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 and assets focused on carbon capture, use, and storage ("CCUS") and enhanced oil recovery ("EOR") in theGulf Coast andRocky Mountain regions. For over two decades, the Company has maintained a unique strategic focus on utilizing CO2 in its EOR operations and since 2012 has also been active in CCUS through the injection of captured industrial-sourced CO2. The Company currently injects over three million tons of captured industrial-sourced CO2 annually, and its objective is 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 production 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 items and production, 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 December 31, Three Months Ended In thousands, except per-unit data March 31, 2021 2020 March 31, 2020 Oil, natural gas, and related product sales$ 235,445 $ 178,787 $ 229,624 Receipt (payment) on settlements of commodity derivatives (38,453) 14,429 24,638 Oil, natural gas, and related product sales and commodity settlements, combined$ 196,992 $ 193,216 $ 254,262 Average daily production (BOE/d) 47,357 48,805 55,965 Average net realized prices Oil price per Bbl - excluding impact of derivative settlements$ 56.28 $ 40.63 $ 45.96 Oil price per Bbl - including impact of derivative settlements 47.00 43.94 50.92 17
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NYMEX WTI oil prices strengthened from the mid-$40s per Bbl range in
First Quarter 2021 Financial Results and Highlights. We recognized a net loss of$69.6 million , or$1.38 per diluted common share, during the first quarter of 2021, compared to net income of$74.0 million , or$0.14 per diluted common share, during the first quarter of 2020. The principal determinant of our comparative first quarter results between 2020 and 2021 was the$262.5 million increase in commodity derivatives expense ($115.7 million of expense during the first quarter of 2021 compared to$146.8 million of income during the first quarter of 2020), resulting from a$199.4 million loss on noncash fair value changes and a$63.1 million decrease in cash receipts upon contract settlements ($38.5 million in payments during the first quarter of 2021 compared to$24.6 million in receipts upon settlements during the first quarter of 2020). Additional drivers of the comparative operating results were the following: •Oil and natural gas revenues increased$5.8 million (3%), as the increase in commodity prices was largely offset by production declines; •A$14.4 million full cost pool ceiling test write-down during the first quarter of 2021 compared to a$72.5 million write-down in the prior-year period; •A reduction in depletion, depreciation, and amortization expense of$57.4 million as a result of a$37.4 million accelerated depreciation charge recorded in the first quarter of 2020 and lower depletable costs due to the step down in book value resulting from fresh start accounting on the Emergence Date; •A$27.3 million reduction in lease operating expense across nearly all expense categories with the largest decrease in power and fuel ($16.0 million ) primarily associated with the severe winter storm inFebruary 2021 which created significant power outages inTexas and disrupted the Company's operations. Other significant drivers included lower workover costs ($3.2 million ) and a decrease of$4.4 million due to the Gulf Coast Working Interests Sale inMarch 2020 ; •A$22.3 million increase in general and administrative expense in the first quarter of 2021 primarily due to non-recurring stock-based compensation expense of$15.3 million in the first quarter of 2021 due to 100% vesting of performance awards upon the achievement of specified common stock trading price levels; •An$18.4 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 inSeptember 2020 ; and •A noncash gain on debt extinguishment of$19.0 million in the first quarter of 2020.March 2021 Acquisition ofWyoming CO2 EOR Fields. OnMarch 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 inWyoming 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 inJanuary 2022 and one inJanuary 2023 , of$4 million each, conditioned on NYMEX WTI oil prices averaging at least$50 per Bbl during 2021 and 2022, respectively. As ofMarch 31, 2021 , the contingent consideration was recorded on our unaudited condensed consolidated balance sheets at its fair value of$5.3 million .Wind River Basin production averaged approximately 2,700 BOE/d from theMarch 3, 2021 acquisition date throughMarch 31, 2021 , contributing 871 BOE/d to first quarter of 2021 average daily production. Carbon Capture, Use and Storage. In addition to our oil and natural gas operations, our strategically located and extensive CO2 pipeline infrastructure provides a meaningful opportunity to participate in the emerging CCUS industry. We believe that the assets and technical expertise required for CCUS are highly aligned with our existing CO2 EOR operations, providing us with an advantage, particularly in theGulf Coast region, where our CO2 infrastructure is located in close proximity to multiple large sources of industrial emissions. During the first quarter of 2021, approximately 36% 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 supportiveU.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 have begun engaging in discussions with third-party industrial CO2 emitters regarding transportation and storage solutions and identifying future sequestration sites and landowners of those locations. While our financial and operational results today do not reflect activities associated with the emerging CCUS industry, and development of this business is likely to take several years, we believeDenbury is well positioned to leverage our existing CO2 pipeline infrastructure and EOR expertise to be a leader in this industry. 18
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Denbury Inc.
