Denbury Resources Inc.
EXHIBIT 13
PAGE 2, PAGES 9 THROUGH 10 INCLUSIVE, PAGES 12 THROUGH 13 INCLUSIVE, PAGES 17
THROUGH 18 INCLUSIVE, PAGES 20 THROUGH 21 INCLUSIVE, PAGES 23 THROUGH 25
INCLUSIVE, PAGES 27 THROUGH 31 INCLUSIVE, AND PAGES 33 THROUGH 86 INCLUSIVE, OF
THE COMPANY'S ANNUAL REPORT TO SHAREHOLDERS FOR THE YEAR ENDED DECEMBER 31,
2003, 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.
Denbury Resources Inc.
Financial Highlights
Year ended December 31,
-----------------------------------------------------
AVERAGE
ANNUAL
Amounts in thousands of U.S. dollars unless noted 2003 2002 2001(1) 2000 1999 GROWTH(2)
- ------------------------------------------------------------------------------------------------------------------------
Production (daily)
Oil (Bbls) 18,894 18,833 16,978 15,219 12,090 12%
Natural Gas (Mcf) 94,858 100,443 85,238 37,078 27,948 36%
BOE (6:1) 34,704 35,573 31,185 21,399 16,748 20%
Revenues 333,014 285,152 285,111 181,651 82,990 42%
Unit sales price (excluding hedges)
Oil (per Bbl) 27.47 22.36 21.34 25.89 15.03 16%
Natural Gas (per Mcf) 5.66 3.31 4.12 4.45 2.42 24%
Unit sales price (including hedges)
Oil (per Bbl) 24.52 22.27 21.65 23.50 13.08 17%
Natural Gas (per Mcf) 4.45 3.35 4.66 3.57 2.34 17%
Cash flow from operations 197,615 159,600 185,047 95,972 41,200 48%
Income before accounting change (3) 53,941 46,795 56,550 142,227 4,614 85%
Net income (3) 56,553 46,795 56,550 142,227 4,614 87%
Average common shares outstanding
Basic 53,881 53,243 49,325 45,823 39,928 8%
Diluted 55,464 54,365 50,361 46,352 39,987 9%
Income per share before accounting change
Basic 1.00 0.88 1.15 3.10 0.12 70%
Diluted 0.97 0.86 1.12 3.07 0.12 69%
Net income per share
Basic 1.05 0.88 1.15 3.10 0.12 72%
Diluted 1.02 0.86 1.12 3.07 0.12 71%
Oil and gas capital investments 158,444 155,637 327,175 134,021 54,967 30%
CO2 capital investments 22,673 16,445 45,555 - - -
Total assets 982,621 895,292 789,988 457,379 252,566 40%
Long-term liabilities 434,845 432,616 360,882 202,428 154,976 29%
Stockholders' equity (4) 421,202 366,797 349,168 216,165 72,428 55%
Proved reserves
Oil (MBbls) 91,266 97,203 76,490 70,667 51,832 15%
Natural Gas (MMcf) 221,887 200,947 198,277 100,550 50,438 45%
MBOE (6:1) 128,247 130,694 109,536 87,425 60,238 21%
Discounted future cash flow before tax - 10% 1,566,371 1,426,220 574,328 1,158,969 462,870 36%
Standard measure of discounted future net
cash flows 1,124,127 1,028,976 505,795 841,299 488,374 23%
Per BOE data (6:1)
Oil and natural gas revenues 30.43 21.17 22.88 26.13 14.88 20%
Gain (loss) on settlements of derivative
contracts (4.91) 0.07 1.64 (3.23) (1.54) 34%
Lease operating costs (7.06) (5.48) (4.84) (4.94) (4.25) 14%
Production taxes and marketing expenses (1.17) (0.92) (0.96) (1.02) (0.60) 18%
- ----------------------------------------------------------------------------------------------------------------------
Production netback 17.29 14.84 18.72 16.94 8.49 19%
Operating margin from CO2 operations 0.51 0.48 0.38 - - -
General and administrative expense (1.20) (0.96) (0.89) (1.09) (1.21) -
Net cash interest expense (1.61) (1.73) (1.74) (1.54) (2.22) -8%
Current income taxes and other (0.01) 0.04 (0.06) (0.07) 0.11 -
Changes in assets and liabilities 0.62 (0.38) (0.15) (1.99) 1.57 -21%
- ----------------------------------------------------------------------------------------------------------------------
Cash flow from operations 15.60 12.29 16.26 12.25 6.74 23%
======================================================================================================================
(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 1999 as a base year.
(3) In 2003, we recognized a gain of $2.6 million for the cumulative effect adoption of SFAS No. 143,
"Accounting for Asset Retirement Obligations," (see Note 4 to the Consolidated Financial Statements). 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 at December 31, 2000.
(4) We have never paid any dividends on our common stock.
2
Denbury Resources Inc.
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.
Selected Operating Data
Oil and Gas Reserves
DeGolyer and MacNaughton, independent petroleum engineers located in
Dallas, Texas, prepared estimates of our net proved oil and natural gas reserves
as of December 31, 2003, 2002 and 2001. The reserve estimates were prepared
using constant prices and costs in accordance with the guidelines of the
Securities and Exchange Commission ("SEC"). The prices used in preparation of
the reserve estimates were based on the market prices in effect as of December
31 of each year, with the appropriate historical adjustments (transportation,
gravity, basic sediment and water "BS&W," purchasers' bonuses, Btu, etc.)
applied to each field. The reserve estimates 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 interests
in our properties.
As is the case with our independent accountants, our independent petroleum
engineers are retained and their work reviewed by the audit committee of our
board of directors. In addition, one of our audit committee members is a
petroleum engineer who monitors the entire reserve reporting process. We do not
book proved undeveloped reserves until we have committed to perform the required
operations, the majority of which are expected to commence within the next year.
Our proved nonproducing reserves primarily relate to reserves that are to
be recovered from productive zones that are currently behind pipe. Since a
majority of our properties are in areas with multiple pay zones, these
properties typically have both proved producing and proved nonproducing
reserves.
Proved undeveloped reserves associated with our CO2 tertiary operations in
West Mississippi and our Heidelberg waterfloods in East Mississippi account for
approximately 90% of our proved undeveloped oil reserves. We consider these
reserves to be lower risk than other proved undeveloped reserves that require
drilling at locations offsetting existing production because all of these proved
undeveloped reserves are associated with secondary recovery or tertiary recovery
operations in fields and reservoirs that historically produced substantial
volumes of oil under primary production. The main reason these reserves are
classified as undeveloped is because they require significant additional capital
associated with drilling/re-entering wells or additional facilities in order to
produce the reserves and/or are waiting for a production response to the water
or CO2 injections.
Our proved undeveloped natural gas reserves are not as concentrated as our
proved undeveloped oil reserves. The offshore properties we acquired in the 2001
Matrix acquisition account for approximately 48% of our proved undeveloped
natural gas reserves. These reserves are typically located up-dip to existing
9
Denbury Resources Inc.
wells or up-dip to wells that previously ceased producing due to water
encroachment. These natural gas reserves are confirmed not only by subsurface
geology but also by 3D seismic that covers these areas. An additional 24% 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. Our
remaining undeveloped natural gas reserves are located within our currently
producing reservoirs. Our current plans for 2004 include development of
approximately 27% of our proved undeveloped natural gas reserves.
Year Ended December 31,
-------------------------------------------
2003 2002 2001
------------ ------------- -------------
Estimated proved reserves:
Oil (MBbls)................................................ 91,266 97,203 76,490
Natural gas (MMcf)......................................... 221,887 200,947 198,277
Oil equivalent (MBOE)...................................... 128,247 130,694 109,536
Percentage of total MBOE:
Proved producing........................................... 43% 43% 53%
Proved non-producing....................................... 18% 23% 23%
Proved undeveloped......................................... 39% 34% 24%
Representative oil and gas prices: (1)
Oil - NYMEX................................................ $ 32.52 $ 31.20 $ 19.84
Natural gas - NYMEX Henry Hub.............................. 6.19 4.79 2.57
Present Values:(2)
Discounted estimated future net cash flow before
income taxes ("PV-10 Value") (thousands)............... $ 1,566,371 $ 1,426,220 $ 574,328
Standardized measure of discounted estimated future net
cash flow after income taxes (thousands)............... $ 1,124,127 $ 1,028,976 $ 505,795
(1) The prices as of each year-end were based on market prices in effect as of December 31 of each year, NYMEX prices per Bbl and
NYMEX Henry Hub prices per MMBtu, with the appropriate historical adjustments (transportation, gravity, BS&W, purchasers'
bonuses, Btu, etc.) applied to each 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.
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Denbury Resources Inc.
Field Summaries
Denbury operates in four primary areas: Louisiana, offshore Gulf of Mexico,
Eastern Mississippi and Western Mississippi. Our 18 largest fields (listed
below) constitute approximately 85% of our total proved reserves on a BOE basis
and 80% on a PV-10 Value basis. Within these 18 fields we own a weighted average
91% working interest and operate all of these 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.
2003 Average
Proved Reserves as of December 31, 2003(1) Daily Production
------------------------------------------------------ ----------------
Natural Average Net
Oil Natural Gas MBOE's BOE PV-10 Value Oil Gas Revenue
(MBbls) (MMcf) (000's) % of Total (000's) (Bbls/d) (Mcf/d) Interest(2)
----------------------------------------------------------------------------------------------------------------------------------
Mississippi - CO2 floods
Mallalieu (East & West)................. 16,026 - 16,026 12.5% 218,041 1,578 - 81%
McComb................ ................. 11,853 - 11,853 9.2% 103,887 - - 83%
Little Creek & Lazy Creek............... 7,432 - 7,432 5.8% 112,666 3,093 - 83%
------ -------- ------- ----- --------- ------ ------ --
Total Mississippi - CO2 floods ... 35,311 - 35,311 27.5% 434,594 4,671 - 82%
------ -------- ------- ----- --------- ------ ------ --
Offshore Gulf of Mexico
Brazos A-22............................. 173 21,345 3,731 2.9% 44,864 13 1,069 72%
South Marsh Island...................... 211 21,072 3,723 2.9% 86,657 72 7,652 83%
W.Delta 27.............................. 622 8,984 2,119 1.7% 41,193 417 8,322 56%
N. Padre A-9............................ 8 10,804 1,809 1.4% 34,751 - 259 39%
Other offshore.......................... 60 27,500 4,643 3.6% 105,990 152 26,465 31%
------ -------- ------- ----- --------- ------ ------ --
Total offshore.................... 1,074 89,705 16,025 12.5% 313,455 654 43,767 48%
------ -------- ------- ----- --------- ------ ------ --
Other Mississippi
Heidelberg (East & West)................ 35,226 51,853 43,868 34.2% 341,133 5,824 10,265 78%
Eucutta................................. 4,691 - 4,691 3.7% 43,878 1,252 159 69%
King Bee................................ 2,853 - 2,853 2.2% 26,958 554 - 81%
Brookhaven ............................ 1,687 - 1,687 1.3% 20,381 452 - 77%
Other Mississippi....................... 8,421 6,104 9,438 7.4% 89,610 3,600 1,309 27%
------ -------- ------- ----- --------- ------ ------ --
Total Other Mississippi........... 52,878 57,957 62,537 48.8% 521,960 11,682 11,733 60%
------ -------- ------- ----- --------- ------ ------ --
Louisiana
Lirette................................. 167 12,276 2,213 1.7% 59,410 288 12,379 58%
S.Chauvin............................... 367 10,663 2,144 1.7% 45,163 155 3,335 37%
Thornwell............................... 177 11,026 2,015 1.6% 62,368 507 12,343 65%
Other Louisiana......................... 1,292 22,176 4,988 3.9% 107,640 878 10,306 39%
------ -------- ------- ----- --------- ------ ------ --
Total Louisiana................... 2,003 56,141 11,360 8.9% 274,581 1,828 38,363 41%
------ -------- ------- ----- --------- ------ ------ --
Texas
Newark (Barnett Shale).................. - 18,084 3,014 2.3% 21,781 59 995 71%
------ -------- ------- ----- --------- ------ ------ --
Company Total.............................. 91,266 221,887 128,247 100% 1,566,371 18,894 94,858 61%
====== ======== ======= ===== ========= ====== ====== ==
(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, 2003. The prices at that date were a NYMEX oil price of $32.52 per
Bbl adjusted by field and a NYMEX natural gas price average of $6.19 per MMBtu also adjusted by field.
(2) Only includes wells in which the Company has a working interest as of December 31, 2003.
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Denbury Resources Inc.
Oil and Gas Acreage
The following table sets forth Denbury's acreage position at December
31, 2003:
Developed Undeveloped Total
------------------------- ------------------------- -------------------------
Gross Net Gross Net Gross Net
------------ ---------- ----------- ----------- ----------- -----------
Louisiana................ 24,473 16,693 26,025 18,857 50,498 35,550
Mississippi.............. 84,942 69,374 242,397 33,663 327,339 103,037
Offshore Gulf Coast...... 122,301 68,782 58,580 52,010 180,881 120,792
Texas, other............. 5,698 4,405 73,887 16,899 79,585 21,304
------- ------- ------- ------- ------- -------
Total........ 237,414 159,254 400,889 121,429 638,303 280,683
======== ======== ======= ======= ======= =======
Productive Wells
This table sets forth our gross and net productive oil and natural gas
wells at December 31, 2003:
Producing Natural
Producing Oil Wells Gas Wells Total
------------------------ ------------------------ ------------------------
Gross Net Gross Net Gross Net
--------------------------- ----------- --------- ---------- ---------- --------- ----------
Louisiana................ 28 23.2 59 39.1 87 62.3
Mississippi.............. 410 379.9 94 76.6 504 456.5
Offshore Gulf Coast...... 5 3.4 76 45.3 81 48.7
Texas, other............. 52 1.6 13 12.0 65 13.6
--- ----- --- ----- --- -----
Total............ 495 408.1 242 173.0 737 581.1
=== ===== === ===== === =====
Drilling Activity
The following table sets forth the results of our drilling activities over
the last three years:
Year Ended December 31,
---------------------------------------------------------------
2003 2002 2001
-------------------- -------------------- -------------------
Gross Net Gross Net Gross Net
---------- --------- --------- --------- -------- ---------
Exploratory Wells: (1)
Productive (2)........................ 7 5.3 7 4.9 15 9.7
Nonproductive (3)..................... 7 4.8 4 3.2 3 1.4
Development Wells: (1)
Productive (2)........................ 37 31.3 33 27.1 60 49.9
Nonproductive (3)(4).................. 3 1.2 2 1.9 - -
-- ---- -- ----- -- ----
Total........................... 54 42.6 46 37.1 78 61.0
== ==== == ==== == ====
(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 developmental 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 2003, 2002 and 2001, an additional 5, 9 and 24 wells, respectively, were drilled for water or CO2 injection purposes.
13
Denbury Resources Inc.
Operations Report
Our CO2 Assets
Just over four years ago, we started a new focus area through an
acquisition of a carbon dioxide ("CO2") tertiary flood in an area very familiar
to us, Mississippi. We have subsequently acquired other related assets and are
making that focus area a major part of our business. In summary, we are
gradually becoming more of a tertiary exploitation company than a traditional
acquire, drill and exploit type of exploration and production company. We
particularly like this play as (i) it is lower risk and more predictable than
most traditional exploration and development activities, (ii) it provides a
reasonable rate of return at relatively low oil prices (upper teens to low
twenties), and (iii) we have virtually no competition for this type of activity
in our geographic area. Generally, from East Texas to Florida, there are no
natural sources of carbon dioxide except our own, and these large volumes of CO2
that we own drive the play. Our CO2 comes from an old volcano located near
Jackson, Mississippi, discovered in the 1960s while companies were drilling for
oil and natural gas. Instead they found CO2, which at the time was of little
use. 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 general area.
