Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis should be read in conjunction with our consolidated financial statements and Notes thereto included in Item 8, Financial Statements and Supplementary Information . 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 this 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 from our forward-looking statements. For a discussion of the financial results for the fiscal year ended December 31, 2020, see Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations , of our Annual Report on Form 10-K for the fiscal year ended December 31, 2021, as filed with the Securities and Exchange Commission (“SEC”) on February 25, 2022.
As a result of the Company’s emergence from bankruptcy and adoption of fresh start accounting on September 18, 2020 (the “Emergence Date”), certain values and operational results of the consolidated financial statements subsequent to September 18, 2020 are not comparable to those in the Company’s consolidated financial statements prior to, and including September 18, 2020. References to “Successor” relate to the results of operations of the Company subsequent to September 18, 2020, and references to “Predecessor” relate to the results of operations of the Company prior to, and including, September 18, 2020.
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 CO 2 enhanced oil recovery (“EOR”) and the emerging carbon capture, utilization, and storage (“CCUS”) industry, supported by the Company’s CO 2 EOR technical and operational expertise and its extensive CO 2 pipeline infrastructure. The utilization of captured industrial-sourced CO 2 in EOR significantly reduces the carbon footprint of the oil that Denbury produces, making the Company’s Scope 1 and 2 CO 2 e 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 a consumer’s use of the oil and natural gas we sell (defined as Category 11 emissions by the Greenhouse Gas Protocol).
Oil Price Impact on Our Business. Our financial results are significantly impacted by changes in oil prices, as 97% of our sales volumes in 2022 were oil. Changes in oil prices impact all aspects of our business; most notably our cash flows from operations, revenues, capital allocation and budgeting decisions, and oil and natural gas reserves volumes. Oil prices have historically been volatile and can fluctuate significantly over short periods of time. For example, average NYMEX WTI oil prices increased from the mid-$70s per Bbl range in the fourth quarter of 2021 to an average of approximately $109 per Bbl during the second quarter of 2022 before declining to an average of approximately $83 per Bbl during the fourth quarter of 2022. The increases in oil prices from 2021 levels were largely due to increased demand since the height of the COVID-19 coronavirus (“COVID-19”) pandemic in 2020 and 2021, plus the effect on energy markets and prices of the Russian attacks on Ukraine.
The table below outlines selected financial items and sales volumes, along with changes in our realized oil prices, before and after commodity derivative impacts, over the last three years:
Year Ended December 31,
In thousands, except per-unit data
Oil, natural gas, and related product sales
Receipt (payment) on settlements of commodity derivatives
Oil, natural gas, and related product sales and commodity settlements, combined
Average daily sales (BOE/d)
Average net realized prices
Oil price per Bbl - excluding impact of derivative settlements
Oil price per Bbl - including impact of derivative settlements
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As shown in the table above, our oil and natural gas revenues have increased dramatically since 2020 due to increases in oil prices. However, the benefit of the increase in revenues during 2021 and 2022 was muted by the impact of higher cash payments on our commodity derivative contracts, which contracts were generally put in place as a requirement under our bank credit facility shortly after we exited bankruptcy. Beginning in the second half of 2022, less of our production was hedged, and our hedges were at more favorable prices and with a greater mix of collars, allowing us to realize a greater portion of increased oil prices. We paid $315.8 million during the year ended December 31, 2022 related to the settlement of commodity derivative contracts.
Comparative Financial Results and Highlights. We recognized net income of $480.2 million, or $8.83 per diluted common share during 2022, and net income of $56.0 million, or $1.04 per diluted common share during 2021. Drivers of the comparative operating results between 2022 and 2021 include the following:
• Oil and natural gas revenues increased by $418.7 million (36%) in 2022, all attributable to higher commodity prices, slightly offset by lower sales volumes;
• Commodity derivative expense decreased by $174.2 million consisting of a $212.8 million improvement in noncash fair value changes between periods ($137.0 million gain during 2022 compared to a $75.7 million loss during 2021), partially offset by a $38.6 million increase in cash payments upon derivative contract settlements ($315.8 million in payments during 2022 compared to $277.2 million in payments during 2021).
• Lease operating expenses increased by $77.9 million (18%), primarily due to higher power and fuel costs and workover costs from inflation and higher activity levels; and
• Taxes other than income increased $40.1 million primarily due to an increase in production taxes resulting from higher oil and gas revenues.
Common Share Repurchase Program. In early May 2022, our Board of Directors authorized a common share repurchase program for up to $250 million of outstanding Denbury common stock. During June and July 2022, the Company repurchased 1.6 million 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.
Cedar Creek Anticline CO 2 EOR Development. In early February 2022, we commenced CO 2 injection in the first phase of our CCA EOR project. In order to stay ahead of potential supply chain delays, and to prepare for earlier processing of CO 2 based on CO 2 injection levels being at the high end of our expectations, we increased capital investment in the second half of 2022 at CCA to accelerate our procurement of compression equipment and construction of CO 2 recycle facilities to ensure facilities are in place to handle anticipated production from the field. We continue to expect tertiary oil production response from CCA in the second half of 2023. In addition, drilling and facility construction at the Company’s Pennel CO 2 pilot, in advance of Phase 2 development of CCA, commenced during the third quarter.
Advancing Carbon Capture, Utilization and Storage Activities. CCUS is a process that captures CO 2 from industrial sources and either reuses or stores the CO 2 in geologic formations in order to prevent its release into the atmosphere. We utilize CO 2 from industrial sources in our EOR operations, and our extensive CO 2 pipeline infrastructure and operations, particularly in the Gulf Coast, are strategically located in close proximity to both large sources of industrial emissions and geological formations well-suited for permanent CO 2 storage. During the year ended December 31, 2022, approximately 40% of the CO 2 utilized in our operated oil iand gas operations was industrial-sourced CO 2 . This compares to 33% utilized during the year ended December 31, 2021. We believe that the assets and technical expertise required for CCUS are highly aligned with our existing CO 2 EOR operations, providing us with a significant advantage and opportunity to lead in the emerging CCUS industry, as the building of a permanent carbon capture and storage business by others requires both time and capital to build assets such as those we own and have been operating for years.
We have been seeking to build our CCUS business and pursue new CCUS opportunities on two fronts: first, we have been engaged with existing and potential third-party industrial CO 2 emitters regarding CO 2 transportation and storage solutions under long term agreements; second, we have been identifying and securing potential future storage sites for permanent CO 2 storage. In 2023, our goals include continuing to capture more of the emissions market and adding storage sites to our portfolio. We also plan to drill stratigraphic wells, submit additional Class VI storage permits for our contracted sites, and purchase long-lead
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time items for network buildout. We currently have signed agreements covering the potential future transportation and storage of up to 20 Mmtpa from the planned capture of CO 2 emissions from existing and proposed industrial plants. On the sequestration front, we have also signed agreements securing the rights to seven future storage sites which we believe have the potential to store up to 2 billion metric tons of CO 2 . Initial CCUS transportation and/or storage volumes are anticipated in 2025 and we are projecting those volumes could increase to an average of 50–70 Mmtpa by 2030.
While our use of CO 2 in EOR is currently reflected in our historical financial and operational results (as a cost), we believe the incentives offered under Section 45Q of the Internal Revenue Code and the expansion of those incentives under the August 2022 Inflation Reduction Act will drive demand for CCUS and allow us to collect a fee for the transportation and storage of captured industrial-sourced CO 2 . Although we believe our first revenues associated with the storage of CO 2 will likely occur in 2025, we are currently incurring costs to engineer, conduct feasibility studies and otherwise develop and permit storage sites, along with payments to pore space owners, and will continue to advance those efforts over the next several years. In addition, we will need to expand our CO 2 pipeline network to connect to emission sites and storage sites. During the year ended December 31, 2022, we capitalized $65.0 million in “CCUS storage sites and related assets” in our Consolidated Balance Sheets, primarily consisting of acquisition costs associated with storage sites. On a long-term forward-looking basis, we currently estimate that cumulative capital investments for CCUS projects and initiatives between 2023 and 2030 will total between $1.6 billion and $2 billion with an average of $200 million to $250 million per year, and will be focused on CO 2 storage site development and pipeline costs. The highest investment period is expected in 2024 and 2025 as we plan to continue construction and development of multiple sequestration sites, including drilling Class VI injection wells and installing pipeline extensions to connect to storage sites and industrial emissions. Currently, we anticipate we can internally fund CCUS capital expenditures from free cash flows through 2030 assuming a minimum of $60 NYMEX WTI oil prices, although we may consider alternative financing options as a supplemental source of capital. As early as 2026 or 2027, we expect the CCUS business will be generating cash flows that could internally fund its development.
