EXHIBIT 99.1
DENBURY RESOURCES INC.
P R E S S R E L E A S E
Denbury Resources Announces Second Quarter 2003 Results
Provides Operational Update
News Release
Released at 7:30 AM CDT
DALLAS - July 31, 2003 - Denbury Resources Inc. (NYSE symbol: DNR)
("Denbury" or the "Company") today announced its second quarter 2003 financial
and operating results. The Company posted earnings for the quarter of $5.1
million, or $0.10 per common share, as compared to earnings of $13.5 million, or
$0.25 per common share for the second quarter of 2002. For purposes of period to
period comparability, if you exclude the $17.6 million pre-tax ($11.5 million
after tax) non-recurring charge to earnings on early retirement of debt in the
second quarter of 2003 relating to the Company's refinancing of its subordinated
debt, earnings for the second quarter of 2003 would have been $16.6 million or
$0.31 per common share.
Adjusted cash flow from operations for the quarter was $49.0 million, as
compared to $43.4 million during the second quarter of 2002. (Please see the
accompanying schedules for a reconciliation of adjusted cash flow, a non-GAAP
measure, to net cash flow provided by operations, the GAAP measure). Net cash
flow provided by operating activities, as defined by generally accepted
accounting principles (GAAP), totaled $55.0 million during the second quarter of
2003, compared to $46.6 million during the second quarter of 2002.
Second Quarter 2003 Financial Results
- -------------------------------------
Denbury's second quarter 2003 average daily production of 35,050 BOE/d was
1% lower than the 35,526 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 temporary CO2 curtailments (see review of
operations below). Oil production from the Company's tertiary recovery
operations averaged 4,522 BOE/d during the second quarter, a 4% increase over
the level of this production in the first quarter of 2003, in spite of a nine
day curtailment of CO2 production as a result of a CO2 pipeline leak in early
May.
Commodity prices were higher in the second quarter of 2003 as compared to
prices in the second quarter of the prior year. NYMEX oil prices averaged almost
$29.00 per Bbl and natural gas prices averaged almost $5.50 per Mcf in the
second quarter of 2003, as compared to NYMEX averages of around $26.25 per Bbl
and $3.40 per Mcf in the second quarter of 2002. On a weighted average price per
BOE received net to the Company, prices were $7.71 per BOE and $13.05 per BOE
higher (excluding hedges) in the second quarter and first half of 2003,
respectively, than in the comparable periods of 2002. However, approximately
$4.19 per BOE and $6.37 per BOE of this increase was paid out on the Company's
oil and natural gas hedges in the current quarter and first half of 2003,
respectively, as compared to minor hedging cash receipts in the 2002 periods. As
a result of the hedging payments, the net realized per BOE price increase
received by the Company between the respective second quarters was reduced to
$3.52 per BOE and to approximately $6.27 per BOE between the respective first
six months.
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Partially offsetting the higher revenues were increases in expenses,
particularly operating expenses and loss on early extinguishment of debt. Lease
operating expenses increased from $5.30 per BOE in the second quarter of 2002 to
$7.23 per BOE in the second quarter of 2003. The primary reason for the increase
was a mechanical failure in two Louisiana gas wells late in the first quarter of
2003, which continued into the second quarter, at a total repair cost of
approximately $850,000 in the first quarter and $2.0 million in the second
quarter. 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. The
Company anticipates that its lease operating expenses on a per BOE basis will
decrease later this year, assuming normal operating parameters.
Late in the first quarter, the Company issued $225 million of 7.5%
subordinated notes due 2013 and called its existing $200 million principal
amount of 9% subordinated notes due 2008. The old notes were retired on April
16th and the refinancing is expected to save the Company approximately $2.6
million per year in interest expense. As a result of the refinancing, the
Company recorded a $17.6 million pre-tax charge ($11.5 million after tax) in the
second quarter of 2003 relating to the call premium paid to retire the old notes
and the write-off of the remaining debt issue costs and unamortized discount on
the old notes. The refinancing was the primary reason for the reduction in
interest expense in the second quarter of 2003, as compared to interest expense
in the comparable quarter in 2002.
General and administrative expenses increased slightly, averaging $1.06 per
BOE in the second quarter of 2003, up from $1.02 per BOE in the comparable
quarter of 2002. The increase primarily relates to incremental expenses
associated with the requirements of the Sarbanes-Oxley Act. The sale of stock by
the Texas Pacific Group early in 2003, higher expenses relating to year-end
reporting than in the prior year for items such as engineering fees and audit
fees, and an overall increase in personnel and associated expenses also
contributed to the six month comparative increase.
