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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 March 31, 2023
OR

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

For the transition period from _______ to ________

Commission file number: 001-12935
Logo2.jpg
DENBURY INC.
(Exact name of registrant as specified in its charter)

Delaware 20-0467835
(State or other jurisdiction of incorporation or organization)
 
(I.R.S. Employer Identification No.)
5851 Legacy Circle,
Plano, TX 75024
(Address of principal executive offices) (Zip Code)
Registrant’s telephone number, including area code: (972)673-2000

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

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

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☑  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 filerAccelerated filerNon-accelerated filerSmaller reporting companyEmerging growth company
   

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

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

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

The number of shares outstanding of the registrant’s Common Stock, $.001 par value, as of April 30, 2023, was 50,277,186.





Denbury Inc.

Table of Contents

Page
 
 


2


PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
Denbury Inc.
Unaudited Condensed Consolidated Balance Sheets
(In thousands, except par value and share data)
March 31, 2023December 31, 2022
Assets
Current assets  
Cash and cash equivalents$525 $521 
Accrued production receivable143,484 144,277 
Trade and other receivables, net29,770 27,343 
Derivative assets23,554 15,517 
Prepaids14,803 18,572 
Total current assets212,136 206,230 
Property and equipment  
Oil and natural gas properties (using full cost accounting)  
Proved properties1,474,721 1,414,779 
Unevaluated properties284,584 240,435 
CO2 properties
192,107 190,985 
Pipelines218,822 220,125 
CCUS storage sites and related assets85,059 64,971 
Other property and equipment111,265 107,133 
Less accumulated depletion, depreciation, amortization and impairment(340,312)(306,743)
Net property and equipment2,026,246 1,931,685 
Operating lease right-of-use assets16,768 18,017 
Derivative assets1,617  
Intangible assets, net76,849 79,128 
Restricted cash for future asset retirement obligations47,424 47,359 
Other assets51,023 45,080 
Total assets$2,432,063 $2,327,499 
Liabilities and Stockholders’ Equity
Current liabilities  
Accounts payable and accrued liabilities$215,291 $248,800 
Oil and gas production payable77,507 80,368 
Derivative liabilities1,613 13,018 
Current maturities of long-term debt107  
Operating lease liabilities4,430 4,676 
Total current liabilities298,948 346,862 
Long-term liabilities  
Long-term debt, net of current portion68,276 29,000 
Asset retirement obligations315,169 315,942 
Deferred tax liabilities, net97,031 71,120 
Operating lease liabilities14,407 15,431 
Other liabilities13,649 16,527 
Total long-term liabilities508,532 448,020 
Commitments and contingencies (Note 8)
Stockholders’ equity
Preferred stock, $.001 par value, 50,000,000 shares authorized, none issued and outstanding
  
Common stock, $.001 par value, 250,000,000 shares authorized; 50,276,526 and 49,814,874 shares issued, respectively
50 50 
Paid-in capital in excess of par1,049,830 1,047,063 
Retained earnings574,703 485,504 
Total stockholders equity
1,624,583 1,532,617 
Total liabilities and stockholders’ equity$2,432,063 $2,327,499 
 
See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

3


Denbury Inc.
Unaudited Condensed Consolidated Statements of Operations
(In thousands, except per-share data)
Three Months Ended March 31,
20232022
Revenues and other income 
Oil, natural gas, and related product sales$314,489 $384,911 
CO2 sales and transportation fees
10,686 13,422 
Oil marketing revenues14,548 13,276 
Other income1,295 250 
Total revenues and other income341,018 411,859 
Expenses 
Lease operating expenses129,174 117,828 
Transportation and marketing expenses5,389 4,645 
CO2 operating and discovery expenses
1,196 2,817 
Taxes other than income29,038 31,381 
Oil marketing purchases14,468 13,040 
General and administrative expenses22,977 18,692 
Interest, net of amounts capitalized of $1,693 and $1,158, respectively
927 657 
Depletion, depreciation, and amortization42,032 35,345 
Commodity derivatives expense (income)(23,123)192,719 
Other expenses1,491 2,112 
Total expenses223,569 419,236 
Income (loss) before income taxes117,449 (7,377)
Income tax provision (benefit)28,250 (6,505)
Net income (loss)$89,199 $(872)
Net income (loss) per common share
Basic$1.73 $(0.02)
Diluted$1.66 $(0.02)
Weighted average common shares outstanding 
Basic51,503 51,602 
Diluted53,763 51,602 

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.


