EXHIBIT 13
PAGE 2, PAGES 8 THROUGH 11 INCLUSIVE, PAGE 14, PAGES 16 THROUGH 17 INCLUSIVE,
PAGES 19 THROUGH 20 INCLUSIVE, PAGES 22 THROUGH 25 INCLUSIVE AND PAGES 27
THROUGH 70, INCLUSIVE, OF THE COMPANY'S ANNUAL REPORT TO SHAREHOLDERS FOR THE
YEAR ENDED DECEMBER 31, 2002, BUT EXCLUDING PHOTOGRAPHS AND ILLUSTRATIONS SET
FORTH ON THESE PAGES, NONE OF WHICH SUPPLEMENTS THE TEXT AND WHICH ARE NOT
OTHERWISE REQUIRED TO BE DISCLOSED IN THIS ANNUAL REPORT ON FORM 10-K.
EX 13-1
Financial Highlights
YEAR ENDED DECEMBER 31,
---------------------------------------------------------- ----------
AVERAGE
ANNUAL
AMOUNTS IN THOUSANDS OF U.S. DOLLARS UNLESS NOTED 2002 2001(1) 2000 1999 1998 GROWTH(2)
- ------------------------------------------------------------------------------------------------------------- ---------
PRODUCTION (DAILY)
Oil (Bbls) 18,833 16,978 15,219 12,090 13,603 8%
Natural Gas (Mcf) 100,443 85,238 37,078 27,948 36,605 29%
BOE (6:1) 35,573 31,185 21,399 16,748 19,704 16%
REVENUES 285,152 285,111 181,651 82,990 83,506 36%
UNIT SALES PRICE (excluding hedges)
Oil (per Bbl) 22.36 21.34 25.89 15.03 10.29 21%
Natural Gas (per Mcf) 3.31 4.12 4.45 2.42 2.31 9%
UNIT SALES PRICE (including hedges)
Oil (per Bbl) 22.27 21.65 23.50 13.08 10.29 21%
Natural Gas (per Mcf) 3.35 4.66 3.57 2.34 2.32 10%
CASH FLOW FROM OPERATIONS 159,600 185,047 95,972 41,200 20,285 67%
NET INCOME (LOSS) (3) 46,795 56,550 142,227 4,614 (287,145) --
AVERAGE COMMON SHARES OUTSTANDING
Basic 53,243 49,325 45,823 39,928 25,926 20%
Diluted 54,365 50,361 46,352 39,987 25,926 20%
NET INCOME (LOSS) PER SHARE
Basic 0.88 1.15 3.10 0.12 (11.08) --
Diluted 0.86 1.12 3.07 0.12 (11.08) --
OIL AND GAS CAPITAL INVESTMENTS 155,637 327,175 134,021 54,967 102,652 11%
CO2 CAPITAL INVESTMENTS 16,445 45,555 - - - --
TOTAL ASSETS 895,292 789,988 457,379 252,566 212,859 43%
LONG-TERM LIABILITIES 432,616 360,882 202,428 154,976 226,436 18%
STOCKHOLDERS' EQUITY (DEFICIT) (4) 366,797 349,168 216,165 72,428 (32,265) --
PROVED RESERVES
Oil (MBbls) 97,203 76,490 70,667 51,832 28,250 36%
Natural Gas (MMcf) 200,947 198,277 100,550 50,438 48,803 42%
MBOE (6:1) 130,694 109,536 87,425 60,238 36,383 38%
Discounted future cash flow - 10% 1,426,220 574,328 1,158,969 462,870 115,019 88%
PER BOE DATA (6:1)
Oil and natural gas revenues 21.17 22.88 26.13 14.88 11.36 17%
Gain (loss) on settlements of derivative contracts 0.07 1.64 (3.23) (1.54) 0.02 37%
Lease operating expenses (5.48) (4.84) (4.94) (4.25) (3.49) 12%
Production taxes and marketing expenses (0.92) (0.96) (1.02) (0.60) (0.56) 13%
- ------------------------------------------------------------------------------------------------------------------------
Production netback 14.84 18.72 16.94 8.49 7.33 19%
CO2 operating margin 0.48 0.38 - - - --
General and administrative expense (0.96) (0.89) (1.09) (1.21) (1.02) -2%
Net cash interest expense (1.73) (1.74) (1.54) (2.22) (2.13) -5%
Current income taxes and other 0.04 (0.06) (0.07) 0.11 - --
Changes in assets and liabilities (0.38) (0.15) (1.99) 1.57 (1.36) --
- ------------------------------------------------------------------------------------------------------------------------
CASH FLOW FROM OPERATIONS 12.29 16.26 12.25 6.74 2.82 44%
- ------------------------------------------------------------------------------------------------------------------------
(1) We acquired Matrix Oil and Gas, Inc. in July 2001. See Note 2 to the
Consolidated Financial Statements.
(2) Four-year compounded annual growth rate computed using 1998 as a base year.
(3) In 2000, we recorded a deferred income tax benefit of $67.9 million related
to the reversal of the valuation allowance on our net deferred tax assets.
In 1998, we recorded a $280.0 million writedown of our oil and natural gas
properties under the full cost ceiling test.
(4) We have never paid any dividends on our common stock.
Reporting Format
Unless otherwise noted, the disclosures in this report have (i) production
volumes expressed on a net revenue interest basis, and (ii) gas volumes
converted to equivalent barrels at 6:1.
-2-
SELECTED OPERATING DATA
OIL AND GAS RESERVES
Estimates of our net proved oil and natural gas reserves as of December 31,
2002, 2001 and 2000 have been prepared by DeGolyer and MacNaughton, independent
petroleum engineers located in Dallas, Texas. The reserves were prepared using
constant prices and costs in accordance with the guidelines of the Securities
and Exchange Commission ("SEC"), based on the prices received on a
field-by-field basis as of December 31 of each year. The reserves do not include
any value for probable or possible reserves that may exist, nor do they include
any value for undeveloped acreage. The reserve estimates represent our net
revenue interest in our properties.
Our proved non-producing reserves relate primarily to additional potential from
producing zones that are currently behind pipe or are associated with
waterfloods and tertiary recovery (CO2) floods. Since a majority of our
properties are in areas with multiple pay zones or are fields with secondary or
tertiary recovery operations, most of our properties have both proved producing
and proved non-producing reserves.
Reserves associated with our CO2 operations in West Mississippi and our
Heidelberg waterfloods in East Mississippi account for approximately 84% of our
proved undeveloped oil reserves. We consider these reserves to be lower risk
than proved undeveloped reserves that require drilling at locations offsetting
existing production because the reservoir has already been defined by wells that
produced during primary production. All of our reserves associated with
secondary recovery and tertiary recovery operations are in fields and reservoirs
that produced substantial volumes of oil under primary production. The main
reason they are classified as undeveloped is because they require significant
additional capital to drill wells or install facilities in order to produce the
reserves, or they are required to demonstrate a production response after the
water or CO2 is injected before their classification from proved undeveloped can
be changed. The remaining 16% of our undeveloped oil reserves are located well
within the currently producing regions of our fields, many of which are up-dip
to existing production.
Our proved undeveloped natural gas reserves are not as concentrated as our oil
reserves. Approximately 62% of our proved undeveloped natural gas reserves are
on offshore properties located in six fields, from our latest discovery at North
Padre A-9, offshore Texas, to West Delta 27 located offshore eastern Louisiana.
These natural gas reserves are confirmed by both sub- surface geology and 3D
seismic that covers these areas. An additional 15% of our proved undeveloped
natural gas reserves are located in Heidelberg Field where we continue to have
success in-fill drilling the Selma Chalk formation. The remaining significant
undeveloped natural gas reserves are in our Thornwell/Lakeside and Newark, East
(Barnett Shale) areas. In Thornwell/Lakeside our undeveloped reserves are
primarily associated
-8-
with the Bol Perc reservoir where we drilled and completed one additional well
during 2002, bringing our total number of successful Bol Perc wells to seven
without a dry hole. The Newark, East (Barnett Shale) field is a new and growing
area for us. We have now drilled nine wells that have confirmed the presence of
commercial gas reserves in this part of the field. We plan to drill an
additional six wells during 2003 and assuming gas prices remain strong, we are
planning larger development programs in this area in future years. We plan to
develop most of our proved undeveloped natural gas reserves during 2003.
December 31,
-------------------------------------------
2002 2001 2000
------------ ------------ ------------
ESTIMATED PROVED RESERVES:
Oil (MBbls)................................................ 97,203 76,490 70,667
Natural gas (MMcf)......................................... 200,947 198,277 100,550
Oil equivalent (MBOE)...................................... 130,694 109,536 87,425
PERCENTAGE OF TOTAL MBOE:
Proved producing........................................... 43% 53% 57%
Proved non-producing....................................... 23% 23% 18%
Proved undeveloped......................................... 34% 24% 25%
REPRESENTATIVE OIL AND NATURAL GAS PRICES: (1)
Oil - NYMEX................................................$ 31.20 $ 19.84 $ 26.80
Natural gas - NYMEX Henry Hub.............................. 4.79 2.57 9.78
PRESENT VALUES:(2)
Discounted estimated future net cash flow before
income taxes ("PV10 Value") (thousands)................$ 1,426,220 $ 574,328 $ 1,158,969
Standardized measure of discounted estimated future net
cash flow after income taxes (thousands)...............$ 1,028,976 $ 505,795 $ 841,299
- ---------------
(1) The oil prices as of each respective year-end were based on NYMEX prices
per Bbl and NYMEX Henry Hub ("NYMEX") prices per MMBtu, with these
representative prices adjusted by field to arrive at the appropriate
corporate net price.
(2) Determined based on year-end unescalated prices and costs in accordance
with the guidelines of the SEC, discounted at 10% per annum.
-9-
FIELD SUMMARIES
Denbury operates in four primary core areas, Louisiana, offshore Gulf of Mexico,
Eastern Mississippi and Western Mississippi. Our 15 largest fields constitute
approximately 80% of our total proved reserves on a BOE basis and 76% on a PV10
Value basis. Within these 15 fields we own an average 88% working interest and
operate all of the fields. The concentration of value in a relatively small
number of fields allows us to benefit substantially from any operating cost
reductions or production enhancements we achieve and allows us to effectively
manage the properties from our three primary field offices in Houma and
Covington, Louisiana, and Laurel, Mississippi.
2002
PROVED RESERVES AS OF DECEMBER 31, 2002 (1) AVERAGE DAILY PRODUCTION
------------------------------------------------------------- ------------------------
NATURAL AVERAGE NET
OIL NATURAL GAS MBOE'S BOE PV10 VALUE OIL GAS REVENUE
(MBBLS) (MMcf) (000's) % OF TOTAL ($ 000's) (Bbls/d) (Mcf/d) INTEREST(2)
- ------------------------------------------------------------------------------------------------------------------------------------
MISSISSIPPI - CO2 FLOODS
Mallalieu........................ 10,639 - 10,639 8.1% 108,518 568 - 80.9%
Little Creek..................... 7,541 - 7,541 5.8% 120,883 3,393 - 82.5%
McComb........................... 8,293 - 8,293 6.3% 53,633 1 - 82.5%
Other Mississippi CO2 floods..... 1,397 - 1,397 1.1% 18,159 8 - 82.2%
---------- --------- --------- ---------- ----------- -------- --------- ----------
Total Mississippi - CO2 floods 27,870 - 27,870 21.3% 301,193 3,970 - 81.9%
---------- ---------- --------- ---------- ----------- -------- --------- ----------
OFFSHORE GULF OF MEXICO
W.Delta 27....................... 929 12,278 2,975 2.3% 49,307 350 9,132 58.9%
South Marsh Island 48............ 172 22,609 3,940 3.0% 67,307 65 7,379 83.3%
Brazos A-22...................... 88 11,174 1,950 1.5% 21,081 11 1,695 35.7%
N. Padre A-9..................... 11 10,965 1,838 1.4% 26,067 - - 41.5%
Other offshore................... 84 34,099 5,768 4.4% 107,728 177 38,027 28.0%
---------- ---------- --------- ---------- ----------- -------- --------- ----------
Total offshore................ 1,284 91,125 16,471 12.6% 271,490 603 56,233 40.9%
---------- ---------- --------- ---------- ----------- -------- --------- ----------
OTHER MISSISSIPPI - NON-CO2
Heidelberg...................... 37,363 38,518 43,783 33.5% 327,308 6,294 7,114 78.7%
Eucutta......................... 4,978 - 4,978 3.8% 46,339 1,441 31 67.8%
King Bee........................ 3,536 - 3,536 2.7% 26,894 694 - 78.7%
Brookhaven (3) ................. 2,086 - 2,086 1.6% 28,475 172 - 78.7%
Laurel (3)...................... 7,380 - 7,380 5.6% 69,450 552 - 73.9%
Other Mississippi............... 10,250 2,656 10,693 8.2% 104,865 2,828 1,237 62.2%
---------- ---------- --------- ---------- ----------- -------- --------- ----------
Total Other Mississippi...... 65,593 41,174 72,456 55.4% 603,331 11,981 8,382 74.5%
---------- ---------- --------- ---------- ----------- -------- --------- ----------
LOUISIANA
Lirette......................... 349 13,403 2,583 2.0% 58,572 351 7,581 56.2%
Thornwell....................... 595 9,865 2,239 1.7% 51,231 1,074 17,017 52.6%
S.Chauvin....................... 369 10,397 2,102 1.6% 34,482 177 2,832 40.4%
Other Louisiana................. 1,141 25,611 5,409 4.1% 93,545 599 7,664 27.8%
---------- ---------- --------- ---------- ----------- -------- --------- ----------
Total Louisiana.............. 2,454 59,276 12,333 9.4% 237,830 2,201 35,094 36.7%
---------- ---------- --------- ---------- ----------- -------- --------- ----------
OTHER.............................. 2 9,372 1,564 1.3% 12,376 78 734 68.9%
---------- ---------- --------- ---------- ----------- -------- --------- ----------
COMPANY TOTAL...................... 97,203 200,947 130,694 100.0% 1,426,220 18,833 100,443 63.0%
========== ========== ========= ========== =========== ======== ========= ==========
(1) The reserves were prepared using constant prices and costs in accordance
with the guidelines of the SEC based on the prices received on a
field-by-field basis as of December 31, 2002. The prices at that date were
a NYMEX oil price of $31.20 per Bbl adjusted by field and a NYMEX natural
gas price of $4.79 per MMBtu, also adjusted by field.
(2) Includes only productive wells in which the Company has a working interest
as of December 31, 2002.
(3) These fields were acquired during 2002. The average production during the
period they were owned by the Company was 515 Bbls/d at Brookhaven and
1,651 Bbls/d at Laurel. Laurel Field was sold in February 2003.
-10-
OIL AND GAS ACREAGE
The following table sets forth Denbury's acreage position at December 31,
2002:
DEVELOPED UNDEVELOPED
---------------------------------- ---------------------------------
GROSS NET GROSS NET
-------------- --------------- --------------- -------------
Louisiana.................... 24,539 15,611 31,062 19,852
Mississippi.................. 84,740 75,497 77,864 53,253
Offshore Gulf Coast.......... 116,541 63,090 52,820 52,820
Texas........................ 3,919 3,563 19,828 16,859
-------------- --------------- --------------- -------------
Total............ 229,739 157,761 181,574 142,784
============== =============== =============== =============
PRODUCTIVE WELLS
This table sets forth our gross and net productive oil and natural gas
wells at December 31, 2002:
PRODUCING NATURAL
PRODUCING OIL WELLS GAS WELLS TOTAL
--------------------------- --------------------------- ----------------------------
GROSS NET GROSS NET GROSS NET
----------- ---------- ----------- ----------- ----------- -----------
Louisiana.................. 30 12.1 55 22.4 85 34.5
Mississippi................ 460 350.3 76 49.9 536 400.2
Offshore Gulf Coast........ 3 1.7 76 31.0 85 35.0
Texas...................... - - 10 7.1 10 7.1
----------- ---------- ----------- ----------- ----------- -----------
Total............... 493 364.1 217 110.4 716 476.8
=========== ========== =========== =========== =========== ===========
DRILLING ACTIVITY
The following table sets forth the results of our drilling activities over
the last three years:
YEAR ENDED DECEMBER 31,
--------------------------------------------------------------
2002 2001 2000
------------------- ------------------ -------------------
GROSS NET GROSS NET GROSS NET
-------- -------- -------- -------- -------- --------
EXPLORATORY WELLS: (1)
Productive (2)........................ 7 3.7 15 8.2 3 1.1
Nonproductive (3)..................... 4 2.5 3 1.2 1 0.2
DEVELOPMENT WELLS: (1)
Productive (2)........................ 33 22.7 60 37.9 38 26.5
Nonproductive (3)(4).................. 2 1.4 - - 2 0.2
-------- -------- -------- -------- -------- --------
Total........................... 46 30.3 78 47.3 44 28.0
======== ======== ======== ======== ======== ========
(1) An exploratory well is a well drilled either in search of a new, as yet
undiscovered oil or gas reservoir or to greatly extend the known limits of
a previously discovered reservoir. A development well is a well drilled
within the presently proved productive area of an oil or natural gas
reservoir, as indicated by reasonable interpretation of available data,
with the objective of completing in that reservoir.
(2) A productive well is an exploratory or development well found to be capable
of producing either oil or natural gas in sufficient quantities to justify
completion as an oil or natural gas well.
(3) A nonproductive well is an exploratory or development well that is not a
producing well.
(4) During 2002, 2001 and 2000, an additional 9, 24 and 12 wells, respectively,
were drilled for water or CO2 injection purposes.
-11-
OPERATIONS REPORT
WEST MISSISSIPPI AND OUR CO2 ASSETS
- ------------------------------------
Carbon dioxide ("CO2") injection is one of the most efficient tertiary
recovery mechanisms for producing crude oil; however, its application requires
large quantities of CO2, and therefore its use has been restricted to West
Texas, Mississippi and other isolated areas where large quantities of CO2 are
available. The CO2 acts as a type of solvent for the oil, removing it from the
formation and allowing the oil to be recovered along with the CO2 as it is
produced. For example, in a typical oil field, between 40% and 50% of the oil in
place can be extracted by primary and secondary (waterflooding) recovery. An
additional amount of oil (17% at Little Creek) can be recovered by injecting CO2
into certain wells and then recovering the additional oil and the CO2 from other
wells.
One of the few natural sources of CO2 in the United States was discovered
around Jackson Dome in Mississippi, a volcanic intrusive, which was emplaced
about 80 million years ago. These CO2 reserves are found in structural traps in
the Buckner, Smackover and Norphlet formations at depths of about 16,000 feet.
Some estimates have suggested that there are 12 Tcf of usable CO2 in this area.
In September 1999 we acquired our first CO2 tertiary recovery project at
Little Creek Field in Mississippi, which was originally developed by Shell Oil
Company. Since our acquisition of this field, we have increased oil production
here from 1,350 Bbls/d to an average of 3,033 Bbls/d during the fourth quarter
of 2002. Following our success at Little Creek, we embarked upon a strategic
program to build a dominant position in this niche play. We recognized that
several other older fields in the area would also be excellent CO2 flood
candidates because they produced from the same Lower Tuscaloosa formation,
shared very similar reservoir characteristics and were in close proximity to
each other. Following are highlights of our activities over the last two years:
o In February 2001, we acquired approximately 800 Bcf of proved
producing CO2 reserves for $42.0 million, a purchase that gave us
control of almost all of the CO2 supply in Mississippi, as well as
ownership and control of a critical 183- mile CO2 pipeline. This
acquisition provided the platform to significantly expand our CO2
tertiary recovery operations because it assured us that CO2 would be
available to us at a reasonable and predictable cost. Since February
2001, we have acquired an additional CO2 property and drilled two
additional CO2 wells, increasing our estimated proved CO2 reserves to
approximately 1.6 Tcf as of December 31, 2002. These additional wells
are each capable of producing between 20 and 30 MMcf of CO2 per day.
Although the proven and potential reserves are quite large, in order
to continue our tertiary development of the old oil fields in the
area, incremental production of CO2 is needed. In order to obtain the
additional CO2 production we plan to drill several additional wells,
including one or two more wells during 2003.
o During the fourth quarter of 2002, we sold an average of 63.1 MMcf/d
of CO2 to commercial users and we used an average of 57.4 MMcf/d for
our tertiary activities. With the completion of our latest well,
currently scheduled for late March 2003, we expect to increase our
daily CO2 production to over 165
-14-
MMcf/d and by year-end 2003 we hope to further increase our CO2
production to approximately 200 MMcf/d. We expect to continue our CO2
drilling in 2004 and beyond, with plans to increase the CO2 production
to over 300 MMcf/d within the next couple of years. We expect the
majority of the incremental production to be used in our tertiary
recovery operations, while we expect CO2 sales to industrial customers
to continue to provide us with net cash flow of around $6 to $7
million per year for the next several years. As of December 31, 2002,
the present value of these industrial contracts discounted at 10% per
year was approximately $57 million based on the current life of each
contract. We believe the majority of these contracts will be extended
beyond their current terms, which would result in the present value of
the industrial sales being higher.
o During 2001 and 2002, we acquired several oil fields in our CO2
operating area, including the West Mallalieu and McComb Fields.
Typical of mature fields in this area, the acquisition cost of both of
these fields was relatively low in comparison to the significant
reserve potential as a tertiary recovery project. As an example, we
acquired West Mallalieu in May 2001 for $4.0 million, and by year-end
2001 had recognized 10.4 MMBOE of proved reserves, with additional
future reserve potential in this field. We acquired McComb Field in
2002 for $2.3 million, and by year-end 2002 had recognized 8.3 MMBOE
of proved reserves with additional future reserve potential here also.
We expect the development cost at these fields to average around $4.00
per BOE.
o In August 2002, we acquired COHO Energy Inc.'s Gulf Coast properties
for $48.2 million, which as of year-end 2002 contained an estimated
15.0 million barrels of oil (excluding any potential reserves from
tertiary recovery). Brookhaven Field, another significant tertiary
flood candidate along our CO2 pipeline, was included in the properties
acquired from COHO. By exploiting our scale, regional competitive
advantage and strategic ownership of the general partner interest in
Genesis Energy, we were able to increase the average realized price
for post-acquisition production from these properties by approximately
$3.40 per barrel (relative to NYMEX prices) over the prices that COHO
realized earlier in 2002. This translates into a 50% increase in the
PV-10 Value of the acquisition, using constant prices and the future
price strip as of the time of acquisition. We do not expect to begin
development of Brookhaven Field until at least 2004, but believe that
this field contains one of the area's most significant opportunities
for potential oil reserves using CO2 tertiary recovery. In February
2003, we sold one of the acquired COHO fields, Laurel Field, for $27.0
million and also received an interest in another field and seismic
data valued by us at approximately $1.0 million. At December 31, 2002,
Laurel Field had 7.4 MMBbls of proven reserves, just less than 50% of
the total proved reserves of the COHO properties acquired in August
2002.
o In May 2002, we acquired the 2.0% general partner interest in Genesis
Energy, L.P. Genesis is engaged in crude oil gathering, marketing and
transportation with three primary pipeline systems in Texas,
Alabama/Florida and Mississippi. Genesis' Mississippi pipeline runs
near several of our tertiary recovery operations in southwest
Mississippi and within 25 miles of our Heidelberg Field and several
-16-
of our other east Mississippi fields. This acquisition has enhanced
our marketing position for our Mississippi oil production. Genesis
could also function as a financier and operator of new pipelines and
gathering systems that are required in order to develop these fields.
With anticipated all-in finding and development costs of approximately
$4.00 per BOE and anticipated operating costs of $9.00 to $10.00 per BOE over
the life of each field, these tertiary recovery operations in West Mississippi
along our pipeline should prove to be highly profitable, even at $18 to $20 oil
prices, as they produce light sweet oil that receives near NYMEX pricing. We
believe there is also significant potential in the future to extend our pipeline
to eastern Mississippi and/or southern Louisiana to exploit the use of CO2 in
tertiary recovery operations in these areas.
The western part of Mississippi has produced over 245 MMBbls of light sweet
crude oil from Tuscaloosa sandstones at a depth of about 10,000 feet. The
application of a theoretical recovery factor of 17% of original oil in place
suggests that about 80-100 MMBbls of additional gross reserves may be available
in fields in this part of the state. To date, we have booked approximately 38.2
MMBOE (gross) of this potential as proven reserves, of which 4.1 MMBbls (gross)
has been produced to date. Obviously, a great deal of work is required before
these additional reserves can be recorded as proved reserves, such as additional
landwork, reworking/reentering wells and installing production facilities. We
plan to spend around $43.0 million in this area during 2003, the largest single
portion of our $130 million 2003 exploration and development budget.
