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, 2021 (the "Form 10-K"), along with Management's Discussion and Analysis of Financial Condition and Results of Operations contained in the Form 10-K. Any terms used but not defined herein have the same meaning given to them in the Form 10-K. Our discussion and analysis includes forward-looking information that involves risks and uncertainties and should be read in conjunction with Risk Factors under Item 1A of the Form 10-K, along with Forward-Looking Information at the end of this section for information on the risks and uncertainties that could cause our actual results to be materially different than our forward-looking statements. 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 be net-zero on its Scope 1, 2, and 3 CO2 emissions by 2030, primarily through increasing the amount of captured industrial-sourced CO2 used in its operations. Oil Price Impact on Our Business. Our financial results are significantly impacted by changes in oil prices, as 97% of our sales volumes are oil. Changes in oil prices impact all aspects of our business; most notably our cash flows from operations, revenues, capital allocation and budgeting decisions, and oil and natural gas reserves volumes. The table below outlines selected financial items and sales volumes, along with changes in our realized oil prices, before and after commodity derivative impacts, for our most recent comparative quarterly periods: Three Months Ended In thousands, except per-unit data March 31, 2022 Dec. 31, 2021 Sept. 30, 2021 June 30, 2021 March 31, 2021 Oil, natural gas, and related product sales$ 384,911 $ 333,348 $ 308,454 $ 282,708 $ 235,445 Receipt (payment) on settlements of commodity derivatives (93,057) (97,774) (77,670) (63,343) (38,453) Oil, natural gas, and related product sales and commodity settlements, combined$ 291,854 $ 235,574 $ 230,784 $ 219,365 $ 196,992 Average daily sales (BOE/d) 46,925 48,882 49,682 49,133 47,357 Average net realized oil prices Oil price per Bbl - excluding impact of derivative settlements $ 93.17$ 75.68 $ 68.88$ 64.70 $ 56.28 Oil price per Bbl - including impact of derivative settlements 70.43 53.21 51.35 50.10 47.00 Average NYMEX WTI oil prices increased from the mid-$70s per Bbl range in the fourth quarter of 2021 to approximately$95 per Bbl during the first quarter of 2022, reaching highs of over$123 per Bbl inearly-March 2022 . This increase in oil prices was due in large part to concerns around potential worldwide oil supply disruptions associated with the Russian invasion ofUkraine during the first quarter of 2022. 16
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Denbury Inc.
Management's Discussion and Analysis of Financial Condition and Results of
Operations
As shown in the table above, our oil and natural gas revenues increased
significantly over the last four quarters as oil prices increased. However, the
benefit of the increase in revenues over this time period was offset in part by
the impact of higher cash payments on our commodity derivative contracts, which
were largely required to be entered into during the fourth quarter of 2020 under
the terms of our September 18, 2020 bank credit facility. During the first
quarter of 2022, we paid $93.1 million related to the expiration of commodity
derivative contracts and expect to make additional payments on the settlement of
our contracts expiring during the remainder of 2022. In the second half of 2022,
less of our production is hedged, and our hedges are at more favorable prices
and with a greater mix of collars, allowing us to realize additional upside of
currently anticipated higher oil prices.
First Quarter 2022 Financial Results and Highlights. We recognized a net loss of
$0.9 million , or $0.02 per diluted common share, during the first quarter of
2022, compared to a net loss of $69.6 million , or $1.38 per diluted common
share, during the first quarter of 2021. The primary drivers of the comparative
operating results include the following:
•Oil and natural gas revenues increased $149.5 million (63%) due to an increase
in commodity prices;
•Lease operating expenses increased $35.9 million (44%), offset in part by
reductions in other expense categories; and
•Commodity derivatives expense increased by $77.0 million consisting of a $54.6
million increase in cash payments upon contract settlements and a $22.4 million
loss on noncash fair value changes.
Commencement of Cedar Creek Anticline ("CCA") CO2 Injection. In early February
2022 , we commenced CO2 injection in the first phase of our CCA EOR project, and
during April 2022 we increased CO2 injections to approximately 115 MMcf/d of
industrial-sourced CO2 into the field. We continue to anticipate tertiary oil
production response from this new project in the second half of 2023.
Carbon Capture, Use and Storage. CCUS is a process that captures CO2 from
industrial sources and reuses it or stores the CO2 in geologic formations in
order to prevent its release into the atmosphere. We utilize CO2 from industrial
sources in our EOR operations, and our extensive CO2 pipeline infrastructure and
operations, particularly in the Gulf Coast , are strategically located in close
proximity to large sources of industrial emissions. We believe that the assets
and technical expertise required for CCUS are highly aligned with our existing
CO2 EOR operations, providing us with a significant advantage and opportunity to
participate in the emerging CCUS industry, as the building of a permanent carbon
sequestration business requires both time and capital to build assets such as
those we own and have been operating for years. During the first quarter of
2022, approximately 36% of the CO2 utilized in our oil and gas operations was
industrial-sourced CO2, and we anticipate this percentage will increase in the
future as supportive U.S. government policy and public pressure on industrial
CO2 emitters will provide strong incentives for these entities to capture their
CO2 emissions.