4


Denbury Inc.
Unaudited Condensed Consolidated Statements of Cash Flows
(In thousands)
Three Months Ended March 31,
 20232022
Cash flows from operating activities 
Net income (loss)$89,199 $(872)
Adjustments to reconcile net income (loss) to cash flows from operating activities 
Depletion, depreciation, and amortization42,032 35,345 
Deferred income taxes25,912 (5,944)
Stock-based compensation4,938 2,971 
Commodity derivatives expense (income)(23,123)192,719 
Receipt (payment) on settlements of commodity derivatives2,065 (93,057)
Debt issuance costs531 685 
Other, net(1,958)(1,267)
Changes in assets and liabilities, net of effects from acquisitions 
Accrued production receivable793 (72,795)
Trade and other receivables(2,425)1,644 
Other current and long-term assets4,506 189 
Accounts payable and accrued liabilities(42,247)11,410 
Oil and natural gas production payable(2,861)23,348 
Asset retirement obligations and other liabilities(8,840)(4,233)
Net cash provided by operating activities88,522 90,143 
Cash flows from investing activities 
Oil and natural gas capital expenditures(104,782)(58,707)
CCUS storage sites and related capital expenditures(14,645)(14,900)
Acquisitions of oil and natural gas properties(35) 
Pipelines and plants capital expenditures(623)(15,204)
Equity investments(7,108) 
Other(5,879)(1,396)
Net cash used in investing activities(133,072)(90,207)
Cash flows from financing activities 
Bank repayments(319,000)(274,000)
Bank borrowings358,000 274,000 
Other5,619 (3,068)
Net cash provided by (used in) financing activities44,619 (3,068)
Net increase (decrease) in cash, cash equivalents, and restricted cash69 (3,132)
Cash, cash equivalents, and restricted cash at beginning of period47,880 50,344 
Cash, cash equivalents, and restricted cash at end of period$47,949 $47,212 

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

5


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 ParRetained Earnings
SharesAmountTotal Equity
Balance – December 31, 202249,814,874 $50 $1,047,063 $485,504 $1,532,617 
Issued pursuant to stock compensation plans268,748 — — — — 
Stock-based compensation— — 5,320 — 5,320 
Tax withholding and retirement related to stock compensation plans(16,281)— (2,683)— (2,683)
Issued pursuant to exercise of warrants209,185 — 130 — 130 
Net income— — — 89,199 89,199 
Balance – March 31, 202350,276,526 $50 $1,049,830 $574,703 $1,624,583 

Common Stock
($.001 Par Value)
Paid-In Capital in Excess of ParRetained Earnings (Accumulated Deficit)
SharesAmountTotal Equity
Balance – December 31, 202150,193,656 $50 $1,129,996 $5,344 $1,135,390 
Issued pursuant to stock compensation plans141,581 — — — — 
Stock-based compensation— — 3,142 — 3,142 
Tax withholding for stock compensation plans— — (58)— (58)
Issued pursuant to exercise of warrants14,153 — 47 — 47 
Net loss— — — (872)(872)
Balance – March 31, 202250,349,390 $50 $1,133,127 $4,472 $1,137,649 

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

6


Denbury Inc.
Notes to Unaudited Condensed Consolidated Financial Statements

Note 1. Basis of Presentation

Organization and Nature of Operations

Denbury Inc., a Delaware corporation, is an independent energy company with operations focused in the Gulf Coast and Rocky Mountain regions of the United States. The Company is differentiated by its focus on CO2 enhanced oil recovery (“EOR”) and the emerging carbon capture, use, and storage (“CCUS”) industry, supported by the Company’s CO2 EOR technical and operational expertise and its extensive CO2 pipeline infrastructure.

Interim Financial Statements

The accompanying unaudited condensed consolidated financial statements of Denbury Inc. and its subsidiaries have been prepared in accordance with the rules and regulations of the Securities and Exchange Commission (“SEC”) and do not include all of the information and footnotes required by accounting principles generally accepted in the United States for complete financial statements.  These financial statements and the notes thereto should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2022 (the “Form 10-K”).  Unless indicated otherwise or the context requires, the terms “we,” “our,” “us,” “Company” or “Denbury,” refer to Denbury Inc. and its subsidiaries.

Accounting measurements at interim dates inherently involve greater reliance on estimates than at year end, and the results of operations for the interim periods shown in this report are not necessarily indicative of results to be expected for the year.  In management’s opinion, the accompanying unaudited condensed consolidated financial statements include all adjustments of a normal recurring nature necessary for a fair presentation of our consolidated financial position as of March 31, 2023, our consolidated results of operations for the three months ended March 31, 2023 and 2022, our consolidated cash flows for the three months ended March 31, 2023 and 2022, and our consolidated statements of changes in stockholders’ equity for the three months ended March 31, 2023 and 2022.

Reclassifications

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

Cash, Cash Equivalents, and Restricted Cash

We consider all highly liquid investments to be cash equivalents if they have maturities of three months or less at the date of purchase. The following table provides a reconciliation of cash, cash equivalents, and restricted cash as reported within the Unaudited Condensed Consolidated Balance Sheets to “Cash, cash equivalents, and restricted cash at end of period” as reported within the Unaudited Condensed Consolidated Statements of Cash Flows:
In thousandsMarch 31, 2023March 31, 2022
Cash and cash equivalents$525 $517 
Restricted cash for future asset retirement obligations47,424 46,695 
Total cash, cash equivalents, and restricted cash shown in the Unaudited Condensed Consolidated Statements of Cash Flows$47,949 $47,212 

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

Net Income (Loss) per Common Share

Basic net income (loss) per common share is computed by dividing the net income (loss) attributable to common stockholders by the weighted average number of shares of common stock outstanding during the period.  Basic weighted average common shares exclude shares of nonvested restricted stock (although nonvested restricted stock is issued and outstanding upon grant). As these restricted shares vest, they will be included in the shares outstanding used to calculate basic

7


Denbury Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
net income (loss) per common share.  Restricted stock units and performance stock units are also excluded from basic weighted average common shares outstanding until the vesting date. Basic weighted average common shares during the three months ended March 31, 2023 includes 1,775,182 performance-based and restricted stock units which are fully vested as of March 31, 2023; however, the shares underlying these awards are not included in shares currently issued or outstanding as actual delivery of the shares is not scheduled to occur until December 4, 2023.

