second quarter of 2023 compared to $127.9 million in payments during the second quarter of 2022), partially offset by a $56.6 million decrease in noncash fair value changes between periods ($14.5 million gain during the second quarter of 2023 compared to a $71.1 million gain during the second quarter of 2022);

•Depletion, depreciation and amortization increased by $14.4 million (41%) during the second quarter of 2023 due to higher depletable costs, most significantly attributable to capital spending and the transfer of unevaluated costs to the full cost pool associated with the recognition of proved reserves; and

•Taxes other than income decreased by $9.4 million (26%) during the second quarter of 2023 due to a decrease in oil production tax expense corresponding to the decline in oil revenues.

June 2023 West Yellow Creek Divestiture. On June 30, 2023, we closed on a transaction exchanging our 49% non-operated interest in West Yellow Creek Field for a term overriding royalty interest in the field (7% for the first 8 years and 3.4% for the next 5 years). Our existing CO2 sales contract to supply CO2 to the field was also amended as part of the transaction, so that we will continue to supply CO2 to the West Yellow Creek Field for a fee. As a result of this transaction, we anticipate that our future production will decrease by approximately 400 Bbls/d with a corresponding reduction in revenues, and

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we will no longer be obligated for lease operating expenses or capital expenditures for this field. Our lease operating costs at West Yellow Creek Field were approximately $2.6 million for the three months ended June 30, 2023.

Cedar Creek Anticline CO2 EOR Development. During the six months ended June, 30, 2023, we incurred 44% of our total oil & gas development capital expenditures, or $88.7 million, on 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, and commissioning of the second facility was completed during the second quarter of 2023, with the remaining two recycle facilities currently expected to be completed during the second half of 2023. Initial EOR production commenced during the second quarter of 2023, averaging 574 Bbls/d for the full quarter, and we continue to anticipate incremental EOR production to increase throughout the remainder of 2023.

Carbon Capture, Utilization and Storage Activities. During the six months ended June 30, 2023, we invested $48.1 million of development capital into CCUS assets, primarily for the acquisition of new sequestration sites, the drilling of a stratigraphic test well in our Alabama sequestration site, and the acquisition of seismic data. In the first quarter of 2023, we obtained the rights to develop a new sequestration site in Wyoming, located adjacent to our Greencore CO2 pipeline, with estimated CO2 storage potential of up to 40 million metric tons. In the second quarter of 2023, we obtained the rights to another sequestration site in Wyoming with estimated CO2 storage potential of up to another 40 million metric tons, for a total of up to 80 million metric tons in Wyoming adjacent to the Greencore CO2 pipeline. Additionally, 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. We also acquired the right to develop an 8,500-acre dedicated CO2 sequestration site in St. Helena Parish, Louisiana, with estimated CO2 storage potential of at least 100 million metric tons. In total, we have agreements securing the rights to eleven future storage sites which we believe have the potential to store more than 2 billion metric tons of CO2.

On the transportation and storage side of our CCUS business, in the first quarter of 2023, we executed two 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. During the second quarter of 2023, we executed an agreement with SunGas Renewables Inc. (“SunGas”) to provide CO2 transportation and storage services associated with SunGas’ low carbon methanol facility to be constructed in Pineville, Louisiana. SunGas’ project is planned to commence operation in 2027 with an estimated one million metric tons per year of associated CO2 emissions. To date, we have signed agreements covering the potential future transportation and storage of up to 23 Mmtpa from the planned capture of CO2 emissions from existing and proposed industrial plants.

In addition to the CCUS development activities discussed above, during the six months ended June 30, 2023, we made several investments in carbon capture technology companies. During first quarter, we invested $2 million in Aqualung Carbon Capture AS and $5 million in ION Clean Energy, Inc. During the second quarter, we invested $1.5 million in Libra CO2 Storage Solutions, LLC in connection with a joint venture related to a CO2 sequestration project at a 14,000-acre site in St. Charles Parish, Louisiana, with estimated CO2 storage potential of at least 200 million metric tons. Also, in the second quarter of 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 June 30, 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 six months ended June 30, 2023, we generated $231.0 million in cash flow from operations, or $268.1 million before working capital changes, as the first half of 2023 included $37.1 million in cash outflows for working capital items primarily related to annual ad valorem tax and bonus payments. We invested cash of $293.7 million, primarily in oil and gas and CCUS activities, including equity investments during the first half of 2023 and financing activities supplemented our cash flow by $63.7 million, primarily from borrowings under our bank credit facility. As of June 30, 2023, we had $85.0 million of outstanding borrowings, up from $68.0 million at March 31, 2023, and $10.1 million of outstanding

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letters of credit under our $750 million senior secured bank credit facility, leaving us with $654.9 million of borrowing base availability. This liquidity is more than adequate to meet our currently planned operating and capital needs.

2023 Capital Expenditure Plans. Consistent with our original 2023 budget, we continue to estimate that our oil and natural gas development capital expenditures, 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 $21 million for CCUS equity investments and approximately $36 million for plugging and abandonment costs. During the first half of 2023, we incurred $203.2 million of oil and natural gas development capital expenditures and $48.1 million of CCUS capital expenditures, or approximately 56% and 32% of our total annual budgets, respectively. During the first half of 2023, we also incurred $19.8 million of plugging and abandonment costs or approximately 55% of our 2023 expected costs.

