DENBURY INC. The following discussion and analysis should be read in conjunction with our Unaudited Condensed Consolidated Financial Statements and Notes thereto included herein and our Consolidated Financial Statements and Notes thereto included in our Annual Report on Form 10-K for the year endedDecember 31, 2020 (the "Form 10-K"), along with Management's Discussion and Analysis of Financial Condition and Results of Operations contained in the Form 10-K. Any terms used but not defined herein have the same meaning given to them in the Form 10-K. As a result of the Company's emergence from bankruptcy and adoption of fresh start accounting onSeptember 18, 2020 (the "Emergence Date"), certain values and operational results of the condensed consolidated financial statements subsequent toSeptember 18, 2020 are not comparable to those in the Company's condensed consolidated financial statements prior to, and includingSeptember 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 sheets of the Predecessor contained in periodic reports previously filed with theSecurities and Exchange Commission . References to "Successor" relate to the financial position and results of operations of the Company subsequent toSeptember 18, 2020 , and references to "Predecessor" relate to the financial position and results of operations of the Company prior to, and including,September 18, 2020 . 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-Q as well as Item 1A of the Form 10-K, along with Forward-Looking Information at the end of this section for information on the risks and uncertainties that could cause our actual results to be materially different than our forward-looking statements.
OVERVIEW
Denbury is an independent energy company with operations focused in theGulf Coast andRocky Mountain regions. The Company is differentiated by its focus on CO2 enhanced oil recovery ("EOR") and the emerging carbon capture, use, and storage ("CCUS") industry, supported by the Company's CO2 EOR technical and operational expertise and its extensive CO2 pipeline infrastructure. The utilization of captured industrial-sourced CO2 in EOR significantly reduces the carbon footprint of the oil thatDenbury produces, underpinning the Company's goal to fully offset its Scope 1, 2, and 3 CO2 emissions within this decade, primarily through increasing the amount of captured industrial-sourced CO2 used in its operations. Oil Price Impact on Our Business. Our financial results are significantly impacted by changes in oil prices, as 97% of our sales is oil. Changes in oil prices impact all aspects of our business; most notably our cash flows from operations, revenues, capital allocation and budgeting decisions, and oil and natural gas reserves volumes. The table below outlines selected financial 17 --------------------------------------------------------------------------------
Table of Contents
Denbury Inc.
Management's Discussion and Analysis of Financial Condition and Results of
Operations
items and sales volumes, along with changes in our realized oil prices, before
and after commodity derivative impacts, for our most recent comparative periods:
Successor Predecessor
Three Months Ended
In thousands, except December 31, Three Months Ended
per-unit data June 30, 2021 March 31, 2021 2020 June 30, 2020
Oil, natural gas, and
related product sales $ 282,708 $ 235,445 $ 178,787 $ 109,387
Receipt (payment) on
settlements of commodity
derivatives (63,343) (38,453) 14,429 45,629
Oil, natural gas, and
related product sales and
commodity settlements,
combined $ 219,365 $ 196,992 $ 193,216 $ 155,016
Average daily sales (BOE/d) 49,133 47,357 48,805 50,190
Average net realized prices
Oil price per Bbl -
excluding impact of
derivative settlements $ 64.70 $ 56.28 $ 40.63 $ 24.39
Oil price per Bbl -
including impact of
derivative settlements 50.10 47.00 43.94 34.64
NYMEX WTI oil prices strengthened from the mid-$40s per Bbl range in December
2020 to an average of approximately $66 per Bbl during the second quarter of
2021, reaching highs of over $74 per Bbl in June 2021 .
Second Quarter 2021 Financial Results and Highlights. We recognized a net loss
of $77.7 million , or $1.52 per diluted common share, during the second quarter
of 2021, compared to a net loss of $697.5 million , or $1.41 per diluted common
share, during the second quarter of 2020. The principal determinant of our
comparative second quarter results between 2020 and 2021 was the $662.4 million
full cost pool ceiling test write-down in the prior-year period. Additional
drivers of the comparative operating results include the following:
•Oil and natural gas revenues increased $173.3 million (158%), primarily due to
an increase in commodity prices;
•Commodity derivatives expense increased by $132.5 million consisting of a
$109.0 million decrease in cash receipts upon contract settlements ($63.3
million in payments during the second quarter of 2021 compared to $45.6 million
in receipts upon settlements during the second quarter of 2020) and a $23.5
million increase in the loss on noncash fair value changes;
•A $28.9 million increase in lease operating expense, across nearly all expense
categories, consisting of increases of $8.4 million in workovers, $4.4 million
in CO2 expense, $3.7 million in power and fuel, and approximately $7.1 million
due to the Wind River Basin acquisition in March 2021 ;
•A $19.4 million reduction in net interest expense resulting from the full
extinguishment of senior secured second lien notes, convertible senior notes,
and senior subordinated notes pursuant to the terms of the prepackaged joint
plan of reorganization completed in September 2020 ;
•A reduction in depletion, depreciation, and amortization expense of $19.0
million as a result of lower depletable costs due to the step down in book value
resulting from fresh start accounting on the Emergence Date; and
•An $8.3 million decrease in general and administrative expense in the second
quarter of 2021, primarily due to higher expense in the prior-year period as a
result of modifications in our compensation program during the second quarter of
2020 which resulted in adjustments to the bonus program for 2020, as well as
certain severance-related costs recorded during the second quarter of 2020.
June 2021 Divestiture of Hartzog Draw Deep Mineral Rights. On June 30, 2021 , we
closed the sale of undeveloped, unconventional deep mineral rights in Hartzog
Draw Field in Wyoming . The cash proceeds of $18 million were recorded to "Proved
properties" in our Unaudited Condensed Consolidated Balance Sheets. The proceeds
reduced our full cost pool; therefore, no gain or loss was recorded on the
transaction, and the sale had no impact on our production or reserves.
18
--------------------------------------------------------------------------------Table of Contents
Denbury Inc.