Diluted net income (loss) per common share is calculated in the same manner but includes the impact of all potentially dilutive securities. Potentially dilutive securities include restricted stock, restricted stock units, performance stock units, shares to be issued under the employee stock purchase plan (“ESPP”), and series A and series B warrants.

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

The following table sets forth the weighted average shares used for purposes of calculating basic and diluted net income (loss) per common share for the periods indicated:
Three Months Ended
March 31,
In thousands20232022
Weighted average common shares outstanding – basic51,503 51,602 
Effect of potentially dilutive securities
Restricted stock, restricted stock units and performance stock units360  
Warrants1,899  
Employee Stock Purchase Program1  
Weighted average common shares outstanding – diluted53,763 51,602 

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

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

The following outstanding securities were excluded from the computation of diluted net income (loss) per share for the three months ended March 31, 2023 and March 31, 2022, as their effect would have been antidilutive, as of the respective dates:
March 31,
In thousands20232022
Restricted stock, restricted stock units and performance stock units490 1,005 
Warrants 5,162 

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

8


Denbury Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
September 18, 2023, at which times the warrants expire. Through March 31, 2023, 0.9 million series A warrants and 1.8 million series B warrants were exercised for a total of 1.5 million shares, most of which were exercised on a cashless basis.

Oil and Natural Gas Properties

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

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

CCUS Storage Sites and Other Assets

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

Note 2. Revenue Recognition

We record revenue in accordance with Financial Accounting Standards Board (“FASB”) Codification (“FASC”) Topic 606, Revenue from Contracts with Customers. The core principle of FASC Topic 606 is that an entity should recognize revenue for the transfer of goods or services equal to the amount of consideration that it expects to be entitled to receive for those goods or services. Once we have delivered the volume of commodity to the delivery point and the customer takes delivery and possession, we are entitled to payment and we invoice the customer for such delivered production. Payment under most oil and CO2 contracts is received within one month following product delivery, and for natural gas and NGL contracts, payment is generally received within two months following delivery. Timing of revenue recognition may differ from the timing of invoicing to customers; however, as the right to consideration after delivery is unconditional based on only the passage of time before payment of the consideration is due, upon delivery we record a receivable in “Accrued production receivable” in our Unaudited Condensed Consolidated Balance Sheets. In certain situations, the Company enters into marketing arrangements for the purchase and subsequent sale of crude oil from third parties. We recognize the revenue received and the associated expense incurred on these sales on a gross basis, as “Oil marketing revenues” and “Oil marketing purchases” in our Unaudited Condensed Consolidated Statements of Operations, since we act as a principal in the transaction by assuming control of the commodities purchased and responsibility to deliver the commodities sold. Revenue is recognized when control transfers to the purchaser at the delivery point based on the price received from the purchaser.


9


Denbury Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
Disaggregation of Revenue

The following table summarizes our revenues by product type for the three months ended March 31, 2023 and 2022:
Three Months Ended
March 31,
In thousands20232022
Oil sales$312,572 $381,242 
Natural gas sales1,917 3,669 
CO2 sales and transportation fees
10,686 13,422 
Oil marketing revenues14,548 13,276 
Total revenues$339,723 $411,609 

Note 3. Long-Term Debt

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

In thousandsMarch 31, 2023December 31, 2022
Senior Secured Bank Credit Agreement$68,000 $29,000 
Capital lease obligations383  
Total debt principal balance68,383 29,000 
Less: current maturities of long-term debt(107) 
Long-term debt and capital lease obligations$68,276 $29,000 

Senior Secured Bank Credit Agreement

In September 2020, we entered into a credit agreement with JPMorgan Chase Bank, N.A., as administrative agent, and other lenders party thereto (as amended, the “Bank Credit Agreement”). The Bank Credit Agreement is a senior secured revolving credit facility with a maturity date of May 4, 2027. Under the Bank Credit Agreement, letters of credit are available in an aggregate amount not to exceed $100 million, and short-term swingline loans are available in an aggregate amount not to exceed $25 million, each subject to the available commitments under the Bank Credit Agreement. Availability under the Bank Credit Agreement is subject to a borrowing base, which is redetermined semiannually on or around May 1 and November 1 of each year. The borrowing base is adjusted at the lenders’ discretion and is based, in part, upon external factors over which we have no control. If our outstanding debt under the Bank Credit Agreement exceeds the then-effective borrowing base, we would be required to repay the excess amount over a period not to exceed six months. As part of our Spring 2023 semiannual borrowing base redetermination, the borrowing base and lender commitments for our Bank Credit Agreement were reaffirmed at $750 million, with our next scheduled redetermination around November 1, 2023. The undrawn portion of the aggregate lender commitments under the Bank Credit Agreement is subject to a commitment fee of 0.5% per annum. As of March 31, 2023, we had $10.1 million of outstanding letters of credit.