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 year ended December 31, 2022, we generated $520.7 million in cash flow from operations, invested net cash of $427.9 million in oil and gas and CCUS activities, and utilized net cash of $95.3 million in financing activities, primarily associated with $100.0 million of Denbury common stock purchased under the Company’s stock repurchase program.
As of December 31, 2022, we had $29.0 million of outstanding borrowings and $10.1 million of outstanding letters of credit under our $750 million senior secured bank credit facility, leaving us with $710.9 million of borrowing base availability. This liquidity is more than adequate to meet our currently planned operating and capital needs. As further discussed below, based on oil price futures as of the middle of February 2023, we currently anticipate funding all of our 2023 capital budget from projected operating cash flow.
Capital Expenditure Summary. For purposes of tracking and comparing our capital budget to capital expenditure activity, we utilize data reflective of when capital expenditures are incurred, which is generally different than what is reported
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in our cash flow statements, which reflects when cash is actually paid. The information included in the following table reflects incurred capital expenditures for the years ended December 31, 2022, 2021 and 2020:
Year Ended December 31,
In thousands
Capital expenditure summary (1)
CCA EOR field expenditures (2)
CCA CO 2 pipelines
CCA tertiary development
Non-CCA tertiary and non-tertiary fields
CO 2 sources, other CO 2 pipelines and other
Capitalized internal costs (3)
Oil and gas development capital expenditures
CCUS storage sites and related capital expenditures
Oil and gas and CCUS development capital expenditures
Capitalized interest
Acquisitions of oil and natural gas properties (4)
Investment in Clean Hydrogen Works (5)
Total capital expenditures
(1) Capital expenditures in this summary are presented on an as-incurred basis (including accruals), and are $27.3 million higher, $35.7 million higher, and $10.9 million lower than the capital expenditures in the Consolidated Statements of Cash Flows for the years ended December 31, 2022, 2021, and 2020, respectively, which are presented on a cash paid basis.
(2) Includes pre-production CO 2 costs associated with the CCA EOR development project totaling $23.1 million during the year ended December 31, 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.
(5) Represents an investment made during the third quarter of 2022 in the project development company (“Clean Hydrogen Works”) of a planned blue hydrogen/ammonia multi-block facility, while also signing a definitive agreement for the transportation and storage of CO 2 for the first two blocks of the proposed plant. The investment is included in “Other assets” in the Consolidated Balance Sheet as of December 31, 2022. We have committed to invest another $10 million when certain project milestones are achieved, which is currently projected to occur in 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 beginning in late 2021 and continued throughout 2022. Although the level of inflationary cost increases and supply chain issues has 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.
2023 Plans and Capital Budget. We estimate 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. At the combined midpoint of $510 million, total capital expenditures are 19% higher than expenditures in 2022, with the expected 2023 increases driven entirely by higher CCUS capital expenditures, which are primarily for the development of dedicated CO 2 storage sites and preparation for expansion of our CO 2 pipelines. 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.
Based on the Company’s projections, including estimated production, costs, oil price differentials and other assumptions, we currently anticipate our 2023 cash flows from operations, excluding working capital changes, will approximately meet or exceed our budgeted 2023 capital expenditures and planned asset retirement obligation activities, assuming oil prices of
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approximately $75 per Bbl in 2023. Also, at December 31, 2022, we had $710.9 million of availability under our bank credit facility, which we believe is more than adequate to cover any near-term liquidity needs.
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”). 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.
On May 4, 2022, we entered into a Second Amendment to the Bank Credit Agreement, which among other things:
• Increased the borrowing base and lender commitments from $575 million to $750 million;
• Extended the maturity date from January 30, 2024 to May 4, 2027;
• Modified the interest provisions on loans under the Bank Credit Agreement to (1) reduce the applicable margin for alternate base rate loans from 2% to 3% per annum to 1.5% to 2.5% per annum and (2) replace provisions referencing LIBOR loans with Secured Overnight Financing Rate loans, with an applicable margin of 2.5% to 3.5% per annum; and
• Permitted us to pay dividends on and repurchase 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.
As part of our Fall 2022 semiannual borrowing base redetermination, the borrowing base and lender commitments for our Bank Credit Agreement were reaffirmed at $750 million, with our next scheduled redetermination around May 1, 2023.
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 SOFR loans 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. 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 December 31, 2022, our ratio of consolidated total debt to consolidated EBITDAX was 0.05 to 1.0 (with a maximum permitted ratio of 3.5 to 1.0) and our current ratio was 2.70 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 February 22, 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 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
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Securities and Exchange Commission (“SEC”). The Second Amendment to the Credit Agreement, which is attached as Exhibit 10(d) to the Form 10-Q filed on May 6, 2022, contains the full text of the current version of the Bank Credit Agreement inclusive of all changes made by virtue of both the First and Second Amendments thereto.
Commitments, Obligations and 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 CO 2 captured from industrial sources, CO 2 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 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, we entered into storage contracts to secure rights to underground pore space in anticipation of future CCUS operations. Noncancelable commitments under those contracts total $4 million. 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. Certain of these capital spending plans are further described in 2023 Plans and Capital Budget above. For a further discussion of our future development costs, see Supplemental Oil and Natural Gas Disclosures (Unaudited) to the consolidated financial statements.
Our periodic obligations include operational expenses that we anticipate being paid out of our cash flow from sale of production, plus the capital expenditures detailed above. In addition to these periodic expenditures, we have various future cash commitments under contracts in place as of December 31, 2022. The most material of these commitments within the next 12 months include:
• Approximately $52.0 million under contracts for the purchase of CO 2 captured from industrial sources and for processing fees related to our overriding royalty interest in the CO 2 at LaBarge Field, both of which are used in our tertiary recovery activities, assuming a $75 per Bbl NYMEX oil price. The commitment level declines in 2023 and again in 2028 due to the expiration of the current term of certain industrial-CO 2 purchase commitments (see Note 14, Commitments and Contingencies , to the consolidated financial statements for further discussion); and
• Approximately $6 million in operating lease obligations (see Note 5, Leases , to the consolidated financial statements for further discussion).
In addition to these commitments, we have recurring expenditures for such things as accounting, engineering and legal fees; software maintenance; subscriptions; and other overhead-type items. Normally these expenditures do not change materially on an aggregate basis from year to year and are part of our general and administrative expenses. Most of these recurring expenditures could be quickly canceled with regard to any specific vendor, even though the expense itself may be required for our ongoing normal operations. Other commitments include certain transportation agreements and well-related costs. Our longer-term commitments that extend beyond the next 12 months include the following:
• Obligations and periodic interest payments under our senior secured bank credit facility, which matures on May 4, 2027, and of which $29.0 million of borrowings and $10.1 million of letters of credit were outstanding as of December 31, 2022; and
• Asset retirement obligations related to future costs associated with plugging and abandoning our oil, natural gas and CO 2 wells, removing equipment and facilities from leased acreage, and returning land to its original condition (see Note 6, Asset Retirement Obligations , to the consolidated financial statements).
As detailed throughout this report, the largest determinant of our cash flow is the oil price we receive. Oil prices and cash flow are highly impacted by worldwide oil supply and fluctuations in demand due to economic activity, which volatility we attempt to offset to some extent with our hedging program. The variability of proceeds from the sale of our production is partially offset by similar directional variances in certain expenses, including a portion of our lease operating expenses and production taxes, as these expenses correlate to some degree with changes in oil prices.