Management's Discussion and Analysis of Financial Condition and Results of
Operations
March 2021 Acquisition of Wyoming CO2 EOR Fields. On March 3, 2021 , we acquired
a nearly 100% working interest (approximately 83% net revenue interest) in the
Big Sand Draw and Beaver Creek EOR fields (collectively "Wind River Basin ")
located in Wyoming from a subsidiary of Devon Energy Corporation for $10.7
million cash (before final closing adjustments), including surface facilities
and a 46-mile CO2 transportation pipeline to the acquired fields. The
acquisition agreement provides for us to make two contingent cash payments, one
in January 2022 and one in January 2023 , of $4 million each, conditioned on
NYMEX WTI oil prices averaging at least $50 per Bbl during 2021 and 2022,
respectively. As of June 30, 2021 , the contingent consideration was recorded on
our unaudited condensed consolidated balance sheets at its fair value of $7.0
million , a $1.7 million increase from the March 2021 acquisition date fair
value. This $1.7 million increase was the result of higher NYMEX WTI oil prices
and was recorded to "Other expenses" in our Unaudited Condensed Consolidated
Statements of Operations. Wind River Basin sales averaged approximately 2,750
BOE/d during the second quarter of 2021 and utilize 100% industrial-sourced CO2.
Carbon Capture, Use and Storage. CCUS is a process that captures CO2 from
industrial sources and reuses it or stores the CO2 in geologic formations in
order to prevent its release into the atmosphere. We utilize CO2 from industrial
sources in our EOR operations, and our extensive CO2 pipeline infrastructure and
operations, particularly in the Gulf Coast , are strategically located in close
proximity to large sources of industrial emissions. We believe that the assets
and technical expertise required for CCUS are highly aligned with our existing
CO2 EOR operations, providing us with a significant advantage and opportunity to
participate in the emerging CCUS industry, as the building of a permanent carbon
sequestration business requires both time and capital to build assets such as
those we own and have been operating for years. During the first half of 2021,
approximately 34% of the CO2 utilized in our oil and gas operations was
industrial-sourced CO2, and we anticipate this percentage could increase in the
future as supportive U.S. government policy and public pressure on industrial
CO2 emitters will provide strong incentives for these entities to capture their
CO2 emissions. In an effort to proactively pursue these new CCUS opportunities,
we are engaged in discussions with existing and potential third-party industrial
CO2 emitters regarding transportation and storage solutions, while also
identifying potential future sequestration sites and landowners of those
locations. While EOR is the only CCUS operation reflected in our current and
historical financial and operational results, and development of our permanent
carbon sequestration business is likely to take several years, we believe
Denbury is well positioned to leverage our existing CO2 pipeline infrastructure
and EOR expertise to be a leader in this industry.
CAPITAL RESOURCES AND LIQUIDITY
Overview. Our primary sources of capital and liquidity are our cash flows from operations and availability under our senior secured bank credit facility. Our most significant cash capital outlays in 2021 relate to our$250 million to$270 million of budgeted development capital expenditures and$70 million of pipeline financing obligations associated with the NEJD pipeline. Based on our current 2021 full-year projections using recent oil price futures, we currently expect that our cash flow from operations in 2021 will more than cover our budgeted development capital expenditures and also cover a significant portion of our pipeline financing obligations. In addition, we have sold certain non-producing assets that will further supplement our cash flow from operations. As ofJune 30, 2021 , we had$35 million of outstanding borrowings on our$575 million senior secured bank credit facility, leaving us with$517.7 million of borrowing base availability after consideration of$22.3 million of outstanding letters of credit. Our borrowing base availability, coupled with unrestricted cash of$13.6 million , provides us total liquidity of$531.3 million as ofJune 30, 2021 , which is more than adequate to meet our currently planned operating and capital needs. 2021 Plans and Capital Budget. Considering the current oil price environment and strategic importance of the EOR CO2 flood at Cedar Creek Anticline ("CCA"), we announced inFebruary 2021 our plans to move forward with development of this significant long-term project. We expect to spend approximately$150 million in 2021 on this CCA development, consisting of approximately$100 million dedicated to the 105-mile extension of the Greencore CO2 pipeline fromBell Creek to CCA, with the remainder dedicated to facilities, well work and field development at CCA. Based on our current plans, most of the capital spend for the pipeline extension to CCA will occur in the second half of 2021, with completion of the pipeline expected by the end of 2021, first CO2 injection planned during the first half of 2022, and first tertiary production expected in the second half of 2023. We currently anticipate that our full-year 2021 development capital spending, excluding capitalized interest and 19 --------------------------------------------------------------------------------
Table of Contents
Denbury Inc.
Management's Discussion and Analysis of Financial Condition and Results of
Operations
acquisitions, will be in a range of $250 million to $270 million . Our current
2021 capital budget, excluding capitalized interest and acquisitions, at the
$260 million midpoint level is as follows:
•$100 million for the 105-mile extension of the Greencore CO2 pipeline to CCA;
•$50 million for CCA tertiary well work, facilities, and field development;
•$50 million allocated for other tertiary oil field development;
•$35 million allocated for non-tertiary oil field development; and
•$25 million for other capital items such as capitalized internal acquisition,
exploration and development costs and pre-production tertiary startup costs.
We currently anticipate 2021 average daily sales volumes to be between 47,500
BOE/d and 51,500 BOE/d, including the Big Sand Draw and Beaver Creek working
interests acquisition which closed in early March 2021 .