Operational Update
- ------------------
The Company recently drilled an exploratory discovery well at North Lirette
Field, the Exxon Fee A1, that is in the process of being completed. The Company
estimates that this initial discovery well developed between 10 to 15 Bcf of
reserves, net to the Company, with an additional 10 to 15 Bcf of net potential
reserves to be evaluated by a second well in this area that is expected to be
drilled and completed early in the fourth quarter. The Company anticipates that
each well could produce as much as 7.5 MMcf/d, net to the Company. Production
from the initial well is expected to commence within the next three weeks. The
preliminary estimates of reserves and production from this discovery more than
make up for the less than expected exploration and development results during
the first half of the year, a significant factor in the second quarter 1%
production decrease from the prior year's quarter.
During July, the Company completed its third CO2 well drilled during the
last twelve months, all of which are producing, or capable of producing, at
levels almost double the originally forecasted rates. Due to these positive CO2
production rates, the Company has accelerated the timing of a scheduled
expansion shutdown of its CO2 facility from early 2004 to this last week of
July. This shutdown is necessary in order to upgrade equipment at the Jackson
Dome treating facility, expected to increase capacity of the facility from
approximately 200 MMcf/d to approximately 300 MMcf/d. However, due to the
facility shutdown, which started on
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July 28th and is expected to last approximately one week, and the resulting
temporary curtailment of CO2 injections, the anticipated third quarter 2003 oil
production from the Company's tertiary operations is not expected to increase
over the second quarter levels. Oil production levels from these fields are
expected to resume their growth in the fourth quarter after the additional CO2
production volumes become available for injection following the facility
upgrade.
Five offshore wells scheduled for the first seven months of 2003 have been
delayed while waiting for partner approvals and clearance of other logistical
issues. The Company has up to six wells scheduled for the last five months of
2003, although due to the timing, these wells will not have a meaningful
production impact in 2003. The installation of production facilities at North
Padre Island, the Company's year-end 2002 discovery, is still on schedule, and
this field is expected to commence production during the fourth quarter.
2003 Outlook
- ------------
Denbury's 2003 development and exploration budget is currently set at $143
million, including approximately $8 million of projects carried over from 2002,
but excluding any acquisitions. During the first half of 2003, the Company made
several minor acquisitions, primarily consisting of incremental interests in
existing properties, at an aggregate cost of approximately $11.6 million.
The Company has revised its average daily production forecast for 2003 to a
range of 35,000 BOE/d to 36,000 BOE/d, depending on the results and ultimate
timing of wells drilled in the second half of the year. This is a reduction from
its previously announced annual production target of 37,500 BOE/d, caused by the
timing delays discussed above and less than expected exploration and development
results during the first half of the year (see operational update above).
Overall, third quarter average daily production is expected to be slightly less
than second quarter production, although as previously mentioned, oil production
from tertiary operations is expected to be approximately the same. Production
increases are expected to resume in the fourth quarter. Subsequent to May, the
Company has not processed natural gas liquids, but has chosen to sell them in
the natural gas stream due to the relative natural gas and liquid prices, and
does not anticipate doing so in the near term. This decision, made monthly, has
minimal effect on total revenue but does affect production volumes. The Company
has excluded any natural gas liquid production from this revised forecast, which
impacts production by 300 to 400 BOE/d.
Denbury's total debt as of June 30, 2003 is approximately $335 million,
with $110 million undrawn on its bank borrowing base of $220 million. Even
though the Company added approximately $15 million of additional debt as part of
its recent subordinated debt refinancing, the Company still expects to reduce
its debt during 2003 to its target of $300 million, based on anticipated cash
flow computed using the current commodity prices.
Gareth Roberts, Chief Executive Officer, said: "We are pleased with our
recent exploration success at North Lirette Field. Although we have additional
testing to do on this play, it appears to be significant enough to make our
entire 2003 exploration program a success, with five additional exploratory
wells elsewhere still scheduled to be drilled during the remainder of 2003. At
Jackson Dome, our CO2 wells are performing better than anticipated, and with the
facility upgrade that is almost completed, we will be capable of producing
approximately 220 MMcf/d of CO2, almost double our CO2 production rate a year
earlier. However, with the temporary curtailments of CO2 necessary to upgrade
our facilities to deliver CO2 at this rate, our oil production response will
effectively be delayed about one quarter. Although we needed to
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lower our production forecast for the next two quarters, we are confident that
this is primarily just a timing issue. The Company is gradually working toward
our debt target of $300 million and still anticipates achieving that goal by
year-end. Looking forward to 2004, we are fortunate in that we have a
significant inventory of internal projects to choose from, the cost of which
significantly exceeds our expected cash flow available for these projects. The
hardest part will be choosing which projects to invest in during 2004. 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, July 31, 2003, at 10:00 A.M. CDT. The call will be broadcast live over
the Internet at our web site: www. denbury.com. If you are unable to participate
during the live broadcast, the call will be archived on our web site for
approximately 30 days and will also be available for playback for one week by
dialing 888-286-8010, passcode 58276745.