Management's Discussion and Analysis of Financial Condition and Results of
OperationsCAPITAL 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 outlays relate to our development capital expenditures and current period operating expenses, as well as our pipeline financing obligations associated with the NEJD pipeline. During the first quarter of 2021,Denbury paid$17.5 million to Genesis Energy, L.P. in the first of four quarterly installments totaling$70.0 million to be paid during 2021 in accordance with the restructuring of our NEJD CO2 pipeline system. The second quarterly installment of$17.5 million was paid inApril 2021 , and the remaining quarterly payments are payable onJuly 31 andOctober 31, 2021 . As ofMarch 31, 2021 , we had$75 million of outstanding borrowings on our$575 million senior secured bank credit facility, leaving us with$477.0 million of borrowing base availability after consideration of$23.0 million of outstanding letters of credit. Our borrowing base availability coupled with unrestricted cash of$5.6 million , provides us total liquidity of$482.6 million as ofMarch 31, 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 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. Based on these capital spending plans, we currently anticipate 2021 average daily production to be between 47,500 BOE/d and 51,500 BOE/d, including the Big Sand Draw andBeaver Creek working interests acquisition which closed in earlyMarch 2021 . 19
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Capital Expenditure Summary. The following table reflects incurred capital
expenditures (including accrued capital) for the three months ended March 31,
2021 and 2020:
Three Months Ended
March 31,
In thousands 2021 2020
Capital expenditure summary
CCA tertiary development $ 36 $ 1,354
Other tertiary oil fields 4,080 13,372
Non-tertiary fields 8,342 10,954
Capitalized internal costs(1) 7,600 8,881
Oil and natural gas capital expenditures 20,058 34,561
CCA CO2 pipeline 21
4,175
Other CO2 pipelines, sources and other -
49
Development capital expenditures 20,079
38,785
Acquisitions of oil and natural gas properties(2) 10,665
42
Capital expenditures, before capitalized interest 30,744 38,827 Capitalized interest 1,083 9,452 Capital expenditures, total$ 31,827 $ 48,279 (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; nonetheless, we may seek other sources of funding or fund any potential shortfall with incremental borrowings under our senior secured bank credit facility. 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 period 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 times. 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 ofMarch 31, 2021 , our ratio of consolidated total debt to consolidated EBITDAX was 0.38 to 1.0 (with a maximum permitted ratio of 3.5 to 1.0) and our current ratio was 3.49 to 1.0 (with a required ratio of not less than 1.0 to 1.0). Based upon our currently forecasted levels of 20 --------------------------------------------------------------------------------
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Management's Discussion and Analysis of Financial Condition and Results of
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production and costs, hedges in place as of
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 consists 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 three months endedMarch 31, 2021 , our long-term asset retirement obligations increased by$44.1 million , primarily related to our acquisition of working interest positions inWyoming CO2 EOR fields (see Note 2, Acquisition). Off-Balance Sheet Arrangements. Our off-balance sheet arrangements include obligations for various development and exploratory expenditures that arise from our normal capital expenditure program or from other transactions common to our industry, none of which are recorded on our balance sheet. In addition, in order to recover our undeveloped proved reserves, we must also fund the associated future development costs estimated in our proved reserve reports. 21 --------------------------------------------------------------------------------
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Management's Discussion and Analysis of Financial Condition and Results of
OperationsRESULTS OF OPERATIONS
Certain of our financial and operating results and statistics for the comparative three months endedMarch 31, 2021 and 2020 are included in the following table: Successor Predecessor Three Months Ended Three Months Ended In thousands, except per-share and unit data March 31, 2021 March 31, 2020 Financial results Net income (loss)$ (69,642) $ 74,016 Net income (loss) per common share - basic (1.38) 0.15 Net income (loss) per common share - diluted (1.38) 0.14 Net cash provided by operating activities 52,656 61,842 Average daily production volumes Bbls/d 46,007 54,649 Mcf/d 8,102 7,899 BOE/d(1) 47,357 55,965 Oil and natural gas sales Oil sales$ 233,044 $ 228,577 Natural gas sales 2,401 1,047 Total oil and natural gas sales$ 235,445 $ 229,624 Commodity derivative contracts(2) Receipt (payment) on settlements of commodity derivatives$ (38,453) $ 24,638 Noncash fair value gains (losses) on commodity derivatives (77,290) 122,133 Commodity derivatives income (expense)$ (115,743) $ 146,771