Capital Expenditure Summary. The following table reflects incurred capital
expenditures (including accrued capital) for the six months ended June 30, 2021
and 2020:
Six Months Ended
June 30,
In thousands 2021 2020
Capital expenditure summary
CCA tertiary development $ 10,260 $ 2,151
Other tertiary oil fields 20,774 17,769
Non-tertiary fields 19,523 13,248
Capitalized internal costs(1) 14,785 18,344
Oil and natural gas capital expenditures 65,342 51,512
CCA CO2 pipeline 8,839
8,374
Other CO2 pipelines, sources and other -
158
Development capital expenditures 74,181
60,044
Acquisitions of oil and natural gas properties(2) 10,811
80
Capital expenditures, before capitalized interest 84,992 60,124 Capitalized interest 2,251 18,181 Capital expenditures, total$ 87,243 $ 78,305 (1)Includes capitalized internal acquisition, exploration and development costs and pre-production tertiary startup costs. (2)Primarily consists of working interest positions in theWind River Basin enhanced oil recovery fields acquired onMarch 3, 2021 . Based on current oil prices and the Company's hedge positions, we expect that our 2021 cash flows from operations will exceed our budgeted level of planned development capital expenditures. Senior Secured Bank Credit Agreement. InSeptember 2020 , we entered into a bank credit agreement withJPMorgan Chase Bank, N.A ., as administrative agent, and other lenders party thereto (the "Bank Credit Agreement"). The Bank Credit Agreement is a senior secured revolving credit facility with a maturity date ofJanuary 30, 2024 . As part of our spring 2021 semiannual borrowing base redetermination, the borrowing base and lender commitments for ourBank Credit Agreement were reaffirmed at$575 million , with our next scheduled redetermination aroundNovember 2021 . 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 20 --------------------------------------------------------------------------------
Table of Contents
Denbury Inc.
Management's Discussion and Analysis of Financial Condition and Results of
Operationsperiod not to exceed six months. 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 time. 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 ofJune 30, 2021 , our ratio of consolidated total debt to consolidated EBITDAX was 0.18 to 1.0 (with a maximum permitted ratio of 3.5 to 1.0) and our current ratio was 3.00 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 ofAugust 4, 2021 , and current oil commodity derivative 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, which is an exhibit to our Form 8-K Report filed with theSEC onSeptember 18, 2020 . Commitments and Obligations. We have numerous contractual commitments in the ordinary course of business including debt service requirements, operating and finance leases, purchase obligations, and asset retirement obligations. Our operating leases primarily consist of our office leases. Our purchase obligations represent future cash commitments primarily for purchase contracts for CO2 captured from industrial sources, CO2 processing fees, transportation agreements and well-related costs. Our commitments and obligations consist of those detailed as ofDecember 31, 2020 , in our Form 10-K under Management's Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources and Liquidity - Commitments, Obligations and Off-Balance Sheet Arrangements. During the six months endedJune 30, 2021 , our long-term asset retirement obligations increased by$47.3 million , primarily related to our acquisition of working interest positions inWyoming CO2 EOR fields (see Note 2, Acquisition and Divestiture). Off-Balance Sheet Arrangements. Our off-balance sheet arrangements include obligations for various development and exploratory expenditures that arise from our normal capital expenditure program or from other transactions common to our industry, none of which are recorded on our balance sheet. In addition, in order to recover our undeveloped proved reserves, we must also fund the associated future development costs estimated in our proved reserve reports. 21 --------------------------------------------------------------------------------
Table of Contents
Denbury Inc.
Management's Discussion and Analysis of Financial Condition and Results of
OperationsRESULTS OF OPERATIONS
Certain of our financial and operating results and statistics for the comparative three and six months endedJune 30, 2021 and 2020 are included in the following table: Successor Predecessor Successor Predecessor Three Months Three Months Six Months In thousands, except per-share and unit Ended Ended Ended Six Months Ended data June 30, 2021 June 30, 2020 June 30, 2021 June 30, 2020 Financial results Net loss(1)$ (77,695) $ (697,474) $ (147,337) $ (623,458) Net loss per common share - basic(1) (1.52) (1.41) (2.91)
(1.26)
Net loss per common share - diluted(1) (1.52) (1.41) (2.91)
(1.26)
Net cash provided by operating activities 90,882 10,969 143,538 72,811 Average daily sales volumes Bbls/d 47,653 48,900 46,834 51,774 Mcf/d 8,882 7,737 8,494 7,818 BOE/d(2) 49,133 50,190 48,250 53,077 Oil and natural gas sales Oil sales$ 280,577 $ 108,538 $ 513,621 $ 337,115 Natural gas sales 2,131 849 4,532 1,896 Total oil and natural gas sales$ 282,708 $ 109,387 $ 518,153 $
339,011
Commodity derivative contracts(3) Receipt (payment) on settlements of commodity derivatives$ (63,343) $ 45,629 $ (101,796) $
70,267
Noncash fair value gains (losses) on commodity derivatives (109,321) (85,759) (186,611)
36,374
Commodity derivatives income (expense)$ (172,664) $ (40,130) $ (288,407) $
106,641
Unit prices - excluding impact of derivative settlements Oil price per Bbl$ 64.70 $ 24.39 $ 60.59 $ 35.78 Natural gas price per Mcf 2.64 1.21 2.95 1.33 Unit prices - including impact of derivative settlements(3) Oil price per Bbl$ 50.10 $ 34.64 $ 48.58 $ 43.23 Natural gas price per Mcf 2.64 1.21 2.95 1.33 Oil and natural gas operating expenses Lease operating expenses$ 110,225 $ 81,293 $ 192,195 $
190,563
Transportation and marketing expenses 8,522 9,388 16,319
19,009
Production and ad valorem taxes 21,836 8,766 39,731
26,753
Oil and natural gas operating revenues and expenses per BOE Oil and natural gas revenues$ 63.23 $ 23.95 $ 59.33 $ 35.09 Lease operating expenses 24.65 17.80 22.01 19.73 Transportation and marketing expenses 1.91 2.06 1.87
1.97
Production and ad valorem taxes 4.88 1.92 4.55
2.77
CO2 - revenues and expenses CO2 sales and transportation fees$ 10,134 $ 6,504 $ 19,362 $
14,532
CO2 operating and discovery expenses (1,531) (885) (2,524) (1,637) CO2 revenue and expenses, net$ 8,603 $ 5,619 $ 16,838 $ 12,895 (1)Includes a pre-tax full cost pool ceiling test write-down of$14.4 million during the first quarter of 2021, as compared to write-downs of$662.4 million and$735.0 million for the three and six months endedJune 30, 2020 , respectively. (2)Barrel of oil equivalent using the ratio of one barrel of oil to six Mcf of natural gas ("BOE"). (3)See also Commodity Derivative Contracts below and Item 3. Quantitative and Qualitative Disclosures about Market Risk for information concerning our derivative transactions. 22
--------------------------------------------------------------------------------
Table of Contents
Denbury Inc.
