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 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. OVERVIEWDenbury 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, making the Company's scope 1 and 2 CO2 emissions negative today, with a goal to also 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 volumes are oil. Changes in oil prices impact all aspects of our business; most notably our cash flows from operations, revenues, capital allocation and budgeting decisions, and oil and natural gas reserves volumes. The table below 19 --------------------------------------------------------------------------------
Table of Contents
Denbury Inc.
Management's Discussion and Analysis of Financial Condition and Results of
Operations
outlines selected financial items and sales volumes, along with changes in our
realized oil prices, before and after commodity derivative impacts, for our most
recent comparative quarterly periods:
Three Months Ended
In thousands, except per-unit
data Sept. 30, 2021 June 30, 2021 March 31, 2021 Dec. 31, 2020 Sept. 30, 2020
Oil, natural gas, and related
product sales $ 308,454 $ 282,708 $ 235,445 $ 178,787 $ 175,411
Receipt (payment) on
settlements of commodity
derivatives (77,670) (63,343) (38,453) 14,429 17,789
Oil, natural gas, and related
product sales and commodity
settlements, combined $ 230,784 $ 219,365 $ 196,992 $ 193,216 $ 193,200
Average daily sales (BOE/d) 49,682 49,133 47,357 48,805 49,686
Average net realized oil
prices
Oil price per Bbl - excluding
impact of derivative
settlements $ 68.88 $ 64.70 $ 56.28 $ 40.63 $ 39.23
Oil price per Bbl - including
impact of derivative
settlements 51.35 50.10 47.00 43.94 43.23
NYMEX WTI oil prices strengthened from the mid-$40s per Bbl range in December
2020 to an average of approximately $71 per Bbl during the third quarter of
2021, reaching highs of over $75 per Bbl in early-July 2021 and late-September
2021 .
The benefit of the steady growth in our oil sales over the last four quarters
due to rising oil prices has been offset in part by our payments on settlement
of commodity derivative contracts, especially in the second and third quarters
of 2021, principally due to the strike prices of our fixed-price swaps which
were entered into in late 2020 based on the hedging requirements we were
obligated to meet under our bank credit facility. During the first nine months
of 2021, we paid $179.5 million related to the expiration of commodity
derivative contracts and expect to make additional payments on the settlement of
our contracts expiring during the fourth quarter of 2021. Our current hedging
levels decrease significantly in 2022, and we are hedged at more favorable
prices and with a greater mix of collars, allowing for additional upside. We do
not have any additional hedging requirements under our bank credit facility.
Third Quarter 2021 Financial Results and Highlights. We recognized net income of
$82.7 million , or $1.51 per diluted common share, during the third quarter of
2021. As a result of Denbury filing for bankruptcy and emerging from bankruptcy
during the same quarter, our prior-year quarterly financial results are broken
out between the predecessor period (July 1, 2020 through September 18, 2020 ) and
the successor period (September 19, 2020 through September 30, 2020 ). For the
predecessor period from July 1, 2020 through September 18, 2020 , we recognized a
net loss of $809.1 million , and for the successor period from September 19, 2020
through September 30, 2020 , we recognized net income of $2.8 million . The
principal determinant of our comparative third quarter results between 2020 and
2021 were (a) an $850.0 million charge for reorganization items, net, during the
prior-year predecessor period, primarily consisting of fresh start accounting
adjustments and (b) a $261.7 million full cost pool ceiling test write-down
during the prior-year predecessor period. Additional drivers of the comparative
operating results include the following:
•Oil and natural gas revenues increased $133.0 million (76%), nearly entirely
due to an increase in commodity prices;
•Lease operating expenses increased $45.3 million , primarily due to (a) a $15.4
million insurance reimbursement that reduced lease operating expenses in the
prior-year period, (b) an increase of $8.1 million related to the March 2021
Wind River Basin acquisition, and (c) higher expenses across all lease operating
expense categories, largely driven by higher commodity prices and increased
workover activity; and
•Commodity derivatives expense increased by $41.2 million consisting of a $95.5
million decrease in cash receipts upon contract settlements ($77.7 million in
payments during the third quarter of 2021 compared to $17.8 million in receipts
upon settlements during the third quarter of 2020), partially offset by a $54.3
million improvement in noncash fair value changes ($35.9 million of income in
the current period compared to $18.4 million of expense in the prior-year
period).
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Denbury Inc.
Management's Discussion and Analysis of Financial Condition and Results of
Operations
Third Quarter 2021 Houston Area Land Sales. During the third quarter of 2021, we
completed sales of a portion of certain non-producing surface acreage in the
Houston area. We recognized cash proceeds of $11.8 million from the sales and
recorded a $7.0 million gain to "Other income" in our Unaudited Condensed
Consolidated Statements of Operations.
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.
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 $10.9
million cash (after 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 each of 2021 and 2022. As of
September 30, 2021 , the contingent consideration was recorded on our unaudited
condensed consolidated balance sheets at its fair value of $7.4 million , a
$2.1 million increase from the March 2021 acquisition date fair value. This
$2.1 million increase at September 30, 2021 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 3,015 BOE/d during the third 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 nine months ended
September 30, 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.