Based on current projections, including estimated production costs, oil price differentials and other assumptions, we continue to anticipate that our 2023 cash flows from operations, excluding working capital changes, will approximate our budgeted capital expenditures and planned asset retirement obligation activities for the year, assuming oil prices of approximately $75 per Bbl in 2023. We have more than adequate availability under our bank credit facility to cover any shortfall in operating cash flow relative to our 2023 capital expenditure plans, investments, and other working capital needs. In the fourth quarter of 2023, we estimate a $65 million cash payment for withholding taxes for shares anticipated to be surrendered to the Company for post-emergence equity awards granted in December 2020 and scheduled to be delivered to the recipients in December 2023.

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


	Six Months Ended
	June 30,
In thousands	2023		2022
Capital expenditure summary(1)
CCA EOR field expenditures(2)	$	87,775	$	39,205
CCA CO2 pipelines	965		1,241
CCA tertiary development	88,740		40,446
Non-CCA tertiary and non-tertiary fields	92,988		86,437
CO2 sources, other CO2 pipelines and other	3,306		2,110

Capitalized internal costs(3)	18,152		14,903
Oil and gas development capital expenditures	203,186		143,896
CCUS storage sites and related capital expenditures	48,078		23,900
Oil and gas and CCUS development capital expenditures	251,264		167,796
Capitalized interest	3,952		2,133
Acquisitions of oil and natural gas properties	42		374

Equity investments(4)	19,034		—
Total capital expenditures	$	274,292	$	170,303

(1)Capital expenditures in this summary are presented on an as-incurred basis (including accruals) and are $10.4 million and $9.3 million lower than the capital expenditures in the Unaudited Condensed Consolidated Statements of Cash Flows for the six months ended June 30, 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 $9.3 million during the first half of 2023 and $10.8 million during the first half of 2022.

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

(4)Represents investments made in carbon capture technology companies during the six months ended June 30, 2023, including a $2 million investment in Aqualung Carbon Capture AS, a $5 million investment in ION Clean Energy, Inc, a $1.5 million equity investment in Libra CO2 Storage Solutions, LLC, as well as an additional $10 million equity investment in Clean Hydrogen Works. The investments are included in “Other assets” in the Unaudited Condensed Consolidated Balance Sheet as of June 30, 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 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 June 30, 2023, our ratio of consolidated total debt to consolidated EBITDAX was 0.15 to 1.0 (with a maximum permitted ratio of 3.5 to 1.0) and our current ratio was 2.79 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 August 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.

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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 $2.0 million as of June 30, 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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RESULTS OF OPERATIONS

Financial and Operating Results Tables

Certain of our operating results and statistics for the comparative three and six months ended June 30, 2023 and 2022 are included in the following table:


	Three Months Ended				Six Months Ended
	June 30,				June 30
In thousands, except per-share and unit data	2023		2022		2023		2022
Financial results
Net income	$	67,281	$	155,494	$	156,480	$	154,622
Net income per common share – basic	1.30		3.00		3.03		2.99
Net income per common share – diluted	1.25		2.83		2.90		2.81
Net cash provided by operating activities	142,491		149,965		231,013		240,108
Average daily sales volumes
Bbls/d	45,648		45,104		46,016		45,284
Mcf/d	8,004		8,741		7,803		8,747
BOE/d(1)	46,982		46,561		47,317		46,742
Oil and natural gas sales
Oil sales	$	301,543	$	446,592	$	614,115	$	827,834
Natural gas sales	1,403		5,378		3,320		9,047
Total oil and natural gas sales	$	302,946	$	451,970	$	617,435	$	836,881
Commodity derivative contracts(2)
Receipt (payment) on settlements of commodity derivatives	$	5,157	$	(127,959)	$	7,222	$	(221,016)
Noncash fair value gains (losses) on commodity derivatives	14,520		71,105		35,578		(28,557)
Commodity derivatives income (expense)	$	19,677	$	(56,854)	$	42,800	$	(249,573)
Unit prices – excluding impact of derivative settlements
Oil price per Bbl	$	72.59	$	108.81	$	73.73	$	101.00
Natural gas price per Mcf	1.93		6.76		2.35		5.71
Unit prices – including impact of derivative settlements(2)
Oil price per Bbl	$	73.83	$	77.63	$	74.60	$	74.03
Natural gas price per Mcf	1.93		6.76		2.35		5.71
Oil and natural gas operating expenses
Lease operating expenses	$	130,291	$	124,351	$	259,465	$	242,179
Transportation and marketing expenses	5,159		4,802		10,548		9,447
Production and ad valorem taxes	26,193		35,570		54,456		66,013
Oil and natural gas operating revenues and expenses per BOE
Oil and natural gas revenues	$	70.86	$	106.67	$	72.09	$	98.92
Lease operating expenses	30.48		29.35		30.30		28.63
Transportation and marketing expenses	1.21		1.13		1.23		1.12
Production and ad valorem taxes	6.13		8.40		6.36		7.80
CO2 – revenues and expenses
CO2 sales and transportation fees	$	11,164	$	12,610	$	21,850	$	26,032
CO2 operating and discovery expenses	(1,597)		(1,681)		(2,793)		(4,498)
CO2 revenue and expenses, net	$	9,567	$	10,929	$	19,057	$	21,534

