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. 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 theGulf 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 lead in the emerging CCUS industry, as the building of a permanent carbon sequestration business requires both time and capital to build assets such as those we own and have been operating for years. During the first half of 2022, approximately 39% of the CO2 utilized in our oil and gas operations was industrial-sourced CO2, equivalent to an annualized average usage rate of over 4 million metric tons in 2022. This compares to 34% utilized during the first half of 2021, with the increase related to commencing CO2 injection in the first phase of our Cedar Creek Anticline ("CCA") EOR project. We anticipate this percentage will increase in the future as supportiveU.S. government policy and public pressure on industrial CO2 emitters will provide strong incentives for these entities to capture their CO2 emissions. 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 CO2 offtake, transportation and storage solutions. In the nearer term, while the energy transition is still evolving nationally, we believe that a key driver in speeding that transition is identifying and securing the long-term supply of industrial CO2, while also identifying potential future sequestration sites and landowners of those locations. We continue to make material progress in both of these areas, and thus far have signed agreements securing the rights to five future sequestration sites which we believe have the potential to store up to 1.5 billion metric tons of CO2. In addition, we have executed several term sheets for the future transportation and sequestration of CO2. During the first half of 2022, we capitalized$24.0 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 our use of CO2 in 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 and the proposed Inflation Reduction Act of 2022 or otherwise will drive demand for CCUS and allow us to collect a fee for the transportation and storage of captured industrial-sourced CO2, including CO2 utilized in our EOR operations. 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. 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 17 --------------------------------------------------------------------------------
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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 June 30, 2022 March 31,2022 Dec. 31, 2021 Sept. 30, 2021 June 30, 2021
Oil, natural gas, and related
product sales $ 451,970 $ 384,911 $ 333,348 $ 308,454 $ 282,708
Payment on settlements of
commodity derivatives (127,959) (93,057) (97,774) (77,670) (63,343)
Oil, natural gas, and related
product sales and commodity
derivative settlements,
combined $ 324,011 $ 291,854 $ 235,574 $ 230,784 $ 219,365
Average daily sales (BOE/d) 46,561 46,925 48,882 49,682 49,133
Average net realized oil
prices
Oil price per Bbl - excluding
impact of derivative
settlements $ 108.81 $ 93.17 $ 75.68 $ 68.88 $ 64.70
Oil price per Bbl - including
impact of derivative
settlements 77.63 70.43 53.21 51.35 50.10
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, then increasing to approximately $109 per Bbl during the second quarter of
2022. This increase in oil prices was due in part to worldwide oil supply
disruptions associated with the Russian invasion of Ukraine during the first
half of 2022.
As shown in the table above, our oil and natural gas revenues increased
significantly during 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.
These contracts were largely required to be entered into during the fourth
quarter of 2020 under the one-time requirement of our September 18, 2020 bank
credit facility. During the second quarter of 2022, we paid $128.0 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,
providing the potential for us to realize a greater portion of increased oil
prices.
Second Quarter 2022 Financial Results and Highlights. We recognized net income
of $155.5 million , or $2.83 per diluted common share, during the second quarter
of 2022, compared to a net loss of $77.7 million , or $1.52 per diluted common
share, during the second quarter of 2021. The primary drivers of the comparative
second quarter operating results include the following:
•Oil and natural gas revenues increased $169.3 million (60%) due primarily to an
increase in oil prices;
•Commodity derivatives expense decreased by $115.8 million consisting of a
$180.4 million increase in noncash fair value changes ($71.1 million gain during
the second quarter of 2022 compared to a $109.3 million loss in the prior-year
period), partially offset by a $64.6 million increase in cash payments upon
derivative contract settlements;
•Lease operating expenses increased $14.1 million (13%), primarily consisting of
increases of $6.5 million in power and fuel costs, $4.6 million in workovers,
$2.8 million in labor costs, and $2.4 million in CO2 expense, partially offset
by a $6.7 million insurance recovery of costs incurred in 2013 from property
damage at Delhi Field;
•Taxes other than income increased $13.9 million (62%) primarily due to an
increase in production taxes resulting from higher oil and gas revenues; and
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•Income taxes increased to an expense of