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FINANCIAL OVERVIEW OF TERTIARY OPERATIONS
Our tertiary operations represent a significant portion of our overall operations. The economics of a tertiary field and the related impact on our financial statements differ from a conventional oil and gas play and are explained further below.
While it is difficult to accurately forecast future production, we believe our tertiary recovery operations provide significant long-term production growth potential at reasonable return metrics, with relatively low risk, assuming crude oil prices are at levels that support the development of those projects. We have been developing tertiary oil properties for over 23 years, and the financial impact of such operations is reflected in our historical financial statements. The summary below highlights our observations regarding how tertiary operations have impacted our financial statements.
Finding and Development Costs. We currently expect finding and development costs (including future development and abandonment costs but excluding CO 2 pipeline infrastructure capital expenditures) over the life of each field to be competitive with the industry average costs for other oil properties. See the definition of finding and development costs in the Glossary and Selected Abbreviations .
Timing of Capital Costs. When initiating a new tertiary flood, there generally is a delay between the initial capital expenditures and the resulting production increases. We must build facilities, and often a CO 2 pipeline to the field, before CO 2 flooding can commence, and it usually takes six to twelve months before the field responds to the injection of CO 2 (i.e., oil production commences). For certain fields such as those in CCA, we estimate it could take up to 18 months or longer for a tertiary production response to occur. Further, we may spend significant amounts of capital before we can recognize any proved reserves from fields we flood and, even after a field has proved reserves, significant amounts of additional capital will usually be required to fully develop the field.
Recognition of Proved Reserves. In order to recognize proved tertiary oil reserves, we must either demonstrate production resulting from the tertiary process or the field must be analogous to an existing tertiary flood. The magnitude of proved reserves that we can book in any given year will depend on our progress with new floods, the timing of the production response from new floods and the performance of our existing floods.
Production Rates. The production rate at a tertiary flood can vary from quarter to quarter, as a tertiary field’s production may increase rapidly when wells respond to the CO 2 , plateau temporarily, and then resume growth as additional areas of the field are developed. During a tertiary flood life cycle, facility capacity is increased from time to time, which occasionally requires temporary shutdowns during installation, thereby causing temporary declines in production. We also find it difficult to precisely predict when any given well will respond to the injected CO 2 , as the CO 2 seldom travels through the rock consistently due to heterogeneity in the oil-bearing formations. We find all of these fluctuations to be normal and generally expect oil production at a tertiary field to increase over time until the field is fully developed, albeit sometimes in inconsistent patterns.
Operating Costs. Tertiary projects may be more expensive to operate than traditional industry operations because of the cost of injecting and recycling the CO 2 (primarily due to the cost of the CO 2 and the significant energy requirements to re-compress the CO 2 back into a near-liquid state for re-injection purposes). The costs of our CO 2 and the electricity required to recycle and inject this CO 2 comprise over half of our typical tertiary operating expenses. Since these costs vary along with commodity and commercial electricity prices, they are highly variable and will increase in a high-commodity-price environment and decrease in a low-price environment. The cost of purchasing and/or producing CO 2 for use in tertiary floods is allocated to our tertiary oil fields and recorded as lease operating expenses (following the commencement of tertiary oil production) at the time the CO 2 is injected. These costs have historically represented approximately 20% to 25% of the total operating costs for our tertiary operations. Since we expense all of the operating costs to produce and inject our CO 2 (following the commencement of tertiary oil production), operating costs per barrel for a new flood will be higher at the inception of CO 2 injection projects because of minimal related oil production at that time.
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RESULTS OF OPERATIONS
Financial and Operating Results Tables
Certain of our financial results for our Successor and Predecessor periods are included in the following table.
Successor
Predecessor
Year Ended
Dec. 31, 2022
Year Ended
Dec. 31, 2021
Period from
Sept. 19, 2020 through
Dec. 31, 2020
Period from
Jan. 1, 2020 through
Sept. 18, 2020
In thousands, except per-share data
Financial results
Net income (loss) (1)
Net income (loss) per common share – basic (1)
Net income (loss) per common share – diluted (1)
Net cash provided by operating activities
(1) Includes a pre-tax full cost pool ceiling test write-down of our oil and natural gas properties of $14.4 million for the year ended December 31, 2021, $1.0 million for the Successor period September 19, 2020 through December 31, 2020, and $996.7 million for the Predecessor period January 1, 2020 through September 18, 2020. In addition, the Predecessor period January 1, 2020 through September 18, 2020 includes reorganization adjustments, net totaling $850.0 million.
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Certain of our operating results and statistics for each of the last three years are included in the following table.
Year Ended December 31,
In thousands, except per-unit data
Average daily sales volumes
Bbls/d
Mcf/d
BOE/d
Oil and natural gas sales
Oil sales
Natural gas sales
Total oil and natural gas sales
Commodity derivative contracts (1)
Receipt (payment) on settlements of commodity derivatives
Noncash fair value losses on commodity derivatives
Commodity derivatives income (expense)
Unit prices – excluding impact of derivative settlements
Oil price per Bbl
Natural gas price per Mcf
Unit prices – including impact of derivative settlements (1)
Oil price per Bbl
Natural gas price per Mcf
Oil and natural gas operating expenses
Lease operating expenses
Transportation and marketing expenses
Production and ad valorem taxes
Oil and natural gas operating revenues and expenses per BOE
Oil and natural gas revenues
Lease operating expenses
Transportation and marketing expenses
Production and ad valorem taxes
CO 2 – revenues and expenses
CO 2 sales and transportation fees
CO 2 operating and discovery expenses
CO 2 revenue and expenses, net
(1) See also Commodity Derivative Contracts below and Market Risk Management for information concerning our commodity derivative transactions.
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Sales Volumes
Average daily sales volumes by area for 2022, 2021 and 2020, and for each of the quarters of 2022, are shown below:
Average Daily Sales Volumes (BOE/d)
2022 Quarters
Year Ended December 31,
Operating Area
First
Quarter
Second
Quarter
Third
Quarter
Fourth
Quarter
Tertiary oil sales volumes
Gulf Coast region
Delhi
Hastings
Heidelberg
Oyster Bayou
Tinsley
Other (1)
Total Gulf Coast region
Rocky Mountain region
Bell Creek
Wind River Basin
Other (2)
Total Rocky Mountain region
Total tertiary oil sales volumes
Non-tertiary oil and gas sales volumes
Gulf Coast region
Total Gulf Coast region
Rocky Mountain region
Cedar Creek Anticline
Other (3)
Total Rocky Mountain region
Total non-tertiary sales volumes
Total continuing sales volumes
Property sales
Gulf Coast Working Interests Sale (4)
Total sales volumes
(1) Includes Brookhaven, Cranfield, Eucutta, Little Creek, Mallalieu, Martinville, McComb, Soso and West Yellow Creek fields.
(2) Includes Salt Creek and Grieve fields.
(3) Includes non-tertiary sales volumes from Wind River Basin, as well as Hartzog Draw and Bell Creek fields.
(4) Includes non-tertiary sales related to the March 2020 sale of 50% of our working interests in Webster, Thompson, Manvel, and East Hastings fields (the “Gulf Coast Working Interests Sale”).
Total sales volumes during 2022 averaged 46,809 BOE/d, including 32,004 Bbls/d from tertiary properties and 14,805 BOE/d from non-tertiary properties. This total sales volume represents a decrease of 1,961 BOE/d (4%) compared to 2021 total sales volumes. The year-over-year decline was primarily attributable to natural field declines associated with low levels of development spending in recent years (excluding new CO 2 EOR development at CCA), partially offset by increased production at Wind River Basin, which was acquired in March 2021, due both to the inclusion in 2022 of a full year of production as well
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as post-acquisition development activities, and increases at Grieve Field as a result of CO 2 injection response. Our production during 2022 was 97% oil, consistent with 2021 and 2020.
Based on our capital spending plans, we currently anticipate 2023 average daily production will be between 46,000 BOE/d and 49,000 BOE/d, which, at its midpoint is 691 BOE/d higher than our average production in 2022. We anticipate first production from the CCA CO 2 EOR development in the second half of 2023, which is the primary driver for our expected production increase in 2023.