As we seek to grow our CCUS business and pursue new CCUS opportunities, we have
been engaged in discussions with existing and potential third-party industrial
CO2 emitters regarding transportation and storage solutions, while also
identifying potential future sequestration sites and landowners of those
locations. We continue to make progress in these discussions and have recently
executed several term sheets for the future transportation and sequestration of
CO2. 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 cash flows from operations and availability under our senior secured bank credit facility are our primary sources of capital and liquidity. Our most significant cash capital outlays in 2021 relate to our budgeted development capital expenditures and payment of$70 million of pipeline financing obligations associated with the NEJD pipeline. Based on our current 2021 full-year projections using recent oil price futures, our cash flow from operations in 2021 should be more than adequate to cover our remaining budgeted development capital expenditures and also cover a significant portion of our$70 million repayment of pipeline financing obligations. In addition,$29.8 million of non-producing property sales in the first nine months of 2021 provided cash to further reduce our debt. As ofSeptember 30, 2021 , we had no outstanding borrowings on our$575 million senior secured bank credit facility, leaving us with$563.2 million of borrowing base availability after consideration of$11.8 million of outstanding letters of credit. Our borrowing base availability, coupled with unrestricted cash of$1.8 million provides us total liquidity of 21 --------------------------------------------------------------------------------
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Denbury Inc.
Management's Discussion and Analysis of Financial Condition and Results of
Operations2021 Capital Expenditures. Capital expenditures during the first nine months of 2021 were$173.8 million . We continue to 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 . Approximately 45% of our 2021 capital expenditures throughSeptember 30, 2021 have been focused on the previously announced development of the EOR CO2 flood at Cedar Creek Anticline ("CCA"). The project is currently underway, with completion of the 105-mile extension of the Greencore CO2 pipeline fromBell Creek to CCA expected before the end ofNovember 2021 , first CO2 injection planned during the first quarter of 2022, and first tertiary production expected in the second half of 2023.
Capital Expenditure Summary. The following table reflects incurred capital
expenditures for the nine months ended
Nine Months Ended
September 30,
In thousands 2021 2020
Capital expenditure summary(1)
Tertiary and non-tertiary fields $ 102,640 $ 41,679
Capitalized internal costs(2) 22,639
26,695
Oil and natural gas capital expenditures 125,279
68,374
CCA CO2 pipeline 48,542
9,192
Development capital expenditures 173,821
77,566
Acquisitions of oil and natural gas properties(3) 10,927
95
Capital expenditures, before capitalized interest 184,748 77,661 Capitalized interest 3,500 23,068 Capital expenditures, total$ 188,248 $ 100,729 (1)Capital expenditures in this summary are presented on an as-incurred basis (including accruals), and are$45.2 million higher than the capital expenditures in the Unaudited Condensed Consolidated Statements of Cash Flows which are presented on a cash basis. (2)Includes capitalized internal acquisition, exploration and development costs and pre-production tertiary startup costs. (3)Primarily consists of working interest positions in theWind River Basin enhanced oil recovery fields acquired onMarch 3, 2021 . SupplyChain Issues and Potential Cost Inflation. Recent worldwide andU.S. supply chain issues, together with rising commodity prices and tight labor markets in theU.S. , could increase our costs in 2022 and future periods. Most of the cost inflation pressures we have experienced during 2021 have been tied to rising fuel and power costs in our operations; however, there is the potential for more significant increases in the cost of goods and services and wages in our operations which could negatively impact our results of operations and cash flows in future periods. 22 --------------------------------------------------------------------------------
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Denbury Inc.
Management's Discussion and Analysis of Financial Condition and Results of
Operations
Senior Secured Bank Credit Agreement. In September 2020 , we entered into a bank
credit agreement with JPMorgan 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 of
January 30, 2024 . As part of our fall 2021 semiannual borrowing base
redetermination, the borrowing base and lender commitments for our Bank Credit
Agreement were reaffirmed at $575 million , with our next scheduled
redetermination around May 1, 2022 . The borrowing base is adjusted at the
lenders' discretion and is based, in part, upon external factors over which we
have no control. If our outstanding debt under the Bank Credit Agreement exceeds
the then-effective borrowing base, we would be required to repay the excess
amount over a period not to exceed six months. The Bank Credit Agreement
contains certain financial performance covenants including the following:
•A Consolidated Total Debt to Consolidated EBITDAX covenant (as defined in the
Bank Credit Agreement), with such ratio not to exceed 3.5 times; and
•A requirement to maintain a current ratio (i.e., Consolidated Current Assets to
Consolidated Current Liabilities) of 1.0.
For purposes of computing the current ratio per the Bank Credit Agreement,
Consolidated Current Assets exclude the current portion of derivative assets but
include available borrowing capacity under the Bank Credit Agreement, and
Consolidated Current Liabilities exclude the current portion of derivative
liabilities as well as the current portions of long-term indebtedness
outstanding. Under these financial performance covenant calculations, as of
September 30, 2021 , our ratio of consolidated total debt to consolidated EBITDAX
was 0.05 to 1.0 (with a maximum permitted ratio of 3.5 to 1.0) and our current
ratio was 2.60 to 1.0 (with a required ratio of not less than 1.0 to 1.0). Based
upon our currently forecasted levels of production and costs, hedges in place as
of November 3, 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 the SEC on September 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 of December 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 nine
months ended September 30, 2021 , our long-term asset retirement obligations
increased by $63.8 million , primarily related to our acquisition of working
interest positions in Wyoming CO2 EOR fields (see Note 2, Acquisition and
Divestitures).
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.
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Denbury Inc.