Commencement of Cedar Creek Anticline CO2 Injection. In earlyFebruary 2022 , we commenced CO2 injection in the first phase of our CCA EOR project and have subsequently continued to increase CO2 injections into the field. In order to stay ahead of potential supply chain delays, we plan to increase capital investment in the second half of the year at CCA to accelerate our procurement of compression equipment and construction of CO2 recycle facilities to ensure facilities are in place to handle anticipated production from the field. We continue to expect tertiary oil production response from CCA in the second half of 2023. Common Share Repurchase Program. In earlyMay 2022 , our Board of Directors authorized a common share repurchase program for up to$250 million of outstandingDenbury common stock. During the second quarter of 2022, the Company repurchased 457,549 shares ofDenbury common stock for$28.8 million , or$62.84 per share. Cumulatively throughJuly 31, 2022 , the Company repurchased 1,615,356 shares ofDenbury common stock (approximately 3.2% of our outstanding shares of common stock atMarch 31, 2022 ) for approximately$100.0 million , or an average price of$61.92 per share. OnAugust 2, 2022 , the Board of Directors increased the dollar amount ofDenbury common stock that can be purchased under the program to an aggregate of$350 million , and at that date, we were authorized to repurchase up to an additional$250.0 million of 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. Increase in 2022 Capital Expenditure Plans. Based on inflationary cost increases and the desire to accelerate capital spending to offset potential supply chain delays, we are increasing our 2022 capital expenditures estimate for oil and gas development activities from the previously anticipated upper end of$320 million to approximately$360 million . Approximately half of the increase relates to overall service cost inflation impacting the Company's operations, primarily related to labor and steel costs, and the rest of the increase is associated with CCA EOR development activities, where the Company is accelerating the purchase of compression equipment and construction of CO2 recycle facilities to ensure the field is ready to process the expected oil production response. In addition, our original budget for CCUS capital is still estimated at$50 million , but could increase depending on activity in the second half of the year. See further discussion under Capital Resources and Liquidity - 2022 Plans and Capital Budget.May 2022 Amendment to Senior Secured Bank Credit Agreement. In earlyMay 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 toMay 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. As ofJune 30, 2022 , we had no outstanding borrowings on our senior secured bank credit facility. Warrant Exercises. During the three and six months endedJune 30, 2022 , 1,796,237 and 1,822,013 warrants were exercised for a total of 987,411 shares and 1,001,564 shares, respectively, most of which were exercised on a cashless basis. AtJune 30, 2022 , the Company had approximately 3.4 million warrants outstanding that can be exercised for shares of our common stock, which represents approximately 60.9% of the aggregate series A and B warrants issued inSeptember 2020 , at an exercise price of$32.59 per share for the 1.8 million series A warrants outstanding and at an exercise price of$35.41 per share for the 1.6 million series B warrants outstanding. The warrants may be exercised for cash or on a cashless basis. The series A warrants are exercisable untilSeptember 18, 2025 , and the series B warrants are exercisable untilSeptember 18, 2023 , at which times the warrants expire.
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 ofJune 30, 2022 , we had no outstanding borrowings and$12.0 million of outstanding letters of credit under our$750 million senior secured bank credit facility, leaving us with$738.0 million of borrowing base availability and approximately$738.5 million of total liquidity including our cash position atJune 30, 2022 . This liquidity is more than adequate to meet our 19 --------------------------------------------------------------------------------
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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 early May 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).
Six Months Ended 2022 Sources and Uses. During the first half of 2022, we
generated cash flows from operations of $240.1 million , while incurring capital
costs of $169.9 million , consisting primarily of oil and gas development capital
expenditures of $143.9 million , CCUS related capital expenditures of $23.9
million , and capitalized interest of $2.1 million . During the second quarter of
2022, the Company also repurchased 457,549 shares of Denbury common stock for
$28.8 million , or $62.84 per share.
As further discussed below, based on oil price futures as of early August 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 2022, our Board of Directors adopted a share
repurchase program in early May 2022 authorizing the repurchase of up to $250
million of Denbury's common stock. Cumulatively through July 31, 2022 , the
Company repurchased 1,615,356 shares of Denbury common stock (approximately 3.2%
of our outstanding shares of common stock at March 31, 2022 ) for approximately
$100 million , or an average price of $61.92 per share. On August 2, 2022 , the
Board of Directors increased the dollar amount of Denbury common stock that can
be purchased under the program to an aggregate of $350 million , and at that
date, we were authorized to repurchase up to an additional $250.0 million of
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 also returning capital to our
shareholders through our share repurchase program.
2022 Plans and Capital Budget. Based on inflationary cost increases and the
desire to accelerate capital spending to offset potential supply chain delays,
we are increasing our 2022 capital expenditures estimate for oil and gas
development activities from the previously anticipated upper end of our range of
$320 million to approximately $360 million . Approximately half of the increase
relates to overall service cost inflation impacting the Company's operations,
primarily related to labor and steel costs, and the rest of the increase is
associated with CCA EOR development activities, where the Company is
accelerating the purchase of compression equipment and construction of CO2
recycle facilities to ensure the field is ready to process the expected oil
production response. In addition, anticipated spending for our CCUS business of
approximately $50 million remains unchanged but could increase depending on
activity levels in the second half of the year, with expenditures primarily
focused on securing CO2 sequestration sites and drilling one or more
stratigraphic test wells in those sequestration sites.