CO2 injection is one of the most efficient tertiary recovery mechanisms for
producing crude oil; however, because it requires large quantities of CO2, its
use has been restricted to West Texas, Mississippi and other isolated areas
where large quantities of CO2 are available. The CO2 (in liquid form) acts as a
type of solvent for the oil, causing the oil to expand and become mobile,
allowing the oil to be recovered along with the CO2 as it is produced. The CO2
is then extracted from the oil, compressed back into a liquid state, and
re-injected into the reservoir, with this recycling process occurring several
times during the life of the tertiary operations. In a typical oil field up to
50% of the oil in place can be extracted during primary and secondary
(waterflooding) recovery operations. Through the use of CO2 in tertiary
operations, it is possible to recover additional oil (for example, 17% based on
historical results at Little Creek), almost as much oil as initially recovered
during the primary production phase.
We started this play in August 1999, when we acquired our first CO2
tertiary recovery project, Little Creek Field in Mississippi, a project
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 3,201
Bbls/d during the fourth quarter of 2003. 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 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 three 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 most 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
17
Denbury Resources Inc.
be available to us on a reliable basis and at a reasonable and
predictable cost. Since February 2001, we have acquired two and
drilled three additional CO2 producing wells, doubling our estimated
proved CO2 reserves to approximately 1.6 Tcf as of December 31, 2003
(including approximately 162.6 Bcf of reserves dedicated to a
volumetric production payment to Genesis). Today, we own every
producing CO2 well in the region. Although our current proven and
potential CO2 reserves are quite large, in order to continue our
tertiary development of oil fields in the area, incremental
deliverability of CO2 is needed. In order to obtain the additional CO2
deliverability, we plan to drill several additional CO2 wells in the
future, including up to four more wells during 2004, including one
side-track operation.
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 properties in this area, the acquisition costs of
both of these fields were relatively low in comparison to their
significant reserve potential as tertiary recovery projects. As an
example, we acquired West Mallalieu Field 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 all-in finding and
development costs at these fields to average between $4.00 and $5.00
per BOE.
o In May 2002, we acquired the 2.0% general partner interest in Genesis
Energy, L.P. ("Genesis"). 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 of
our other East Mississippi fields. This acquisition has enhanced our
marketing position for our Mississippi oil production. Genesis may
also function as a financier and operator of new pipelines and
gathering systems that are required in order for us to develop these
fields.
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 MMBOE (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
18
Denbury Resources Inc.
competitive advantage and strategic ownership of the general partner
interest in Genesis, 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. Initial
development of the Brookhaven CO2 flood is expected to begin in late
2004. While we have not currently recorded any proved reserves
associated with the CO2 flood at Brookhaven, we believe that this
field contains one of the area's most significant opportunities for
potential oil reserves using CO2 tertiary recovery.
o During the fourth quarter of 2003, we sold an average of 64 MMcf/d of
CO2 to commercial users and we used an average of 145 MMcf/d for our
tertiary activities. With the acquisition of our latest well, we
estimate our current daily CO2 deliverability is over 250 MMcf/d, and
by year-end 2004 we hope to further increase our CO2 deliverability to
approximately 350 MMcf/d. We plan to continue our CO2 drilling in 2004
and beyond, as we estimate that we will need to be producing around
400 MMcf/d by 2006 in order to meet the projected timetable for our
tertiary projects in Southwest Mississippi. During 2004, two of the
CO2 wells we expect to drill will be testing new structures, which if
successful, will increase our CO2 reserves and provide additional
deliverability. We believe that it is prudent to add additional
reserves and deliverability before we commence with our tentative
plans to expand our CO2 operations into East Mississippi and/or other
regions. We expect to use almost all of the anticipated
20
Denbury Resources Inc.
incremental CO2 production in our own tertiary recovery operations.
Our CO2 sales to industrial customers are expected to provide us with
between five and six million dollars of net cash flow per year,
approximately 85 % of the 2003 level. The decrease is a result of our
2003 sale of 167.5 Bcf of CO2 to Genesis pursuant to a volumetric
production payment (see discussion below). As of December 31, 2003,
the present value of the remaining industrial sales contracts (using
pricing provided in the contracts) discounted at 10% per year was
approximately $33 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 additional value.
o In October 2003, we sold 167.5 Bcf of CO2 to Genesis for $24.9 million
under a volumetric production payment. In conjunction with the sale,
we included the assignment of three of our existing long-term
commercial CO2 supply agreements with our industrial customers.
Pursuant to the terms of the volumetric production payment, Genesis
has specific maximums on the amount of CO2 they are allowed to take
each year, which generally relate to the anticipated volumes of the
three industrial customers. We will continue to provide Genesis with
certain processing and transportation services in connection with this
agreement for a fee of $0.16 per Mcf of CO2 delivered to their
industrial customers. In a separate transaction, we purchased
approximately 689,000 partnership common units of Genesis for $7.15
per unit, an aggregate purchase price of $4.9 million, giving us
approximately 9.25% total ownership (2.0% general partner and 7.25%
limited partner ownership) of Genesis.
o In February 2004, we disclosed the results of our preliminary study to
determine the feasibility of implementing tertiary recovery operations
in East Mississippi, in addition to the development of fields along
our CO2 pipeline. We reviewed five fields that we expect to be part of
the first phase of operations in this area. While the study is
preliminary and requires significant additional work and review,
including a determination of the precise costs and best location for a
CO2 pipeline to this part of the state and further refinement of the
economics, preliminarily this project appears to have reasonable
economics at NYMEX prices in the low to mid twenties. These five
fields also appear to have aggregate potential oil reserves of about
80 MMBbls that could be developed through tertiary operations,
approximately the same magnitude of potential as those fields along
our existing CO2 pipeline. To be considered proven reserves, these
potential tertiary floods must (i) have evidence of a response to CO2
injections, from either a pilot test, actual response, or by analogy,
and (ii) have a commitment from the company to do the project. Our
preliminary projections of forecast production for both East and West
Mississippi indicate that oil production from tertiary operations
could peak at rates of almost 32,000 Bbls/d by 2013. While it is
extremely difficult to accurately forecast that far into the future,
we do believe that our tertiary recovery operations provide
significant long-term production growth potential at reasonable rates
of return with relatively low risk.
With anticipated all-in finding and development costs of between $4.00 and
$5.00 per BOE and anticipated operating costs of around $10.00 per BOE over the
life of each field, these tertiary recovery operations in
21
Denbury Resources Inc.
West Mississippi along our pipeline should prove to be profitable, even at $18
oil prices, as they produce light sweet oil that receives near NYMEX pricing.
As noted above, 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.
However, there are a few differences that we have noted when comparing these two
areas: (i) operating cost in East Mississippi is likely to be one to three
dollars per BOE higher than it is for those fields along our CO2 pipeline,
primarily because of the incremental cost of transporting the CO2 to this new
area, (ii) the incremental operating cost may be partially offset by an
anticipated lower finding cost, as these East Mississippi fields may not require
as many wells to be drilled or re-entered, as more wells are currently active,
(iii) there are reservoir related differences, which although not exactly
quantified, are expected to improve the overall economics in the eastern area,
and (iv) the quality of the oil is different in the two areas. In the eastern
part of the state, the oil is generally heavier and usually sour, and thus has a
higher negative differential to NYMEX, ranging from one to six dollars per
barrel worse than West Mississippi light sweet oil. In summary, while the fields
in West Mississippi along our pipeline provide a satisfactory rate of return at
NYMEX oil prices of around $18, our preliminary study indicates that it takes
NYMEX oil prices in the low to mid twenties to achieve the same rate of return
in East Mississippi.
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 recovered
from fields in this part of the state as a result of CO2 flooding. To date, we
have recognized approximately 49.4 MMBbls (gross) of this potential as proven
reserves, of which 6.2 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 leasing, reworking/reentering wells and
installing production facilities. We plan to spend around $80 million in this
area during 2004, almost one-half of our current $172 million 2004 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, the first two phases were complete and
Phase III was in process. We have completed development of Phase III, Phase IV
and Phase V and most of the currently planned development work at this field,
although we will continue to modify existing patterns and drill wells as
necessary to recover the maximum amount of oil or to extend the field into areas
which have not benefited from CO2 injection. Currently there are 29 producing
wells and 28 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 the flooded portion of the field by
approximately 17%, as compared to recoveries of approximately 20% for primary
recovery and 18% for secondary recovery. The field has produced a cumulative
63.2 MMBbls (gross) of light sweet crude and we currently estimate that an
additional 7.2 MMBbls (gross) can be recovered.
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Denbury Resources Inc.
Production from Little Creek Field was approximately 1,350 Bbls/d when we
acquired it in 1999. During the fourth quarter of 2003, production had increased
to an average of 3,201 BOE/d. Although we experienced a temporary shortage of
CO2 deliverability for several months during 2003, our oil production at Little
Creek has now recovered and has recently been increasing again. We expect the
production from Little Creek to increase further during 2004 by another 500 to
750 BOE/d. At December 31, 2003, we had proved reserves of 35.3 MMBbls relating
to our tertiary recovery operations. From inception through December 31, 2003,
we had net positive cash flow from Little Creek (including Lazy Creek) of $17.8
million (at the field level), plus the fields have a PV-10 Value, using December
31,2003 SEC NYMEX pricing, of $112.7 million.
We purchased West Mallalieu Field in May 2001. Shell Oil Company unitized
West Mallalieu Field and commenced a pilot project in 1986. The pilot project,
consisting of four 5-spot patterns, has cumulatively produced approximately 2.1
MMBbls of oil as a result of CO2 flooding. We have expanded the pilot project by
adding an additional four patterns during 2001, four patterns in 2002 and three
patterns in 2003, in addition to an injection well in the East Mallalieu Unit
added during 2003. During 2002 we began to see initial response to CO2 injection
as the West Mallalieu Field Unit averaged 778 Bbls/d during the fourth quarter
of 2002. Response in 2003 has continued as production increased to 2,378 Bbls/d
during the fourth quarter of 2003. In contrast to Little Creek Field, West
Mallalieu Field was not waterflooded prior to CO2 injection. Therefore, we
believe that 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.
We purchased McComb Field in 2002, a field with no pilot programs or
tertiary operations at that time and virtually no current oil production. McComb
is very close in proximity and analogous to Little Creek and Mallalieu Fields.
We commenced tertiary recovery operations in 2003 by substantially completing
two patterns, and by November 2003 had started injecting CO2. We do not expect
any oil production response until late 2004 from this activity. As of December
31, 2003, we had 11.9 MMBbls of proven reserves at McComb Field. During 2004, we
expect to add five patterns within McComb field and expand the production
facilities. In addition, we also plan on starting an additional CO2 flood at
nearby Smithdale Field during 2004 utilizing the same facilities. We believe
that the total potential at McComb and Smithdale Fields is significantly higher
than the current proved reserves (at McComb only), and therefore expect to have
upward reserve additions here over the next several years as we fully develop
these fields.
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Denbury Resources Inc.
At December 31, 2003, we have proved reserves of 35.3 MMBbls relating to
our tertiary recovery operations. Through December 31, 2003, we have spent a
total of $104.8 million on fields in this area, and have received $83.0 million
in net operating income, leaving us a balance of $21.8 million to recover for
payout. The proved oil reserves in our CO2 fields have a PV-10 Value, using
December 31, 2003 SEC NYMEX pricing, of $434.6 million.
Heidelberg and East Mississippi
We own interests in 504 wells in the eastern part of the Mississippi salt
basin and operate 472 of these wells (94%) from our regional office in Laurel,
Mississippi. These fields produced an average of 11,028 Bbls/d and 12.2 MMcf/d
during the fourth quarter of 2003. The largest field in the region, and our
largest field corporately, is Heidelberg Field, which for the fourth quarter of
2003 produced an average of 7,568 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. Since we have generally owned these eastern
Mississippi properties longer than properties in our other regions, they tend to
be more fully developed and thus require less capital spending. During 2003, we
spent a total of approximately $24.6 million (excluding acquisitions), drilling
29 wells and performing various workovers, recompletions and other maintenance
type projects. Even with the relatively low level of spending here, our
production in eastern Mississippi averaged 13,638 BOE/d during 2003, slightly
higher than the 2002 average of 13,378 BOE/d. For 2004, we expect our budget in
this region to be a little higher than it was in 2003, approximately $32.4
million, or 19% of our current $172 million 2004 exploration and development
budget.
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,
recompleting wells, improving production efficiency, and in some cases, by water
flooding producing reservoirs. Most of our wells in this area produce large
amounts of saltwater and require large pumps, which increase 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). Our biggest
future upside in this area will likely be from CO2 flooding (tertiary recovery).
We initiated a study of the feasibility of implementing tertiary recovery
operations in East Mississippi during 2003, evaluating several of our existing
fields, plus a few other fields in the general area that we do not own. The
preliminary results of our study indicate that there are significant volumes of
oil reserves that can be recovered in this area through CO2 tertiary recovery
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Denbury Resources Inc.
operations that should provide a reasonable rate of return at NYMEX oil prices
in the low to mid twenties. As such, we will be taking steps to increase our CO2
reserves during 2004 (see Our CO2 Assets above), which if successful, could be
used for an expansion of tertiary activities to this area.
Heidelberg Field was acquired from Chevron in December 1997. This field was
discovered in 1944 and has produced an estimated 198 MMBbls of oil and 43 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 2003 averaged 7,535 BOE/d.
The primary oil production at Heidelberg is from five waterflood units that
produce from the Eutaw formation (at 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 natural gas wells in 2001, 13 natural gas wells in 2002 and 15
natural gas wells in 2003, increasing the natural gas production at Heidelberg
to an average for 2003 of around 10.3 MMcf/d. We believe that there are
opportunities to further reduce the well spacing here and we plan to drill up to
16 additional Selma Chalk wells during 2004. In addition, we have determined
additional natural gas reserves can be recovered from the Upper Selma Chalk and
recently have increased our fracture stimulation size in one well with positive
results. Our 2004 projects include performing the larger fracture treatments on
new wells and additional completions in the Upper Selma Chalk in seven wells.
Offshore Gulf of Mexico
During 2003, another area of focus for us was 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. We own an interest in 81 wells and operate 63 of these wells
(78%) from our regional office in Covington, Louisiana. This area became a more
significant part of our business in 2001 with the purchase of Matrix Oil & Gas,
Inc.
Due to the downturn in natural gas prices that occurred late in 2001, we
budgeted little drilling activity offshore during 2002, with spending primarily
limited to workovers, recompletions and other maintenance type projects. We
drilled only two offshore wells late in 2002, both successful exploration wells
at North Padre Island A-9. During 2003, we spent approximately $54.0 million
(excluding acquisitions), significantly higher than the $13.6 million incurred
here (excluding acquisitions) during 2002. We drilled six wells during 2003
(including two wells drilling as of year-end) and completed the platform and
production facilities at North Padre A-9, our late 2002 discovery. As is typical
of the shorter-life natural gas production in this area, a high level of
activity must be maintained or production will decline. Since our spending was
reduced during
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Denbury Resources Inc.
2002 and most of the 2003 wells were not completed until late in the year, our
2003 production averaged only 47.7 MMcfe/d, a decline from our 2002 average of
59.9 MMcfe/d. Late in the fourth quarter of 2003, we made 15 well completions,
four at Brazos A-21, three at North Padre A-9, three at Chandeleur Sound 69, two
at West Cameron 192 and three at West Cameron 427. Although most of these were
not completed until the latter half of the fourth quarter, the incremental
production was sufficient to at least temporarily arrest the overall production
decline in this area. During 2004, with the gradual shifting of our emphasis to
our CO2 play (see above), we have reduced our budgeted offshore spending to
approximately $28.7 million, or about 17% of our $172 million 2004 exploration
and development budget.
During 2004, we expect to drill three to six offshore wells, with unrisked
potential target objectives ranging from 5 Bcf to 55 Bcf, net to our interest.