Management's Discussion and Analysis of Financial Condition and Results of
OperationsRESULTS OF OPERATIONS
Certain of our financial results for our Successor and Predecessor periods are presented in the following tables:
Successor Predecessor
Three Months Period from
Ended Sept. 19, 2020 Period from July
Sept. 30, through 1, 2020 through
In thousands, except per-share and unit data 2021 Sept. 30, 2020 Sept. 18, 2020
Operating results
Net income (loss)(1) $ 82,708 $ 2,758 $ (809,120)
Net income (loss) per common share - basic(1) 1.62 0.06 (1.63)
Net income (loss) per common share - diluted(1) 1.51 0.06 (1.63)
Net cash provided by operating activities 104,019 32,910 40,597
Successor Predecessor
Nine Months Period from
Ended Sept. 19, 2020 Period from Jan.
Sept. 30, through 1, 2020 through
In thousands, except per-share and unit data 2021 Sept. 30, 2020 Sept. 18, 2020
Operating results
Net income (loss)(1) $ (64,629) $ 2,758 $ (1,432,578)
Net income (loss) per common share - basic(1) (1.27) 0.06 (2.89)
Net income (loss) per common share - diluted(1) (1.27) 0.06 (2.89)
Net cash provided by operating activities 247,557 32,910 113,408
(1)Includes a pre-tax full cost pool ceiling test write-down of our oil and
natural gas properties of $14.4 million during the first quarter of 2021, as
compared to write-downs of $261.7 million and $996.7 million for the Predecessor
periods July 1, 2020 through September 18, 2020 and January 1, 2020 through
September 18, 2020 , respectively. In addition, includes reorganization
adjustments, net totaling $850.0 million during the 2020 Predecessor periods.
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Denbury Inc.
Management's Discussion and Analysis of Financial Condition and Results of
Operations
Certain of our operating results and statistics for the comparative three and
nine months ended September 30, 2021 and 2020 are included in the following
table:
Three Months Ended Nine Months Ended
September 30 September 30
In thousands, except per-share and unit data 2021 2020 2021 2020
Average daily sales volumes
Bbls/d 48,145 48,334 47,276 50,619
Mcf/d 9,222 8,110 8,739 7,916
BOE/d(1) 49,682 49,686 48,732 51,939
Oil and natural gas sales
Oil sales $ 305,093 $ 174,447 $ 818,714 $ 511,562
Natural gas sales 3,361 964 7,893 2,860
Total oil and natural gas sales $ 308,454 $ 175,411 $ 826,607 $ 514,422
Commodity derivative contracts(2)
Receipt (payment) on settlements of commodity
derivatives $ (77,670) $ 17,789 $ (179,466) $ 88,056
Noncash fair value gains (losses) on
commodity derivatives 35,925 (18,363) (150,686) 18,011
Commodity derivatives income (expense) $ (41,745) $ (574) $ (330,152) $ 106,067
Unit prices - excluding impact of derivative
settlements
Oil price per Bbl $ 68.88 $ 39.23 $ 63.44 $ 36.88
Natural gas price per Mcf 3.96 1.29 3.31 1.32
Unit prices - including impact of derivative
settlements(2)
Oil price per Bbl $ 51.35 $ 43.23 $ 49.53 $ 43.23
Natural gas price per Mcf 3.96 1.29 3.31 1.32
Oil and natural gas operating expenses
Lease operating expenses $ 116,536 $ 71,192 $ 308,731 $ 261,755
Transportation and marketing expenses 5,985 9,499 22,304 28,508
Production and ad valorem taxes 23,464 13,697 63,195 40,450
Oil and natural gas operating revenues and
expenses per BOE
Oil and natural gas revenues $ 67.48 $ 38.37 $ 62.13 $ 36.15
Lease operating expenses 25.50 15.57 23.21 18.39
Transportation and marketing expenses 1.31 2.08 1.68 2.00
Production and ad valorem taxes 5.13 3.00 4.75 2.84
CO2 - revenues and expenses
CO2 sales and transportation fees $ 12,237 $ 7,484 $ 31,599 $ 22,016
CO2 operating and discovery expenses (1,963) (1,197) (4,487) (2,834)
CO2 revenue and expenses, net $ 10,274 $ 6,287 $ 27,112 $ 19,182
(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.
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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 three quarters of 2021 is shown below:
Average Daily Sales Volumes (BOE/d)
First Second Third First Second Third Fourth
Quarter Quarter Quarter Quarter Quarter Quarter Quarter
Operating Area 2021 2021 2021 2020 2020 2020 2020
Tertiary oil sales
Gulf Coast region
Delhi 2,925 2,931 2,859 3,813 3,529 3,208 3,132
Hastings 4,226 4,487 4,343 5,232 4,722 4,473 4,598
Heidelberg 4,054 3,942 3,895 4,371 4,366 4,256 4,198
Oyster Bayou 3,554 3,791 3,942 3,999 3,871 3,526 3,880
Tinsley 3,424 3,455 3,390 4,355 3,788 4,042 3,654
Other(1) 6,098 6,074 5,907 7,161 5,944 6,271 6,332
Total Gulf Coast region 24,281 24,680 24,336 28,931 26,220 25,776 25,794
Rocky Mountain region
Bell Creek 4,614 4,394 4,330 5,731 5,715 5,551 5,079
Other(2) 2,573 4,378 4,703 2,199 1,393 2,167 2,007
Total Rocky Mountain region 7,187 8,772 9,033 7,930 7,108 7,718 7,086
Total tertiary oil sales 31,468 33,452 33,369 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 3,763 4,173 3,805 3,728 3,523
Rocky Mountain region
Cedar Creek Anticline 11,150 10,918 11,182 13,046 11,988 11,485 11,433
Other(2) 1,118 1,348 1,368 1,105 1,069 979 969
Total Rocky Mountain region 12,268 12,266 12,550 14,151 13,057 12,464 12,402
Total non-tertiary sales 15,889 15,681 16,313 18,324 16,862 16,192 15,925
Total continuing sales 47,357 49,133 49,682 55,185 50,190 49,686 48,805
Property sales
Gulf Coast Working Interests
Sale(3) - - - 780 - - -
Total sales 47,357 49,133 49,682 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 third quarter of 2021 averaged 49,682 BOE/d,
including 33,369 Bbls/d from tertiary properties and 16,313 BOE/d from
non-tertiary properties. This sales volume represents a slight increase of 549
BOE/d (1%) compared to sales levels in the second quarter of 2021 and was
essentially flat with third quarter of 2020 sales volumes. The increase on a
sequential-quarter basis was primarily attributable to higher sales volumes at
our Wind River Basin properties acquired in March 2021 and sales of non-tertiary
production at Conroe Field in our Gulf Coast region.