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Capital Expenditure Summary. The following table reflects incurred capital
expenditures for the six months ended
Six Months Ended
June 30,
In thousands 2022 2021
Capital expenditure summary(1)
CCA EOR field expenditures(2) $ 39,205 $ 9,100
CCA CO2 pipelines 1,241 9,999
CCA tertiary development 40,446 19,099
Non-CCA tertiary and non-tertiary fields 86,437 40,297
CO2 sources and other CO2 pipelines 2,110
-
Capitalized internal costs(3) 14,903
14,785
Oil & gas development capital expenditures 143,896
74,181
CCUS storage sites and related capital expenditures 23,900
-
Acquisitions of oil and natural gas properties(4) 374 10,811 Capitalized interest 2,133 2,251 Total capital expenditures$ 170,303 $ 87,243 (1)Capital expenditures in this summary are presented on an as-incurred basis (including accruals), and are$7.6 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$10.8 million during the first half 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 late 2021 and thus far in 2022. Based on cost increases and shortages experienced across the industry and higher fuel and power costs 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"). Availability under the Bank Credit Agreement is subject to a borrowing base, which is redetermined semiannually on or aroundMay 1 orNovember 1 of each year, with our next scheduled redetermination aroundNovember 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.
On
•Increased the borrowing base and lender commitments from$575 million to$750 million ; •Extended the maturity date fromJanuary 30, 2024 toMay 4, 2027 ; •Modified the interest provisions on loans under the Bank Credit Agreement to (1) reduce the applicable margin for alternate base rate loans from 2% to 3% per annum to 1.5% to 2.5% per annum and (2) replace provisions referencing LIBOR loans with Secured Overnight Financing Rate loans, with an applicable margin of 2.5% to 3.5% per annum; and •Permitted us to pay dividends on 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. 21 --------------------------------------------------------------------------------
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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 certain customary exceptions to
such limitations, as specified in the Bank Credit Agreement. Our Bank Credit
Agreement required certain minimum commodity hedge levels in connection with our
emergence from bankruptcy; however, these conditions were met as of December 31,
2020 , and we currently have no ongoing hedging requirements under the Bank
Credit Agreement.
The Bank Credit Agreement contains certain financial performance covenants including the following:
•A Consolidated Total Debt to Consolidated EBITDAX covenant (as defined in the Bank Credit Agreement), with such ratio not to exceed 3.5 times; and •A requirement to maintain a current ratio (i.e., Consolidated Current Assets to Consolidated Current Liabilities) of 1.0. For purposes of computing the current ratio per the Bank Credit Agreement, Consolidated Current Assets exclude the current portion of derivative assets but include available borrowing capacity under the Bank Credit Agreement, and Consolidated Current Liabilities exclude the current portion of derivative liabilities as well as the current portions of long-term indebtedness outstanding. Under these financial performance covenant calculations, as ofJune 30, 2022 , our ratio of consolidated total debt to consolidated EBITDAX was 0.00 to 1.0 (with a maximum permitted ratio of 3.5 to 1.0) and our current ratio was 2.70 to 1.0 (with a required ratio of not less than 1.0 to 1.0). Based upon our currently forecasted levels of production and costs, hedges in place as ofAugust 3, 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 theSecurities and Exchange Commission ("SEC"). The Second Amendment to the Credit Agreement, which is attached as Exhibit 10(d) to the Form 10-Q filed onMay 6, 2022 , contains the full text of the current version of the Bank Credit Agreement inclusive of all changes made by virtue of both the First and Second Amendments thereto. Commitments 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. 22 --------------------------------------------------------------------------------
