10-Q 1 den-20220331.htm FORM 10-Q den-20220331
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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, 2022
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
den-20220331_g1.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
  (Do not check if a smaller reporting company) 

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

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

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

The number of shares outstanding of the registrant’s Common Stock, $.001 par value, as of April 30, 2022, was 50,369,023.





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, 2022December 31, 2021
Assets
Current assets  
Cash and cash equivalents$517 $3,671 
Accrued production receivable216,161 143,365 
Trade and other receivables, net17,571 19,270 
Prepaids10,175 9,099 
Total current assets244,424 175,405 
Property and equipment  
Oil and natural gas properties (using full cost accounting)  
Proved properties1,149,762 1,109,011 
Unevaluated properties131,677 112,169 
CO2 properties
184,043 183,369 
Pipelines226,766 224,394 
CCUS storage sites and related assets20,949  
Other property and equipment94,993 93,950 
Less accumulated depletion, depreciation, amortization and impairment(210,537)(181,393)
Net property and equipment1,597,653 1,541,500 
Operating lease right-of-use assets18,595 19,502 
Derivative assets265  
Deferred tax assets, net4,306  
Intangible assets, net85,966 88,248 
Restricted cash for future asset retirement obligations46,695 46,673 
Other assets33,445 31,625 
Total assets$2,031,349 $1,902,953 
Liabilities and Stockholders’ Equity
Current liabilities  
Accounts payable and accrued liabilities$201,598 $191,598 
Oil and gas production payable99,247 75,899 
Derivative liabilities223,598 134,509 
Operating lease liabilities4,683 4,677 
Total current liabilities529,126 406,683 
Long-term liabilities  
Long-term debt, net of current portion35,000 35,000 
Asset retirement obligations282,792 284,238 
Derivative liabilities10,837  
Deferred tax liabilities, net 1,638 
Operating lease liabilities16,095 17,094 
Other liabilities19,850 22,910 
Total long-term liabilities364,574 360,880 
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; 50,349,390 and 50,193,656 shares issued, respectively50 50 
Paid-in capital in excess of par1,133,127 1,129,996 
Retained earnings4,472 5,344 
Total stockholders equity
1,137,649 1,135,390 
Total liabilities and stockholders’ equity$2,031,349 $1,902,953 
 
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,
20222021
Revenues and other income 
Oil, natural gas, and related product sales$384,911 $235,445 
CO2 sales and transportation fees
13,422 9,228 
Oil marketing revenues13,276 6,126 
Other income250 360 
Total revenues and other income411,859 251,159 
Expenses 
Lease operating expenses117,828 81,970 
Transportation and marketing expenses4,645 7,797 
CO2 operating and discovery expenses
2,817 993 
Taxes other than income31,381 18,963 
Oil marketing purchases13,040 6,085 
General and administrative expenses18,692 31,983 
Interest, net of amounts capitalized of $1,158 and $1,083, respectively657 1,536 
Depletion, depreciation, and amortization35,345 39,450 
Commodity derivatives expense192,719 115,743 
Write-down of oil and natural gas properties 14,377 
Other expenses2,112 2,146 
Total expenses419,236 321,043 
Loss before income taxes(7,377)(69,884)
Income tax benefit(6,505)(242)
Net loss$(872)$(69,642)
Net loss per common share
Basic$(0.02)$(1.38)
Diluted$(0.02)$(1.38)
Weighted average common shares outstanding 
Basic51,602 50,319 
Diluted51,602 50,319 

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,
 20222021
Cash flows from operating activities 
Net loss$(872)$(69,642)
Adjustments to reconcile net loss to cash flows from operating activities 
Depletion, depreciation, and amortization35,345 39,450 
Write-down of oil and natural gas properties 14,377 
Deferred income taxes(5,944)(51)
Stock-based compensation2,971 17,680 
Commodity derivatives expense192,719 115,743 
Payment on settlements of commodity derivatives(93,057)(38,453)
Debt issuance costs685 685 
Other, net(1,267)727 
Changes in assets and liabilities, net of effects from acquisitions 
Accrued production receivable(72,795)(36,750)
Trade and other receivables1,644 865 
Other current and long-term assets189 (2,542)
Accounts payable and accrued liabilities11,410 (1,402)
Oil and natural gas production payable23,348 12,795 
Other liabilities(4,233)(826)
Net cash provided by operating activities90,143 52,656 
Cash flows from investing activities 
Oil and natural gas capital expenditures(58,707)(19,627)
CCUS storage sites and related capital expenditures(14,900) 
Acquisitions of oil and natural gas properties (10,665)
Pipelines and plants capital expenditures(15,204)(458)
Other(1,396)(2,913)
Net cash used in investing activities(90,207)(33,663)
Cash flows from financing activities 
Bank repayments(274,000)(202,000)
Bank borrowings274,000 207,000 
Pipeline financing repayments (16,509)
Other(3,068)(3,013)
Net cash used in financing activities(3,068)(14,522)
Net increase (decrease) in cash, cash equivalents, and restricted cash(3,132)4,471 
Cash, cash equivalents, and restricted cash at beginning of period50,344 42,248 
Cash, cash equivalents, and restricted cash at end of period$47,212 $46,719 

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 (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 0 — — 0 
Stock-based compensation— — 3,142 — 3,142 
Tax withholding for stock compensation plans— — (58)— (58)
Issued pursuant to exercise of warrants14,153 0 47 — 47 
Net loss— — — (872)(872)
Balance – March 31, 202250,349,390 $50 $1,133,127 $4,472 $1,137,649 