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

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

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Sales Volumes

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


	Average Daily Sales Volumes (BOE/d)
	Second Quarter	First Quarter	Fourth Quarter	Third Quarter	Second Quarter	First Quarter
Operating Area	2023	2023	2022	2022	2022	2022
Tertiary oil sales volumes
Gulf Coast region
Delhi	2,151	2,514	2,528	2,557	2,478	2,675
Hastings	4,502	4,450	4,198	4,211	4,304	4,430
Heidelberg	3,481	3,539	3,670	3,571	3,528	3,653
Oyster Bayou	3,615	3,832	3,417	3,490	3,423	3,745
Tinsley	2,686	3,205	2,248	3,133	3,050	3,015
Other(1)	5,606	5,585	5,652	5,541	5,422	5,498
Total Gulf Coast region	22,041	23,125	21,713	22,503	22,205	23,016
Rocky Mountain region
Bell Creek	3,300	3,808	3,767	3,975	4,122	4,474
Wind River Basin	3,866	3,872	3,726	3,121	2,703	2,517
Cedar Creek Anticline	574	—	—	—	—	—
Other(2)	2,501	2,744	2,824	2,759	2,361	2,229
Total Rocky Mountain region	10,241	10,424	10,317	9,855	9,186	9,220
Total tertiary oil sales volumes	32,282	33,549	32,030	32,358	31,391	32,236
Non-tertiary oil and gas sales volumes
Gulf Coast region
Total Gulf Coast region	3,506	3,398	3,666	3,727	3,566	3,630
Rocky Mountain region
Cedar Creek Anticline	9,661	9,316	9,366	9,593	10,224	9,721
Other(3)	1,533	1,392	1,579	1,431	1,380	1,338
Total Rocky Mountain region	11,194	10,708	10,945	11,024	11,604	11,059
Total non-tertiary sales volumes	14,700	14,106	14,611	14,751	15,170	14,689



Total sales volumes	46,982	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 second quarter of 2023 averaged 46,982 BOE/d, down approximately 1% from the first quarter of 2023. Compared to the first quarter of 2023, the decrease in sales volumes was primarily driven by anticipated declines at Tinsley and Delhi fields, and higher than anticipated downtime at Bell Creek field, offset in part by increases in CCA tertiary volumes in the second quarter due to initial tertiary production commencing during the quarter. The anticipated sales volume decline at Tinsley field was due to first quarter 2023 sales volumes including higher than normal inventory sale volumes due to inventory built in the fourth quarter of 2022, and the decline at Delhi field was due to scheduled facility downtime. Second quarter 2023 sales volumes increased slightly compared to sales levels in the second quarter of 2022, due to additional development at the Wind River Basin and initial tertiary production at CCA, partially offset by the reduction in non-tertiary production at CCA primarily due to curtailed production stemming from CO2 development activities, and downtime and natural decline at Bell Creek Field.

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Our sales volumes during the three and six months ended June 30, 2023 were 97% oil, consistent with our sales during the comparable prior-year periods.

Oil and Natural Gas Revenues

Our oil and natural gas revenues during the three and six months ended June 30, 2023 decreased 33% and 26%, respectively, compared to these revenues for the same periods 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				Six Months Ended
	June 30,				June 30,
	2023 vs. 2022				2023 vs. 2022
In thousands	Increase (Decrease) in Revenues		Percentage Increase (Decrease) in Revenues		Increase (Decrease) in Revenues		Percentage Increase (Decrease) in Revenues
Change in oil and natural gas revenues due to:
Increase in sales volumes	$	4,083	1	%	$	10,287	1	%
Decrease in realized commodity prices	(153,107)		(34)	%	(229,733)		(27)	%
Total decrease in oil and natural gas revenues	$	(149,024)	(33)	%	$	(219,446)	(26)	%

Excluding any impact of our commodity derivative contracts, our average net realized commodity prices and NYMEX differentials were as follows during the three months ended March 31, 2023 and 2022 and the three and six months ended June 30, 2023 and 2022:


	Three Months Ended									Six Months Ended
	June 30,				March 31,				June 30,
	2023		2022		2023		2022			2023		2022
Average net realized prices
Oil price per Bbl	$	72.59	$	108.81	$	74.87	$	93.17		$	73.73	$	101.00
Natural gas price per Mcf	1.93		6.76		2.80		4.66			2.35		5.71
Price per BOE	70.86		106.67		73.32		91.14			72.09		98.92
Average NYMEX differentials
Gulf Coast region
Oil per Bbl	$	(0.92)	$	0.16	$	(1.29)	$	(1.37)		$	(1.08)	$	(0.72)
Natural gas per Mcf	(0.30)		0.02		(0.05)		0.16			(0.15)		0.01
Rocky Mountain region
Oil per Bbl	$	(1.41)	$	0.01	$	(1.28)	$	(1.38)		$	(1.35)	$	(0.59)
Natural gas per Mcf	(0.42)		(1.12)		0.04		0.08			(0.22)		(0.49)
Total Company
Oil per Bbl	$	(1.14)	$	0.09	$	(1.28)	$	(1.37)		$	(1.20)	$	(0.67)
Natural gas per Mcf	(0.39)		(0.71)		0.01		0.11			(0.20)		(0.31)

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.