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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 and six months endedJune 30, 2022 and 2021 are included in the following table: Three Months Ended Six Months Ended June 30, June 30 In thousands, except per-share and unit data 2022 2021 2022 2021 Financial results Net income (loss)(1)$ 155,494 $ (77,695) $ 154,622 $ (147,337) Net income (loss) per common share - basic(1) 3.00 (1.52) 2.99 (2.91) Net income (loss) per common share - diluted(1) 2.83 (1.52) 2.81 (2.91) Net cash provided by operating activities 149,965 90,882 240,108 143,538 Average daily sales volumes Bbls/d 45,104 47,653 45,284 46,834 Mcf/d 8,741 8,882 8,747 8,494 BOE/d(2) 46,561 49,133 46,742 48,250 Oil and natural gas sales Oil sales$ 446,592 $ 280,577 $ 827,834 $ 513,621 Natural gas sales 5,378 2,131 9,047 4,532 Total oil and natural gas sales$ 451,970 $ 282,708 $ 836,881 $ 518,153 Commodity derivative contracts(3) Payment on settlements of commodity derivatives$ (127,959) $ (63,343) $ (221,016) $ (101,796) Noncash fair value gains (losses) on commodity derivatives 71,105 (109,321) (28,557) (186,611) Commodity derivatives expense$ (56,854) $ (172,664) $ (249,573) $ (288,407) Unit prices - excluding impact of derivative settlements Oil price per Bbl$ 108.81 $ 64.70 $ 101.00 $ 60.59 Natural gas price per Mcf 6.76 2.64 5.71 2.95 Unit prices - including impact of derivative settlements(3) Oil price per Bbl$ 77.63 $ 50.10 $ 74.03 $ 48.58 Natural gas price per Mcf 6.76 2.64 5.71 2.95 Oil and natural gas operating expenses Lease operating expenses$ 124,351 $ 110,225 $ 242,179 $ 192,195 Transportation and marketing expenses 4,802 8,522 9,447 16,319 Production and ad valorem taxes 35,570 21,836 66,013 39,731 Oil and natural gas operating revenues and expenses per BOE Oil and natural gas revenues$ 106.67 $ 63.23 $ 98.92 $ 59.33 Lease operating expenses 29.35 24.65 28.63 22.01 Transportation and marketing expenses 1.13 1.91 1.12 1.87 Production and ad valorem taxes 8.40 4.88 7.80 4.55 CO2 - revenues and expenses CO2 sales and transportation fees$ 12,610 $ 10,134 $ 26,032 $ 19,362 CO2 operating and discovery expenses (1,681) (1,531) (4,498) (2,524) CO2 revenue and expenses, net$ 10,929 $ 8,603 $ 21,534 $ 16,838 (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. 23
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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 and second quarters of 2022 is shown below:
Average Daily Sales Volumes (BOE/d)
Second First Fourth Third Second First
Quarter Quarter Quarter Quarter Quarter Quarter
Operating Area 2022 2022 2021 2021 2021 2021
Tertiary oil sales volumes
Gulf Coast region
Delhi 2,478 2,675 2,731 2,859 2,931 2,925
Hastings 4,304 4,430 4,212 4,343 4,487 4,226
Heidelberg 3,528 3,653 3,797 3,895 3,942 4,054
Oyster Bayou 3,423 3,745 4,039 3,942 3,791 3,554
Tinsley 3,050 3,015 3,353 3,390 3,455 3,424
Other(1) 5,422 5,498 5,801 5,907 6,074 6,098
Total Gulf Coast region 22,205 23,016 23,933 24,336 24,680 24,281
Rocky Mountain region
Bell Creek 4,122 4,474 4,331 4,330 4,394 4,614
Other(2) 5,064 4,746 4,551 4,703 4,378 2,573
Total Rocky Mountain region 9,186 9,220 8,882 9,033 8,772 7,187
Total tertiary oil sales volumes 31,391 32,236 32,815 33,369 33,452 31,468
Non-tertiary oil and gas sales volumes
Gulf Coast region
Total Gulf Coast region 3,566 3,630 3,929 3,763 3,415 3,621
Rocky Mountain region
Cedar Creek Anticline 10,224 9,721 10,784 11,182 10,918 11,150
Other(3) 1,380 1,338 1,354 1,368 1,348 1,118
Total Rocky Mountain region 11,604 11,059 12,138 12,550 12,266 12,268
Total non-tertiary sales volumes 15,170 14,689 16,067 16,313 15,681 15,889
Total sales volumes 46,561 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 second quarter of 2022 averaged 46,561 BOE/d,
including 31,391 Bbls/d from tertiary properties and 15,170 BOE/d from
non-tertiary properties. This sales volume was relatively flat with first
quarter of 2022 sales volumes as sales volume increases at CCA, Wind River Basin
(262 BOE/d increase) and Grieve fields (297 BOE/d increase) in the Rocky
Mountain region were offset by declines across various fields, with the largest
declines at Bell Creek and Oyster Bayou due to downtime related to compressor
and workover activities. On a year-over-year basis, sales volumes decreased
2,572 BOE/d (5%) compared to sales levels in the second quarter of 2021
primarily attributable to low levels of capital investment and development
spending in recent years (excluding the new EOR development at CCA). We
currently expect sales volumes during the third quarter of 2022 to be consistent
with the second quarter of 2022 and sales volumes to increase during the fourth
quarter of 2022, as a result of incremental production increases from
development projects completed in the first half of the year.
