Exhibit 99.1
DENBURY RESOURCES INC.
P R E S S R E L E A S E
Denbury Resources Announces Third Quarter 2003 Results
News Release
Released at 7:30 AM CDT
DALLAS - November 3, 2003 - Denbury Resources Inc. (NYSE symbol: DNR)
("Denbury" or the "Company") today announced its third quarter 2003 financial
and operating results. The Company posted earnings for the quarter of $15.1
million, or $0.28 per common share, as compared to earnings of $13.5 million, or
$0.25 per common share for the third quarter of 2002. Adjusted cash flow from
operations for the quarter was $45.6 million, as compared to $44.2 million
during the third quarter of 2002. (Please see the accompanying schedules for a
reconciliation of net cash flow provided by operations, as defined by generally
accepted accounting principles (GAAP), which is the GAAP measure, as opposed to
adjusted cash flow, which is the non-GAAP measure). Net cash flow provided by
operations, the GAAP measure, totaled $49.8 million during the third quarter of
2003, as compared to $44.4 million during the third quarter of 2002.
Third Quarter 2003 Financial Results
During late July and early August 2003, Denbury upgraded its CO2 facility
at Jackson Dome, increasing the CO2 processing capacity of its facility by
approximately 50%, from around 200 MMcf/d to approximately 300 MMcf/d. This
upgrade was performed several months ahead of the original schedule to handle
the higher than expected production volumes from its CO2 wells drilled during
late 2002 and early 2003. At the same time, the Company increased the size of
its CO2 processing facility at Mallalieu Field, increasing the amount of CO2
that the Company can recycle at that field from approximately 28 MMcf/d to
approximately 108 MMcf/d. With the completion of the Company's third CO2 well,
the Barksdale, coupled with the upgraded Jackson Dome facility, the Company's
CO2 production capability is now around 220 MMcf/d, approximately double its
production capability one year ago. As a result of these upgrades, which shut-in
the Company's CO2 production and associated injections for approximately one
week in late July, the Company's oil production from tertiary recovery decreased
slightly in the third quarter to 4,227 BOE/d. However, with the increased CO2
production, oil production from these tertiary recovery properties is
preliminarily estimated to average approximately 5,400 BOE/d during the month of
October 2003, the Company's highest monthly average to date.
Denbury's overall third quarter 2003 average daily production of 33,116
BOE/d was 7% lower than the 35,506 BOE/d production average for the comparable
period in 2002. Production decreased due to normal depletion, less than expected
production increases from first half exploration and development results,
unexpected delays offshore and the one-week temporary CO2 curtailment (see
above). Property sales have also contributed to the production decrease. During
the first nine months of 2003, the Company sold over $29 million of properties,
principally the Laurel Field sold in February, with estimated aggregate
production from these properties of approximately 2,000 BOE/d.
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Commodity prices were higher in the third quarter of 2003 as compared to
prices in the third quarter of the prior year. NYMEX oil prices averaged over
$30.00 per Bbl, and natural gas prices averaged just under $5.00 per Mcf in the
third quarter of 2003, as compared to NYMEX averages of around $28.25 per Bbl
and $3.20 per Mcf in the third quarter of 2002. Denbury's weighted average price
per BOE was $7.05 higher per BOE (excluding hedges) in the third quarter of 2003
than in the comparable period of 2002. However, approximately $3.95 per BOE of
this increase was paid out on the Company's hedges in the current quarter of
2003, as compared to only $0.07 per BOE of hedge payments in the comparable 2002
period. Net of these hedge payments, the net realized per BOE price increase
received by the Company between the respective third quarters was $3.17 per BOE.
Partially offsetting higher revenues were increases in certain expenses.
Lease operating expenses increased from $5.43 per BOE in the third quarter of
2002 to $7.35 per BOE in the third quarter of 2003. The primary reason for the
increase was the cost of various workovers and repairs, including a $700,000
tubing repair on a CO2 well charged to lease operating expense. This tubing
repair also affected CO2 operating expenses. Continued high expenses on the
properties acquired from COHO, continued expansion of CO2 tertiary projects,
which typically have a higher than average operating cost per BOE, and higher
lease fuel costs due to high natural gas prices also contributed to the higher
than historical operating costs. Partially offsetting these higher operating
expenses relating to CO2 operations are improved oil prices as a result of the
gradually decreasing NYMEX differentials, partially relating to an increasing
percentage of light sweet oil production from the Company's CO2 operations. The
Company anticipates that its lease operating expenses on a per BOE basis will
decrease in the fourth quarter of 2003, assuming a return to normal operating
parameters.
General and administrative expenses increased to an average of $1.13 per
BOE in the third quarter of 2003, up from $0.93 per BOE in the comparable
quarter of 2002. The increase primarily relates to incremental expenses
associated with the requirements of the Sarbanes-Oxley Act and an overall
increase in personnel and associated expenses.