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

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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 $11.2 million and $21.9 million during the three and six months ended June 30, 2023, respectively, compared to $12.6 million and $26.0 million during the three and six months ended June 30, 2022, respectively. The decrease in CO2 sales and transportation fees from the prior-year periods is primarily due to a short-term contract in place in 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 and six months ended June 30, 2023 and 2022:


	Three Months Ended				Six Months Ended
	June 30,				June 30,
In thousands	2023		2022		2023		2022
Receipt (payment) on settlements of commodity derivatives	$	5,157	$	(127,959)	$	7,222	$	(221,016)
Noncash fair value gains (losses) on commodity derivatives	14,520		71,105		35,578		(28,557)
Total income (expense)	$	19,677	$	(56,854)	$	42,800	$	(249,573)

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 half of 2023, we received $7.2 million upon expiration of commodity derivative contracts, compared to cash payments upon settlement of $221.0 million during the first half 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 7, Commodity Derivative Contracts, to the Unaudited Condensed Consolidated Financial Statements for additional details of our outstanding commodity derivative contracts as of June 30, 2023, and Item 3, Quantitative and Qualitative Disclosures about Market Risk below for additional discussion. In addition, the following table summarizes our commodity derivative contracts as of August 1, 2023:


		2H 2023	1H 2024	2H 2024
WTI NYMEX	Volumes Hedged (Bbls/d)	18,000	17,000	2,000
Fixed-Price Swaps	Weighted Average Swap Price	$78.51	$75.02	$75.75
WTI NYMEX	Volumes Hedged (Bbls/d)	9,000	—	—
Collars	Weighted Average Floor / Ceiling Price	$68.33 / $100.69	—	—
	Total Volumes Hedged (Bbls/d)	27,000	17,000	2,000

Based on current contracts in place and NYMEX oil futures prices as of August 1, 2023, which averaged approximately $81 per Bbl for the remainder of 2023, we currently expect that we would make cash payments of approximately $5 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

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

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				Six Months Ended
	June 30,				June 30,
In thousands, except per-BOE data	2023		2022		2023		2022
Total lease operating expenses	$	130,291	124,351		$	259,465	$	242,179

Total lease operating expenses per BOE	$	30.48	$	29.35	$	30.30	$	28.63

Total lease operating expenses increased $5.9 million (5%) and $17.3 million (7%) on an absolute-dollar basis, or $1.13 (4%) and $1.67 (6%) on a per-BOE basis, during the three and six months ended June 30, 2023, respectively, compared to the same prior-year periods. The increase on an absolute-dollar and per-BOE basis during the three months ended June 30, 2023 was primarily due to the absence in the 2023 period of a $6.7 million insurance reimbursement received during the three months ended June 30, 2022 related to property damage costs incurred during 2013 at Delhi Field. Also, lower power and fuel costs benefited the second quarter of 2023 when compared to the same 2022 period, partially offset by higher labor and repair and maintenance costs due to inflation and higher activity levels. In addition to the fluctuations noted above, the comparative increase during the six months ended June 30, 2023 and 2022 include first quarter 2023 comparative increases in labor and repair and maintenance costs as well as higher workover and CO2 costs. The increase to CO2 costs is largely the result of an industrial contract change.

Compared to the first quarter of 2023, lease operating expenses in the most recent quarter increased $1.1 million (1%) on an absolute-dollar basis and $0.36 (1%) on a per-BOE basis, due primarily to higher labor and other 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 $5.2 million and $4.8 million for the three months ended June 30, 2023 and 2022, respectively, and $10.5 million and $9.4 million for the six months ended June 30, 2023 and 2022, respectively. The increases were 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 $9.4 million (26%) and $11.7 million (17%) during the three and six months ended June 30, 2023, respectively, compared to the same prior-year periods, 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				Six Months Ended
	June 30,				June 30,
In thousands, except per-BOE data and employees	2023		2022		2023		2022
Cash G&A costs	$	20,347	$	15,131	$	38,386	$	30,852
Stock-based compensation	6,548		4,104		11,486		7,075
G&A expense	$	26,895	$	19,235	$	49,872	$	37,927

G&A per BOE
Cash G&A costs	$	4.76	$	3.57	$	4.48	$	3.65
Stock-based compensation	1.53		0.97		1.34		0.83
G&A expenses	$	6.29	$	4.54	$	5.82	$	4.48

Employees as of period end	793		740

Our G&A expense on an absolute-dollar basis was $26.9 million during the three months ended June 30, 2023, an increase of $7.7 million from the same prior-year period, primarily due to higher employee-related costs, including salaries and stock compensation expense. During the six months ended June 30, 2023, G&A expense on an absolute-dollar basis was $49.9 million, an increase of $11.9 million when compared to the same prior-year period, also primarily due to higher employee-related costs, including salaries and stock compensation expense.

Interest and Financing Expenses


	Three Months Ended						Six Months Ended
	June 30,						June 30,
In thousands, except per-BOE data and interest rates	2023			2022			2023			2022
Cash interest(1)	$	2,553		$	1,252		$	4,641		$	2,382

Noncash interest expense	531			1,249			1,063			1,934

Less: capitalized interest	(2,259)			(975)			(3,952)			(2,133)
Interest expense, net	$	825		$	1,526		$	1,752		$	2,183
Interest expense, net per BOE	$	0.19		$	0.36		$	0.20		$	0.26
Average debt principal outstanding	$	89,291		$	29,088		$	75,893		$	31,669
Average cash interest rate(2)	7.8		%	6.0		%	7.8		%	5.7		%

(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.