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Denbury Inc.
Management's Discussion and Analysis of Financial Condition and Results of
Operations
Our sales volumes during the three and nine months ended
Oil and Natural Gas Revenues
Our oil and natural gas revenues during the three and nine months endedSeptember 30, 2021 increased 76% and 61%, 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), with the change during the nine months endedSeptember 30, 2021 offset somewhat by changes in sales volumes, as reflected in the following table: Three Months Ended Nine Months Ended September 30, September 30, 2021 vs. 2020 2021 vs. 2020 Increase Increase Percentage Increase (Decrease) in Percentage Increase (Decrease) in (Decrease) in In thousands Revenues in Revenues Revenues Revenues Change in oil and natural gas revenues due to: Decrease in sales volumes$ (14) 0 %$ (33,517) (6) % Increase in realized commodity prices 133,057 76 % 345,702 67 % Total increase in oil and natural gas revenues$ 133,043 76 %$ 312,185 61 %
Excluding any impact of our commodity derivative contracts, our average net
realized commodity prices and NYMEX differentials were as follows during each of
the first three quarters and nine months ended
Three Months Ended Nine Months Ended
March 31, June 30, September 30, September 30,
2021 2020 2021 2020 2021 2020 2021 2020
Average net realized prices
Oil price per Bbl $ 56.28 $ 45.96 $ 64.70 $ 24.39 $ 68.88 $ 39.23 $ 63.44 $ 36.88
Natural gas price per Mcf 3.29 1.46 2.64 1.21 3.96 1.29 3.31 1.32
Price per BOE 55.24 45.09 63.23 23.95 67.48 38.37 62.13 36.15
Average NYMEX differentials
Gulf Coast region
Oil per Bbl $ (1.37) $ 1.18 $ (1.13) $ (3.59) $ (1.77) $ (1.38) $ (1.40) $ (0.86)
Natural gas per Mcf 0.68 (0.06) (0.11) (0.09) 0.16 (0.06) 0.26 (0.07)
Rocky Mountain region
Oil per Bbl $ (1.80) $ (2.78) $ (1.59) $ (4.68) $ (1.72) $ (2.03) $ (1.49) $ (2.89)
Natural gas per Mcf 0.49 (0.91) (0.47) (1.04) (0.65) (1.74) (0.22) (1.25)
Total Company
Oil per Bbl $ (1.54) $ (0.38) $ (1.32) $ (4.03) $ (1.75) $ (1.64) $ (1.44) $ (1.67)
Natural gas per Mcf 0.58 (0.41) (0.33) (0.54) (0.33) (0.83) (0.02) (0.60)
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$1.77 per Bbl during the third quarter of 2021, compared to a negative$1.38 per Bbl during the third quarter of 2020 and a negative$1.13 per Bbl during the second quarter of 2021. NYMEX WTI oil prices continued to strengthen during the third quarter of 2021; however, the pricing for ourGulf Coast grades weakened relative to NYMEX WTI index prices. For 27 --------------------------------------------------------------------------------
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Denbury Inc.
Management's Discussion and Analysis of Financial Condition and Results of
Operations
our crude oil sold under Light Louisiana Sweet ("LLS") index prices, the
LLS-to-NYMEX differential averaged a positive $0.98 per Bbl on a trade-month
basis for the third quarter of 2021, compared to a positive $1.52 per Bbl
differential in the third quarter of 2020 and a positive $2.10 per Bbl in the
second quarter of 2021.
•Rocky Mountain Region. NYMEX oil differentials in the Rocky Mountain region
averaged $1.72 per Bbl and $2.03 per Bbl below NYMEX during the third quarters
of 2021 and 2020, respectively, and $1.59 per Bbl below NYMEX during the second
quarter of 2021. Differentials in the Rocky Mountain region tend to fluctuate
with regional supply and demand trends and can fluctuate significantly on a
month-to-month basis due to weather, refinery or transportation issues, and
Canadian and U.S. crude oil price index volatility.
CO2 Revenues and Expenses
We sell 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. CO2 sales and transportation fees were$12.2 million and$31.6 million during the three and nine months endedSeptember 30, 2021 , respectively, compared to$7.5 million and$22.0 million during the combined Predecessor and Successor periods included within the three and nine-month periods endedSeptember 30, 2020 , respectively. The increases from the prior-year periods were primarily due to an increase in CO2 sales volumes to our industrial CO2 customers.
Oil Marketing Revenues and Purchases
In certain situations, we purchase and subsequently sell oil from third parties. We recognize the revenue received and the associated expenses incurred on these sales on a gross basis as "Oil marketing revenues" and "Oil marketing purchases" in our Unaudited Condensed Consolidated Statements of Operations.