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Our sales volumes during the three and six months ended
Oil and Natural Gas Revenues
Our oil and natural gas revenues during the three and six months endedJune 30, 2022 increased 60% and 62%, respectively, compared to these revenues for the same periods 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 Six Months Ended June 30, June 30, 2022 vs. 2021 2022 vs. 2021 Increase Percentage Increase Increase Percentage Increase (Decrease) in (Decrease) in (Decrease) in (Decrease) in In thousands Revenues Revenues Revenues Revenues Change in oil and natural gas revenues due to: Decrease in sales volumes$ (14,799) (5) %$ (16,191) (3) % Increase in realized commodity prices 184,061 65 % 334,919 65 % Total increase in oil and natural gas revenues$ 169,262 60 %$ 318,728 62 % Excluding any impact of our commodity derivative contracts, our average net realized commodity prices and NYMEX differentials were as follows during the three months endedMarch 31, 2022 and 2021 and the three and six months endedJune 30, 2022 and 2021: Three Months Ended Three Months Ended Six Months Ended March 31, June 30, June 30, 2022 2021 2022 2021 2022 2021 Average net realized prices Oil price per Bbl$ 93.17 $ 56.28 $ 108.81 $ 64.70 $ 101.00 $ 60.59 Natural gas price per Mcf 4.66 3.29 6.76 2.64 5.71 2.95 Price per BOE 91.14 55.24 106.67 63.23 98.92 59.33 Average NYMEX differentials Gulf Coast region Oil per Bbl$ (1.37) $ (1.37) $ 0.16 $ (1.13) $ (0.72) $ (1.23) Natural gas per Mcf 0.16 0.68 0.02 (0.11) 0.01 0.30Rocky Mountain region Oil per Bbl$ (1.38) $ (1.80) $ 0.01 $ (1.59) $ (0.59) $ (1.54) Natural gas per Mcf 0.08 0.49 (1.12) (0.47) (0.49) (0.04)Total Company Oil per Bbl$ (1.37) $ (1.54) $ 0.09 $ (1.32) $ (0.67) $ (1.36) Natural gas per Mcf 0.11 0.58 (0.71) (0.33) (0.31) 0.11
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 positive$0.16 per Bbl during the second quarter of 2022, an improvement compared to a negative$1.13 per Bbl during the second quarter of 2021 and a negative$1.37 per Bbl during the first quarter of 2022. During the second quarter of 2022, the Company 25 --------------------------------------------------------------------------------
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modified certain of its sales contracts and benefited from improved pricing for
its
•Rocky Mountain Region. NYMEX oil differentials in theRocky Mountain region were essentially flat with NYMEX WTI prices during the second quarter of 2022, compared to$1.59 per Bbl below NYMEX during the second quarter of 2021 and$1.38 per Bbl below NYMEX during the first quarter of 2022. Similar to our differentials in theGulf Coast region, differentials in theRocky Mountain region improved significantly during the second quarter of 2022 as regional demand for our Rockies crude was strong. Differentials in theRocky Mountain region tend to fluctuate with regional supply and demand trends and can fluctuate significantly on a month-to-month basis due to weather, refinery or transportation issues, and Canadian andU.S. crude oil price index volatility.
CO2 Revenues and Expenses
We sell 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$12.6 million and$26.0 million during the three and six months endedJune 30, 2022 , respectively, compared to$10.1 million and$19.4 million during the three and six-month periods endedJune 30, 2021 , respectively. The increases from the prior-year periods were primarily due to new contracts and an increase in CO2 sales volumes.
Oil Marketing Revenues and Purchases
In certain situations, we purchase and subsequently sell oil from third parties. We recognize the revenue received and the associated expenses incurred on these sales on a gross basis as "Oil marketing revenues" and "Oil marketing purchases" in our Unaudited Condensed Consolidated Statements of Operations.