Management's Discussion and Analysis of Financial Condition and Results of
OperationsSales Volumes
Average daily sales volumes by area for each of the four quarters of 2020 and for the first and second quarters of 2021 is shown below:
Average Daily Sales Volumes (BOE/d)
First Second First Second Third Fourth
Quarter Quarter Quarter Quarter Quarter Quarter
Operating Area 2021 2021 2020 2020 2020 2020
Tertiary oil sales
Gulf Coast region
Delhi 2,925 2,931 3,813 3,529 3,208 3,132
Hastings 4,226 4,487 5,232 4,722 4,473 4,598
Heidelberg 4,054 3,942 4,371 4,366 4,256 4,198
Oyster Bayou 3,554 3,791 3,999 3,871 3,526 3,880
Tinsley 3,424 3,455 4,355 3,788 4,042 3,654
Other(1) 6,098 6,074 7,161 5,944 6,271 6,332
Total Gulf Coast region 24,281 24,680 28,931 26,220 25,776 25,794
Rocky Mountain region
Bell Creek 4,614 4,394 5,731 5,715 5,551 5,079
Other(2) 2,573 4,378 2,199 1,393 2,167 2,007
Total Rocky Mountain region 7,187 8,772 7,930 7,108 7,718 7,086
Total tertiary oil sales 31,468 33,452 36,861 33,328 33,494 32,880
Non-tertiary oil and gas sales
Gulf Coast region
Total Gulf Coast region 3,621 3,415 4,173 3,805 3,728 3,523
Rocky Mountain region
Cedar Creek Anticline 11,150 10,918 13,046 11,988 11,485 11,433
Other(2) 1,118 1,348 1,105 1,069 979 969
Total Rocky Mountain region 12,268 12,266 14,151 13,057 12,464 12,402
Total non-tertiary sales 15,889 15,681 18,324 16,862 16,192 15,925
Total continuing sales 47,357 49,133 55,185 50,190 49,686 48,805
Property sales
Gulf Coast Working Interests Sale(3) - - 780 - - -
Total sales 47,357 49,133 55,965 50,190 49,686 48,805
(1)Includes our mature properties (Brookhaven, Cranfield, Eucutta, Little Creek ,
Mallalieu, Martinville, McComb and Soso fields) and West Yellow Creek Field .
(2)Includes sales volumes related to our working interest positions in the Big
Sand Draw and Beaver Creek fields acquired on March 3, 2021 .
(3)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 the second quarter of 2021 averaged 49,133 BOE/d,
including 33,452 Bbls/d from tertiary properties and 15,681 BOE/d from
non-tertiary properties. This sales volume represents an increase of 1,776 BOE/d
(4%) compared to sales levels in the first quarter of 2021 and a decrease of
1,057 BOE/d (2%) compared to second quarter of 2020. The increase on a
sequential-quarter basis was primarily attributable to our Wind River Basin
acquisition in March 2021 and sales from these properties during the most recent
quarter.
23--------------------------------------------------------------------------------
Table of Contents
Denbury Inc.
Management's Discussion and Analysis of Financial Condition and Results of
Operations
The year-over-year decline was primarily impacted by (1) the carryover impact of
exceptionally low levels of capital investment in 2020, significantly below
levels required to hold production flat, (2) decreases at CCA due to the net
profits interest of a third party, whereby increased oil prices have resulted in
increased profitability and thus, lower reported sales volumes net to Denbury of
approximately 625 BOE/d when compared to the second quarter of 2020, and (3)
declines at Delhi Field due to lower CO2 purchases between late-February and
late-October 2020 as a result of the Delta-Tinsley pipeline being down for
repair. The year-over-year decline in sales volumes was partially offset by
sales increases from our Wind River Basin enhanced oil recovery fields acquired
on March 3, 2021 .
Our sales volumes during the three and six months ended
Oil and Natural Gas Revenues
Our oil and natural gas revenues during the three and six months endedJune 30, 2021 increased 158% and 53%, respectively, compared to these revenues for the same periods in 2020. The changes in our oil and natural gas revenues are due primarily to higher realized commodity prices (excluding any impact of our commodity derivative contracts), offset somewhat by changes in sales volumes, as reflected in the following table: Three Months Ended Six Months Ended June 30, June 30, 2021 vs. 2020 2021 vs. 2020 Increase Percentage Increase Increase Percentage Increase (Decrease) in (Decrease) in (Decrease) in (Decrease) in In thousands Revenues Revenues Revenues Revenues Change in oil and natural gas revenues due to: Decrease in sales volumes$ (2,303) (2) %$ (32,528) (10) % Increase in realized commodity prices 175,624 160 % 211,670 63 % Total increase in oil and natural gas revenues$ 173,321 158 %$ 179,142 53 % Excluding any impact of our commodity derivative contracts, our average net realized commodity prices and NYMEX differentials were as follows during the three months endedMarch 31, 2021 and 2020 and the three and six months endedJune 30, 2021 and 2020: Three Months Ended Three Months Ended Six Months Ended March 31, June 30, June 30, 2021 2020 2021 2020 2021 2020 Average net realized prices Oil price per Bbl$ 56.28 $ 45.96 $ 64.70 $ 24.39 $ 60.59 $ 35.78 Natural gas price per Mcf 3.29 1.46 2.64 1.21 2.95 1.33 Price per BOE 55.24 45.09 63.23 23.95 59.33 35.09 Average NYMEX differentials Gulf Coast region Oil per Bbl$ (1.37) $ 1.18 $ (1.13) $ (3.59) $ (1.23) $ (0.53) Natural gas per Mcf 0.68 (0.06) (0.11) (0.09) 0.30 (0.07)Rocky Mountain region Oil per Bbl$ (1.80) $ (2.78) $ (1.59) $ (4.68) $ (1.54) $ (3.25) Natural gas per Mcf 0.49 (0.91) (0.47) (1.04) (0.04) (0.98)Total Company Oil per Bbl$ (1.54) $ (0.38) $ (1.32) $ (4.03) $ (1.36) $ (1.61) Natural gas per Mcf 0.58 (0.41) (0.33) (0.54) 0.11 (0.48) 24
--------------------------------------------------------------------------------
Table of Contents
Denbury Inc.