Unit prices - excluding impact of derivative settlements Oil price per Bbl
$ 56.28 $ 45.96 Natural gas price per Mcf 3.29 1.46
Unit prices - including impact of derivative settlements(2) Oil price per Bbl
$ 47.00 $ 50.92 Natural gas price per Mcf 3.29 1.46 Oil and natural gas operating expenses Lease operating expenses$ 81,970 $ 109,270 Transportation and marketing expenses 7,797 9,621 Production and ad valorem taxes 17,895 17,987
Oil and natural gas operating revenues and expenses per BOE Oil and natural gas revenues
$ 55.24 $ 45.09 Lease operating expenses 19.23 21.46 Transportation and marketing expenses 1.83 1.89 Production and ad valorem taxes 4.20 3.53 CO2 - revenues and expenses CO2 sales and transportation fees$ 9,228 $ 8,028 CO2 operating and discovery expenses (993) (752) CO2 revenue and expenses, net$ 8,235 $ 7,276 (1)Barrel of oil equivalent using the ratio of one barrel of oil to six Mcf of natural gas ("BOE"). (2)See also Commodity Derivative Contracts below and Item 3. Quantitative and Qualitative Disclosures about Market Risk for information concerning our derivative transactions. 22
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Management's Discussion and Analysis of Financial Condition and Results of
OperationsProduction
Average daily production by area for each of the four quarters of 2020 and for the first quarter of 2021 is shown below:
Average Daily Production (BOE/d)
First First Second Third Fourth
Quarter Quarter Quarter Quarter Quarter
Operating Area 2021 2020 2020 2020 2020
Tertiary oil production
Gulf Coast region
Delhi 2,925 3,813 3,529 3,208 3,132
Hastings 4,226 5,232 4,722 4,473 4,598
Heidelberg 4,054 4,371 4,366 4,256 4,198
Oyster Bayou 3,554 3,999 3,871 3,526 3,880
Tinsley 3,424 4,355 3,788 4,042 3,654
Other(1) 6,098 7,161 5,944 6,271 6,332
Total Gulf Coast region 24,281 28,931 26,220 25,776 25,794
Rocky Mountain region
Bell Creek 4,614 5,731 5,715 5,551 5,079
Other(2) 2,573 2,199 1,393 2,167 2,007
Total Rocky Mountain region 7,187 7,930 7,108 7,718 7,086
Total tertiary oil production 31,468 36,861 33,328 33,494 32,880
Non-tertiary oil and gas production
Gulf Coast region
Total Gulf Coast region 3,621 4,173 3,805 3,728 3,523
Rocky Mountain region
Cedar Creek Anticline 11,150 13,046 11,988 11,485 11,433
Other(2) 1,118 1,105 1,069 979 969
Total Rocky Mountain region 12,268 14,151 13,057 12,464 12,402
Total non-tertiary production 15,889 18,324 16,862 16,192 15,925
Total continuing production 47,357 55,185 50,190 49,686 48,805
Property sales
Gulf Coast Working Interests Sale(3) - 780 - - -
Total production 47,357 55,965 50,190 49,686 48,805
(1)Other Gulf Coast properties primarily consist of mature properties
(Brookhaven, Cranfield, Eucutta, Little Creek , Mallalieu, Martinville, McComb
and Soso fields) and West Yellow Creek Field .
(2)Includes production related to our working interest positions in the Big Sand
Draw and Beaver Creek enhanced oil recovery fields acquired on March 3, 2021 .
(3)Includes non-tertiary production 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 production during the first quarter of 2021 averaged 47,357 BOE/d,
including 31,468 Bbls/d from tertiary properties and 15,889 BOE/d from
non-tertiary properties. This production level represents a decrease of 1,448
BOE/d (3%) compared to production levels in the fourth quarter of 2020 and a
decrease of 7,828 BOE/d (14%) compared to first quarter of 2020 continuing
production, which is adjusted to exclude production related to our Gulf Coast
Working Interests Sale in March 2020 . The decreases on a sequential-quarter and
year-over-year period basis included the impact of weather-related downtime of
approximately 1,400 BOE/d resulting from the February 2021 winter storms that
impacted the Gulf Coast region, with the year-over-year decline more
significantly impacted by reduced capital investment and 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
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sequential-quarter production decline was partially offset by production
increases from Wind River Basin enhanced oil recovery fields acquired on March
3, 2021 . Wind River Basin production averaged approximately 2,700 BOE/d from the
March 3, 2021 acquisition date through March 31, 2021 , contributing 871 BOE/d to
first quarter of 2021 average daily production.