Common Stock
($.001 Par Value)
Paid-In Capital in Excess of ParRetained Earnings (Accumulated Deficit)
SharesAmountTotal Equity
Balance – December 31, 202049,999,999 $50 $1,104,276 $(50,658)$1,053,668 
Stock-based compensation— — 19,172 — 19,172 
Tax withholding for stock compensation plans— — (1,467)— (1,467)
Issued pursuant to exercise of warrants5,620 0 195 — 195 
Net loss— — — (69,642)(69,642)
Balance – March 31, 202150,005,619 $50 $1,122,176 $(120,300)$1,001,926 

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, 2021 (the “Form 10-K”).  Unless indicated otherwise or the context requires, the terms “we,” “our,” “us,” “Company” or “Denbury,” refer to Denbury Inc. and its subsidiaries.

Accounting measurements at interim dates inherently involve greater reliance on estimates than at year end, and the results of operations for the interim periods shown in this report are not necessarily indicative of results to be expected for the year.  In management’s opinion, the accompanying unaudited condensed consolidated financial statements include all adjustments of a normal recurring nature necessary for a fair presentation of our consolidated financial position as of March 31, 2022, our consolidated results of operations for the three months ended March 31, 2022 and 2021, our consolidated cash flows for the three months ended March 31, 2022 and 2021, and our consolidated statements of changes in stockholders’ equity for the three months ended March 31, 2022 and 2021.

Reclassifications

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

Cash, Cash Equivalents, and Restricted Cash

The following table provides a reconciliation of cash, cash equivalents, and restricted cash as reported within the Unaudited Condensed Consolidated Balance Sheets to “Cash, cash equivalents, and restricted cash at end of period” as reported within the Unaudited Condensed Consolidated Statements of Cash Flows:
In thousandsMarch 31, 2022December 31, 2021
Cash and cash equivalents$517 $3,671 
Restricted cash for future asset retirement obligations46,695 46,673 
Total cash, cash equivalents, and restricted cash shown in the Unaudited Condensed Consolidated Statements of Cash Flows$47,212 $50,344 

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 net income (loss) per common share.  Restricted stock units and performance stock units are also excluded from basic weighted

7


Denbury Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
average common shares outstanding until the vesting date. Basic weighted average common shares during the three months ended March 31, 2022 includes 1,404,649 performance-based and restricted stock units which are fully vested as of March 31, 2022. Although vesting criteria for these awards have been achieved, the shares underlying these awards are not 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, and series A and series B warrants.

For each of the three months ended March 31, 2022 and 2021, there were no adjustments to net income (loss) for purposes of calculating basic and diluted net income (loss) per common share.

For the three months ended March 31, 2022 and 2021, 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 net losses each period. Assuming the Company had recorded net income during the three months ended March 31, 2022 and 2021, 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) and 51.2 million (including the impact of 0.5 million restricted stock units and 0.4 million shares with respect to warrants), respectively.

The following outstanding securities could potentially dilute earnings per share in the future, but were excluded from the computation of diluted net income (loss) per share for the three months ended March 31, 2022 and 2021, as their effect would have been antidilutive, as of the respective dates:
March 31,
In thousands20222021
Restricted stock, restricted stock units and performance stock units1,005 1,276 
Warrants5,162 5,520 

At March 31, 2022, the Company had approximately 5.2 million warrants outstanding that can be exercised for shares of our common stock, at an exercise price of $32.59 per share for the 2.6 million series A warrants outstanding and at an exercise price of $35.41 per share for the 2.6 million series B warrants outstanding. The series A warrants are exercisable until September 18, 2025, and the series B warrants are exercisable until September 18, 2023, at which time the warrants expire. As of March 31, 2022, 12,294 series A warrants and 352,442 series B warrants have been exercised for a total of 207,810 shares, as the warrants may be exercised for cash or 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 recognized a full cost pool ceiling test write-down of $14.4 million during the three months ended March 31, 2021, with first-day-of-the-month NYMEX oil prices for the preceding 12 months averaging $36.40 per Bbl, after adjustments for market differentials and transportation expenses by field. The write-down was primarily a result of the March 2021 acquisition of Wyoming property interests (see Note 2, Acquisition) which was recorded based on a valuation that utilized NYMEX strip

8


Denbury Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
oil prices at the acquisition date, which were significantly higher than the average first-day-of-the-month NYMEX oil prices used to value the cost ceiling. We did not record a ceiling test write-down during the three months ended March 31, 2022.

CCUS Storage Sites and Related Assets

Capitalized Costs. Beginning with our financial statements for the three months ended March 31, 2022, we have capitalized various costs that we incur to acquire and develop storage sites for the injection of CO2. These costs generally include, or are expected to include, expenditures for acquiring surface and subsurface rights; third-party acquisition costs; permitting; drilling; facilities; environmental monitoring equipment for groundwater and storage site gas; engineering; capitalized interest; on-site road construction and other capital infrastructure costs. If a storage site is no longer deemed probable of being developed, all previously capitalized costs are expensed.

Amortization. Our CCUS storage sites are not yet operational. Accordingly, we currently have no amortization of capitalized costs. Amortization of these costs will begin when CO2 storage operations commence.