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Financial and Statistical Data Tables
- -------------------------------------
Following are financial highlights for the respective three and six month
periods ended June 30, 2003 and June 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.
SECOND QUARTER FINANCIAL HIGHLIGHTS
(Amounts in thousands of U.S. dollars, except per share and per unit data)
Three Months Ended
June 30,
--------------------------- Percentage
2003 2002 Change
----------- ------------- ---------------
Revenues:
Oil sales 43,922 37,404 + 17%
Gas sales 50,830 33,710 + 51%
CO2 sales 2,445 1,896 + 29%
Gain (loss) on settlements of derivative contracts (13,356) 12 N/A
Interest and other income 382 431 - 11%
----------- ------------- ---------------
Total revenues 84,223 73,453 + 15%
----------- ------------- ---------------
Expenses:
Lease operating expenses 23,048 17,124 + 35%
Production taxes and marketing expense 3,467 3,297 + 5%
CO2 operating expenses 534 362 + 48%
General and administrative expenses 3,376 3,294 + 2%
Interest expense 6,227 6,572 - 5%
Loss on early retirement of debt 17,629 - N/A
Depletion and depreciation 23,130 24,205 - 4%
Amortization of derivative contracts and other
non-cash hedging adjustments (751) (1,012) - 26%
----------- ------------- ---------------
Total expenses 76,660 53,842 + 42%
----------- ------------- ---------------
Income before income taxes 7,563 19,611 - 61%
Income tax provision (benefit)
Current income taxes (1,093) 33 N/A
Deferred income taxes 3,527 6,080 - 42%
----------- ------------- ---------------
NET INCOME 5,129 13,498 - 62%
=========== ============= ===============
Net income per common share
Basic 0.10 0.25 - 60%
Diluted 0.09 0.25 - 64%
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Three Months Ended
June 30,
--------------------------- Percentage
2003 2002 Change
----------- ------------ ----------------
Weighted average common shares:
Basic 53,815 53,158 + 1%
Diluted 55,337 54,301 + 2%
Production (daily - net of royalties)
Oil (barrels) 18,957 17,921 + 6%
Gas (mcf) 96,558 105,634 - 9%
BOE (6:1) 35,050 35,526 - 1%
Unit sales price (including hedges)
Oil (per barrel) 23.93 22.94 + 4%
Gas (per mcf) 4.56 3.51 + 30%
Unit sales price (excluding hedges)
Oil (per barrel) 25.46 22.94 + 11%
Gas (per mcf) 5.78 3.51 + 65%
Non-GAAP Financial Measure: (1)
Adjusted or discretionary cash flow from operations
(non-GAAP measure) 48,989 43,423 + 13%
Net change in assets and liabilities relating to
operations 6,019 3,149 + 91%
------------ ------------- ---------------
Net cash flow from operations (GAAP) 55,008 46,572 + 18%
------------ ------------- ---------------
Oil & gas capital investments 43,973 25,642 + 71%
CO2 capital investments 6,470 5,599 + 16%
Proceeds from sales of oil and gas properties 1,788 4,552 - 61%
Cash and cash equivalents 19,348 20,175 - 4%
Total assets 944,685 780,352 + 21%
Total debt (excluding discount) 335,000 336,000 - 0%
Total stockholders' equity 381,213 351,018 + 9%
BOE data (6:1)
Revenue 29.71 22.00 + 35%
Gain (loss) on settlements of derivative contracts (4.19) - N/A
Lease operating expense (7.23) (5.30) + 36%
Production taxes and marketing expense (1.08) (1.02) + 6%
------------ ------------- ----------------
Production netback 17.21 15.68 + 10%
CO2 operating margin 0.60 0.47 + 28%
General and administrative expense (1.06) (1.02) + 4%
Net cash interest expense (1.75) (1.70) + 3%
Current income taxes and other 0.36 - N/A
Changes in assets and liabilities 1.89 0.98 + 93%
------------ ------------- ----------------
Cash flow from operations 17.25 14.41 + 20%
============ ============= ================
(1) See "Non-GAAP Measure" at the end of this report.