Cash interest during the three and six months ended June 30, 2023 increased $1.3 million (104%) and $2.3 million (95%) when compared to the same prior-year periods. The increases between periods were primarily due to an increase in the average principal outstanding on our senior secured bank credit facility. The decrease in noncash interest expense during the three and six months ended June 30, 2023, compared to the same prior-year periods, was due to a write-off of debt issuance costs related to lenders who exited our senior secured bank credit facility in conjunction with our May 2022 amendment.

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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				Six Months Ended
	June 30,				June 30,
In thousands, except per-BOE data	2023		2022		2023		2022
Oil and natural gas properties	$	42,652	$	29,084	$	76,851	$	57,752
CO2 properties, pipelines, plants and other property and equipment	7,073		6,316		13,789		12,993
Accelerated depreciation charge	42		—		1,159		—
Total DD&A	$	49,767	$	35,400	$	91,799	$	70,745

DD&A per BOE
Oil and natural gas properties	$	9.98	$	6.86	$	8.97	$	6.83
CO2 properties, pipelines, plants and other property and equipment	1.65		1.49		1.61		1.53
Accelerated depreciation charge	0.01		—		0.14		—
Total DD&A cost per BOE	$	11.64	$	8.35	$	10.72	$	8.36

DD&A expense increased $14.4 million between the three months ended June 30, 2023 and 2022, and $21.1 million between the six months ended June 30, 2023 and 2022 due to higher depletable costs, most significantly attributable to capital spending and the transfer of unevaluated costs to the full cost pool associated with the recognition of initial proved reserves associated with our new CCA CO2 Phase I development.

During the second quarter of 2023, we added 6.4 MMBOE of new proved reserves related to our new CCA CO2 Phase I development. Concurrent with the addition of new reserves, all unevaluated costs for that development were transferred to proved properties, and those costs aggregated with associated estimated future development costs were added to our full cost pool for purposes of calculating depletion. Although the oil reserves added for Phase I of CCA during the second quarter represent only a portion of the potential oil reserves that we believe are recoverable, our depletion calculation includes a significant portion of the expected costs for Phase I CCA future anticipated barrels, resulting in virtually all of the increase to our oil and gas DD&A rate on a sequential quarter basis. Our DD&A expense and DD&A rate per BOE could fluctuate significantly in the future with the recognition of additional proved reserves.

Other Expenses

Other expenses during the three and six months ended June 30, 2023 totaled $4.0 million and $5.5 million, respectively, compared to $6.6 million and $8.7 million, respectively, during the three and six months ended June 30, 2022. Other expenses during the six months ended June 30, 2023 primarily includes $3.0 million in CCUS-related expenses (including $0.5 million of expense related to the Gulf Coast Midstream Partners sequestration site which we no longer intend to pursue), $1.8 million in plant operating expenses and $1.1 million in Merger-related expenses. Other expenses during the six months ended June 30, 2022 included $4.3 million in Delta Pipeline incident costs, $1.9 million in plant operating expenses, and $1.0 million in legal settlements. We expect other expenses will be higher during the second half of 2023, primarily related to Merger-related expenses such as legal and advisory fees.

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

Income Taxes


	Three Months Ended						Six Months Ended
	June 30,						June 30,
In thousands, except per-BOE amounts and tax rates	2023			2022			2023			2022
Current income tax expense	$	857		$	2,912		$	3,195		$	2,351
Deferred income tax expense	21,139			21,936			47,051			15,992
Total income tax expense	$	21,996		$	24,848		$	50,246		$	18,343
Average income tax expense per BOE	$	5.14		$	5.87		$	5.86		$	2.17
Effective tax rate	24.6		%	13.8		%	24.3		%	10.6		%
Total net deferred tax liability	$	118,171		$	17,630

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 June 30, 2023 was in line with our estimated statutory rate and our effective tax rate for the six months ended June 30, 2023 was slightly lower than our estimated statutory rate primarily due to excess stock compensation deductions that were recorded discretely in the first quarter. Our effective tax rate for the three and six months ended June 30, 2022 was lower than our estimated statutory rate due to the release of a portion of the valuation allowance on our deferred tax assets. Our annualized effective tax rate for the year ended December 31, 2023 is currently estimated to be approximately 24.5%.

During the six months ended June 30, 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.

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

Per-BOE Data

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


	Three Months Ended				Six Months Ended
	June 30,				June 30,
Per-BOE data	2023		2022		2023		2022
Oil and natural gas revenues	$	70.86	$	106.67	$	72.09	$	98.92
Receipt (payment) on settlements of commodity derivatives	1.21		(30.20)		0.85		(26.13)
Lease operating expenses	(30.48)		(29.35)		(30.30)		(28.63)
Production and ad valorem taxes	(6.13)		(8.40)		(6.36)		(7.80)
Transportation and marketing expenses	(1.21)		(1.13)		(1.23)		(1.12)
Production netback	34.25		37.59		35.05		35.24
CO2 sales, net of operating and discovery expenses	2.24		2.58		2.22		2.55
General and administrative expenses	(6.29)		(4.54)		(5.82)		(4.48)
Interest expense, net	(0.19)		(0.36)		(0.20)		(0.26)
Stock compensation and other	0.05		(1.01)		0.05		(0.45)
Changes in assets and liabilities relating to operations	3.27		1.13		(4.33)		(4.22)
Cash flows from operations	33.33		35.39		26.97		28.38
DD&A	(11.63)		(8.35)		(10.58)		(8.36)
DD&A – accelerated depreciation charge	(0.01)		—		(0.14)		—