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

The Bank Credit Agreement limits our ability to, among other things, incur and repay other indebtedness; grant liens; engage in certain mergers, consolidations, liquidations and dissolutions; engage in sales of assets; make acquisitions and investments; make other restricted payments (including redeeming, repurchasing or retiring our common stock); and enter into commodity derivative agreements, in each case subject to certain exceptions to such limitations, as specified in the Bank Credit Agreement.

The Bank Credit Agreement is secured by (1) our proved oil and natural gas properties, which are held through our restricted subsidiaries; (2) the pledge of equity interests of such subsidiaries; (3) a pledge of our commodity derivative

10


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

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

A Consolidated Total Debt to Consolidated EBITDAX covenant (as defined in the Bank Credit Agreement), with such ratio not to exceed 3.5 times; and
A requirement to maintain a current ratio (i.e., Consolidated Current Assets to Consolidated Current Liabilities) of 1.0.

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

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

Note 4. Stockholders’ Equity

Share Repurchase Program

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

Retirement of Treasury Stock

During the year ended December 31, 2022, we retired 1.6 million shares of existing treasury stock, with a carrying value of $100 million, acquired through our stock repurchase program. Upon the retirement of treasury stock, we reduce common stock by the par value of common stock retired, and we reduce additional paid-in capital by the value of those shares in excess of par value.

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

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

Note 5. Income Taxes

We make estimates and judgments in determining our income tax expense for financial reporting purposes. These estimates and judgments occur in the calculation of certain tax assets and liabilities that arise from differences in the timing and recognition of revenue and expense for tax and financial reporting purposes. Significant judgment is required in estimating valuation allowances, and in making this determination we consider all available positive and negative evidence and make certain assumptions. The realization of a deferred tax asset ultimately depends on the existence of sufficient taxable income in the applicable carryback or carryforward periods. In our assessment, we consider the nature, frequency, and severity of current

11


Denbury Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
and cumulative losses, as well as historical and forecasted financial results, the overall business environment, our industry’s historic cyclicality, the reversal of existing deferred tax assets and liabilities, and tax planning strategies.

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

We evaluate our estimated annual effective income tax rate based on current and forecasted business results and enacted tax laws on a quarterly basis and apply this tax rate to our ordinary income or loss to calculate our estimated tax liability or benefit. Our income taxes are based on an estimated combined federal and state statutory rate of approximately 25% in 2023 and 2022. Our effective tax rate for the three months ended March 31, 2023 was slightly lower than our estimated statutory rate primarily due to excess stock compensation deductions that were recorded discretely in the quarter. Our effective tax rate for the three months ended March 31, 2022 was higher than our estimated statutory rate due to the release of a portion of the valuation allowance on our deferred tax assets combined with the net loss for the period.

Note 6. Commodity Derivative Contracts

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

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

We manage and control market and counterparty credit risk through established internal control procedures that are reviewed on an ongoing basis.  We attempt to minimize credit risk exposure to counterparties through formal credit policies, monitoring procedures and diversification, and all of our commodity derivative contracts are with parties that are lenders under our Bank Credit Agreement (or affiliates of such lenders). As of March 31, 2023, all of our outstanding derivative contracts were subject to enforceable master netting arrangements whereby payables on those contracts can be offset against receivables from separate derivative contracts with the same counterparty. It is our policy to classify derivative assets and liabilities on a gross basis on our balance sheets, even if the contracts are subject to enforceable master netting arrangements.


12


Denbury Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
The following table summarizes our commodity derivative contracts as of March 31, 2023, none of which are classified as hedging instruments in accordance with the FASC Derivatives and Hedging topic:
MonthsIndex PriceVolume (Barrels per day)Contract Prices ($/Bbl)
Weighted Average Price
SwapFloorCeiling
Oil Contracts:   
2023 Fixed-Price Swaps
Apr – JuneNYMEX9,500$76.65 $— $— 
July – DecNYMEX14,00078.46 — — 
2023 Collars
Apr – JuneNYMEX17,500$— $69.71 $100.42 
July – DecNYMEX9,000— 68.33 100.69 
2024 Fixed-Price Swaps
Jan – JuneNYMEX2,000$75.21 $— $— 
July – DecNYMEX1,00075.12 — — 

Note 7. Fair Value Measurements

The FASC Fair Value Measurement topic defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (often referred to as the “exit price”). We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. We primarily apply the income approach for recurring fair value measurements and endeavor to utilize the best available information. Accordingly, we utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. We are able to classify fair value balances based on the observability of those inputs. The FASC establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are as follows:

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

Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reported date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. Instruments in this category include non-exchange-traded oil derivatives that are based on NYMEX. Our costless collars are valued using the Black-Scholes model, an industry standard option valuation model that takes into account inputs such as contractual prices for the underlying instruments, maturity, quoted forward prices for commodities, interest rates, volatility factors and credit worthiness, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.