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SIX MONTH FINANCIAL HIGHLIGHTS
(Amounts in thousands of U.S. dollars, expect per share and per unit data)
Six Months Ended
June 30,
--------------------------- Percentage
2003 2002 Change
----------- ------------- --------------
Revenues:
Oil sales 96,135 65,237 + 47%
Gas sales 110,341 56,787 + 94%
CO2 sales 4,634 3,386 + 37%
Gain (loss) on settlements of derivative contracts (41,041) 2,648 N/A
Interest and other income 602 842 - 29%
----------- ------------- --------------
Total revenues 170,671 128,900 + 32%
----------- ------------- --------------
Expenses:
Lease operating expenses 45,450 32,552 + 40%
Production taxes and marketing expense 7,363 5,911 + 25%
CO2 operating expenses 851 529 + 61%
General and administrative 7,167 6,510 + 10%
Interest expense 12,688 13,226 - 4%
Loss on early retirement of debt 17,629 - N/A
Depletion and depreciation 46,683 47,131 - 1%
Amortization of derivative contracts and other
non-cash hedging adjustments (2,261) (2,093) + 8%
----------- ------------- --------------
Total expenses 135,570 103,766 + 31%
----------- ------------- --------------
Income before income taxes 35,101 25,134 + 40%
Income tax provision (benefit)
Current income taxes 1,637 (448) N/A
Deferred income taxes 9,882 7,538 + 31%
----------- ------------- --------------
Income before cumulative effect of a change in
accounting principle 23,582 18,044 + 31%
Cumulative effect on prior years of a change in
accounting principal, net of income tax expense of
$1,600 2,612 - N/A
----------- ------------- --------------
NET INCOME 26,194 18,044 + 45%
=========== ============= ==============
Net income per common share - basic:
Income before cumulative effect of a change in
accounting principle 0.44 0.34 + 29%
Cumulative effect of a change in accounting
principle 0.05 - N/A
----------- ------------ ---------------
Net income per common share - basic 0.49 0.34 + 44%
=========== ============ ===============
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Six Months Ended
June 30,
--------------------------- Percentage
2003 2002 Change
----------- ------------ ----------------
Net income per common share - diluted:
Income before cumulative effect of a change in
accounting principle 0.42 0.33 + 30%
Cumulative effect of a change in accounting
principle 0.05 - N/A
----------- ------------ ---------------
Net income per common share - diluted 0.47 0.33 + 45%
=========== ============ ===============
Weighted average common shares:
Basic 53,728 53,077 + 1%
Diluted 55,186 54,024 + 2%
Production (daily - net of royalties)
Oil (barrels) 19,259 17,831 + 8%
Gas (mcf) 97,857 105,680 - 7%
BOE (6:1) 35,569 35,444 - 0%
Unit sales price (including hedges)
Oil (per barrel) 24.32 20.36 + 19%
Gas (per mcf) 4.55 3.08 + 48%
Unit sales price (excluding hedges)
Oil (per barrel) 27.58 20.21 + 36%
Gas (per mcf) 6.23 2.97 + 110%
Non-GAAP Financial Measure: (1)
Adjusted or discretionary cash flow from operations
(non-GAAP measure) 96,354 71,947 + 34%
Net change in assets and liabilities relating to
operations (5,837) (13,343) - 56%
----------- ------------ ---------------
Cash flow from operations (GAAP) 90,517 58,604 + 54%
----------- ------------ --------------
Oil & gas capital investments 80,333 51,918 + 55%
CO2 capital investments 13,373 5,934 + 125%
Proceeds from sales of oil and gas properties 28,154 4,552 + 518%
BOE data (6:1)
Revenue 32.07 19.02 + 69%
Gain (loss) on settlements of derivative contracts (6.37) 0.41 N/A
Lease operating expense (7.06) (5.07) + 39%
Production taxes and marketing expense (1.15) (0.92) + 25%
----------- ------------ ---------------
Production netback 17.49 13.44 + 30%
CO2 operating margin 0.59 0.45 + 31%
General and administrative expense (1.11) (1.01) + 10%
Net cash interest expense (1.76) (1.73) + 2%
Current income taxes and other (0.24) 0.06 N/A
Changes in assets and liabilities (0.91) (2.08) - 56%
----------- ------------ ---------------
Cash flow from operations 14.06 9.13 + 54%
============ ============== ===============
(1) See "Non-GAAP Measure" at the end of this report.
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Non-GAAP Measure
- ----------------
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. We believe that this is important to consider separately, as we
believe it can often be a better way to discuss changes in operating trends in
our 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 our 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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