Note 2. Acquisition

Acquisition of Wyoming CO2 EOR Fields

On March 3, 2021, we acquired a nearly 100% working interest (approximately 83% net revenue interest) in the Big Sand Draw and Beaver Creek EOR fields located in Wyoming from a subsidiary of Devon Energy Corporation, including surface facilities and a 46-mile CO2 transportation pipeline to the acquired fields. The acquisition purchase price was $10.9 million (after final closing adjustments) plus two contingent $4 million cash payments if NYMEX WTI oil prices average at least $50 per Bbl during each of 2021 and 2022. We made the first contingent payment in January 2022 and if the price condition is met, the second $4 million payment will be due in January 2023. The fair value of the contingent consideration recorded on our Unaudited Condensed Consolidated Balance Sheets was $3.9 million as of March 31, 2022.

The fair values allocated to our assets acquired and liabilities assumed for the acquisition, based on significant inputs not observable in the market and considered level 3 inputs, were finalized during the third quarter of 2021, after consideration of final closing adjustments and evaluation of reserves and liabilities assumed. The following table presents a summary of the fair value of assets acquired and liabilities assumed in the acquisition:

In thousands
Consideration:
Cash consideration$10,906 
Less: Fair value of assets acquired and liabilities assumed:
Proved oil and natural gas properties60,101 
Other property and equipment1,685 
Asset retirement obligations(39,794)
Contingent consideration(5,320)
Other liabilities(5,766)
Fair value of net assets acquired$10,906 

Note 3. 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

9


Denbury Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
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 revenues 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, 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 months ended March 31, 2022 and 2021:
Three Months Ended
March 31,
In thousands20222021
Oil sales$381,242 $233,044 
Natural gas sales3,669 2,401 
CO2 sales and transportation fees
13,422 9,228 
Oil marketing revenues13,276 6,126 
Total revenues$411,609 $250,799 

Note 4. Long-Term Debt

The table below reflects long-term debt outstanding as of the dates indicated:
In thousandsMarch 31, 2022December 31, 2021
Senior Secured Bank Credit Agreement$35,000 $35,000 
Long-term debt $35,000 $35,000 

Senior Secured Bank Credit Agreement

On September 18, 2020, we entered into a $575 million credit agreement for a senior secured revolving credit facility with JPMorgan Chase Bank, N.A., as administrative agent, and other lenders party thereto (the “Bank Credit Agreement”). On May 4, 2022, we entered into a Second Amendment to the Bank Credit Agreement, which among other things:

Increases the borrowing base and lender commitments from $575 million to $750 million;
Extends the maturity date from January 30, 2024 to May 4, 2027;
Modifies the interest provisions on loans under the Bank Credit Agreement to (1) reduce the applicable margin for alternate base rate loans from 2% to 3% per annum to 1.5% to 2.5% per annum and (2) replace provisions referencing LIBOR loans with Secured Overnight Financing Rate loans, with an applicable margin of 2.5% to 3.5% per annum; and
Permits us to pay dividends on our common stock and make other unlimited restricted payments and investments so long as (1) no event of default or borrowing base deficiency exists; (2) our total leverage ratio is 1.5 to 1 or lower; and (3) availability under the Bank Credit Agreement is at least 20% of the borrowing base.

Availability under the Bank Credit Agreement is subject to a borrowing base, which is redetermined semiannually on or around May 1 and November 1 of each year, with our next scheduled redetermination around November 1, 2022. The borrowing base is adjusted at the lenders’ discretion and is based, in part, upon external factors over which we have no control. If our outstanding debt under the Bank Credit Agreement exceeds the then-effective borrowing base, we would be required to repay the excess amount over a period not to exceed six months. The weighted average interest rate on borrowings outstanding

10


Denbury Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
as of March 31, 2022 under the Bank Credit Agreement was 5.5%. The undrawn portion of the aggregate lender commitments under the Bank Credit Agreement is subject to a commitment fee of 0.5% per annum.

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

The Bank Credit Agreement is secured by (1) our proved oil and natural gas properties, which are held through our restricted subsidiaries; (2) the pledge of equity interests of such subsidiaries; (3) a pledge of our commodity derivative agreements; (4) a pledge of deposit accounts, securities accounts and our commodity accounts; and (5) a security interest in substantially all other collateral that may be perfected by a Uniform Commercial Code filing, subject to certain exceptions.

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

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

For purposes of computing the current ratio per the Bank Credit Agreement, Consolidated Current Assets exclude the current portion of derivative assets but include available borrowing capacity under the Bank Credit Agreement, and Consolidated Current Liabilities exclude the current portion of derivative liabilities as well as the current portions of long-term indebtedness outstanding. As of March 31, 2022, we were in compliance with all debt covenants under the Bank Credit Agreement.

The above description of our Bank Credit Agreement is qualified by the express language and defined terms contained in the Bank Credit Agreement and amendments thereto.

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 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.

At March 31, 2022, we assessed the valuation allowance recorded on our deferred tax assets, which was $125.5 million at December 31, 2021. This valuation allowance on our federal and certain state deferred tax assets was recorded in September 2020 after the application of fresh start accounting, as (1) the tax basis of our assets, primarily our oil and gas properties, was in excess of the carrying value, as adjusted for fresh start accounting and (2) our historical pre-tax income reflected a three-year cumulative loss primarily due to ceiling test write-downs and reorganization items that were recorded in 2020. While we continued to be in a cumulative three-year-loss position during the first quarter of 2022, we determined that there is sufficient positive evidence, primarily related to a substantial increase in worldwide oil prices, to conclude that $64.9 million of our federal and certain state deferred tax assets are more likely than not to be realized. Accordingly, we currently expect to reverse $64.9 million of this valuation allowance during the year ended December 31, 2022 as follows: (1) $5.9 million during the three months ended March 31, 2022, and (2) $59.0 million during the second through fourth quarters of 2022, resulting in a change to our annualized effective tax rate. We will continue to maintain a valuation allowance of $60.6 million for certain state tax benefits that we currently do not expect to realize before their expiration.