Commodity Derivative Contracts
The following tables summarize the impact our crude oil derivative contracts had on our operating results for the three and nine months endedSeptember 30, 2021 and 2020: Successor Predecessor Three Months Period from Ended Sept. 19, 2020 Period from July 1, Sept. 30, through 2020 through In thousands 2021 Sept. 30, 2020 Sept. 18, 2020 Receipt (payment) on settlements of commodity derivatives$ (77,670) $ 6,660 $ 11,129 Noncash fair value gains (losses) on commodity derivatives 35,925 (2,625) (15,738) Total income (expense)$ (41,745) $ 4,035 $ (4,609) Successor Predecessor Period from Nine Months Sept. 19, 2020 Period from Jan. 1, Ended through 2020 through In thousands Sept. 30, 2021 Sept. 30, 2020 Sept. 18, 2020 Receipt (payment) on settlements of commodity derivatives$ (179,466) $ 6,660 $ 81,396 Noncash fair value gains (losses) on commodity derivatives(1) (150,686) (2,625) 20,636 Total income (expense)$ (330,152) $ 4,035 $ 102,032 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 third 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, 28 --------------------------------------------------------------------------------
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Denbury Inc.
Management's Discussion and Analysis of Financial Condition and Results of
Operations
and
Largely based on the hedging requirements that we were obligated to meet under our bank credit facility, which required certain minimum commodity hedge levels throughJuly 31, 2022 , we have oil commodity hedges in place for a portion of our estimated oil production through 2022 using NYMEX fixed-price swaps and costless collars. We do not have any additional hedging requirements under our Bank Credit Agreement. See Note 6, Commodity Derivative Contracts, to the Unaudited Condensed Consolidated Financial Statements for additional details of our outstanding commodity derivative contracts as ofSeptember 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 ofNovember 3, 2021 : 4Q 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 ofNovember 3, 2021 , which averaged approximately$81 per Bbl, we currently expect that we would make cash payments of approximately$110 million upon settlement of our October throughDecember 2021 contracts, the amount of which is primarily dependent upon fluctuations in future NYMEX oil prices in relation to the prices of our remaining 2021 fixed-price swaps which have a weighted average NYMEX oil price of$43.86 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 Period from
Ended Sept. 19, 2020 Period from July 1,
Sept. 30, through 2020 through
In thousands, except per-BOE data 2021 Sept. 30, 2020 Sept. 18, 2020
Total lease operating expenses $ 116,536 $ 11,484 $ 59,708
Total lease operating expenses per BOE $ 25.50 $ 19.20 $ 15.03
Successor Predecessor
Nine Months Period from
Ended Sept. 19, 2020 Period from Jan. 1,
Sept. 30, through 2020 through
In thousands, except per-BOE data 2021 Sept. 30, 2020 Sept. 18, 2020
Total lease operating expenses $ 308,731 $ 11,484 $ 250,271
Total lease operating expenses per BOE $ 23.21 $ 19.20 $ 18.36
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Denbury Inc.
Management's Discussion and Analysis of Financial Condition and Results of
Operations
Total lease operating expenses were $116.5 million , or $25.50 per BOE, during
the three months ended September 30, 2021 , compared to $71.2 million , or $15.57
per BOE, for the combined Predecessor and Successor periods included within the
three months ended September 30, 2020 . Total lease operating expenses were
$308.7 million , or $23.21 per BOE, during the nine months ended September 30,
2021 , compared to $261.8 million , or $18.39 , for the combined Predecessor and
Successor periods included within the nine months ended September 30, 2020 . The
increases on an absolute-dollar basis and per-BOE basis were primarily due to
(a) an insurance reimbursement totaling $15.4 million recorded in the third
quarter of 2020 for previously-incurred well control costs, cleanup costs, and
damages associated with a 2013 incident at Delhi Field (b) $8.1 million and
$17.0 million of expense during the three and nine months ended September 30,
2021 , respectively, related to the Wind River Basin acquisition in March 2021 ,
as these properties have higher operating costs than our other fields (c) higher
expenses across nearly all expense categories as our costs are correlated to
varying degrees with changes in oil prices (reflecting rising oil prices in
2021) and (d) 2020 period reduced spending and shut-in production in response to
significantly lower oil prices in the third quarter of 2020. Lease operating
expenses for the nine months ended September 30, 2021 were offset by a $7.6
million reduction in power and fuel costs. The significant reduction in power
and fuel costs was associated with the severe winter storm in February 2021
which created widespread power outages in Texas 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 $16.1 million ; as of September 30, 2021 ; $10.3 million
of these savings were included in "Trade and other receivables, net" and $1.7
million included in "Other assets" in our Unaudited Condensed Consolidated
Balance Sheets. Compared to the second quarter of 2021, lease operating expenses
in the most recent quarter increased $6.3 million (6%) on an absolute-dollar
basis and $0.85 (3%) on a per-BOE basis, due primarily to higher power and fuel
costs and contract labor.
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$6.0 million for the three months endedSeptember 30, 2021 , compared to$9.5 million for the combined Predecessor and Successor periods included within the three months endedSeptember 30, 2020 . Transportation and marketing expenses were$22.3 million for the nine months endedSeptember 30, 2021 , compared to$28.5 million for the combined Predecessor and Successor periods included within the nine months endedSeptember 30, 2020 . The decrease during the comparative three-month periods was primarily due to changes to a portion of our transportation agreements in theRocky Mountain region during the third quarter of 2021 to begin selling our production atGuernsey, Wyoming versusCushing, Oklahoma . The decrease between the comparative nine-month periods was primarily due to lower sales volumes during 2021.