As we seek to grow our CCUS business and pursue new CCUS opportunities, we have
been engaged in discussions with existing and potential third-party industrial
CO2 emitters regarding transportation and storage solutions, while also
identifying potential future sequestration sites and landowners of those
locations. We continue to make progress in these discussions and thus far have
signed agreements securing the rights to future sequestration sites which we
believe have the potential to store up to 1.4 billion metric tons of CO2. In
addition, we have executed several term sheets for the future transportation and
sequestration of CO2. During the first quarter of 2022, we capitalized $20.9
million in "CCUS storage sites and related assets" in our Unaudited Condensed
Consolidated Balance Sheets, primarily consisting of acquisition costs
associated with sequestration sites. While EOR is the only CCUS operation
reflected in our historical financial and operational results (as a cost), we
believe the incentives offered under Section 45Q of the Internal Revenue Code
("Section 45Q") or otherwise will drive demand for CCUS and will allow us to
collect a fee for the transportation and storage of captured industrial-sourced
CO2, including CO2 utilized in our EOR operations. As the enhanced Section 45Q
regulations are relatively new, it will likely take several years to construct
new capture facilities and for dedicated storage sites to be developed. We
believe our existing CO2 pipeline infrastructure, EOR operations, and experience
and expertise in working with CO2 all position us to be a leader in this rapidly
developing industry.
May 2022 Amendment to Senior Secured Bank Credit Agreement. In early May 2022 ,
we amended our bank credit facility to among other things, (1) increase the
borrowing base and lender commitments to $750 million , (2) extend the maturity
date to May 4, 2027 , (3) modify certain interest rate provisions, and (4)
provide additional flexibility regarding our ability to make restricted payments
and investments. See further discussion of this amendment under Capital
Resources and Liquidity - Senior Secured Bank Credit Agreement.
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Denbury Inc.
Management's Discussion and Analysis of Financial Condition and Results of
Operations
Common Share Repurchase Program. On May 5, 2022 , we announced Board
authorization of a common share repurchase program for up to $250 million of
outstanding Denbury common stock. The program has no pre-established ending date
and may be suspended or discontinued at any time. The Company is not obligated
to repurchase any dollar amount or specific number of shares of its common stock
under the program. As of May 5, 2022 , there have been no repurchases of common
stock under this share repurchase program.
CAPITAL RESOURCES AND LIQUIDITY
Overview. Our cash flows from operations and availability under our senior secured bank credit facility are our primary sources of capital and liquidity. Our most significant cash capital outlays relate to our oil and gas development capital expenditures and CCUS initiatives. As ofMarch 31, 2022 , we had$35.0 million of outstanding borrowings and$11.9 million of outstanding letters of credit under our$575 million senior secured bank credit facility, leaving us with$528.1 million of borrowing base availability and approximately$528.6 million of total liquidity including our cash position atMarch 31, 2022 . This liquidity is more than adequate to meet our currently planned operating and capital needs as we currently project our cash flow from operations to significantly exceed our planned capital expenditures in 2022. In earlyMay 2022 , we amended our bank credit facility to among other things, increase the borrowing base availability and lender commitments to$750 million (see further discussion of this amendment under Senior Secured Bank Credit Agreement below). 2022 Sources and Uses. During the first quarter of 2022, we generated cash flows from operations of$90.1 million , while incurring capital costs of$79.7 million , consisting of oil and gas development capital expenditures of$57.6 million , CCUS storage sites and related capital expenditures of$20.9 million , and capitalized interest of$1.2 million . As further discussed below, based on oil price futures as of earlyMay 2022 , we currently anticipate funding all of our 2022 capital budget from projected operating cash flow while also generating excess cash flow. As the level of excess cash we expect to generate in 2022 and future periods has increased with the rise in oil prices during the first part of 2022, our Board of Directors recently adopted a share repurchase program for up to$250 million ofDenbury's outstanding common stock. The ultimate level of excess cash we may generate in 2022 and future periods will be highly dependent on oil prices and many other factors, but we currently believe our level of cash flow generation will be adequate to fund our EOR and CCUS strategic priorities while returning capital to our shareholders through our recently announced share repurchase program. 2022 Plans and Capital Budget. Based on our original 2022 budget, we estimated that our full-year 2022 oil and gas development capital spending, excluding capitalized acquisitions and capitalized interest, would be in the range of$290 million to$320 million , which at the midpoint includes approximately$115 million for CCA's new EOR development (inclusive of an estimated$25 million of pre-production CO2 costs) and$190 million for other tertiary and non-tertiary oil-focused development projects, capitalized internal costs and CO2 sources and pipelines. In addition to our budgeted oil and natural gas capital investments, our budget assumed spending of approximately$50 million in connection with our CCUS strategic priorities, making our combined 2022 projected capital expenditures in the range of$340 million to$370 million . Based on recent cost increases and inflationary pressures, we now expect that our 2022 capital expenditures will be toward the upper end of our budgeted range. 18 --------------------------------------------------------------------------------
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Denbury Inc.