Oil and Natural Gas Revenues
Oil and natural gas revenues increased 36% between 2021 and 2022 and increased 67% between 2020 and 2021. The changes in our oil and natural gas revenues are due to changes in production quantities and realized commodity prices (excluding any impact of our commodity derivative contracts), as reflected in the following table:
Year Ended December 31,
Year Ended December 31,
In thousands
Increase (Decrease) in Revenues
Percentage Increase (Decrease) in Revenues
Increase (Decrease) in Revenues
Percentage Increase (Decrease) in Revenues
Change in oil and natural gas revenues due to:
Decrease in production
Increase in commodity prices
Total increase in oil and natural gas revenues
Excluding any impact of our commodity derivative contracts, our average net realized commodity prices and NYMEX differentials were as follows during 2022, 2021 and 2020:
Year Ended December 31,
Average net realized prices
Oil price per Bbl
Natural gas price per Mcf
Price per BOE
Average NYMEX differentials
Gulf Coast region
Oil per Bbl
Natural gas per Mcf
Rocky Mountain region
Oil per Bbl
Natural gas per Mcf
Total Company
Oil per Bbl
Natural gas per Mcf
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 $0.19 per Bbl in 2022 and a negative $1.42 per Bbl during 2021. During 2022, the Company benefited from improved Light Louisiana Sweet (“LLS”) pricing for its Gulf Coast grades relative to NYMEX WTI prices. For our crude oil sold under LLS index prices, the
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Denbury Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
LLS-to-NYMEX differential averaged a positive $2.25 per Bbl on a trade-month basis during 2022, compared to a positive $1.49 per Bbl differential during 2021.
Rocky Mountain Region. NYMEX oil differentials in the Rocky Mountain region averaged $0.02 per Bbl above NYMEX during 2022, compared to an average differential of $1.32 per Bbl below NYMEX in 2021. Differentials in the Rocky Mountain region generally 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.
CO 2 Revenues and Expenses
We sell a portion of the CO 2 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 CO 2 sales as “CO 2 sales and transportation fees” with the corresponding costs recognized as “CO 2 operating and discovery expenses” in our Consolidated Statements of Operations. CO 2 sales and transportation fees were $60.6 million during 2022, compared to $44.2 million during 2021. The increase from the prior-year period was primarily due to revenues received pursuant to a short-term contractual agreement that ended during the fourth quarter of 2022.
Oil Marketing Revenues and Purchases
In certain situations, we purchase and subsequently sell oil from third parties. We recognize the revenue received and the associated expenses incurred on these sales on a gross basis as “Oil marketing revenues” and “Oil marketing purchases” in our 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 have historically consisted of price floors, collars, three-way collars, fixed-price swaps, fixed-price swaps enhanced with a sold put, and basis swaps.
The following tables summarize the impact our commodity derivative contracts had on our operating results for the periods indicated:
Three Months Ended
In thousands
March 31
June 30
September 30
December 31
Full Year
Payment on settlements of commodity derivatives
Noncash fair value gains (losses) on commodity derivatives
Commodity derivatives income (expense)
Three Months Ended
In thousands
March 31
June 30
September 30
December 31
Full Year
Payment on settlements of commodity derivatives
Noncash fair value gains (losses) on commodity derivatives
Commodity derivatives expense
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Denbury Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Predecessor
Successor
Three Months Ended
Period from July 1 through September 18
Period from September 19 through September 30
Three Months Ended
In thousands
March 31
June 30
December 31
Full Year
Receipt on settlements of commodity derivatives
Noncash fair value gains (losses) on commodity derivatives
Commodity derivatives income (expense)
Commodity derivatives income (expense) is comprised of (1) payments or receipts on settlements of commodity derivatives and (2) changes in the fair values of commodity derivatives. Changes in the fair values of commodity derivatives are due to the expiration of commodity derivative contracts and changes in oil futures prices since the prior period or subsequent to entering into new derivative agreements. During 2022, we paid $315.8 million upon expiration of commodity derivative contracts, compared to cash payments upon settlement of $277.2 million during 2021.
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 2021 and 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 12, Commodity Derivative Contracts , to the consolidated financial statements for additional details of our outstanding commodity derivative contracts as of December 31, 2022, and Market Risk Management below for additional discussion. In addition, the following table summarizes our oil derivative contracts as of February 22, 2023:
WTI NYMEX
Volumes Hedged (Bbls/d)
Fixed-Price Swaps
Weighted Average Swap Price
WTI NYMEX
Volumes Hedged (Bbls/d)
Collars
Weighted Average Floor / Ceiling Price
Total Volumes Hedged (Bbls/d)
Based on current contracts in place and NYMEX oil futures prices as of February 22, 2023, which averaged approximately $74 per Bbl for the remainder of 2023, we currently expect that we would receive cash receipts of approximately $19 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 $77.74 per Bbl). See Note 12, Commodity Derivative Contracts , to the consolidated financial statements for further discussion. 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.
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Denbury Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Production Expenses
Lease Operating Expenses
Successor
Predecessor
Year Ended
Dec. 31, 2022
Year Ended Dec. 31, 2021
Period from Sept. 19, 2020 through Dec. 31, 2020
Period from
Jan. 1, 2020 through
Sept. 18, 2020
In thousands, except per-BOE data
Total lease operating expenses
Total lease operating expenses per BOE
Total lease operating expenses were $502.4 million, or $29.41 per BOE, during 2022, compared to $424.6 million, or $23.85 per BOE, during 2021. The $77.9 million (18%) increase on an absolute-dollar basis was the result of a $22.6 million increase for special items and a $55.3 million increase due primarily to inflation and higher activity levels. The increase on a per BOE basis was further impacted by lower production in the current year period.
Special items driving the increase in year-over-year LOE include (1) a $16.1 million non-recurring benefit in 2021 resulting from compensation under certain of the Company’s power agreements for power interruption during the severe winter storm in February 2021, (2) an additional $13.2 million of LOE in 2022 reflecting an entire 12 months’ worth expenses from our March 2021 acquisition of Wind River Basin properties, offset in part by (3) a $6.7 million benefit in 2022 for an insurance reimbursement of for property damage costs incurred during 2013 at Delhi Field.
Lifting cost excluding the special items increased 13% in 2022 compared to 2021. Inflation and higher activity levels resulted in higher power and fuel costs ($19.6 million), workover costs ($13.6 million), labor costs ($8.2 million), and CO 2 purchase costs ($2.7 million), as well as other increases.
We currently expect lease operating expenses during 2023 to increase slightly from 2022 levels as a result of CO 2 cost increases (primarily due to a contractual price change under an existing industrial CO 2 contract), inflationary impacts to cost categories such as company and contract labor, and the absence in 2023 of the $6.7 million Delhi Field insurance reimbursement.
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 $20.1 million during 2022, compared to $28.8 million for the year ended December 31, 2021. The decrease between periods was primarily due to a change in the sales contracts of certain of our production, which reduced our transportation expense.
Taxes Other than Income
Taxes other than income, which includes production, ad valorem and franchise taxes, were $131.5 million during 2022, compared to $91.4 million for the year ended December 31, 2021. The increase between periods was primarily due to an increase in production taxes resulting from higher oil and natural gas revenues.
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Denbury Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
General and Administrative Expenses (“G&A”)
Successor
Predecessor
Year Ended
Dec. 31, 2022
Year Ended Dec. 31, 2021
Period from Sept. 19, 2020 through Dec. 31, 2020
Period from
Jan. 1, 2020 through
Sept. 18, 2020
In thousands, except per-BOE data and employees
Cash G&A costs
Stock-based compensation
Severance-related costs
G&A expenses
G&A per BOE
Cash G&A costs
Stock-based compensation
Severance-related costs
G&A expenses
Employees as of period end
Our G&A expense on an absolute-dollar basis was $82.2 million during 2022, compared to $79.3 million during 2021. The 23% increase in our cash G&A expenses during 2022 was primarily associated with increased employee headcount and professional services while the decrease in stock-based compensation in 2022 is due to the absence in 2022 of expense associated with the 2021 vesting of performance-based equity awards which were granted in late 2020. Although the performance criteria for these performance-based equity awards were met in 2021, the shares underlying these awards are not currently outstanding as under the terms of these awards actual delivery of the shares is not scheduled to occur until after the end of the performance period, no earlier than December 4, 2023. We currently expect G&A expense to increase in 2023 due to the inclusion in 2023 of a full year of expense associated with employees hired in 2022, additional headcount increases anticipated during 2023, and the cumulative expense for long-term equity incentive awards, with 2023 being the third full year of expense following emergence. A significant portion of the Company’s planned headcount additions in 2023 are related to the Company’s expanding CCUS activities. We currently expect our stock-based compensation to range between $22 million and $26 million in 2023.