Commodity Derivative Contracts
The following table summarizes the impact our crude oil derivative contracts had on our operating results for the three and six months endedJune 30, 2022 and 2021: Three Months Ended Six Months Ended June 30, June 30, In thousands 2022 2021 2022 2021 Payment on settlements of commodity derivatives$ (127,959) $ (63,343) $ (221,016) $ (101,796) Noncash fair value gains (losses) on commodity derivatives 71,105 (109,321) (28,557) (186,611) Total expense$ (56,854) $ (172,664) $ (249,573) $ (288,407) Changes in our commodity derivatives expense are related to the expiration of commodity derivative contracts, changes in oil futures prices between the second quarter of 2021 and 2022, and new commodity derivative contract commitments for future periods. During the first half of 2022, we paid$221.0 million upon settlement of commodity derivative contracts, corresponding with the large increase in oil prices and the Company's oil revenues during that same period. 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 7, Commodity Derivative Contracts, to the Unaudited Condensed Consolidated Financial Statements for additional details of our outstanding commodity 26 --------------------------------------------------------------------------------
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derivative contracts as of June 30, 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 August 3, 2022 :
2H 2022 1H 2023 2H 2023
WTI NYMEX Volumes Hedged (Bbls/d) 9,500 4,500 2,000
Fixed-Price Swaps Weighted Average Swap Price $57.52 $74.88 $76.80
WTI NYMEX Volumes Hedged (Bbls/d) 11,500 17,500 9,000
Collars Weighted Average Floor / Ceiling Price $52.39 / $67.29 $69.71 / $100.42 $68.33 / $100.69
Total Volumes Hedged (Bbls/d) 21,000 22,000 11,000
Based on current contracts in place and NYMEX oil futures prices as of August 3,
2022 , which averaged approximately $89 per Bbl, we currently expect that we
would make cash payments of approximately $115 million upon settlement of our
July through December 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 $57.52 per Bbl and weighted average ceiling prices of our 2022 collars of
$67.29 per Bbl. Changes in commodity prices, expiration of contracts, and new
commodity contract commitments 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 Six Months Ended
June 30, June 30,
In thousands, except per-BOE data 2022 2021 2022 2021
Total lease operating expenses $ 124,351 $ 110,225
Total lease operating expenses per BOE
Total lease operating expenses increased$14.1 million (13%) and$50.0 million (26%) on an absolute-dollar basis, or$4.70 (19%) and$6.62 (30%) on a per-BOE basis, during the three and six months endedJune 30, 2022 , respectively, compared to the same prior-year periods. The increases on an absolute-dollar and per-BOE basis during the three months endedJune 30, 2022 were primarily due to increases of$6.5 million in power and fuel costs,$4.6 million in workovers,$2.8 million in labor costs, and$2.4 million in CO2 expense, partially offset by an insurance reimbursement totaling$6.7 million recorded for property damage costs incurred during 2013 at Delhi Field. The increase in lease operating expenses during the six months endedJune 30, 2022 was further impacted by (a) a benefit of$16.3 million during the six months endedJune 30, 2021 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 and (b) an additional$9.5 million of expense as the 2022 period reflects an entire six month's worth of lease operating expenses from ourMarch 2021 acquisition ofWind River Basin properties. Compared to the first quarter of 2022, lease operating expenses in the most recent quarter increased$6.5 million (6%) on an absolute-dollar basis and$1.45 (5%) on a per-BOE basis, due primarily to higher workover, labor costs, CO2 expense, and power and fuel costs, partially offset by the insurance reimbursement discussed above.
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$4.8 million and$8.5 million for the three months endedJune 30, 2022 and 2021, respectively, and$9.4 million and$16.3 million for the six months endedJune 30, 2022 and 2021, respectively. The decreases during the most recent comparative three and six-month periods were primarily due to a change in the sales contracts of certain of our production, which reduced our transportation expense. 27 --------------------------------------------------------------------------------
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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$13.9 million (62%) and$26.4 million (64%) during the three and six months endedJune 30, 2022 , respectively, compared to the same prior-year periods, due primarily to an increase in production taxes resulting from higher oil and natural gas revenues.
General and Administrative Expenses ("G&A")
Three Months Ended Six Months Ended
June 30, June 30,
In thousands, except per-BOE data and
employees 2022 2021 2022 2021
Cash G&A costs $ 15,131 $ 12,898 $ 30,852 $ 27,201
Stock-based compensation 4,104 2,552 7,075 20,232
G&A expense $ 19,235 $ 15,450 $ 37,927 $ 47,433
G&A per BOE
Cash G&A costs $ 3.57 $ 2.89 $ 3.65 $ 3.11
Stock-based compensation 0.97 0.57 0.83 2.32
G&A expenses $ 4.54 $ 3.46 $ 4.48 $ 5.43
Employees as of period end 740 690
Our G&A expense on an absolute-dollar basis was $19.2 million during the three
months ended June 30, 2022 , an increase of $3.8 million from the same prior-year
period, primarily due to higher employee-related costs ($1.6 million for
stock-based compensation) and higher professional service fees. During the six
months ended June 30, 2022 , our G&A expense decreased $9.5 million , primarily
due to a decrease in stock-based compensation as the six months ended June 30,
2021 included $15.3 million of stock-based compensation expense in the first
quarter of 2021 resulting from the accelerated performance achievement and
vesting of performance-based equity awards granted in late 2020, partially
offset by higher employee-related costs and professional service fees.