Management's Discussion and Analysis of Financial Condition and Results of
Operations
Capital Expenditure Summary. The following table reflects incurred capital
expenditures for the three months ended
Three Months Ended
March 31,
In thousands 2022 2021
Capital expenditure summary(1)
CCA EOR field expenditures(2) $ 17,722 $ 9
CCA CO2 pipelines 2,191 48
CCA tertiary development 19,913 57
Non-CCA tertiary and non-tertiary fields 29,363 12,422
CO2 sources and other CO2 pipelines 730
-
Capitalized internal costs(3) 7,600
7,600
Oil & gas development capital expenditures 57,606
20,079
CCUS storage sites and related capital expenditures 20,949
-
Acquisitions of oil and natural gas properties(4) 371 10,665 Capitalized interest 1,158 1,083 Total capital expenditures$ 80,084 $ 31,827 (1)Capital expenditures in this summary are presented on an as-incurred basis (including accruals), and are$8.7 million lower than the capital expenditures in the Unaudited Condensed Consolidated Statements of Cash Flows which are presented on a cash basis. (2)Includes pre-production CO2 costs associated with the CCA EOR development project totaling$2.8 million during the first quarter of 2022. (3)Includes capitalized internal acquisition, exploration and development costs and pre-production tertiary startup costs. (4)Primarily consists of working interest positions in 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. , have increased our costs during 2022 and may continue to do so in future periods. Most of the cost inflation pressures we experienced during late 2021 were tied to rising fuel and power costs in our operations, but were not material to our 2021 financial results. Our 2022 operational budget considered anticipated inflation and we have taken steps to build our on-hand supply stock for items frequently used in our operations to address possible supply chain disruptions. Based on cost increases and shortages experienced across the industry thus far in 2022, we anticipate additional increases in the cost of, and demand for, goods and services and wages in our operations during the remainder of 2022 which could negatively impact our results of operations and cash flows in future periods. Senior Secured Bank Credit Agreement. InSeptember 2020 , we entered into a$575 million bank credit agreement for a senior secured revolving credit facility withJPMorgan Chase Bank, N.A ., as administrative agent, and other lenders party thereto (the "Bank Credit Agreement"). OnMay 4, 2022 , we entered into a Second Amendment to the Bank Credit Agreement, which among other things: •Increases the borrowing base and lender commitments from$575 million to$750 million ; •Extends the maturity date fromJanuary 30, 2024 toMay 4, 2027 ; •Modifies the interest provisions on loans under the Bank Credit Agreement to (1) reduce the applicable margin for alternate base rate loans from 2% to 3% per annum to 1.5% to 2.5% per annum and (2) replace provisions referencing LIBOR loans with Secured Overnight Financing Rate loans, with an applicable margin of 2.5% to 3.5% per annum; and •Permits us to pay dividends on our common stock and make other unlimited restricted payments and investments so long as (1) no event of default or borrowing base deficiency exists; (2) our total leverage ratio is 1.5 to 1 or lower; and (3) availability under the Bank Credit Agreement is at least 20% of the borrowing base. 19
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Denbury Inc.
Management's Discussion and Analysis of Financial Condition and Results of
Operations
Availability under the Bank Credit Agreement is subject to a borrowing base,
which is redetermined semiannually on or around May 1 or November 1 of each
year, with our next scheduled redetermination around November 1, 2022 . The
borrowing base is adjusted at the lenders' discretion and is based, in part,
upon external factors over which we have no control. If our outstanding debt
under the Bank Credit Agreement exceeds the then-effective borrowing base, we
would be required to repay the excess amount over a period not to exceed six
months.
The Bank Credit Agreement also limits our ability to, among other things, incur
and repay other indebtedness; grant liens; engage in certain mergers,
consolidations, liquidations and dissolutions; engage in sales of assets; make
acquisitions and investments; make other restricted payments (including
redeeming, repurchasing or retiring our common stock); and enter into commodity
derivative agreements, in each case subject to customary exceptions. Our Bank
Credit Agreement required certain minimum commodity hedge levels in connection
with our emergence from bankruptcy; however, these conditions were met as of
December 31, 2020 , and we currently have no ongoing hedging requirements under
the Bank Credit Agreement.