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Denbury Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Interest and Financing Expenses
Successor
Predecessor
Year Ended
Dec. 31, 2022
Year Ended Dec. 31, 2021
Period from Sept. 19, 2020 through Dec. 31, 2020
Period from
Jan. 1, 2020 through
Sept. 18, 2020
In thousands, except per-BOE data and interest rates
Cash interest (1)
Less: interest not reflected as expense for financial reporting purposes (2)
Noncash interest expense
Amortization of debt discount (3)
Less: capitalized interest
Interest expense, net
Interest expense, net per BOE
Average debt principal outstanding (4)
Average cash interest rate (5)
(1) Cash interest during the 2020 Predecessor period includes the portion of interest on certain debt instruments accounted for as a reduction of debt for GAAP financial reporting purposes in accordance with Financial Accounting Standards Board Codification (“FASC”) 470-60, Troubled Debt Restructuring by Debtors . Includes commitment fees paid on the Company’s bank credit facility but excludes debt issue costs.
(2) The portion of interest treated as a reduction of debt during the 2020 Predecessor period was related to the Predecessor’s 9% Senior Secured Second Lien Notes due 2021 (the “2021 Notes”) and 9¼% Senior Secured Second Lien Notes due 2022 (the “2022 Notes”). Amounts related to the 2021 Notes and 2022 Notes remaining in future interest payable were written-off to “Reorganization items, net” in the Consolidated Statements of Operations on July 30, 2020 (the “Petition Date”).
(3) Represents amortization of debt discounts during the 2020 Predecessor period related to the 7¾% Senior Secured Second Lien Notes due 2024 (the “7¾% Senior Secured Notes”) and 6⅜% Convertible Senior Notes due 2024 (the “2024 Convertible Notes”). Remaining debt discounts were written-off to “Reorganization items, net” in the Consolidated Statements of Operations on the Petition Date.
(4) For the 2020 period, excludes debt discounts related to the Predecessor’s 7¾% Senior Secured Notes and 2024 Convertible Notes.
(5) Excludes commitment fees paid on the Company’s bank credit facility and debt issue costs.
Cash interest was $5.3 million during 2022, compared to $6.0 million for the year ended December 31, 2021. The decrease between periods was primarily due to a decrease in the average debt principal outstanding.
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Denbury Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Depletion, Depreciation, and Amortization (“DD&A”)
Successor
Predecessor
Year Ended
Dec. 31, 2022
Year Ended Dec. 31, 2021
Period from Sept. 19, 2020 through Dec. 31, 2020
Period from
Jan. 1, 2020 through
Sept. 18, 2020
In thousands, except per-BOE data
Oil and natural gas properties
CO 2 properties, pipelines, plants and other property and equipment
Accelerated depreciation charge (1)
Total DD&A
DD&A per BOE
Oil and natural gas properties
CO 2 properties, pipelines, plants and other property and equipment
Accelerated depreciation charge (1)
Total DD&A cost per BOE
Write-down of oil and natural gas properties
(1) Accelerated depreciation in 2021 represents an accelerated depreciation charge related to capitalized amounts associated with unevaluated properties that were transferred to the full cost pool.
DD&A expense was $151.4 million during 2022, compared to $150.6 million for the year ended December 31, 2021. The 1% increase during 2022 compared to the 2021 period was primarily due to an accelerated depreciation charge. The slight increase related to oil and natural gas properties is the result of an increase in the accretion of our asset retirement obligations, largely offset by a lower depletion rate from an increase in our estimate of proved reserves between the periods based on higher commodity pricing. Our oil and natural gas properties depletion rate was $7.69 per BOE during the fourth quarter of 2022. We expect DD&A expense will be higher subsequent to the initial booking of proved reserves at our new CCA CO 2 flood, which we currently estimate will occur during 2023.
Full Cost Pool Ceiling Test
Under full cost accounting rules, we are required each quarter (as well as at the end of the Predecessor period) to perform a ceiling test calculation. Under these rules, the full cost ceiling value is calculated using the average first-day-of-the-month oil and natural gas prices for each month during a 12-month rolling period prior to the end of a particular reporting period. We recognized a full cost pool ceiling test write-down of $14.4 million during the first quarter of 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 3, Acquisition and Divestitures ) which was recorded based on a valuation that utilized NYMEX strip oil prices at the acquisition date, which were significantly higher than the average first-day-of-the-month NYMEX oil prices used to value the cost ceiling.
2020 Reorganization Items, Net
“Reorganization items, net” in our Consolidated Statements of Operations for the 2020 Predecessor period included (i) expenses incurred during the Company’s “prepackaged” voluntary bankruptcy subsequent to the Petition Date as a direct result of the Plan, (ii) gains or losses from liabilities settled and (iii) fresh start accounting adjustments. Professional service provider charges associated with our restructuring that were incurred outside of this period (before the Petition Date and after the Emergence Date) were recorded in “Other expenses” in our Consolidated Statements of Operations.
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Denbury Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following table summarizes the losses (gains) on reorganization items, net:
Predecessor
Period from
Jan. 1, 2020 through
Sept. 18, 2020
In thousands
Gain on settlement of liabilities subject to compromise
Fresh start accounting adjustments
Professional service provider fees and other expenses
Success fees for professional service providers
Loss on rejected contracts and leases
Valuation adjustments to debt classified as subject to compromise
Debtor-in-possession credit agreement fees
Acceleration of Predecessor stock compensation expense
Total reorganization items, net
Other Expenses
Other expenses totaled $16.3 million during 2022 and primarily includes $4.9 million related to CCUS, a $3.9 million accrual for a preliminarily assessed civil penalty proposed by the Pipeline and Hazardous Materials Safety Administration of the U.S. Department of Transportation in a Notice of Probable Violation (see Item 3, Legal Proceedings – Notice of Probable Violation from Pipeline and Hazardous Materials Safety Administration (“PHMSA”) Regarding Delta-Tinsley CO 2 Pipeline Failure ), and $3.7 million related to plant operating expenses. Other expenses totaled $10.8 million for the year ended December 31, 2021 and primarily includes plant operating expenses, litigation accruals and noncash fair value adjustments for contingent consideration payments related to our March 2021 Wind River Basin CO 2 EOR field acquisition, slightly offset by insurance reimbursements for previously-incurred costs associated with the February 2020 Delta-Tinsley CO 2 pipeline repair.
Income Taxes
Successor
Predeccesor
Year Ended
Dec. 31, 2022
Year Ended Dec. 31, 2021
Period from Sept. 19, 2020 through Dec. 31, 2020
Period from
Jan. 1, 2020 through
Sept. 18, 2020
In thousands, except per-BOE amounts and tax rates
Current income tax expense (benefit)
Deferred income tax expense (benefit)
Total income tax expense (benefit)
Average income tax expense (benefit) per BOE
Effective tax rate
Total net deferred tax liability
Our income tax provisions were based on an estimated combined federal and state statutory tax rate of approximately 25% for 2022, 2021 and 2020. Our effective tax rate for 2022 was lower than our estimated statutory rate, primarily due to the reversal of the valuation allowance on our federal and certain state deferred tax assets.