11


Denbury Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
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 2022 and 2021. Our effective tax rate for the three months ended March 31, 2022 was significantly higher than our estimated statutory rate primarily due to the release of $5.9 million of the valuation allowance that was recorded discretely in the quarter.

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” 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.

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, 2022, all of our outstanding derivative contracts were subject to enforceable master netting arrangements whereby payables on those contracts can be offset against receivables from separate derivative contracts with the same counterparty. It is our policy to classify derivative assets and liabilities on a gross basis on our balance sheets, even if the contracts are subject to enforceable master netting arrangements.

The following table summarizes our commodity derivative contracts as of March 31, 2022, 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)
Range(1)
Weighted Average Price
SwapFloorCeiling
Oil Contracts:    
2022 Fixed-Price Swaps
Apr – JuneNYMEX15,500$42.65 58.15 $49.01 $— $— 
July – DecNYMEX9,50050.13 78.53 57.52 — — 
2022 Collars
Apr – JuneNYMEX11,000$47.50 70.75 $— $49.77 $64.31 
July – DecNYMEX11,50047.50 91.60 — 52.39 67.29 
2023 Fixed-Price Swaps
Jan – JuneNYMEX4,500$71.50 78.10 $74.88 $— $— 
July – DecNYMEX2,00075.50 78.10 76.80 — — 
2023 Collars
Jan – JuneNYMEX7,500$60.00 104.60 $— $64.00 $88.83 
July – DecNYMEX4,00065.00 104.60 — 65.00 93.23 

(1)Ranges presented for fixed-price swaps represent the lowest and highest fixed prices of all open contracts for the period presented. For collars, ranges represent the lowest floor price and highest ceiling price for all open contracts for the period presented.


12


Denbury Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
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 and regional pricing other than NYMEX (e.g., Light Louisiana Sweet). 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, 2022 
Assets
Oil derivative contracts – long-term$ $265 $ $265 
Total Assets$ $265 $ $265 
Liabilities
Oil derivative contracts – current$ $(223,598)$ $(223,598)
Oil derivative contracts – long-term (10,837) (10,837)
Total Liabilities$ $(234,435)$ $(234,435)
December 31, 2021    
Liabilities
Oil derivative contracts – current$ $(134,509)$ $(134,509)
Total Liabilities$ $(134,509)$ $(134,509)

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

Note 8. Commitments and Contingencies

Litigation

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


14


Denbury Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
Note 9. Subsequent Event

Common Share Repurchase Program

On May 5, 2022, we announced Board authorization of a common share repurchase program for up to $250 million of outstanding Denbury common stock. 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. As of May 5, 2022, there have been no repurchases of common stock under this share repurchase program.

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, 2021 (the “Form 10-K”), along with Management’s Discussion and Analysis of Financial Condition and Results of Operations contained in the Form 10-K.  Any terms used but not defined herein have the same meaning given to them in the Form 10-K.  

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

OVERVIEW

Denbury is an independent energy company with operations focused in the Gulf Coast and Rocky Mountain regions. The Company is differentiated by its focus on CO2 enhanced oil recovery (“EOR”) and the emerging carbon capture, use, and storage (“CCUS”) industry, supported by the Company’s CO2 EOR technical and operational expertise and its extensive CO2 pipeline infrastructure. The utilization of captured industrial-sourced CO2 in EOR significantly reduces the carbon footprint of the oil that Denbury produces, making the Company’s Scope 1 and 2 CO2 emissions negative today, with a goal to be net-zero on its Scope 1, 2, and 3 CO2 emissions by 2030, primarily through increasing the amount of captured industrial-sourced CO2 used in its operations.

Oil Price Impact on Our Business.  Our financial results are significantly impacted by changes in oil prices, as 97% of our sales volumes are oil. Changes in oil prices impact all aspects of our business; most notably our cash flows from operations, revenues, capital allocation and budgeting decisions, and oil and natural gas reserves volumes. The table below 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, 2022Dec. 31, 2021Sept. 30, 2021June 30, 2021March 31, 2021
Oil, natural gas, and related product sales$384,911 $333,348 $308,454 $282,708 $235,445 
Receipt (payment) on settlements of commodity derivatives(93,057)(97,774)(77,670)(63,343)(38,453)
Oil, natural gas, and related product sales and commodity settlements, combined$291,854 $235,574 $230,784 $219,365 $196,992 
Average daily sales (BOE/d)46,925 48,882 49,682 49,133 47,357 
Average net realized oil prices   
Oil price per Bbl - excluding impact of derivative settlements$93.17 $75.68 $68.88 $64.70 $56.28 
Oil price per Bbl - including impact of derivative settlements70.43 53.21 51.35 50.10 47.00 

Average NYMEX WTI oil prices increased from the mid-$70s per Bbl range in the fourth quarter of 2021 to approximately $95 per Bbl during the first quarter of 2022, reaching highs of over $123 per Bbl in early-March 2022. This increase in oil prices was due in large part to concerns around potential worldwide oil supply disruptions associated with the Russian invasion of Ukraine during the first quarter of 2022.