The Bank Credit Agreement contains certain financial performance covenants including the following:
•A Consolidated Total Debt to Consolidated EBITDAX covenant (as defined in the Bank Credit Agreement), with such ratio not to exceed 3.5 times; and •A requirement to maintain a current ratio (i.e., Consolidated Current Assets to Consolidated Current Liabilities) of 1.0. For purposes of computing the current ratio per the Bank Credit Agreement, Consolidated Current Assets exclude the current portion of derivative assets but include available borrowing capacity under the Bank Credit Agreement, and Consolidated Current Liabilities exclude the current portion of derivative liabilities as well as the current portions of long-term indebtedness outstanding. Under these financial performance covenant calculations, as ofMarch 31, 2022 , our ratio of consolidated total debt to consolidated EBITDAX was 0.09 to 1.0 (with a maximum permitted ratio of 3.5 to 1.0) and our current ratio was 2.53 to 1.0 (with a required ratio of not less than 1.0 to 1.0). Based upon our currently forecasted levels of production and costs, hedges in place as ofMay 4, 2022 , and current oil commodity futures prices, we currently anticipate continuing to be in compliance with our financial performance covenants during the foreseeable future. The above description of our Bank Credit Agreement is qualified by the express language and defined terms contained in the Bank Credit Agreement and amendments thereto, each of which is filed as an exhibit to our periodic reports filed with theSEC . The Second Amendment to the Credit Agreement, which is attached as Exhibit 10(d) to this Form 10-Q, contains the full text of the current version of the Bank Credit Agreement inclusive of all changes made by virtue of both the First and Second Amendments thereto. Commitments and Obligations. We have numerous contractual commitments in the ordinary course of business including debt service requirements, operating leases, purchase obligations, and asset retirement obligations. Our operating leases primarily consist of our office leases. Our purchase obligations represent future cash commitments primarily for purchase contracts for CO2 captured from industrial sources, CO2 processing fees, transportation agreements and well-related costs. Our commitments and obligations consist of those detailed as ofDecember 31, 2021 , in our Form 10-K under Management's Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources and Liquidity - Commitments, Obligations and Off-Balance Sheet Arrangements. Off-Balance Sheet Arrangements. Our off-balance sheet arrangements include obligations for various development and exploratory expenditures that arise from our normal capital expenditure program or from other transactions common to our industry, none of which are recorded on our balance sheet. In addition, in order to recover our undeveloped proved reserves, we must also fund the associated future development costs estimated in our proved reserve reports. 20 --------------------------------------------------------------------------------
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Denbury Inc.
Management's Discussion and Analysis of Financial Condition and Results of
OperationsRESULTS OF OPERATIONS
Certain of our operating results and statistics for the comparative three months
ended
Three Months Ended
March 31 , In thousands, except per-share and unit data 2022
2021
Financial results Net loss(1)$ (872) $ (69,642) Net loss per common share - basic(1) (0.02) (1.38) Net loss per common share - diluted(1) (0.02) (1.38) Net cash provided by operating activities 90,143 52,656 Average daily sales volumes Bbls/d 45,466 46,007 Mcf/d 8,753 8,102 BOE/d(2) 46,925 47,357 Oil and natural gas sales Oil sales$ 381,242 $ 233,044 Natural gas sales 3,669 2,401 Total oil and natural gas sales$ 384,911 $ 235,445 Commodity derivative contracts(3) Payment on settlements of commodity derivatives$ (93,057) $ (38,453) Noncash fair value losses on commodity derivatives (99,662) (77,290) Commodity derivatives expense $
(192,719)
$ 93.17 $ 56.28 Natural gas price per Mcf 4.66 3.29
Unit prices - including impact of derivative settlements(3) Oil price per Bbl
$ 70.43 $ 47.00 Natural gas price per Mcf 4.66 3.29 Oil and natural gas operating expenses Lease operating expenses$ 117,828 $ 81,970 Transportation and marketing expenses 4,645
7,797
Production and ad valorem taxes 30,443
17,895
Oil and natural gas operating revenues and expenses per BOE Oil and natural gas revenues
$ 91.14 $ 55.24 Lease operating expenses 27.90
19.23
Transportation and marketing expenses 1.10 1.83 Production and ad valorem taxes 7.21 4.20 CO2 - revenues and expenses CO2 sales and transportation fees$ 13,422 $ 9,228 CO2 operating and discovery expenses (2,817) (993) CO2 revenue and expenses, net$ 10,605 $ 8,235 (1)Includes a pre-tax full cost pool ceiling test write-down of our oil and natural gas properties of$14.4 million during the first quarter of 2021. (2)Barrel of oil equivalent using the ratio of one barrel of oil to six Mcf of natural gas ("BOE"). (3)See also Commodity Derivative Contracts below and Item 3. Quantitative and Qualitative Disclosures about Market Risk for information concerning our derivative transactions. 21
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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 2021 and for the first quarter of 2022 is shown below:
Average Daily Sales Volumes (BOE/d)
First Fourth Third Second First
Quarter Quarter Quarter Quarter Quarter
Operating Area 2022 2021 2021 2021 2021
Tertiary oil sales volumes
Gulf Coast region
Delhi 2,675 2,731 2,859 2,931 2,925
Hastings 4,430 4,212 4,343 4,487 4,226
Heidelberg 3,653 3,797 3,895 3,942 4,054
Oyster Bayou 3,745 4,039 3,942 3,791 3,554
Tinsley 3,015 3,353 3,390 3,455 3,424
Other(1) 5,498 5,801 5,907 6,074 6,098
Total Gulf Coast region 23,016 23,933 24,336 24,680 24,281
Rocky Mountain region
Bell Creek 4,474 4,331 4,330 4,394 4,614
Other(2) 4,746 4,551 4,703 4,378 2,573
Total Rocky Mountain region 9,220 8,882 9,033 8,772 7,187
Total tertiary oil sales volumes 32,236 32,815 33,369 33,452 31,468
Non-tertiary oil and gas sales volumes
Gulf Coast region
Total Gulf Coast region 3,630 3,929 3,763 3,415 3,621
Rocky Mountain region
Cedar Creek Anticline 9,721 10,784 11,182 10,918 11,150
Other(3) 1,338 1,354 1,368 1,348 1,118
Total Rocky Mountain region 11,059 12,138 12,550 12,266 12,268
Total non-tertiary sales volumes 14,689 16,067 16,313 15,681 15,889
Total sales volumes 46,925 48,882 49,682 49,133 47,357
(1)Includes Brookhaven, Cranfield, Eucutta, Little Creek , Mallalieu,
Martinville, McComb, Soso, and West Yellow Creek fields.