These projects are supported with 3D seismic that is enhanced by modern
acquisition techniques and 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, South Marsh Island 49, and North Padre
A-9. As is the case with all oil and natural gas activity, but perhaps to an
even more pronounced degree in the Gulf of Mexico, the timing and drilling of
individual wells is subject to, among other things, working interest owner
approvals, farm-out agreements, solicitation of participating entities, rig
availability and our continual process of upgrading our prospect inventory. In
March 2004 we hired an investment banker to assist us with the sale of our
offshore operations. No buyer has been identified as yet, and if the sales price
is less than anticipated, we may withdraw the sales package.
South Louisiana
We own interests in 87 wells in the land and marshes of south Louisiana and
operate 74 of these wells (85%) from our regional office in Houma, Louisiana.
This region produces primarily natural gas, averaging 39.2 MMcf/d net to our
interest in the fourth quarter of 2003, approximately 42% of our total natural
gas production. During 2003, we spent approximately $33.1 million (excluding
acquisitions) in this region, approximately 20% of our total exploration and
development expenditures, drilling approximately 16 wells, primarily in the
Thornwell and Terrebonne Parish areas (Lirette, Bay Baptiste, Bayou Sauveur,
Gibson and Lake Gero Fields). For 2004, our spending is expected to be about the
same, with a budget of $22.7 million, or 13% of our $172 million exploration and
development budget.
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 recent shallow natural gas plays at Lake Gero and Gibson Fields. 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 650 square miles of 3D data, and plan to expand our data
ownership. During 2003, we expanded our seismic holdings in this area by
acquiring an additional 165 square miles of 3D data. We drilled nine wells in
Terrebonne Parish during 2003, seven of which were discoveries. In 2004, we plan
to drill approximately six wells: three exploratory wells in or around Lirette
Field and three wells that are planned to further exploit shallow gas plays.
We have had good success with a shallow natural gas play in the Lake Gero
area of Terrebonne Parish, although our 2003 results were not as good as we had
hoped. At Lake Gero, we drilled two successful wells during 2002, another
successful well in 2003, followed
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Denbury Resources Inc.
by one marginal well and one dry hole. These shallow gas reservoirs are
approximately 3,000 feet deep, but have the ability to produce from 1.0 to 4.0
Mmcf/d. During the fourth quarter of 2003, we drilled similar anomalies in
Gibson Field and Bayou Sauveur Fields. As of January 2004, our Gibson well was
producing at around 1.7 MMcf/d, with several additional prospects in the area,
and our Bayou Sauveur well is producing approximately 1.0 MMcf/d. We plan to
drill an additional three shallow gas prospects in Terrebonne Parish during
2004, with another 5 to 15 additional shallow gas prospects in the Terrebonne
Parish under review.
We purchased Thornwell Field, located in Cameron and Jeff Davis parishes,
in late 2000. Our primary interest in purchasing this field was the substantial
upside potential that we believed existed in the continued development of the
existing producing zones (Bol Perc), and the exploration potential of the deeper
zones (Marg howei and Camerina). All of these prospects were defined by a 110
square mile 3D seismic survey. We had significant activity at this field during
2001 and 2002, with positive results, but reduced our activity during 2003 as
the field became more fully developed. During 2003, we drilled one successful
Bol Perc well, drilled our first dry hole in the field, and a third well was
unsuccessful in the Bol Perc but found pay in a shallower sand. During 2003, we
also successfully drilled our first Marg howei test in the field. We also
recompleted a well that averaged just under 1.0 MMcfe/d during the fourth
quarter of 2003. Our plans for 2004 are more limited, but do include a Marg
howei well and further leasing for future potential exploration prospects.
Thornwell Field is characterized by short-life natural gas properties that
have high initial production rates
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Denbury Resources Inc.
with a good rate of return, but are depleted in two to three years. The high
rates of decline have dramatically impacted our overall production rates the
last two years, and are expected to continue to do so throughout 2004.
Production at Thornwell Field averaged 4,275 BOE/d in 2001, 3,910 BOE/d in 2002
and 2,564 BOE/d in 2003, and is expected to average approximately 1,100 BOE/d
during 2004. Even though this field is negatively affecting our overall
production growth, the purchase and development of this field has been
profitable. From inception through December 31, 2003, we have net positive cash
flow (at the field level) to date of $18.9 million from our activities at this
field. Furthermore, we have remaining proved reserves with a PV-10 Value, using
December 31, 2003 constant SEC NYMEX pricing, of $62.4 million.
Barnett Shale
We own about 20,000 acres of leases in the Fort Worth Basin in North
Central Texas that are prospective for natural gas in the Barnett Shale. Six
wells were drilled in 2001, two in 2002 and an additional five in 2003. In
addition to our own drilling during 2003, we entered into a joint venture with
another entity to drill up to 60 wells in this area over a 36-month time frame.
During 2003, the joint venture partner drilled 10 wells on our acreage and is
expected to drill an additional 10 wells by the end of March 2004. Based on our
wells, the joint venture wells and the other wells in the immediate area, we
believe the majority of our acreage contains productive natural gas in the
Barnett Shale with significant reserve potential. During 2004, our plans include
the drilling of three horizontal wells to determine if this drilling technique
will improve the overall economics. In addition to our own plans, our joint
venture partner is expected to drill an additional 15 wells, some of which may
be horizontal, in which we plan to participate for our full interest. During
2003, we also addressed an issue of pipeline capacity in our area of the Barnett
Shale play by installing additional pipelines to relieve some packed lines.
Several of the gas buyers in the area are making plans to install additional
pipelines to handle the expected future volumes of gas from this area of the
play.
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Denbury Resources Inc.
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.
MBbls 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.
MMBbls 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.
PV-10 Value When used with respect to oil and natural gas reserves, PV-10 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,
before income taxes, and without giving effect to non-property-related expenses, discounted to a
present value using an annual discount rate of 10% in accordance with the guidelines of the Securities
and Exchange Commission.
Proved Developed Reserves Reserves that can be expected to be recovered through existing wells with existing
equipment and operating methods.
Proved Reserves The estimated quantities of crude oil, natural gas and natural gas liquids that 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
Reserves existing wells where a relatively major expenditure is required.
Tcf One trillion cubic feet of natural gas or CO2.
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.
MMCFE One thousand Mcfe.
MCFE/D MCFEs produced per day.
MMCFE/D MMCFEs produced per day.
31
Denbury Resources Inc.
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 and hold significant
operating acreage in the onshore Louisiana and 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, including secondary and tertiary recovery operations. Our corporate
headquarters are in Plano, Texas (a suburb of Dallas), and we have three primary
field offices located in Houma and Covington, Louisiana, and Laurel,
Mississippi.
OVERVIEW
Just over four years ago, we started a new focus area through an
acquisition of a carbon dioxide ("CO2") tertiary flood in an area very familiar
to us, Mississippi. We have subsequently acquired other related assets and are
making that focus area a major part of our business. In summary, we are
gradually becoming more of a tertiary exploitation company than a traditional
acquire, drill and exploit type of exploration and production company. We
particularly like this play as (i) it is lower risk and more predictable than
most traditional exploration and development activities, (ii) it provides a
reasonable rate of return at relatively low oil prices (upper teens to low
twenties in the area of our current operations), and (iii) we have virtually no
competition for this type of activity in our geographic area. Generally, from
East Texas to Florida, there are no significant natural sources of carbon
dioxide except our own, and these large volumes of CO2 that we own drive the
play.
During the last two years, we have gradually increased the percentage of
our spending dedicated to CO2 related operations. During 2002, we spent
approximately 23% of our capital budget on these operations, and during 2003 we
spent approximately 27%. During 2004, we anticipate spending approximately 47%
of our capital budget on these CO2 related projects. There are certain
short-term ramifications to the gradual shift in focus, the most significant
being relatively flat production levels from 2002 through 2004. This results
from a shift in capital spending from shorter-life, higher-decline natural gas
properties to longer-life oil properties (the tertiary operations) that have
lower initial production rates and a longer lead time before production
commences. In our tertiary operations, there is a significant delay between the
initial capital expenditures and the resulting production, as the operations
require installation of certain facilities before CO2 flooding can commence and
there is usually a six- to twelve-month delay between the first injections of
CO2 and resultant oil production. While our production from these tertiary
operations has increased each year, during 2003 it did not quite offset the more
rapid declines in our natural gas production in both Louisiana and offshore,
which have steep decline rates due to their relatively short lives. For similar
reasons, we expect our overall production for 2004 to be about the same as in
2003. Although still preliminary, we expect production to be higher in 2005, as
the projected increases in production from our tertiary operations should exceed
the production declines elsewhere. Our tertiary operations are also contributing
to a general increase in operating expenses per BOE, although that increase is
partially offset by a gradual improvement in our overall oil price relative to
NYMEX. See "CO2 Operations" under "Results of Operations" below for a more
extensive discussion of these operations and their perceived potential.
One of our primary financial goals during 2003 was to reduce our total debt
to approximately $300 million by year-end, a proposed $50 million reduction from
the $350 million outstanding as of December 31, 2002. This target was determined
by reviewing our leverage and setting a debt level that we believed to be
reasonable in the anticipated near-term price environment. We generally measure
leverage using 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, which we currently define as oil prices of around
$25.00 per Bbl and natural gas prices of around $3.50 per Mcf. We were able to
accomplish this goal with the net proceeds from the Genesis transactions (see
"Genesis Transactions" below), property sales and cash generated from
operations, ending the year with $300 million of total debt. During 2004 and the
near future, we plan to spend no more than cash flow from operations, unless we
make a significant acquisition, which would likely be financed with debt.
33
Denbury Resources Inc.
Management's Discussion and Analysis of Financial
Condition and Results of Operations
Graph depicting average NYMEX crude oil price listings by quarter from 2001 to
2003
2001 2002 2003
- --------------------------------------- -------------------------------------- -----------------------------------
Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4
- --------------------------------------- -------------------------------------- -----------------------------------
$28.79 $27.98 $26.78 $20.45 $21.68 $26.24 $28.26 $28.20 $33.87 $28.93 $30.26 $31.22
Graph depicting average NYMEX natural gas price listings by quarter from 2001 to
2003
2001 2002 2003
- --------------------------------------- -------------------------------------- -----------------------------------
Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4
- --------------------------------------- -------------------------------------- -----------------------------------
$ 6.30 $ 4.41 $ 2.81 $ 2.72 $ 2.49 $ 3.41 $ 3.21 $ 4.33 $ 5.90 $ 5.73 $ 4.89 $ 5.40
Our cash flow from operations and net income have been strong during the
last three years, primarily because of higher than historical commodity prices.
For 2003, the higher commodity prices more than offset a 2% decline in
production and higher operating expenses, resulting in a 24% increase in cash
flow from operations as compared to 2002. The increase in net income
corresponded to the higher cash flow from operations, increasing 21% from 2002
to 2003. Finding costs and the related depreciation and amortization expense on
a per BOE basis increased in 2003 because of higher expenditure levels in 2003
than in 2002 in the offshore Gulf of Mexico, which typically has higher finding
costs, and because some of our higher potential exploration targets failed to
materialize. Our finding and development costs related to our tertiary
operations were relatively low (just over $5.00 per BOE for 2003 including the
related future development costs), but they were not sufficient to offset the
higher finding and development costs of the offshore and other natural gas
properties. See "Results of Operations" for a more thorough discussion of these
factors.
Debt Refinancing
In late March 2003, we issued $225 million of 7.5% Senior Subordinated
Notes due 2013 to refinance our $200 million of then existing 9% Senior
Subordinated Notes due 2008. The subordinated debt was refinanced to take
advantage of the then current attractive interest rates and to extend the
maturity of our long-term debt an additional five years. We estimate that we
will save approximately $2.6 million per year in interest expense as a result of
this refinancing. The total cost of the refinancing was approximately $15.6
million, consisting of the debt issue discount, underwriters' commission and
other expenses totaling approximately $6.6 million, and a $9.0 million call
premium to retire the old notes. The old notes were not retired until April 16,
2003, at the end of the required thirty-day notice period to call the old notes.
We had a pre-tax charge to earnings in the second quarter of 2003 of
approximately $17.6 million from the early retirement of the old 9% notes, made
up of the $9.0 million call premium and the write-off of the remaining
unamortized discount of $4.8 million and debt issue costs of $3.8 million on the
old notes. The proceeds from the new issue were used to retire the old 9%
subordinated notes in April 2003.
Genesis Transactions
During November 2003, we sold 167.5 Bcf of CO2 to Genesis Energy, L.P.
("Genesis") for $24.9 million ($23.9 million as adjusted for transaction costs
and interim cash flow from the effective date until closing) under a volumetric
production
34
Denbury Resources Inc.
Management's Discussion and Analysis of Financial
Condition and Results of Operations
payment ("VPP"). Included in the transaction was the assignment to Genesis of
three of our existing long-term CO2 supply agreements with our industrial
customers, which represented approximately 60% of our industrial CO2 sales
volumes at that time. Pursuant to the volumetric production payment, Genesis may
take up to 52.5 MMcf of CO2 per day through 2009, 43.0 MMcf/d from 2010 through
2012 and 25.2 MMcf/d to the end of the term. We provide processing and
transportation services to Genesis for a fee of $0.16 per Mcf in connection with
the delivery of CO2 to the industrial customers.
In a separate transaction, we purchased approximately 689,000 common
partnership units of Genesis for $7.15 per unit for an aggregate purchase price
of $4.9 million, representing approximately 7.25% of Genesis' total outstanding
common units, increasing our total ownership of Genesis to 9.25%. We used the
net cash proceeds of approximately $20 million from these two transactions to
reduce our bank debt.
CAPITAL RESOURCES AND LIQUIDITY
Since our last significant acquisition in the third quarter of 2002, we
have generally been reducing our debt with both excess cash flow from operations
and proceeds from property sales. In addition to the $50 million debt reduction
during 2003 (see "Overview" above), we repaid approximately $25 million of bank
debt during the fourth quarter of 2002, or a total of approximately $75 million
of repayments during the last fifteen months. By December 31, 2003, we had
reached our targeted debt level of $300 million, so we anticipate that our
spending during 2004 will be about the same, or less than, our cash flow from
operations, as we do not see the need for further debt reduction. However, there
will likely be some minor borrowings and repayments throughout the year in order
to manage our working capital and to fund minor acquisitions. We do not
anticipate an increase in overall debt during 2004 unless we make a significant
acquisition. As of February 27, 2004, our total debt was $305 million,
comprising $225 million of 7.5% Senior Subordinated Notes due 2013 and $80
million of bank debt. The incremental borrowings of $5.0 million since December
31 were to fund an acquisition of another CO2 producing well, which also
included another industrial sales contract, giving us ownership of every
producing CO2 well in the region.
Graph depicting the Company's debt to total capitalization (in millions of
dollars)
Year Ended December 31,
------------------------------------------------
2000 2001 2002 2003
---- ---- ---- ----
Long-term Debt 199.0 334.8 344.9 298.2
Total Capitalization 415.2 683.9 711.7 719.4
Capital Spending Forecast
Our 2004 capital budget, excluding acquisitions, is currently approximately
$172 million. Based on current projections, using NYMEX futures prices in place
as of the last part of February 2004, this exploration and development spending
level is expected to be as much as $25 million less than our 2004 forecasted
cash flow. However, as we have done from time to time in prior years, if
commodity prices remain strong, we will likely increase our capital budget
throughout the year to more closely match our cash flow from operations. As of
February 27, 2004, we had approximately $140 million of availability on our bank
borrowing base, more than we could reasonably expect to use for short-term
working capital requirements and enough credit line availability to fund all but
the largest acquisitions.
35
Denbury Resources Inc.