Interest and Financing Expenses
Three Months Ended Six Months Ended
June 30, June 30,
In thousands, except per-BOE data and
interest rates 2022 2021 2022 2021
Cash interest(1) $ 1,252 $ 1,735 $ 2,382 $ 3,669
Noncash interest expense 1,249 685 1,934 1,370
Less: capitalized interest (975) (1,168) (2,133) (2,251)
Interest expense, net $ 1,526 $ 1,252 $ 2,183 $ 2,788
Interest expense, net per BOE $ 0.36 $ 0.28 $ 0.26 $ 0.32
Average debt principal outstanding $ 29,088 $ 107,542 $ 31,669 $ 121,392
Average cash interest rate(2) 6.0 % 4.2 % 5.7 % 4.1 %
(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 and six months ended June 30, 2022 decreased $0.5
million (28%) and $1.3 million (35%) when compared to the same prior-year
periods. The decreases between periods were primarily due to repayment of our
pipeline financings in October 2021 and a decrease in the average principal
outstanding on our senior secured bank credit facility. The
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increase in noncash interest expense during the three and six months ended
June 30, 2022 , compared to the same prior-year periods, was due to a write-off
of debt issuance costs related to lenders who exited our senior secured bank
credit facility in conjunction with our May 2022 amendment.
Depletion, Depreciation, and Amortization ("DD&A")
Three Months Ended Six Months Ended
June 30, June 30,
In thousands, except per-BOE data 2022 2021 2022 2021
Oil and natural gas properties $ 29,084 $ 28,550 $ 57,752 $ 60,565
CO2 properties, pipelines, plants and
other property and equipment 6,316 7,831 12,993 15,266
Total DD&A $ 35,400 $ 36,381 $ 70,745 $ 75,831
DD&A per BOE
Oil and natural gas properties $ 6.86 $ 6.39 $ 6.83 $ 6.94
CO2 properties, pipelines, plants and
other property and equipment 1.49 1.75 1.53 1.74
Total DD&A cost per BOE $ 8.35 $ 8.14 $ 8.36 $ 8.68
Write-down of oil and natural gas
properties $ - $ - $ - $ 14,377
The decrease in DD&A expense during the three months ended June 30, 2022 , when
compared to the same period in 2021, was primarily due to lower depreciation on
other fixed assets and CO2 sources, partially offset by higher accretion expense
related to asset retirement obligations at our oil and gas properties. DD&A
expense decreased $5.1 million during the six months ended June 30, 2022 , when
compared to the same prior-year period, 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 and lower depreciation on other fixed
assets and CO2 sources.
First Quarter 2021 Full Cost Pool Ceiling Test Write-Down
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 . The write-down was primarily a result of theMarch 2021 acquisition ofWyoming CO2 EOR properties (see Note 2, Acquisition and Divestiture) 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 or six months endedJune 30, 2022 .
Other Expenses
Other expenses during the three and six months endedJune 30, 2022 include a$3.9 million accrual for a preliminarily assessed civil penalty proposed by thePipeline and Hazardous Materials Safety Administration of theU.S. Department of Transportation in a Notice of Probable Violation (see Item 1, Legal Proceedings - Notice of Probable Violation fromPipeline and Hazardous Materials Safety Administration ("PHMSA") Regarding Delta-Tinsley CO2 Pipeline Failure). Other expenses totaled$3.2 million and$5.4 million during the three and six months endedJune 30, 2021 , respectively. 29 --------------------------------------------------------------------------------
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Income Taxes
Three Months Ended Six Months Ended
June 30, June 30,
In thousands, except per-BOE amounts and
tax rates 2022 2021 2022 2021
Current income tax expense (benefit) $ 2,912 $ (260) $ 2,351 $ (451)
Deferred income tax expense (benefit) 21,936 (36) 15,992 (87)
Total income tax expense (benefit) $ 24,848 $ (296) $ 18,343 $ (538)
Average income tax expense (benefit) per
BOE $ 5.87 $ (0.07) $ 2.17 $ (0.06)
Effective tax rate 13.8 % 0.4 % 10.6 % 0.4 %
Total net deferred tax liability $ 17,630 $ 1,187
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 and six months endedJune 30, 2022 was significantly lower than our estimated statutory rate primarily due to the release of the valuation allowance that was recorded in the three and six months endedJune 30, 2022 . 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$40.2 million of valuation allowances over the remaining two quarters of 2022. This rate could move higher or lower based on our ultimate level of income. 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 and cumulative losses, as well as historical and forecasted financial results, the overall business environment, our industry's historic cyclicality, the reversal of existing deferred tax assets and liabilities, and tax planning strategies. We assess the valuation allowance recorded on our deferred tax assets, which was$125.5 million atDecember 31, 2021 , on a quarterly basis. 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 initially determined, at that time, that there was 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 reversed$5.9 million of this valuation allowance during the three months endedMarch 31, 2022 ,$18.8 million during the three months endedJune 30, 2022 , and currently expect to reverse the remaining$40.2 million during the second half of 2022, resulting in a reduction 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. As ofJune 30, 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. 30 --------------------------------------------------------------------------------
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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.