LITTLE CREEK, MALLALIEU AND MCCOMB FIELDS
- -----------------------------------------
Little Creek Field was discovered in 1958, and by 1962 the field had been
unitized and waterflooding had commenced. The pilot phase of CO2 flooding began
in 1974 and the first two phases (each in a distinct area of the field) began in
1985. When we acquired the field in 1999, these first two phases were
substantially complete and Phase III was in process. We have completed Phase III
and Phase IV and have initiated Phase V utilizing CO2 injection. Our plans in
2003 are to continue the development of these phases. Currently there are 39
producing wells and 26 injection wells at Little Creek. Based on the results of
the two earliest phases of CO2 flooding at Little Creek, tertiary recovery has
increased the ultimate recovery factor in that portion of the field by
approximately 17%, as compared to approximately 20% for primary recovery and 18%
for secondary recovery. The field has produced a cumulative 61.9 gross MMBbls of
light sweet crude and we currently estimate that an additional 9.1 gross MMBbls
can be recovered.
Production from Little Creek Field was approximately 1,350 Bbls/d when we
acquired it in 1999. During the fourth quarter of 2002, production had increased
to an average of 3,033 BOE/d. With our recent increases in CO2 production, we
expect the production from Little Creek to increase further during 2003 by
another 750 to 1,250 BOE/d.
-17-
In addition to our expansion activities at Little Creek, we purchased West
Mallalieu Field in May 2001. West Mallalieu Field was originally unitized by
Shell Oil Company, and a subsequent pilot project was commenced in 1986. The
pilot project, consisting of four 5-spot patterns, has cumulatively produced
approximately 2.3 MMBbls of oil as a result of CO2 flooding. We expanded the
pilot project by adding an additional four patterns during 2001 and an
additional four patterns in 2002. During 2002 we began to see initial response
to CO2 injection as the unit averaged 778 Bbls/d during the fourth quarter of
2002. In contrast to Little Creek Field, West Mallalieu Field was not
waterflooded prior to CO2 injection. Therefore, the tertiary recovery of oil
from West Mallalieu Field Unit as a result of CO2 injection could exceed the 17%
of original oil in place that we expect from Little Creek Field.
McComb Field, purchased in 2002, has not had any pilot programs or tertiary
operations to date and has virtually no current oil production, but is close in
proximity and analogous to our fields at Little Creek and Mallalieu. We plan to
commence tertiary recovery operations in 2003 and expect to see initial oil
production responses in early 2004. As of December 31, 2002, we had recognized
8.3 MMBOE of proven reserves at McComb Field. The total potential from McComb
Field is estimated to be as much as twice the booked proven reserves and thus we
expect the reserves at McComb to increase over the next several years as we
develop the field in its entirety.
At December 31, 2002, we had proved reserves of 27.9 MMBOE relating to our
tertiary recovery operations. Through December 31, 2002, we had spent a total of
$74.4 million on fields in this area, primarily Little Creek and Mallalieu
Fields, and have received $50.1 million in net operating income, leaving us a
balance of $24.3 million to recover for payout. This compares to a PV-10 Value,
using December 31, 2002 SEC pricing of $31.20 per Bbl, of $301.2 million for the
proved reserves in these fields.
OFFSHORE GULF OF MEXICO
- -----------------------
Denbury's second largest focus area for 2003 is the federal offshore waters
of the Gulf of Mexico. Employing the latest 3D seismic techniques and
interpretations has allowed us to better understand the complexities of these
offshore areas. Denbury owns an interest in 85 wells and operates 68 of these
wells (80%) from its regional office in Covington, Louisiana. Based on our
initial successful results in the Gulf of Mexico, in July 2001 we purchased
Matrix Oil & Gas, Inc. Matrix had followed our same strategy of acquiring
offshore fields from the major oil and gas companies that had produced large
quantities of oil and natural gas. We believe large fields that have produced
hundreds of millions of barrels of oil and hundreds of billions of cubic feet of
natural gas generally have an additional 10% to 15% of additional reserves which
can be produced when detailed geology and engineering work is applied. The
Matrix properties were producing approximately 40 MMcf/d at the time of the
acquisition.
Due to the downturn in natural gas prices that occurred late in 2001, we
budgeted little drilling activity offshore during 2002, with planned spending
limited to workovers, recompletions and other maintenance
-19-
type projects. We drilled only two offshore wells late in the year, both
successful exploration wells at North Padre Island A-9. Our total spending
during 2002 was approximately $17.1 million in this region, approximately 15% of
our total exploration and development budget. During 2002 there were two storms
in the Gulf of Mexico, Tropical Storm Isidore and Hurricane Lili, which impacted
our offshore production and caused significant damage to one of our offshore
platforms. Most of this damage was covered by insurance, but we did expense
approximately $750,000 during the fourth quarter of 2002 related to the
insurance deductibles and certain items not covered by insurance. Even with the
reduced spending and the losses in production caused by the two storms, our
production offshore averaged 59.9 MMcfe/d during 2002, slightly higher than the
2001 average of approximately 55 MMcfe/d during the period they were owned by
us. During 2003, our offshore spending will be significantly higher, primarily
due to several prospects we developed during 2002 and intend to drill in 2003.
We expect to spend an estimated $41.0 million on offshore activities, or 32% of
our $130.0 million 2003 exploration and development budget.
We booked net proved reserves as of year-end 2002 of approximately 11 Bcf
net to our interest in the two wells at North Padre Island A-9 drilled in late
2002. This discovery should be on production in the second half of 2003.
During 2003 we expect to drill eight to ten wells, with unrisked potential
target objectives ranging from 5 Bcf to 55 Bcf, net to our interest. These plays
are supported with 3D seismic that is enhanced by modern acquisition techniques,
the latest processing techniques and seismic modeling. The application of these
techniques allows our geoscientists to better image deeper reservoirs and
recognize hydrocarbon indicators in and around these mature prolific fields. Our
scheduled wells include both development and exploration prospects at Brazos
A-21 and A-22, High Island A-6, West Cameron 192, East Cameron 33, West Cameron
427 and West Delta 27.
SOUTH LOUISIANA
- ---------------
Denbury operates on the land and in the marshes of South Louisiana,
including state waters. We own interests in 85 wells and operate 63 of these
wells (74%) from our regional office in Houma, Louisiana. This region produces
primarily natural gas, averaging 34.4 MMcf/d net to our interest in the fourth
quarter of 2002, approximately 38% of our total natural gas production. During
2002, we spent approximately $35.0 million in this region, approximately 32% of
our total exploration and development budget, drilling approximately 10 wells,
primarily in the Thornwell and Terrebonne Parish areas (Lirette, Bay Baptiste,
Bayou Rambio and Lake Gero). For 2003, our spending will be reduced somewhat in
this area to an estimated $21.0 million, or 16% of our $130.0 million
exploration and development budget, as we focus more of our natural gas
exploration and development efforts in the offshore Gulf of Mexico.
The majority of our onshore Louisiana fields lie in the Houma embayment
area of Terrebonne Parish, including Lirette, Bayou Rambio and South Chauvin
Fields, and a recent shallow natural gas play at
-20-
Lake Gero. The advent of 3D seismic data in these geologically complex areas has
become a valuable tool in exploration and development. We currently own or have
a license covering over 630 square miles of 3D data, and plan to expand our data
ownership. During 2002, we expanded our seismic holdings in this area by
acquiring an additional 290 square miles of 3D data. We drilled six wells in
Terrebonne Parish during 2002, four of which were discoveries. In 2003, we plan
to drill around 15 wells, eight of which are planned to further exploit the
shallow gas play in the Lake Gero area, five of which we expect to drill in the
Thornwell area, primarily targeting additional Bol Perc potential, and the rest
of which we expect to be drilled at other fields in the Terrebonne Parish area
using similar 3D interpretation techniques.
Our activities in the Lake Gero area of Terrebonne Parish provided strong
results during 2002. We re-processed a portion of our Terrebonne seismic to
better image the shallower sands in the area. The majority of newer data being
shot is to image the deeper sands, thus the processing of the shallow sands has
generally been overlooked. This reprocessing indicated there were multiple
shallow seismic anomalies present in the area around Lake Gero. We drilled two
successful wells at Lake Gero during the year. These reservoirs are shallow,
approximately 3000 feet deep, but the two wells produced an average of 4,000
Mcf/d during the fourth quarter of 2002. We plan to drill an additional eight
wells in the Lake Gero area during 2003. In addition to the Lake Gero area,
through our seismic reprocessing, we have another 12 prospects in the Terrebonne
Parish area we are currently reviewing.
We were very active in the Thornwell Field area, located in Cameron and
Jeff Davis Parishes, during 2001 and 2002. This field, purchased in late 2000,
produced an average of 23.5 MMcfe/d net to our interest during 2002. Our primary
interest in purchasing this field was the substantial upside potential that we
believe exists in the continued development of the existing producing zones (Bol
Perc), and the exploration potential of several deeper zones (Marg Howei and
Camerina). All of these prospects were defined by a 110 square mile 3D seismic
survey. During 2002 we continued successful development of the Bol Perc sands,
with the drilling of one Bol Perc well. During 2002, we also drilled the
Lacassane #6-1 (Brenda prospect), which targeted the Camerina formation. We were
unsuccessful in our largest target, the Lower Camerina sands, although this well
did prove up additional Bol Perc prospects in another fault block and reserves
in the shallower Camerina sands. The Lacassane #6-1 produced an average of 3.5
net MMcfe/d during the fourth quarter of 2002. In addition to drilling these two
wells, during 2002 we expanded our acreage position over several Bol Perc
anomalies, recompleted a well that averaged 2.8 MMcfe/d and purchased one
additional well. During 2003, we plan to drill four additional Bol Perc wells
and one Marg Howei well, although our total spending in this area, budgeted at
approximately $7.0 million, will be less than the $18.8 million spent here in
2002.
HEIDELBERG AND EAST MISSISSIPPI
- -------------------------------
In the eastern part of the Mississippi salt basin, from our office in
Laurel, Mississippi, we operate 418 wells (91%) out of 459 in which we own an
interest. These fields produced an average of 14,165 Bbls/d and 9.2 MMcf/d
during the fourth quarter of 2002. The largest
-22-
field in the region, and our largest field is Heidelberg Field, which for the
fourth quarter of 2002 produced an average of 7,290 BOE/d. We have been active
in this area since Denbury was founded in 1990 and are by far the largest
producer in the basin as well as in the State of Mississippi. In general, we
have owned our Eastern Mississippi properties longer than properties in most of
our other regions and thus they are more fully developed and we are spending
less in this region than in our other three regions. During 2002, we drilled 28
wells and performed various workovers, recompletions and other maintenance type
projects, with total spending (excluding acquisitions) during 2002 of
approximately $24.0 million in this region, approximately 21% of our total
exploration and development budget. As a result of our reduced spending here
during the year, our production in Eastern Mississippi averaged 13,379 BOE/d
during 2002, just slightly less than the 2001 average of 13,481 BOE/d. For 2003,
our spending will be about the same as in 2002, as we expect to spend an
estimated $21.0 million, or 16% of our $130.0 million 2003 exploration and
development budget in this region.
The fields in this region are characterized by structural traps that
generate prolific production from stacked or multiple pay sands. As such, they
provide opportunities to increase reserves through infield drilling,
recompletions, improvements in production efficiency, and in some cases, by
water flooding producing reservoirs. Most of our wells produce large amounts of
saltwater and require large pumps, which increases the operating costs per
barrel relative to our properties in Louisiana that are predominantly natural
gas producers. We plan to continue our basic strategy in this region,
supplemented by additional waterflooding (secondary recovery) and eventually CO2
flooding (tertiary recovery). Future tertiary recovery operations may offer the
biggest upside potential in this area. Although the reserve potential here is
significant, we are initially developing the fields along our CO2 pipeline (see
"West Mississippi and our CO2 Assets" above), as the CO2 is easily delivered to
these fields, which produce light sweet oil that commands a higher price
(relative to NYMEX) than the production from the Eastern Mississippi properties.
To extend our tertiary CO2 operations to Eastern Mississippi will require a
pipeline and slightly higher oil prices for this production than production from
our Western Mississippi properties. The higher oil price is needed to provide
similar rates of return, due to the overall quality of the crude oil and a
higher negative differential to NYMEX prices, and in order to cover the
additional cost of building a pipeline. However, with the high oil prices
prevailing in late 2002 and early 2003, tertiary operations appear to be
profitable. We plan to further evaluate this potential during the next couple of
years, as this could be part of our future expansion plans.
Our primary interests at Heidelberg Field, our single largest field, were
acquired from Chevron in December 1997. This field was discovered in 1944 and
has produced an estimated 196 MMBbls of oil and 39 Bcf of gas since its
discovery. The field is a large salt-cored anticline that is divided into
western and eastern segments due to subsequent faulting. There are 11 producing
formations in Heidelberg Field containing 40 individual reservoirs, with the
majority of the past and current production coming from the Eutaw, Selma Chalk
and Christmas sands at depths of 3,500 to 5,000 feet. When we acquired the
property, production was approximately 2,800 BOE/d. As a result of our
subsequent development work, production for 2002 averaged 7,479 BOE/d.
-23-
The primary oil production at Heidelberg is from five waterflood units that
produce from the Eutaw formation (approximately 4,400 feet). These units are
generally developed although they will require additional work and capital for
the next few years. In addition, Heidelberg is our single largest gas field. We
began extensive development of the Selma Chalk natural gas reservoir at a depth
of 3,700 feet in 2000 and 2001. Previous operators had only partially developed
this formation in order to provide fuel gas for the rest of the field. We
drilled 13 wells here in 2001 and 13 in 2002 that effectively reduced the well
spacing to 40 acres in East Heidelberg, and increased the natural gas production
at Heidelberg to an average for the year of around 7.1 MMcf/d and a fourth
quarter average of 7.9 MMcf/d. We believe that there may be opportunities to
further reduce the well spacing and we plan to drill an additional 11 Selma
Chalk wells in 2003.
We have pursued the same strategy at our other significant fields in East
Mississippi: Eucutta, Quitman, Davis, Sandersville and King Bee Fields. After we
acquired each of these oil fields, we initiated a rework program to increase
production and reserves. We shot the first 3D seismic survey ever shot over King
Bee Field (Cypress Creek Dome) in 2001, a field we acquired from Fina in 1999.
King Bee Field is a salt dome with relatively few wells drilled over the years
because it underlies a national forest and a U.S. military bombing range. Due to
these surface restrictions, wells have to be drilled from sites outside of the
bombing area, and thus well costs are higher than normal. The higher costs of
drilling and the steeply dipping beds of the producing formations make it
imperative to have a very good geologic picture of the subsurface to minimize
the risks prior to drilling. We drilled our first well at King Bee during 2002,
which we plan to convert to an injection well during the second quarter to begin
a pressure maintenance project in the largest reservoir currently in the field.
Based on our simulation study, we believe this project will allow us to recover
a significant amount of additional oil reserves (up to 1.0 MMBbls) that would
not be recovered otherwise. During 2003, we also plan to drill our first well
based on the 3D seismic data we shot over the field. This seismic data has
revealed a very complex and highly faulted field that will require extremely
detailed subsurface geology and geophysical efforts. We have identified an
additional four to six prospect leads at this time.
BARNETT SHALE
- -------------
Denbury also owns about 22,000 acres of leases in the Fort Worth Basin that
is prospective for the Barnett Shale. Six wells were drilled in 2001 and two in
2002, all but one of which were producing as of year-end 2002. Due to low
natural gas prices in late 2001, our 2002 development of this area was limited,
as we spent only approximately $2.2 million there during 2002. Although we
believe this area has a reserve potential in excess of 200 Bcf, it requires
natural gas prices greater than $3.00 per Mcf in order to provide us with our
minimum acceptable rate of return. As such, our other areas have provided better
opportunities to date. We have entered into two joint ventures with business
partners to drill up to 60 wells in this area. The addition of these wells,
combined with the nine wells we have drilled, will prove up the majority of our
acreage, leaving us the opportunity to further exploit this area in 2004 and
beyond.
-24-
GLOSSARY AND SELECTED ABBREVIATIONS
Bbl One stock tank barrel, of 42 U.S. gallons liquid volume, used herein in reference to crude oil or
other liquid hydrocarbons.
Bbls/d Barrels of oil produced per day.
Bcf One billion cubic feet of natural gas or CO2.
BOE One barrel of oil equivalent using the ratio of one barrel of crude oil, condensate or natural gas
liquids to 6 Mcf of natural gas.
BOE/d BOEs produced per day.
Btu British thermal unit, which is the heat required to raise the temperature of a one-pound mass of
water from 58.5 to 59.5 degrees Fahrenheit.
CO2 Carbon dioxide.
MBbl One thousand barrels of crude oil or other liquid hydrocarbons.
MBOE One thousand BOEs.
MBtu One thousand Btus.
Mcf One thousand cubic feet of natural gas or CO2.
Mcf/d One thousand cubic feet of natural gas or CO2 produced per day.
Mcfe One thousand cubic feet of natural gas equivalent using the ratio of one barrel of crude oil,
condensate or natural gas liquids to 6 Mcf of natural gas.
Mcfe/d Mcfes produced per day.
MMBbl One million barrels of crude oil or other liquid hydrocarbons.
MMBOE One million BOEs.
MMBtu One million Btus.
MMcf One million cubic feet of natural gas or CO2.
MMcfe One thousand Mcfe.
MMcfe/d MMcfes produced per day.
PV10 Value When used with respect to oil and natural gas reserves, PV10 Value means the estimated future
gross revenue to be generated from the production of proved reserves, net of estimated production
and future development costs, using prices and costs in effect at the determination date, without
giving effect to non-property related expenses such as general and administrative expenses, debt
service and future income tax expense or the depreciation, depletion and amortization, discounted
to present value using an annual discount rate of 10% in accordance with the guidelines of the
Securities and Exchange Commission.
Proved Developed Reserves that can be expected to be recovered through existing wells with existing equipment
Reserves and operating methods.
Proved Reserves The estimated quantities of crude oil, natural gas and natural gas liquids which geological and
engineering data demonstrate with reasonable certainty to be recoverable in future years from
known reservoirs under existing economic and operating conditions.
Proved Undeveloped Reserves that are expected to be recovered from new wells on undrilled acreage or from existing
Reserves wells where a relatively major expenditure is required.
Tcf One trillion cubic feet of natural gas or CO2.
-25-
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
We are a growing independent oil and gas company engaged in acquisition,
development and exploration activities in the U.S. Gulf Coast region. We are the
largest oil and natural gas producer in Mississippi, hold key operating acreage
onshore Louisiana and have a growing presence in the offshore Gulf of Mexico
areas. Our goal is to increase the value of acquired properties through a
combination of exploitation, drilling, and proven engineering extraction
processes. Our corporate headquarters are in Dallas, Texas, and we have three
primary field offices located in Houma and Covington, Louisiana, and Laurel,
Mississippi.
2002 ACQUISITIONS
Acquisition of COHO Gulf Coast Properties
In late August 2002, we acquired COHO Energy, Inc.'s Gulf Coast properties
through a bankruptcy auction. Our net purchase price, adjusted for interim
production and purchase adjustments to date, was $48.2 million and included nine
fields, eight of which are located in Mississippi and one in Texas. We operate
all but one of the smaller Mississippi fields. As of December 31, 2002, these
properties had net proved reserves of approximately 15.1 million barrels of oil
equivalent with net production of approximately 4,000 barrels of oil per day.
The Mississippi fields include interests in the Brookhaven, Laurel, Martinville,
Soso and Summerland Fields, with working interests in excess of 90%, plus
interests in the smaller Bentonia, Cranfield and Glazier Fields. At the time of
the acquisition, we hedged nearly 100% of the forecasted proved developed
production relating to this acquisition through the end of 2004 with no-cost oil
swaps (i.e., forward sales). The average fixed price of these swaps for 2003 is
$24.27 per barrel and for 2004 is $22.94 per barrel.
Subsequent to the purchase, we elected to sell several of the acquired
properties, primarily to reduce debt. The largest of these is Laurel Field, a
field with approximately 7.4 MMBbls of proved reserves as of December 31, 2002.
This disposition closed in February 2003. We received $27.0 million and other
consideration which included an interest in Atchafalaya Bay Field (where we
already own an interest) and seismic over that area. We have reached an
agreement to sell two other fields, Bentonia and Glazier Fields, for
approximately $2.0 million combined, which is expected to close in late March.
Both of these are much smaller fields with approximately 269,000 Bbls of proven
reserves at year-end 2002. The proceeds from the sale of Laurel Field were
applied to our bank debt, reducing our total debt to $325 million of as February
28, 2003.
We have been able to substantially improve the pricing (relative to NYMEX)
for the crude oil sold from the COHO properties since their acquisition. Our
sales prices one month after acquiring these properties (October 2002) increased
by approximately $3.40 per barrel over the prices that COHO was receiving per
barrel earlier in the year. This translated into a 50% increase in the PV10
Value of the acquisition, using constant prices and the futures price strip as
of early September 2002. This additional value was possible due to our
prominence in the area (we are the largest oil and natural gas producer in
Mississippi), coupled with the strategic benefits of acquiring the general
partner of Genesis Energy, L.P., which provides us an alternative market for our
production because of their pipeline in the area. These improved prices had not
changed substantially as of year-end 2002.
Acquisition of Genesis General Partner
On May 14, 2002, a newly formed subsidiary of Denbury acquired Genesis
Energy, L.L.C. (which was converted to Genesis Energy, Inc.), the general
partner of Genesis Energy, L.P. ("Genesis"), a publicly traded master limited
partnership, for total consideration, including expenses and commissions, of
approximately $2.2 million. The general partner owns a 2% interest in the
limited partnership. Genesis is engaged in two primary lines of business: crude
oil gathering and marketing and pipeline transportation. Genesis was a strategic
acquisition for us because of a crude oil pipeline they own in Mississippi near
several of our significant oil fields. We believe that Genesis may be in the
position to serve as a future financier and developer of our gathering systems,
CO2 and crude oil pipelines and other midstream assets. We are also considering
the economic transfer of certain of our assets, such as value of our industrial
CO2 sales, to Genesis in exchange for cash or a combination of cash and
partnership units. Whether such a transaction will occur, and if so, the
pricing, form and timing, are still being evaluated.
We are accounting for our investment in Genesis under the equity method of
accounting, which increased our 2002 net income by $55,000. We have included in
the footnotes to the consolidated financial statements summarized financial
information of Genesis (see Note 2 to the consolidated financial statements).
Genesis Energy, Inc., the general partner of which we own 100%, has guaranteed
the bank debt of Genesis, which was $5.5 million as of December 31, 2002, and
also included $26.3 million in letters of credit of which $3.2 million are for
Denbury's benefit to secure purchases from Denbury. There are no guarantees by
Denbury or any of its other subsidiaries of the debt of Genesis or of Genesis
Energy, Inc.
-27-
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
CAPITAL RESOURCES AND LIQUIDITY
During 2002, we spent $99.3 million on oil and natural gas exploration and
development expenditures, $16.4 million on CO2 capital investments, and
approximately $56.4 million on oil and natural gas property acquisitions, the
largest being the acquisition of properties from COHO Energy, Inc. (see
"Acquisition of COHO Gulf Coast properties"). Our cash flow from operations for
the year totaled $159.6 million, and we sold properties for aggregate proceeds
of approximately $7.7 million. The combined funds of $167.3 million funded all
but $4.8 million of our 2002 expenditures, the balance of which was funded by a
$9.1 million net increase in bank debt.
Graph depicting average NYMEX crude oil price listings by quarter from 2000
through 2002:
2000 2001 2002
- --------------------------------------- ----------------------------------- ---------------------------------------
Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4
28.77 28.68 31.77 31.88 28.79 27.98 26.78 20.45 21.68 26.24 28.26 28.20
Graph depicting average NYMEX natural gas price listings by quarter from 2000
through 2002:
2000 2001 2002
- --------------------------------------- ----------------------------------- ---------------------------------------
Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4
2.61 3.66 4.54 6.50 6.30 4.41 2.81 2.72 2.49 3.41 3.21 4.33
We anticipate that our capital spending during 2003, excluding any possible
acquisitions, will be equal to or less than our cash flow generated from
operations, as has been our policy since 1999. We currently have budgeted $130
million of new development and exploratory projects for 2003, plus approximately
$7.7 million of projects from 2002. Based on current projections, using futures
prices in place as of the first part of March 2003, this spending level is
expected to be as much as $50 million to $75 million below our forecasted cash
flow, depending on 2003 commodity prices. Initially, we plan to use any excess
funds generated from operations to pay down debt or to fund, in whole or in
part, possible acquisitions, although we may consider increasing our budget
later in 2003 if commodity prices remain high and we reach our debt target of
$300 million. We review our capital expenditure budget every quarter and make
adjustments as necessary to reflect changes in commodity prices and successes or
failures in our drilling program. As a result, since 1999, we have been able to
keep our capital spending (excluding acquisitions) at levels equal to or below
our cash flow from operations.
Although we have a significant inventory of development and exploration
projects in-house, on a long-term basis we will need to make acquisitions in
order to continue our growth and to replace our production. We are continuing to
pursue small acquisitions that are near our CO2 pipeline in Western Mississippi
and Southern Louisiana, plus individual fields in the Gulf of Mexico. Although
we now control most of the fields along our CO2 pipeline, there are a few
remaining smaller fields with potential that we do not control, plus we are
continuing to acquire additional interests in the fields that we do own. We have
targeted the acquisition of offshore blocks, which generally consist of one or
two fields, where we see additional potential based on our review of 3D seismic
or other geologic and geophysical data. Although we are continuing to pursue
acquisitions in our other core areas, including larger acquisitions, this
activity is a lower priority for us in 2003 than has been the case historically,
given our good inventory of projects in-house and our goal of reducing our debt
level. Any acquisitions that we make will likely be funded with either our
excess cash flow or bank debt.