Management's Discussion and Analysis of Financial
Condition and Results of Operations
During 2004, we intend to focus on our CO2 operations, one objective of
which will be to develop additional CO2 reserves and deliverability for a
possible future expansion of our CO2 tertiary floods to other areas, most likely
East Mississippi. (See "CO2 Operations" under "Results of Operations" for a
discussion of the production and reserve potential.) This may have a short-term
impact on our oil and natural gas production growth, although we believe it will
provide long-term value for our shareholders, as it is the first step in
expanding our CO2 operations, adding additional fields as CO2 flood candidates,
and ultimately adding oil reserves. We are also considering the possibility of
selling certain lower priority properties during 2004, including our offshore
operations, which in the short-term would also reduce production, although the
proceeds would likely be used to reduce debt. Ideally, rather than pay down
debt, we would like to re-invest any sales proceeds in other properties that
could be future potential tertiary flood candidates. In March 2004 we hired an
investment banker to assist us with the sale of our offshore operations. No
buyer has been identified as yet, and if the sales price is less than
anticipated, we may withdraw the sales package.
Our current acquisition focus is to seek additional properties that are
potential tertiary flood candidates and to acquire incremental interests in
fields that we already own. We continue to review other properties in all of our
operating areas where we see additional potential based on our review of 3D
seismic or other geologic and geophysical data, although this activity is a
lower priority for us than has been the case historically, given our substantial
inventory of projects in-house related to tertiary operations. Any acquisitions
that we do make will likely be funded with either excess cash flow or bank debt.
Sources and Uses of Capital Resources
During 2003, we generated approximately $197.6 million of cash flow from
operations and generated an additional $29.4 million of cash from sales of oil
and gas properties. The largest single asset sale was the sale of Laurel Field,
acquired from COHO in August 2002, which netted us approximately $25.9 million.
Later in the year, we also sold a volumetric production payment to Genesis,
which netted us approximately $20 million of cash (see "Genesis Transactions"
above). During 2003, we spent $146.6 million on oil and natural gas exploration
and development expenditures, $22.7 million on CO2 capital investments and
acquisitions, and approximately $11.8 million on oil and natural gas property
acquisitions, for total capital expenditures of approximately $181.1 million. In
addition, during 2003 we incurred approximately $15.6 million of costs for the
subordinated debt refinancing (see "Debt Refinancing" above). The $147.3 million
of net total expenditures (including the $15.6 million of debt refinancing costs
and net of property sales) was funded by our cash flow from operations, with the
balance used to reduce our total debt by approximately $50.0 million.
Graph depicting capital expenditures (in million of dollars)
Year Ended December 31,
---------------------------------
2001 2002 2003
----- ----- -----
Acquisitions 157.1 60.6 14.9
Development and Exploration 170.1 111.4 166.3
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, for a total of approximately
$172.1 million. 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.
36
Denbury Resources Inc.
Management's Discussion and Analysis of Financial
Condition and Results of Operations
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 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.
Graph depicting development and exploration expenditures vs. cash flow from
operations (in millions of dollars)
Year Ended December 31,
---------------------------------
2001 2002 2003
----- ----- -----
Development and Exploration Expenditures 170.1 111.4 166.3
Cash Flow from Operations 185.0 159.6 197.6
Bank Credit Facility
Our bank borrowing base was reaffirmed as of October 1, 2003 at $220
million as part of the semi-annual review by the banks. During 2003, we amended
our credit agreement to increase the percentage of production we are allowed to
hedge, setting a maximum of 85% of our forecasted production from our proved
reserves for the current year (as defined in the amendment and which may include
up to 18 months), a maximum of 70% of the forecasted production for the
subsequent year, a maximum of 55% of the forecasted production for the third
year and a maximum of 40% of the forecasted production for the fourth year. We
also amended the credit agreement to allow us to borrow up to $20 million in a
bond issue from a Mississippi governmental authority, resulting in the exemption
or reduction of sales and ad valorem taxes on CO2 facilities we build through
May 2005 in Mississippi. This bond funding arrangement was completed in May
2003. Any borrowings under this bond program will be purchased by the banks in
our credit facility, will become part of our outstanding borrowings under our
credit line and will accrue interest and be repaid on the same basis as our bank
line. Our bank agreement was amended again in December 2003 to accommodate our
conversion to a holding company organizational structure, although this
amendment did not include any significant changes to the terms or covenants
included therein (see "General and Administrative Expenses" under "Results of
Operations" and Note 1 to the Consolidated Financial Statements). Our next bank
borrowing base redetermination will be as of April 1, 2004, based on December
31, 2003 assets. We do not anticipate any significant changes to our borrowing
base at this next review, although we cannot be certain, as there are several
subjective aspects to the borrowing base determination.
OFF-BALANCE SHEET ARRANGEMENTS
Commitments and Obligations
We have no off-balance sheet arrangements, special purpose entities,
financing partnerships or guarantees, other than as disclosed in this section.
We have no debt or equity triggers based upon our stock or commodity prices. Our
dollar denominated obligations that are not on our balance sheet include our
operating leases, the largest of which is a $6.0 million lease financing of
certain equipment at our CO2 recycling facility at Mallalieu Field that
commenced in August 2003. We also have several leases relating to office space
and other minor equipment leases. We also have dollar related obligations that
are not currently recorded on our balance sheet relating to various obligations
for development and exploratory expenditures that arise from our normal capital
expenditure program or from 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 forecasted in our proved reserve
reports. For a further discussion of our future development costs and proved
reserves, see "Results of Operations - Depletion, Depreciation and
Amortization."
At December 31, 2003, we had a total of $820,000 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 approximately $7.0 million as of
37
Denbury Resources Inc.
Management's Discussion and Analysis of Financial
Condition and Results of Operations
December 31, 2003, and also included $21.6 million in letters of credit, of
which $12.5 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 and a VPP sold to Genesis as discussed in Note 3 to our
Consolidated Financial Statements.
A summary of our obligations is presented in the following table:
Payments Due by Period
- ---------------------------------------------------------------------------------------------------------------------------
Amounts in Thousands Total 2004 2005 2006 2007 2008 Thereafter
- ---------------------------------------------------------------------------------------------------------------------------
Contractual Obligations:
- -----------------------
Bank debt (a) $ 75,000 $ - $ - $ 75,000 $ - $ - $ -
Subordinated debt (a) 225,000 - - - - - 225,000
Operating lease obligations 16,621 2,664 2,784 2,786 2,781 2,670 2,936
Capital expenditure obligations (b) 6,657 6,657 - - - - -
Other long-term liabilities reflected
in our Consolidated Balance Sheet:
Derivative liabilities (c) 37,129 37,057 72 - - - -
Other Cash Commitments:
- ----------------------
Future development costs on proved
reserves, net of capital obligations (d) 268,936 69,329 107,536 24,399 29,548 18,656 19,468
Asset retirement obligations (e) 82,733 2,563 4,464 2,725 1,006 2,880 69,095
- ---------------------------------------------------------------------------------------------------------------------------
Total $ 712,076 $ 118,270 $ 114,856 $ 104,910 $33,335 $ 24,206 $ 316,499
===========================================================================================================================
(a) These long-term borrowings and related interest payments are further
discussed in Note 6 to the Consolidated Financial Statements. The table
assumes that our long-term debt is held until maturity.
(b) Represents future minimum cash commitments under contracts in place as
of December 31, 2003, primarily for drilling rig services and well related
costs. 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 usually part of our normal operating
expenses or part of our capital budget, which for 2004 is currently set at
$172 million. In addition, we have recurring expenditures for such things
as accounting, engineering and legal fees, software maintenance,
subscriptions, and other overhead type items. Normally these do not change
materially from year to year and are part of our general and administrative
expenses. We have not attempted to estimate these types of expenditures in
this table as most could be quickly cancelled with regard to any specific
vendor, even though the expense itself may be required for ongoing normal
operations of the Company.
(c) Represents the estimated future payments under our derivative
obligations based on the futures market prices as of December 31, 2003.
These amounts will change as oil and natural gas commodity prices change.
The estimated fair market value of our oil and natural gas commodity
derivatives at December 31, 2003 was a $44.6 million liability. See further
discussion of our derivative contracts in "Market Risk Management"
contained in this Management's Discussion and Analysis of Financial
Condition and in Note 9 to the Consolidated Financial Statements.
(d) Represents projected capital costs as scheduled in our December 31,
2003 proved reserve report that are necessary in order to recover our
proved undeveloped reserves but are not current contractual commitments.
(e) Represents the estimated future asset retirement obligations on an
undiscounted basis. The discounted asset retirement obligation of $43.8
million, as determined under SFAS No. 143, is further discussed in Note 4
to the Consolidated Financial Statements.
38
Denbury Resources Inc.
Management's Discussion and Analysis of Financial
Condition and Results of Operations
Long-term contracts require us to deliver CO2 to our industrial CO2
customers at various contracted prices, plus we have a CO2 delivery obligation
to Genesis related to a VPP entered into during 2003 (see "Genesis Transactions"
above). Based upon the maximum amounts deliverable as stated in the contracts
and the volumetric production payment, we estimate that we may be obligated to
deliver up to 412 Bcf of CO2 to these customers over the next 18 years; however,
based on the current level of deliveries, our commitment would likely be reduced
to approximately 310 Bcf. The maximum volume required in any given year is
approximately 97 MMcf/d, although based on our current level of deliveries, this
would likely be reduced to approximately 70 MMcf/d. Given the size of our proven
CO2 reserves at December 31, 2003 (approximately 1.6 Tcf before deducting
approximately 162.6 Bcf for the VPP), our current production capabilities and
our projected levels of CO2 usage for our own tertiary flooding program, we
believe that we can meet these delivery obligations.
RESULTS OF OPERATIONS
CO2 Operations
OVERVIEW. Since 1999, when we acquired our first tertiary oil recovery
operation at Little Creek Field, tertiary recovery operations have become
increasingly important for us. More importantly, in February 2001 we acquired
the sources of CO2 and a pipeline to transport it to these fields. Since
February 2001, we have acquired two and drilled three CO2 producing wells,
doubling our initial proven CO2 reserves to 1.6 Tcf as of December 31, 2003
(including the 162.6 Bcf of reserves dedicated to a VPP with Genesis). Today, we
own every known producing CO2 well in the region, providing us a significant
strategic advantage in the acquisition of other properties in Mississippi and
Louisiana that could be further exploited through tertiary recovery. With the
latest acquisition, which closed in early January 2004, we are capable of
producing approximately 250 MMcf/d of CO2, about three times the production
capacity at the time of our initial acquisition. We have four additional CO2
wells planned for 2004 (including one side-track operation), which are expected
to increase our production capacity to around 350 MMcf/d of CO2 by the end of
2004, just short of our forecasted maximum requirement of about 400 MMcf/d in
2007 for the planned future projects in southwestern Mississippi along our CO2
pipeline. During 2004, two of these CO2 wells will test new structures, which if
successful, will both increase our CO2 reserves and provide additional
production capacity. We believe it is prudent to add additional reserves and
deliverability before we commence our tentative plans to expand our CO2
operations to East Mississippi and/or other regions. Based on our current
tertiary recovery projects and planned phases of expansion in both Southwest and
East Mississippi, we will continue to drill additional CO2 wells after 2004,
attempting to further increase our production capacity to at least 530 MMcf/d of
CO2 production by 2011, in order to meet the delivery requirements for the
operations that we currently have modeled. 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.
OIL PRODUCTION POTENTIAL. Although our oil production from our CO2 tertiary
recovery activities is still relatively modest, we expect it to be an ever
increasing portion of our production. Almost all of our incremental CO2
production is being used for our tertiary recovery operations currently ongoing
at Little Creek, Mallalieu and McComb Fields. We have tentatively scheduled
tertiary projects at other oil fields along our pipeline, and project that these
projects will increase our net tertiary related oil production from its current
level of over 6,000 Bbls/d during January 2004, to as much as 18,000 Bbls/d in
2010. As of December 31, 2003, we had approximately 35.3 MMBbls of proven oil
reserves related to tertiary operations in these fields along our CO2 pipeline
and have identified and estimated significant additional potential in fields
that we own in this area. In addition to the development of the fields along our
CO2 pipeline, we have completed a preliminary study of the feasibility of
implementing tertiary recovery operations in East Mississippi, reviewing five
fields that we expect to be part of the first phase of operations in this area.
While the study is preliminary and requires significant additional work and
review, including a determination of the precise costs and best location for a
CO2 pipeline to this part of the state, and further refinement of the economics,
preliminarily this project appears to have reasonable economics at NYMEX oil
prices in the low to mid twenties. These five fields also appear to have
aggregate
39
Denbury Resources Inc.
Management's Discussion and Analysis of Financial
Condition and Results of Operations
potential oil reserves of approximately the same magnitude as those fields along
our existing CO2 pipeline. Combining the initial production forecast for both of
these areas, the forecasted oil production from tertiary operations could peak
at rates of almost 32,000 Bbls/d by 2013. While it is extremely difficult to
accurately forecast that far into the future, we do believe that our tertiary
recovery operations provide significant long-term production growth potential at
reasonable rates of return with relatively low risk.
FINANCIAL STATEMENT IMPACT. 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
(primarily due to the significant energy requirements to re-compress the
CO2 back into a liquid state for re-injection purposes), 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 around
$10 per BOE in operating expenses over the life of the field for those
projects along our CO2 pipeline, although the cost per BOE is generally
higher at the beginning of each operation. These levels of operating
expenses compare to a cost of around $5 to $7 per BOE for a more
traditional oil property. We allocate the cost to produce and transport the
CO2 between the sales to commercial users and CO2 used in our own oil
fields. The CO2 operating expenses allocated to our oil fields are recorded
as lease operating expenses on those fields.
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 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 and our 2003 average decreased further to $3.60 below NYMEX. We
expect that this positive trend should continue, subject of course to the
normal fluctuations in the marketplace.
2003 OPERATING ACTIVITIES. During late July and early August 2003, we
upgraded our CO2 facility at Jackson Dome, increasing the CO2 processing
capacity of our facility by approximately 50%, from around 200 MMcf/d to
approximately 300 MMcf/d. This upgrade was performed several months ahead of our
original schedule in order to handle the higher than expected production volumes
from our CO2 wells drilled during late 2002 and early 2003. At the same time, we
increased the size of our CO2 processing facility at Mallalieu Field, increasing
the amount of CO2 that we can recycle at that field from approximately 28 MMcf/d
to approximately 108 MMcf/d.
Our oil production from our CO2 tertiary recovery activities increased 18%
from 2002 levels of 3,970 Bbls/d to 4,671 Bbls/d during 2003, and to 5,579
Bbls/d during the fourth quarter of 2003. This represents approximately 29%
40
Denbury Resources Inc.
Management's Discussion and Analysis of Financial
Condition and Results of Operations
of our total corporate oil production during the fourth quarter of 2003 and
approximately 16% of our total corporate production on a BOE basis. We believe
that the year-over-year increase would have been more significant had we not
curtailed CO2 production in the second quarter of 2003 due to a leak in a newly
installed CO2 pipeline and a one-week shutdown during the third quarter while
the facilities at Jackson Dome were upgraded. Our experience has indicated that
any time our CO2 production and associated injections are curtailed, there is a
corresponding drop in our oil production from these projects. While our CO2
production capability is currently ahead of schedule, as previously noted,
temporary curtailments have had a negative short-term effect on our 2003 oil
production. Recently we have been injecting more CO2 than initially forecasted,
contributing to the recent increase in the related oil production, as evidenced
by the record fourth quarter 2003 production, and a preliminary production
estimate of over 6,000 Bbls/d during January 2004. We expect that this oil
production will continue to increase, although the increases are not always
predictable or consistent.