Three Months Ended Six Months Ended
June 30, June 30,
Per-BOE data 2022 2021 2022 2021
Oil and natural gas revenues $ 106.67 $ 63.23 $ 98.92 $ 59.33
Payment on settlements of commodity
derivatives (30.20) (14.17) (26.13) (11.65)
Lease operating expenses (29.35) (24.65) (28.63) (22.01)
Production and ad valorem taxes (8.40) (4.88) (7.80) (4.55)
Transportation and marketing expenses (1.13) (1.91) (1.12) (1.87)
Production netback 37.59 17.62 35.24 19.25
CO2 sales, net of operating and discovery
expenses 2.58 1.93 2.55 1.93
General and administrative expenses(1) (4.54) (3.46) (4.48) (5.43)
Interest expense, net (0.36) (0.28) (0.26) (0.32)
Stock compensation and other (1.01) 0.12 (0.45) 1.95
Changes in assets and liabilities relating
to operations 1.13 4.40 (4.22) (0.94)
Cash flows from operations 35.39 20.33 28.38 16.44
DD&A (8.35) (8.14) (8.36) (8.68)
Write-down of oil and natural gas
properties - - - (1.65)
Deferred income taxes (5.18) 0.01 (1.89) 0.01
Noncash fair value gains (losses) on
commodity derivatives 16.78 (24.45) (3.37) (21.37)
Other noncash items (1.94) (5.13) 3.52 (1.62)
Net income (loss) $ 36.70 $ (17.38) $ 18.28 $ (16.87)
(1)General and administrative expenses include $15.3 million of performance
stock-based compensation related to the full vesting of outstanding performance
awards during the six months ended June 30, 2021 , resulting in a significant
non-recurring expense, which if excluded, would have caused these expenses to
average $3.68 per BOE.
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 oil markets or 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 recent higher worldwide oil prices; the extent of future oil price volatility; current or future liquidity sources or their adequacy to support our 31 --------------------------------------------------------------------------------
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anticipated future activities; statements or predictions related to the ultimate
timing and financial impact of our current or proposed carbon capture, use and
storage arrangements; our projected production levels, oil and natural gas
revenues, oil and gas prices and oilfield costs, the impact of current supply
chain and inflation on our results of operations; current or future expectations
or estimations of our cash flows or the impact of changes in commodity prices on
cash flows; availability, terms and financial statement and cash settlement
impact of commodity derivative contracts or their predicted downside cash flow
protection; forecasted drilling activity or methods, including the timing and
location thereof; 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;
the outcomes of any pending litigation or regulatory proceedings; and overall
worldwide or U.S. economic conditions, and other variables surrounding
operations and future plans. Such forward-looking statements generally are
accompanied by words such as "plan," "estimate," "expect," "predict,"
"forecast," "to our knowledge," "anticipate," "projected," "preliminary,"
"should," "assume," "believe," "may" or other words that convey, or are intended
to convey, the uncertainty of future events or outcomes.
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 or U.S. oil prices, especially as oil prices are
affected by the war in Ukraine , and geopolitical and economic consequences of
such war and resulting financial sanctions; decisions as to production levels
and/or pricing by OPEC or U.S. producers in future periods; the impact of
COVID-19 or other viral outbreaks on economic activity levels and ultimately oil
prices; the pace and terms of agreements reached with third parties for the
capture, transportation, use and ultimate permanent sequestration of CO2; the
timing and success of CCUS projects that, while undertaken by third parties, are
related to our CCUS efforts; 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 currency and credit markets; the risks and
uncertainties inherent in oil and gas drilling and production activities; and
the risks and uncertainties set forth from time to time in this or our other
public reports, filings and public statements including, without limitation, the
Company's most recent Form 10-K.
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