Management's Discussion and Analysis of Financial Condition and Results of
OperationsPrices 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 theGulf Coast region was a negative$1.13 per Bbl during the second quarter of 2021, compared to a negative$3.59 per Bbl during the second quarter of 2020 and a negative$1.37 per Bbl during the first quarter of 2021. For both the first quarter of 2020 and for many years prior, ourGulf Coast region differentials were positive to NYMEX due to historically higher prices received forGulf Coast crudes, such as Light Louisiana Sweet crude oil. As a result of the market disruptions, storage constraints and weak demand caused by the COVID-19 coronavirus ("COVID-19") pandemic, these differentials weakened significantly during the second quarter of 2020 and have remained lower than historical values sinceApril 2020 . •Rocky Mountain Region. NYMEX oil differentials in theRocky Mountain region averaged$1.59 per Bbl and$4.68 per Bbl below NYMEX during the second quarters of 2021 and 2020, respectively, and$1.80 per Bbl below NYMEX during the first quarter of 2021. Differentials in theRocky Mountain region tend to fluctuate with regional supply and demand trends and can fluctuate significantly on a month-to-month basis due to weather, refinery or transportation issues, and Canadian andU.S. crude oil price index volatility.
CO2 Revenues and Expenses
We sell CO2 produced fromJackson Dome to third-party industrial users at various contracted prices primarily under long-term contracts. We recognize the revenue received on these CO2 sales as "CO2 sales and transportation fees" with the corresponding costs recognized as "CO2 operating and discovery expenses" in our Unaudited Condensed Consolidated Statements of Operations.
Oil Marketing Revenues and Expenses
From time to time, we market third-party production for sale in exchange for a fee. We recognize the revenue received on these oil sales as "Oil marketing sales" and the expenses incurred to market and transport the oil as "Oil marketing expenses" in our Unaudited Condensed Consolidated Statements of Operations.
Commodity Derivative Contracts
The following table summarizes the impact our crude oil derivative contracts had on our operating results for the three and six months endedJune 30, 2021 and 2020: Successor Predecessor Successor Predecessor Three Months Six Months Ended Three Months Ended Ended Six Months Ended In thousands June 30, 2021 June 30, 2020 June 30, 2021 June 30, 2020 Receipt (payment) on settlements of commodity derivatives$ (63,343) $ 45,629$ (101,796) $ 70,267 Noncash fair value gains (losses) on commodity derivatives (109,321) (85,759) (186,611) 36,374 Total income (expense)$ (172,664) $ (40,130)$ (288,407) $ 106,641 Changes in our commodity derivatives expense were primarily related to the expiration of commodity derivative contracts, new commodity derivative contracts entered into for future periods, and to the changes in oil futures prices between the second quarters of 2020 and 2021. The period-to-period changes reflect the very large fluctuations in oil prices betweenMarch 2020 ($30.45 per barrel), when worldwide financial markets were first beginning to absorb the potential impact of a global pandemic, andJune 2021 oil prices ($71.35 per barrel) as prospects for increased economic activity and oil demand showed improvement. In order to provide a level of price protection to a portion of our oil production, we have hedged a portion of our estimated oil production through 2022 using NYMEX fixed-price swaps and costless collars. See Note 6, Commodity Derivative Contracts, to the Unaudited Condensed Consolidated Financial Statements for additional details of our outstanding commodity 25 --------------------------------------------------------------------------------
Table of Contents
Denbury Inc.
Management's Discussion and Analysis of Financial Condition and Results of
Operations
derivative contracts as of June 30, 2021 , and Item 3, Quantitative and
Qualitative Disclosures about Market Risk below for additional discussion. In
addition, the following table summarizes our commodity derivative contracts as
of August 4, 2021 :
2H 2021 1H 2022 2H 2022
WTI NYMEX Volumes Hedged (Bbls/d) 29,000 15,500 9,000
Fixed-Price Swaps Swap Price(1) $43.86 $49.01 $56.35
WTI NYMEX Volumes Hedged (Bbls/d) 4,000 11,000 10,000
Collars Floor / Ceiling Price(1) $46.25 / $53.04 $49.77 / $64.31 $49.75 / $64.18
Total Volumes Hedged (Bbls/d) 33,000 26,500 19,000
(1)Averages are volume weighted.
Based on current contracts in place and NYMEX oil futures prices as ofAugust 4, 2021 , which averaged approximately$68 per Bbl, we currently expect that we would make cash payments of approximately$145 million upon settlement of our July throughDecember 2021 contracts, the amount of which is primarily dependent upon fluctuations in future NYMEX oil prices in relation to the prices of our 2021 fixed-price swaps which have a weighted average NYMEX oil price of$43.69 per Bbl. Changes in commodity prices, expiration of contracts, and new commodity contracts entered into cause fluctuations in the estimated fair value of our oil derivative contracts. Because we do not utilize hedge accounting for our commodity derivative contracts, the period-to-period changes in the fair value of these contracts, as outlined above, are recognized in our statements of operations. Production Expenses Lease Operating Expenses Successor Predecessor Successor Predecessor Three Months Six Months Ended Three Months Ended Ended Six Months Ended In thousands, except per-BOE data June 30, 2021 June 30, 2020 June 30, 2021 June 30, 2020 Total lease operating expenses$ 110,225 $ 81,293$ 192,195 $ 190,563 Total lease operating expenses per BOE$ 24.65 $ 17.80$ 22.01 $ 19.73 Total lease operating expenses increased$28.9 million (36%) and$1.6 million (1%) on an absolute-dollar basis, or$6.85 (38%) and$2.28 (12%) on a per-BOE basis, during the three and six months endedJune 30, 2021 , respectively, compared to the same prior-year periods. The increase during the second quarter of 2021 on an absolute-dollar basis compared to the same period in 2020 was primarily due to (a) higher expenses across nearly all expense categories as our costs are correlated to varying degrees with changes in oil prices, with the largest increases attributable to workovers ($8.4 million ), CO2 expense ($4.4 million ), and power and fuel ($3.7 million ) and (b) 2020 period reduced spending and shut-in production in response to significantly lower oil prices in the second quarter of 2020. Lease operating expenses during the three months endedJune 30, 2021 were further impacted by$7.1 million of expense related to theWind River Basin acquisition inMarch 2021 , as these properties have higher operating costs than our other fields. Lease operating expenses for the six months endedJune 30, 2021 were relatively flat with the same prior-year period as increased expenses resulting from ourWind River Basin acquisition inMarch 2021 and increases in workover and CO2 expense were largely offset by a$11.1 million reduction in power and fuel costs. The significant reduction in power and fuel costs was associated with the severe winter storm inFebruary 2021 which created widespread power outages inTexas and disrupted the Company's operations. Under certain of the Company's power agreements the Company is compensated for its reduced power usage, which resulted in a benefit to the Company of approximately$16.3 million ; as ofJune 30, 2021 ,$9.9 million of these savings were included in "Trade and other receivables, net" and$3.7 million included in "Other assets" in our Unaudited Condensed Consolidated Balance Sheets. Compared to the first quarter of 2021, lease operating expenses in the most recent quarter increased$28.3 million (34%) on an absolute-dollar basis and$5.42 (28%) on a per-BOE basis, due primarily to the first quarter 2021 utility benefit mentioned above, the second quarter of 2021 reflecting a full quarter of operating expenses for theWind River Basin properties acquired inMarch 2021 , as well as increases in workover and CO2 expense. 26 --------------------------------------------------------------------------------
Table of Contents
Denbury Inc.