We spent approximately $0.15 per Mcf to produce our CO2 during 2003,
slightly higher than our 2002 annual average of $0.13 per Mcf, primarily due to
higher royalty expenses, as certain of our royalty payments increase if the
price of oil increases beyond a certain threshold, and due to approximately
$700,000 of workover expenses on one CO2 well during the third quarter. The
higher overall CO2 production rates partially offset the workover expenses. Our
estimated total cost per thousand cubic feet of CO2 during 2003 was
approximately $0.22, after inclusion of depreciation and amortization expense,
still significantly less than the $0.34 per thousand cubic feet that we would
currently be paying under the purchase contract in place at the time we acquired
the CO2 properties in February 2001.
The higher cost per Mcf of CO2 during 2003 contributed to a corresponding
increase in the operating costs of our tertiary projects, as did higher
electricity and other expenses, as we continue to inject and recycle higher
volumes of CO2 each quarter. Furthermore, at Mallalieu Field in August 2003 we
commenced lease payments relating to a portion of the upgraded CO2 facilities
there (see "Commitments and Obligations" above). For 2003, our operating costs
for our tertiary properties averaged $11.34 per BOE, higher than our 2002 annual
average of $9.84 per BOE.
In addition to using CO2 for our tertiary operations, 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, $6.2 million during 2002 and $6.5
million during 2003. Our average CO2 production during 2001, 2002 and 2003 was
approximately 84 million, 104 million, and 170 million cubic feet per day, of
which approximately 53% in 2001, 54% in 2002 and 62% in 2003 was used in our
tertiary recovery operations, with the balance sold to third parties for
industrial use.
At December 31, 2003, we had proved reserves of 35.3 MMBbls relating to our
tertiary recovery operations. Through December 31, 2003, we had spent a total of
$104.8 million on fields involved in this process, and had received $83.0
million in net cash flow (revenue less operating expenses and capital
expenditures), leaving us a balance of $21.8 million to recover for payout. The
proved oil reserves in our CO2 fields have a PV-10 Value of $434.6 million,
using December 31, 2003 constant NYMEX pricing of $32.52 per Bbl. These amounts
do not include the capital costs or related depreciation and amortization of our
CO2 producing properties. Through December 31, 2003, we have spent a total of
$85.3 million on our CO2 producing properties, received a total of $41.3 million
in net cash flow (revenue less operating expenses and capital expenditures,
including the Genesis volumetric production payment receipts), leaving us a
balance of approximately $44.0 million of unrecovered costs.
CO2 RELATED CAPITAL BUDGET FOR 2004. Tentatively, we plan to spend
approximately $30 million in 2004 in the Jackson Dome area, over and above what
is currently required for our operations in Southwest Mississippi, with the
intent to add additional CO2 reserves and deliverability for future operations.
Approximately $50 million in capital expenditures is budgeted in 2004 for our
oil fields with tertiary operations, increasing our combined CO2 related
expenditures to just under 50% of our 2004 capital budget.
41
Denbury Resources Inc.
Management's Discussion and Analysis of Financial
Condition and Results of Operations
Operating Income
Cash flow from operations and net income have been strong for the last
three years, primarily because of higher than historical commodity prices.
Production increased 14% from 2001 to 2002, but declined slightly (2%) in 2003
(see also "Overview"). The higher commodity prices in 2003 more than offset the
production decline, resulting in higher overall net income and cash flow from
operations. Commodity prices were slightly lower in 2002, reducing our overall
net income and cash flow during 2002 as compared to 2001.
Year Ended December 31,
- ----------------------------------------------------------------------------------------------------------
Amounts in Thousands Except Per Share Amounts 2003 2002 2001
- ----------------------------------------------------------------------------------------------------------
Net income $ 56,553 $ 46,795 $ 56,550
Net income per common share:
Basic $ 1.05 $ 0.88 $ 1.15
Diluted 1.02 0.86 1.12
- ----------------------------------------------------------------------------------------------------------
Adjusted cash flow from operations $ 189,802 $ 164,565 $ 186,801
Net change in assets and liabilities relating to operations 7,813 (4,965) (1,754)
- ----------------------------------------------------------------------------------------------------------
Cash flow from operations (GAAP measure) $ 197,615 $ 159,600 $ 185,047
- ----------------------------------------------------------------------------------------------------------
Adjusted cash flow from operations is a non-GAAP measure that represents
cash flow provided by operations before changes in assets and liabilities, as
presented in our Consolidated Statements of Cash Flows. In our discussion of
cash flow from operations herein, we have elected to discuss these two
components of cash flow provided by operations (the GAAP measure).
Graph depicting cash flow from operations by quarter (in millions of dollars)
2001 2002 2003
--------------------- --------------------- ---------------------
Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4
--------------------- --------------------- ---------------------
Cash flow from operations 66.1 30.9 45.1 43.0 12.0 46.6 44.4 56.6 35.5 60.5 49.8 51.8
Adjusted cash flow from operations* 55.0 45.2 48.7 37.9 28.5 43.4 44.2 48.4 47.4 49.0 45.6 47.8
*Cash flow from operations before changes in assets and liabilities. See table above.
Adjusted cash flow from operations, the non-GAAP measure, measures the cash
flow earned or incurred from operating activities without regard to the
collection or payment of associated receivables or payables. We believe that
this is important to consider separately, as we believe it can often be a better
way to discuss changes in operating trends in our business caused by changes in
production, prices, operating costs, and so forth, without regard to whether the
earned or incurred item was collected or paid during that year. We also use this
measure because the collection of our receivables or payment of our obligations
has not been a significant issue for our business, but merely a timing issue
from one period to the next, with fluctuations generally caused by significant
changes in commodity prices or significant changes in drilling activity.
The net change in assets and liabilities relating to 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 2003, our accounts payable and accrued liabilities increased as a
result of our higher drilling activity level late in the year, particularly
offshore, increasing our available cash from operations. Conversely, 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 that was not paid (or even due) until 2002.
42
Denbury Resources Inc.
Management's Discussion and Analysis of Financial
Condition and Results of Operations
Certain of our operating statistics for the last three years are set forth
in the following chart.
Year Ended December 31,
- -----------------------------------------------------------------------------------------------------------
2003 2002 2001
- -----------------------------------------------------------------------------------------------------------
Average daily production volume
Bbls 18,894 18,833 16,978
Mcf 94,858 100,443 85,238
BOE(1) 34,704 35,573 31,185
Operating revenues and expenses (thousands)
Oil sales $189,442 $153,705 $132,219
Natural gas sales 196,021 121,189 128,179
Gain (loss) on settlements of derivative contracts (2) (62,210) 932 18,654
-------- -------- --------
Total oil and natural gas revenues $323,253 $275,826 $279,052
======== ======== ========
Lease operating expenses $ 89,439 $ 71,188 $ 55,049
Production taxes and marketing expenses 14,819 11,902 10,963
-------- -------- --------
Total production expenses $104,258 $ 83,090 $ 66,012
======== ======== ========
CO2 sales to industrial customers (3) $ 8,188 $ 7,580 $ 5,210
CO2 operating expenses 1,710 1,400 891
-------- -------- --------
CO2 operating margin $ 6,478 $ 6,180 $ 4,319
======== ======== ========
Unit prices-including impact of hedges(2)
Oil price per Bbl $ 24.52 $ 22.27 $ 21.65
Gas price per Mcf 4.45 3.35 4.66
Unit prices-excluding impact of hedges(2)
Oil price per Bbl $ 27.47 $ 22.36 $ 21.34
Gas price per Mcf 5.66 3.31 4.12
Oil and gas operating revenues and expenses per BOE (1)
Oil and natural gas revenues (including hedges) $ 25.52 $ 21.24 $ 24.52
-------- -------- --------
Lease operating expenses $ 7.06 $ 5.48 $ 4.84
Production taxes and marketing expenses 1.17 0.92 0.96
-------- -------- --------
Total production expenses $ 8.23 $ 6.40 $ 5.80
======== ======== ========
(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.
(3) For 2003, includes deferred revenue of $322,000 associated with a volumetric production payment and $355,000
of transportation income, both from Genesis.
Graph depicting production by quarter (Average MBOE per day)
2001 2002 2003
------------------------- ------------------------- -------------------------
Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4
------------------------- ------------------------- -------------------------
Oil 16.2 16.5 16.9 18.3 17.8 17.9 18.9 20.7 19.6 19.0 18.0 19.0
Natural Gas 10.4 11.4 18.2 16.7 17.6 17.6 16.6 15.2 16.5 16.1 15.1 15.6
------------------------- ------------------------- -------------------------
Total BOE 26.6 27.9 35.1 35.0 35.4 35.5 35.5 35.9 36.1 35.1 33.1 34.6
43
Denbury Resources Inc.
Management's Discussion and Analysis of Financial
Condition and Results of Operations
PRODUCTION. Average daily production by area for 2001, 2002 and 2003, and
each of the quarters of 2003 is listed in the following table (BOE/d).
Average Daily Production (BOE/d)
--------------------------------------------------------------------------
First Second Third Fourth
Quarter Quarter Quarter Quarter
Operating Area 2001 2002 2003 2003 2003 2003 2003
---------------------------- --------------------------------------------------------------------------
Mississippi - non-CO2 floods 13,481 13,378 14,537 13,600 13,367 13,066 13,638
Mississippi - CO2 floods 2,560 3,970 4,345 4,522 4,227 5,579 4,671
Onshore Louisiana 9,268 8,050 8,509 8,231 7,836 8,320 8,222
Offshore Gulf of Mexico 5,691 9,975 8,544 8,537 7,374 7,357 7,949
Other 185 200 158 160 312 268 224
--------------------------------------------------------------------------
Total Company 31,185 35,573 36,093 35,050 33,116 34,590 34,704
============================ ==========================================================================
Our average daily BOE production for 2003 was approximately 2% lower than
in 2002, due primarily to production decreases in our offshore Gulf of Mexico
properties, offset in part by production increases in our Mississippi CO2 flood
properties. In both the offshore and onshore Louisiana areas, we have
experienced production declines from normal depletion, along with delayed
production from equipment downtime and well workovers, with the single largest
production decrease on a field basis coming from Thornwell Field in Louisiana.
Average annual production at this field declined 1,346 BOE/d (principally
natural gas), from 2002 to 2003, although we have generally had good success
from our acquisition of Thornwell Field in 2000, as evidenced by a net profit
(at the field level) to date through December 31, 2003 of $18.9 million and a
remaining PV-10 Value of the reserves at year-end prices of $62.4 million.
However, this field is characterized by relatively short-lived gas production
that declines rapidly unless there is constant drilling activity. During 2003,
our drilling activity at Thornwell was significantly less than in prior years as
the field became more fully developed, contributing to the production decline.
This trend is expected to continue into 2004. Partially offsetting the large
decrease from Thornwell Field, onshore Louisiana, was the impact of our recent
success in the Exxon Fee A-1 well in North Lirette Field, which came on
production late in the third quarter. A second well drilled in that field
commenced production early in the fourth quarter. While both are strong
producers, they too are relatively short-lived wells and are expected to decline
in the near future.
The production increase in our Mississippi CO2 flood properties is almost
entirely due to increased production at Mallalieu Field, which increased over
1,000 BOE/d from the prior year due to the CO2 flood that we initiated there
during 2002 (see "CO2 operations" above for a further discussion of our tertiary
properties). Offshore, production declined at several fields during the year,
generally due to normal depletion and the short-lived nature of the reserves.
Late in the fourth quarter of 2003, we made 15 well completions, four at Brazos
A-21, three at North Padre A-9, three at Chandeleur Sound 69, two at West
Cameron 192 and three at West Cameron 427. Although most of these were not
completed until the latter half of the fourth quarter, the incremental
production was sufficient to arrest, at least temporarily, the overall
production decline in this area. Depending on our 2004 drilling success, we
expect 2004 production offshore to be relatively flat or down slightly when
compared with 2003 production.
In addition, there are other factors that have impacted our production. For
example, we have had temporary curtailments of CO2 injections at least twice
during 2003, which have delayed the response of additional oil production from
these projects (see "CO2 Operations" above). Our expected production increases
from our exploration and development results were also less than anticipated,
particularly during the first half of 2003, and we have experienced unexpected
delays in drilling and completing offshore wells. In January 2003, we sold one
of the largest producing fields acquired in the August 2002 COHO acquisition.
Year over year, the properties in the COHO package contributed an additional 908
BOE/d to our annual production average, although there have been more
significant fluctuations on a quarterly basis due to the timing of the
acquisition and subsequent disposition. Our production for 2003 was weighted
slightly toward oil
44
Denbury Resources Inc.
Management's Discussion and Analysis of Financial
Condition and Results of Operations
(54%), and it appears that we will remain weighted toward oil in the future due
to our increasing emphasis on tertiary operations, unless we make an acquisition
that is predominantly natural gas.
Our production growth in 2002, as compared to 2001, was primarily 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 $4.0 million acquisition of Mallalieu Field in May 2001,
the $157.4 million corporate acquisition of Matrix in July 2001 (offshore Gulf
of Mexico properties), 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. The biggest impact on 2002 was the effect of a full year of
production from the Matrix properties (as compared to six months of production
during 2001) and five months of production from the COHO acquisition.
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. Annual average production under our
ownership peaked in 2001 at 7,908 BOE/d, averaging 7,479 BOE/d in 2002 and 7,535
BOE/d for 2003. In its early years, our primary emphasis was on implementing our
waterfloods, plus other developmental drilling. During the last few years, we
have expanded our development of the natural gas production in the Selma Chalk
formation, increasing Heidelberg's natural gas production from almost nothing at
the time of acquisition to an average of 10.3 MMcf/d during 2003, the highest
level to date, making Heidelberg Field our third largest natural gas producer
for 2003, but our second largest during the fourth quarter of 2003. Overall
production from this field is expected to remain relatively flat or slightly
decline as the waterflood units appear to have reached a plateau, although there
may be periodic spikes in the natural gas production as a result of recently
drilled natural gas wells and the anticipated production from 16 additional
natural gas wells scheduled for 2004.
OIL AND NATURAL GAS REVENUES. Our oil and natural gas revenues were
relatively flat between 2001 and 2002, but increased 17% between 2002 and 2003.
Three factors cause the change in revenues: commodity prices, production levels
and hedging receipts or payments. 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 6% decrease) and an overall decrease of
$22.1 million in commodity prices (or an 8% decrease). Between 2002 and 2003,
revenues increased by 17%, due primarily to higher commodity prices. The overall
increase in commodity prices contributed $117.3 million in revenue, a 42%
increase, partially offset by a reduction in revenues due to a decrease in cash
receipts from hedges of $63.1 million (a 23% decrease) and an overall decrease
of $6.7 million related to the 2% lower production volumes.
During 2003, we paid out $20.3 million on our oil hedges ($2.95 per Bbl)
and $41.9 million ($1.21 per Mcf) on our natural gas hedges relating to swaps
and collars we purchased a year or more earlier when commodity prices were
lower. About $15.0 million of the hedge payments related to swaps originally put
in place to protect the rate of return for the COHO acquisition in August 2002.
During 2002, we had total net receipts on our hedges of $932,000, paying out
$0.6 million ($0.09 per Bbl) on our oil hedges but collecting a net $1.5 million
($0.04 per Mcf) on our natural gas hedges. During 2001, we collected $18.7
million in hedge receipts, collecting $1.9 million ($0.31 per Bbl) on our oil
hedges and $16.7 million ($0.54 per Mcf) on our natural gas hedges. Most of the
natural gas hedge receipts for 2001 related to funds received from "puts" or
floors purchased at the time of the Matrix acquisition in mid-2001. These hedges
were purchased at a level just below the then current futures price for natural
gas, resulting in cash receipts as natural gas prices dropped significantly
during the latter half of that year. See "Market Risk Management" for a further
discussion of our hedging activities.
Our net oil and natural gas prices have fluctuated as outlined on the prior
table. During 2003, we received the highest weighted average net price per BOE
in our history, netting $25.52 per BOE even after paying out approximately $4.91
per BOE for hedge losses. This resulted from average NYMEX prices of
approximately $31.00 per Bbl and approximately $5.45 per MMBtu during the year.