Debt
As of September 30, 2002, we had total debt of approximately $375 million
following the COHO acquisition. It is our goal to limit our leverage. We
generally measure leverage by a debt-to-cash flow ratio, cash flow being defined
as cash flow from operations. Our target is a debt-to-cash flow ratio of 2 to 1
or less, using a moderate price deck. In today's commodity price environment, we
interpret that to be oil prices in between $22.50 and $25.00 per Bbl and natural
gas prices between $3.25 and $3.50 per Mcf. Based on these price assumptions, we
would be within our targeted debt-to-cash flow ratio during 2003 if our total
debt was reduced to $300 million. Thus, since the third quarter of 2002, we have
used a portion of our cash flow from operations and proceeds from
-28-
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Graph depicting capital expenditures (in millions of dollars):
Year Ended December 31,
-----------------------------------------------
2000 2001 2002
------------ ------------ -------------
Acquisitions 60.3 157.1 60.6
Development and Exploration 73.7 170.1 111.4
property sales to reduce our bank debt. During the fourth quarter of 2002, we
reduced debt by approximately $25 million, and with proceeds from the sale of
Laurel Field in February 2003 we paid down another $25 million of debt,
resulting in total debt as of February 28, 2003, of approximately $325 million.
Due to the high commodity prices in February 2003 and the resulting amounts due
on our hedges that were paid in early March, we borrowed $10 million on March 6,
2003 to fund our hedge payments. We expect to pay back this temporary borrowing
after we receive our February production revenues, the majority of which will be
received during the third week of March. We expect to achieve our debt goal of
$300 million during the latter half of 2003 through the application of excess
cash flow from operations, assuming that commodity prices do not change
substantially, or possibly by the economic transfer of certain of our assets,
such as the value of some of our industrial CO2 sales, to Genesis.
Graph depicting the Company's debt to total capitalization (in millions of
dollars):
December 31,
-------------------------------------
2000 2001 2002
---------- ------------ -----------
Long-Term Debt 199.0 334.8 344.9
Total Capitalization 415.2 683.9 711.7
In September 2002, we extended the maturity of our bank line from December
2003 to April 2006. Our borrowing base was left unchanged at $220 million and
generally the same banks remained in the line, although Bank One became the new
administrative agent. Our bank borrowing base is set by our banks at their sole
discretion based on various factors, some of which are out of our control, such
as the oil and natural gas prices used by the banks to value our reserves. As of
March 15, 2003, we had approximately $135 million of bank debt outstanding,
leaving us $85 million of current bank line availability. The next borrowing
base review by the banks will be as of April 1, 2003, based primarily on
year-end reserves. We currently do not anticipate any significant change in the
borrowing base at the next redetermination, nor do we currently plan to ask for
an increase, even though we believe such a request would be reasonable based
upon the additional properties we acquired from COHO. As discussed above, we
expect to reduce our total debt to $300 million, which (assuming completion of
our subordinated debt refinancing discussed below) would leave us $145 million
of availability on our bank line, which we believe is sufficient credit
availability, as we do not expect to spend more than our cash flow on
development and exploration for the foreseeable future.
On March 17, 2003, we announced a refinancing of our 9% Senior Subordinated
Notes due 2008. We sold $225 million of 7.5% Senior Subordinated Notes due 2013
and called our existing $200 million of 9% notes at 104.5% of face value.
Closing on the new notes is scheduled for March 25, 2003, subject to the
satisfaction of customary closing conditions, and the redemption of the old
notes is expected to occur on April 16, 2003. We intend to use the remaining net
proceeds from this offering to reduce bank debt. Once completed, the refinancing
is expected to save us around $2.6 million per year in interest expense.
Assuming completion, we estimate that we will have a charge to earnings in the
second quarter of 2003 of approximately $11.25 million, net of related income
taxes, from the early retirement of our currently outstanding 9% notes.
Commitments and Obligations
We have no off-balance sheet arrangements, special purpose entities,
financing partnerships or guarantees, other than as disclosed in this section,
nor do we have any debt or equity triggers based upon our stock or commodity
prices. Subject to semi-annual reaffirmation, our bank debt is not due until
April 2006, and our $200 million of subordinated debt is due in March 2008. Our
only other obligations that are not currently recorded on our balance sheet are
our operating leases, which primarily relate to our office space and minor
equipment leases and various obligations for development and exploratory
expenditures arising from purchase agreements or other transactions common to
our industry. In addition, in order to recover our undeveloped proved reserves,
we must also fund the associated future development costs as forecasted in the
proved reserve reports. Our operating
-29-
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
lease obligations total $11.7 million in the aggregate and $1.7 million for
2003. We have committed to another operating lease on a portion of our CO2
facilities equipment at Mallalieu Field with an estimated value of approximately
$5.6 million. This lease is expected to commence during mid-2003 with payments
of approximately $900,000 per year for seven years. Our capital spending
obligations total approximately $13.0 million over the next five years, $2.3
million of which is required in 2003. As is common in our industry, we commit to
make certain expenditures on a regular basis as part of our ongoing development
and exploration program. These commitments generally relate to projects that
occur during the subsequent six months and are part of our ongoing budget
process. For a further discussion of our future development costs and proved
reserves, see "Results of Operations - Depletion, Depreciation and Site
Restoration".
At December 31, 2002, we had a total of $370,000 outstanding in letters of
credit. Genesis Energy, Inc., the general partner of which we own 100%, has
guaranteed the bank debt of Genesis, which was $5.5 million as of December 31,
2002, and also included $26.3 million in letters of credit of which $3.2 million
secured purchases from Denbury. There are no guarantees by Denbury or any of its
other subsidiaries of the debt of Genesis or of Genesis Energy, Inc. We do not
have any material transactions with related parties other than sales of
production to Genesis Energy, L.P. as discussed in Note 2 to our consolidated
financial statements. A summary of our obligations discussed above is presented
in the following table:
Expected Maturity Dates
- ---------------------------------------------------------------------------------------------------------------------
Amounts in Thousands 2003 2004 2005 2006 2007 Thereafter
- ---------------------------------------------------------------------------------------------------------------------
Bank debt $ - $ - $ - $ 150,000 $ - $ -
Subordinated debt - - - - - 200,000(1)
Operating lease obligations 1,708 1,640 1,764 1,766 1,761 3,022
Capital expenditure obligations 2,332 2,500 2,500 2,500 2,500 -
Future development costs on proved
reserves, net of capital obligations 70,747 70,290 43,815 16,201 11,912 42,972
- ---------------------------------------------------------------------------------------------------------------------
Total $ 74,787 $ 74,430 $ 48,079 $ 170,467 $ 16,173 $ 245,994
- ---------------------------------------------------------------------------------------------------------------------
(1) See "Debt" section above regarding a refinancing of this debt.
Long-term contracts require us to deliver CO2 to our industrial CO2
customers at various contracted prices. Based upon the maximum amounts
deliverable as stated in the contracts, we estimate that we may be obligated to
deliver up to 387 Bcf of CO2 to these customers over the next 18 years; however,
based on the current level of deliveries, our commitment would be reduced to
approximately 250 Bcf. Given the size of our proven CO2 reserves (approximately
1.6 Tcf), our current production capabilities and our predicted levels of CO2
usage for our own tertiary flooding program, we are confident that we can meet
these delivery obligations.
We have oil price floors, collars and swaps that cover 75% to 85% of our
currently anticipated 2003 oil and natural gas production, 40% to 50% of our
currently anticipated 2004 oil and natural gas production and a minor portion of
our anticipated 2005 natural gas production. Nearly 100% of the forecasted
proved developed production from the COHO acquisition has been hedged through
2004 and is included in those production estimates (see also Note 7 to our
consolidated financial statements for more detail on these hedges). We have
entered into these hedges in order to protect our cash flow, so that a majority
of our capital program can be implemented, and so that we can achieve a minimum
rate of return on acquisitions, provided that our other assumptions related to
the acquisitions are correct. While the current market value of almost all of
our hedges is negative (i.e., a liability), they do offer significant protection
should commodity prices drop in the future (see also "Market Risk Management"
and Note 7 to the Consolidated Financial Statements).
Sources and Uses of Funds
During 2002, we spent approximately $99.3 million on exploration and
development activities, approximately $56.4 million on acquisitions, the largest
being the $48.2 million acquisition of the COHO properties, and approximately
$16.4 million on CO2 related capital expenditures. Our exploration and
development expenditures included approximately $62.3 million spent on drilling,
$17.8 million of geological, geophysical and acreage expenditures and $19.1
million spent on facilities and recompletion costs. The exploration and
development expenditures were funded by cash flow from operations, and the
acquisitions were primarily funded by cash flow, supplemented by property
dispositions totaling $7.7 million and incremental bank debt for the year of
$9.1 million.
During 2001, we spent approximately $170.1 million on exploration and
development activities and approximately $157.1 million on acquisitions
(excluding the $42 million CO2 acquisition), the largest being the acquisition
of Matrix. Our exploration and development expenditures included approximately
$115.9 million spent on drilling, $18.7 million of geological, geophysical
-30-
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
and acreage expenditures and $35.5 million spent on facilities and recompletion
costs. The exploration and development expenditures were funded by cash flow
from operations, and the acquisitions were primarily funded by net incremental
debt.
During 2000, we spent approximately $73.7 million on exploration and
development activities and approximately $60.3 million on acquisitions. These
exploration and development expenditures included approximately $37.8 million
spent on drilling, $8.5 million of geological, geophysical and acreage
expenditures and $27.4 million spent on facilities and recompletion costs. We
funded these exploration and development expenditures with cash flow from
operations and funded our acquisitions with cash flow and net incremental bank
debt of $46.5 million.
RESULTS OF OPERATIONS
CO2 Operations
Since 1999, when we acquired our first tertiary oil recovery operation at
Little Creek Field, we have increasingly emphasized these types of operations
and have acquired several fields which are potential flood candidates since that
date. More importantly, in February 2001 we acquired the sources of CO2 and a
pipeline to transport it to these fields. This acquisition included significant
carbon dioxide reserves, production, production facilities located near Jackson,
Mississippi and a 183-mile 20-inch pipeline which runs from the Jackson,
Mississippi area into southern Louisiana. We acquired nearly 100% of the working
interest in the producing CO2 wells and we operate the properties. During 2002,
we drilled another CO2 producing well, which as of March 5, 2003, was producing
around 28 million cubic feet of CO2 per day. Another well was completed in early
March 2003, and we plan to drill two more wells during the remainder of 2003. As
of December 31, 2002, we were capable of producing approximately 146 MMcf/d of
CO2 and we expect to increase this capacity to around 200 MMcf/d by the end of
2003. Based on our inventory of potential tertiary recovery projects, we will
need to drill additional CO2 wells in 2004 and beyond to further increase our
production capacity to 350 MMcf/d of CO2 production in order to develop the oil
fields along our CO2 pipeline as planned. Although we believe that our plans and
projections are reasonable and achievable, there could be delays or unforeseen
problems in the future which could delay our overall tertiary development
program. We believe that such delays, if any, should only be temporary. As of
December 31, 2002, based on a report prepared by DeGolyer and MacNaughton, we
estimate that we have approximately 1.6 trillion cubic feet of usable CO2
reserves, net to our working interest.
Although our oil production from our CO2 tertiary recovery activities is
still modest, we expect it to be an ever increasing portion of our production
(see discussion of production below). In order to develop fields which are
tertiary flood candidates and increase our oil production, we must continue to
increase our CO2 production. Since we acquired the CO2 properties in February
2001, CO2 production has increased from approximately 65 MMcf/d to 146 MMcf/d as
of year-end 2002. We plan for this to further increase during the next few years
to over 300 MMcf/d. We are using this CO2 to further develop Little Creek Field,
develop Mallalieu Field (acquired in 2001), and we expect to commence tertiary
operations at McComb Field during 2003. We have tentatively scheduled tertiary
projects at other oil fields along our pipeline, and project that oil production
from these tertiary activities will increase from its current level of 3,863
Bbls/d during the fourth quarter of 2002 to as much as 17,000 Bbls/d in 2008. As
of December 31, 2002, we had approximately 27.9 MMBbls of proven oil reserves in
these fields along our CO2 pipeline and have identified and estimated
significantly more potential in fields that we own. In addition to the
development of the fields we currently own along our pipeline, we see other
potential tertiary recovery projects in fields we own in Eastern Mississippi,
including Heidelberg and Eucutta Fields, plus potential in several large old oil
fields in Southern Louisiana which we do not currently own. However, in order to
develop these areas we would need additional pipeline transportation facilities,
and thus these potential projects are not in our short-term plans.
The increasing emphasis on CO2 tertiary recovery projects has made, and
will continue to make, an impact on our financial results and certain operating
statistics. First, there is a significant delay between the initial capital
expenditures and the resulting production increases, as these tertiary
operations require the building of facilities before CO2 flooding can commence
and usually require six to twelve months before the field responds to the
injection of CO2. Secondly, as these tertiary projects are more expensive to
operate than our other oil fields because of the cost of injecting and recycling
the CO2, our overall operating expenses on a per BOE basis will likely continue
to increase as these operations constitute an increasingly larger percentage of
our operations. These tertiary recovery fields are expected to average between
$9 and $10 per BOE in operating expenses over the life of the field, although
the cost per BOE is higher at the beginning of each operation. This compares to
a cost of around $5 per BOE for a more traditional oil property. Third, while
our operating expense on a per BOE basis may rise, our overall oil prices,
measured as a discount to NYMEX prices, should continue to improve. These CO2
operations are all currently conducted in fields that produce light sweet oil
and receive oil prices close to (and sometimes actually higher than) NYMEX
prices. As this production
-31-
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Graph depicting development and exploration expenditures vs. cash flow from
operations (in millions of dollars):
Year Ended December 31,
-------------------------------------------
2000 2001 2002
----------- ------------ ------------
Development and Exploration Expenditures 73.7 170.1 111.4
Cash Flow from Operations 96.0 185.0 159.6
becomes a larger percentage of our overall production, our overall average
differential to NYMEX should decrease. While our oil prices have historically
averaged between $4.00 and $5.00 below NYMEX prices, our 2002 average was $3.73
below NYMEX. This positive trend should continue, subject of course to the
normal fluctuations in the marketplace. Despite these high operating costs, due
to the high oil price (relative to NYMEX) and the relatively low finding and
development costs (anticipated average of approximately $4.00 per BOE), these
tertiary recovery operations generate a reasonable rate of return at NYMEX oil
prices of $18 to $19 and generate positive cash flow at oil prices significantly
lower than that. These tertiary recovery operations are generally lower risk
than other types of oil and gas development or exploration, as they are
conducted in fields where there has been substantial proven oil production in
the past. We anticipate that we will spend between 25% and 50% of our annual
development budget on these projects, at least for the next few years, unless
there is a significant drop in oil prices or our economics change for some
unforeseen reason. We believe that the ownership of our CO2 reserves provides us
a significant strategic advantage in the acquisition of other properties in
Mississippi and Louisiana that could be further exploited through tertiary
recovery.
It cost us approximately $0.13 per thousand cubic feet to produce our CO2
during 2002, higher than the $0.07 average for 2001, primarily due to the
incremental cost of compression equipment beginning in the third quarter of 2002
and increased maintenance work performed on the facilities during 2002. We
allocate the operating expenses to produce our CO2 and operate and maintain our
CO2 pipeline between the sales to commercial users and CO2 used for our own
account. We expect these costs to be reduced slightly in the future as a result
of the incremental CO2 production from the wells we drilled in 2002 and early
2003 and the anticipated production from the two additional CO2 wells scheduled
later in 2003. The estimated total cost per thousand cubic feet of CO2 for us
during 2002 was approximately $0.16, after inclusion of depreciation and
amortization expense, still less than the $0.25 per thousand cubic feet that we
were paying before we acquired the properties in February 2001.
In addition to using CO2 for our own account, we sell CO2 to third party
industrial users under long-term contracts. Our net operating margin from these
sales was $4.3 million during 2001 and $6.2 million during 2002. Our average CO2
production during 2001 and 2002 was approximately 84 million and 104 million
cubic feet per day, of which approximately 53% in 2001 and 54% in 2002 was used
in our tertiary recovery operations, with the balance sold to third parties for
industrial use.
Operating Income
Since 1998, cash flow from operations improved each year until 2002 because
of higher commodity prices and production levels. Even though production
increased approximately 14% in 2002 over 2001 production levels, our cash flow
from operations decreased 14% due to a 24% decline in the average NYMEX natural
gas price, a 95% decrease in the proceeds from derivative contracts and a 5%
increase in total expenses.
Year Ended December 31,
- -----------------------------------------------------------------------------------------------------------
Amounts in Thousands Except Per Share Amounts 2002 2001 2000
- -----------------------------------------------------------------------------------------------------------
Net income $ 46,795 $ 56,550 $ 142,227
Net income per common share:
Basic $ 0.88 $ 1.15 $ 3.10
Diluted 0.86 1.12 3.07
- -----------------------------------------------------------------------------------------------------------
Adjusted cash flow from operations $ 164,565 $ 186,801 $ 111,555
Net change in assets and liabilities relating to operations (4,965) (1,754) (15,583)
- -----------------------------------------------------------------------------------------------------------
Cash flow from operations $ 159,600 $ 185,047 $ 95,972
- -----------------------------------------------------------------------------------------------------------
Adjusted cash flow from operations represents cash flow provided by
operations before the changes in assets and liabilities. In our discussion of
operations herein, we have elected to discuss the two primary components of cash
flow provided by operations. 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
-32-
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Graph depicting cash flow from operations and adjusted cash flow from
operations by quarter (in millions of dollars):
2000 2001 2002
-------------------------- --------------------------- ---------------------------
Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4
Cash flow from operations 15,201 27,642 26,837 26,292 66,089 30,886 45,097 42,975 12,032 46,572 44,379 55,617
Adjusted cash flow from
operations* 19,562 21,340 27,502 43,151 54,982 45,194 48,670 37,955 28,524 43,423 44,177 48,411
*(Cash flow from operations before changes in assets and liabilities. See prior table.)
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
year. We also use this measure because the collection of our receivables and
payment of our obligations has not been a significant issue for our business,
but merely a timing issue from one period to the next, as we have very few
uncollectible items and pay all of our obligations.
The net change in assets and liabilities that is a part of cash flow
provided by operations is also important as it does require or provide
additional cash for use in our business; however, we prefer to discuss its
effect separately. For instance, as noted above, during 2002 we used
approximately $5.0 million of cash to fund a net increase in working capital.
This was primarily caused by a high level of drilling and exploitation activity
late in 2001 which was not paid (or even due) until 2002. We also used a
significant amount of cash flow from operations in 2000, as our net change in
assets and liabilities in that year was a negative $15.6 million, primarily
relating to unusually high natural gas prices late in 2000, for which we were
not paid until the following month (as is normal in our industry), causing a
higher than normal increase at year-end 2000 in production receivables. While
both are components of a GAAP measure, we believe that it makes sense to discuss
them independently.
During 2002, we set another Company record for production. Certain of our
operating statistics are set forth in the following chart.
Year Ended December 31,
- -----------------------------------------------------------------------------------------------------------
2002 2001 2000
- -----------------------------------------------------------------------------------------------------------
AVERAGE DAILY PRODUCTION VOLUME
Bbls 18,833 16,978 15,219
Mcf 100,443 85,238 37,078
BOE(1) 35,573 31,185 21,399
OPERATING REVENUES AND EXPENSES (THOUSANDS)
Oil sales $ 153,705 $ 132,219 $ 144,230
Natural gas sales 121,189 128,179 60,406
Gain (loss) on settlements of derivative contracts (2) 932 18,654 (25,264)
-------------- -------------- -------------
Total oil and natural gas revenues $ 275,826 $ 279,052 $ 179,372
============== ============== =============
Lease operating expenses $ 71,188 $ 55,049 $ 38,676
Production taxes and marketing expenses 11,902 10,963 8,051
-------------- -------------- -------------
Total production expenses $ 83,090 $ 66,012 $ 46,727
============== ============== =============
CO2 sales to industrial customers $ 7,580 $ 5,210 $ -
CO2 operating expenses 1,400 891 -
-------------- -------------- -------------
CO2 operating margin $ 6,180 $ 4,319 $ -
============== ============== =============
UNIT PRICES-INCLUDING IMPACT OF HEDGES(2)
Oil price per Bbl $ 22.27 $ 21.65 $ 23.50
Gas price per Mcf 3.35 4.66 3.57
UNIT PRICES-EXCLUDING IMPACT OF HEDGES(2)
Oil price per Bbl $ 22.36 $ 21.34 $ 25.89
Gas price per Mcf 3.31 4.12 4.45
OIL AND GAS OPERATING REVENUES AND EXPENSES PER BOE (1)
Oil and natural gas revenues (including hedges) $ 21.24 $ 24.52 $ 22.90
-------------- -------------- -------------
Lease operating expenses 5.48 4.84 4.94
Production taxes and marketing expenses 0.92 0.96 1.02
-------------- -------------- -------------
Total production expenses $ 6.40 $ 5.80 $ 5.96
- -----------------------------------------------------------------------------------------------------------
(1) Barrel of oil equivalent using the ratio of one barrel of oil to six Mcf of
natural gas ("BOE").
(2) See also "Market Risk Management" below for information concerning the
Company's hedging transactions.
-33-
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Graph depicting production by quarter (average MBOE per day):
2000 2001 2002
---------------------------------- --------------------------------- -------------------------------
Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4
---------------------------------- --------------------------------- -------------------------------
Oil 14,382 14,809 15,405 16,268 16,269 16,454 16,877 18,292 17,740 17,920 18,931 20,706
Natural Gas 4,739 4,771 5,148 10,028 10,366 11,448 18,235 16,664 17,621 17,606 16,575 15,188
---------------------------------- --------------------------------- -------------------------------
Total BOE 19,121 19,580 20,553 26,296 26,635 27,902 35,112 34,956 35,361 35,526 35,506 35,894
PRODUCTION. From the first quarter of 1999 through the third quarter of
2001, our average daily production increased each quarter, with production in
the fourth quarter of 2001 being only slightly less than our third quarter 2001
peak. Our production during 2002 was relatively constant, with only slight
growth during the year. Our 2002 production growth was less than it had been in
prior years primarily due to a smaller capital budget because of lower commodity
prices, particularly late in 2001 and early 2002. In addition, as discussed in
"CO2 Operations" above, our production does not directly correspond with our
related capital spending on tertiary recovery projects.
Our production growth over the years has generally been related to
acquisitions and subsequent development of the acquired fields. During the last
three years, our significant acquisitions of oil and natural gas properties have
consisted of the $56.5 million acquisitions of Thornwell, Porte Barre and Iberia
Fields in the fourth quarter of 2000, the $4.0 million acquisition of Mallalieu
Field in May 2001, the $157.4 million corporate acquisition of Matrix in July
2001, the $2.3 million acquisition of McComb Field in September 2002, and the
$48.2 million acquisition of COHO's Gulf Coast properties in August 2002 (see
"Acquisition of COHO Gulf Coast Properties" above).
Production by area for 2000, 2001 and each of the quarters of 2002 is
listed in the following table.
Average Daily Production (BOE/d)
--------------------------------------------------------------------------------
First Second Third Fourth
Quarter Quarter Quarter Quarter
Operating Area 2000 2001 2002 2002 2002 2002
- --------------------------------- ----------- ------------ ---------------- ------------ ----------- -----------
Mississippi - non-CO2 floods 13,179 13,481 12,423 12,124 13,232 15,703
Mississippi - CO2 floods 2,018 2,560 3,839 4,278 3,895 3,863
Onshore Louisiana 5,878 9,268 8,405 7,717 8,224 7,859
Offshore Gulf of Mexico 201 5,691 10,550 11,229 9,863 8,287
Other 123 185 144 178 292 182
----------- ------------ ---------------- ------------ ----------- -----------
Total Company 21,399 31,185 35,361 35,526 35,506 35,894
- --------------------------------- ----------- ------------ ---------------- ------------ ----------- -----------
Our average production from our non-CO2 flood properties in Mississippi
decreased slightly during 2002, excluding the increases attributable to the
acquisition of COHO properties, due to general production declines at most of
our significant fields and a reduced level of capital expenditures in this area
during 2002. Heidelberg Field, located in Eastern Mississippi, is Denbury's
largest single field. At the time of its acquisition in December 1997,
Heidelberg Field was producing approximately 2,800 BOE/d. Production under our
ownership has subsequently averaged 3,760 BOE/d, 5,708 BOE/d, 7,310 BOE/d, 7,908
BOE/d and 7,479 BOE/d for 1998, 1999, 2000, 2001 and 2002. During 1998, our
primary emphasis was implementation of the field's largest waterflood unit, the
East Heidelberg Waterflood Unit, plus other developmental drilling. During 1999,
we began to see response from our waterflood efforts. We added other waterflood
units during 1999 and 2001 and also expanded our drilling for natural gas at
Heidelberg in the Selma Chalk formation during the second half of 1999. As a
result, natural gas production at Heidelberg increased from 0.5 MMcf/d in 1998
to 1.0 MMcf/d in 1999, 3.8 MMcf/d in 2000 and 7.4 MMcf/d in 2001. Our activity
in 2002 was generally related to continued maintenance of the waterfloods in
progress, plus the drilling of eight additional natural gas wells in the second
half of the year as a result of the higher natural gas prices. Average
production at our Heidelberg Field during 2002 was 5% lower than production
levels there in 2001. Overall production from this field is expected to remain
relatively flat or slightly decline as the waterfloods appear to have reached a
plateau, although there may be periodic spikes in the natural gas production as
a result of the recently drilled additional natural gas wells.