Interest expense decreased 22% in the third quarter of 2003 as compared to
the third quarter of the prior year, as the Company recognized a full quarter of
the interest rate savings that resulted from its subordinated debt refinancing
in March and April. In addition to the interest rate reduction, the Company's
overall average debt was also lower in third quarter of 2003 as a result of the
Company's 2003 debt reduction plan.
Offshore Update
Five offshore wells scheduled to be drilled for the first seven months of
2003 were delayed while waiting for partner approvals and clearance of other
logistical issues. Two offshore wells have been drilled during the third quarter
and early fourth quarter and were in the process of being completed as of
October 31, 2003, as were the wells at North Padre Island, Denbury's year-end
2002 discovery. The delay in these wells negatively affected the third quarter
production, although with their anticipated production, fourth quarter
production is expected to be higher than that in the third quarter. As of
October 31, 2003, three offshore wells were expected to commence drilling within
the next week or two, although since it is so late in
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the year, these wells will not have a meaningful production impact in 2003 even
if they are successful.
2003 Outlook
Denbury's 2003 development and exploration budget (excluding acquisitions)
is currently set at $154 million, including approximately $8 million of projects
carried over from 2002. During the first nine months of 2003, the Company made
several minor acquisitions, primarily consisting of incremental interests in
existing properties, at an aggregate cost of approximately $11 million. The 2004
budget has not been finalized to date, but is expected to be in the range of
$150 to $175 million, with as much as 50% of this budget related to CO2
operations. The Company expects its average daily production for the fourth
quarter of 2003 to be between 34,500 BOE/d to 35,500 BOE/d, depending on the
completion dates and ultimate production rates of the offshore wells currently
being completed.
Denbury's total debt as of September 30, 2003 was $329 million, consisting
of $225 million of subordinated debt and $104 million of bank debt, with $116
million undrawn on its bank borrowing base of $220 million. As of October 31,
2003, the Company's total debt was $325 million and is expected to be reduced to
$305 million upon closing of the anticipated sale of CO2 to Genesis pursuant to
a volumetric production payment. Closing of this transaction is expected within
the next two weeks. The Company expects to further reduce its debt during the
remainder of 2003, ending the year with an anticipated debt level of around $300
million, its previously stated target.
Gareth Roberts, Chief Executive Officer, said: "Although we did not
increase our production this quarter, we are pleased with our progress in other
key areas. We continue to add longer-life reserves in our CO2 operations to
replace the shorter-lived natural gas production that affects our production
rates. We have increased the amount of CO2 available for injection, resulting in
higher related oil production during the last few weeks, a trend we expect to
continue. The results of our drilling program offshore appears to be ahead of
expectations, with three more wells still scheduled to be drilled this year. We
should achieve our debt target this year through free cash flow and asset sales,
significantly lowering our leverage and providing us with financing flexibility
for the future. Looking forward to 2004, we plan to invest heavily in our CO2
operations, attempting to build additional deliverability and reserves for a
possible future expansion of our CO2 operations to other areas, most likely
Eastern Mississippi. This strategy will have the impact of limiting our
short-term production growth, but should benefit our long- term production
growth. Although our 2004 budget is not yet finalized, initial indications are
that, without assuming exploration success, our production could be lower in
2004 than 2003. However, we are confident that this strategy will build value
for our shareholders in the long- term. We continue to be enthusiastic about the
future."
Conference Call
The public is invited to listen to the Company's conference call set for
today, November 3, 2003, at 10:00 A.M. CDT. The call will be broadcast live over
the Internet at Denbury's web site: www. denbury.com. If you are unable to
participate during the live broadcast, the call will
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be archived on Denbury's web site for approximately 30 days and will also be
available for playback for one week by dialing 888-286-8010, passcode 80292379.
Financial and Statistical Data Tables
Following are financial highlights for the respective three and nine month
periods ended September 30, 2003 and September 30, 2002. All dollar amounts are
in U.S. dollars and production volumes and dollars are expressed on a net
revenue interest basis with gas volumes converted to equivalent barrels at 6:1.