In addition, we had one of our best years with regard to our realized net
45
Denbury Resources Inc.
Management's Discussion and Analysis of Financial
Condition and Results of Operations
price relative to NYMEX prices. During 2001, we received an average discount to
NYMEX of $4.66 per Bbl. This was reduced to an average discount of $3.73 per Bbl
during 2002 and further reduced to an average discount of $3.60 per Bbl in 2003.
While this differential fluctuates from period to period with market conditions,
we are gradually improving the overall discount as the amount of light sweet oil
production from the tertiary operations continues to grow, improving the overall
quality of our product mix. This tertiary production along our CO2 pipeline
receives a premium price, sometimes in excess of NYMEX prices. Year over year,
there is generally less fluctuation in our natural gas prices relative to NYMEX.
Normally, we receive a slight premium to the NYMEX market, primarily because of
the high Btu content of our natural gas. For 2003, we averaged an $0.18 premium
to NYMEX, as compared to a $0.05 discount in the prior year and a $0.06 premium
during 2001.
OPERATING EXPENSES. Lease operating expenses increased to $7.06 per BOE
during 2003, an increase of 29% from the $5.48 per BOE average during 2002. The
expense of two workovers totaling approximately $2.8 million, relating to
mechanical failures at two onshore Louisiana gas wells, was the single biggest
source of the increase in the first half of 2003, with several smaller
workovers, including one on a CO2 well (see "CO2 Operations" above),
contributing to the higher expense levels during the third quarter of 2003. As
discussed under "CO2 Operations," the growth in our CO2 tertiary projects is
causing an increase in both gross and per BOE operating expenses. Operating
expenses per BOE for the tertiary operations averaged $11.34 per BOE during 2003
as compared to $9.84 per BOE during 2002, and on a gross cost basis, operating
expenses related to these activities increased from $14.3 million in 2002 to
$19.3 million during 2003. Other factors contributing to higher operating
expenses during 2003 were (i) a full year of expenses on the properties acquired
from COHO, which have typically had higher expenses on a per BOE basis than our
other oil properties due to their age, their relatively low production rates and
their general condition at the time we acquired them in August 2002, (ii) lease
fuel costs that increased from $2.5 million during 2002 to $4.4 million during
2003 as a result of higher natural gas prices, and (iii) the slight decline in
2003 production rates, which also had an impact on per BOE rates. While our
lease operating expenses during the fourth quarter of 2003 were lower than in
any other quarter of the year (averaging $6.78 per BOE), they were still
significantly higher than 2002 lease operating expense levels. We anticipate
that lease operating expenses will remain at these generally higher levels, and
probably gradually increase over time, for the aforementioned reasons.
Our 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 were not covered by insurance or were part
of insurance deductibles, higher per BOE costs due to lost production from that
storm and Tropical Storm Isidore, higher than average operating expenses on the
properties acquired from COHO in August 2002, as significant repairs and
clean-up were required, and the general increase caused by growing tertiary
operations. Lease operating expenses increased on a gross basis by $16.1
million, or 29%, between 2001 and 2002.
Production taxes and marketing expenses also increased to $1.17 per BOE in
2003, as compared to an average per BOE of $0.92 during 2002. The higher rate
during 2003 is primarily due to higher commodity prices, as a significant
portion of the severance tax is value based. Marketing expenses were relatively
consistent at $1.8 million during 2003 and $1.9 million during 2002, primarily
related to our offshore properties. Between 2001 and 2002, production taxes and
marketing expenses were about the same, or $0.96 per BOE during 2001 and $0.92
per BOE during 2002.
General and Administrative Expenses
During the last three years, general and administrative ("G&A") expenses on
a per BOE basis have gradually increased from $0.89 per BOE during 2001 to $1.20
per BOE during 2003 in line with the overall increase in gross G&A expense. With
our slight decrease in production during 2003, the impact on G&A expense per BOE
was even more pronounced.
46
Denbury Resources Inc.
Management's Discussion and Analysis of Financial
Condition and Results of Operations
Year Ended December 31,
- ---------------------------------------------------------------------------------------------------
Amounts in Thousands Except Per BOE and Employee Data 2003 2002 2001
- ---------------------------------------------------------------------------------------------------
Gross G&A expense $46,031 $40,149 $33,727
Operator overhead charges (26,823) (23,857) (20,328)
Capitalized exploration expense (5,507) (5,325) (4,102)
- ---------------------------------------------------------------------------------------------------
13,701 10,967 9,297
State franchise taxes 1,488 1,459 877
- ---------------------------------------------------------------------------------------------------
Net G&A expense $15,189 $12,426 $10,174
===================================================================================================
Average G&A expense per BOE $ 1.20 $ 0.96 $ 0.89
Employees as of December 31 374 356 320
====================================================================================================
Gross G&A expenses increased $5.9 million, or 15%, between 2002 and 2003.
The largest component of the increase was approximately $1.4 million of expenses
spent for consultants hired to help document and test our system of internal
controls, a requirement of the Sarbanes-Oxley Act of 2002. The cost of complying
with this act and related new laws and regulations is significantly higher than
these third party expenses, but most other costs are not as easily measured and
identified. The second largest source of the increase was approximately $630,000
of legal, accounting, bank and other fees associated with the conversion to a
holding company organizational structure during December 2003. This corporate
restructure is expected to save us around $750,000 per year in taxes and
expenses and provide other future operational benefits. Other factors also
contributed to the increase, the most significant being expenses associated with
the sale of stock by the Texas Pacific Group in the first and last quarters of
2003, higher year-end expenses for engineering and audit fees, and an overall
increase in personnel and associated expenses primarily related to cost of
living salary increases. Partially offsetting these increases was a reduction in
our 2003 bonuses due to less positive operating results during 2003 in certain
areas. An increase in operator overhead recovery charges and capitalized
exploration costs in 2003 also partially offset the increase in gross G&A. Our
well operating agreements allow us, when we are the operator, to charge a well
with a specified overhead rate during the drilling phase and also to charge a
monthly fixed overhead rate for each producing well. As a result of the
additional operated wells from acquisitions, additional tertiary operations, and
drilling activity during the past year, the amount we recovered as operator
overhead charges increased by 12% between 2002 and 2003. Capitalized exploration
costs increased slightly between 2002 and 2003, along with increases in employee
related costs. The net effect of the increases in gross G&A expenses, operator
overhead recoveries and capitalized exploration costs was a 22% increase in net
G&A expense between 2002 and 2003 and a 25% increase on a per BOE basis.
Most of the G&A increase between 2001 and 2002 was a result of additional
personnel hired as part of the Matrix acquisition in July 2001 and COHO
acquisition in August 2002. Along with the additional personnel, we had general
increases in consultant fees as a result of the higher level of activity. Gross
G&A expenses increased 19% between 2001 and 2002, net expenses increased 22%,
and expenses increased 8% on a per BOE basis.
Interest and Financing Expenses
Year Ended December 31,
- ---------------------------------------------------------------------------------------------------------
Amounts in Thousands Except Per BOE Data 2003 2002 2001
- ---------------------------------------------------------------------------------------------------------
Interest expense $ 23,201 $ 26,833 $ 22,335
Non-cash interest expense (1,251) (2,659) (1,665)
- ---------------------------------------------------------------------------------------------------------
Cash interest expense 21,950 24,174 20,670
Interest and other income (1,573) (1,746) (849)
- ---------------------------------------------------------------------------------------------------------
Net cash interest expense $ 20,377 $ 22,428 $ 19,821
=========================================================================================================
Average net cash interest expense per BOE $ 1.61 $ 1.73 $ 1.74
Average debt outstanding $341,496 $350,556 $264,792
Average interest rate (1) 6.4% 6.9% 7.8%
=========================================================================================================
(1) Includes commitment fees but excludes amortization of debt issue costs.
47
Denbury Resources Inc.
Management's Discussion and Analysis of Financial
Condition and Results of Operations
Interest expense for 2003 decreased from levels in the prior year primarily
due to (i) lower overall interest rates, resulting from an overall drop in
market interest rates on our bank debt and due to the refinancing of our
subordinated debt (see "Debt Refinancing" above), (ii) a 3% lower average
outstanding debt balance during 2003, as we reduced debt by $50 million during
the year, and (iii) reduced debt issue cost amortization resulting from the
complete amortization of costs associated with the original maturity of our bank
credit line in December 2002 after we refinanced and extended the bank credit
line to April 2006.
Our interest expense was $4.5 million (20%) higher in 2002 than 2001
primarily as a result of higher average debt levels. 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 2001, (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. 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). The net effect of these transactions was $85.8 million
higher average debt outstanding during 2002 than in 2001, an increase of 32%.
Interest rates decreased during 2002, partially offsetting the higher debt
levels.
Depletion, Depreciation and Amortization
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 our 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 DD&A rate in
1999, particularly the finding cost of certain of our acquisitions.
Year Ended December 31,
- -----------------------------------------------------------------------------------------------------------
Amounts in Thousands Except Per BOE Data 2003 2002 2001
- -----------------------------------------------------------------------------------------------------------
Depletion and depreciation of oil and natural gas properties $ 87,842 $ 87,728 $ 66,402
Depletion and depreciation of CO2 assets 2,542 1,858 1,572
Asset retirement obligations 2,852 2,951 1,946
Depreciation of other fixed assets 1,472 1,699 1,425
- -----------------------------------------------------------------------------------------------------------
Total DD&A $ 94,708 $ 94,236 $ 71,345
===========================================================================================================
DD&A per BOE:
Oil and natural gas properties $ 7.16 $ 6.98 $ 6.01
CO2 assets and other fixed assets 0.32 0.28 0.26
- -----------------------------------------------------------------------------------------------------------
Total DD&A cost per BOE $ 7.48 $ 7.26 $ 6.27
===========================================================================================================
But for the sale of 8.3 million BOEs in early 2003, our total proved
reserve quantities would have increased each of the last three years. Our proved
reserves increased from 109.5 MMBOE as of December 31, 2001, to 130.7 MMBOE as
of December 31, 2002, and decreased to 128.2 MMBOE as of December 31, 2003.
Reserve quantities and associated production are only one side of the DD&A
equation, with capital expenditures, asset retirement obligations less related
salvage value, 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. Even though the reserves from this acquisition have increased
by 6% (or 57% by adding back production) through December 31, 2003, our offshore
Gulf of Mexico properties in the aggregate have consistently had higher finding
and development costs than our other properties, contributing to the rising DD&A
rate.
48
Denbury Resources Inc.
Management's Discussion and Analysis of Financial
Condition and Results of Operations
Graph depicting our proved reserves (MMBOE)
December 31,
------------------------------------
2001 2002 2003
----- ----- -----
Oil 76.5 97.2 91.2
Natural Gas 33.0 33.5 37.0
----- ----- -----
Total 109.5 130.7 128.2
During 2002, our DD&A rate increased slightly from the $7.19 DD&A rate per
BOE (after the Matrix acquisition), averaging $7.26 per BOE for the year. During
2003, the fourth quarter DD&A rate increased to $8.00 per BOE, increasing the
2003 annual average to $7.48 per BOE. The higher DD&A was partially due to the
higher percentage of capital expenditures spent on our offshore properties, 34%
during 2003 as compared to approximately 10% during 2002, where we have a higher
overall finding cost. The rate was also affected by less than hoped for drilling
results in the Gulf of Mexico and Southern Louisiana, particularly in the fourth
quarter, where some of our larger exploration potential failed to materialize.
In contrast to our offshore properties, our tertiary operations during 2003
yielded a finding and development cost, including the net change in forecasted
future development costs, of just over $5.00 per BOE, in line with our long-term
expectations, helping to partially offset the higher finding and development
cost of our offshore and other natural gas properties. DD&A expense on our CO2
properties increased $684,000 between 2002 and 2003 (37%) as a result of a 53%
increase in our CO2 production and $22.7 million of incremental capital cost
related to our CO2 properties incurred during 2003.
Historically, we have provided for the estimated future costs of well
abandonment and site reclamation, net of any anticipated salvage, on a
unit-of-production basis. This provision was included in DD&A expense and
increased each year, along with the general increase in the number of our
properties, especially the acquisition of our offshore properties. Effective
January 1, 2003, we adopted 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, discounted to its present value
using our credit adjusted risk-free interest rate, and that the corresponding
amount be capitalized by increasing the carrying amount of the related
long-lived asset. The liability is accreted 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 adoption of this
statement resulted in a $2.6 million benefit to net income during the first
quarter of 2003 and was recorded as the cumulative effect of a change in
accounting principle in our Consolidated Statements of Operations. As part of
this adoption, we ceased accruing for site reclamation costs, as had been our
practice in the past, and recorded a $41.0 million liability representing the
estimated present value of our retirement obligations, with a $34.4 million
increase to oil and natural gas properties. On an undiscounted basis, we
estimated our retirement obligations as of December 31, 2003 to be $82.7
million, with an estimated salvage value of $43.3 million, also on an
undiscounted basis. DD&A is calculated on the increase to oil and natural gas
and CO2 properties, net of estimated salvage value. We also include the
accretion of discount on the asset retirement obligation in our DD&A expense.
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 2001, 2002 or 2003 and do not expect to have any such writedowns
in the foreseeable future at current commodity price levels.
49
Denbury Resources Inc.
Management's Discussion and Analysis of Financial
Condition and Results of Operations
Income Taxes
During 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
rate 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 net operating
losses ("NOLs"). The current portion of the tax provision was related to
alternative minimum taxes that could not be offset by NOLs.
Prior to 2002, our statutory tax rate was 37%. During 2002, we determined
that our statutory rate had increased to 38% and adjusted our statutory
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. The net effective tax rate for
2003 was 33%, also lower than the effective rate primarily because of the
enhanced oil recovery credits. As of December 31, 2003, we had an estimated
$16.6 million of enhanced oil recovery credits to carry forward. We also had
approximately $95.0 million of regular tax net operating loss carryforwards
remaining to shelter our future income against regular tax and $14.9 million of
alternative minimum tax net operating loss carryforwards. We were able to
generate additional alternative minimum tax net operating loss carryforwards
during 2003 as a result of a tax loss for the year, primarily due to the high
percentage of expenditures that were intangible drilling costs, a portion of
which were deducted for income tax purposes.
Our overall current income tax credit for 2002 was 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.
Year Ended December 31,
- -------------------------------------------------------------------------------------------------------
Amounts in Thousands Except Per BOE Amounts 2003 2002 2001
- -------------------------------------------------------------------------------------------------------
Current income tax expense (benefit) $ (91) $ (406) $ 640
Deferred income tax provision 26,303 23,926 24,184
- -------------------------------------------------------------------------------------------------------
Total income tax provision $26,212 $ 23,520 $ 24,824
=======================================================================================================
Average income tax provision per BOE $ 2.07 $ 1.81 $ 2.18
Net operating loss carryforwards 94,955 84,891 100,601
Total net deferred tax asset (liability) (43,538) (21,777) (17,433)
=======================================================================================================
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.
50
Denbury Resources Inc.