Management's Discussion and Analysis of Financial Condition and Results of
OperationsTransportation and Marketing Expenses
Transportation and marketing expenses primarily consist of amounts incurred relating to the transportation, marketing, and processing of oil and natural gas production. Transportation and marketing expenses were$8.5 million and$9.4 million for the three months endedJune 30, 2021 and 2020, respectively, and$16.3 million and$19.0 million for the six months endedJune 30, 2021 and 2020, respectively. The decreases between periods were primarily due to lower sales volumes. Taxes Other Than Income Taxes other than income includes production, ad valorem and franchise taxes. Taxes other than income increased$12.0 million (116%) and$11.3 million (38%) during the three and six months endedJune 30, 2021 , respectively, compared to the same prior-year periods, due primarily to an increase in production taxes resulting from higher oil and natural gas revenues.
General and Administrative Expenses ("G&A")
Successor Predecessor Successor Predecessor
Three Months Six Months
In thousands, except per-BOE data and Ended Three Months Ended Ended Six Months Ended
employees June 30, 2021 June 30, 2020 June 30, 2021 June 30, 2020
Cash administrative costs $ 12,898 $ 22,689 $ 27,201 $ 29,969
Stock-based compensation 2,552 1,087 20,232 3,540
G&A expense $ 15,450 $ 23,776 $ 47,433 $ 33,509
G&A per BOE
Cash administrative costs $ 2.89 $ 4.97 $ 3.11 $ 3.10
Stock-based compensation 0.57 0.24 2.32 0.37
G&A expenses $ 3.46 $ 5.21 $ 5.43 $ 3.47
Employees as of period end 690 686
Our G&A expense on an absolute-dollar basis was $15.5 million during the three
months ended June 30, 2021 , a decrease of $8.3 million (35%) from the same
prior-year period, primarily due to modifications in our compensation program
during the second quarter of 2020 which resulted in adjustments to the bonus
program for 2020, as well as certain severance-related costs recorded during the
second quarter of 2020. During the six months ended June 30, 2021 , our G&A
expense increased $13.9 million (42%) primarily due to $15.3 million of
stock-based compensation expense in the first quarter of 2021 resulting from the
full vesting of performance-based equity awards with vesting parameters tied to
the Company's common stock trading prices. The shares underlying these awards
are not currently outstanding as actual delivery of the shares is not scheduled
to occur until after the end of the performance period, December 4, 2023 .
27
--------------------------------------------------------------------------------Table of Contents
Denbury Inc.
Management's Discussion and Analysis of Financial Condition and Results of
OperationsInterest and Financing Expenses
Successor Predecessor Successor Predecessor
Three Months
In thousands, except per-BOE data and Ended Three Months Ended Six Months Ended Six Months Ended
interest rates June 30, 2021 June 30, 2020 June 30, 2021 June 30, 2020
Cash interest(1) $ 1,735 $ 45,263 $ 3,669 $ 91,089
Less: interest not reflected as expense for
financial reporting purposes(1) - (20,912) - (42,266)
Noncash interest expense 685 1,061 1,370 2,092
Amortization of debt discount(2) - 3,934 - 7,829
Less: capitalized interest (1,168) (8,729) (2,251) (18,181)
Interest expense, net $ 1,252 $ 20,617 $ 2,788 $ 40,563
Interest expense, net per BOE $ 0.28 $ 4.51 $ 0.32 $ 4.20
Average debt principal outstanding(3) $ 107,542 $ 2,185,029 $ 121,392 $ 2,186,322
Average cash interest rate(4) 6.5 % 8.3 % 6.0 % 8.3 %
(1)Cash interest during the 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 FASC 470-60, Troubled Debt
Restructuring by Debtors. The portion of interest treated as a reduction of debt
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 on July 30, 2020 (the "Petition Date").
(2)Represents amortization of debt discounts during the Predecessor period
related to the 7¾% Senior Secured Second Lien Notes due 2024 (the "7¾% Senior
Secured Notes") and 6?% Convertible Senior Notes due 2024 (the "2024 Convertible
Senior Notes"). Remaining debt discounts were written-off on the Petition Date.
(3)Excludes debt discounts related to the Predecessor's 7¾% Senior Secured Notes
and 2024 Convertible Senior Notes.
(4)Includes commitment fees but excludes debt issue costs and amortization of
discount.