(2)Includes tertiary sales volumes related to our working interest positions in
the Big Sand Draw and Beaver Creek EOR fields (collectively "Wind River Basin ")
acquired on March 3, 2021 , as well as Salt Creek and Grieve fields.
(3)Includes non-tertiary sales volumes from Wind River Basin , as well as Hartzog
Draw and Bell Creek fields.
Total sales volumes during the first quarter of 2022 averaged 46,925 BOE/d,
including 32,236 Bbls/d from tertiary properties and 14,689 BOE/d from
non-tertiary properties. This sales volume represents a decrease of 1,957 BOE/d
(4%) compared to sales levels in the fourth quarter of 2021 and was essentially
flat with first quarter of 2021 sales volumes. The decrease on a
sequential-quarter basis was primarily attributable to (a) weather-related
downtime and downtime coinciding with activities to progress our tertiary
development at CCA and (b) production decline due to low levels of capital
investment and development spending in recent years (excluding the new EOR
development at CCA).
Our sales volumes during the three months ended
22
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Denbury Inc.
Management's Discussion and Analysis of Financial Condition and Results of
OperationsOil and Natural Gas Revenues
Our oil and natural gas revenues during the three months endedMarch 31, 2022 increased 63% compared to these revenues for the same period in 2021. The changes in our oil and natural gas revenues are due to higher realized commodity prices (excluding any impact of our commodity derivative contracts), as reflected in the following table: Three Months Ended March 31, 2022 vs. 2021 Increase Percentage Increase (Decrease) in (Decrease) in In thousands Revenues Revenues Change in oil and natural gas revenues due to: Decrease in sales volumes$ (2,146) (1) % Increase in realized commodity prices 151,612 64 % Total increase in oil and natural gas revenues$ 149,466 63 %
Excluding any impact of our commodity derivative contracts, our average net
realized commodity prices and NYMEX differentials were as follows during each of
the three months ended
Three Months Ended
March 31,
2022 2021
Average net realized prices
Oil price per Bbl $ 93.17 $ 56.28
Natural gas price per Mcf 4.66 3.29
Price per BOE 91.14 55.24
Average NYMEX differentials
Gulf Coast region
Oil per Bbl $ (1.37) $ (1.37)
Natural gas per Mcf 0.16 0.68
Rocky Mountain region
Oil per Bbl $ (1.38) $ (1.80)
Natural gas per Mcf 0.08 0.49
Total Company
Oil per Bbl $ (1.37) $ (1.54)
Natural gas per Mcf 0.11 0.58
Prices received in a regional market fluctuate frequently and can differ from NYMEX pricing due to a variety of reasons, including supply and/or demand factors, crude oil quality, and location differentials.
•Gulf Coast Region. Our average NYMEX oil differential in theGulf Coast region was a negative$1.37 per Bbl during the first quarter of 2022, consistent with the first quarter of 2021 and a slight improvement from a negative$1.41 per Bbl during the fourth quarter of 2021. NYMEX WTI oil prices continued to strengthen during 2022, including the pricing for ourGulf Coast grades relative to NYMEX WTI index prices. For our crude oil sold under Light Louisiana Sweet ("LLS") index prices, the LLS-to-NYMEX differential averaged a positive$2.16 per Bbl on a trade-month basis for the first quarter of 2022, compared to a positive$2.02 per Bbl differential in the first quarter of 2021 and a positive$0.88 per Bbl in the fourth quarter of 2021. 23 --------------------------------------------------------------------------------
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Management's Discussion and Analysis of Financial Condition and Results of
Operations
•Rocky Mountain Region. NYMEX oil differentials in the Rocky Mountain region
averaged $1.38 per Bbl and $1.80 per Bbl below NYMEX during the first quarters
of 2022 and 2021, respectively, and $0.95 per Bbl below NYMEX during the fourth
quarter of 2021. Differentials in the Rocky Mountain region tend to fluctuate
with regional supply and demand trends and can fluctuate significantly on a
month-to-month basis due to weather, refinery or transportation issues, and
Canadian and U.S. crude oil price index volatility.