Deferred income taxes	(4.94)		(5.18)		(5.49)		(1.89)

Noncash fair value gains (losses) on commodity derivatives	3.39		16.78		4.15		(3.37)
Other noncash items	(4.40)		(1.94)		3.36		3.52
Net income (loss)	$	15.74	$	36.70	$	18.27	$	18.28

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, predictions, economics and timing 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 available from third-party emitters for transportation and storage through our CCUS platform and the dates that new or add-on facilities will become

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operational, 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 or the volumes thereof; 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, long-term CO2 storage sites or industrial facilities or processes that emit CO2; 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 global economic uncertainties or geopolitical events such as the war in Ukraine and future levels of oil demand in China; widespread inflation in economies across the world; future decisions or actions as to production levels and/or pricing by OPEC; any adverse changes to business relationships due to our pending merger with ExxonMobil; as to our CCUS activities, the successful completion of technical and feasibility evaluations of future sequestration sites and third-party emission facilities or processes, the availability of funds to us and third parties sufficient to build and operate add-on or new infrastructure and facilities, and the assessment by third parties of the economic feasibility of constructing such facilities, the pace of finalization of CCUS arrangements with third parties, the receipt of required regulatory approval or classifications, and the timing and coordination necessary to bring together numerous industry and governmental entities in order to create a CCUS industry at scale; 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 June 30, 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 7, Commodity Derivative Contracts, and Note 8, 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 June 30, 2023, our commodity derivative contracts were recorded at their fair value, which was a net asset of $38.1 million, a $14.5 million change from the $23.6 million net asset recorded at March 31, 2023, and a $35.6 million change from the $2.5 million net asset recorded at December 31, 2022. The changes are primarily related to the expiration of commodity derivative contracts during the three and six months ended June 30, 2023, new commodity derivative contracts entered during 2023 for future periods, and to the changes in oil futures prices between December 31, 2022 and June 30, 2023.

Commodity Derivative Sensitivity Analysis

Based on NYMEX crude oil futures prices and derivative contracts in place as of June 30, 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 June 30, 2023	$	35,061
10% increase in prices	2,845
10% decrease in prices	72,283

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 June 30, 2023, we had $85.0 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 June 30, 2023:


In thousands	2023 - 2026		2027		Total		Fair Value
Variable rate debt:
Senior Secured Bank Credit Facility (weighted average interest rate of 7.77% at June 30, 2023)	$	—	$	85,000	$	85,000	$	85,000

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 June 30, 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 second 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. Except as disclosed below, 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. The following risk factors relate to the proposed Merger with ExxonMobil:

Because the Exchange Ratio is fixed and the market price of ExxonMobil common stock has fluctuated and will continue to fluctuate, Denbury stockholders cannot be sure of the value of the consideration they will receive in the Merger, if completed.

If the Merger is completed, each share of Denbury common stock outstanding immediately prior to the Merger (except for the excluded shares) will automatically be converted into the right to receive 0.840 shares of ExxonMobil common stock, with cash to be paid in lieu of fractional shares. Because the Exchange Ratio is fixed, the value of the Merger consideration will depend on the market price of ExxonMobil common stock at the time the Merger is completed. Prior to completion of the Merger, the market price of ExxonMobil common stock is also expected to impact the market price of Denbury common stock. The value of ExxonMobil common stock has fluctuated since the date of the announcement of the Merger Agreement and will continue to fluctuate. Accordingly, Denbury stockholders will not know or be able to determine the market value of the Merger consideration they would receive upon completion of the Merger. Stock price changes may result from a variety of factors, including, among others, general market and economic conditions, changes in ExxonMobil’s and Denbury’s respective businesses, operations and prospects, market assessments of the likelihood that the Merger will be completed, the timing of the Merger, regulatory considerations and COVID-19. Many of these factors are beyond ExxonMobil’s and Denbury’s control.

Denbury may have difficulty attracting, motivating and retaining employees in light of the Merger.

Uncertainty about the effect of the Merger on Denbury employees may impair Denbury’s ability to attract, retain and motivate personnel prior to and following the Merger. Employee retention may be particularly challenging during the pendency of the Merger, as employees of Denbury may experience uncertainty about their future roles with the combined business.

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Denbury Inc.

Completion of the Merger is subject to certain conditions and if these conditions are not satisfied or waived, the Merger will not be completed.