We make estimates and judgements in determining our income tax expense for financial reporting purposes. These estimates and judgements occur in the calculation of certain tax assets and liabilities that arise from differences in the timing and recognition of revenue and expense for tax and financial reporting purposes. Significant judgment is required in estimating valuation allowances, and in making this determination we consider all available positive and negative evidence and make certain assumptions. The realization of a deferred tax asset ultimately depends on the existence of sufficient taxable income in the applicable carryback or carryforward periods. In our assessment, we consider the nature, frequency, and severity of current
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Denbury Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
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. At December 31, 2021 we had a $125.5 million valuation allowance recorded against our federal and certain state deferred tax assets. This valuation allowance was initially 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 continue to be in a cumulative three-year-loss position through 2022, we initially determined on March 31, 2022, that there was sufficient positive evidence, primarily related to a substantial increase in worldwide oil prices and taxable income generated from future reversals of existing taxable temporary differences, to conclude that our federal and certain state deferred tax assets are more likely than not to be realized. Accordingly, we reversed $51.4 million and $14.8 million of our federal and state valuation allowances during the year ended December 31, 2022, respectively. We continue to maintain a valuation allowance of $59.2 million for certain state tax benefits that we currently do not expect to realize before their expiration.
We have $0.6 million of alternative minimum tax credits, which under the Tax Cut and Jobs Act will be refunded in 2023 and are recorded as a receivable on the balance sheet. Our state net operating loss carryforwards expire in various years, starting in 2025. The statutes of limitation for our income tax returns for tax years ending prior to 2019 have lapsed and therefore are not subject to examination by respective taxing authorities. Our estimated annual effective tax rate for 2023 is expected to be approximately 25% with current taxes anticipated to represent 5% to 10% of total taxes.
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Denbury Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Per-BOE Data
The following table summarizes our cash flow and results of operations on a per-BOE basis for the comparative periods. Each of the significant individual components is discussed above.
Year Ended December 31,
Per-BOE data
Oil and natural gas revenues
Receipt (payment) on settlements of commodity derivatives
Lease operating expenses
Production and ad valorem taxes
Transportation and marketing expenses
Production netback
CO 2 sales, net of operating and discovery expenses
General and administrative expenses (1)
Interest expense, net
Reorganization items settled in cash
Stock compensation and other
Changes in assets and liabilities relating to operations
Cash flows from operations
DD&A – excluding accelerated depreciation charge
DD&A – accelerated depreciation charge (2)
Write-down of oil and natural gas properties
Deferred income taxes
Gain on extinguishment of debt
Noncash fair value losses on commodity derivatives
Noncash reorganization items, net
Other noncash items
Net income (loss)
(1) General and administrative expenses include $15.3 million of performance stock-based compensation related to the full vesting of outstanding performance awards during the year ended December 31, 2021, resulting in a significant non-recurring expense, which if excluded, would have caused these expenses to average $3.60 per BOE.
(2) Represents an accelerated depreciation charge related to impaired unevaluated properties that were transferred to the full cost pool.
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Denbury Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
MARKET RISK MANAGEMENT
Debt and Interest Rate Sensitivity
At December 31, 2022, we had $29.0 million of outstanding borrowing under our Bank Credit Agreement. At this level of variable-rate debt, an increase or decrease of 10% in interest rates would have an immaterial effect on our interest expense. Our Bank Credit Agreement does not have any triggers or covenants regarding our debt ratings with rating agencies. The following table presents the principal and fair values of our outstanding debt as of December 31, 2022:
In thousands
Total
Fair
Value
Variable rate debt
Senior Secured Bank Credit Facility (weighted average interest rate of 9.0% at December 31, 2022)
Commodity Derivative Contracts
We enter into oil derivative contracts to provide an economic hedge of our exposure to commodity price risk associated with anticipated future oil production and to provide more certainty to our future cash flows. We do not hold or issue derivative financial instruments for trading purposes. Over the last few years, these contracts have consisted of costless collars and fixed-price swaps. The production that we hedge has varied from year to year depending on our levels of debt, financial strength, expectation of future commodity prices, and occasionally requirements under our bank credit facility. We currently have no hedging requirements under our Bank Credit Agreement. 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. Depending on market conditions, we may continue to add to our existing 2023 and 2024 hedges. See also Note 12, Commodity Derivative Contracts , and Note 13 , Fair Value Measurements, to the consolidated financial statements for additional information regarding our commodity derivative contracts.
All of the mark-to-market valuations used for our commodity derivatives are provided by external sources. We manage and control market and counterparty credit risk through established internal control procedures that are reviewed on an ongoing basis. We attempt to minimize credit risk exposure to counterparties through formal credit policies, monitoring procedures and diversification. All of our commodity derivative contracts are with parties that are lenders under our senior secured bank credit facility (or affiliates of such lenders). We have included an estimate of nonperformance risk in the fair value measurement of our commodity derivative contracts, which we have measured for nonperformance risk based upon credit default swaps or credit spreads.
For accounting purposes, we do not apply hedge accounting to our commodity derivative contracts. This means that any changes in the fair value of these commodity derivative contracts are charged to earnings instead of charging the effective portion to other comprehensive income and the ineffective portion to earnings.
At December 31, 2022, our commodity derivative contracts were recorded at their fair value, which was a net asset of $2.5 million, a $137.0 million change from the $134.5 million net liability recorded at December 31, 2021. This change is related to the expiration of commodity derivative contracts during 2022, new commodity derivative contracts entered into during 2022 for future periods, and to the changes in oil futures prices between December 31, 2021 and 2022.
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Denbury Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Commodity Derivative Sensitivity Analysis
Based on NYMEX oil futures prices and derivative contracts in place as of December 31, 2022, and assuming both a 10% increase and decrease thereon, we would expect to make payments on our crude oil derivative contracts as shown in the following table:
In thousands
Receipt / (Payment)
Based on:
Futures prices as of December 31, 2022
10% increase in prices
10% decrease in prices
Our commodity derivative contracts are used as an economic hedge of our exposure to commodity price risk associated with anticipated future production. As a result, changes in receipts or payments on our commodity derivative contracts due to changes in commodity prices, as reflected in the above table, would be mostly offset by a corresponding increase or decrease in the cash receipts on sales of our oil production to which those commodity derivative contracts relate.
CRITICAL ACCOUNTING ESTIMATES
The preparation of financial statements in accordance with generally accepted accounting principles requires that we make certain estimates and judgments. Our significant accounting policies are included in Note 1, Nature of Operations and Summary of Significant Accounting Policies , to the consolidated financial statements. These policies, along with the underlying assumptions and judgments by our management in their application, have a significant impact on our consolidated financial statements. Following is a discussion of our most critical accounting estimates, judgments and uncertainties that are inherent in the preparation of our financial statements.
Full Cost Method of Accounting, Depletion and Depreciation and Oil and Natural Gas Properties
Businesses involved in the production of oil and natural gas are required to follow accounting rules that are unique to the oil and gas industry. We apply the full cost method of accounting for our oil and natural gas properties. Another acceptable method of accounting for oil and natural gas production activities is the successful efforts method of accounting. In general, the primary differences between the two methods are related to the capitalization of costs and the evaluation for asset impairment. Under the full cost method, all geological and geophysical costs, exploratory dry holes and delay rentals are capitalized to the full cost pool, whereas under the successful efforts method such costs are expensed as incurred. In the assessment of impairment of oil and natural gas properties, the successful efforts method follows the Accounting for the Impairment or Disposal of Long-Lived Assets topic of the FASC, under which the net book value of assets is measured for impairment against the undiscounted future cash flows using commodity prices consistent with management expectations. Under the full cost method, the full cost pool (net book value of oil and natural gas properties) is measured future cash flows discounted at 10% using the average first-day-of-the-month oil and natural gas price for each month during a 12-month rolling period through the end of each quarterly reporting period. The financial results for a given period could be substantially different depending on the method of accounting that an oil and gas entity applies. Further, we do not designate our oil and natural gas derivative contracts as hedging instruments for accounting purposes under the Derivatives and Hedging topic of the FASC (see below), and as a result, these contracts are not considered in the full cost ceiling test.