Since 1999, when we acquired our first tertiary oil recovery operation at
Little Creek Field, we have increasingly emphasized these types of operations
and have acquired several fields that are potential CO2 flood candidates since
that date (see the discussion of
-34-
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
"CO2 Operations" above). Although production from our CO2 activities is still
modest, we expect it to be an ever increasing portion of our production. It has
generally increased each period, although in the third and fourth quarters of
2002, average production on our tertiary recovery properties was slightly less
than the second quarter 2002 average due to a temporary lack of deliverability
of CO2. We have increased our CO2 production since that time and are continuing
to drill additional CO2 wells and believe that we have sufficiently increased
our CO2 production to meet our current needs for our tertiary recovery
operations, although we will require additional CO2 production in the future
(see "CO2 Operations" above for further information). As such, production from
these fields has begun to respond, averaging approximately 4,019 Bbls/d during
February 2003, a 4% increase over the fourth quarter 2002 average. Production at
Little Creek Field, our oldest and currently our largest tertiary recovery
operation, has also increased since we acquired it in August 1999. At the time
of acquisition, Little Creek was producing approximately 1,350 BOE/d, with a
1999 annual average production rate of 587 BOE/d, due to our ownership for a
partial year. Since acquiring the field, we have completed phase III of the CO2
flood and implemented phases IV and V, resulting in gradual production
increases. Production from Little Creek Field averaged 2,018 BOE/d for 2000,
2,462 BOE/d for 2001, and 3,393 BOE/d in 2002. We are continuing to expand our
tertiary recovery operations at Little Creek and anticipate that production will
further increase at this field throughout 2003.
Production from our onshore Louisiana area was generally down year over
year, although there have been fluctuations up and down on a quarter-to-quarter
basis primarily as a result of drilling activity at Thornwell Field. Production
at Thornwell Field during 2002 averaged 3,910 BOE/d, a 9% decrease from
production levels in 2001. The majority of the production at Thornwell is
short-lived natural gas production, and thus volumes can fluctuate significantly
from period to period depending on the level of activity, the timing of well
completions, and other factors. Overall, we believe the Thornwell acquisition in
October of 2000 has performed well, as we recovered our acquisition cost within
the first year of ownership. We are continuing development and exploration
activities at Thornwell Field in 2003, although at a lower level than in 2002.
Our natural gas production has significantly increased during the last
couple of years, primarily due to the acquisition of the offshore Gulf of Mexico
properties owned by Matrix Oil and Gas in July 2001. Our development and
exploration activities on these properties was minimal in 2002 due to the low
natural gas prices at the beginning of the year. Thus offshore production
generally declined during the latter half of 2002, although annual average
production here was still higher in 2002 than in 2001. Production was also hurt
by two storms, Tropical Storm Isidore in September 2002 and Hurricane Lili in
October 2002. Although it is difficult to measure the exact impact of the
storms, our offshore production declined by 1,366 BOE/d between the second and
third quarters of 2002 and further declined by 1,576 BOE/d in the fourth quarter
of 2002, a significant portion of which relates to the shut-in of production
caused by the two storms. The storm also caused other indirect declines in
production, both onshore and offshore, by delaying several projects because of
unusually wet conditions, high water, and other storm-related effects. As an
example, the incremental CO2 production from a well we drilled in the third
quarter was delayed because the wet conditions made it difficult to install a
pipeline to hook up the well. These types of delays caused our production to be
less than we had originally anticipated in the last half of the year. During
2003, with anticipated higher natural gas prices, we are spending almost 30% of
our budget offshore, second only to our CO2 operations expenditures. Since the
acquisition of Matrix in July 2001, our production has generally been close to
50/50 oil and natural gas and we anticipate that balance to remain near 50/50 in
the near future based on our current development plans.
REVENUE. Our oil and natural gas revenues increased 56% between 2000 and
2001, but decreased slightly (1%) in 2002. The growth in 2001 revenues was
primarily due to a 46% increase in production, as our net per BOE prices were
almost the same. During 2002, production increased 14%, but the decline in
natural gas prices caused our net per BOE price to decline by 7%, thereby
limiting the revenue increase between years. Between 2000 and 2001, the overall
increase in production volumes contributed $92.8 million in revenue, or a 52%
increase, and the incremental cash receipts from hedges contributed $43.9
million, or a 25% increase, partially offset by an overall decrease of $37.0
million in commodity prices (or a negative 21%). Between 2001 and 2002, revenues
decreased by 1%, due primarily to lower hedging receipts. The overall increase
in production volumes contributed $36.6 million in revenue, or a 13% increase,
more than offset by the combined 14% reduction in revenues due to a decrease in
cash receipts from hedges of $17.7 million (a negative 6%) and an overall
decrease of $22.1 million in commodity prices (or a negative 8%).
During 2000, we paid out $13.3 million ($2.39 per Bbl) on our oil hedges
and $11.9 million ($0.88 per Mcf) on our natural gas hedges. In contrast, during
2001, we collected $1.9 million ($0.31 per Bbl) on our oil hedges and $16.7
million ($0.54 per Mcf) on our natural gas hedges. During 2002, we paid out $0.6
million ($0.09 per Bbl) on our oil hedges but collected a net $1.5 million
($0.04 per Mcf) on our natural gas hedges. See "Market Risk Management" for a
further discussion of our hedging activities.
-35-
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
OPERATING EXPENSES. Oil and natural gas lease operating expenses decreased
2% on a per BOE basis between 2000 and 2001, as a result of the addition of the
Matrix properties in July 2001 and savings resulting from our ownership of CO2
assets purchased in February 2001. These savings were partially offset by
overall higher service and equipment costs in the industry during the year. The
Matrix properties predominately consisted of natural gas, which typically have a
lower per unit operating cost than oil properties. We also reduced operating
expenses by approximately $2.6 million during 2001 because of our acquisition of
the CO2 source fields and operations in February 2001 (see "CO2 Operations"
above).
Our oil and natural gas lease operating expenses increased 13% on a per BOE
basis between 2001 and 2002. This increase was primarily due to higher than
usual workover expenses, principally offshore on the Matrix properties, repairs
relating to storm damage from Hurricane Lili that was not covered by insurance
or was part of the insurance deductible amount, higher per BOE costs due to the
lost production from that storm and Tropical Storm Isidore, and higher than
average operating expenses on the properties acquired from COHO in August 2002,
as significant repairs and clean-up were required. Lastly, as discussed under
"CO2 Operations" above, operating expenses are gradually increasing as a result
of the increased tertiary recovery operations. Lease operating expenses
increased on a gross basis by $16.1 million, or 29%, between the two years.
Operating expenses increased slightly in our non-CO2 flood Mississippi
properties from $6.07 per BOE in 2001 to $6.31 per BOE for 2002, primarily due
to the addition of the COHO properties in late August 2002. Operating expenses
for the COHO properties averaged $9.91 per BOE and are expected to remain
unusually high during the first half of 2003 as we continue to clean up these
fields and perform necessary repairs and maintenance to return these fields to
proper working condition. In comparison, operating costs per BOE for our
long-standing non-CO2 Mississippi properties were $5.21 per BOE in 2000, lower
than the $6.07 per BOE in 2001, with the increase primarily due to higher
overall costs in the industry in 2001. Offshore operating expenses were $5.08
per BOE for 2002, higher than the 2001 average of $3.46 per BOE. The higher
operating expenses generally correlate with the increased number of workovers in
2002 and lower production than anticipated due to the suspended production as a
result of Tropical Storm Isidore and Hurricane Lili. In addition, we had
approximately $750,000 of repairs due to Hurricane Lili which were not covered
by insurance or were part of our insurance deductible expensed in the fourth
quarter of 2002. Operating costs per BOE for 2000 in our limited offshore
operations do not provide a meaningful basis for comparison due to the lower
level of activity prior to the Matrix acquisition. Operating expenses at Little
Creek Field were $9.45 per BOE in 2002, slightly less than the $9.80 per BOE for
2001, due primarily to higher production rates. In comparison, operating costs
per BOE were $11.15 at Little Creek in 2000, with the savings primarily due to
the lower cost of CO2 after the CO2 acquisition in February 2001 and higher
overall production rates.
Production taxes and marketing expenses on a per BOE basis decreased 6%
between 2000 and 2001 and 4% between 2001 and 2002. The decrease in 2002 was
primarily due to a reduction in the Louisiana gas severance tax rate effective
July 1, 2002. The decrease in production taxes and marketing expenses in 2001
was due to the addition of the Matrix properties, a portion of which are tax
exempt due to their offshore location, partially offset by higher marketing
expenses on the offshore properties relating to incremental processing and
transportation costs.
General and Administrative Expenses
During the last three years, general and administrative ("G&A") expenses on
a per BOE basis have fluctuated between $0.89 and $1.09 per BOE. Our gross G&A
expense increased each year, but with our significant production increases, net
G&A expense on a per BOE basis has remained around $1.00 per BOE.
Year Ended December 31,
- ---------------------------------------------------------------------------------------------------------------
Amounts in Thousands Except Per BOE and Employee Data 2002 2001 2000
- ---------------------------------------------------------------------------------------------------------------
Gross G&A expense $ 40,149 $ 33,727 $ 24,941
Operator overhead charges (23,857) (20,328) (13,684)
Capitalized exploration expense (5,325) (4,102) (3,202)
- ---------------------------------------------------------------------------------------------------------------
10,967 9,297 8,055
State franchise taxes 1,459 877 467
- ---------------------------------------------------------------------------------------------------------------
Net G&A expense $ 12,426 $ 10,174 $ 8,522
- ---------------------------------------------------------------------------------------------------------------
Average G&A expense per BOE $ 0.96 $ 0.89 $ 1.09
Employees as of December 31 356 320 242
- ---------------------------------------------------------------------------------------------------------------
-36-
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
We have grown for the last several years from both acquisitions and our own
internal development and exploration work. As a result, we have had general
increases in consultant fees, hired additional personnel, and have given salary
increases and bonuses each year. In particular, we hired additional personnel as
part of the Matrix acquisition in July 2001 and COHO acquisition in August 2002.
Our bonuses, as authorized by our board of directors, were at the upper end of
the bonus plan range in all three years, 2000 through 2002, based primarily on
our overall financial and operating results.
Partially offsetting the overall increase in gross G&A costs are the
increases in operator overhead charges and capitalized exploration expenses. The
respective well operating agreements allow us, when we are the operator, to
charge a specified overhead rate during the drilling phase and to charge a
monthly fixed overhead rate for each producing well. As a result of the general
escalation in activity each year and the addition of more operated wells from
our acquisitions, this recovery of G&A increased from $13.7 million in 2000 to
$20.3 million in 2001 and to $23.9 million in 2002. Capitalized exploration
costs also increased each year as a result of the increase in gross G&A expense
and the additional technical personnel added as part of the Matrix and COHO
acquisitions. As a result, net G&A expense increased only 19% in 2001 and 22% in
2002, even though gross G&A expense increased 35% and 19% respectively. On a per
BOE basis, G&A costs decreased 18% in 2001 but increased 8% in 2002, both
changes less than the absolute change in G&A due to the higher production
volumes each year.
Interest and Financing Expenses
Year Ended December 31,
- ---------------------------------------------------------------------------------------------------------
Amounts in Thousands Except Per BOE Data 2002 2001 2000
- ---------------------------------------------------------------------------------------------------------
Interest expense $ 26,833 $ 22,335 $ 15,255
Non-cash interest expense (2,659) (1,665) (945)
- ---------------------------------------------------------------------------------------------------------
Cash interest expense 24,174 20,670 14,310
Interest and other income (1,746) (849) (2,279)
- ---------------------------------------------------------------------------------------------------------
Net cash interest expense $ 22,428 $ 19,821 $ 12,031
- ---------------------------------------------------------------------------------------------------------
Average net cash interest expense per BOE $ 1.73 $ 1.74 $ 1.54
Average debt outstanding $ 350,556 $ 264,792 $ 160,884
Average interest rate (1) 6.9% 7.8% 8.9%
- ---------------------------------------------------------------------------------------------------------
(1) Includes commitment fees but excludes amortization of debt issue costs.
We began 2000 with $152.5 million of total outstanding debt. During 2000,
we borrowed $61 million to fund property acquisitions and related hedges, but
repaid $14.5 million from cash flow, ending the year with $199 million of
long-term debt outstanding. During 2001, we had total bank borrowings of $146.0
million, primarily to fund our acquisition of Matrix ($100.0 million) and the
CO2 acquisition ($42.0 million). We repaid a total of $79.1 million during the
year, (i) $13.0 million of which related to excess cash flow generated from
operations early in the year given the unusually high natural gas prices and
(ii) $65.9 million of which represented the net proceeds of our issuance of
Series B 9% Senior Subordinated Notes due 2008, in August 2001. These notes were
issued at a discount with an estimated yield to maturity of 10 7/8%. Our total
outstanding debt increased from $199 million as of December 31, 2000, to $340.9
million as of December 31, 2001 (excluding the unamortized issue discount), a
71% increase. Our average interest rate decreased in 2001 due to an overall drop
in interest rates, even though we issued an additional $75 million of
subordinated debt in August at a relatively high interest rate. Overall, we had
a 65% increase in net cash interest expense in 2001, but only a 13% increase on
a BOE basis due to our overall production increases.
During 2002, we borrowed $49.1 million, primarily to fund the COHO
acquisition, and repaid $40.0 million during the year from excess cash flow,
leaving us with $350 million of total debt outstanding as of December 31, 2002
(excluding the discount). On average our debt balance was $85.8 million higher
in 2002 than in 2001 due to the acquisitions during both periods. Our average
interest rate was 0.9% lower in 2002 primarily due to decreases throughout 2001
and 2002 in interest rates on our variable rate bank debt, offset in part by the
issuance of $75 million of subordinated debt in August 2001 which carries a
higher interest rate than the bank debt it replaced. Net cash interest expense
on a per BOE basis decreased 1% between 2001 and 2002 due to our higher
production, an increase in interest and other income in 2002, and a higher
percentage of interest expense relating to non-cash amortization following the
issuance of subordinated debt at a discount in August 2001.
-37-
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Depletion, Depreciation and Site Restoration
Depletion, depreciation and amortization ("DD&A") was at its lowest rate on
a per BOE basis in our history in 1999 as a result of the full cost pool
writedowns in 1998. Since that time, our DD&A rate has increased each year as
our overall finding cost has been greater than the abnormally low rate in 1999,
particularly the finding cost of certain of our acquisitions.
Year Ended December 31,
- --------------------------------------------------------------------------------------------------------
Amounts in Thousands Except Per BOE Data 2002 2001 2000
- --------------------------------------------------------------------------------------------------------
Depletion and depreciation $ 87,728 $ 66,402 $ 34,530
Depreciation of CO2 assets 1,858 1,572 -
Site restoration provision 2,951 1,946 560
Depreciation of other fixed assets 1,699 1,425 1,124
- --------------------------------------------------------------------------------------------------------
Total DD&A $ 94,236 $ 71,345 $ 36,214
- --------------------------------------------------------------------------------------------------------
DD&A per BOE:
Oil and natural gas properties $ 6.98 $ 6.01 $ 4.48
CO2 assets and other fixed assets 0.28 0.26 0.14
- --------------------------------------------------------------------------------------------------------
Total DD&A cost per BOE $ 7.26 $ 6.27 $ 4.62
- --------------------------------------------------------------------------------------------------------
The NYMEX oil prices used in our reserve reports have ranged from $26.80
per Bbl as of December 31, 2000 to $19.84 per Bbl as of December 31, 2001, and
$31.20 per Bbl as of December 31, 2002. Natural gas prices have been even more
volatile, moving from $9.78 per Mcf at December 31, 2000, to $2.57 per Mcf at
December 31, 2001, then to $4.79 per Mcf at December 31, 2002. Even though we
require our proved undeveloped properties to be economic at relatively low
commodity prices, so that their inclusion in our reserves is not dependent on
commodity prices, the fluctuating prices do impact DD&A because of the effect
commodity prices have on the economic lives of our properties (and thus the
changes in reserve quantities). Between 2000 and 2001, the significant reduction
in commodity prices, particularly those for oil, reduced the economic lives of
our properties and reduced reserve quantities by 8.3 MMBOE. Overall, during 2001
we showed a 25% increase in reserve quantities as we added 41.8 MMBOEs from
acquisitions, other development work, and upward revisions. Our total proved
reserve quantities increased from 87.4 MMBOE as of December 31, 2000, to 109.5
MMBOE as of December 31, 2001.
Graph depicting our proved reserves (MMBOE):
December 31,
-----------------------------------------------
2000 2001 2002
------------ ------------ -------------
Oil 70.7 76.5 97.2
Natural Gas 16.7 33.0 33.5
------------ ------------ -------------
Total 87.4 109.5 130.7
During 2002, prices rebounded, increasing our reserve quantities by
approximately 3.5 MMBOE due solely to the price changes. During 2002, we also
added 35.9 MMBOE, primarily from our COHO acquisition and additional reserves
booked on our CO2 tertiary flood properties. Our total proved reserve quantities
increased from 109.5 MMBOE as of December 31, 2001, to 130.7 MMBOE as of
December 31, 2002.
Reserve quantities are only one side of the DD&A equation, with capital
expenditures and projected future development costs making up the remainder of
the calculation. During 2001 our DD&A rate increased from $4.62 per BOE in 2000
to an average rate of $6.27 per BOE ($7.19 per BOE during the second half of the
year after the Matrix acquisition), primarily as result of our acquisition of
Matrix in July 2001. This acquisition had a higher than average cost per BOE
($13.28 per BOE, including unevaluated property costs) because of the high
natural gas price environment. The acquisition itself looks positive, as we have
increased our reserve quantities from this acquisition since the acquisition
closed in July 2001 by 22% (or 55% by adding back production), natural gas
prices are currently above price levels at the time of acquisition, and we still
have most of the probable and possible reserves remaining to exploit. In
addition, the PV10 Value of these properties at December 31, 2002, is
approximately $101.7 million more than our net unrecovered cost.
-38-
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The DD&A calculation is also affected by our future development costs,
which increased from $95.1 million as of December 31, 2000, to $178.5 million as
of December 31, 2001, to $268.3 million as of December 31, 2002. These future
development costs represent the estimated cost necessary to recover our
undeveloped reserves, with the largest single increases relating to the 10.4
MMBbls of reserves recorded at Mallalieu Field in 2001 and 8.3 MMBbls recorded
at McComb Field in 2002. As the overall percentage of undeveloped reserves
relative to our total reserves has increased from approximately 24% in 2001 to
approximately 34% in 2002, so has the amount of future development costs. In
addition, at two of our fields, McComb and North Padre Island, pending further
development work and/or testing, the reserve quantities booked at year-end are
only a portion of what we believe to be each field's ultimate potential. Since
the currently booked proven reserves must bear the total cost of these fields'
required facilities, the future development costs per BOE are higher here than
what we ultimately expect them to be. In summary, even though reserve quantities
were 19% higher in 2002 than in 2001, as a result of the other factors discussed
above, our DD&A rate per BOE of $7.26 in 2002 was relatively unchanged from the
$7.19 DD&A rate per BOE during the last half of 2001 (the rate after the Matrix
acquisition).
We provide for the estimated future costs of well abandonment and site
reclamation, net of any anticipated salvage, on a unit-of-production basis. This
provision is included in DD&A expense and has increased each year, along with
the general increase in the number of our properties, especially the acquisition
of our offshore properties. Beginning January 1, 2003, we are required to adopt
Statement of Financial Accounting Standards No. 143, "Accounting for Asset
Retirement Obligations." With the adoption of this new accounting standard, we
will record the estimated future abandonment cost as an asset and liability on
our balance sheet. While there may be some adjustments as a result of the
adoption of this accounting pronouncement, we do not expect the adoption to
materially impact our income statements going forward as these abandonment costs
have historically been amortized as part of our DD&A.
Under full cost accounting rules, we are required each quarter to perform a
ceiling test calculation. We did not have any full cost pool ceiling test
writedowns in 2000, 2001 or 2002 and do not expect to have any such writedowns
in the foreseeable future at the current commodity price levels.
Income Taxes
For the year ended December 31, 2000, we had taxable income of $27.6
million, but were able to offset this income with our net operating loss
carryforwards ("NOLs"). We did incur $558,000 of current income tax expense
during 2000 which related to alternative minimum taxes that could not be offset
by NOLs. For the year ended December 31, 2000, a normal tax provision would have
resulted in income tax expense of $27.7 million. However, we utilized a portion
of our deferred tax assets and the corresponding valuation allowance to offset
this provision. We also reevaluated the remaining balance of $67.9 million
relating to our net deferred tax asset as of December 31, 2000. We concluded
that it was more likely than not that there would be sufficient future taxable
income that would allow us to realize the tax benefits of our deferred tax
assets, resulting in a deferred tax benefit of $67.9 million and a net deferred
tax asset balance as of December 31, 2001, of $67.9 million, none of which was
impaired.
With the adjustment to deferred taxes in 2000, we began booking a normal
tax provision in 2001. In 2001, we began to recognize the amount of enhanced oil
recovery credits that we had earned to date from our tertiary projects, which
totaled $5.3 million at year-end 2001. As a result of these credits, our
effective tax provision for 2001 was lowered from 37% to 30.5%. Most of this
provision was deferred, as we were able to offset our taxable income with our
NOLs. The current portion of the tax provision related to alternative minimum
taxes that could not be offset by NOLs.
Prior to 2002, our effective tax rate was 37%. During 2002, we determined
that our effective rate had increased to 38% and adjusted our provision for the
year accordingly. The net effective tax rate for 2002 was lower than 38%,
primarily due to the recognition of enhanced oil recovery credits which lowered
our overall tax expense. During 2002 we utilized almost all of our alternative
minimum tax loss carryforwards. Therefore, in 2003 and beyond, a portion of our
tax provision will be current as we will become an alternative minimum tax
payer. As of December 31, 2002, we had approximately $84.9 million of regular
tax net operating loss carryforwards remaining, to shelter our future income
against regular tax.
The overall current income tax credit for 2002 is the result of a tax law
change that allowed us to offset 100% of our 2001 alternative minimum taxes with
our alternative minimum tax net operating loss carryforwards. Prior to the law
change, we were able to offset only 90% of our alternative minimum taxes with
these carryforwards. This change resulted in a refund of cash taxes paid for
2001 and a reclassification of tax expense between current and deferred taxes,
but did not impact our overall effective tax rate.
-39-
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Year Ended December 31,
- -----------------------------------------------------------------------------------------------------------
Amounts in Thousands Except Per Unit Amounts 2002 2001 2000
- -----------------------------------------------------------------------------------------------------------
Current income tax expense (benefit) $ (406) 640 $ 558
Deferred income tax provision (benefit) . 23,926 24,184 (67,852)
- -----------------------------------------------------------------------------------------------------------
Total income tax provision (benefit) $ 23,520 $ 24,824 $ (67,294)
- -----------------------------------------------------------------------------------------------------------
Average income tax provision (benefit) per BOE $ 1.81 $ 2.18 $ (8.59)
Net operating loss carryforwards 84,891 100,601 112,690
- -----------------------------------------------------------------------------------------------------------
Net deferred tax asset (liability) $ (21,777) $ (17,433) $ 67,852
Valuation allowance - - -
- -----------------------------------------------------------------------------------------------------------
Total net deferred tax asset (liability) $ (21,777) $ (17,433) $ 67,852
- -----------------------------------------------------------------------------------------------------------
Results of Operations on a per BOE Basis
The following table summarizes the cash flow, DD&A and results of
operations on a per BOE basis for the comparative periods. Each of the
individual components is discussed above.