16


Denbury Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
As shown in the table above, our oil and natural gas revenues increased significantly over the last four quarters as oil prices increased. However, the benefit of the increase in revenues over this time period was offset in part by the impact of higher cash payments on our commodity derivative contracts, which were largely required to be entered into during the fourth quarter of 2020 under the terms of our September 18, 2020 bank credit facility. During the first quarter of 2022, we paid $93.1 million related to the expiration of commodity derivative contracts and expect to make additional payments on the settlement of our contracts expiring during the remainder of 2022. In the second half of 2022, less of our production is hedged, and our hedges are at more favorable prices and with a greater mix of collars, allowing us to realize additional upside of currently anticipated higher oil prices.

First Quarter 2022 Financial Results and Highlights. We recognized a net loss of $0.9 million, or $0.02 per diluted common share, during the first quarter of 2022, compared to a net loss of $69.6 million, or $1.38 per diluted common share, during the first quarter of 2021. The primary drivers of the comparative operating results include the following:

Oil and natural gas revenues increased $149.5 million (63%) due to an increase in commodity prices;
Lease operating expenses increased $35.9 million (44%), offset in part by reductions in other expense categories; and
Commodity derivatives expense increased by $77.0 million consisting of a $54.6 million increase in cash payments upon contract settlements and a $22.4 million loss on noncash fair value changes.

Commencement of Cedar Creek Anticline (“CCA”) CO2 Injection. In early February 2022, we commenced CO2 injection in the first phase of our CCA EOR project, and during April 2022 we increased CO2 injections to approximately 115 MMcf/d of industrial-sourced CO2 into the field. We continue to anticipate tertiary oil production response from this new project in the second half of 2023.

Carbon Capture, Use and Storage. CCUS is a process that captures CO2 from industrial sources and reuses it or stores the CO2 in geologic formations in order to prevent its release into the atmosphere. We utilize CO2 from industrial sources in our EOR operations, and our extensive CO2 pipeline infrastructure and operations, particularly in the Gulf Coast, are strategically located in close proximity to large sources of industrial emissions. We believe that the assets and technical expertise required for CCUS are highly aligned with our existing CO2 EOR operations, providing us with a significant advantage and opportunity to participate in the emerging CCUS industry, as the building of a permanent carbon sequestration business requires both time and capital to build assets such as those we own and have been operating for years. During the first quarter of 2022, approximately 36% of the CO2 utilized in our oil and gas operations was industrial-sourced CO2, and we anticipate this percentage will increase in the future as supportive U.S. government policy and public pressure on industrial CO2 emitters will provide strong incentives for these entities to capture their CO2 emissions.

As we seek to grow our CCUS business and pursue new CCUS opportunities, we have been engaged in discussions with existing and potential third-party industrial CO2 emitters regarding transportation and storage solutions, while also identifying potential future sequestration sites and landowners of those locations. We continue to make progress in these discussions and thus far have signed agreements securing the rights to future sequestration sites which we believe have the potential to store up to 1.4 billion metric tons of CO2. In addition, we have executed several term sheets for the future transportation and sequestration of CO2. During the first quarter of 2022, we capitalized $20.9 million in “CCUS storage sites and related assets” in our Unaudited Condensed Consolidated Balance Sheets, primarily consisting of acquisition costs associated with sequestration sites. While EOR is the only CCUS operation reflected in our historical financial and operational results (as a cost), we believe the incentives offered under Section 45Q of the Internal Revenue Code (“Section 45Q”) or otherwise will drive demand for CCUS and will allow us to collect a fee for the transportation and storage of captured industrial-sourced CO2, including CO2 utilized in our EOR operations. As the enhanced Section 45Q regulations are relatively new, it will likely take several years to construct new capture facilities and for dedicated storage sites to be developed. We believe our existing CO2 pipeline infrastructure, EOR operations, and experience and expertise in working with CO2 all position us to be a leader in this rapidly developing industry.

May 2022 Amendment to Senior Secured Bank Credit Agreement. In early May 2022, we amended our bank credit facility to among other things, (1) increase the borrowing base and lender commitments to $750 million, (2) extend the maturity date to May 4, 2027, (3) modify certain interest rate provisions, and (4) provide additional flexibility regarding our ability to make restricted payments and investments. See further discussion of this amendment under Capital Resources and LiquiditySenior Secured Bank Credit Agreement.


17


Denbury Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Common Share Repurchase Program. On May 5, 2022, we announced Board authorization of a common share repurchase program for up to $250 million of outstanding Denbury common stock. 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. As of May 5, 2022, there have been no repurchases of common stock under this share repurchase program.

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.

As of March 31, 2022, we had $35.0 million of outstanding borrowings and $11.9 million of outstanding letters of credit under our $575 million senior secured bank credit facility, leaving us with $528.1 million of borrowing base availability and approximately $528.6 million of total liquidity including our cash position at March 31, 2022. This liquidity is more than adequate to meet our currently planned operating and capital needs as we currently project our cash flow from operations to significantly exceed our planned capital expenditures in 2022. In early May 2022, we amended our bank credit facility to among other things, increase the borrowing base availability and lender commitments to $750 million (see further discussion of this amendment under Senior Secured Bank Credit Agreement below).