We make significant estimates at the end of each period related to accruals for oil and natural gas revenues, production, capitalized costs and operating expenses. We calculate these estimates with our best available data, which includes, among other things, production reports, price posting, information compiled from daily drilling reports and other internal tracking devices, and analysis of historical results and trends. While management is not aware of any required revisions to its estimates, there will likely be future adjustments resulting from such things as revisions in estimated oil and natural gas volumes, changes in ownership interests, payouts, joint venture audits, re-allocations by the purchasers or pipelines, or other corrections and adjustments common in the oil and gas industry, many of which will require retroactive application. These types of adjustments cannot be currently estimated or determined and will be recorded in the period during which the adjustment occurs.
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Denbury Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Under full cost accounting, the estimated quantities of proved oil and natural gas reserves used to compute depletion and the related present value of estimated future net cash flows therefrom used to perform the full cost ceiling test have a significant impact on the underlying financial statements. The process of estimating oil and natural gas reserves is very complex, requiring significant decisions in the evaluation of all available geological, geophysical, engineering and economic data. The data for a given field may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and continued reassessment of the viability of production under varying economic conditions. As a result, material revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure the reported reserve estimates represent the most accurate assessments possible, including the hiring of independent engineers to prepare reported estimates, the subjective decisions and variances in available data for various fields make these estimates generally less precise than other estimates included in our financial statement disclosures. Over the last three years, annual revisions to our reserve estimates, excluding any revisions related to changes in commodity prices, have averaged approximately 4.8% of the previous year’s estimates and have been both positive and negative.
Changes in commodity prices also affect our reserve quantities. These changes in quantities affect our DD&A rate, and the combined effect of changes in quantities and commodity prices impacts our full cost ceiling test calculation. For example, we estimate that a 5% increase in our estimate of proved reserve quantities would have lowered our fourth quarter 2022 oil and natural gas property DD&A rate from $7.69 per BOE to approximately $7.38 per BOE, and a 5% decrease in our proved reserve quantities would have increased our DD&A rate to approximately $8.02 per BOE. Also, reserve quantities and their ultimate values, determined solely by our lenders, are the primary factors in determining the maximum borrowing base under our senior secured bank credit facility, particularly quantities and values of our proved developed producing reserves.
Under full cost accounting rules, we are required each quarter (as well as at the end of the Predecessor period) to perform a ceiling test calculation. 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 CO 2 reserves nor those related to the cost of constructing CO 2 pipelines, as we do not have to incur additional CO 2 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 CO 2 costs related to CO 2 reserves and CO 2 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 hedging instruments for accounting purposes. The cost center ceiling test is prepared quarterly.
The average first-day-of-the-month NYMEX oil price used in estimating our proved reserves, after adjustments for market differentials and transportation expenses by field, was $93.02 at December 31, 2022, $63.86 at December 31, 2021, $35.84 at December 31, 2020, and $40.08 at September 18, 2020. We recognized a full cost pool ceiling test write-down of $14.4 million during the first quarter of 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 3, Acquisition and Divestitures ) which was recorded based on a valuation that utilized NYMEX strip oil prices at the acquisition date, which were significantly higher than the average first-day-of-the-month NYMEX oil prices used to value the cost ceiling. Primarily as a result of commodity price declines during 2020, the Predecessor recognized full cost pool ceiling test write-downs of $996.7 million during the period from January 1, 2020 through September 18, 2020, and an additional full cost pool ceiling test write-down of $1.0 million was recognized during the Successor period from September 19, 2020 through December 31, 2020.
We exclude certain unevaluated costs from the amortization base and full cost ceiling test pending the determination of whether proved reserves can be assigned to such properties. The costs classified as unevaluated are transferred to the full cost amortization base as the properties are developed, tested and evaluated. At least annually, we test these assets for impairment based on an evaluation of management’s expectations of future pricing, evaluation of lease expiration terms, and planned project development activities. Given the significant declines in NYMEX oil prices in March and April 2020 due to the oil supply and demand imbalance precipitated by the dramatic fall in demand associated with the COVID-19 pandemic combined with the concurrent OPEC+ decision to increase oil supply, we reassessed our development plans and transferred $244.9
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Management’s Discussion and Analysis of Financial Condition and Results of Operations
million of our unevaluated costs to the full cost pool during the Predecessor period from January 1, 2020 through September 18, 2020. Upon emergence from bankruptcy, the Company adopted fresh start accounting which resulted in our oil and natural gas properties, including unevaluated properties, being recorded at their fair values at the Emergence Date (see Note 2, Fresh Start Accounting , for additional information).
Tertiary Injection Costs
Our tertiary operations are conducted in reservoirs that have already produced significant amounts of oil over many years; however, in accordance with the rules for recording proved reserves, we cannot recognize proved reserves associated with enhanced recovery techniques, such as CO 2 injection, until we can demonstrate production resulting from the tertiary process or unless the field is analogous to an existing flood. Our costs associated with the CO 2 we produce (or acquire) and inject are principally our cash out-of-pocket costs of production, transportation and acquisition, and to pay royalties.
We capitalize, as a development cost, injection costs in fields that are in their development stage, which means we have not yet seen incremental oil production due to the CO 2 injections (i.e., a production response). These capitalized development costs will be included in our unevaluated property costs until we are able to recognize proved oil reserves associated with the development project. After we see a production response to the CO 2 injections (i.e., the production stage), injection costs will be expensed as incurred, and any previously deferred unevaluated development costs will become subject to depletion. We capitalized $32.8 million of tertiary injection costs associated with our tertiary projects during 2022, $7.6 million during 2021, $2.3 million during the Successor period from September 19, 2020 through December 31, 2020 and $16.2 million during the Predecessor period from January 1, 2020 through September 18, 2020.
CCUS Asset Allocation
The Company has entered into numerous storage agreements that provide a right to inject CO 2 into the pore space (sub-surface) and access the surface above the pore space. The agreements do not give the Company ownership of the land, but instead require payment of annual fees for these rights. Denbury recognizes the rights to the surface and subsurface as intangible assets, and will capitalize and depreciate the related contract costs. Denbury will allocate payments between the surface and the subsurface based upon the fair value of surface assets versus subsurface assets. The surface assets will be depreciated over the period during which the Company has access to the land and the subsurface assets will be amortized based on utilization of available pore space.
Income Taxes
We make certain 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. Our federal and state income tax returns are generally not prepared or filed before the consolidated financial statements are prepared; therefore, we estimate the tax basis of our assets and liabilities at the end of each period as well as the effects of tax rate changes, tax credits and net operating loss carryforwards. Adjustments related to these estimates are recorded in our tax provision in the period in which we finalize our income tax returns. Further, we must assess the likelihood that we will be able to recover or utilize our deferred tax assets. If recovery is not likely, we must record a valuation allowance against such deferred tax assets for the amount we would not expect to recover, which would result in an increase to our income tax expense. As of December 31, 2022, we had tax valuation allowances totaling $59.2 million to reduce the carrying value of our state deferred tax assets. The valuation allowances will remain until the realization of future deferred tax benefits are more likely than not to become utilized. Management considers all available evidence (both positive and ) in determining whether a valuation allowance is required. Such evidence includes our cumulative position, the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies and judgment is required in considering the relative weight of and evidence. Significant judgment is involved in this determination as we are required to make assumptions about forecasted commodity prices and economics in the oil and gas industry that may impact our ability to generate future earnings. Such estimates are inherently subjective. Changes in judgment regarding future realization of deferred tax assets may result in a reversal of all or a portion of the valuation allowance in the period that determination is made, and our net income during that period would from a lower tax rate. A 1% increase in our statutory tax rate would have increased our calculated income tax expense () by approximately $5.6 million for the year ended December 31, 2022, and $0.6 million for the year ended December 31, 2021.
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Management’s Discussion and Analysis of Financial Condition and Results of Operations
Fair Value Estimates
The FASC defines fair value, establishes a framework for measuring fair value and requires disclosures about fair value measurements. The FASC establishes a fair value hierarchy that prioritizes the inputs to the valuation techniques used to measure fair value. Level 1 inputs are given the highest priority in the fair value hierarchy, as they represent observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the reporting date, while Level 3 inputs are given the lowest priority, as they represent unobservable inputs that are not corroborated by market data. Valuation techniques that maximize the use of observable inputs are favored. See Note 13, Fair Value Measurements , to the consolidated financial statements for disclosures regarding our recurring fair value measurements.