Level 3 – Pricing inputs include significant inputs that are generally less observable. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value.

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


13


Denbury Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
The following table sets forth, by level within the fair value hierarchy, our financial assets and liabilities that were accounted for at fair value on a recurring basis as of the periods indicated:
 Fair Value Measurements Using:
In thousandsQuoted Prices
in Active
Markets
(Level 1)
Significant
Other
Observable
Inputs
(Level 2)
Significant
Unobservable
Inputs
(Level 3)
Total
March 31, 2023 
Assets
Oil derivative contracts – current$ $23,554 $ $23,554 
Oil derivative contracts – long-term 1,617  1,617 
Total Assets$ $25,171 $ $25,171 
Liabilities
Oil derivative contracts – current$ $(1,613)$ $(1,613)
Total Liabilities$ $(1,613)$ $(1,613)
December 31, 2022    
Assets    
Oil derivative contracts – current$ $15,517 $ $15,517 
Total Assets$ $15,517 $ $15,517 
Liabilities
Oil derivative contracts – current$ $(13,018)$ $(13,018)
Total Liabilities$ $(13,018)$ $(13,018)

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

Other Fair Value Measurements

The carrying value of our loans under our Bank Credit Agreement approximate fair value, as they are subject to short-term floating interest rates that approximate the rates available to us for those periods. The estimated fair value of the principal amount of our debt as of March 31, 2023 and December 31, 2022 was $68.0 million and $29.0 million, respectively. We have other financial instruments consisting primarily of cash, cash equivalents, U.S. Treasury notes, short-term receivables and payables that approximate fair value due to the nature of the instrument and the relatively short maturities.

Note 8. Commitments and Contingencies

Litigation and Regulatory Proceedings

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


14


Denbury Inc.
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.






15


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

The following discussion and analysis should be read in conjunction with our Unaudited Condensed Consolidated Financial Statements and Notes thereto included herein and our Consolidated Financial Statements and Notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2022 (the “Form 10-K”), along with Management’s Discussion and Analysis of Financial Condition and Results of Operations contained in the Form 10-K.  Any terms used but not defined herein have the same meaning given to them in the Form 10-K.

Our discussion and analysis includes forward-looking information that involves risks and uncertainties and should be read in conjunction with Risk Factors under Item 1A of the Form 10-K, along with Forward-Looking Information at the end of this section for information on the risks and uncertainties that could cause our actual results to be materially different than our forward-looking statements.

OVERVIEW

Denbury is an independent energy company with operations focused in the Gulf Coast and Rocky Mountain regions. The Company is differentiated by its focus on CO2 enhanced oil recovery (“EOR”) and the emerging carbon capture, utilization, and storage (“CCUS”) industry, supported by the Company’s CO2 EOR technical and operational expertise and its extensive CO2 pipeline infrastructure. The utilization of captured industrial-sourced CO2 in EOR significantly reduces the carbon footprint of the oil that Denbury produces, making the Company’s Scope 1 and 2 CO2e emissions negative today. We have set a target, within the decade, to reach Net Zero for our Scope 1, Scope 2 and those Scope 3 emissions that result from consumers’ use of the oil and natural gas we sell (defined as Category 11 emissions by the Greenhouse Gas Protocol).

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

Oil Price Impact on Our Business.  Our financial results are significantly impacted by changes in oil prices, as 97% of our sales volumes are oil. Changes in oil prices impact all aspects of our business; most notably our cash flows from operations, revenues, capital allocation and budgeting decisions, and oil and natural gas reserves volumes. Oil prices have historically been volatile and can fluctuate significantly over short periods of time for many different reasons, such as global supply and demand and geopolitical events. Average NYMEX WTI oil prices were approximately $76 per Bbl during the first quarter of 2023 as compared to $95 per Bbl in the first quarter of 2022.


16


Denbury Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
The table below outlines selected financial items and sales volumes, along with changes in our realized oil prices, before and after commodity derivative impacts, for our most recent comparative quarterly periods:
Three Months Ended
In thousands, except per-unit dataMarch 31, 2023Dec. 31, 2022Sept. 30, 2022June 30, 2022March 31, 2022
Oil, natural gas, and related product sales$314,489 $346,578 $395,223 $451,970 $384,911 
Receipt (payment) on settlements of commodity derivatives2,065 (38,956)(55,780)(127,959)(93,057)
Oil, natural gas, and related product sales and commodity derivative settlements, combined$316,554 $307,622 $339,443 $324,011 $291,854 
Average daily sales (BOE/d)47,655 46,641 47,109 46,561 46,925 
Average net realized oil prices   
Oil price per Bbl - excluding impact of derivative settlements$74.87 $82.54 $92.77 $108.81 $93.17 
Oil price per Bbl - including impact of derivative settlements75.36 73.1379.4977.63 70.43 
Average NYMEX oil differential per Bbl$(1.28)$0.03 $0.82 $0.09 $(1.37)