2022 Sources and Uses. During the first quarter of 2022, we generated cash flows from operations of $90.1 million, while incurring capital costs of $79.7 million, consisting of oil and gas development capital expenditures of $57.6 million, CCUS storage sites and related capital expenditures of $20.9 million, and capitalized interest of $1.2 million.

As further discussed below, based on oil price futures as of early May 2022, we currently anticipate funding all of our 2022 capital budget from projected operating cash flow while also generating excess cash flow. As the level of excess cash we expect to generate in 2022 and future periods has increased with the rise in oil prices during the first part of 2022, our Board of Directors recently adopted a share repurchase program for up to $250 million of Denbury’s outstanding common stock. The ultimate level of excess cash we may generate in 2022 and future periods will be highly dependent on oil prices and many other factors, but we currently believe our level of cash flow generation will be adequate to fund our EOR and CCUS strategic priorities while returning capital to our shareholders through our recently announced share repurchase program.

2022 Plans and Capital Budget. Based on our original 2022 budget, we estimated that our full-year 2022 oil and gas development capital spending, excluding capitalized acquisitions and capitalized interest, would be in the range of $290 million to $320 million, which at the midpoint includes approximately $115 million for CCA’s new EOR development (inclusive of an estimated $25 million of pre-production CO2 costs) and $190 million for other tertiary and non-tertiary oil-focused development projects, capitalized internal costs and CO2 sources and pipelines. In addition to our budgeted oil and natural gas capital investments, our budget assumed spending of approximately $50 million in connection with our CCUS strategic priorities, making our combined 2022 projected capital expenditures in the range of $340 million to $370 million. Based on recent cost increases and inflationary pressures, we now expect that our 2022 capital expenditures will be toward the upper end of our budgeted range.


18


Denbury Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Capital Expenditure Summary. The following table reflects incurred capital expenditures for the three months ended March 31, 2022 and 2021:
Three Months Ended
March 31,
In thousands20222021
Capital expenditure summary(1)
 
CCA EOR field expenditures(2)
$17,722 $
CCA CO2 pipelines
2,191 48 
CCA tertiary development19,913 57 
Non-CCA tertiary and non-tertiary fields29,363 12,422 
  CO2 sources and other CO2 pipelines
730 — 
  Capitalized internal costs(3)
7,600 7,600 
Oil & gas development capital expenditures57,606 20,079 
CCUS storage sites and related capital expenditures20,949 — 
Acquisitions of oil and natural gas properties(4)
371 10,665 
Capitalized interest1,158 1,083 
Total capital expenditures$80,084 $31,827 

(1)Capital expenditures in this summary are presented on an as-incurred basis (including accruals), and are $8.7 million lower than the capital expenditures in the Unaudited Condensed Consolidated Statements of Cash Flows which are presented on a cash basis.
(2)Includes pre-production CO2 costs associated with the CCA EOR development project totaling $2.8 million during the first quarter of 2022.
(3)Includes capitalized internal acquisition, exploration and development costs and pre-production tertiary startup costs.
(4)Primarily consists of working interest positions in the Wind River Basin enhanced oil recovery fields acquired on March 3, 2021.

Supply Chain Issues and Potential Cost Inflation. Recent worldwide and U.S. supply chain issues, together with rising commodity prices and tight labor markets in the U.S., have increased our costs during 2022 and may continue to do so in future periods. Most of the cost inflation pressures we experienced during late 2021 were tied to rising fuel and power costs in our operations, but were not material to our 2021 financial results. Our 2022 operational budget considered anticipated inflation and we have taken steps to build our on-hand supply stock for items frequently used in our operations to address possible supply chain disruptions. Based on cost increases and shortages experienced across the industry thus far in 2022, we anticipate additional increases in the cost of, and demand for, goods and services and wages in our operations during the remainder of 2022 which could negatively impact our results of operations and cash flows in future periods.

Senior Secured Bank Credit Agreement. In September 2020, we entered into a $575 million bank credit agreement for a senior secured revolving credit facility with JPMorgan Chase Bank, N.A., as administrative agent, and other lenders party thereto (the “Bank Credit Agreement”). On May 4, 2022, we entered into a Second Amendment to the Bank Credit Agreement, which among other things:

Increases the borrowing base and lender commitments from $575 million to $750 million;
Extends the maturity date from January 30, 2024 to May 4, 2027;
Modifies the interest provisions on loans under the Bank Credit Agreement to (1) reduce the applicable margin for alternate base rate loans from 2% to 3% per annum to 1.5% to 2.5% per annum and (2) replace provisions referencing LIBOR loans with Secured Overnight Financing Rate loans, with an applicable margin of 2.5% to 3.5% per annum; and
Permits us to pay dividends on our common stock and make other unlimited restricted payments and investments so long as (1) no event of default or borrowing base deficiency exists; (2) our total leverage ratio is 1.5 to 1 or lower; and (3) availability under the Bank Credit Agreement is at least 20% of the borrowing base.


19


Denbury Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Availability under the Bank Credit Agreement is subject to a borrowing base, which is redetermined semiannually on or around May 1 or November 1 of each year, with our next scheduled redetermination around November 1, 2022. The borrowing base is adjusted at the lenders’ discretion and is based, in part, upon external factors over which we have no control. If our outstanding debt under the Bank Credit Agreement exceeds the then-effective borrowing base, we would be required to repay the excess amount over a period not to exceed six months.