Year Ended December 31,
- -----------------------------------------------------------------------------------------------------
Per BOE Data 2002 2001 2000
- -----------------------------------------------------------------------------------------------------
Oil and natural gas revenues $ 21.17 $ 22.88 $ 26.13
Gain (loss) on settlements of derivative contracts 0.07 1.64 (3.23)
Lease operating expenses (5.48) (4.84) (4.94)
Production taxes and marketing expenses (0.92) (0.96) (1.02)
- -----------------------------------------------------------------------------------------------------
Production netback 14.84 18.72 16.94
CO2 operating margin 0.48 0.38 -
General and administrative expenses (0.96) (0.89) (1.09)
Net cash interest expense (1.73) (1.74) (1.54)
Current income taxes and other 0.04 (0.06) (0.07)
Changes in assets and liabilities (0.38) (0.15) (1.99)
- -----------------------------------------------------------------------------------------------------
Cash flow from operations 12.29 16.26 12.25
DD&A (7.26) (6.27) (4.62)
Deferred income taxes (1.84) (2.12) 8.66
Amortization of derivative contracts and other
non-cash hedging adjustments 0.24 (2.90) -
Changes in assets and liabilities and other non-cash
items 0.17 - 1.87
- -----------------------------------------------------------------------------------------------------
Net income $ 3.60 $ 4.97 $ 18.16
- -----------------------------------------------------------------------------------------------------
MARKET RISK MANAGEMENT
We finance some of our acquisitions and other expenditures with fixed and
variable rate debt. These debt agreements expose us to market risk related to
changes in interest rates. The following table presents the carrying and fair
values of our debt, along with average interest rates. The fair value of our
bank debt is considered to be the same as the carrying value because the
interest rate is based on floating short-term interest rates. The fair value of
the subordinated debt is based on quoted market prices. None of our debt has any
triggers or covenants regarding our debt ratings with rating agencies.
Expected Maturity Dates
- -------------------------------------------------------------------------------------------------------------------------
Carrying Fair
Amounts in Thousands 2003-2005 2006 2007 2008 Value Value
- -------------------------------------------------------------------------------------------------------------------------
Variable rate debt:
Bank debt.......................... $ - $ 150,000 $ - $ - $ 150,000 $ 150,000
The weighted-average interest rate on the bank debt at December 31, 2002 is 3.2%.
Fixed rate debt:
Subordinated debt, net of discount. $ - $ - $ - $ 194,889 $ 194,889 $ 206,580
The interest rate on the subordinated debt is a fixed rate of 9%.
-40-
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
We enter into various financial contracts to hedge our exposure to
commodity price risk associated with anticipated future oil and natural gas
production. We do not hold or issue derivative financial instruments for trading
purposes. These contracts have historically consisted of price floors, collars
and fixed price swaps. We generally attempt to hedge between 50% and 75% of our
anticipated production each year to provide us with a reasonably certain amount
of cash flow to cover most of our budgeted exploration and development
expenditures without incurring significant debt. When we make an acquisition, we
attempt to hedge a large percentage, up to 100%, of the forecasted production
for the subsequent one to three years following the acquisition in order to help
provide us with a minimum return on our investment. Our recent hedging activity
has been predominately with collars, although for the recent COHO acquisition,
we also used swaps in order to lock in the prices used in our economic
forecasts. All of the mark-to-market valuations used for our financial
derivatives are provided by external sources and are based on prices that are
actively quoted. We manage and control market and counterparty credit risk
through established internal control procedures which are reviewed on an ongoing
basis. We attempt to minimize credit risk exposure to counterparties through
formal credit policies, monitoring procedures, and diversification.
At December 31, 2002, our derivative contracts were recorded at their fair
value, which was a net liability of approximately $35.6 million, a decrease of
approximately $59.1 million from the $23.5 million fair value asset recorded as
of December 31, 2001. This change is the result of (i) a decrease in the fair
market value of our hedges due to an increase in oil and natural gas commodity
prices between December 31, 2001, and December 31, 2002, (ii) the settlement
received from our former Enron hedge positions in February 2002, and (iii) the
expiration of certain derivative contracts during 2002 for which we recorded
amortization expense of $9.7 million. Information regarding our current hedging
positions and historical hedging results is included in Note 7 to the
Consolidated Financial Statements.
Based on NYMEX natural gas futures prices at December 31, 2002, we would
expect to make future cash payments of $17.2 million on our natural gas
commodity hedges. If natural gas futures prices were to decline by 10%, the
amount we would expect to pay under our natural gas commodity hedges would
decrease to $3.7 million, and if futures prices were to increase by 10% we would
expect to pay $36.1 million. Based on NYMEX crude oil futures prices at December
31, 2002, we would expect to pay $7.5 million on our crude oil commodity hedges.
If crude oil futures prices were to decline by 10%, we would expect to receive
$7.6 million under our crude oil commodity contracts, and if crude oil futures
prices were to increase by 10%, we would expect to pay $25.2 million under our
crude oil commodity hedges. Since December 31, 2002, prices increased
substantially on both oil and natural gas, through at least early March 2003.
CRITICAL ACCOUNTING POLICIES
Our significant accounting policies are included in Note 1 to the
Consolidated Financial Statements. These policies, along with the underlying
assumptions and judgments by our management in their application, have a
significant impact on our consolidated financial statements. We consider our
most critical accounting policies are those related to property and equipment
and hedging activities.
Property, Plant and Equipment, Depletion and Depreciation and Oil and Natural
Gas Reserves
We follow the full-cost method of accounting for oil and natural gas
properties. Under this method of accounting, the estimated quantities of proved
oil and natural gas reserves used to compute depletion and the related present
value of estimated future net cash flows therefrom used to perform the full-cost
ceiling test have a significant impact on the underlying financial statements.
The process of estimating oil and natural gas reserves is very complex,
requiring significant decisions in the evaluation of all available geological,
geophysical, engineering and economic data. The data for a given field may also
change substantially over time as a result of numerous factors, including
additional development activity, evolving production history and continued
reassessment of the viability of production under varying economic conditions.
As a result, material revisions to existing reserve estimates may occur from
time to time. Although every reasonable effort is made to ensure that the
reported reserve estimates represent the most accurate assessments possible,
including the hiring of independent engineers to prepare the report, the
subjective decisions and variances in available data for various fields make
these estimates generally less precise than other estimates included in the
financial statement disclosures.
The changes in commodity prices also affect our reserve quantities. For
instance, between 2000 and 2001, the significant reduction in commodity prices,
particularly oil, reduced the economic lives of our properties and reduced
reserve quantities by 8.3 MMBOE. During 2002, both commodity prices rebounded,
resulting in an increase to our reserve quantities of approximately 3.5 MMBOE.
These changes in quantities affect our DD&A rate and the combined effect of
changes in quantities and commodity
-41-
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
prices impacts our full-cost ceiling test calculation. Also, reserve quantities
and their ultimate values are the primary factors in determining the borrowing
base under our bank credit facility and are determined solely by our banks.
There can also be significant questions as to whether the reserves are
sufficiently supported by technical evidence to be considered proven. In some
cases our proven reserves are less than what we believe to exist because
additional evidence, including production testing, is required in order to
classify the reserves as proven. In other cases, properties such as certain of
our potential tertiary recovery projects may not have proven reserves assigned
to them primarily because we have not yet completed a specific plan for
development or firmly scheduled such development. We have a corporate policy
whereby we do not book proved undeveloped reserves unless the project is
scheduled in our development budget (or at least the commencement of the project
in the case of longer-term multi-year projects such as waterfloods and tertiary
recovery projects). In most cases, our development budget is prepared only for
the next year or so. Therefore, particularly with regard to potential reserves
from tertiary recovery (our CO2 operations), there is uncertainty as to whether
the reserves should be included as proven or not. We also have a corporate
policy whereby proved undeveloped reserves must be economic at long-term
historical prices, which we have interpreted during the last several years as
$18.50 per Bbl of oil and $2.50 per Mcf of natural gas. This also can have the
effect of eliminating certain projects in a high price environment, as was the
case at year-end 2002. (See "CO2 Operations" and "Depletion, Depreciation, and
Site Restoration" under "Results of Operations" above for a further discussion).
All of these factors and the decisions made regarding these issues can have a
significant effect on our proven reserves and thus on our DD&A rate, full-cost
ceiling test calculation, borrowing base and financial statements.
Hedging Activities
We enter into derivative contracts (i.e., hedges) to mitigate our exposure
to commodity price risk associated with future oil and natural gas production.
These contracts have historically consisted of options, in the form of price
floors or collars, and fixed price swaps. With the adoption of SFAS No. 133 in
2001, every derivative instrument must be recorded on the balance sheet as
either an asset or a liability measured at its fair value. If the derivative
does not qualify as a hedge or is not designated as a hedge, the change in fair
value of the derivative is recognized currently in earnings. If the derivative
qualifies for hedge accounting, the change in fair value of the derivative is
recognized in other comprehensive income (equity), to the extent that the hedge
is effective and in the income statement to the extent it is ineffective. We
recognized ineffectiveness on our hedges of $600,000 for 2002.
With the significant changes in commodity prices over the last two years,
the fair value of our hedges has gone from an asset valued at $23.5 million at
year-end 2001 to a liability of $35.6 million as of year-end 2002. While most of
this change in value is recorded in other comprehensive income, the dramatic
swing in commodity prices and the corresponding effect on the fair value of our
hedges can cause a dramatic change to our balance sheet. If these hedges were
deemed to no longer qualify for hedge accounting at some point in time, as
happened to our hedges with Enron in 2001 (see below), then the change in value
would be reflected in our income statement.
In order to qualify for hedge accounting, the changes in fair value or cash
flows of the hedging instruments and the hedged items must have a high degree of
correlation (i.e., be effective). We measure and compute hedge effectiveness on
a quarterly basis. If a hedging instrument becomes ineffective, hedge accounting
is discontinued and any deferred gains or losses on the cash flow hedge remain
in accumulated other comprehensive income until the periods during which the
hedges would have otherwise expired. If we determine it probable that a hedged
forecasted transaction will not occur, deferred gains or losses on the hedging
instrument are recognized in earnings immediately.
All of our current derivative hedging instruments qualify for hedge
accounting. However, during 2001 we had derivative contracts with Enron that
initially qualified for hedge accounting, but their status changed when Enron
filed bankruptcy, causing us to change our accounting treatment of this asset
before the hedge expired. As these hedges no longer qualified for hedge
accounting, we recognized a pre-tax write down of $24.4 million in the fourth
quarter of 2001. As demonstrated by the prior year impact, these adjustments can
be material to our financial statements and are unpredictable.
The preparation of financial statements requires us to make other estimates
and assumptions that affect the reported amounts of certain assets, liabilities,
revenues and expenses during each reporting period. We believe that our
estimates and assumptions are reasonable and reliable and believe that the
ultimate actual results will not differ significantly from those reported;
however, such estimates and assumptions are subject to a number of risks and
uncertainties and such risks and uncertainties could cause the actual results to
differ materially from our estimates.
-42-
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS
In July 2001, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards ("SFAS") No. 143, "Accounting for
Asset Retirement Obligations." SFAS No. 143 requires that the fair value of a
liability for an asset retirement obligation be recorded in the period in which
it is incurred and the corresponding cost capitalized by increasing the carrying
amount of the related long-lived asset. The liability is accreted to its present
value each period, and the capitalized cost is depreciated over the useful life
of the related asset. If the liability is settled for an amount other than the
recorded amount, the difference is recorded to the full cost pool, unless
significant. The standard is effective for us beginning January 1, 2003.
Although we are still finalizing our evaluation of the impact of adopting SFAS
No. 143, we currently believe that the adoption of this standard will result in
an increase to property and equipment and to our accrual for site reclamation
costs, and a charge to income as a cumulative effect adjustment from a change in
accounting principle, net of tax. Historically, we have made an accrual each
period for our future retirement obligations as a part of our DD&A calculation.
The total amount accrued at December 31, 2002 was $6.8 million and is recorded
in our Consolidated Balance Sheets as "Provision for site reclamation costs." We
are still reviewing certain legal obligations and the estimated future periods
in which these costs will be incurred, which information is necessary to
calculate the present value of our future retirement obligations. We presently
estimate our future retirement obligations, before any salvage value recoupment
and before the obligations are discounted for the time value of money, at
approximately $75 million. We estimate the net salvage value for the equipment
associated with these asset retirement obligations to be approximately $40
million, which will be included in our future DD&A calculations.
In November 2002, FASB issued Interpretation ("FIN") No. 45, "Guarantor's
Accounting and Disclosure Requirements for Guarantees, Including Indirect
Guarantees of Indebtedness by Others." FIN No. 45 requires that a guarantor must
recognize, at the inception of the guarantee, a liability for the fair value of
the obligation that it has undertaken in issuing a guarantee. FIN 45 also
addresses the disclosure requirements that a guarantor must include in its
financial statements for guarantees issued. The disclosure requirements of this
interpretation are effective for financial statements ending after December 15,
2002. The initial recognition and measurement provisions of this interpretation
are applicable on a prospective basis to guarantees issued or modified after
December 31, 2002. We have made all relevant disclosures regarding our
guarantees.
FORWARD-LOOKING INFORMATION
The statements contained in this Annual Report on Form 10-K that are not
historical facts, including, but not limited to, statements found in this
Management's Discussion and Analysis of Financial Condition and Results of
Operations, are forward-looking statements, as that term is defined in Section
21E of the Securities and Exchange Act of 1934, as amended, that involve a
number of risks and uncertainties. Such forward-looking statements may be or may
concern, among other things, capital expenditures, drilling activity,
acquisition plans and proposals and dispositions, development activities, cost
savings, production efforts and volumes, hydrocarbon reserves, hydrocarbon
prices, liquidity, regulatory matters, mark-to- market values, and competition.
Such forward-looking statements generally are accompanied by words such as
"plan," "estimate," "expect," "predict," "anticipate," "projected," "should,"
"assume," "believe" or other words that convey the uncertainty of future events
or outcomes. Such forward-looking information is based upon management's current
plans, expectations, estimates and assumptions and is subject to a number of
risks and uncertainties that could significantly affect current plans,
anticipated actions, the timing of such actions and the Company's 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 or on behalf of the Company. Among the
factors that could cause actual results to differ materially are: fluctuations
of the prices received or demand for the Company's oil and natural gas, the
uncertainty of drilling results and reserve estimates, operating hazards,
acquisition risks, requirements for capital, general economic conditions,
competition and government regulations, as well as the risks and uncertainties
discussed in this annual report, including, without limitation, the portions
referenced above, and the uncertainties set forth from time to time in the
Company's other public reports, filings and public statements.
This Annual Report is not deemed to be "soliciting material" or to be
"filed" with the Securities and Exchange Commission or subject to the
liabilities of Section 18 of the Securities Act of 1934, except with respect to
pages 2, 8-11, 14, 16-17, 19-20, 22-25 and 27-70, which are incorporated into
the Company's Annual Report on Form 10-K.
-43-
Independent Auditors' Report
To the Stockholders of Denbury Resources Inc.
We have audited the consolidated balance sheets of Denbury Resources Inc. and
subsidiaries (the "Company") as of December 31, 2002 and 2001 and the related
consolidated statements of operations, stockholders' equity (deficit) and cash
flows for each of the three years in the period ended December 31, 2002. These
consolidated financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these consolidated
financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States of America. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly in all
material respects, the financial position of Denbury Resources Inc. and
subsidiaries as of December 31, 2002 and 2001 and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2002, in conformity with accounting principles generally accepted
in the United States of America.
/s/ Deloitte & Touche LLP
Dallas, Texas
March 3, 2003
-44-
CONSOLIDATED BALANCE SHEETS
AMOUNTS IN THOUSANDS EXCEPT SHARE AMOUNTS DECEMBER 31,
------------------------------
2002 2001
------------- --------------
ASSETS
CURRENT ASSETS
Cash and cash equivalents........................................... $ 23,940 $ 23,496
Accrued production receivables...................................... 34,458 23,411
Related party accrued production receivable - Genesis............... 3,334 -
Trade and other receivables, net of allowance of $207 and $233...... 16,846 31,924
Derivative assets................................................... - 23,458
Deferred tax asset.................................................. 49,886 989
------------- --------------
Total current assets ..................................... 128,464 103,278
------------- --------------
PROPERTY AND EQUIPMENT
Oil and natural gas properties (using full cost accounting)
Proved ......................................................... 1,245,896 1,098,263
Unevaluated..................................................... 45,736 44,521
CO2 properties and equipment........................................ 62,370 45,555
Less accumulated depletion and depreciation......................... (609,917) (520,332)
------------- --------------
Net property and equipment................................... 744,085 668,007
------------- --------------
INVESTMENT IN GENESIS.................................................. 2,224 -
OTHER ASSETS........................................................... 20,519 18,703
------------- --------------
TOTAL ASSETS................................................ $ 895,292 $ 789,988
============= ==============
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable and accrued liabilities............................ $ 49,281 $ 66,498
Oil and gas production payable...................................... 17,309 13,440
Derivative liabilities.............................................. 29,289 -
------------- --------------
Total current liabilities................................... 95,879 79,938
------------- --------------
LONG-TERM LIABILITIES
Long-term debt...................................................... 344,889 334,769
Provision for site reclamation costs................................ 6,845 4,318
Derivative liabilities.............................................. 6,281 -
Deferred tax liability.............................................. 71,663 18,422
Other............................................................... 2,938 3,373
------------- --------------
Total long-term liabilities................................. 432,616 360,882
------------- --------------
COMMITMENTS AND CONTINGENCIES (NOTE 8)
STOCKHOLDERS' EQUITY
Preferred stock, $.001 par value, 25,000,000 shares authorized; none
issued and outstanding............................................. - -
Common stock, $.001 par value, 100,000,000 shares authorized;
53,539,329 and 52,956,825 shares issued and outstanding at
December 31, 2002 and December 31, 2001, respectively.............. 54 53
Paid-in capital in excess of par..................................... 395,906 391,557
Accumulated deficit.................................................. (9,875) (56,670)
Accumulated other comprehensive income (loss)........................ (19,288) 14,228
------------- --------------
Total stockholders' equity.................................. 366,797 349,168
------------- --------------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY.................. $ 895,292 $ 789,988
============= ==============
See Notes to Consolidated Financial Statements.
-45-
CONSOLIDATED STATEMENTS OF OPERATIONS
YEAR ENDED DECEMBER 31,
-------------------------------------------
AMOUNTS IN THOUSANDS EXCEPT PER SHARE AMOUNTS 2002 2001 2000
------------- ----------- ------------
REVENUES
Oil, natural gas and related product sales
Unrelated parties....................................... $ 251,972 $ 260,398 $ 204,636
Related party - Genesis................................. 22,922 - -
CO2 sales.................................................. 7,580 5,210 -
Gain (loss) on settlements of derivative contracts......... 932 18,654 (25,264)
Interest income and other.................................. 1,746 849 2,279
------------- ----------- ------------
Total revenues.......................................... 285,152 285,111 181,651
------------- ----------- ------------
EXPENSES
Lease operating expenses................................... 71,188 55,049 38,676
Production taxes and marketing expenses.................... 11,902 10,963 8,051
CO2 operating expenses..................................... 1,400 891 -
General and administrative expenses........................ 10,967 9,297 8,055
Interest expense........................................... 26,833 22,335 15,255
Depletion and depreciation................................. 94,236 71,345 36,214
Franchise taxes............................................ 1,459 877 467
Loss on Enron related assets............................... - 25,164 -
Amortization of derivative contracts and other non-cash
hedging adjustments....................................... (3,093) 7,816 -
------------- ----------- ------------
Total expenses.......................................... 214,892 203,737 106,718
------------- ----------- ------------
Equity in net income of Genesis................................. 55 - -
------------- ----------- ------------
Income before income taxes...................................... 70,315 81,374 74,933
Income tax provision (benefit)
Current income taxes....................................... (406) 640 558
Deferred income taxes...................................... 23,926 24,184 (67,852)
------------- ----------- ------------
NET INCOME ..................................................... $ 46,795 $ 56,550 $ 142,227
============= =========== ============
NET INCOME PER COMMON SHARE
Basic...................................................... $ 0.88 $ 1.15 $ 3.10
Diluted.................................................... 0.86 1.12 3.07
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING
Basic...................................................... 53,243 49,325 45,823
Diluted.................................................... 54,365 50,361 46,352
See Notes to Consolidated Financial Statements.
-46-
CONSOLIDATED STATEMENTS OF CASH FLOWS
YEAR ENDED DECEMBER 31,
----------------------------------------
AMOUNTS IN THOUSANDS 2002 2001 2000
------------ ------------- ------------
CASH FLOW FROM OPERATING ACTIVITIES:
Net income .................................................... $ 46,795 $ 56,550 $ 142,227
Adjustments needed to reconcile to net cash flow provided
by operations:
Depletion and depreciation................................. 94,236 71,345 36,214
Deferred income taxes...................................... 23,926 24,184 (67,852)
Non-cash loss on Enron related assets...................... - 25,164 -
Amortization of derivative contracts and other non-cash
hedging adjustments..................................... (3,093) 7,816 -
Amortization of debt issue costs and other................. 2,701 1,742 966
Changes in assets and liabilities relating to operations:
Accrued production receivable.............................. (14,381) 19,399 (21,691)
Trade and other receivables................................ 15,078 (17,622) (2,797)
Derivative assets and liabilities.......................... 8,427 (28,043) -
Other assets............................................... 133 863 (5,109)
Accounts payable and accrued liabilities................... (17,217) 23,560 8,586
Oil and gas production payable............................. 3,869 (2,213) 5,038
Other liabilities.......................................... (874) 2,302 390
------------ ------------- ------------
NET CASH PROVIDED BY OPERATING ACTIVITIES......................... 159,600 185,047 95,972
------------ ------------- ------------
CASH FLOW USED FOR INVESTING ACTIVITIES:
Oil and natural gas expenditures............................... (99,273) (170,109) (73,736)
Acquisitions of oil and gas properties......................... (56,364) (97,871) (60,285)
Investment in Genesis.......................................... (2,170) - -
Acquisition of CO2 assets and capital expenditures............. (16,445) (45,555) -
Net purchases of other assets.................................. (3,688) (1,799) (1,629)
Increase in restricted cash.................................... (909) (3,496) (322)
Proceeds from sales of oil and gas properties.................. 7,688 - 2,932
------------ ------------- ------------
NET CASH USED FOR INVESTING ACTIVITIES............................ (171,161) (318,830) (133,040)
------------ ------------- ------------
CASH FLOW FROM FINANCING ACTIVITIES:
Bank repayments................................................ (40,000) (79,130) (14,500)
Bank borrowings................................................ 49,130 146,000 61,000
Issuance of subordinated debt.................................. - 68,528 -
Issuance of common stock....................................... 3,594 2,594 1,491
Costs of debt financing........................................ (719) (3,026) (398)
Other.......................................................... - 20 -
------------ ------------- ------------
NET CASH PROVIDED BY FINANCING ACTIVITIES......................... 12,005 134,986 47,593
------------ ------------- ------------
NET INCREASE IN CASH AND CASH EQUIVALENTS......................... 444 1,203 10,525
Cash and cash equivalents at beginning of year.................... 23,496 22,293 11,768
------------ ------------- ------------
CASH AND CASH EQUIVALENTS AT END OF YEAR.......................... $ 23,940 $ 23,496 $ 22,293
============ ============= ============
See Notes to Consolidated Financial Statements.
-47-
CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS' EQUITY
PAID-IN RETAINED ACCUMULATED
CAPITAL IN EARNINGS OTHER TOTAL
COMMON STOCK EXCESS OF (ACCUMULATED COMPREHENSIVE STOCKHOLDER'S COMPREHENSIVE
($.001 PAR VALUE) PAR DEFICIT) INCOME (LOSS) EQUITY INCOME (LOSS)
---------------------- ----------- ------------ -------------- ------------- --------------
DOLLAR AMOUNTS IN THOUSANDS SHARES AMOUNT
------------- --------
BALANCE - DECEMBER 31, 1999 45,718,486 $ 46 $ 327,829 $ (255,447) $ - $ 72,428
------------- -------- ----------- --------- - ----------- -------------
Issued pursuant to employee stock
purchase plan...................... 218,493 - 1,305 - - 1,305
Issued pursuant to employee stock
option plan........................ 40,458 - 186 - - 186
Issued pursuant to directors
compensation plan.................. 2,544 - 19 - - 19
Net income and comprehensive income.. - - - 142,227 - 142,227 $ 142,227
------------- -------- ----------- ----------- ----------- ------------- -------------
BALANCE - DECEMBER 31, 2000 45,979,981 46 329,339 (113,220) - 216,165 142,227
------------- -------- ----------- ----------- ----------- ------------- =============
Issued pursuant to employee stock
purchase plan...................... 189,485 - 1,546 - - 1,546
Issued pursuant to employee stock
option plan........................ 209,600 - 1,048 - - 1,048
Issued pursuant to directors
compensation plan.................. 7,829 - 63 - - 63
Issued in Matrix acquisition......... 6,569,930 7 59,188 - - 59,195
Tax benefit from stock options....... - - 373 - - 373
Net income........................... - - - 56,550 - 56,550 56,550
Other comprehensive income (loss):
Change in accounting principle for
derivative contracts, net of tax
of $594.......................... - - - - 1,012 1,012 1,012
Reclassification adjustments for
derivative contracts, net of tax
of $594.......................... - - - - (1,012) (1,012) (1,012)
Change in fair value of derivative
contracts, net of tax of $8,356.. - - - - 14,228 14,228 14,228
------------- -------- ----------- ----------- ----------- ------------- -------------
BALANCE - DECEMBER 31, 2001 52,956,825 53 391,557 (56,670) 14,228 349,168 70,778
------------- -------- ----------- ----------- ----------- ------------- =============
Issued pursuant to employee stock
purchase plan...................... 203,893 - 1,928 - - 1,928
Issued pursuant to employee stock
option plan........................ 370,120 1 1,665 - - 1,666
Issued pursuant to directors
compensation plan.................. 8,491 - 82 - - 82
Tax benefit from stock options....... - - 674 - - 674
Net income........................... - - - 46,795 - 46,795 46,795
Other comprehensive income (loss):
Reclassification adjustments for
derivative contracts, net of tax
of $4,919........................ - - - - (7,838) (7,838) (7,838)
Amortization of derivative contracts,
net of tax of $3,598............. - - - - 6,066 6,066 6,066
Change in fair value of derivative
contracts, net of tax of $18,857. - - - - - (31,744) (31,744)
------------- -------- ----------- ----------- ----------- ------------- -------------
BALANCE - DECEMBER 31, 2002 53,539,329 $ 54 $ 395,906 $ (9,875) $ (19,288) $ 366,797 $ 13,279
============= ======== =========== =========== =========== ============= =============
See Notes to Consolidated Financial Statements.