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

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

Oil and natural gas revenues decreased by $70.4 million (18%) during the first quarter of 2023 due to lower oil prices;
Commodity derivatives expense decreased by $215.8 million consisting of a $120.7 million improvement in noncash fair value changes between periods ($21.1 million gain during the first quarter of 2023 compared to a $99.7 million loss during the first quarter of 2022), and a $95.1 million decrease in cash payments upon derivative contract settlements ($2.1 million in cash receipts during the first quarter of 2023 compared to $93.1 million in payments during the first quarter of 2022);
Lease operating expenses increased by $11.3 million (10%), primarily due to higher workover, repair and maintenance, labor, and CO2 purchase costs; and
Income tax expense increased by $34.8 million, from a benefit of $6.5 million during the first quarter of 2022 to $28.3 million in expense during the first quarter of 2023, primarily due to the release in 2022 of a portion of the valuation allowance on our deferred tax assets.

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

17


Denbury Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
quarter of 2023. We currently expect initial EOR production to commence during the second quarter of 2023, with incremental EOR production reaching 2,000 Bbls/d by the end of 2023 and 7,500 Bbls/d to 12,500 Bbls/d by the end of 2024.

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

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

CAPITAL RESOURCES AND LIQUIDITY

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

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

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


18


Denbury Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Capital Expenditure Summary. For purposes of tracking and comparing our capital budget to capital expenditure activity, we base those comparisons on when the capital expenditures are incurred, which is generally different than what is reported in our cash flow statements which reflects when cash is actually paid. The information included in the following table reflects our incurred capital expenditures:
Three Months Ended
March 31,
In thousands20232022
Capital expenditure summary(1)
 
CCA EOR field expenditures(2)
$40,038 $17,722 
CCA CO2 pipelines
523 2,191 
CCA tertiary development40,561 19,913 
Non-CCA tertiary and non-tertiary fields49,093 29,363 
CO2 sources, other CO2 pipelines and other
1,563 730 
  Capitalized internal costs(3)
8,574 7,600 
Oil and gas development capital expenditures99,791 57,606 
CCUS storage sites and related capital expenditures19,688 20,949 
Oil and gas and CCUS development capital expenditures119,479 78,555 
Capitalized interest1,693 1,158 
Acquisitions of oil and natural gas properties35 371 
Equity investments(4)
7,108 — 
Total capital expenditures$128,315 $80,084 

(1)Capital expenditures in this summary are presented on an as-incurred basis (including accruals) and are $0.9 million and $10.0 million lower than the capital expenditures in the Unaudited Condensed Consolidated Statements of Cash Flows for the three months ended March 31, 2023 and 2022, respectively, which are presented on a cash basis.
(2)Includes pre-production CO2 costs associated with the CCA EOR development project totaling $5.2 million during the first quarter of 2023 and $2.8 million during the first quarter of 2022.
(3)Includes capitalized internal acquisition, exploration and development costs and pre-production tertiary startup costs, excluding CCA.
(4)Represents two investments made in carbon capture technology companies during the first quarter of 2023, including a $2 million equity investment in Aqualung Carbon Capture AS and a $5 million equity investment in ION Clean Energy, Inc. The investments are included in “Other assets” in the Unaudited Condensed Consolidated Balance Sheet as of March 31, 2023.

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

Senior Secured Bank Credit Agreement. In September 2020, we entered into a credit agreement with JPMorgan Chase Bank, N.A., as administrative agent, and other lenders party thereto (as amended, the “Bank Credit Agreement”). The Bank Credit Agreement is a senior secured revolving credit facility with a maturity date of May 4, 2027. Under the Bank Credit Agreement, letters of credit are available in an aggregate amount not to exceed $100 million, and short-term swingline loans are available in an aggregate amount not to exceed $25 million, each subject to the available commitments under the Bank Credit Agreement. Availability under the Bank Credit Agreement is subject to a borrowing base, which is redetermined semiannually on or around May 1 and November 1 of each year. As part of our Spring 2023 semiannual borrowing base redetermination, the borrowing base and lender commitments for our Bank Credit Agreement were reaffirmed at $750 million, with our next scheduled redetermination around November 1, 2023. The borrowing base is adjusted at the lenders’ discretion and is based, in

19


Denbury Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
part, upon external factors over which we have no control. If our outstanding debt under the Bank Credit Agreement exceeds the then-effective borrowing base, we would be required to repay the excess amount over a period not to exceed six months.

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

The Bank Credit Agreement also limits our ability to, among other things, incur and repay other indebtedness; grant liens; engage in certain mergers, consolidations, liquidations and dissolutions; engage in sales of assets; make acquisitions and investments; make other restricted payments (including redeeming, repurchasing or retiring our common stock); and enter into commodity derivative agreements, in each case subject to certain exceptions to such limitations, as specified in the Bank Credit Agreement. Our Bank Credit Agreement required certain minimum commodity hedge levels in connection with our emergence from bankruptcy; however, these conditions were met as of December 31, 2020, and we currently have no ongoing hedging requirements under the Bank Credit Agreement.

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

A Consolidated Total Debt to Consolidated EBITDAX covenant (as defined in the Bank Credit Agreement), with such ratio not to exceed 3.5 times; and
A requirement to maintain a current ratio (i.e., Consolidated Current Assets to Consolidated Current Liabilities) of 1.0.