The Bank Credit Agreement also limits our ability to, among other things, incur and repay other indebtedness; grant liens; engage in certain mergers, consolidations, liquidations and dissolutions; engage in sales of assets; make acquisitions and investments; make other restricted payments (including redeeming, repurchasing or retiring our common stock); and enter into commodity derivative agreements, in each case subject to customary exceptions. 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, 2022, our ratio of consolidated total debt to consolidated EBITDAX was 0.09 to 1.0 (with a maximum permitted ratio of 3.5 to 1.0) and our current ratio was 2.53 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 4, 2022, 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 is qualified by the express language and defined terms contained in the Bank Credit Agreement and amendments thereto, each of which is filed as an exhibit to our periodic reports filed with the SEC. The Second Amendment to the Credit Agreement, which is attached as Exhibit 10(d) to this Form 10-Q, contains the full text of the current version of the Bank Credit Agreement inclusive of all changes made by virtue of both the First and Second Amendments thereto.

Commitments and Obligations. We have 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 commitments and obligations consist of those detailed as of December 31, 2021, 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.

Off-Balance Sheet Arrangements. Our off-balance sheet arrangements include obligations for various development and exploratory expenditures that arise from our normal capital expenditure program or from other transactions common to our industry, none of which are recorded on our balance sheet.  In addition, in order to recover our undeveloped proved reserves, we must also fund the associated future development costs estimated in our proved reserve reports.


20


Denbury Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
RESULTS OF OPERATIONS
Certain of our operating results and statistics for the comparative three months ended March 31, 2022 and 2021 are included in the following table:
Three Months Ended
March 31,
In thousands, except per-share and unit data20222021
Financial results
Net loss(1)
$(872)$(69,642)
Net loss per common share – basic(1)
(0.02)(1.38)
Net loss per common share – diluted(1)
(0.02)(1.38)
Net cash provided by operating activities90,143 52,656
Average daily sales volumes 
Bbls/d45,466 46,007 
Mcf/d8,753 8,102 
BOE/d(2)
46,925 47,357 
Oil and natural gas sales 
Oil sales
$381,242 $233,044 
Natural gas sales3,669 2,401 
Total oil and natural gas sales
$384,911 $235,445 
Commodity derivative contracts(3)
 
Payment on settlements of commodity derivatives$(93,057)$(38,453)
Noncash fair value losses on commodity derivatives(99,662)(77,290)
Commodity derivatives expense$(192,719)$(115,743)
Unit prices – excluding impact of derivative settlements 
Oil price per Bbl$93.17 $56.28 
Natural gas price per Mcf4.66 3.29 
Unit prices – including impact of derivative settlements(3)
 
Oil price per Bbl$70.43 $47.00 
Natural gas price per Mcf4.66 3.29 
Oil and natural gas operating expenses 
Lease operating expenses$117,828 $81,970 
Transportation and marketing expenses4,645 7,797 
Production and ad valorem taxes30,443 17,895 
Oil and natural gas operating revenues and expenses per BOE 
Oil and natural gas revenues$91.14 $55.24 
Lease operating expenses27.90 19.23 
Transportation and marketing expenses1.10 1.83 
Production and ad valorem taxes7.21 4.20 
CO2 – revenues and expenses
 
CO2 sales and transportation fees
$13,422 $9,228 
CO2 operating and discovery expenses
(2,817)(993)
CO2 revenue and expenses, net
$10,605 $8,235 

(1)Includes a pre-tax full cost pool ceiling test write-down of our oil and natural gas properties of $14.4 million during the first quarter of 2021.
(2)Barrel of oil equivalent using the ratio of one barrel of oil to six Mcf of natural gas (“BOE”).
(3)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 2021 and for the first quarter of 2022 is shown below:
 Average Daily Sales Volumes (BOE/d)
First
Quarter
Fourth
Quarter
Third
Quarter
Second
Quarter
First
Quarter
Operating Area20222021202120212021
Tertiary oil sales volumes    
Gulf Coast region
Delhi2,675 2,731 2,859 2,931 2,925 
Hastings4,430 4,212 4,343 4,487 4,226 
Heidelberg3,653 3,797 3,895 3,942 4,054 
Oyster Bayou3,745 4,039 3,942 3,791 3,554 
Tinsley3,015 3,353 3,390 3,455 3,424 
Other(1)
5,498 5,801 5,907 6,074 6,098 
Total Gulf Coast region23,016 23,933 24,336 24,680 24,281 
Rocky Mountain region
Bell Creek4,474 4,331 4,330 4,394 4,614 
Other(2)
4,746 4,551 4,703 4,378 2,573 
Total Rocky Mountain region9,220 8,882 9,033 8,772 7,187 
Total tertiary oil sales volumes32,236 32,815 33,369 33,452 31,468 
Non-tertiary oil and gas sales volumes
Gulf Coast region
Total Gulf Coast region3,630 3,929 3,763 3,415 3,621 
Rocky Mountain region
Cedar Creek Anticline9,721 10,784 11,182 10,918 11,150 
Other(3)
1,338 1,354 1,368 1,348 1,118 
Total Rocky Mountain region11,059 12,138 12,550 12,266 12,268 
Total non-tertiary sales volumes14,689 16,067 16,313 15,681 15,889 
Total sales volumes46,925 48,882 49,682 49,133 47,357 

(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 Big Sand Draw and Beaver Creek EOR fields (collectively “Wind River Basin”) acquired on March 3, 2021, as well as 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 2022 averaged 46,925 BOE/d, including 32,236 Bbls/d from tertiary properties and 14,689 BOE/d from non-tertiary properties. This sales volume represents a decrease of 1,957 BOE/d (4%) compared to sales levels in the fourth quarter of 2021 and was essentially flat with first quarter of 2021 sales volumes. The decrease on a sequential-quarter basis was primarily attributable to (a) weather-related downtime and downtime coinciding with activities to progress our tertiary development at CCA and (b) production decline due to low levels of capital investment and development spending in recent years (excluding the new EOR development at CCA).