-48-
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1. SIGNIFICANT ACCOUNTING POLICIES
Organization and Nature of Operations
Denbury Resources Inc. is a Delaware corporation, organized under Delaware
General Corporation Law, engaged in the acquisition, development, operation and
exploration of oil and natural gas properties. Denbury has one primary business
segment, which is the exploration, development and production of oil and natural
gas in the U.S. Gulf Coast region. In 2001, we acquired carbon dioxide ("CO2" )
reserves that are used in our tertiary oil recovery operations. In addition, we
sell some CO2 to third parties for industrial uses.
Principles of Reporting and Consolidation
The consolidated financial statements herein have been prepared in accordance
with generally accepted accounting principles ("GAAP") and include the accounts
of Denbury and its subsidiaries, all of which are wholly owned. In 2002, one of
our subsidiaries acquired the general partner of Genesis Energy, L.P.
("Genesis"), a public limited partnership. We account for our 2% interest in
Genesis under the equity method. Even though we have significant influence over
the limited partnership in our role as general partner, because our control is
limited by the general partnership agreement we do not consolidate Genesis. See
Note 2 for more information regarding the Genesis acquisition and summary
financial information. All material intercompany balances and transactions have
been eliminated.
Oil and Natural Gas Operations
A) CAPITALIZED COSTS. We follow the full-cost method of accounting for oil and
natural gas properties. Under this method, all costs related to acquisitions,
exploration and development of oil and natural gas reserves are capitalized and
accumulated in a single cost center representing our activities, which are
undertaken exclusively in the United States. Such costs include lease
acquisition costs, geological and geophysical expenditures, lease rentals on
undeveloped properties, costs of drilling both productive and non-productive
wells and general and administrative expenses directly related to exploration
and development activities and do not include any costs related to production,
general corporate overhead or similar activities. Proceeds received from
disposals are credited against accumulated costs except when the sale represents
a significant disposal of reserves, in which case a gain or loss is recognized.
B) DEPLETION AND DEPRECIATION. The costs capitalized, including production
equipment, are depleted or depreciated on the unit-of- production method, based
on proved oil and natural gas reserves as determined by independent petroleum
engineers. Oil and natural gas reserves are converted to equivalent units based
upon the relative energy content which is six thousand cubic feet of natural gas
to one barrel of crude oil.
C) SITE RECLAMATION. Estimated future costs of well abandonment and site
reclamation, including the removal of production facilities at the end of their
useful life, are provided for on a unit-of-production basis. Costs are based on
engineering estimates of the anticipated method and extent of site restoration,
valued at year-end prices, net of estimated salvage value, and in accordance
with the current legislation and industry practice. The annual provision for
future site reclamation costs is included in depletion and depreciation expense
and reported under long-term liabilities in the Consolidated Balance Sheets as
"Provision for site reclamation costs."
D) CEILING TEST. The net capitalized costs of oil and natural gas properties are
limited to the lower of unamortized cost or the cost center ceiling. The cost
center ceiling is defined as the sum of (i) the present value of estimated
future net revenues from proved reserves (discounted at 10%), based on
unescalated period-end oil and natural gas prices; (ii) plus the cost of
properties not being amortized; (iii) plus the lower of cost or estimated fair
value of unproved properties included in the costs being amortized, if any; (iv)
less related income tax effects. The cost center ceiling test is prepared
quarterly.
E) JOINT INTEREST OPERATIONS. Substantially all of our oil and natural gas
exploration and production activities are conducted jointly with others. These
financial statements reflect only Denbury's proportionate interest in such
activities and any amounts due from other partners are included in trade
receivables.
F) PROVED RESERVES. See Note 10 for information on our proved oil and natural
gas reserves and the basis on which they are recorded.
-49-
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Revenue Recognition
Revenue is recognized at the time oil and natural gas is produced and sold. Any
amounts due from purchasers of oil and natural gas are included in accrued
production receivables.
We follow the "sales method" of accounting for our oil and natural gas revenue,
whereby we recognize sales revenue on all oil or natural gas sold to our
purchasers, regardless of whether the sales are proportionate to our ownership
in the property. A receivable or liability is recognized only to the extent that
we have an imbalance on a specific property greater than the expected remaining
proved reserves. As of December 31, 2002 and 2001, our aggregate oil and natural
gas imbalances were not material to our consolidated financial statements.
We recognize revenue and expenses of purchased producing properties at the time
we assume effective control, commencing from either the closing or purchase
agreement date, depending on the underlying terms and agreements. We follow the
same methodology in reverse when we sell properties by recognizing revenue and
expenses of the sold properties until either the closing or purchase agreement
date, depending on the underlying terms and agreements.
Derivative Instruments and Hedging Activities
We enter into derivative contracts to mitigate our exposure to commodity price
risk associated with future oil and natural gas production. These contracts have
historically consisted of options, in the form of price floors or collars, and
fixed price swaps. On January 1, 2001, we adopted Statement of Financial
Accounting Standards ("SFAS") No. 133, "Accounting for Derivative Instruments
and Hedging Activities," as amended. Upon adoption of SFAS No. 133, we recorded
a $1.6 million increase in our derivative assets to reflect the fair value of
our derivative instruments in place at that time and a corresponding increase to
accumulated other comprehensive income of approximately $1.0 million, net of
tax, in the transition adjustment. This transition adjustment was reclassified
out of accumulated other comprehensive income to earnings over the remainder of
2001.
SFAS No. 133 requires that every derivative instrument be recorded on the
balance sheet as either an asset or a liability measured at fair value. If the
derivative does not qualify as a hedge or is not designated as a hedge, the
change in fair value of the derivative is recognized currently in earnings. If
the derivative qualifies for hedge accounting, the change in fair value of the
derivative is recognized either currently in earnings or deferred in other
comprehensive income (equity) depending on the type of hedge and to what extent
the hedge is effective. All of our current derivative hedging instruments are
cash flow hedges.
In order to qualify for hedge accounting the relationship between the hedging
instruments and the hedged items must be highly effective in achieving the
offset of changes in fair values or cash flows attributable to the hedged risk,
both at the inception of the hedge and on an ongoing basis. We measure hedge
effectiveness on a quarterly basis. Hedge accounting is discontinued
prospectively when a hedging instrument becomes ineffective. We assess hedge
effectiveness based on total changes in the fair value of options used in cash
flow hedges rather than changes of intrinsic value only. As a result, changes in
the entire fair value of option contracts are deferred in accumulated other
comprehensive income, to the extent they are effective, until the hedged
transaction is completed. If a hedge becomes ineffective, any deferred gains or
losses on the cash flow hedge remain in accumulated other comprehensive income
until the underlying production related to the derivative hedge has been
delivered. If it is determined probable that a hedged forecasted transaction
will not occur, and the hedge is not redesignated, deferred gains or losses on
the hedging instrument are recognized in earnings immediately.
Receipts and payments resulting from settlements of derivative hedging
instruments are recorded in "Gain (loss) on settlements of derivative contracts"
included in revenues in the Consolidated Statements of Operations. We apply
Derivative Implementation Group Issue G20 in accounting for our net purchased
puts and collars, which allows the amortization of the cost of net purchased
options over the period of the hedge. We record this amortization and any gains
or losses resulting from hedge ineffectiveness in "Amortization of derivative
contracts and other non-cash hedging adjustments" under expenses in the
Consolidated Statements of Operations. Denbury's hedging activities are further
discussed in Note 7.
Comprehensive Income (Loss)
Our comprehensive income (loss) information is included in our Consolidated
Statements of Stockholders' Equity. All of our adjustments to other
comprehensive income and the balances in accumulated other comprehensive income
(loss) at December 31, 2002 and 2001 relate to our derivative hedging contracts
which are discussed in Note 7.
-50-
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Financial Instruments with Off-Balance-Sheet Risk
and Concentrations of Credit Risk
Our financial instruments that are exposed to concentrations of credit risk
consist primarily of cash equivalents and trade and accrued production
receivables in addition to the derivative hedging instruments discussed above.
Our cash equivalents represent high-quality securities placed with various
investment grade institutions. This investment practice limits our exposure to
concentrations of credit risk. Our trade and accrued production receivables are
dispersed among various customers and purchasers; therefore, concentrations of
credit risk are limited. Also, most of our significant purchasers are large
companies with excellent credit ratings. If customers are considered a credit
risk, letters of credit are the primary security obtained to support lines of
credit. We attempt to minimize our credit risk exposure to the counterparties of
our derivative hedging contracts through formal credit policies, monitoring
procedures and diversification.
CO2 Operations
We own and produce CO2 reserves that are used for our own tertiary oil recovery
operations and, in addition, we sell a portion to third party industrial users.
We record revenue from our sales of CO2 to third parties when it is produced and
sold. CO2 used for our own tertiary oil recovery operations is not recorded as
revenue in the Consolidated Statements of Operations. Expenses related to the
production of CO2 are allocated between volumes sold to third parties and
volumes used for our own use. The expenses related to third party sales are
recorded in "CO2 operating costs" and the expenses related to our own uses are
recorded in "Lease operating costs" in the Consolidated Statements of
Operations. We capitalize acquisitions and the costs of exploring and developing
CO2 reserves. The costs capitalized are depleted or depreciated on the
unit-of-production method, based on proved CO2 reserves as determined by
independent engineers.
Cash Equivalents
We consider all highly liquid investments to be cash equivalents if they have
maturities of three months or less at the date of purchase.
Restricted Cash
At December 31, 2002 and 2001, we had approximately $8.7 million and $7.8
million, respectively, of restricted cash held in escrow for future site
reclamation costs. This restricted cash is included in "Other Assets" in the
Consolidated Balance Sheets.
Net Income Per Common Share
Basic net income per common share is computed by dividing the net income
attributable to common stockholders by the weighted average number of shares of
common stock outstanding during the period. Diluted net income per common share
is calculated in the same manner, but also considers the impact to net income
and common shares for the potential dilution from stock options, stock warrants
and any other outstanding convertible securities.
For each of the three years in the period ended December 31, 2002, there were no
adjustments to net income for purposes of calculating basic and diluted net
income per common share. The following is a reconciliation of the weighted
average shares used in the basic and diluted net income per common share
computations:
YEAR ENDED DECEMBER 31,
---------------------------------------------
AMOUNTS IN THOUSANDS 2002 2001 2000
------------- ------------- -------------
Weighted average common shares - basic.......... 53,243 49,325 45,823
Effect of diluted securities:
Stock options.......................... 1,122 1,036 529
------------- ------------- -------------
Weighted average common shares - diluted 54,365 50,361 46,352
============= ============= =============
We did not include in the diluted shares outstanding calculation 1.7 million
options in 2002, 1.8 million options in 2001 and 1.6 million options in 2000
because their inclusion would be antidilutive as their exercise prices exceeded
the average market price of our common stock during the respective periods.
-51-
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Stock Options
We issue stock options to all of our employees under our stock option plan which
is described more fully in Note 6. We account for our stock option plan
utilizing the recognition and measurement principles of Accounting Principles
Board Opinion 25, "Accounting for Stock Issued to Employees," and its related
interpretations. Under these principles, no stock-based employee compensation
expense is reflected in net income as long as the stock options have an exercise
price equal to the underlying common stock on the date of grant. The following
table illustrates the effect on net income and net income per common share if we
had applied the fair value provisions of SFAS No. 123, "Accounting for
Stock-Based Compensation," in accounting for our stock option plan.
YEAR ENDED DECEMBER 31,
-----------------------------------------
2002 2001 2000
------------ ----------- ------------
NET INCOME: (THOUSANDS)
Net Income, as reported ............................................$ 46,795 $ 56,550 $ 142,227
Less: stock-based compensation expense applying fair value
based method, net of related tax effects.................. 2,866 2,763 2,401
------------ ----------- ------------
Pro forma net income............................................$ 43,929 $ 53,787 $ 139,826
============ =========== ============
NET INCOME PER COMMON SHARE:
As reported:
Basic.......................................................$ 0.88 $ 1.15 $ 3.10
Diluted..................................................... 0.86 1.12 3.07
Pro forma:
Basic.......................................................$ 0.83 $ 1.09 $ 3.05
Diluted..................................................... 0.83 1.09 3.05
The fair value of each option grant was estimated with the Black-Scholes option
pricing model using the following weighted average assumptions:
2002 2001 2000
------------ ------------ ----------
Risk-free interest rate................. 4.05% 4.64% 6.5%
Expected life.......................... 5 years 5 years 5 years
Expected volatility..................... 61.4% 63.4% 55.0%
Dividend yield.......................... - - -
Income Taxes
Income taxes are accounted for using the liability method under which deferred
income taxes are recognized for the future tax effects of temporary differences
between the financial statement carrying amounts and the tax basis of existing
assets and liabilities using the enacted statutory tax rates in effect at year
end. The effect on deferred taxes for a change in tax rates is recognized in
income in the period that includes the enactment date. A valuation allowance for
deferred tax assets is recorded when it is more likely than not that the benefit
from the deferred tax asset will not be realized.
Use of Estimates
The preparation of financial statements in conformity with GAAP requires
management to make estimates and assumptions that affect the reported amount of
certain assets and liabilities and disclosure of contingent assets and
liabilities at the date of the financial statements and the reported amounts of
revenues and expenses during each reporting period. Management believes its
estimates and assumptions are reasonable; however, such estimates and
assumptions are subject to a number of risks and uncertainties that may cause
actual results to differ materially from such estimates. Significant estimates
underlying these financial statements include the fair value of financial
derivative instruments and the estimated quantities of proved oil and natural
gas reserves used to compute depletion of oil and natural gas properties and the
related present value of estimated future net cash flows therefrom.
-52-
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Reclassifications
Certain prior period amounts have been reclassified to conform with the current
year presentation. Such reclassifications had no impact on our reported net
income, current assets, total assets, current liabilities, total liabilities or
stockholders' equity.
Recently Issued Accounting Pronouncements
SFAS No. 143, "Accounting for Asset Retirement Obligations," requires that the
fair value of a liability for an asset retirement obligation be recorded in the
period in which it is incurred and the corresponding cost capitalized by
increasing the carrying amount of the related long-lived asset. The liability is
accreted to its present value each period, and the capitalized cost is
depreciated over the useful life of the related asset. If the liability is
settled for an amount other than the recorded amount, the difference is recorded
to the full cost pool, unless significant. The standard is effective for us
beginning January 1, 2003. Although we are still finalizing our evaluation of
the impact of adopting SFAS No. 143, we currently believe that the adoption of
this standard will result in an increase to property and equipment and to our
accrual for site reclamation costs, and a charge to income as a cumulative
effect adjustment from a change in accounting principle, net of tax.
Historically, we have made an accrual each period for our future retirement
obligations as a part of our DD&A calculation. The total amount accrued at
December 31, 2002 was $6.8 million and is recorded in our Consolidated Balance
Sheets as "Provision for site reclamation costs." We are still reviewing certain
legal obligations and the estimated future periods in which these costs will be
incurred, which information is necessary to calculate the present value of our
future retirement obligations. We presently estimate our future retirement
obligations, before any salvage value recoupment and before the obligations are
discounted for the time value of money, at approximately $75 million. We
estimate the net salvage value for the equipment associated with these asset
retirement obligations to be approximately $40 million, which will be used in
our future DD&A calculations.
In November 2002, FASB issued Interpretation ("FIN") No. 45, "Guarantor's
Accounting and Disclosure Requirements for Guarantees, Including Indirect
Guarantees of Indebtedness by Others." FIN No. 45 requires that a guarantor must
recognize, at the inception of the guarantee, a liability for the fair value of
the obligation that it has undertaken in issuing a gurantee. FIN 45 also
addresses the disclosure requirements that a guarantor must include in its
financial statements for guarantees issued. The disclosure requirements of this
interpretation are effective for financial statements ending after December 15,
2002. The initial recognition and measurement provisions of this interpretation
are applicable on a prospective basis to guarantees issued or modified after
December 31, 2002. We have made all relevant disclosures regarding our
guarantees.
NOTE 2. ACQUISITIONS
COHO Gulf Coast Properties
In August 2002, we acquired COHO Energy, Inc's Gulf Coast properties auctioned
in the U.S. Bankruptcy Court in Dallas, Texas. Our net purchase price, adjusted
for interim cash flow from the June 1, 2002 effective date, together with
purchase adjustments through December 31, 2002, was $48.2 million and included
nine fields, eight of which are located in Mississippi and one in Texas. We
operate all but one of the smaller Mississippi fields. At December 31, 2002,
these properties had proved reserves of approximately 15.1 million barrels of
oil equivalent with net production of approximately 4,000 barrels of oil per
day. The Mississippi fields include interests in the Brookhaven, Laurel,
Martinville, Soso and Summerland Fields, with such interests representing
operational control with working interests in excess of 90%, plus interests in
the smaller Bentonia, Cranfield and Glazier fields. We have hedged nearly 100%
of the forecasted proved developed production relating to this acquisition
through the end of 2004 with no-cost oil swaps (i.e., forward sales). The
average fixed price of these swaps for 2003 is $24.27 per barrel and for 2004 is
$22.94 per barrel.
Subsequent to December 31, 2002, we have sold or have reached an agreement to
sell certain of these fields, which is further discussed in Note 12.
Genesis Energy, L.L.C.
On May 14, 2002, a newly-formed subsidiary of Denbury acquired Genesis Energy,
L.L.C. (which was converted to Genesis Energy, Inc.), the general partner of
Genesis Energy, L.P. ("Genesis"), a publicly traded master limited partnership,
for total consideration, including expenses and commissions, of approximately
$2.2 million. The general partner owns a 2% interest in the limited partnership.
Genesis is engaged in two primary lines of business: crude oil gathering and
marketing and pipeline transportation, primarily in Mississippi, Texas, Alabama
and Florida.
-53-
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
We are accounting for our 2% ownership in Genesis under the equity method as we
have significant influence over the limited partnership; however, our control is
limited under the general partnership agreement and therefore we do not
consolidate Genesis. Our equity in Genesis' net income for 2002 was $55,000,
representing 2% of Genesis' net income for the period from May 14, 2002 through
December 31, 2002. Genesis Energy, Inc., the general partner of which we own
100%, has guaranteed the bank debt of Genesis, which was $5.5 million as of
December 31, 2002, and also included $26.3 million in letters of credit of which
$3.2 million are for Denbury's benefit to secure purchases from Denbury. There
are no guarantees by Denbury or any of its other subsidiaries of the debt of
Genesis or of Genesis Energy, Inc. Our investment of $2.2 million exceeded our
percentage of net equity in the limited partnership at the time of acquisition
by approximately $1.0 million, which represents goodwill and is not subject to
amortization.
Genesis has historically been a purchaser of our crude oil and we anticipate
future purchases of our crude oil production by Genesis. For the year ended
December 31, 2002, we recorded sales to Genesis of $30.0 million and at December
31, 2002, had a production receivable from Genesis of $3.3 million. Our sales to
Genesis from the period May 14, 2002 through December 31, 2002 were $22.9
million and are shown separately as related party sales in our Consolidated
Statements of Operations.
Summarized financial information of Genesis Energy, L.P. is as follows (amounts
in thousands):
Year Ended
December 31,
2002
-------------------
Revenues........................... $ 911,806
Cost of sales...................... 888,691
Other expenses..................... 18,023
-------------------
Net income ..................... $ 5,092
===================
December 31,
2002
-------------------
Current assets..................... $ 92,830
Non-current assets................. 44,707
-------------------
Total assets.................... $ 137,537
===================
Current liabilities................ $ 96,220
Non-current liabilities............ 5,500
Partners' capital.................. 35,817
-------------------
Total liabilities and
partners' capital............. $ 137,537
===================
Other 2002 Acquisitions
We completed other minor acquisitions in 2002 for approximately $12.4 million.
These acquisitions consisted of an additional CO2 well and reserves for $4.3
million, McComb Field, a new tertiary oil recovery field, for $2.3 million, and
other minor acquisitions.
Matrix Oil and Gas, Inc.
On July 10, 2001, we completed the acquisition of Matrix Oil & Gas,
Inc.("Matrix"), an independent oil and gas company based in Covington,
Louisiana. Under the merger agreement, we paid a total of approximately $157.4
million, comprised of $98.2 million (62%) in cash and $59.2 million (38%) in the
form of 6.6 million shares of Denbury's common stock, including post-closing
adjustments. The purchase price was allocated to the net assets acquired based
on estimated fair market values at the date of acquisition, with the predominant
amount allocated to oil and gas properties. As part of our purchase price
allocations, we recorded a deferred income tax liability of $53.1 million to
reflect the difference between the book and carryover tax basis of the
properties acquired, and we allocated $30.0 million of the purchase price to
unevaluated property to reflect the significant probable and possible reserves
that were identified in the acquisition. Based on subsequent drilling activity
and our ongoing evaluation of the undeveloped prospects, we have reclassified
$6.0 million of the original $30.0 million to developed property as of December
31, 2002. Denbury's financial statements include the operations of Matrix from
July 1, 2001.
-54-
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following pro forma information reflects the consolidated financial results
of operations for the years ended December 31, 2001 and 2000, based upon
adjustments to the historical financial statements of Denbury and the historical
financial statements of Matrix as if the acquisition had occurred at the
beginning of such periods presented. The effects of other acquisitions in 2002
and 2001 were not significant for inclusion in the pro forma presentation. Pro
forma amounts are not necessarily indicative of what the actual results would
have been.
YEAR ENDED DECEMBER 31,
---------------------------------------
AMOUNTS IN THOUSANDS EXCEPT PER SHARE AMOUNTS 2001 2000
------------------ ------------------
Revenues................................................... $ 324,401 $ $ 214,473
Expenses................................................... 234,097 147,409
Net income................................................. 62,243 137,387
Income per common share:
Basic................................................... $ 1.18 $ 2.62
Diluted................................................. 1.16 2.60
CO2 Acquisition
On February 2, 2001, we purchased certain CO2 reserves, production and
associated assets from a division of Airgas, Inc., for $42.0 million. The
acquisition included ten producing CO2 wells and production facilities located
near Jackson, Mississippi, and a 183-mile, 20-inch pipeline that is currently
transporting CO2 to our tertiary oil recovery operations at Little Creek and
Mallalieu Fields, as well as to other commercial customers.
Other 2001 Acquisitions
During 2001 we completed other minor acquisitions totaling approximately $5.0
million.
2000 Acquisitions
During the fourth quarter of 2000, Denbury completed acquisitions totaling $56.5
million in the Thornwell, Porte Barre and Iberia Fields located in southwestern
Louisiana. Approximately $10.0 million of these acquisition costs were initially
recorded as unevaluated property costs at December 31, 2000. The Company also
completed other minor acquisitions totaling $3.8 million during 2000.
NOTE 3. PROPERTY AND EQUIPMENT
DECEMBER 31,
----------------------------------------------
AMOUNTS IN THOUSANDS 2002 2001
--------------------- --------------------
Oil and natural gas properties
Proved properties................................. $ 1,245,896 $ 1,098,263
Unevaluated properties............................ 45,736 44,521
--------------------- --------------------
Total.......................................... 1,291,632 1,142,784
Accumulated depletion and depreciation................ (606,488) (518,760)
--------------------- --------------------
Net oil and natural gas properties................. 685,144 624,024
--------------------- --------------------
CO2 properties........................................ 62,370 45,555
Accumulated depletion and depreciation................ (3,429) (1,572)
--------------------- --------------------
Net CO2 properties................................. 58,941 43,983
--------------------- --------------------
Net property and equipment............................ $ 744,085 $ 668,007
===================== ====================
Unevaluated Oil and Natural Gas Properties Excluded From Depletion
Under full cost accounting, we may exclude certain unevaluated costs from the
amortization base pending determination of whether proved reserves have been
discovered or impairment has occurred. A summary of the unevaluated properties
excluded from oil and
-55-
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
natural gas properties being amortized at December 31, 2002 and 2001 and the
year in which they were incurred follows:
DECEMBER 31, 2002 DECEMBER 31, 2001
-------------------------------------------------- --------------------------------------------
Costs Incurred During: Costs Incurred During:
------------------------------------- -----------------------------
2002 2001 2000 Total 2001 2000 Total
------------ ----------- ------------ ------------ -------------- ------------- --------------
AMOUNTS IN THOUSANDS
Property acquisition costs .$ 12,459 $ 22,128 $ 228 $ 34,815 $ 34,195 $ 3,688 $ 37,883
Exploration costs........... 7,526 2,938 457 10,921 5,395 1,243 6,638
------------ ----------- ------------ ------------ -------------- ------------- --------------
Total...................$ 19,985 $ 25,066 $ 685 $ 45,736 $ 39,590 $ 4,931 $ 44,521
============ =========== ============ ============ ============== ============= ==============
Costs are transferred into the amortization base on an ongoing basis as the
projects are evaluated and proved reserves established or impairment determined.