For purposes of computing the current ratio per the Bank Credit Agreement, Consolidated Current Assets exclude the current portion of derivative assets but include available borrowing capacity under the Bank Credit Agreement, and Consolidated Current Liabilities exclude the current portion of derivative liabilities as well as the current portions of long-term indebtedness outstanding. Under these financial performance covenant calculations, as of March 31, 2023, our ratio of consolidated total debt to consolidated EBITDAX was 0.11 to 1.0 (with a maximum permitted ratio of 3.5 to 1.0) and our current ratio was 2.89 to 1.0 (with a required ratio of not less than 1.0 to 1.0). Based upon our currently forecasted levels of production and costs, hedges in place as of May 1, 2023, and current oil commodity futures prices, we currently anticipate continuing to be in compliance with our financial performance covenants during the foreseeable future.

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

Commitments, Obligations and Off-Balance Sheet Arrangements. We incur numerous contractual commitments in the ordinary course of business including debt service requirements, operating leases, purchase obligations, and asset retirement obligations. Our operating leases primarily consist of our office leases. Our purchase obligations represent future cash commitments primarily for purchase contracts for CO2 captured from industrial sources, CO2 processing fees, transportation agreements and well-related costs. Our off-balance sheet arrangements include obligations for various development and exploratory expenditures that arise from our normal oil and natural gas or CCUS capital expenditure program or from other transactions common to our industry, none of which are recorded on our balance sheet.  During 2022 and 2023, we entered into storage contracts to secure rights to underground pore space in anticipation of future CCUS operations. Noncancelable commitments under those contracts total $2 million as of March 31, 2023.  In addition, in order to recover our undeveloped proved reserves, we must also fund the associated future development costs estimated in our proved reserve reports.

Our commitments, obligations and off-balance sheet arrangements as of December 31, 2022, are detailed in our Form 10-K under Management’s Discussion and Analysis of Financial Condition and Results of Operations Capital Resources and Liquidity Commitments, Obligations and Off-Balance Sheet Arrangements.


20


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

Financial and Operating Results Tables

Certain of our operating results and statistics for the comparative three months ended March 31, 2023 and 2022 are included in the following table:
Three Months Ended
March 31,
In thousands, except per-share and unit data20232022
Financial results
Net income (loss)$89,199 $(872)
Net income (loss) per common share – basic1.73 (0.02)
Net income (loss) per common share – diluted1.66 (0.02)
Net cash provided by operating activities88,522 90,143
Average daily sales volumes 
Bbls/d46,389 45,466 
Mcf/d7,600 8,753 
BOE/d(1)
47,655 46,925 
Oil and natural gas sales 
Oil sales
$312,572 $381,242 
Natural gas sales1,917 3,669 
Total oil and natural gas sales
$314,489 $384,911 
Commodity derivative contracts(2)
 
Receipt (payment) on settlements of commodity derivatives$2,065 $(93,057)
Noncash fair value gains (losses) on commodity derivatives21,058 (99,662)
Commodity derivatives income (expense)$23,123 $(192,719)
Unit prices – excluding impact of derivative settlements 
Oil price per Bbl$74.87 $93.17 
Natural gas price per Mcf2.80 4.66 
Unit prices – including impact of derivative settlements(2)
 
Oil price per Bbl$75.36 $70.43 
Natural gas price per Mcf2.80 4.66 
Oil and natural gas operating expenses 
Lease operating expenses$129,174 $117,828 
Transportation and marketing expenses5,389 4,645 
Production and ad valorem taxes28,263 30,443 
Oil and natural gas operating revenues and expenses per BOE 
Oil and natural gas revenues$73.32 $91.14 
Lease operating expenses30.12 27.90 
Transportation and marketing expenses1.26 1.10 
Production and ad valorem taxes6.59 7.21 
CO2 – revenues and expenses
 
CO2 sales and transportation fees
$10,686 $13,422 
CO2 operating and discovery expenses
(1,196)(2,817)
CO2 revenue and expenses, net
$9,490 $10,605 

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



21


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

Average daily sales volumes by area for each of the four quarters of 2022 and for the first quarter of 2023 is shown below:
 Average Daily Sales Volumes (BOE/d)
First
Quarter
Fourth
Quarter
Third
Quarter
Second
Quarter
First
Quarter
Operating Area20232022202220222022
Tertiary oil sales volumes    
Gulf Coast region
Delhi2,514 2,528 2,557 2,478 2,675 
Hastings4,450 4,198 4,211 4,304 4,430 
Heidelberg3,539 3,670 3,571 3,528 3,653 
Oyster Bayou3,832 3,417 3,490 3,423 3,745 
Tinsley3,205 2,248 3,133 3,050 3,015 
Other(1)
5,585 5,652 5,541 5,422 5,498 
Total Gulf Coast region23,125 21,713 22,503 22,205 23,016 
Rocky Mountain region
Bell Creek3,808 3,767 3,975 4,122 4,474 
Wind River Basin3,872 3,726 3,121 2,703 2,517 
Other(2)
2,744 2,824 2,759 2,361 2,229 
Total Rocky Mountain region10,424 10,317 9,855 9,186 9,220 
Total tertiary oil sales volumes33,549 32,030 32,358 31,391 32,236 
Non-tertiary oil and gas sales volumes
Gulf Coast region
Total Gulf Coast region3,398 3,666 3,727 3,566 3,630 
Rocky Mountain region
Cedar Creek Anticline9,316 9,366 9,593 10,224 9,721 
Other(3)
1,392 1,579 1,431 1,380 1,338 
Total Rocky Mountain region10,708 10,945 11,024 11,604 11,059 
Total non-tertiary sales volumes14,106 14,611 14,751 15,170 14,689 
Total sales volumes47,655 46,641 47,109 46,561 46,925 