Taxes Other Than Income
Taxes other than income includes production, ad valorem and franchise taxes. Taxes other than income were$24.2 million during the three months endedSeptember 30, 2021 , compared to$15.5 million for the combined Predecessor and Successor periods included within the three months endedSeptember 30, 2020 . Taxes other than income were$65.5 million during the nine months endedSeptember 30, 2021 , compared to$45.6 million for the combined Predecessor and Successor periods included within the nine months endedSeptember 30, 2020 . The increases in both periods when compared to 2020 were due primarily to an increase in production taxes resulting from higher oil and natural gas revenues. 30 --------------------------------------------------------------------------------
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Denbury Inc.
Management's Discussion and Analysis of Financial Condition and Results of
OperationsGeneral and Administrative Expenses ("G&A")
Successor Predecessor
Period from
Three Months Sept. 19, 2020 Period from July 1,
Ended through 2020 through
In thousands, except per-BOE data and employees
Sept. 30, 2020 Sept. 18, 2020 Cash G&A costs$ 12,832 $ 1,735 $ 14,442 Stock-based compensation 2,556 - 571 G&A expense$ 15,388 $ 1,735 $ 15,013 G&A per BOE Cash G&A costs$ 2.81 $ 2.90 $ 3.64 Stock-based compensation 0.56 - 0.14 G&A expenses$ 3.37 $ 2.90 $ 3.78 Employees as of period end 698 663 662 Successor Predecessor Period from Nine Months Sept. 19, 2020 Period from Jan. 1, Ended through 2020 through In thousands, except per-BOE data Sept. 30, 2021 Sept. 30, 2020 Sept. 18, 2020 Cash G&A costs$ 40,033 $ 1,735 $ 44,411 Stock-based compensation 22,788 - 4,111 G&A expense$ 62,821 $ 1,735 $ 48,522 G&A per BOE Cash G&A costs$ 3.01 $ 2.90 $ 3.26 Stock-based compensation 1.71 - 0.30 G&A expenses$ 4.72 $ 2.90 $ 3.56 Our G&A expense on an absolute-dollar basis was$15.4 million during the three months endedSeptember 30, 2021 , a decrease of$1.4 million (8%) from the combined Predecessor and Successor periods included within the three months endedSeptember 30, 2020 . The decrease in G&A expense during the three months endedSeptember 30, 2021 compared to 2020, was primarily due to higher operator labor and overhead recovery charges in the current period, partially offset by higher long-term incentives for employees. Our G&A expenses on an absolute-dollar basis were$62.8 million during the nine months endedSeptember 30, 2021 , an increase of$12.6 million (25%) from the combined Predecessor and Successor periods within the nine months endedSeptember 30, 2020 . The increase in our G&A expenses during the nine months endedSeptember 30, 2021 was 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, partially offset by higher operator labor and overhead recovery charges. 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 . 31 --------------------------------------------------------------------------------
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Denbury Inc.
Management's Discussion and Analysis of Financial Condition and Results of
OperationsInterest and Financing Expenses
Successor Predecessor
Three Months Period from Sept. Period from July 1,
Ended 19, 2020 through 2020 through
In thousands, except per-BOE data and interest rates Sept. 30, 2021 Sept. 30, 2020 Sept. 18, 2020
Cash interest(1) $ 1,233 $ 403 $ 17,734 Less: interest not reflected as expense for financial reporting purposes(1)
- - (6,976)
Noncash interest expense 685 114 347
Amortization of debt discount(2) - - 1,303
Less: capitalized interest (1,249) (183) (4,704)
Interest expense, net $ 669 $ 334 $ 7,704
Interest expense, net per BOE $ 0.15 $ 0.56 $ 1.94
Average debt principal outstanding(3) $ 55,667 $ 185,877 $ 815,025
Average cash interest rate(4) 8.9 % 6.6 % 10.0 %
Successor Predecessor
Nine Months
Ended Period from Sept. Period from Jan.
Sept. 30, 19, 2020 through 1, 2020 through
In thousands, except per-BOE data and interest rates 2021 Sept. 30, 2020 Sept. 18, 2020
Cash interest(1) $ 4,902 $ 403 $ 108,824 Less: interest not reflected as expense for financial reporting purposes(1)
- - (49,243)
Noncash interest expense 2,055 114 2,439
Amortization of debt discount(2) - - 9,132
Less: capitalized interest (3,500) (183) (22,885)
Interest expense, net $ 3,457 $ 334 $ 48,267
Interest expense, net per BOE $ 0.26 $ 0.56 $ 3.54
Average debt principal outstanding(3) $ 99,243 $ 185,877 $ 1,767,605
Average cash interest rate(4) 6.6 % 6.6 % 8.6 %
(1)Cash interest during the Predecessor periods 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 periods
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 was $1.2 million during the three months ended September 30, 2021 ,
compared to $18.1 million for the combined Predecessor and Successor periods
included within the three months ended September 30, 2020 . Cash interest was
$4.9 million during the nine months ended September 30, 2021 , compared to $109.2
million for the combined Predecessor and Successor periods included within the
nine months ended September 30, 2020 . 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.
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Denbury Inc.