Cash interest during the three and six months ended June 30, 2021 decreased
$43.5 million (96%) and $87.4 million (96%), respectively, when compared to the
same prior-year periods. The decreases between periods were primarily due to a
decrease in the average debt principal outstanding, with the Successor periods
reflecting the full extinguishment of all outstanding obligations under our
previously outstanding senior secured second lien notes, convertible senior
notes, and senior subordinated notes on the Emergence Date, pursuant to the
terms of the prepackaged joint plan of reorganization, relieving us of
approximately $2.1 billion of debt by issuing equity and/or warrants in the
Successor period to the holders of that debt.
28
--------------------------------------------------------------------------------Table of Contents
Denbury Inc.
Management's Discussion and Analysis of Financial Condition and Results of
OperationsDepletion, Depreciation, and Amortization ("DD&A")
Successor Predecessor Successor Predecessor
Three Months Six Months
Ended Three Months Ended Ended Six Months Ended
In thousands, except per-BOE data June 30, 2021 June 30, 2020 June 30, 2021 June 30, 2020
Oil and natural gas properties$ 28,550 $ 40,290$ 60,565 $
82,859
CO2 properties, pipelines, plants and other property and equipment 7,831 15,124 15,266
32,049
Accelerated depreciation charge(1) - - - 37,368 Total DD&A$ 36,381 $ 55,414$ 75,831 $ 152,276 DD&A per BOE Oil and natural gas properties$ 6.39 $ 8.82$ 6.94 $
8.58
CO2 properties, pipelines, plants and other property and equipment 1.75 3.31 1.74
3.31
Accelerated depreciation charge(1) - - - 3.87 Total DD&A cost per BOE$ 8.14 $ 12.13$ 8.68 $ 15.76 Write-down of oil and natural gas properties $ - $ 662,440$ 14,377 $ 734,981 (1)Represents an accelerated depreciation charge related to capitalized amounts associated with unevaluated properties that were transferred to the full cost pool. The decreases in DD&A expense during the three and six months endedJune 30, 2021 , when compared to the same periods in 2020, were primarily due to lower depletable costs due to the step down in book value resulting from fresh start accounting as ofSeptember 18, 2020 , with the year-over-year decrease further impacted by accelerated depreciation of$37.4 million in the first quarter of 2020 related to unevaluated properties that were transferred to the full cost pool.
Full Cost Pool Ceiling Test Write-Downs
Under full cost accounting rules, we are required each quarter 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 price 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 three months endedMarch 31, 2021 , with first-day-of-the-month NYMEX oil prices for the preceding 12 months averaging$36.40 per Bbl, after adjustments for market differentials and transportation expenses by field. The write-down was primarily a result of the recent acquisition (see Overview -March 2021 Acquisition ofWyoming CO2 EOR Fields) 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. We also recognized full cost pool ceiling test write-downs of$662.4 million and$72.5 million during the Predecessor three months endedJune 30, 2020 andMarch 31, 2020 , respectively. We did not record a ceiling test write-down during the three months endedJune 30, 2021 . 29 --------------------------------------------------------------------------------
Table of Contents
Denbury Inc.
Management's Discussion and Analysis of Financial Condition and Results of
Operations
Income Taxes
Successor Predecessor Successor Predecessor
Three MonthsIn thousands, except per-BOE amounts and Three Months Ended
Ended Six Months Ended Six Months Ended
tax rates June 30, 2021 June 30, 2020 June 30, 2021 June 30, 2020
Current income tax expense (benefit) $ (260) $ 598 $ (451) $ (5,809)
Deferred income tax benefit (36) (102,304) (87) (106,513)
Total income tax benefit $ (296) $ (101,706) $ (538) $ (112,322)
Average income tax benefit per BOE $ (0.07) $ (22.27) $ (0.06) $ (11.63)
Effective tax rate 0.4 % 12.7 % 0.4 % 15.3 %
Total net deferred tax liability $ 1,187 $ 306,186
We evaluate our estimated annual effective income tax rate based on current and
forecasted business results and enacted tax laws on a quarterly basis and apply
this tax rate to our ordinary income or loss to calculate our estimated tax
liability or benefit. Our income taxes are based on an estimated combined
federal and state statutory rate of approximately 25% in 2021 and 2020. Our
effective tax rates for the Successor three and six months ended June 30, 2021
were significantly lower than our estimated statutory rate, primarily due to our
overall deferred tax asset position and the valuation allowance offsetting those
assets. As we had a pre-tax loss for the second quarter of 2021 and first half
of 2021, the income tax benefit resulting from these losses is fully offset by
the change in valuation allowance, resulting in essentially no tax provision.
The tax basis of our assets, primarily our oil and gas properties, is in excess
of their carrying value, as adjusted in fresh start accounting; therefore, we
are currently in a net deferred tax asset position. Based on all available
evidence, both positive and negative, we continue to record a valuation
allowance on our underlying deferred tax assets as of June 30, 2021 , as we
believe our deferred tax assets are not more-likely-than-not to be realized. We
intend to maintain the valuation allowances on our deferred tax assets until
there is sufficient evidence to support the reversal of all or some portion of
the allowances, which will largely be determined based on oil prices and the
Company's ability to generate positive pre-tax income. A $1.2 million state
deferred tax liability is recorded on the Successor balance sheet.
The current income tax benefits for the Predecessor six months ended June 30,
2020 , represent amounts estimated to be receivable resulting from alternative
minimum tax credits.
As of June 30, 2021 , we had $0.6 million of alternative minimum tax credits,
which under the Tax Cut and Jobs Act will be refunded in 2021 and are recorded
as a receivable on the balance sheet. Our state net operating loss carryforwards
expire in various years, starting in 2025.
30
--------------------------------------------------------------------------------Table of Contents
Denbury Inc.
Management's Discussion and Analysis of Financial Condition and Results of
OperationsPer-BOE Data
The following table summarizes our cash flow and results of operations on a per-BOE basis for the comparative periods. Each of the significant individual components is discussed above.