The obligation of each of ExxonMobil, Denbury and EMPF Corporation, ExxonMobil’s wholly owned merger subsidiary (“Merger Sub”) to complete the Merger is subject to the satisfaction (or, to the extent permitted by applicable law, waiver) of a number of conditions, including, among others: (i) the affirmative vote of the holders of a majority of the shares of Denbury common stock outstanding and entitled to vote at the date of the special meeting of Denbury stockholders approving and adopting the Merger Agreement (which condition described in this clause (i) may not be waived), (ii) the expiration or termination of any applicable waiting period, or any extension thereof, under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 (the “HSR Act”) (in the case of ExxonMobil and Merger Sub’s obligation to complete the Merger, without the imposition of a Burdensome Condition, as defined in the Merger Agreement), (iii) absence of any injunction or other order or applicable law preventing or making illegal the consummation of the Merger (in the case of ExxonMobil and Merger Sub’s obligation to complete the Merger, without the imposition of a Burdensome Condition to the extent such law or prohibition relates to the matters in clause (i) above), (iv) the future registration statement being declared effective and no stop order suspending the effectiveness of the registration statement being in effect and no proceedings for such purpose pending or threatened by the SEC, (v) approval for the listing on the New York Stock Exchange of the shares of ExxonMobil common stock to be issued in the Merger, subject to official notice of issuance, (vi) accuracy of the representations and warranties made in the Merger Agreement by, in the case of ExxonMobil and Merger Sub’s obligations to complete the Merger, Denbury and, in the case of Denbury’s obligation to complete the Merger, ExxonMobil and Merger Sub, in each case, as of the date of the Merger Agreement and as of the date of completion of the Merger, subject to certain materiality thresholds, (vi) performance in all material respects by, in the case of ExxonMobil and Merger Sub’s obligations to complete the Merger, Denbury and, in the case of Denbury’s obligation to complete the Merger, ExxonMobil and Merger Sub, of the obligations required to be performed by it at or prior to the effective time of the Merger, (vii) the absence since the date of the Merger Agreement of a material adverse effect on, in the case of ExxonMobil and Merger Sub’s obligations to complete the Merger, Denbury and (viii) the absence since the date of the Merger Agreement of a material adverse effect on, in the case of Denbury’s obligations to complete the Merger, ExxonMobil and Merger Sub.

There can be no assurance that the conditions to the closing of the Merger will be satisfied or waived or that the Merger will be completed.

Denbury’s business relationships may be subject to disruption due to uncertainty associated with the Merger.

Parties with which Denbury does business may experience uncertainty associated with the Merger, including with respect to current or future business relationships with ExxonMobil, Denbury or the combined business. Denbury’s business relationships may be subject to disruption as parties with which ExxonMobil or Denbury does business may attempt to negotiate changes in existing business relationships or consider entering into business relationships with parties other than ExxonMobil, Denbury or the combined business. These disruptions could have an adverse effect on the businesses, financial condition, results of operations or prospects of the combined business, including an adverse effect on ExxonMobil’s ability to realize the anticipated benefits of the Merger. The risk, and adverse effect, of such disruptions could be exacerbated by a delay in completion of the Merger or termination of the Merger Agreement.

Completion of the Merger may trigger change in control or other provisions in certain agreements to which Denbury is a party.

Denbury is a party to certain agreements that give the counterparty certain rights following a “change in control,” including in some cases the right to terminate such agreements. Under some such agreements, the Merger may constitute a change in control and therefore the counterparty may exercise certain rights under the agreement upon the closing of the Merger. Any such counterparty may request modifications of its respective agreements as a condition to granting a waiver or consent under its agreement. There is no assurance that such counterparties will not exercise their rights under the agreements, including termination rights where available and/or requiring payment of substantial financial penalties.

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The Merger Agreement limits Denbury’s ability to pursue alternatives to the Merger and may discourage other companies from trying to acquire Denbury for greater consideration than what ExxonMobil has agreed to pay pursuant to the Merger Agreement.

The Merger Agreement contains provisions that make it more difficult for Denbury to sell its business to a party other than ExxonMobil. These provisions include a general prohibition on Denbury soliciting any acquisition proposal or offer for a competing transaction. Further, subject to certain exceptions, the Denbury board of directors will not withdraw or modify in a manner adverse to ExxonMobil the recommendation of the Denbury board of directors in favor of the approval and adoption of the Merger Agreement, and ExxonMobil generally has a right to match any competing acquisition proposals that may be made. Notwithstanding the foregoing, at any time prior to the approval and adoption of the Merger Agreement by Denbury stockholders, the Denbury board of directors is permitted to withdraw or modify in a manner adverse to ExxonMobil the recommendation of the Denbury board of directors in favor of the approval and adoption of the Merger Agreement in certain circumstances if it determines in good faith that the failure to take such action would be reasonably likely to be inconsistent with its fiduciary duties to Denbury stockholders under applicable law. The Merger Agreement does not require that Denbury submit the approval and adoption of the Merger Agreement to a vote of Denbury stockholders if the Denbury board of directors changes its recommendation in favor of the approval and adoption of the Merger Agreement in a manner adverse to ExxonMobil and terminates the Merger Agreement in order to enter into an alternative acquisition agreement with respect to a competing transaction in accordance with the terms of the Merger Agreement. In certain circumstances, upon termination of the Merger Agreement, Denbury will be required to pay a termination fee of $144 million to ExxonMobil, including if Denbury terminates the Merger Agreement prior to obtaining Denbury stockholder approval in order to enter into an alternative acquisition agreement with respect to a competing transaction in accordance with the terms of the Merger Agreement.

While both Denbury and ExxonMobil believe these provisions and agreements are reasonable and customary and are not preclusive of other offers, the restrictions, including the added expense of the $144 million termination fee that may become payable by Denbury to ExxonMobil in certain circumstances, might discourage a third party that has an interest in acquiring all or a significant part of Denbury from considering or proposing that acquisition, even if that party were prepared to pay consideration with a higher per-share value than the consideration payable in the Merger pursuant to the Merger Agreement.