Management's Discussion and Analysis of Financial Condition and Results of
OperationsDepletion, Depreciation, and Amortization ("DD&A")
Successor Predecessor
Period from
Three Months Sept. 19, 2020 Period from July 1,
Ended through 2020 through
In thousands, except per-BOE data Sept. 30, 2021 Sept. 30, 2020 Sept. 18, 2020
Oil and natural gas properties $ 29,269 $ 4,105 $ 21,636
CO2 properties, pipelines, plants and other property and equipment
8,422 1,178 12,890
Accelerated depreciation charge(1) - - 1,791
Total DD&A $ 37,691 $ 5,283 $ 36,317
DD&A per BOE
Oil and natural gas properties $ 6.40 $ 6.86 $ 5.45
CO2 properties, pipelines, plants and other property and equipment
1.85 1.97 3.24
Accelerated depreciation charge(1) - - 0.45
Total DD&A cost per BOE $ 8.25 $ 8.83 $ 9.14
Write-down of oil and natural gas properties $ - $ - $ 261,677
Successor Predecessor
Nine Months Period from
Ended Sept. 19, 2020 Period from Jan. 1,
Sept. 30, through 2020 through
In thousands, except per-BOE data 2021 Sept. 30, 2020 Sept. 18, 2020
Oil and natural gas properties $ 89,834 $ 4,105 $ 104,495 CO2 properties, pipelines, plants and other property and equipment
23,688 1,178 44,939
Accelerated depreciation charge(1) - - 39,159
Total DD&A $ 113,522 $ 5,283 $ 188,593
DD&A per BOE
Oil and natural gas properties $ 6.75 $ 6.86 $ 7.66
CO2 properties, pipelines, plants and other property and equipment
1.78 1.97 3.30
Accelerated depreciation charge(1) - - 2.87
Total DD&A cost per BOE $ 8.53 $ 8.83 $ 13.83
Write-down of oil and natural gas properties $ 14,377 $ - $ 996,658
(1)Represents an accelerated depreciation charge related to capitalized amounts
associated with unevaluated properties that were transferred to the full cost
pool.
DD&A expense was $37.7 million during the three months ended September 30, 2021 ,
compared to $41.6 million for the combined Predecessor and Successor periods
included within the three months ended September 30, 2020 . DD&A expense was
$113.5 million during the nine months ended September 30, 2021 , compared to
$193.9 million for the combined Predecessor and Successor periods within the
nine months ended September 30, 2020 . The decreases during the three and
nine-month periods ended September 30, 2021 compared to the comparable 2020
periods were primarily due to lower depletable costs due to the step down in
book value resulting from fresh start accounting as of September 18, 2020 , with
the year-over-
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Denbury Inc.
Management's Discussion and Analysis of Financial Condition and Results of
Operations
year decrease further impacted by accelerated depreciation of
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 theMarch 2021 acquisition ofWyoming property interests (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. The Predecessor also recognized full cost pool ceiling test write-downs of$261.7 million during the period fromJuly 1, 2020 throughSeptember 18, 2020 ,$662.4 million during the three months endedJune 30, 2020 and$72.5 million during the three months endedMarch 31, 2020 . We did not record any ceiling test write-down during the Successor periods fromSeptember 19, 2020 throughSeptember 30, 2020 , for the three months endedJune 30, 2021 , or the three months endedSeptember 30, 2021 .
Reorganization Items, Net
Reorganization items, net, include (i) expenses incurred during the Company's
"prepackaged" voluntary bankruptcy subsequent to the Petition Date as a direct
result of the Plan, (ii) gains or losses from liabilities settled and (iii)
fresh start accounting adjustments and are recorded in "Reorganization items,
net" in our Unaudited Condensed Consolidated Statements of Operations.
Professional service provider charges associated with our restructuring that
were incurred before the Petition Date and after the Emergence Date are recorded
in "Other expenses" in our Unaudited Condensed Consolidated Statements of
Operations. The following table summarizes the losses (gains) on reorganization
items, net:
Predecessor
Period from July
1, 2020 through
In thousands Sept. 18, 2020
Gain on settlement of liabilities subject to compromise $ (1,024,864)
Fresh start accounting adjustments 1,834,423
Professional service provider fees and other expenses 11,267
Success fees for professional service providers 9,700
Loss on rejected contracts and leases 10,989
Valuation adjustments to debt classified as subject to compromise
757
Debtor-in-possession credit agreement fees 3,107
Acceleration of Predecessor stock compensation expense 4,601
Total reorganization items, net $ 849,980
Other Expenses
Other expenses totaled $4.6 million and $9.9 million during the three and nine
months ended September 30, 2021 . Other expenses during 2021 periods primarily
include litigation accruals and noncash fair value adjustments for contingent
consideration payments related to our March 2021 Wind River Basin CO2 EOR field
acquisition. Other expenses totaled $24.2 million for the combined Predecessor
and Successor periods included within the three months ended September 30, 2020 ,
and $38.0 million for the combined Predecessor and Successor periods included
within the nine months ended September 30, 2020 . Other expenses during 2020
primarily are comprised of $24.1 million of professional fees associated with
restructuring activities, $4.2 million of write-off of certain trade
receivables, $3.8 million of costs associated with the Delta-Tinsley CO2
pipeline incident, and $1.6 million of costs associated with the APMTG Helium,
LLC helium supply contract ruling.
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Denbury Inc.