Our production during the three months ended
Oil and Natural Gas Revenues
Our oil and natural gas revenues during the three months endedMarch 31, 2021 increased 3% compared to these revenues for the same period in 2020. 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: Three Months Ended March 31, 2021 vs. 2020 Increase Percentage Increase (Decrease) in (Decrease) in In thousands Revenues Revenues Change in oil and natural gas revenues due to: Decrease in production$ (37,455) (16) % Increase in realized commodity prices 43,276 19 % Total increase in oil and natural gas revenues$ 5,821 3 %
Excluding any impact of our commodity derivative contracts, our average net
realized commodity prices and NYMEX differentials were as follows during the
three months ended
Three Months Ended
March 31,
2021 2020
Average net realized prices
Oil price per Bbl $ 56.28 $ 45.96
Natural gas price per Mcf 3.29 1.46
Price per BOE 55.24 45.09
Average NYMEX differentials
Gulf Coast region
Oil per Bbl $ (1.37) $ 1.18
Natural gas per Mcf 0.68 (0.06)
Rocky Mountain region
Oil per Bbl $ (1.80) $ (2.78)
Natural gas per Mcf 0.49 (0.91)
Total Company
Oil per Bbl $ (1.54) $ (0.38)
Natural gas per Mcf 0.58 (0.41)
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 theGulf Coast region was a negative$1.37 per Bbl during the first quarter of 2021, compared to a positive$1.18 per Bbl during the first quarter of 2020 and a negative 24 --------------------------------------------------------------------------------
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$1.85 per Bbl during the fourth quarter of 2020. For both the first quarter of
2020 and for many years prior, our Gulf Coast region differentials have
generally been positive to NYMEX due to historically higher prices received for
Gulf 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 2020 and the first quarter of 2021.
•Rocky Mountain Region. NYMEX oil differentials in the Rocky Mountain region
averaged $1.80 per Bbl and $2.78 per Bbl below NYMEX during the first quarters
of 2021 and 2020, respectively, and $2.30 per Bbl below NYMEX during the fourth
quarter of 2020. Differentials in the Rocky Mountain region tend to fluctuate
with regional supply and demand trends and can fluctuate significantly on a
month-to-month basis due to weather, refinery or transportation issues, and
Canadian and U.S. crude oil price index volatility.
CO2 Revenues and Expenses
We sell 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 months endedMarch 31, 2021 and 2020: Successor Predecessor Three Months Ended Three Months Ended In thousands March 31, 2021 March 31, 2020
Receipt (payment) on settlements of commodity derivatives
$ 24,638
Noncash fair value gains (losses) on commodity
derivatives (77,290) 122,133
Total income (expense) $ (115,743) $ 146,771
Changes in our commodity derivatives expense were primarily related to the
expiration of commodity derivative contracts, new commodity derivative contracts
entered into for future periods, and to the changes in oil futures prices
between the first quarter of 2020 and 2021. The period-to-period change reflects
the very large fluctuations in oil prices between March 2020 ($30.45 per
barrel), when worldwide financial markets were first beginning to absorb the
potential impact of a global pandemic, and March 2021 oil prices ($62.36 per
barrel) as prospects for increased economic activity and oil demand continue to
improve.
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
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derivative contracts as of March 31, 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 May 5, 2021 :
2Q 2021 2H 2021 1H 2022 2H 2022
WTI NYMEX Volumes Hedged (Bbls/d) 29,000 29,000 15,500 8,000
Fixed-Price Swaps Swap Price(1)$43.86 $43.86 $49.01
WTI NYMEX Volumes Hedged (Bbls/d) 4,000 4,000 8,000 7,000
Collars Floor / Ceiling Price(1) $46.25 / $53.04 $46.25 / $53.04 $49.69 / $62.16
Total Volumes Hedged (Bbls/d) 33,000 33,000 23,500 15,000
(1)Averages are volume weighted.