Significant uses of fair value measurements include:
• valuation of the Company’s assets, liabilities and equity upon application of fresh start accounting (see Fresh Start Accounting above);
• allocation of the purchase price to assets acquired and liabilities assumed in acquisitions;
• assessment of impairment of long-lived assets; and
• recorded value of commodity derivative instruments.
Impairment Assessment of Long-Lived Assets
We test long-lived assets that are not subject to our quarterly full cost pool ceiling test for impairment, including a portion of our capitalized CO 2 properties and pipelines, CCUS storage sites and related costs, and long-term contracts to sell CO 2 to industrial customers, whenever events or changes in circumstances indicate that the carrying value may not be recoverable. The factors we assess to determine if a long-lived asset impairment test is necessary include, among other factors, a significant adverse change in the business climate that could affect the value of a long-lived asset, a significant decrease in the market price of an asset group, a significant adverse change in the extent or manner in which a long-lived asset (asset group) is being used or in its physical condition, or a current-period operating or cash flow loss combined with a history of operating or cash flow losses or a projection or forecast that demonstrates continuing losses associated with the use of a long-lived asset (asset group).
We perform our long-lived asset impairment test by comparing the net carrying costs of our long-lived asset groups to the respective expected future undiscounted net cash flows that are supported by these long-lived assets which include production of our probable and possible oil and natural gas reserves and future CCUS revenues. If the undiscounted net cash flows are below the net carrying costs for an asset group, we must record an impairment loss by the amount, if any, that net carrying costs exceed the fair value of the long-lived asset group. Significant assumptions impacting expected future oil and gas undiscounted net cash flows include projections of future oil and natural gas prices, projections of estimated quantities of oil and natural gas reserves, projections of future rates of production, timing and amount of future development and operating costs, projected availability and cost of CO 2 , projected recovery factors of tertiary reserves and risk-adjustment factors applied to the cash flows. Significant assumptions impacting expected future CCUS undiscounted net cash flows include projection of future CO 2 volumes available for transportation and storage and the development and operating costs of our storage sites. We performed a qualitative assessment as of December 31, 2022 and determined there were no material changes to our key cash flow assumptions and no triggering events since September 18, 2020 when the Company’s assets were revalued in fresh start accounting; therefore, no test was performed for the fourth quarter of 2022.
Commodity Derivative Contracts
Historically, we have entered into 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. Our derivative financial instruments are recorded on the balance sheet as either an asset or liability measured at fair value. The valuation methods used to measure the fair values of these assets and liabilities require considerable management judgment and estimates to derive the inputs necessary to determine fair value estimates, such as forward prices for commodities, interest rates, volatility factors and credit worthiness, as well as other relevant economic measures. We do not apply hedge accounting to our commodity derivative contracts under the FASC Derivatives and Hedging
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topic; accordingly, changes in the fair value of these instruments are recognized in earnings instead of charging the effective portion to other comprehensive income and the ineffective portion to earnings. While we may experience more volatility in our net income (loss) than if we were to apply hedge accounting treatment as permitted by the FASC Derivatives and Hedging topic, we believe that for us, the benefits associated with applying hedge accounting do not outweigh the cost, time and effort to comply with hedge accounting. We estimate that a 10% increase in NYMEX oil futures prices as of December 31, 2022 would increase our estimated payments on our crude oil derivative contracts by $35 million, and a 10% decrease in NYMEX oil futures prices would reduce our estimated payments by $36 million.
Fresh Start Accounting
Upon emergence from bankruptcy, we met the criteria and were required to adopt fresh start accounting in accordance with FASC Topic 852, Reorganizations , which on the Emergence Date resulted in a new entity, the Successor, for financial reporting purposes, with no beginning retained earnings or deficit as of the fresh start reporting date. Fresh start accounting requires that new fair values be established for the Company’s assets, liabilities and equity as of the date of emergence from bankruptcy, September 18, 2020. The Emergence Date fair values of the Successor’s assets and liabilities differ materially from their recorded values as reflected on the historical balance sheet of the Predecessor and required a number of estimates and judgments to be made. All estimates, assumptions, valuations and financial projections, including the fair value adjustments, financial projections, enterprise value and equity value, are inherently subject to significant uncertainties and the resolution of contingencies beyond our control. Accordingly, there is no assurance that the estimates, assumptions, valuations or financial projections will be realized, and actual results could vary materially.
Recent Accounting Pronouncements
See Note 1, Nature of Operations and Summary of Significant Accounting Policies , to the consolidated financial statements for a discussion of recent accounting pronouncements.
FORWARD-LOOKING INFORMATION
The data and/or statements contained in this Annual Report on Form 10-K, particularly statements found in “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” that are not historical facts, are forward-looking statements, as that term is defined in Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), that involve a number of risks and uncertainties, and include, but are not limited to: possible or assumed future results of operations, cash flows, production and capital expenditures; goals and predictions as to the Company’s future carbon capture, use and storage (“CCUS”) activities; and assumptions as to oil markets or general economic conditions.
Such forward-looking statements may be or may concern, among other things, the level and volatility of posted or realized oil prices; the adequacy of our liquidity sources to support our future activities; statements or predictions related to the ultimate timing and financial impact of our proposed CCUS arrangements, including the estimated emissions storage capacity of storage sites, predictions of long-term cumulative capital investments in CCUS, the volumes of CO 2 emissions we estimate can be transported and stored, along with the timing of receipt of first revenues from storage of CO 2 ; our projected production levels, oil and natural gas revenues or oilfield costs, the impact of supply chain issues and inflation on our results of operations; current or future expectations or estimations of our cash flows or the impact of changes in commodity prices on cash flows; availability, terms and financial statement and cash settlement impact of commodity derivative contracts or their predicted downside cash flow protection; forecasted drilling activity or methods, including the timing and location thereof; anticipated timing of commencement of CO 2 injections in particular fields or areas, or initial production responses in tertiary flooding projects; other development activities, finding costs, interpretation or prediction of formation details, hydrocarbon reserve quantities and values, CO 2 reserves and supply and their availability, potential reserves, barrels or percentages of recoverable original oil in place; the impact of changes or proposed changes in Federal or state tax or environmental laws or regulations or in any future regulation of CO 2 pipelines; the outcomes of any pending or regulatory proceedings; and overall worldwide or U.S. economic conditions, and other variables surrounding operations and future plans. Such forward-looking statements generally are accompanied by words such as “plan,” “estimate,” “expect,” “predict,” “forecast,” “to our knowledge,” “anticipate,” “projected,” “preliminary,” “should,” “assume,” “believe,” “may” or other words that convey, or are intended to convey, the uncertainty of future events or outcomes.
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Such forward-looking information is based upon management’s current plans, expectations, estimates, and assumptions that could significantly and adversely be affected by various factors discussed below, along with currently unknowable events beyond our control. As a consequence, actual results may differ materially from expectations, estimates or assumptions expressed in or implied by any forward-looking statements made by us or on our behalf. Among the factors that could cause actual results to differ materially from current projections are fluctuations in worldwide or U.S. oil prices, especially in light of existing economic or geopolitical events such as the war in Ukraine; widespread inflation in economies across the world; future decisions as to production levels and/or pricing by OPEC; as to our CCUS activities, the successful completion of technical and feasibility evaluations, the raising of funds sufficient to build and operate add-on or new facilities, the pace of finalization of CCUS arrangements; and the receipt of required regulatory approval or classifications; success of our risk management techniques; the uncertainty of drilling results and reserve estimates; operating hazards and remediation costs; disruption of operations and damages from cybersecurity breaches, or from well , climate events such as hurricanes, tropical storms, floods, or other natural occurrences; conditions in the worldwide financial, trade currency and credit markets; the risks and uncertainties inherent in oil and gas drilling and production activities; and the risks and uncertainties set forth from time to time in this or our other periodic public reports, other filings and public statements.
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Denbury Inc.