Management's Discussion and Analysis of Financial Condition and Results of
Operations
Income Taxes
Successor Predecessor
Three Months Period from Sept. Period from July
Ended 19, 2020 through 1, 2020 through
In thousands, except per-BOE amounts and tax rates
Sept. 30, 2020 Sept. 18, 2020 Current income tax expense (benefit)$ 350 $ 6$ (1,451) Deferred income tax expense (benefit) 53 6 (302,356) Total income tax expense (benefit)$ 403 $ 12$ (303,807) Average income tax expense (benefit) per BOE$ 0.09 $ 0.02 $ (76.47) Effective tax rate 0.5 % 0.4 % 27.3 % Total net deferred tax liability$ 1,241 $ 3,836 Successor Predecessor Period from Sept. Period from Jan. Nine Months Ended 19, 2020 through 1, 2020 through In thousands, except per-BOE amounts and tax rates Sept. 30, 2021 Sept. 30, 2020 Sept. 18, 2020 Current income tax expense (benefit) $ (101) $ 6$ (7,260) Deferred income tax expense (benefit) (34) 6 (408,869) Total income tax expense (benefit) $ (135) $ 12$ (416,129) Average income tax expense (benefit) per BOE $ (0.01)$ 0.02 $ (30.52) Effective tax rate 0.2 % 0.4 % 22.5 % 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 nine months endedSeptember 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 nine months endedSeptember 30, 2021 , the income tax benefit resulting from these losses is fully offset by the change in valuation allowance, resulting in essentially no tax provision. As ofSeptember 30, 2021 , the tax basis of our assets, primarily our oil and gas properties, is in excess of their carrying value, as adjusted for fresh start accounting onSeptember 18, 2020 ; 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 ofSeptember 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. The current income tax benefits for the Predecessor period endedSeptember 18, 2020 represent amounts estimated to be receivable resulting from alternative minimum tax credits and certain state tax obligations.
As of
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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 Nine Months Ended
September 30, September 30,
Per-BOE data 2021 2020 2021 2020
Oil and natural gas revenues $ 67.48 $ 38.37 $ 62.13 $ 36.15
Receipt (payment) on settlements of
commodity derivatives (16.99) 3.90 (13.49) 6.19
Lease operating expenses (25.50) (15.57) (23.21) (18.39)
Production and ad valorem taxes (5.13) (3.00) (4.75) (2.84)
Transportation and marketing expenses (1.31) (2.08) (1.68) (2.00)
Production netback 18.55 21.62 19.00 19.11
CO2 sales, net of operating and discovery
expenses 2.25 1.38 2.04 1.35
General and administrative expenses(1) (3.37) (3.66) (4.72) (3.53)
Interest expense, net (0.15) (1.76) (0.26) (3.42)
Reorganization items settled in cash - (8.55) - (2.75)
Stock compensation and other (0.31) (2.72) 1.18 (0.74)
Changes in assets and liabilities relating
to operations 5.79 9.77 1.37 0.26
Cash flows from operations 22.76 16.08 18.61 10.28
DD&A - excluding accelerated depreciation
charge (8.25) (8.71) (8.53) (10.87)
DD&A - accelerated depreciation charge(2) - (0.39) - (2.75)
Write-down of oil and natural gas
properties - (57.25) (1.08) (70.03)
Deferred income taxes (0.01) 66.14 - 28.73
Gain on extinguishment of debt - - - 1.33
Noncash fair value gains (losses) on
commodity derivatives 7.86 (4.03) (11.33) 1.26
Noncash reorganization items, net - (177.40) - (56.98)
Other noncash items (4.26) (10.85) (2.53) (1.44)
Net income (loss) $ 18.10 $ (176.41) $ (4.86) $ (100.47)
(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 nine months ended September 30, 2021 , resulting in a
significant non-recurring expense, which if excluded, would have caused these
expenses to average $3.58 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, cash
flows, production and capital expenditures, and
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Denbury Inc.
Management's Discussion and Analysis of Financial Condition and Results of
Operations
other plans and objectives for the future operations of Denbury , projections or
assumptions as to general economic conditions and the economics of a carbon
capture, use and storage industry ("CCUS"), and anticipated effects of COVID-19
on U.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"), 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 increases in worldwide oil prices from their
COVID-19 coronavirus caused downturn, financial forecasts, oil price volatility,
current or future liquidity sources or their adequacy to support our anticipated
future activities, statements or predictions related to the ultimate nature,
timing and economic aspects of proposed carbon capture, use and storage industry
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, the impact of current supply chain and
inflationary pressures or expectations on our operational or other assets,
current or future expectations or estimations of our cash flows or the impact of
changes in commodity prices on cash flows, borrowing capacity, price and
availability of advantageous commodity derivative contracts or their predicted
downside cash flow protection or cash settlement payments required,
mark-to-market commodity derivative values, forecasted 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 injections in particular fields or areas, including Cedar
Creek Anticline ("CCA"), or initial production responses in tertiary flooding
projects, other development activities, finding costs, interpretation or
prediction of formation details, 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 changes or
proposed changes in Federal or state laws or outcomes of any pending litigation,
prospective legislation, orders or regulations affecting the oil and gas
industry or environmental regulations, competition, rates of return, and overall
worldwide or U.S. economic conditions, and other variables surrounding
operations and future plans. Such forward-looking statements generally are
accompanied by words such as "plan," "estimate," "expect," "predict,"
"forecast," "to our knowledge," "anticipate," "projected," "preliminary,"
"should," "assume," "believe," "may" or other words that convey, or are intended
to convey, the uncertainty of future events or outcomes. 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.
producers in future periods; success of our risk management techniques; 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, climate events such as hurricanes, tropical storms, floods, forest
fires, or other natural occurrences; 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
consequent 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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Denbury Inc.
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