Three Months Ended Six Months Ended
June 30, June 30,
Per-BOE data 2021 2020 2021 2020
Oil and natural gas revenues $ 63.23
(14.17) 9.99 (11.65) 7.28
Lease operating expenses (24.65) (17.80) (22.01) (19.73)
Production and ad valorem taxes (4.88) (1.92) (4.55) (2.77)
Transportation and marketing expenses (1.91) (2.06) (1.87) (1.97)
Production netback 17.62 12.16 19.25 17.90
CO2 sales, net of operating and discovery
expenses 1.93 1.23 1.93 1.33
General and administrative expenses(1) (3.46) (5.21) (5.43) (3.47)
Interest expense, net (0.28) (4.51) (0.32) (4.20)
Stock compensation and other 0.12 (1.71) 1.95 0.22
Changes in assets and liabilities relating
to operations 4.40 0.44 (0.94) (4.24)
Cash flows from operations 20.33 2.40 16.44 7.54
DD&A - excluding accelerated depreciation
charge (8.14) (12.13) (8.68) (11.89)
DD&A - accelerated depreciation charge(2) - - - (3.87)
Write-down of oil and natural gas
properties - (145.04) (1.65) (76.08)
Deferred income taxes 0.01 22.40 0.01 11.03
Gain on extinguishment of debt - - - 1.97
Noncash fair value gains (losses) on
commodity derivatives (24.45) (18.78) (21.37) 3.76
Other noncash items (5.13) (1.56) (1.62) 3.00
Net loss $ (17.38) $ (152.71) $ (16.87) $ (64.54)
(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 six months ended June 30, 2021 , resulting in a significant
non-recurring expense, which if excluded, would have caused these expenses to
average $3.68 per BOE.
(2)Represents an accelerated depreciation charge related to impaired unevaluated
properties that were transferred to the full cost pool.
CRITICAL ACCOUNTING POLICIES
For additional discussion of our critical accounting policies, see Management's Discussion and Analysis of Financial Condition and Results of Operations in our Form 10-K. Any new accounting policies or updates to existing accounting policies as a result of new accounting pronouncements have been included in the notes to the Company's Unaudited Condensed Consolidated Financial Statements contained in this Quarterly Report on Form 10-Q.
FORWARD-LOOKING INFORMATION
The data and/or statements contained in this Quarterly Report on Form 10-Q that are not historical facts, including, but not limited to, statements found in the section Management's Discussion and Analysis of Financial Condition and Results of Operations, regarding possible or assumed future results of operations and cash flows, and other plans and objectives for the future operations ofDenbury , projections or assumptions as to general economic conditions, predictions as to the nature and economics of a carbon capture, use and storage industry ("CCUS"), and anticipated effects of COVID-19 onU.S. and global oil 31 --------------------------------------------------------------------------------
Table of Contents
Denbury Inc.
Management's Discussion and Analysis of Financial Condition and Results of
Operations
demand 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. Such forward-looking statements may
be or may concern, among other things, the level and sustainability of the
recent recovery in worldwide oil prices from their COVID-19 coronavirus caused
downturn, financial forecasts, future hydrocarbon prices and their volatility,
current or future liquidity sources or their adequacy to support our anticipated
future activities, statements or predictions related to the scope, timing and
economic aspects of the carbon capture, use and storage industry or results of
negotiations of CCUS arrangements, possible future write-downs of oil and
natural gas reserves, together with assumptions based on current and projected
production levels, oil and gas prices and oilfield costs, current or future
expectations or estimations of our cash flows or the impact of changes in
commodity prices on cash flows, availability of capital, borrowing capacity,
price and availability of advantageous commodity derivative contracts or the
predicted cash flow benefits therefrom, forecasted capital expenditures,
production, drilling activity or methods, including the timing and location
thereof, the nature of any future asset purchases or sales or the timing or
proceeds thereof, estimated timing of commencement of CO2 flooding of particular
fields or areas, including Cedar Creek Anticline ("CCA"), or its date of
completion, timing of CO2 injections and initial production responses in
tertiary flooding projects, development activities, finding costs, anticipated
future cost savings, capital budgets, interpretation or prediction of formation
details, production rates and volumes or forecasts thereof, hydrocarbon reserve
quantities and values, CO2 reserves and supply and their availability, potential
reserves, barrels or percentages of recoverable original oil in place, the
impact of regulatory rulings or changes, outcomes of pending litigation,
prospective legislation affecting the oil and gas industry, environmental
regulations, mark-to-market values, competition, rates of return, estimated
costs, changes in costs, future capital expenditures and overall economics,
worldwide economic conditions, and other variables surrounding operations and
future plans. Such forward-looking statements generally are accompanied by words
such as "plan," "estimate," "expect," "predict," "forecast," "to our knowledge,"
"anticipate," "projected," "preliminary," "should," "assume," "believe," "may"
or other words that convey, or are intended to convey, the uncertainty of future
events or outcomes. Such forward-looking information is based upon management's
current plans, expectations, estimates, and assumptions and is subject to a
number of risks and uncertainties that could significantly and adversely affect
current plans, anticipated actions, the timing of such actions and our financial
condition and results of operations. 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 are fluctuations in
worldwide oil prices or in U.S. oil prices and consequently in the prices
received or demand for our oil produced; decisions as to production levels
and/or pricing by OPEC+ or production levels by U.S. shale producers in future
periods; levels of future capital expenditures; success of our risk management
techniques; accuracy of our cost estimates; access to and terms of credit in the
commercial banking or other debt markets; fluctuations in the prices of goods
and services; the uncertainty of drilling results and reserve estimates;
operating hazards and remediation costs; disruption of operations and damages
from cybersecurity breaches, or from well incidents, hurricanes, tropical
storms, floods, forest fires, or other natural occurrences; acquisition risks;
requirements for capital or its availability; conditions in the worldwide
financial, trade and credit markets; general economic conditions; competition;
government regulations, including changes in tax or environmental laws or
regulations; and unexpected delays, as well as the risks and uncertainties
inherent in oil and gas drilling and production activities or that are otherwise
discussed in this quarterly report, including, without limitation, the portions
referenced above, and the uncertainties set forth from time to time in our other
public reports, filings and public statements including, without limitation, the
Company's most recent Form 10-K.
32
--------------------------------------------------------------------------------Table of Contents
Denbury Inc.
© Edgar Online, source