CO2 Revenues and Expenses
We sell a portion of the CO2 we own to third-party industrial users at various contracted prices primarily under long-term contracts. We recognize the revenue received on these CO2 sales as "CO2 sales and transportation fees" with the corresponding costs recognized as "CO2 operating and discovery expenses" in our Unaudited Condensed Consolidated Statements of Operations. CO2 sales and transportation fees were$13.4 million during the three months endedMarch 31, 2022 , compared to$9.2 million during the three months endedMarch 31, 2021 . The increase from the prior-year period was primarily due to new contracts and an increase in CO2 sales volumes.
Oil Marketing Revenues and Purchases
In certain situations, we purchase and subsequently sell oil from third parties. We recognize the revenue received and the associated expenses incurred on these sales on a gross basis as "Oil marketing revenues" and "Oil marketing purchases" in our Unaudited Condensed Consolidated Statements of Operations.
Commodity Derivative Contracts
The following table summarizes the impact our crude oil derivative contracts had on our operating results for the three months endedMarch 31, 2022 and 2021: Three Months Ended March 31, In thousands 2022 2021 Payment on settlements of commodity derivatives$ (93,057) $ (38,453) Noncash fair value losses on commodity derivatives (99,662) (77,290) Total expense$ (192,719) $ (115,743) Changes in our commodity derivatives expense were primarily related to the expiration of commodity derivative contracts, new commodity derivative contracts entered into for future periods, and to the changes in oil futures prices between the first quarter of 2021 and 2022. The benefit of the significant increase in our oil sales during 2022 over 2021 sales levels due to rising oil prices has been offset by payments on settlements of commodity derivative contracts, principally due to the strike prices of our fixed-price swaps. During the first quarter of 2022, we paid$93.1 million upon expiration of commodity derivative contracts, reflecting the very large fluctuations in oil prices preceding and after the invasion byRussia ofUkraine heightening supply uncertainty and oil market volatility. In order to provide a level of price protection to a portion of our oil production, we have hedged a portion of our estimated oil production through 2023 using NYMEX fixed-price swaps and costless collars. See Note 6, Commodity Derivative Contracts, to the Unaudited Condensed Consolidated Financial Statements for additional details of our outstanding commodity 24 --------------------------------------------------------------------------------
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Denbury Inc.
Management's Discussion and Analysis of Financial Condition and Results of
Operations
derivative contracts as of March 31, 2022 , and Item 3, Quantitative and
Qualitative Disclosures about Market Risk below for additional discussion. In
addition, the following table summarizes our commodity derivative contracts as
of May 4, 2022 :
2Q 2022 2H 2022 1H 2023 2H 2023
WTI NYMEX Volumes Hedged (Bbls/d) 15,500 9,500 4,500 2,000
Fixed-Price Swaps Swap Price(1)$49.01 $57.52 $74.88
WTI NYMEX Volumes Hedged (Bbls/d) 11,000 11,500 12,500 7,000
Collars Floor / Ceiling Price(1) $49.77 / $64.31 $52.39 / $67.29 $66.40 / $96.58
Total Volumes Hedged (Bbls/d) 26,500 21,000 17,000 9,000
(1)Averages are volume weighted.
Based on current contracts in place and NYMEX oil futures prices as ofMay 4, 2022 , which averaged approximately$102 per Bbl, we currently expect that we would make cash payments of approximately$265 million upon settlement of our April throughDecember 2022 contracts, the amount of which is primarily dependent upon fluctuations in future NYMEX oil prices in relation to the prices of our remaining 2022 fixed-price swaps which have a weighted average NYMEX oil price of$53.72 per Bbl and weighted average ceiling prices of our 2022 collars of$66.33 per Bbl. Changes in commodity prices, expiration of contracts, and new commodity contracts entered into cause fluctuations in the estimated fair value of our oil derivative contracts. Because we do not utilize hedge accounting for our commodity derivative contracts, the period-to-period changes in the fair value of these contracts, as outlined above, are recognized in our statements of operations. Production Expenses Lease Operating Expenses Three Months Ended March 31, In thousands, except per-BOE data 2022 2021 Total lease operating expenses$ 117,828 $ 81,970
Total lease operating expenses per BOE
Total lease operating expenses increased$35.9 million (44%) on an absolute-dollar basis, or$8.67 (45%) on a per BOE basis, during the three months endedMarch 31, 2022 , compared to the same prior-year period. The increases on an absolute-dollar basis and per-BOE basis were primarily due to (a) a benefit of$14.9 million in the prior-year period resulting from compensation under the Company's power agreements for power interruption during the severe winter storm inFebruary 2021 which related to power outages inTexas and disrupted the Company's operations; (b) a$7.9 million increase in CO2 and power and fuel expenses correlated with higher oil and natural gas prices; (c) an additional$6.6 million of expense as the 2022 period reflects an entire quarter's worth of lease operating expenses from ourMarch 2021 acquisition ofWind River Basin properties; and (d) inflationary impacts and an increase in workover activity contributing to increases across numerous cost categories such as workovers, repair and maintenance parts, and contract labor. Compared to the fourth quarter of 2021, lease operating expenses in the most recent quarter increased$2.0 million (2%) on an absolute-dollar basis and$2.15 (8%) on a per-BOE basis, due primarily to higher workover and power and fuel costs and lower sales volumes.