Until we are able to determine whether there are any proved reserves
attributable to the above costs, we are not able to assess the future impact on
the amortization rate. As of December 31, 2002, approximately $24.0 million of
the total unevaluated property balance of $45.7 million related to the Matrix
acquisition. These costs will be transferred into the amortization base as the
undeveloped areas are tested. We anticipate that the majority of this activity
should be completed over the next three to five years.
NOTE 4. NOTES PAYABLE AND LONG-TERM INDEBTEDNESS
DECEMBER 31,
----------------------------
2002 2001
------------ -------------
AMOUNTS IN THOUSANDS
Senior bank loan..................................................$ 150,000 $ 140,870
9% Senior Subordinated Notes due 2008............................. 125,000 125,000
9% Series B Senior Subordinated Notes due 2008.................... 75,000 75,000
Discount on 9% Series B Subordinated Notes due 2008............... (5,111) (6,101)
------------ -------------
Total long-term debt.........................................$ 344,889 $ 334,769
============ =============
Senior Bank Loan
In September 2002, we entered into a Third Amended and Restated Credit Agreement
with our banks which extended the maturity of our bank credit facility from
December 2003 to April 2006. In conjunction with the amended credit agreement,
Bank One became the new administrative agent bank. The facility borrowing base
remained at $220 million, leaving a borrowing capacity of approximately $70
million as of December 31, 2002, and there were no other significant changes as
part of the amendment.
The credit facility is secured by substantially all of our producing oil and
natural gas properties and contains several restrictions including, among
others: (i) a prohibition on the payment of dividends, (ii) a requirement for a
minimum equity balance, (iii) a requirement to maintain positive working
capital, as defined, (iv) a minimum interest coverage test and (v) a prohibition
of most debt and corporate guarantees. We were in compliance with all of our
bank covenants as of December 31, 2002. Our bank credit facility provides for a
semi- annual redetermination of the borrowing base on April 1 and October 1. At
the April 2001 redetermination, our borrowing base was increased from $150
million to $200 million and was further increased at the October 2001
redetermination to $220 million. It has not changed since that time.
As of December 31, 2002, we had $150.0 million outstanding under the facility,
at a weighted average interest rate of 3.2%, $370,000 of letters of credit
outstanding and a borrowing base of $220 million. The next scheduled
redetermination of the borrowing base will be as of April 1, 2003, based on
December 31, 2002 assets and proved reserves.
Subordinated Debt
On February 26, 1998, Denbury Management Inc. ("DMI"), a wholly owned subsidiary
of Denbury at that time, issued $125 million in aggregate principal amount of 9%
Senior Subordinated Notes due 2008 which require only semi-annual interest
payments until maturity. In April 1999, DMI was merged into Denbury Resources
Inc., which expressly assumed all liabilities of DMI, including the 9% Senior
Subordinated Notes. These notes contain certain debt covenants, including
covenants that limit (i) indebtedness, (ii) certain restricted payments
including dividends, (iii) sale/leaseback transactions, (iv) transactions with
affiliates, (v) liens, (vi) asset sales and (vii) mergers and consolidations. We
received net proceeds from the debt offering of approximately $121.8 million
before offering expenses.
-56-
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
During August 2001, Denbury issued an additional $75 million of subordinated
debt in a private placement at 91.371% of face amount for an effective yield of
10.875%. The notes were issued under a separate indenture, but on terms
substantially identical to the existing 9% Senior Subordinated Notes due 2008.
The net proceeds to us were approximately $65.9 million. These notes were
subsequently exchanged for a like principal amount of publicly registered notes.
Interest payments on our $200.0 million of subordinated debt are payable on
March 1 and September 1. Our subordinated debt is callable at our option
beginning March 1, 2003 at the following redemption prices: 104.5% on March 1,
2003, 103.0% on March 1, 2004, 101.5% on March 1, 2005 and 100% on March 1, 2006
and thereafter. There are no sinking fund requirements for our subordinated
debt.
On March 17, 2003, we announced a refinancing of our $200 million of 9% Senior
Subordinated Notes (see Note 12).
Indebtedness Repayment Schedule
Our indebtedness as of December 31, 2002 is repayable as follows:
AMOUNTS IN THOUSANDS
- -------------------------------------------------------
YEAR
2003.......................................$ -
2004....................................... -
2005....................................... -
2006....................................... 150,000
2007....................................... -
Thereafter (2008).......................... 200,000
------------
Total indebtedness..................$ 350,000
============
NOTE 5. INCOME TAXES
Our income tax provision (benefit) is as follows:
YEAR ENDED DECEMBER 31,
---------------------------------------
AMOUNTS IN THOUSANDS 2002 2001 2000
----------- ----------- -----------
Current income tax expense (benefit)
Federal.............................................$ (419) $ 614 $ 558
State............................................... 13 26 -
----------- ----------- -----------
Total current income tax expense (benefit)..... (406) 640 558
----------- ----------- -----------
Deferred income tax expense (benefit)
Federal............................................. 23,926 24,184 (67,852)
State............................................... - - -
----------- ----------- -----------
Total deferred income tax expense (benefit)...... 23,926 24,184 (67,852)
----------- ----------- -----------
Total income tax expense (benefit).........$ 23,520 $ 24,824 $ (67,294)
=========== =========== ===========
Our income tax benefit for 2000 was primarily the result of the elimination of
the valuation allowance on our net deferred tax assets as of December 31, 2000.
This valuation allowance was initially recorded at December 31, 1998 and
remained fully reserved at December 31, 1999, based upon management's belief
that it was more likely than not that we would not be able to generate
sufficient taxable income to realize the benefit of our net deferred tax assets.
In reaching this conclusion, management considered both historical results and
its expectations regarding future taxable income based on oil and gas pricing
consistent with our long-term forecasting and anticipated levels of capital
spending. As a result of the near-term recovery of oil and natural gas prices
that began in the latter part of 1999 and continued throughout 2000, we were
able to generate net income for 2000 and taxable income that utilized
approximately $27.2 million of our net operating losses. Based on expectations
at that time regarding the future and our expectations regarding future taxable
income and our ability to realize the benefit of our deferred tax asset, we
concluded that the valuation allowance on our net deferred tax assets was no
longer necessary and at December 31, 2000 eliminated the entire valuation
allowance.
-57-
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Our current income tax expense in 2001 and 2000 was for alternative minimum
taxes that could not be offset by our alternative minimum tax net operating
losses and conversely, our current income tax benefit in 2002 is primarily
related to tax law changes in 2002 that allowed us to receive a refund of our
alternative minimum taxes paid for 2001.
At December 31, 2002, we had net operating loss carryforwards for U.S. federal
income tax purposes of $84.9 million and $4.2 million for alternative minimum
tax purposes. During 2002 and 2001, we utilized approximately $16 million and
$23 million, respectively, of regular and alternative minimum net operating
losses to minimize our current tax position. As a result of the acquisition of
Matrix and other prior ownership changes, the utilization of some of our net
operating loss carryforwards is subject to limitations imposed by the Internal
Revenue Code of 1986. However, we do not expect such limitations to have an
effect on our ability to use these net operating loss carryforwards. Our net
operating loss carryforwards are scheduled to expire as follows:
INCOME ALTERNATIVE
AMOUNTS IN THOUSANDS TAX MINIMUM TAX
- ----------------------------------------------------- ---------------
YEAR
2018 ................................. $ 61,882 $ -
2019 ................................. 21,080 3,853
2020 ................................. 826 193
2021 ................................. 1,073 127
2022 ................................. 30 30
In 2001, we began to recognize a benefit for the amount of enhanced oil recovery
credits earned from our tertiary recovery projects. The total credits earned to
date is approximately $9.9 million. These credits begin to expire in 2020.
Deferred income taxes relate to temporary differences based on tax laws and
statutory rates in effect at the December 31, 2002 and 2001 balance sheet dates.
At December 31, 2002 and 2001, our deferred tax assets and liabilities were as
follows:
DECEMBER 31,
---------------------------
AMOUNTS IN THOUSANDS 2002 2001
------------ ------------
Deferred tax assets:
Loss carryforwards................................ $ 32,266 $ 37,222
Tax credit carryover.............................. 1,069 1,403
Enhanced oil recovery credit carryforwards........ 9,927 5,280
Derivative hedging contracts...................... 11,822 -
Other............................................. 79 -
------------ ------------
Total deferred tax assets....................... 55,163 43,905
------------ ------------
Deferred tax liabilities:
Property and equipment............................ (76,940) (52,449)
Derivative hedging contracts...................... - (8,356)
Other............................................. - (533)
------------ ------------
Total deferred tax liabilities.................. (76,940) (61,338)
------------ ------------
Total net deferred tax liability................ $ (21,777) $ (17,433)
============ ============
Our income tax provision (benefit) varies from the amount that would result from
applying the federal statutory income tax rate to income before income taxes as
follows:
YEAR ENDED DECEMBER 31,
-----------------------------------------
AMOUNTS IN THOUSANDS 2002 2001 2000
------------ ------------ -------------
Income tax provision calculated using the
federal statutory income tax rate..................... $ 24,587 $ 28,481 $ 26,227
State income taxes and other............................. 2,327 1,623 1,616
Change in valuation allowance............................ - - (95,137)
Enhanced oil recovery credits............................ (3,394) (5,280) -
------------ ------------ -------------
Total income tax expense (benefit)................... $ 23,520 $ 24,824 $ (67,294)
============ ============ =============
-58-
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 6. STOCKHOLDERS' EQUITY
Authorized
We are authorized to issue 100 million shares of common stock, par value $.001
per share, and 25 million shares of preferred stock, par value $.001 per share.
The preferred shares may be issued in one or more series with rights and
conditions determined by the board of directors.
Stock Option Plan
As of December 31, 2002, we had a total of 7,345,587 shares of common stock
authorized for issuance pursuant to our Stock Option Plan, of which 1,117,347
shares were available for issuance. Denbury's board of directors has authorized
an additional 850,000 shares for this plan, subject to the approval of
shareholders at the May 20, 2003 annual meeting. Under the terms of the plan,
incentive and non-qualified options may be issued to officers, key employees and
consultants. Options generally become exercisable over a four-year vesting
period with the specific terms of vesting determined by the board of directors
at the time of grant. The options expire over terms not to exceed ten years from
the date of grant, 90 days after termination of employment or permanent
disability or one year after the death of the optionee. The options are granted
at the fair market value at the time of grant, which is generally defined as the
average closing price of our common stock for the ten trading days prior to
issuance. The plan is administered by the Stock Option Committee of Denbury's
board of directors.
The following is a summary of our stock option activity:
YEAR ENDED DECEMBER 31,
------------------------------------------------------------------------------------
2002 2001 2000
-------------------------- ---------------------------- ---------------------------
Number Weighted Number Weighted Number Weighted
of Options Average Price of Options Average Price of Options Average Price
----------- -------------- ------------ --------------- ------------ --------------
OUTSTANDING AT BEGINNING OF YEAR... 4,616,333 $ 8.40 3,802,122 $ 8.03 3,317,384 $ 8.66
Granted............................ 921,341 7.50 1,222,141 9.00 595,635 4.11
Exercised.......................... (370,120) 4.51 (209,600) 5.00 (40,458) 4.60
Forfeited.......................... (170,079) 10.30 (198,330) 8.53 (70,439) 6.70
----------- -------------- ------------ --------------- ------------ --------------
OUTSTANDING AT END OF YEAR......... 4,997,475 $ 8.46 4,616,333 $ 8.40 3,802,122 $ 8.03
=========== ============== ============ =============== ============ ==============
Exercisable at end of year......... 2,267,497 $ 10.26 1,858,072 $ 9.49 1,310,382 $ 9.35
=========== ============== ============ =============== ============ ==============
Weighted average fair value of
options granted................. $ 4.17 $ 5.19 $ 2.26
============== =============== ==============
The following is a summary of stock options outstanding at December 31, 2002:
Options Outstanding Options Exercisable
--------------------------------------------- -----------------------------
Weighted
Number Average Number
of Options Remaining Weighted of Options Weighted
Outstanding at Contractual Average Exercisable at Average
Range of Exercise Prices 12/31/02 Life Exercise Price 12/31/02 Exercise Price
- ------------------------------ --------------- -------------- ------------- -------------- -------------
$ 3.77 - $ 5.50 1,549,501 6.3 $ 4.16 694,420 $ 4.24
5.51 - 8.00 1,053,500 7.7 7.00 238,859 6.75
8.01 - 11.50 1,393,734 7.8 9.24 333,478 9.46
11.51 - 14.50 566,738 3.9 13.38 566,738 13.38
14.51 - 22.25 434,002 4.8 18.38 434,002 18.38
--------------- -------------------------------------------------------------------------------
$13.77 - $22.25 4,997,475 6.6 $ 8.46 2,267,497 $ 10.26
--------------- -------------------------------------------------------------------------------
Stock Purchase Plan
We have a Stock Purchase Plan that is authorized to issue up to 1,750,000 shares
of common stock to all full-time employees. As of December 31, 2002, there are
593,272 authorized shares remaining to be issued under the plan. In accordance
with the plan, employees may contribute up to 10% of their base salary and
Denbury matches 75% of their contribution. The combined funds are used to
purchase previously unissued Denbury common stock at its current market value at
the end of each quarter. We recognize compensation expense for the 75% company
matching portion, which totaled $822,000, $666,000 and $560,000 for
-59-
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
the years ended December 31, 2002, 2001 and 2000, respectively. This plan is
administered by the Stock Purchase Plan Committee of Denbury's board of
directors.
401(k) Plan
Denbury offers a 401(k) Plan to which employees may contribute tax deferred
earnings subject to Internal Revenue Service limitations. Up to 3% of an
employee's compensation, as defined by the plan, is matched by Denbury at 100%
and an employee's contribution between 3% and 6% of compensation is matched by
Denbury at 50%. Denbury's match is vested immediately. During 2002, 2001 and
2000, Denbury's matching contributions were $884,000, $670,000 and $427,000,
respectively, to the 401(k) Plan.
NOTE 7. DERIVATIVE HEDGING CONTRACTS
We enter into various financial contracts to hedge our exposure to commodity
price risk associated with anticipated future oil and natural gas production. We
do not hold or issue derivative financial instruments for trading purposes.
These contracts have historically consisted of price floors, collars and fixed
price swaps. We generally attempt to hedge between 50% and 75% of our
anticipated production each year to provide us with a reasonably certain amount
of cash flow to cover most of our budgeted exploration and development
expenditures without incurring significant debt. When we make an acquisition, we
attempt to hedge a large percentage, up to 100%, of the forecasted production
for the subsequent one to three years following the acquisition in order to help
provide us with a minimum return on our investment. Our recent hedging activity
has been predominately with collars, although for the recent COHO acquisition,
we also used swaps in order to lock in the prices used in our economic
forecasts. All of the mark-to-market valuations used for our financial
derivatives are provided by external sources and are based on prices that are
actively quoted. We manage and control market and counterparty credit risk
through established internal control procedures which are reviewed on an ongoing
basis. We attempt to minimize credit risk exposure to counterparties through
formal credit policies, monitoring procedures, and diversification.
The following is a summary of the net gain (loss) representing cash receipts and
payments on our hedge settlements:
Year Ended December 31,
---------------------------------------------------------
2002 2001 2000
----------------- ----------------- -----------------
Oil hedge contracts $ (598) $ 1,925 $ (13,332)
Gas hedge contracts 1,530 16,729 (11,932)
----------------- ----------------- -----------------
Net gain (loss) $ 932 $ 18,654 $ (25,264)
================= ================= =================
Some of our derivative contracts require us to pay a premium which we amortize
over the contract periods. This expense is included in "Amortization of
derivative contracts and other non-cash hedging adjustments" in our Consolidated
Statements of Operations. For the years ended December 31, 2002 and 2001, we
recorded premium amortization expense of $9.7 million and $5.3 million,
respectively. Also, for the year ended December 31, 2002, we reclassified $13.4
million related to our former Enron hedges (discussed below) out of accumulated
other comprehensive income into income and recorded hedge ineffectiveness of
$600,000 which is also included in "Amortization of derivative contracts and
other non-cash hedging adjustments."
Loss on Enron Hedges
In conjunction with the acquisition of Matrix in July 2001, we purchased
commodity hedges to protect our investment. These hedges, in the form of price
floors, covered nearly all of the forecasted production from the acquired
properties through the end of 2003 at floor prices ranging from $3.75 to $4.25
per MMBtu. Due to the falling natural gas prices in the latter half of 2001, we
collected approximately $12.7 million on these hedges. The price floors relating
to 2002 and 2003 were purchased from Enron Corporation, which filed bankruptcy
in December 2001. We sold our bankruptcy claim against Enron in February 2002
for net proceeds of approximately $9.2 million. In total, we collected
approximately $21.9 million from the price floors relating to the Matrix
acquisition, resulting in a net cash gain of approximately $3.9 million over the
cost of the floors. Because of the rise in natural gas prices since December
2001, based on the futures prices as of March 1, 2003, we would not have
collected anything on the price floors relating to 2003 even if Enron had not
filed bankruptcy as the current market price is above $3.75 (the floor price for
2003). We estimate that our total cash loss due to Enron's bankruptcy was
approximately $5.4 million, representing the difference between what we would
have collected during 2002 and the $9.2 million that we obtained from selling
the bankruptcy claim.
-60-
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
When Enron filed for bankruptcy during the fourth quarter of 2001, our Enron
hedges ceased to qualify for hedge accounting treatment, which changed the
accounting treatment for those hedges as of that point in time as required by
SFAS No. 133. The result is that any future changes in the current market value
of these assets must be reflected in the income statement and any remaining
accumulated other comprehensive income at the time of the accounting change must
be recognized over the original expected life of the hedges. To adjust the value
of the Enron hedges down to the market value at December 31, 2001, which was
determined to be the amount that we received from the sale of our claims in
February 2002, we recorded a pre-tax write down of $24.4 million in the fourth
quarter of 2001. We also had a claim against Enron for production receivables
relating to November 2001 natural gas production that was also sold in February
2002, which resulted in an overall total pre-tax loss on our Enron related
assets of $25.2 million. The after-tax balance in accumulated other
comprehensive income related to these Enron hedges was approximately $11.6
million at the point they no longer qualified for hedge accounting. Accordingly,
we recognized pre-tax income attributable to the Enron hedges during 2002 of
approximately $13.4 million and will recognize pre-tax income during 2003 of
approximately $5.1 million. The three year total pre-tax net loss on the Enron
hedges will be approximately $5.9 million, which approximates the difference
between the amount collected and paid for the Enron portion of the Matrix price
floors.
Hedging Contracts at December 31, 2002
CRUDE OIL CONTRACTS:
- -------------------
NYMEX Contract Prices Per Bbl
------------------------------------------------------------
Collar Prices
--------------------------
Fair Value at
Type of Contract and Period Bbls/d Swap Price Floor Price Floor Ceiling December 31, 2002
- ---------------------------------- -------------- -------------- ------------- ----------- ------------ -----------------
Collar Contracts
Jan. 2003 - Dec. 2003 10,000 $ - $ - $ 20.00 $ 30.00 $ (2,077)
-
Swap Contracts
Jan. 2003 - Dec. 2003 2,500 24.25 - - - (2,403)
Jan. 2003 - Dec. 2003 2,000 24.30 - - - (1,886)
Jan. 2003 - Dec. 2003 2,000 25.70 - - - (872)
Jan. 2004 - Dec. 2004 2,500 22.89 - - - (415)
Jan. 2004 - Dec. 2004 4,500 23.00 - - - (571)
Jan. 2004 - Dec. 2004 2,500 23.08 - - - (246)
NATURAL GAS CONTRACTS:
- ---------------------
NYMEX Contract Prices Per MMBtu
-------------------------------------------------------------
Collar Prices
---------------------------- Fair Value at
Type of Contract and Period MMBtu/d Swap Price Floor Price Floor Ceiling December 31, 2002
- ----------------------------------- ------------- -------------- ------------- ------------- ----------- -----------------
Collar Contracts
Jan. 2003 - Dec. 2003 45,000 $ - $ - $ 2.75 $ 4.00 $ (12,866)
Jan. 2003 - Dec. 2003 25,000 - - 2.75 4.07 (6,738)
Jan. 2004 - Dec. 2004 30,000 - - 3.50 4.45 (3,278)
Jan. 2004 - Dec. 2004 15,000 - - 3.00 5.87 (774)
Jan. 2004 - Dec. 2004 15,000 - - 3.00 5.82 (808)
Jan. 2005 - Dec. 2005 15,000 - - 3.00 5.50 (189)
Swap Contracts
Jan. 2003 - Dec. 2003 10,000 3.905 - - - (2,448)
At December 31, 2002, our derivative contracts were recorded at their fair
value, which was a net liability of $35.6 million. To the extent our hedges are
considered effective, this fair value liability, net of income taxes, is
included in Accumulated other comprehensive income (loss) reported under
Stockholders' equity in our Consolidated Balance Sheets. The balance in
accumulated other comprehensive loss of $19.3 million at December 31, 2002,
represents the deficit in the fair market value of our derivative contracts as
compared to the cost of our hedges, net of income taxes, and also includes the
remaining accumulated other comprehensive income of $3.1 million relating to the
Enron hedges that ceased to qualify for hedge accounting treatment when Enron
filed for bankruptcy. This $3.1 million relating to the former Enron hedges will
be reclassified out of accumulated other comprehensive income during 2003, over
the periods that the hedges would have otherwise expired. Of the
-61-
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
$19.3 million in accumulated other comprehensive loss as of December 31, 2002,
$15.4 million relates to current hedging contracts that will expire within the
next 12 months and $3.9 million relates to contracts that expire after December
31, 2003.
NOTE 8. COMMITMENTS AND CONTINGENCIES
We have operating leases for the rental of office space, office equipment, and
vehicles that totaled $1.7 million, $1.6 million and $1.4 million for the years
ended December 31, 2002, 2001 and 2000, respectively. At December 31, 2002,
long-term commitments for these items require the following future minimum
rental payments:
AMOUNTS IN THOUSANDS
2003............................. $ 1,708
2004............................. 1,640
2005............................. 1,764
2006............................. 1,766
2007............................. 1,761
Thereafter ...................... 3,022
----------
Total lease commitments..... $ 11,661
==========
We have future capital expenditure obligations related to field development
costs that total $13.0 million over the next five years, of which $2.3 million
is required to be spent in 2003.
Long-term contracts require us to deliver CO2 to our industrial CO2 customers.
Based upon the maximum amounts deliverable as stated in the contracts, we
estimate that we may be obligated to deliver up to 387 Bcf of CO2 to these
customers over the next 18 years; however, based on the current level of
deliveries, our commitment would be reduced to approximately 250 Bcf. Also, in
the unforeseen circumstance that we could not deliver all of the volumes under
these contracts, we could reduce our deliveries to all parties proportionately
with the exception of one party, which has preferential rights under their
contract. Given the size of our proven CO2 reserves (approximately 1.6 Tcf), our
current production capabilities and our predicted levels of CO2 usage for our
own tertiary flooding program, we are confident that we can meet these delivery
obligations.
Denbury is subject to various possible contingencies which arise primarily from
interpretation of federal and state laws and regulations affecting the oil and
natural gas industry. Such contingencies include differing interpretations as to
the prices at which oil and natural gas sales may be made, the prices at which
royalty owners may be paid for production from their leases, environmental
issues and other matters. Although management believes that it has complied with
the various laws and regulations, administrative rulings and interpretations
thereof, adjustments could be required as new interpretations and regulations
are issued. In addition, production rates, marketing and environmental matters
are subject to regulation by various federal and state agencies.
We are involved in various lawsuits, claims and regulatory proceedings
incidental to our businesses. In the opinion of management, the outcome of such
matters will not have a material adverse effect on our consolidated financial
position, results of operations or cash flows.