Failure to complete the Merger could negatively impact the stock price and the future business and financial results of Denbury.

If the Merger is not completed for any reason, including as a result of Denbury stockholders failing to approve the Merger or any other condition not being satisfied or waived, the ongoing businesses of Denbury may be adversely affected, and without realizing any of the benefits of having completed the Merger, Denbury would be subject to a number of risks, including the following:

•Denbury may experience negative reactions from the financial markets, including negative impacts on its stock price;

•Denbury may experience negative reactions from its clients, regulators and employees;

•Denbury will be required to pay certain costs relating to the Merger, whether or not the Merger is completed;

•the Merger Agreement places certain restrictions on the conduct of Denbury’s businesses prior to completion of the Merger, and such restrictions, the waiver of which are subject to the written consent of ExxonMobil (in certain cases, not to be unreasonably withheld, conditioned or delayed), and subject to certain exceptions and qualifications, may prevent Denbury from taking certain other specified actions or otherwise pursuing business opportunities during the pendency of the Merger that Denbury would have made, taken or pursued if these restrictions were not in place; and

•matters relating to the Merger (including integration planning) will require substantial commitments of time and resources by Denbury management, which would otherwise have been devoted to day-to-day operations and other opportunities that may have been beneficial to Denbury as an independent company. In the event of a termination of the Merger Agreement under certain circumstances specified in the Merger Agreement, Denbury may be required to pay a termination fee of $144 million to ExxonMobil. To the extent that a termination fee is not promptly paid by Denbury when due, Denbury will be required to pay ExxonMobil interest on such fee at the annual rate equal to the prime rate, as published in The Wall Street Journal in effect on the date such payment was required to be made, through the date such payment was actually received, or such lesser rate as is the maximum permitted by applicable law.

There can be no assurance that the risks described above will not materialize. If any of those risks materialize, they may materially and adversely affect Denbury’s businesses, financial condition, financial results, ratings and/or stock price.

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Denbury Inc.

In addition, Denbury could be subject to litigation related to any failure to complete the Merger or related to any enforcement proceeding commenced against Denbury to perform its obligations under the Merger Agreement. If the Merger is not completed, these risks may materialize and may adversely affect Denbury’s businesses, financial condition, financial results, ratings, stock prices and/or bond prices.

Potential litigation against Denbury could result in substantial costs, an injunction preventing the completion of the Merger and/or a judgment resulting in the payment of damages.

Securities class action lawsuits and derivative lawsuits are often brought against public companies that have entered into merger agreements. Even if such a lawsuit is unsuccessful, defending against these claims can result in substantial costs.

Stockholders of Denbury may file lawsuits against ExxonMobil, Denbury and/or the directors and officers of either company in connection with the Merger. These lawsuits could prevent or delay the completion of the Merger and result in significant costs to Denbury, including any costs associated with the indemnification of directors and officers. There can be no assurance that any of the defendants will be successful in the outcome of any potential lawsuits.

Denbury will incur significant transaction and Merger-related costs in connection with the Merger.

Denbury expects to incur a number of non-recurring costs associated with the Merger and combining the operations of the two companies. The significant, non-recurring costs associated with the Merger include, among others, fees and expenses of financial advisors and other advisors and representatives, certain employment-related costs relating to employees of Denbury, filing fees due in connection with filings required under the HSR Act and filing fees and printing and mailing costs for a proxy statement/prospectus. Some of these costs have already been incurred or may be incurred regardless of whether the Merger is completed, including a portion of the fees and expenses of financial advisors and other advisors and representatives and filing fees for a proxy statement/prospectus.

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Denbury Inc.

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

Issuer Purchases of Equity Securities

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


Month	Total Number of Shares Purchased	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
April 2023	—	$	—	—	$	250,000,000
May 2023	—	—		—	$	250,000,000
June 2023	—	—		—	$	250,000,000
Total	—			—

2022 Share Repurchases

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. No share repurchases have been made under this program since that time. In August 2022, the Board increased Denbury’s stock repurchase authorization by $100 million to a total of $250 million for future repurchases under the program. With limited exceptions, the Merger Agreement precludes the Company from any future repurchases or acquisition of shares of its capital stock, including under a repurchase program, without ExxonMobil’s consent.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

None.

Item 5. Other Information

During the three months ended June 30, 2023, no director nor Section 16 officer of the Company adopted or terminated a “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement,” as each term is defined in Item 408(a) of Regulation S-K, pertaining to the common stock of the Company.

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Item 6. Exhibits


Exhibit No.						Exhibit
2.1						Agreement and Plan of Merger, dated as of July 13, 2023, by and among Denbury Inc., Exxon Mobil Corporation and EMPF Corporation (incorporated by reference to Exhibit 2.1 of Form 8-K filed by the Company on July 14, 2023, as amended by the Form 8-K/A filed by the Company on July 31, 2023, File No. 001-12935).
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 June 30, 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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Denbury Inc.

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.

August 3, 2023						/s/ Mark C. Allen
						Mark C. Allen Executive Vice President and Chief Financial Officer

August 3, 2023						/s/ Nicole Jennings
						Nicole Jennings Vice President and Chief Accounting Officer

DENBURY INC 10-Q