THIRD QUARTER FINANCIAL HIGHLIGHTS
(Amounts in thousands of U.S. dollars, except per share and per unit data)
Three Months Ended
September 30,
--------------------------- Percentage
2003 2002 Change
----------- ------------- ---------------
Revenues:
Oil sales 44,863 42,372 + 6%
Gas sales 43,933 29,781 + 48%
CO2 sales 2,238 2,182 + 3%
Loss on settlements of derivative contracts (12,031) (218) NA
Interest and other income 387 409 - 5%
----------- ------------- ---------------
Total revenues 79,390 74,526 + 7%
----------- ------------- ---------------
Expenses:
Lease operating expenses 22,400 17,714 + 26%
Production taxes and marketing expense 3,761 2,969 + 27%
CO2 operating expenses 602 431 + 40%
General and administrative expenses 3,445 3,034 + 14%
Interest expense 5,358 6,860 - 22%
Depletion and depreciation 22,566 23,031 - 2%
Amortization of derivative contracts and other
non-cash hedging adjustments (1,441) (1,133) - 27%
----------- ------------- ---------------
Total expenses 56,691 52,906 + 7%
----------- ------------- ---------------
Income before income taxes 22,699 21,620 + 5%
Income tax provision (benefit)
Current income taxes (1,514) 20 NA
Deferred income taxes 9,064 8,141 + 11%
----------- ------------- ---------------
NET INCOME 15,149 13,459 + 13%
=========== ============= ===============
Net income per common share
Basic 0.28 0.25 + 12%
Diluted 0.27 0.25 + 8%
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Three Months Ended
September 30,
--------------------------- Percentage
2003 2002 Change
----------- ------------ ----------------
Weighted average common shares:
Basic 54,014 53,354 + 1%
Diluted 55,718 54,562 + 2%
Production (daily - net of royalties)
Oil (barrels) 18,051 18,930 - 5%
Gas (mcf) 90,393 99,452 - 9%
BOE (6:1) 33,116 35,506 - 7%
Unit sales price (including hedges)
Oil (per barrel) 24.60 24.18 + 2%
Gas (per mcf) 4.32 3.26 + 33%
Unit sales price (excluding hedges)
Oil (per barrel) 27.01 24.33 + 11%
Gas (per mcf) 5.28 3.25 + 62%
Non-GAAP Financial Measure: (1)
Adjusted or discretionary cash flow from operations
(non-GAAP measure) 45,611 44,177 + 3%
Net change in assets and liabilities relating to
operations 4,178 202 NA
------------ ------------- ----------------
Net cash flow from operations (GAAP measure) 49,789 44,379 + 12%
------------ ------------- ----------------
Oil & gas capital investments 39,253 77,418 - 49%
CO2 capital investments 2,635 5,459 - 52%
Proceeds from sales of oil and gas properties 1,173 - NA
Cash and cash equivalents 28,108 22,924 + 23%
Total assets 942,558 862,748 + 9%
Total debt (excluding discount) 329,000 375,000 - 12%
Total stockholders' equity 410,386 358,934 + 14%
BOE data (6:1)
Revenue 29.14 22.09 + 32%
Loss on settlements of derivative contracts (3.95) (0.07) NA
Lease operating expense (7.35) (5.43) + 35%
Production taxes and marketing expense (1.23) (0.91) + 35%
------------ ------------- ----------------
Production netback 16.61 15.68 + 6%
CO2 operating margin 0.54 0.54 -
General and administrative expense (1.13) (0.93) + 22%
Net cash interest expense (1.55) (1.77) - 12%
Current income taxes and other 0.50 - NA
Changes in assets and liabilities 1.37 0.06 NA
------------ ------------- ----------------
Cash flow from operations 16.34 13.58 + 20%
============ ============= ================
(1) See "Non-GAAP Measures" at the end of this report.
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NINE MONTH FINANCIAL HIGHLIGHTS
(Amounts in thousands of U.S. dollars, expect per share and per unit data)
Nine Months Ended
September 30,
--------------------------- Percentage
2003 2002 Change
----------- ------------- ---------------
Revenues:
Oil sales 140,998 107,608 + 31%
Gas sales 154,274 86,569 + 78%
CO2 sales 6,872 5,568 + 23%
Gain (loss) on settlements of derivative contracts (53,072) 2,430 NA
Interest and other income 989 1,251 - 21%
----------- ------------- ---------------
Total revenues 250,061 203,426 + 23%
----------- ------------- ---------------
Expenses:
Lease operating expenses 67,850 50,266 + 35%
Production taxes and marketing expense 11,124 8,880 + 25%
CO2 operating expenses 1,453 960 + 51%
General and administrative 10,612 9,544 + 11%
Interest expense 18,046 20,086 - 10%
Loss on early retirement of debt 17,629 - NA
Depletion and depreciation 69,249 70,162 - 1%
Amortization of derivative contracts and other
non-cash hedging adjustments (3,702) (3,226) - 15%
----------- ------------- ---------------
Total expenses 192,261 156,672 + 23%
----------- ------------- ---------------
Income before income taxes 57,800 46,754 + 24%
Income tax provision (benefit)
Current income taxes 123 (428) NA
Deferred income taxes 18,946 15,679 + 21%
----------- ------------- ---------------
Income before cumulative effect of a change in
accounting principle 38,731 31,503 + 23%
Cumulative effect on prior years of a change in
accounting principal, net of income tax expense of
$1,600 2,612 - NA
----------- ------------- ---------------
NET INCOME 41,343 31,503 + 31%
=========== ============= ===============