(1)Includes Brookhaven, Cranfield, Eucutta, Little Creek, Mallalieu, Martinville, McComb, Soso, and West Yellow Creek fields.
(2)Includes tertiary sales volumes related to our working interest positions in the Salt Creek and Grieve fields.
(3)Includes non-tertiary sales volumes from Wind River Basin, as well as Hartzog Draw and Bell Creek fields.

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

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


22


Denbury Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Oil and Natural Gas Revenues

Our oil and natural gas revenues during the three months ended March 31, 2023 decreased 18% compared to these revenues for the same period in 2022.  The changes in our oil and natural gas revenues are due to lower realized commodity prices (excluding any impact of our commodity derivative contracts), as reflected in the following table:
Three Months Ended
March 31,
2023 vs. 2022
In thousandsIncrease (Decrease) in RevenuesPercentage Increase (Decrease) in Revenues
Change in oil and natural gas revenues due to:  
Increase in sales volumes$5,989 %
Decrease in realized commodity prices(76,411)(20)%
Total decrease in oil and natural gas revenues$(70,422)(18)%

Excluding any impact of our commodity derivative contracts, our average net realized commodity prices and NYMEX differentials were as follows during each of the three months ended March 31, 2023 and 2022:
Three Months Ended
March 31,
 20232022
Average net realized prices  
Oil price per Bbl
$74.87 $93.17 
Natural gas price per Mcf
2.80 4.66 
Price per BOE
73.32 91.14 
Average NYMEX differentials  
Gulf Coast region
Oil per Bbl
$(1.29)$(1.37)
Natural gas per Mcf
(0.05)0.16 
Rocky Mountain region
Oil per Bbl
$(1.28)$(1.38)
Natural gas per Mcf
0.04 0.08 
Total Company
Oil per Bbl
$(1.28)$(1.37)
Natural gas per Mcf
0.01 0.11 

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

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

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


23


Denbury Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
CO2 Revenues and Expenses

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

Oil Marketing Revenues and Purchases

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

Commodity Derivative Contracts

We have routinely entered into oil derivative contracts to provide an economic hedge of our exposure to commodity price risk associated with anticipated future oil production and to provide more certainty to our future cash flows.  These contracts currently consist of fixed-price swaps and costless collars. The following table summarizes the impact our crude oil derivative contracts had on our operating results for the three months ended March 31, 2023 and 2022:
Three Months Ended
 March 31,
In thousands20232022
Receipt (payment) on settlements of commodity derivatives$2,065 $(93,057)
Noncash fair value gains (losses) on commodity derivatives21,058 (99,662)
Total income (expense)$23,123 $(192,719)

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

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

24


Denbury Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Market Risk below for additional discussion. In addition, the following table summarizes our commodity derivative contracts as of May 1, 2023:
2Q 20232H 20231H 20242H 2024
WTI NYMEXVolumes Hedged (Bbls/d)9,50018,0005,0001,000
Fixed-Price Swaps
Weighted Average Swap Price
$76.65$78.51$75.34$75.12
WTI NYMEXVolumes Hedged (Bbls/d)17,5009,000
Collars
Weighted Average Floor / Ceiling Price
$69.71 / $100.42$68.33 / $100.69
Total Volumes Hedged (Bbls/d)
27,00027,0005,0001,000

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

Production Expenses

Lease Operating Expenses
Three Months Ended
March 31,
In thousands, except per-BOE data20232022
Total lease operating expenses$129,174 117,828 
Total lease operating expenses per BOE$30.12 $27.90 

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

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

Transportation and Marketing Expenses

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

Taxes Other Than Income

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


25


Denbury Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
General and Administrative Expenses (“G&A”)
Three Months Ended
March 31,
In thousands, except per-BOE data and employees20232022
Cash G&A costs$18,039 $15,721 
Stock-based compensation4,938 2,971 
G&A expense$22,977 $18,692 
G&A per BOE 
Cash G&A costs$4.21 $3.72 
Stock-based compensation1.15 0.71 
G&A expenses$5.36 $4.43 
Employees as of period end774724 

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

Interest and Financing Expenses
Three Months Ended
March 31,
In thousands, except per-BOE data and interest rates20232022
Cash interest(1)
$2,089 $1,130 
Noncash interest expense531 685 
Less: capitalized interest(1,693)(1,158)
Interest expense, net
$927