NOTE 9. SUPPLEMENTAL INFORMATION
Significant Oil and Natural Gas Purchasers
Oil and natural gas sales are made on a day-to-day basis or under short-term
contracts at the current area market price. The loss of any purchaser would not
be expected to have a material adverse effect upon our operations. For the year
ended December 31, 2002, we had two significant purchasers that each accounted
for 10% or more of our oil and natural gas revenues: Hunt Refining (14%) and
Genesis (11%). For the year ended December 31, 2001, four purchasers each
accounted for 10% or more of our oil and natural gas revenues: Conoco (14%),
Hunt Refining (13%), EOTT Energy (12%), and Dynegy (12%). For the year ended
December 31, 2000, four purchasers each accounted for 10% or more of our oil and
natural gas revenues: Hunt Refining (24%), Southland Refining (17%), EOTT Energy
(16%), and Dynegy (10%).
-62-
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Accounts Payable and Accrued Liabilities
DECEMBER 31,
----------------------------
AMOUNTS IN THOUSANDS 2002 2001
------------- -------------
Accounts payable............................. $ 25,545 $ 37,718
Accrued exploration and development costs.... 9,935 16,198
Accrued interest............................. 6,248 6,976
Other........................................ 7,553 5,606
------------- -------------
Total..................................... $ 49,281 $ 66,498
============= =============
Supplemental Cash Flow Information
YEAR ENDED DECEMBER 31,
----------------------------------------
AMOUNTS IN THOUSANDS 2002 2001 2000
------------ ------------ ----------
Interest paid........................... $24,636 $17,451 $13,936
Income taxes paid (refunded)............ (1,304) 2,482 275
In 2001, in connection with our acquisition of Matrix, we recorded non-cash
increases to property and equipment resulting from the issuance of common stock
in the amount of $59.2 million and the recording of deferred taxes in the amount
of $53.1 million.
Fair Value of Financial Instruments
DECEMBER 31,
------------------------------------------------------
2002 2001
------------------------- ---------------------------
Carrying Estimated Carrying Estimated
AMOUNTS IN THOUSANDS Amount Fair Value Amount Fair Value
------------ ------------ ------------ --------------
Senior bank debt................................. $ 150,000 $ 150,000 $ 140,870 $ 140,870
9% Senior Subordinated Notes due 2008............ 125,000 129,113 125,000 117,500
9% Series B Senior Subordinated Notes due 2008... 69,889 77,468 68,899 70,500
As of December 31, 2002 and 2001, the carrying value of our bank debt
approximated fair value based on the fact that our bank debt is subject to
short-term floating interest rates that approximated the rates available to us
at those periods. The fair values of our senior subordinated notes are based on
quoted market prices. We have other financial instruments consisting primarily
of cash, cash equivalents, short-term receivables and payables which approximate
fair value due to the nature of the instrument and the relatively short
maturities.
NOTE 10. SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES (UNAUDITED)
Costs Incurred
The following table summarizes costs incurred and capitalized in oil and natural
gas property acquisition, exploration and development activities. Property
acquisition costs are those costs incurred to purchase, lease, or otherwise
acquire property, including both undeveloped leasehold and the purchase of
reserves in place. Exploration costs include costs of identifying areas that may
warrant examination and examining specific areas that are considered to have
prospects containing oil and natural gas reserves, including costs of drilling
exploratory wells, geological and geophysical costs and carrying costs on
undeveloped properties. Development costs are incurred to obtain access to
proved reserves, including the cost of drilling development wells, and to
provide facilities for extracting, treating, gathering and storing the oil and
natural gas.
-63-
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Costs incurred in oil and natural gas activities were as follows:
YEAR ENDED DECEMBER 31,
-----------------------------------------
AMOUNTS IN THOUSANDS 2002 2001 2000
----------- ----------- -----------
Property acquisitions:
Proved (1)....................... $ 56,364 $ 127,066 $ 50,285
Unevaluated...................... 4,342 37,051 11,741
Exploration......................... 13,493 11,692 6,782
Development......................... 81,438 151,366 65,213
----------- ----------- -----------
Total costs incurred (2)......... $ 155,637 $ 327,175 $ 134,021
=========== =========== ===========
(1) Excludes deferred taxes recorded in the acquisition of Matrix of $53.1
million in 2001.
(2) Capitalized general and administrative costs that directly relate to
exploration and development activities were $5.3 million, $4.1 million and $3.2
million for the years ended December 31, 2002, 2001 and 2000, respectively.
Oil and Natural Gas Operating Results
Results of operations from oil and natural gas producing activities, excluding
corporate overhead and interest costs, were as follows:
YEAR ENDED DECEMBER 31,
----------------------------------------------------
AMOUNTS IN THOUSANDS 2002 2001 2000
----------------- --------------- ----------------
Oil, natural gas and related product sales................................. $ 274,894 $ 260,398 $ 204,636
Gain (loss) on settlements of derivative contracts......................... 932 18,654 (25,264)
----------------- --------------- ----------------
Total revenues.......................................................... 275,826 279,052 179,372
----------------- --------------- ----------------
Lease operating costs...................................................... 71,188 55,049 38,676
Production taxes and marketing expenses.................................... 11,902 10,963 8,051
Depletion and depreciation................................................. 90,679 69,773 36,214
Loss on Enron related assets............................................... - 25,164 -
Amortization of derivative contracts and other non-cash hedging
adjustments............................................................. (3,093) 7,816 -
----------------- --------------- ----------------
Net operating income.................................................... 105,150 110,287 96,431
Income tax provision (benefit)............................................. 36,563 35,526 (67,294)
----------------- --------------- ----------------
Results of operations from oil and natural gas producing activities........ $ 68,587 $ 74,761 $ 163,725
================= =============== ================
Depletion and depreciation per BOE......................................... $ 6.98 $ 6.01 $ 4.48
================= =============== ================
Oil and Natural Gas Reserves
Net proved oil and natural gas reserve estimates for all years presented were
prepared by DeGolyer and MacNaughton, independent petroleum engineers located in
Dallas, Texas. The reserves were prepared in accordance with guidelines
established by the Securities and Exchange Commission and, accordingly, were
based on existing economic and operating conditions. Oil and natural gas prices
in effect as of the reserve report date were used without any escalation. (See
"Standardized Measure of Discounted Future Net Cash Flows and Changes Therein
Relating to Proved Oil and Natural Gas Reserves" below for a discussion of the
effect of the different prices on reserve quantities and values.) Operating
costs, production and ad valorem taxes and future development costs were based
on current costs with no escalation.
We have a corporate policy whereby we do not book proved undeveloped reserves
unless the project is scheduled in our development budget (or at least the
commencement of the project in the case of longer-term multi-year projects such
as waterfloods and tertiary recovery projects). In most cases our development
budget is only prepared for the next year or so. We also have a corporate policy
whereby proved undeveloped reserves must be economic at low to moderate
commodity prices, which for 2002 and the prior two years we set at $18.50 per
Bbl of oil and $2.50 per Mcf of natural gas.
There are numerous uncertainties inherent in estimating quantities of proved
reserves and in projecting the future rates of production and timing of
development expenditures. The following reserve data represents estimates only
and should not be construed as being exact. Moreover, the present values should
not be construed as the current market value of our oil and natural gas reserves
or the costs that would be incurred to obtain equivalent reserves. All of our
reserves are located in the United States.
-64-
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Estimated Quantities of Reserves
YEAR ENDED DECEMBER 31,
-----------------------------------------------------------------------
2002 2001 2000
---------------------- ---------------------- ----------------------
Oil Gas Oil Gas Oil Gas
(MBbl) (MMcf) (MBbl) (MMcf) (MBbl) (MMcf)
--------- ---------- ---------- --------- --------- ----------
BALANCE AT BEGINNING OF YEAR................ 76,490 198,277 70,667 100,550 51,832 50,438
Revisions of previous estimates........ (408) (22,975) 4,344 (631) 4,078 8,271
Revisions due to price changes......... 3,020 2,660 (7,800) (2,745) 412 1,905
Extensions and discoveries............. 2,326 51,819 2,308 66,448 2,746 25,593
Improved recovery (1).................. - - 1,667 - 16,466 5,613
Production............................. (6,874) (36,662) (6,197) (31,112) (5,555) (13,533)
Acquisition of minerals in place....... 23,383 9,360 11,501 65,767 1,182 23,209
Sales of minerals in place............. (734) (1,532) - - (494) (946)
--------- ---------- ---------- --------- --------- ----------
BALANCE AT END OF YEAR...................... 97,203 200,947 76,490 198,277 70,667 100,550
========= ========== ========== ========= ========= ==========
PROVED DEVELOPED RESERVES
Balance at beginning of year........... 54,722 169,897 52,353 77,358 32,767 41,635
Balance at end of year................. 62,398 142,812 54,722 169,897 52,353 77,358
(1) Improved recovery additions result from the application of secondary
recovery methods such as waterflooding or tertiary recovery methods such as CO2
flooding.
Standardized Measure of Discounted Future Net Cash Flows and
Changes Therein Relating to Proved Oil and Natural Gas Reserves
The Standardized Measure of Discounted Future Net Cash Flows and Changes Therein
Relating to Proved Oil and Natural Gas Reserves ("Standardized Measure") does
not purport to present the fair market value of our oil and natural gas
properties. An estimate of such value should consider, among other factors,
anticipated future prices of oil and natural gas, the probability of recoveries
in excess of existing proved reserves, the value of probable reserves and
acreage prospects, and perhaps different discount rates. It should be noted that
estimates of reserve quantities, especially from new discoveries, are inherently
imprecise and subject to substantial revision.
Under the Standardized Measure, future cash inflows were estimated by applying
year-end prices, adjusted for fixed and determinable escalations, to the
estimated future production of year-end proved reserves. The product prices used
in calculating these reserves have varied widely during the three-year period.
These prices have a significant impact on both the quantities and value of the
proven reserves as the reduced oil price causes wells to reach the end of their
economic life much sooner and can make certain proved undeveloped locations
uneconomical, both of which reduce the reserves. The following representative
oil and natural gas year-end prices were used in the Standardized Measure. These
prices were adjusted by field to arrive at the appropriate corporate net price.
DECEMBER 31,
-------------------------------------------
2002 2001 2000
------------- ------------ --------------
Oil (NYMEX)..........................$ 31.20 $ 19.84 $ 26.80
Natural Gas (NYMEX Henry Hub)........ 4.79 2.57 9.78
Future cash inflows were reduced by estimated future production and development
costs based on year-end costs to determine pre- tax cash inflows. Future income
taxes were computed by applying the statutory tax rate to the excess of pre-tax
cash inflows over our tax basis in the associated proved oil and natural gas
properties. Tax credits and net operating loss carryforwards were also
considered in the future income tax calculation. Future net cash inflows after
income taxes were discounted using a 10% annual discount rate to arrive at the
Standardized Measure.
-65-
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31,
------------------------------------------------
AMOUNTS IN THOUSANDS 2002 2001 2000
--------------- -------------- --------------
Future cash inflows....................................................... $ 3,787,077 $ 1,786,884 $ 2,609,306
Future production costs................................................... (1,044,193) (655,363) (600,195)
Future development costs.................................................. (268,269) (178,546) (95,068)
--------------- -------------- --------------
Future net cash flows before taxes ................................... 2,474,615 952,975 1,914,043
10% annual discount for estimated timing of cash flows.................... (1,048,395) (378,647) (755,074)
--------------- -------------- --------------
Discounted future net cash flows before taxes......................... 1,426,220 574,328 1,158,969
Discounted future income taxes............................................ (397,244) (68,533) (317,670)
--------------- -------------- --------------
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS............. $ 1,028,976 $ 505,795 $ 841,299
=============== ============== ==============
The following table sets forth an analysis of changes in the Standardized
Measure of Discounted Future Net Cash Flows from proved oil and natural gas
reserves:
YEAR ENDED DECEMBER 31,
--------------------------------------------------
AMOUNTS IN THOUSANDS 2002 2001 2000
--------------- ---------------- --------------
BEGINNING OF YEAR....................................................... $ 505,795 $ 841,299 $ 448,374
Sales of oil and natural gas produced, net of production costs.......... (191,803) (194,386) (157,909)
Net changes in sales prices............................................. 694,646 (838,124) 281,181
Extensions and discoveries, less applicable future development
and production costs................................................. 151,926 123,214 200,966
Improved recovery (1)................................................... - 5,045 77,702
Previously estimated development costs incurred......................... 34,931 64,072 20,623
Revisions of previous estimates, including revised estimates of
development costs, reserves and rates of production.................. (50,855) (13,290) 48,018
Accretion of discount................................................... 57,433 115,897 46,287
Acquisition of minerals in place........................................ 160,899 152,931 183,634
Sales of minerals in place.............................................. (5,285) - (4,403)
Net change in income taxes.............................................. (328,711) 249,137 (303,174)
--------------- ---------------- --------------
END OF YEAR............................................................. $ 1,028,976 $ 505,795 $ 841,299
=============== ================ ==============
(1) Improved recovery additions result from the application of secondary
recovery methods such as waterflooding or tertiary recovery methods such as CO2
flooding.
CO2 Reserves
Based on engineering reports prepared by DeGolyer and MacNaughton, our CO2
reserves, on a working interest basis, were estimated at approximately 1.6 Tcf
at December 31, 2002 and 815 Bcf at December 31, 2001.
NOTE 11. CONDENSED CONSOLIDATING FINANCIAL INFORMATION
As of December 31, 2002, all of our senior subordinated notes were fully and
unconditionally guaranteed by Denbury Resources Inc.'s significant subsidiaries.
The following condensed consolidating financial information for Denbury
Resources Inc. and its significant subsidiaries includes the results of our
equity interest in Genesis, which is recorded under the equity method by Denbury
Gathering & Marketing.
-66-
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Condensed Consolidating Balance Sheets
DECEMBER 31, 2002
---------------------------------------------------------------
Denbury Denbury
Resources Resources
Inc. (Parent Guarantor Inc.
Amounts in Thousands and Issuer) Subsidiaries Eliminations Consolidated
-------------- ------------- ------------- --------------
ASSETS
Current assets..................................$ 111,063 $ 17,401 $ - $ 128,464
Property and equipment.......................... 528,754 215,331 - 744,085
Investment in subsidiaries (equity method)...... 169,309 2,224 (169,309) 2,224
Other assets.................................... 16,881 3,638 - 20,519
-------------- ------------- ------------- --------------
Total assets.................................$ 826,007 $ 238,594 $ (169,309) $ 895,292
============== ============= ============= ==============
LIABILITIES AND STOCKHOLDERS'
EQUITY
Current liabilities.............................$ 87,101 $ 8,778 $ - $ 95,879
Long-term liabilities........................... 372,109 60,507 - 432,616
Stockholders' equity............................ 366,797 169,309 (169,309) 366,797
-------------- ------------- ------------- --------------
Total liabilities and stockholders' equity...$ 826,007 $ 238,594 $ (169,309) $ 895,292
============== ============= ============= ==============
DECEMBER 31, 2001
---------------------------------------------------------------
Denbury Denbury
Resources Resources
Inc. (Parent Guarantor Inc.
Amounts in Thousands and Issuer) Subsidiaries Eliminations Consolidated
-------------- ------------- -------------- --------------
ASSETS
Current assets..................................$ 98,182 $ 5,096 $ - $ 103,278
Property and equipment ......................... 445,693 222,314 - 668,007
Investment in subsidiaries (equity method)...... 164,830 - (164,830) -
Other assets.................................... 15,684 3,019 - 18,703
-------------- ------------- -------------- --------------
Total assets.................................$ 724,389 $ 230,429 $ (164,830) $ 789,988
============== ============= ============== ==============
LIABILITIES AND STOCKHOLDERS'
EQUITY
Current liabilities.............................$ 68,937 $ 11,001 $ - $ 79,938
Long-term liabilities........................... 306,284 54,598 - 360,882
Stockholders' equity............................ 349,168 164,830 (164,830) 349,168
-------------- ------------- -------------- --------------
Total liabilities and stockholders' equity...$ 724,389 $ 230,429 $ (164,830) $ 789,988
============== ============= ============== ==============
Condensed Consolidating Statements of Operations
YEAR ENDED DECEMBER 31, 2002
------------------------------------------------------------------
Denbury Denbury
Resources Resources
Inc. (Parent Guarantor Inc.
Amounts in Thousands and Issuer) Subsidiaries Eliminations Consolidated
--------------- -------------- -------------- --------------
Revenues..................................... $ 231,147 $ 54,005 $ - $ 285,152
Expenses..................................... 166,805 48,087 - 214,892
--------------- ------------ ------------- --------------
Income before the following: 64,342 5,918 - 70,260
Equity in net earnings of subsidiaries.... 3,456 55 (3,456) 55
--------------- -------------- -------------- --------------
Income (loss) before income taxes............ 67,798 5,973 (3,456) 70,315
Income tax provision......................... 21,003 2,517 - 23,520
--------------- -------------- -------------- ------------
Net income (loss)............................ $ 46,795 $ 3,456 $ (3,456) $ 46,795
=============== ============ ============== ==============
-67-
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEAR ENDED DECEMBER 31, 2001
------------------------------------------------------------------
Denbury Denbury
Resources Resources
Inc. (Parent Guarantor Inc.
Amounts in Thousands and Issuer) Subsidiaries Eliminations Consolidated
--------------- -------------- --------------- --------------
Revenues.....................................$ 261,678 $ 23,433 $ - $ 285,111
Expenses..................................... 181,346 22,391 - 203,737
--------------- -------------- --------------- --------------
Income before the following: 80,332 1,042 - 81,374
Equity in net earnings of subsidiaries.... 653 - (653) -
--------------- -------------- --------------- --------------
Income (loss) before income taxes............ 80,985 1,042 (653) 81,374
Income tax provision......................... 24,435 389 - 24,824
--------------- -------------- --------------- --------------
Net income (loss)............................$ 56,550 $ 653 $ (653) $ 56,550
=============== ============== =============== ==============
YEAR ENDED DECEMBER 31, 2000
------------------------------------------------------------------
Denbury Denbury
Resources Inc. Resources
(Parent and Guarantor Inc.
Amounts in Thousands Issuer) Subsidiaries Eliminations Consolidated
---------------- -------------- -------------- --------------
Revenues.....................................$ 180,538 $ 1,113 $ - $ 181,651
Expenses..................................... 106,805 (87) - 106,718
---------------- -------------- -------------- --------------
Income before the following: 73,733 1,200 - 74,933
Equity in net earnings of subsidiaries.... 1,200 - (1,200) -
---------------- -------------- -------------- --------------
Income (loss) before income taxes............ 74,933 1,200 (1,200) 74,933
Income tax benefit........................... (67,294) - - (67,294)
---------------- -------------- -------------- --------------
Net income (loss)............................$ 142,227 $ 1,200 $ (1,200) $ 142,227
================ ============== ============== ==============
Condensed Consolidating Statements of Cash Flows
YEAR ENDED DECEMBER 31, 2002
------------------------------------------------------------------
Denbury Denbury
Resources Inc. Resources
(Parent and Guarantor Inc.
Amounts in Thousands Issuer) Subsidiaries Eliminations Consolidated
----------------- -------------- -------------- --------------
Cash flow from operations....................$ 146,132 $ 13,468 $ - $ 159,600
Cash flow from investing activities.......... (154,908) (16,253) - (171,161)
Cash flow from financing activities.......... 12,005 - - 12,005
----------------- -------------- -------------- --------------
Net increase (decrease) in cash flow......... 3,229 (2,785) - 444
Cash, beginning of period.................... 17,052 6,444 - 23,496
----------------- -------------- -------------- --------------
Cash, end of period..........................$ 20,281 $ 3,659 $ - $ 23,940
================= ============== ============== ==============
YEAR ENDED DECEMBER 31, 2001
------------------------------------------------------------------
Denbury Denbury
Resources Inc. Resources
(Parent and Guarantor Inc.
Amounts in Thousands Issuer) Subsidiaries Eliminations Consolidated
----------------- -------------- -------------- --------------
Cash flow from operations....................$ 154,034 $ 31,013 $ - $ 185,047
Cash flow from investing activities.......... (294,253) (24,577) - (318,830)
Cash flow from financing activities.......... 134,986 - - 134,986
----------------- -------------- -------------- --------------
Net increase (decrease) in cash flow......... (5,233) 6,436 - 1,203
Cash, beginning of period.................... 22,285 8 - 22,293
----------------- -------------- -------------- --------------
Cash, end of period..........................$ 17,052 $ 6,444 $ - $ 23,496
================= ============== ============== ==============
-68-
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEAR ENDED DECEMBER 31, 2000
------------------------------------------------------------------
Denbury Denbury
Resources Inc. Resources
(Parent and Guarantor Inc.
Amounts in Thousands Issuer) Subsidiaries Eliminations Consolidated
----------------- -------------- -------------- --------------
Cash flow from operations....................$ 98,004 $ (2,032) $ - $ 95,972
Cash flow from investing activities.......... (133,040) - - (133,040)
Cash flow from financing activities.......... 47,593 - - 47,593
----------------- -------------- -------------- --------------
Net increase (decrease) in cash flow......... 12,557 (2,032) - 10,525
Cash, beginning of period.................... 9,728 2,040 - 11,768
----------------- -------------- -------------- --------------
Cash, end of period..........................$ 22,285 $ 8 $ - $ 22,293
================= ============== ============== ==============
NOTE 12. SUBSEQUENT EVENTS (UNAUDITED)
In February 2003, we sold Laurel Field, acquired in the COHO acquisition, for
$27.0 million and other consideration which included an interest in Atchafalaya
Bay Field (where we already own an interest) and seismic over that area. At
December 31, 2002, Laurel Field had approximately 7.4 MMBbls of proved reserves.
We have also reached an agreement to sell two other fields that we acquired in
the COHO acquisition, Bentonia and Glazier Fields, for approximately $2.0
million combined, and this sale is expected to close in late March. Both of
these are much smaller fields with approximately 269,000 Bbls of proved reserves
at December 31, 2002. The proceeds from the sale of Laurel Field were used to
reduce our bank debt.
On March 17, 2003, we announced a refinancing of our 9% Senior Subordinated
Notes due 2008. We sold $225 million of 7.5% Senior Subordinated Notes due 2013
and called our existing $200 million of 9% notes at 104.5% of face value.
Closing on the new notes is scheduled for March 25, 2003, subject to the
satisfaction of customary closing conditions, and the redemption of the old
notes is expected to occur on April 16, 2003. We intend to use the remaining net
proceeds from this offering to reduce bank debt. Once completed, the refinancing
is expected to save us around $2.6 million per year in interest expense.
Assuming completion, we estimate that we will have a charge to earnings in the
second quarter of 2003 of approximately $11.25 million, net of related income
taxes, from the early retirement of our currently outstanding 9% notes.
NOTE 13. UNAUDITED QUARTERLY INFORMATION
IN THOUSANDS EXCEPT PER SHARE AMOUNTS MARCH 31 JUNE 30 SEPT. 30 DECEMBER 31
- ------------------------------------------------ ------------------------------------------------------------------
2002
- ----
Revenues........................................ $ 55,447 $ 73,433 $ 74,524 $ 81,748
Expenses........................................ 49,924 53,842 52,906 58,220
Net income...................................... 4,546 13,498 13,459 15,292
Net income per share:
Basic........................................ 0.09 0.25 0.25 0.29
Diluted...................................... 0.08 0.25 0.25 0.28
Cash flow from operations ...................... 12,032 46,572 44,379 56,617
Cash flow used for investing activities......... (27,129) (32,069) (80,622) (31,341)
Cash flow provided by (used for) financing
activities................................... 5,970 (8,697) 38,992 (24,260)
2001
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Revenues........................................ $ 79,180 $ 67,407 $ 74,318 $ 64,206
Expenses........................................ 37,960 35,484 52,178 78,115
Net income (loss)............................... 25,969 20,111 13,948 (3,478)
Net income (loss) per share:
Basic..................................... 0.56 0.44 0.27 (0.07)
Diluted .................................. 0.55 0.42 0.26 (0.07)
Cash flow from operations ...................... 66,089 30,886 45,097 42,975
Cash flow used for investing activities......... (70,391) (44,891) (139,993) (63,555)
Cash flow provided by financing activities...... 8,530 10,820 95,297 20,339
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COMMON STOCK TRADING SUMMARY
The following table summarizes the high and low reported sales prices on days in
which there were trades of Denbury's common stock on the New York Stock Exchange
("NYSE"), for each quarterly period for the last two fiscal years. Denbury
de-listed from the Toronto Stock Exchange effective April 15, 2002.
As of February 1, 2003, to the best of our knowledge, the outstanding shares of
Denbury's common stock were held by approximately 770 holders of record;
however, we estimate that beneficial owners of Denbury's common stock is in
excess of 1,500.
We have never paid any dividends on our common stock and we currently do not
anticipate paying any dividends in the foreseeable future. Also, we are
restricted from declaring or paying any cash dividends on our common stock under
our bank loan agreement.
NYSE
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HIGH LOW
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2002
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First quarter $ 8.50 $ 6.20
Second quarter 10.42 7.91
Third quarter 10.35 7.80
Fourth quarter 11.97 9.45
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2002 annual $ 11.97 $ 6.20
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2001
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First quarter $ 12.00 $ 7.90
Second quarter 12.30 7.30
Third quarter 9.75 7.50
Fourth quarter 8.81 6.00
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2001 annual $ 12.30 $ 6.00
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