Our sales volumes during the three months ended March 31, 2022 were 97% oil, consistent with our sales during the same prior-year period.


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, 2022 increased 63% compared to these revenues for the same period in 2021.  The changes in our oil and natural gas revenues are due to higher realized commodity prices (excluding any impact of our commodity derivative contracts), as reflected in the following table:
Three Months Ended
March 31,
2022 vs. 2021
In thousandsIncrease (Decrease) in RevenuesPercentage Increase (Decrease) in Revenues
Change in oil and natural gas revenues due to:  
Decrease in sales volumes$(2,146)(1)%
Increase in realized commodity prices151,612 64 %
Total increase in oil and natural gas revenues$149,466 63 %

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, 2022 and 2021:
Three Months Ended
March 31,
 20222021
Average net realized prices  
Oil price per Bbl
$93.17 $56.28 
Natural gas price per Mcf
4.66 3.29 
Price per BOE
91.14 55.24 
Average NYMEX differentials  
Gulf Coast region
Oil per Bbl
$(1.37)$(1.37)
Natural gas per Mcf
0.16 0.68 
Rocky Mountain region
Oil per Bbl
$(1.38)$(1.80)
Natural gas per Mcf
0.08 0.49 
Total Company
Oil per Bbl
$(1.37)$(1.54)
Natural gas per Mcf
0.11 0.58 

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 $1.37 per Bbl during the first quarter of 2022, consistent with the first quarter of 2021 and a slight improvement from a negative $1.41 per Bbl during the fourth quarter of 2021. NYMEX WTI oil prices continued to strengthen during 2022, including the pricing for our Gulf Coast grades relative to NYMEX WTI index prices. For our crude oil sold under Light Louisiana Sweet (“LLS”) index prices, the LLS-to-NYMEX differential averaged a positive $2.16 per Bbl on a trade-month basis for the first quarter of 2022, compared to a positive $2.02 per Bbl differential in the first quarter of 2021 and a positive $0.88 per Bbl in the fourth quarter of 2021.


23


Denbury Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Rocky Mountain Region. NYMEX oil differentials in the Rocky Mountain region averaged $1.38 per Bbl and $1.80 per Bbl below NYMEX during the first quarters of 2022 and 2021, respectively, and $0.95 per Bbl below NYMEX during the fourth quarter of 2021. Differentials in the Rocky Mountain region tend to fluctuate with regional supply and demand trends and can fluctuate significantly on a month-to-month basis due to weather, refinery or transportation issues, and Canadian and U.S. crude oil price index volatility.

CO2 Revenues and Expenses

We sell a portion of the CO2 we own to third-party industrial users at various contracted prices primarily under long-term contracts. We recognize the revenue received on these CO2 sales as “CO2 sales and transportation fees” with the corresponding costs recognized as “CO2 operating and discovery expenses” in our Unaudited Condensed Consolidated Statements of Operations. CO2 sales and transportation fees were $13.4 million during the three months ended March 31, 2022, compared to $9.2 million during the three months ended March 31, 2021. The increase from the prior-year period was primarily due to new contracts and an increase in CO2 sales volumes.

Oil Marketing Revenues and Purchases

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

Commodity Derivative Contracts

The following table summarizes the impact our crude oil derivative contracts had on our operating results for the three months ended March 31, 2022 and 2021:
Three Months Ended
 March 31,
In thousands20222021
Payment on settlements of commodity derivatives$(93,057)$(38,453)
Noncash fair value losses on commodity derivatives(99,662)(77,290)
Total expense$(192,719)$(115,743)

Changes in our commodity derivatives expense were primarily related to the expiration of commodity derivative contracts, new commodity derivative contracts entered into for future periods, and to the changes in oil futures prices between the first quarter of 2021 and 2022. The benefit of the significant increase in our oil sales during 2022 over 2021 sales levels due to rising oil prices has been offset by payments on settlements of commodity derivative contracts, principally due to the strike prices of our fixed-price swaps. During the first quarter of 2022, we paid $93.1 million upon expiration of commodity derivative contracts, reflecting the very large fluctuations in oil prices preceding and after the invasion by Russia of Ukraine heightening supply uncertainty and oil market volatility.

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 2023 using NYMEX fixed-price swaps and costless collars. See Note 6, Commodity Derivative Contracts, to the Unaudited Condensed Consolidated Financial Statements for additional details of our outstanding commodity

24


Denbury Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
derivative contracts as of March 31, 2022, and Item 3, Quantitative and Qualitative Disclosures about Market Risk below for additional discussion. In addition, the following table summarizes our commodity derivative contracts as of May 4, 2022:
2Q 20222H 20221H 20232H 2023
WTI NYMEXVolumes Hedged (Bbls/d)15,5009,5004,5002,000
Fixed-Price Swaps
Swap Price(1)
$49.01$57.52$74.88$76.80
WTI NYMEXVolumes Hedged (Bbls/d)11,00011,50012,5007,000
Collars