Based on current contracts in place and NYMEX oil futures prices as ofMay 5, 2021 , which averaged approximately$64 per Bbl, we currently expect that we would make cash payments of approximately$175 million upon settlement of our April 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 Three Months Ended Three Months Ended In thousands, except per-BOE data March 31, 2021 March 31, 2020 Total lease operating expenses $ 81,970
$ 109,270
Total lease operating expenses per BOE $ 19.23 $ 21.46 Total lease operating expenses decreased$27.3 million (25%) on an absolute-dollar basis, or$2.23 (10%) on a per-BOE basis, during the three months endedMarch 31, 2021 , compared to the same prior-year period. The decrease on an absolute-dollar basis was primarily due to lower expenses across nearly all expense categories, with the largest decreases attributable to power and fuel ($16.0 million ), workovers ($3.2 million ), and an approximate$4.4 million decrease due to the Gulf Coast Working Interests Sale inMarch 2020 . The significant reduction in power and fuel costs is associated with the severe winter storm inFebruary 2021 which created significant 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$14.9 million ($4.2 million included in "Trade and other receivables, net" and$10.7 million included in "Other assets" in our Unaudited Condensed Consolidated Balance Sheets). When netting the impacts on our production and revenues and other incremental costs from the winter storm with this benefit, we estimate the overall impact to our first quarter results was a positive$6 million . Lease operating expenses in periods subsequent to the first quarter will return to higher levels as this adjustment is not expected to reoccur. Compared to the fourth quarter of 2020, lease operating expenses decreased$7.8 million (9%) on an absolute-dollar basis and$0.76 (4%) on a per-BOE basis, due to the utility benefit mentioned above, partially offset by minor increases across various expense categories, as well as to the acquisition of the Big Sand Draw andBeaver Creek fields inMarch 2021 .
Transportation 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$7.8 million and$9.6 million for the three months endedMarch 31, 2021 and 2020. The decrease between periods was primarily due to lower marketing expenses. 26 --------------------------------------------------------------------------------
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Denbury Inc.
Management's Discussion and Analysis of Financial Condition and Results of
OperationsTaxes Other Than Income
Taxes other than income includes production, ad valorem and franchise taxes. Taxes other than income were relatively unchanged during the three months endedMarch 31, 2021 , compared to the same prior-year period, as the increase in production taxes resulting from higher oil and natural gas revenues was offset by the decrease in ad valorem taxes.
General and Administrative Expenses ("G&A")
Successor Predecessor
Three Months Ended Three Months Ended
In thousands, except per-BOE data and employees March 31, 2021 March 31, 2020
Cash administrative costs $ 14,303 $ 7,280
Stock-based compensation 17,680 2,453
G&A expense $ 31,983 $ 9,733
G&A per BOE
Cash administrative costs $ 3.35 $ 1.43
Stock-based compensation 4.15 0.48
G&A expenses $ 7.50 $ 1.91
Employees as of period end 677 718
Our net G&A expense on an absolute-dollar basis was $32.0 million during the
three months ended March 31, 2021 , an increase of $22.3 million from the same
prior-year period, primarily due to cash and noncash performance-based
compensation. Net cash administrative costs increased during the three months
ended March 31, 2021 primarily due to a $13.2 million increase in our bonus
expense, compared to no expense for bonuses during the first quarter of 2020,
partially offset by lower employee-related costs due to lower headcount. During
the first quarter of 2021, certain performance-based equity awards with vesting
parameters tied to the Company's common stock trading prices became fully
vested, resulting in $15.3 million of stock-based compensation expense. The
awards were granted on December 4, 2020 , and although the performance measures
for vesting of these awards have been achieved, 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 .
Interest and Financing Expenses
Successor Predecessor
Three Months
Ended Three Months Ended
In thousands, except per-BOE data and interest rates March 31, 2021 March 31, 2020
Cash interest(1) $ 1,934 $ 45,826
Less: interest not reflected as expense for financial reporting purposes(1)
- (21,354)
Noncash interest expense 685 1,031
Amortization of debt discount(2) - 3,895
Less: capitalized interest (1,083) (9,452)
Interest expense, net $ 1,536 $ 19,946
Interest expense, net per BOE $ 0.36 $ 3.92
Average debt principal outstanding(3) $ 135,396 $ 2,187,615
Average cash interest rate(4) 5.7 % 8.4 %
(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
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Denbury Inc.
Management's Discussion and Analysis of Financial Condition and Results of
Operations
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 months ended March 31, 2021 was $1.9 million ,
compared to $45.8 million in the same prior-year period. The decrease between
periods was primarily due to a decrease in the average debt principal
outstanding, with the Successor period 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.