Management's Discussion and Analysis of Financial
Condition and Results of Operations
Year Ended December 31,
------------------------------------------------------------------------------------------------------------------
Per BOE Data 2003 2002 2001
-------------------------------------------------------------------------------------------------------------------
Oil and natural gas revenues $30.43 $21.17 $22.88
Gain (loss) on settlements of derivative contracts (4.91) 0.07 1.64
Lease operating expenses (7.06) (5.48) (4.84)
Production taxes and marketing expenses (1.17) (0.92) (0.96)
-------------------------------------------------------------------------------------------------------------------
Production netback 17.29 14.84 18.72
CO2 operating margin relating to industrial sales 0.51 0.48 0.38
General and administrative expenses (1.20) (0.96) (0.89)
Net cash interest expense (1.61) (1.73) (1.74)
Current income taxes and other (0.01) 0.04 (0.06)
Changes in assets and liabilities 0.62 (0.38) (0.15)
-------------------------------------------------------------------------------------------------------------------
Cash flow from operations 15.60 12.29 16.26
DD&A (7.48) (7.26) (6.27)
Deferred income taxes (2.08) (1.84) (2.12)
Amortization of derivative contracts and other
non-cash hedging adjustments 0.28 0.24 (2.90)
Changes in assets and liabilities, loss on early retirement
of debt, change in accounting principle and other non-cash items (1.86) 0.17 -
---------------------------------------------------------------------------------------------------------------------
Net income $ 4.46 $ 3.60 $ 4.97
=======================================================================================================================
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 2004-2005 2006 2007 2008 Value Value
- -------------------------------------- --------- ---------- ------- ----- ---------- ----------
Variable rate debt:
Bank debt $ - $ 75,000 $ - $ - $ 75,000 $ 75,000
(The weighted-average interest rate on the bank debt at December 31, 2003 is 2.4%.)
Fixed rate debt:
Subordinated debt, net of discount $ - $ - $ - $ - $ 223,203 $ 232,875
(The interest rate on the subordinated debt is a fixed rate of 7.5%.)
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, although our hedging percentage
may decrease somewhat in the future, as we are stronger financially since
lowering our overall debt levels relative to cash flow. 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 predominantly with collars, although for
the 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 that are reviewed on an
ongoing basis. We attempt to minimize credit risk exposure to counterparties
through formal credit policies, monitoring procedures, and diversification.
51
Denbury Resources Inc.
Management's Discussion and Analysis of Financial
Condition and Results of Operations
At December 31, 2003, our derivative contracts were recorded at their fair
value, which was a net liability of approximately $44.6 million, an increase of
approximately $9.0 million from the $35.6 million fair value liability recorded
as of December 31, 2002. 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, 2002 and December 31, 2003 and (ii) the expiration
of certain derivative contracts during 2003 for which we recorded amortization
expense of $1.2 million. Information regarding our current hedging positions and
historical hedging results is included in Note 9 to the Consolidated Financial
Statements.
Based on NYMEX natural gas futures prices at December 31, 2003, we would
expect to make future cash payments of $11.7 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 $4.9 million, and if futures prices were to increase by 10% we would
expect to pay $20.3 million. Based on NYMEX crude oil futures prices at December
31, 2003, we would expect to pay $25.4 million on our crude oil commodity
hedges. If crude oil futures prices were to decline by 10%, we would expect to
pay $14.9 million under our crude oil commodity contracts, and if crude oil
futures prices were to increase by 10%, we would expect to pay $36.0 million
under our crude oil commodity hedges.
Critical Accounting Policies and Estimates
The preparation of financial statements in accordance with generally
accepted accounting principles requires that we select certain accounting
policies and make certain estimates and judgments regarding the application of
those 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. Following is a
discussion of our most critical accounting estimates, judgments and
uncertainties that are inherent in the preparation of our financial statements.
The senior management of Denbury has discussed the following critical accounting
estimates with the Audit Committee of Denbury's Board of Directors.
Full Cost Method of Accounting, Depletion and Depreciation and Oil and Natural
Gas Reserves
Businesses involved in the production of oil and natural gas are required
to follow accounting rules that are unique to the oil and gas industry. We apply
the full-cost method of accounting for our oil and natural gas properties.
Another acceptable method of accounting for oil and gas production activities is
the successful efforts method of accounting. In general, the primary differences
between the two methods are related to the capitalization of costs and the
evaluation for asset impairment. Under the full-cost method, all geological and
geophysical costs, exploratory dry holes and delay rentals are capitalized to
the full cost pool, whereas under the successful efforts method such costs are
expensed as incurred. In the assessment of impairment of oil and gas properties,
the successful efforts method follows the guidance of SFAS No. 144, "Accounting
for the Impairment or Disposal of Long-Lived Assets," under which assets are
measured for impairment against the undiscounted future cash flows using
commodity prices consistent with management expectations. Under the full-cost
method, the full cost pool (net book value of oil and gas properties) is
measured against future cash flows discounted at ten percent using commodity
prices in effect at the end of the reporting period. The financial results for a
given period could be substantially different depending on the method of
accounting an oil and gas entity applies.
In our application of full cost accounting for our oil and gas producing
activities, we make significant estimates at the end of each period related to
accruals for oil and gas revenues, production, capitalized costs and operating
expenses. While management is not aware of any required revisions to its
estimates, there will likely be future adjustments resulting from such things as
changes in ownership interests, payouts, joint venture audits, re-allocations by
the purchaser/pipeline, or other corrections and adjustments common in the oil
and natural gas industry, many of which will require retroactive application.
These types of adjustments cannot be currently estimated or determined and will
be recorded in the period during which the adjustment occurs.
52
Denbury Resources Inc.
Management's Discussion and Analysis of Financial
Condition and Results of Operations
Under full cost 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 our
financial statement disclosures.
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.
During 2003, the change related to commodity prices was virtually zero, less
than in prior years, as prices were relatively high at both year-end 2002 and
year-end 2003. These changes in quantities affect our DD&A rate and the combined
effect of changes in quantities and commodity 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 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 has been
committed to internally, which normally means it is scheduled in our development
budget (or at least the commencement of the project is scheduled in the case of
longer-term multi-year projects such as waterfloods and tertiary recovery
projects). 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 during the last two years are significantly less than the year-end
prices used in our reserve report. This also can have the effect of eliminating
certain projects in a high price environment, as was the case at year-end 2002
and year-end 2003. (See "Depletion, Depreciation and Amortization" 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.
Asset Retirement Obligations
We have significant obligations related to the plugging and abandonment of
our oil and gas wells, dismantling our offshore production platforms, and the
removal of equipment and facilities from leased acreage and returning such land
to its original condition. SFAS No. 143 requires that we estimate the future
cost of this obligation, discount it to its present value, and record a
corresponding asset and liability in our Consolidated Balance Sheets. The values
ultimately derived are based on many significant estimates, including the
ultimate expected cost of the obligation, the expected future date of the
required cash payment, and interest and inflation rates. Revisions to these
estimates may be required based on changes to cost estimates, the timing of
settlement, and changes in legal requirements. Any such changes that result in
upward or downward revisions in the estimated obligation will result in an
adjustment to the related capitalized asset and corresponding liability on a
prospective basis. See Note 4 to our Consolidated Financial Statements for
further discussion regarding our asset retirement obligations.
53
Denbury Resources Inc.
Management's Discussion and Analysis of Financial
Condition and Results of Operations
Income Taxes
We make certain estimates and judgments in determining our income tax
expense for financial reporting purposes. These estimates and judgments occur in
the calculation of certain tax assets and liabilities that arise from
differences in the timing and recognition of revenue and expense for tax and
financial reporting purposes. Further, we must assess the likelihood that we
will be able to recover or utilize our deferred tax assets (primarily our net
operating losses and enhanced oil recovery credits). If recovery is not likely,
we must record a valuation allowance against such deferred tax assets for the
amount we would not expect to recover, which would result in an increase to our
income tax expense. As of December 31, 2003, we believe that all of our deferred
tax assets recorded on our Consolidated Balance Sheet will ultimately be
recovered. If our estimates and judgments change regarding our ability to
utilize our deferred tax assets, our tax provision would increase in the period
it is determined that recovery is not probable. See Note 7 to the Consolidated
Financial Statements for further information concerning our income taxes.
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 cash flow 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
and $282,000 for 2003.
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 $44.6 million as of year-end 2003. 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 future changes
in value would be reflected in our income statement.
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 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 due to the counterparty's inability to perform, 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.
54
Denbury Resources Inc.
Management's Discussion and Analysis of Financial
Condition and Results of Operations
Recent Accounting Pronouncements
SFAS No. 141, "Business Combinations," and SFAS No. 142, "Goodwill and
Other Intangible Assets," became effective July 1, 2001 and January 1, 2002,
respectively. It is our understanding that questions have been raised as to the
proper application by registrants in the oil and gas industry of the provisions
of SFAS No. 141 and SFAS No. 142. The Emerging Issues Task Force of the FASB is
scheduled to address the relevant issues in its March 2004 meeting. In question
is whether the acquisition of contractual mineral interests, including both
proved and undeveloped, should be classified separately as "intangible assets"
on the balance sheet apart from other oil and gas property costs. Currently,
Denbury and virtually all other companies in the oil and gas industry include
purchased contractual mineral rights in oil and gas properties on the balance
sheet. Until there is further guidance regarding this issue, we will continue to
include mineral interests as oil and gas properties on our Consolidated Balance
Sheets for mineral interests acquired subsequent to July 1, 2001. Based on the
limited guidance available at this time, we estimate that approximately $196
million at December 31, 2003, and $206 million at December 31, 2002, of
acquisition costs subsequent to July 1, 2001 would be reclassified from oil and
gas properties to intangible assets in our December 31, 2003 Consolidated
Balance Sheets. The provisions of SFAS No. 141 and 142, if determined to be
applicable to the acquisitions of mineral interests in our industry, would
impact only the classification of certain amounts on our balance sheet and
associated footnote disclosures, and would not impact the Company's results of
operations or cash flows.
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, forecasted 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, competition and
long-term forecasts of production, finding cost, rates of return, estimated
costs and overall economics and other variables surrounding our tertiary
operations and future plans. 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, inaccurate cost estimates, fluctuations in the
prices of goods and services, the uncertainty of drilling results and reserve
estimates, operating hazards, acquisition risks, requirements for capital,
general economic conditions, competition and government regulations, unexpected
delays, 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, 9-10, 12-13, 17-18, 20-21, 23-25, 27-31, and 33-86 which are
incorporated into the Company's Annual Report on Form 10-K.
55
INDEPENDENT AUDITORS' REPORT
To the Stockholders of Denbury Resources Inc.
We have audited the accompanying consolidated balance sheets of Denbury
Resources Inc. and Subsidiaries (the "Company") as of December 31, 2003 and
2002, and the related consolidated statements of operations, cash flows,
stockholders' equity and comprehensive income for each of the three years in the
period ended December 31, 2003. These financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these 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 financial statements present fairly, in all material
respects, the financial position of the Company as of December 31, 2003 and
2002, and the results of its operations and its cash flows for each of the three
years in the period ended December 31, 2003 in conformity with accounting
principles generally accepted in the United States of America.
As discussed in Note 1 to the financial statements under the caption "Asset
Retirement Obligations", the Company changed its method of accounting for asset
retirement obligations in 2003 as required by Statement of Financial Accounting
Standards No. 143, "Accounting for Asset Retirement Obligations".
/s/ Deloitte & Touche LLP
Dallas, TX
March 8, 2004
56
Denbury Resources Inc.
Consolidated Balance Sheets
Amounts in Thousands DECEMBER 31,
---------------------------
2003 2002
---------- ----------
Assets
Current assets
Cash and cash equivalents.......................................... $ 24,188 $ 23,940
Accrued production receivables..................................... 33,944 34,458
Related party accrued production receivable - Genesis.............. 6,927 3,334
Trade and other receivables, net of allowance of $238 and $207..... 18,080 16,846
Deferred tax asset................................................. 25,016 49,886
---------- ----------
Total current assets....................................... 108,155 128,464
---------- ----------
Property and equipment
Oil and natural gas properties (using full cost accounting)
Proved ......................................................... 1,409,579 1,245,896
Unevaluated..................................................... 46,065 45,736
CO2 properties and equipment....................................... 85,467 62,370
Less accumulated depletion and depreciation........................ (696,366) (609,917)
---------- ----------
Net property and equipment.................................. 844,745 744,085
---------- ----------
Investment in Genesis................................................. 7,450 2,224
Other assets.......................................................... 22,271 20,519
---------- ----------
Total assets............................................... $ 982,621 $ 895,292
========== ==========
Liabilities and Stockholders' Equity
Current liabilities
Accounts payable and accrued liabilities........................... $ 62,349 $ 49,281
Oil and gas production payable..................................... 22,215 17,309
Derivative liabilities............................................. 42,010 29,289
---------- ----------
Total current liabilities.................................. 126,574 95,879
---------- ----------
Long-term liabilities
Long-term debt..................................................... 298,203 344,889
Asset retirement obligations....................................... 41,711 6,845
Derivative liabilities............................................. 2,603 6,281
Deferred revenue - Genesis......................................... 21,468 -
Deferred tax liability............................................. 68,555 71,663
Other.............................................................. 2,305 2,938
---------- ----------
Total long-term liabilities................................ 434,845 432,616
---------- ----------
Commitments and contingencies (Note 10)
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;
54,190,042, and 53,539,329 shares issued and outstanding at
December 31, 2003 and December 31, 2002, respectively......... 54 54
Paid-in capital in excess of par................................... 401,709 395,906
Retained earnings (accumulated deficit)............................ 46,656 (9,875)
Accumulated other comprehensive loss............................... (27,113) (19,288)
Treasury stock, at cost, 8,162 shares at December 31, 2003......... (104) -
---------- ----------
Total stockholders' equity................................. 421,202 366,797
---------- ----------
Total liabilities and stockholders' equity................. $ 982,621 $ 895,292
========== ==========
See Notes to Consolidated Financial Statements.
57
Denbury Resources Inc.
Consolidated Statements of Operations
YEAR ENDED DECEMBER 31,
-------------------------------------
Amounts in Thousands Except Per Share Amounts 2003 2002 2001
-------- -------- --------
Revenues
Oil, natural gas and related product sales
Unrelated parties........................................ $336,521 $251,972 $260,398
Related party - Genesis.................................. 48,942 22,922 -
CO2 sales and transportation fees
Unrelated parties........................................ 7,512 7,580 5,210
Related party - Genesis.................................. 676 - -
Gain (loss) on settlements of derivative contracts.......... (62,210) 932 18,654
Interest income and other................................... 1,573 1,746 849
-------- -------- --------
Total revenues............................................. 333,014 285,152 285,111
-------- -------- --------
Expenses
Lease operating expenses.................................... 89,439 71,188 55,049
Production taxes and marketing expenses..................... 14,819 11,902 10,963
CO2 operating expenses...................................... 1,710 1,400 891
General and administrative.................................. 15,189 12,426 10,174
Interest ................................................... 23,201 26,833 22,335
Loss on early retirement of debt............................ 17,629 - -
Depletion, depreciation and accretion....................... 94,708 94,236 71,345
Loss on Enron related assets................................ - - 25,164
Amortization of derivative contracts and other non-cash
hedging adjustments....................................... (3,578) (3,093) 7,816
-------- -------- --------
Total expenses............................................. 253,117 214,892 203,737
-------- -------- --------
Equity in net income of Genesis.................................. 256 55 -
-------- -------- --------
Income before income taxes....................................... 80,153 70,315 81,374
Income tax provision (benefit)
Current income taxes........................................ (91) (406) 640
Deferred income taxes....................................... 26,303 23,926 24,184
-------- -------- --------
Income before cumulative effect of change in accounting
principle................................................. 53,941 46,795 56,550
-------- -------- --------
Cumulative effect of change in accounting principle, net of
income taxes of $1,600.................................... 2,612 - -
-------- -------- --------
Net income ...................................................... $ 56,553 $ 46,795 $ 56,550
======== ======== ========
Net income per share - basic
Income before cumulative effect of change in
accounting principle...................................... $ 1.00 $ $0.88 $ 1.15
Cumulative effect of change in accounting principle......... 0.05 - -
-------- -------- --------
Net income per share - basic................................ $ 1.05 $0.88 $ 1.15
======== ======== ========
Net income per share - diluted
Income before cumulative effect of change in
accounting principle...................................... $ 0.97 $ 0.86 $ 1.12
Cumulative effect of change in accounting principle......... 0.05 - -
-------- -------- --------
Net income per common share - diluted....................... $ 1.02 $ 0.86 $ 1.12
======== ======== ========
Weighted average common shares outstanding
Basic....................................................... 53,881 53,243 49,325
Diluted..................................................... 55,464 54,365 50,361
See Notes to Consolidated Financial Statements.