Net income per common share - basic:
Income before cumulative effect of a change in
accounting principle 0.72 0.59 + 22%
Cumulative effect of a change in accounting
principle 0.05 - NA
----------- ------------ ---------------
Net income per common share - basic 0.77 0.59 + 31%
=========== ============ ================
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Nine Months Ended
September 30,
--------------------------- Percentage
2003 2002 Change
----------- ------------- ---------------
Net income per common share - diluted:
Income before cumulative effect of a change in
accounting principle 0.70 0.58 + 21%
Cumulative effect of a change in accounting
principle 0.05 - NA
----------- ------------ ----------------
Net income per common share - diluted 0.75 0.58 + 29%
=========== ============ ================
Weighted average common shares:
Basic 53,824 53,170 + 1%
Diluted 55,375 54,193 + 2%
Production (daily - net of royalties)
Oil (barrels) 18,852 18,201 + 4%
Gas (mcf) 95,341 103,581 - 8%
BOE (6:1) 34,742 35,465 - 2%
Unit sales price (including hedges)
Oil (per barrel) 24.41 21.70 + 12%
Gas (per mcf) 4.48 3.14 + 43%
Unit sales price (excluding hedges)
Oil (per barrel) 27.40 21.66 + 27%
Gas (per mcf) 5.93 3.06 + 94%
Non-GAAP Financial Measure: (1)
Adjusted or discretionary cash flow from operations
(non-GAAP measure) 141,966 116,124 + 22%
Net change in assets and liabilities relating to
operations 3,874 (13,141) NA
------------ ------------- ----------------
Cash flow from operations (GAAP measure) 145,840 102,983 + 42%
------------ ------------- ----------------
Oil & gas capital investments 119,586 129,336 - 8%
CO2 capital investments 16,008 11,393 + 41%
Proceeds from sales of oil and gas properties 29,328 4,552 NA
BOE data (6:1)
Revenue 31.13 20.06 + 55%
Gain (loss) on settlements of derivative contracts (5.60) 0.25 NA
Lease operating expense (7.15) (5.19) + 38%
Production taxes and marketing expense (1.17) (0.92) + 27%
------------ ------------- ----------------
Production netback 17.21 14.20 + 21%
CO2 operating margin 0.57 0.48 + 19%
General and administrative expense (1.12) (0.99) + 13%
Net cash interest expense (1.69) (1.75) - 3%
Current income taxes and other - 0.05 NA
Changes in assets and liabilities 0.40 (1.35) NA
------------ ------------- ----------------
Cash flow from operations 15.37 10.64 + 44%
============ ============= ================
(1) See "Non-GAAP Measures" at the end of this report.
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Non-GAAP Measures
Adjusted cash flow from operations is a non-GAAP measure that represents
cash flow provided by operations before changes in assets and liabilities, as
summarized from our Consolidated Statements of Cash Flows. Adjusted cash flow
from operations measures the cash flow earned or incurred from operating
activities without regard to the collection or payment of associated receivables
or payables. Management believes that this is important to consider separately,
as they believe it can often be a better way to discuss changes in operating
trends in Denbury's business caused by changes in production, prices, operating
costs, and so forth, without regard to whether the earned or incurred item was
collected or paid during that period. For a further discussion, see
"Management's Discussion and Analysis of Financial Condition and Results of
Operations - Operating Results" in the Company's latest Form 10-Q.
Denbury Resources Inc. (www.denbury.com) is a growing independent oil and
gas company. The Company is the largest oil and natural gas operator in
Mississippi, holds key operating acreage onshore Louisiana and has a growing
presence in the offshore Gulf of Mexico areas. The Company increases the value
of acquired properties in its core areas through a combination of exploitation
drilling and proven engineering extraction practices.
This press release, other than historical financial information, contains
forward-looking statements that involve risks such as those involved in drilling
activity and those due to price volatility, and uncertainties as to drilling
results, production levels, commodity prices, and financial results as detailed
in the Company's filings with the Securities and Exchange Commission, including
its reports on Form 10-K and 10-Q. These reports are incorporated by reference
as though fully set forth herein. These statements are based on assumptions
concerning commodity prices, existing market conditions, scheduling, drilling
and completion results and costs and engineering assumptions that management
believes are reasonable based on currently available information; however,
management's assumptions and the Company's future performance are both subject
to a wide range of business risks, and there is no assurance that these goals
and projections can or will be met. Actual results may vary materially.
For further information contact:
Gareth Roberts, President and CEO, 972-673-2000
Phil Rykhoek, Chief Financial Officer, 972-673-2000
www.denbury.com
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