Depletion, Depreciation, and Amortization ("DD&A")
Successor Predecessor
Three Months Ended Three Months Ended
In thousands, except per-BOE data March 31, 2021 March 31, 2020
Oil and natural gas properties $ 32,015 $ 42,569
CO2 properties, pipelines, plants and other property and equipment
7,435 16,925
Accelerated depreciation charge(1) - 37,368
Total DD&A $ 39,450 $ 96,862
DD&A per BOE
Oil and natural gas properties $ 7.51 $ 8.36
CO2 properties, pipelines, plants and other property and equipment
1.75 3.32
Accelerated depreciation charge(1) - 7.34
Total DD&A cost per BOE $ 9.26 $ 19.02
Write-down of oil and natural gas properties $ 14,377 $ 72,541
(1)Represents an accelerated depreciation charge related to capitalized amounts
associated with unevaluated properties that were transferred to the full cost
pool.
The decrease in DD&A expense during the three months ended March 31, 2021 , when
compared to the same period in 2020, was primarily due to accelerated
depreciation of $37.4 million related to unevaluated properties that were
transferred to the full cost pool during the prior-year period and lower
depletable costs due to the step down in book value resulting from fresh start
accounting as of September 18, 2020 .
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 28 --------------------------------------------------------------------------------
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Denbury Inc.
Management's Discussion and Analysis of Financial Condition and Results of
Operations
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 a full cost pool ceiling test write-down of $72.5 million during the
three months ended March 31, 2020 .
Income Taxes
Successor Predecessor
Three Months Ended Three Months Ended
In thousands, except per-BOE amounts and tax rates March 31, 2021 March 31, 2020
Current income tax benefit $ (191) $ (6,407)
Deferred income tax benefit (51) (4,209)
Total income tax benefit $ (242) $ (10,616)
Average income tax benefit per BOE $ (0.05) $ (2.09)
Effective tax rate 0.3 % (16.7) %
Total net deferred tax liability $ 1,224 $ 406,021
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 rate for the Successor period ended March 31, 2021 was
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 first quarter of 2021, the income tax
benefit resulting from that loss 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 March 31, 2021 , as we believe our deferred
tax assets are not more-likely-than-not to be realized and, as such, we have a
total valuation allowance of $122.5 million recorded at March 31, 2021 . 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 period represent amounts
estimated to be receivable resulting from alternative minimum tax credits and
certain state tax obligations.
As of March 31, 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.
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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
March 31,
Per-BOE data 2021 2020
Oil and natural gas revenues $ 55.24 $ 45.09
Receipt (payment) on settlements of commodity derivatives (9.02) 4.84
Lease operating expenses (19.23) (21.46)
Production and ad valorem taxes (4.20) (3.53)
Transportation and marketing expenses (1.83) (1.89)
Production netback 20.96 23.05
CO2 sales, net of operating and discovery expenses 1.94 1.43
General and administrative expenses(1) (7.50) (1.91)
Interest expense, net (0.36) (3.92)
Stock compensation and other 3.85 1.92
Changes in assets and liabilities relating to operations (6.54) (8.43)
Cash flows from operations 12.35 12.14
DD&A - excluding accelerated depreciation charge (9.26) (11.68)
DD&A - accelerated depreciation charge(2) - (7.34)
Write-down of oil and natural gas properties (3.37) (14.24)
Deferred income taxes 0.01 0.83
Gain on extinguishment of debt - 3.73
Noncash fair value gains (losses) on commodity derivatives (18.14) 23.98
Other noncash items 2.07 7.11
Net income (loss) $ (16.34) $ 14.53
(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 three months ended March 31, 2021 , resulting in a significant
non-recurring expense in the current quarter, which if excluded, would have
caused these expenses to average $3.92 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, and information regarding the available sources of liquidity, possible or assumed future results of operations, and other plans and objectives for the future operations ofDenbury , projections or assumptions as to general economic conditions, and anticipated continuation of the COVID-19 pandemic and its impact onU.S. and global oil 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"), 30 --------------------------------------------------------------------------------
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Denbury Inc.
Management's Discussion and Analysis of Financial Condition and Results of
Operations
that involve a number of risks and uncertainties. Such forward-looking
statements may be or may concern, among other things, the timing 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, statement or predictions
related to the scope, timing and economic aspects of the carbon capture, use and
storage industry, 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, 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 the availability of capital for CCA pipeline
construction, or its ultimate cost or 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 and natural gas; 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 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.
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