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$4.6 million and$7.8 million for the three months endedMarch 31, 2022 and 2021, respectively. The decrease during the comparative three-month periods was primarily due to a change in the sales point of certain of our production, which reduced our transportation expense. 25 --------------------------------------------------------------------------------
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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 increased$12.4 million (65%) during the three months endedMarch 31, 2022 , compared to the same prior-year period, due primarily to an increase in production taxes resulting from higher oil and natural gas revenues.
General and Administrative Expenses ("G&A")
Three Months Ended
March 31,
In thousands, except per-BOE data and employees 2022 2021
Cash G&A costs $ 15,721 $ 14,303
Stock-based compensation 2,971 17,680
G&A expense $ 18,692 $ 31,983
G&A per BOE
Cash G&A costs $ 3.72 $ 3.35
Stock-based compensation 0.71 4.15
G&A expenses $ 4.43 $ 7.50
Employees as of period end 724 677
Our G&A expense on an absolute-dollar basis was $18.7 million during the three
months ended March 31, 2022 , a decrease of $13.3 million from the same
prior-year period, primarily due to a $14.7 million decrease in stock-based
compensation expense in the 2022 period, as the first quarter of 2021 included
stock-based compensation expense resulting from the accelerated performance
achievement and vesting of performance-based equity awards granted in late 2020.
Interest and Financing Expenses
Three Months Ended
March 31,
In thousands, except per-BOE data and interest rates 2022 2021 Cash interest(1)$ 1,130 $ 1,934 Noncash interest expense 685 685 Less: capitalized interest (1,158) (1,083) Interest expense, net$ 657 $ 1,536 Interest expense, net per BOE$ 0.16 $ 0.36 Average debt principal outstanding$ 34,278 $ 135,396 Average cash interest rate(2) 5.5 % 4.0 % (1)Includes commitment fees paid on the Company's bank credit facility but excludes debt issue costs. (2)Excludes commitment fees paid on the Company's bank credit facility and debt issue costs. Cash interest during the three months endedMarch 31, 2022 decreased$0.8 million (42%) when compared to the same prior-year period. The decrease between periods was primarily due to repayment of our pipeline financings inOctober 2021 and a decrease in the average debt principal outstanding on our senior secured bank credit facility. 26 --------------------------------------------------------------------------------
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Management's Discussion and Analysis of Financial Condition and Results of
OperationsDepletion, Depreciation, and Amortization ("DD&A")
Three Months Ended
March 31,
In thousands, except per-BOE data 2022 2021
Oil and natural gas properties $ 28,668 $ 32,015
CO2 properties, pipelines, plants and other property and
equipment 6,677 7,435
Total DD&A $ 35,345 $ 39,450
DD&A per BOE
Oil and natural gas properties $ 6.79 $ 7.51
CO2 properties, pipelines, plants and other property and
equipment 1.58 1.75
Total DD&A cost per BOE $ 8.37 $ 9.26
Write-down of oil and natural gas properties $
-
The decrease in DD&A expense during the three months endedMarch 31, 2022 , when compared to the same period in 2021, was primarily due to a lower depletion rate as a result of an increase in our estimate of proved reserves between the periods based on higher commodity pricing.
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 Note 2, Acquisition) 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 did not record a ceiling test write-down during the three months endedMarch 31, 2022 . Income Taxes Three Months EndedMarch 31 ,
In thousands, except per-BOE amounts and tax rates 2022 2021 Current income tax benefit
$ (561) $
(191)
Deferred income tax benefit (5,944)
(51)
Total income tax benefit$ (6,505) $
(242)
Average income tax benefit per BOE$ (1.54) $
(0.05)
Effective tax rate 88.2 % 0.3 % Total net deferred tax asset (liability)$ 4,306 $
(1,224)
We make estimates and judgments in determining our income tax expense for
financial reporting purposes. These estimates and judgments occur in the
calculation of certain tax assets and liabilities that arise from differences in
the timing and recognition of revenue and expense for tax and financial
reporting purposes. Significant judgment is required in estimating valuation
allowances, and in making this determination we consider all available positive
and negative evidence and make certain assumptions. The realization of a
deferred tax asset ultimately depends on the existence of sufficient taxable
income in the applicable carryback or carryforward periods. In our assessment,
we consider the nature, frequency, and severity of current
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Management's Discussion and Analysis of Financial Condition and Results of
Operationsand cumulative losses, as well as historical and forecasted financial results, the overall business environment, our industry's historic cyclicality, the reversal of existing deferred tax assets and liabilities, and tax planning strategies.
AtMarch 31, 2022 , we assessed the valuation allowance recorded on our deferred tax assets, which was$125.5 million atDecember 31, 2021 . This valuation allowance on our federal and certain state deferred tax assets was recorded inSeptember 2020 after the application of fresh start accounting, as (1) the tax basis of our assets, primarily our oil and gas properties, was in excess of the carrying value, as adjusted for fresh start accounting and (2) our historical pre-tax income reflected a three-year cumulative loss primarily due to ceiling test write-downs and reorganization items that were recorded in 2020. While we continued to be in a cumulative three-year-loss position during the first quarter of 2022, we determined that there is sufficient positive evidence, primarily related to a substantial increase in worldwide oil prices, to conclude that$64.9 million of our federal and certain state deferred tax assets are more likely than not to be realized. Accordingly, we currently expect to reverse$64.9 million of this valuation allowance during the year endedDecember 31, 2022 as follows: (1)$5.9 million during the three months endedMarch 31, 2022 , and (2)$59.0 million during the second through fourth quarters of 2022, resulting in a change to our annualized effective tax rate. We will continue to maintain a valuation allowance of$60.6 million for certain state tax benefits that we currently do not expect to realize before their expiration. We evaluate our estimated annual effective income tax rate based on current and forecasted business results and enacted tax laws on a quarterly basis and apply this tax rate to our ordinary income or loss to calculate our estimated tax liability or benefit. Our income taxes are based on an estimated combined federal and state statutory rate of approximately 25% in 2022 and 2021. Our effective tax rate for the three months endedMarch 31, 2022 was significantly higher than our estimated statutory rate primarily due to the release of$5.9 million of the valuation allowance that was recorded discretely in the quarter. Our annualized effective tax rate for the year endedDecember 31, 2022 is currently estimated to be approximately 15%, as it includes the impact of the release of an additional$59.0 million of valuation allowances. This rate could move higher or lower based on our ultimate level of income. As ofMarch 31, 2022 , we had$0.6 million of alternative minimum tax credits, which under the Tax Cut and Jobs Act will be refundable by 2022 and are recorded as a receivable on the balance sheet. Our significant state net operating loss carryforwards expire in various years, starting in 2025. 28 --------------------------------------------------------------------------------
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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.
March 31,
Per-BOE data 2022 2021
Oil and natural gas revenues $ 91.14 $ 55.24
Payment on settlements of commodity derivatives (22.03) (9.02)
Lease operating expenses (27.90)
(19.23)
Production and ad valorem taxes (7.21)
(4.20)
Transportation and marketing expenses (1.10)
(1.83)
Production netback 32.90
20.96
CO2 sales, net of operating and discovery expenses 2.51
1.94
General and administrative expenses(1) (4.43) (7.50) Interest expense, net (0.16) (0.36) Stock compensation and other 0.09 3.85
Changes in assets and liabilities relating to operations (9.57)
(6.54)
Cash flows from operations 21.34 12.35
DD&A (8.37) (9.26)
Write-down of oil and natural gas properties - (3.37)
Deferred income taxes 1.41
0.01
Noncash fair value gains (losses) on commodity derivatives (23.60)
(18.14) Other noncash items 9.01 2.07 Net loss$ (0.21) $ (16.34) (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 endedMarch 31, 2021 , resulting in a significant non-recurring expense, which if excluded, would have caused these expenses to average$3.92 per BOE. 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, such as those related to our CCUS storage sites and related assets, 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 other plans and objectives for the future operations ofDenbury , projections or assumptions as to general economic conditions and the economics of a carbon capture, use and storage industry ("CCUS"), 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, financial forecasts, the extent of future 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 our current or proposed carbon capture, use and storage arrangements, together with assumptions based on current and projected production levels, oil and natural gas revenues, oil and gas prices and oilfield costs, the impact of current supply chain and inflationary pressures or expectations on our operations or costs, current or future 29 --------------------------------------------------------------------------------
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Denbury Inc.
Management's Discussion and Analysis of Financial Condition and Results of
Operations
expectations or estimations of our cash flows or the impact of changes in
commodity prices on cash flows, price and availability of advantageous commodity
derivative contracts or their predicted downside cash flow protection or cash
settlement payments required, forecasted drilling activity or methods, including
the timing and location thereof, estimated timing of commencement of CO2
injections in particular fields or areas, or initial production responses in
tertiary flooding projects, other development activities, finding costs,
interpretation or prediction of formation details, hydrocarbon reserve
quantities and values, 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 tax or environmental
laws or regulations or outcomes of any pending litigation, 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 that could significantly
and adversely affect current plans, anticipated outcomes, 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, especially as oil prices are affected
by the war in Ukraine , and consequently on the prices received or demand for our
produced oil; geopolitical actions and economic consequences of such war and
recently imposed financial sanctions; decisions as to production levels and/or
pricing by OPEC or U.S. producers in future periods; the impact of COVID-19 on
oil demand and economic activity levels; to what degree inflation impacts future
expenses; success of our risk management techniques; the uncertainty of drilling
results and reserve estimates; operating hazards and remediation costs;
disruption of operations and damages from cybersecurity breaches, or from well
incidents, climate events such as hurricanes, tropical storms, floods, forest
fires, or other natural occurrences; conditions in the worldwide financial,
trade and credit markets; 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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