58
Denbury Resources Inc.
Consolidated Statements of Cash Flows
YEAR ENDED DECEMBER 31,
-------------------------------------
Amounts in Thousands 2003 2002 2001
-------- -------- --------
Cash flow from operating activities:
Net income .................................................... $ 56,553 $ 46,795 $ 56,550
Adjustments needed to reconcile to net cash flow provided
by operations:
Depletion, depreciation and accretion...................... 94,708 94,236 71,345
Deferred income taxes...................................... 26,303 23,926 24,184
Deferred income - Genesis.................................. (322) - -
Loss on early retirement of debt........................... 17,629 - -
Non-cash loss on Enron related assets...................... - - 25,164
Amortization of derivative contracts and other non-cash
hedging adjustments...................................... (3,578) (3,093) 7,816
Amortization of debt issue costs and other................. 1,121 2,701 1,742
Cumulative effect of change in accounting principle........ (2,612) - -
Changes in assets and liabilities relating to operations:
Accrued production receivable.............................. (3,079) (14,381) 19,399
Trade and other receivables................................ (1,234) 15,078 (17,622)
Derivative assets and liabilities.......................... - 8,427 (28,043)
Other assets............................................... 7 133 863
Accounts payable and accrued liabilities................... 8,862 (17,217) 23,560
Oil and gas production payable............................. 4,906 3,869 (2,213)
Other liabilities.......................................... (1,649) (874) 2,302
-------- -------- --------
Net cash provided by operating activities......................... 197,615 159,600 185,047
-------- -------- --------
Cash flow used for investing activities:
Oil and natural gas expenditures............................... (146,596) (99,273) (170,109)
Acquisitions of oil and gas properties......................... (11,848) (56,364) (97,871)
Investment in Genesis.......................................... (5,026) (2,170) -
Acquisition of CO2 assets and capital expenditures............. (22,673) (16,445) (45,555)
Net purchases of other assets.................................. (2,192) (3,688) (1,799)
Increase in restricted cash.................................... (848) (909) (3,496)
Net proceeds from CO2 production payment - Genesis............. 23,895 - -
Proceeds from sales of oil and gas properties.................. 29,410 7,688 -
-------- -------- --------
Net cash used for investing activities............................ (135,878) (171,161) (318,830)
-------- -------- --------
Cash flow from financing activities:
Bank repayments................................................ (160,000) (40,000) (79,130)
Bank borrowings................................................ 85,000 49,130 146,000
Repayment of 9% subordinated debt, including redemption
premium...................................................... (209,000) - -
Issuance of 7.5% subordinated debt, net of discount............ 223,054 - -
Issuance of 9% subordinated debt, net of discount.............. - - 68,528
Issuance of common stock....................................... 5,537 3,594 2,594
Costs of debt financing........................................ (4,812) (719) (3,026)
Other.......................................................... (1,268) - 20
-------- -------- --------
Net cash provided by (used for) financing activities.............. (61,489) 12,005 134,986
-------- -------- --------
Net increase in cash and cash equivalents......................... 248 444 1,203
Cash and cash equivalents at beginning of year.................... 23,940 23,496 22,293
-------- -------- --------
Cash and cash equivalents at end of year.......................... $ 24,188 $ 23,940 $ 23,496
======== ======== ========
See Notes to Consolidated Financial Statements.
59
Denbury Resources Inc.
Consolidated Statements of Changes in Stockholders' Equity
Accumulated
Other
Paid-In Retained Compre-
Capital In Earnings hensive Total
Common Stock Excess of (Accumulated Income Treasury Stock Stockholders'
($.001 Par Value) Par Deficit) (Loss) (at cost) Equity
---------------------- --------- --------- --------- ---------------- -------------
Dollar Amounts in Thousands Shares Amount Shares Amount
---------- ------ ------ ------
Balance - December 31, 2000......... 45,979,981 $46 $329,339 $(113,220) $ - - $ - $216,165
---------- ------ -------- --------- --------- ------ ------ --------
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
Unrealized gain on cash flow hedge.. - - - - 14,228 - - 14,228
Net income.......................... - - - 56,550 - - - 56,550
---------- ------ -------- --------- --------- ------- ------ --------
Balance - December 31, 2001......... 52,956,825 53 391,557 (56,670) 14,228 - - 349,168
---------- ------ -------- --------- --------- ------- ------ --------
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
Unrealized loss on cash flow hedge.. - - - - (33,516) - - (33,516)
Net income.......................... - - - 46,795 - - - 46,795
---------- ------ -------- --------- --------- ------- ------ --------
Balance - December 31, 2002......... 53,539,329 54 395,906 (9,875) (19,288) - - 366,797
---------- ------ -------- --------- --------- ------- ------ --------
Repurchase of common stock.......... - - - - - 100,000 (1,276) (1,276)
Issued pursuant to employee stock
purchase plan................... 94,968 - 1,174 (22) - (91,838) 1,172 2,324
Issued pursuant to employee stock
option plan....... ............. 550,090 - 3,213 - - - - 3,213
Issued pursuant to directors'
compensation plan............... 5,655 - 69 - - - - 69
Tax benefit from stock options...... - - 1,347 - - - - 1,347
Unrealized loss on cash flow hedge.. - - - - (7,825) - - (7,825)
Net income.......................... - - - 56,553 - - - 56,553
---------- ----- -------- --------- --------- ------- ------ --------
Balance - December 31, 2003......... 54,190,042 $54 $401,709 $ 46,656 $ (27,113) 8,162 $(104) $421,202
========== ====== ======== ========= ========= ======= ====== ========
See Notes to Consolidated Financial Statements.
60
Denbury Resources Inc.
Consolidated Statements of Comprehensive Income
Year Ended December 31,
------------------------------------
Amounts in Thousands 2003 2002 2001
------- ------- -------
Net income......................................................................... $56,553 $46,795 $56,550
Other comprehensive income (loss), net of tax:
Reclassification adjustments related to settlements of derivative
contracts, net of tax of $22,173, ($1,758), and ($5,172), respectively... 36,177 (2,868) (8,806)
Change in fair value of derivative contracts, net of tax of
($26,969), ($18,784), and $12,934, respectively......................... (44,002) (30,648) 22,022
Change in accounting principle for derivative contracts,
net of tax of $594...................................................... - - 1,012
------- ------- -------
Comprehensive income............................................................... $48,728 $13,279 $70,778
======= ======= =======
See Notes to Consolidated Financial Statements.
61
Denbury Resources Inc.
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. We also own the rights to a natural source of
carbon dioxide ("CO2" ) reserves that we use for injection in our tertiary oil
recovery operations. We also sell some of the CO2 we produce to third parties
for various 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 publicly traded master limited partnership. During 2003, we
acquired additional partnership units, increasing our ownership interest in
Genesis from 2% to 9.25%. We account for our ownership interest in Genesis under
the equity method of accounting. 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 3 for more information regarding our related party transactions with
Genesis and summary financial information. All material intercompany balances
and transactions have been eliminated.
Effective December 29, 2003, Denbury Resources Inc. changed its corporate
structure to a holding company format. The purposes of creating the holding
company structure were to better reflect the operating practices and methods of
Denbury, to improve its economics, and to provide greater administrative and
operational flexibility. As part of this restructure, Denbury Resources Inc.
(predecessor entity) merged into a newly formed limited liability company and
survived as Denbury Onshore, LLC, a Delaware limited liability company and an
indirect subsidiary of the newly formed holding company, Denbury Holdings, Inc.
Denbury Holdings, Inc. subsequently assumed the name Denbury Resources Inc. (new
entity). The reorganization was structured as a tax free reorganization to
Denbury's stockholders and all outstanding capital stock of the original public
company was automatically converted into the identical number of and type of
shares of the new public holding company. Stockholders' ownership interests in
the business did not change as a result of the new structure and shares of the
Company remain publicly traded under the same symbol (DNR) on the New York Stock
Exchange. The new parent holding company is co-obligor (or guarantor, as
appropriate) regarding the payment of principal and interest on Denbury's
outstanding debt securities.
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.
62
Denbury Resources Inc.
Notes to Consolidated Financial Statements
c) Asset Retirement Obligations. On January 1, 2003, we adopted the
provisions of Statement of Financial Accounting Standards ("SFAS") No. 143,
"Accounting for Asset Retirement Obligations." In general, our future asset
retirement obligations relate to future costs associated with plugging and
abandonment of our oil and natural gas wells, dismantling our offshore
production platforms, and removal of equipment and facilities from leased
acreage and returning such land to its original condition. 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, discounted to its present value
using our credit adjusted risk-free interest rate, and a corresponding amount
capitalized by increasing the carrying amount of the related long-lived asset.
The liability is accreted each period, and the capitalized cost is depreciated
over the useful life of the related asset. Revisions to estimated retirement
obligations will result in an adjustment to the related capitalized asset and
corresponding liability. If the liability is settled for an amount other than
the recorded amount, the difference is recorded to the full cost pool, unless
significant. Prior to the adoption of this new standard, we recognized a
provision for our asset retirement obligations each period as part of our
depletion and depreciation calculation, based on the unit-of-production method.
See Note 4 for more information regarding our change in accounting related to
the adoption of SFAS No. 143.
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 12 for information on our proved oil and
natural gas reserves and the basis on which they are recorded.
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, 2003 and 2002, 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 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
63
Denbury Resources Inc.
Notes to Consolidated Financial Statements
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.
Derivative financial instruments are 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 re-designated, 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 9.
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. There are no margin requirements with the
counterparties of our derivative contracts.
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 expenses" and the expenses related to
our own uses are recorded in "Lease operating expenses" in the Consolidated
Statements of Operations. We capitalize acquisitions and the costs of exploring
and developing CO2 reserves. The costs capitalized are
64
Denbury Resources Inc.
Notes to Consolidated Financial Statements
depleted or depreciated on the unit-of-production method, based on proved CO2
reserves as determined by independent engineers. We evaluate our CO2 assets for
impairment by comparing the expected future revenues from these assets to their
carrying value.
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, 2003 and 2002, we had approximately $9.5 million and $8.7
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, 2003, 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 2003 2002 2001
------ ------ ------
Weighted average common shares - basic.......... 53,881 53,243 49,325
Effect of diluted securities:
Stock options................................ 1,583 1,122 1,036
------ ------ ------
Weighted average common shares - diluted........ 55,464 54,365 50,361
====== ====== ======
We did not include in the diluted shares outstanding calculation 1.0
million options in 2003, 1.7 million options in 2002, and 1.8 million options in
2001 because their inclusion would be antidilutive as their exercise prices
exceeded the average market price of our common stock during the respective
periods.
Stock Option Compensation
We issue stock options to all of our employees under our stock option plan,
which is described more fully in Note 8. 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," as amended by SFAS No. 148, in accounting for our
stock option plan.
65
Denbury Resources Inc.
Notes to Consolidated Financial Statements
Year Ended December 31,
----------------------------------
Amounts in Thousands Except Per Share Amounts 2003 2002 2001
--------- --------- ---------
Net Income, as reported ..................................................... $ 56,553 $ 46,795 $ 56,550
Less: stock-based compensation expense applying fair value based
method, net of related tax effects.................................. 4,114 2,866 2,763
--------- --------- ---------
Pro forma net income................................................ $ 52,439 $ 43,929 $ 53,787
========= ========= =========
Net income per common share:
As reported:
Basic................................................................ $ 1.05 $ 0.88 $ 1.15
Diluted.............................................................. 1.02 0.86 1.12
Pro forma:
Basic................................................................ $ 0.97 $ 0.83 $ 1.09
Diluted.............................................................. 0.97 0.83 1.09
The weighted average fair value of options granted using the Black-Scholes
option pricing model and the weighted average assumptions used in determining
those fair values are as follows:
2003 2002 2001
-------- -------- -------
Weighted average fair value of options granted.. $ 6.02 $ 4.17 $ 5.19
Risk-free interest rate......................... 2.94% 4.05% 4.64%
Expected life................................... 5 years 5 years 5 years
Expected volatility............................. 59.6% 61.4% 63.4%
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 (i) the fair value of financial
derivative instruments, (ii) 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, (iii)
accruals related to oil and gas production and revenues, capital expenditures
and lease operating expenses, (iv) the estimated costs and timing of future
asset retirement obligations, and (v) estimates made in the calculation of
income taxes. While management is not aware of any significant revisions to any
of its estimates, there will likely be future revisions to its estimates
resulting from matters such as changes in ownership interests, payouts, joint
venture audits, re-allocations by purchasers or pipelines, or other corrections
and adjustments common in the oil and gas industry, many of which require
retroactive application. These types of adjustments cannot be currently
estimated and will be recorded in the period during which the adjustment occurs.
66
Denbury Resources Inc.
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.
Recent Accounting Pronouncements
SFAS No. 141, "Business Combinations," and SFAS No. 142, "Goodwill and
Other Intangible Assets," became effective July 1, 2001 and January 1, 2002,
respectively. It is our understanding that questions have been raised as to the
proper application by registrants in the oil and gas industry of the provisions
of SFAS No. 141 and SFAS No. 142. The Emerging Issues Task Force of the FASB is
scheduled to address the relevant issues in its March 2004 meeting. In question
is whether the acquisition of contractual mineral interests, including both
proved and undeveloped, should be classified separately as "intangible assets"
on the balance sheet apart from other oil and gas property costs. Currently,
Denbury and virtually all other companies in the oil and gas industry include
purchased contractual mineral rights in oil and gas properties on the balance
sheet. Until there is further guidance regarding this issue, we will continue to
include mineral interests as oil and gas properties in our Consolidated Balance
Sheets for mineral interests acquired subsequent to July 1, 2001. Based on the
limited guidance available at this time, we estimate that approximately $196
million at December 31, 2003, and $206 million at December 31, 2002, of
acquisition costs subsequent to July 1, 2001 would be reclassified from oil and
gas properties to intangible assets in our December 31, 2003 Consolidated
Balance Sheets. The provisions of SFAS No. 141 and 142, if determined to be
applicable to the acquisitions of mineral interests in our industry, would
impact only the classification of certain amounts on our balance sheet and
associated footnote disclosures, and would not impact the Company's results of
operations or cash flows.
In January 2003, the FASB issued Interpretation No. 46 ("FIN 46"),
"Consolidation of Variable Interest Entities" and amended the Interpretation in
December 2003. FIN 46 requires an investor with a majority of the variable
interests (primary beneficiary) in a variable interest entity (VIE) to
consolidate the entity and also requires majority and significant variable
interest entities to provide certain disclosures. An entity is considered a VIE
if (i) the entity lacks sufficient equity to carry on its principal operations,
(ii) the equity owners of the entity cannot make decisions about the entity's
activities, or (iii) the entity's equity neither absorbs losses nor benefits
from gains. Development stage entities that have sufficient equity to finance
their activities and entities that are businesses, as defined in FIN 46, are not
considered to be VIEs. The provisions of FIN 46 were effective immediately for
VIEs created after January 15, 2003, and we have applied the remaining
provisions of FIN 46 for the period ending December 31, 2003. We do not have any
VIEs that would require consolidation or any significant exposure to VIEs that
would require disclosure.
Note 2. Property Transactions
COHO Gulf Coast Properties
In August 2002, we acquired the Gulf Coast properties of COHO Energy, Inc.,
auctioned in the U.S. Bankruptcy Court in Dallas, Texas. Our net purchase price
was $48.2 million and included nine fields, eight of which are located in
Mississippi and one in Texas. At December 31, 2002, these properties had
reserves of approximately 15.1 million barrels of oil and net production of
approximately 4,000 barrels of oil per day. The Mississippi fields included
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.
In February 2003, we sold Laurel Field, acquired in the COHO acquisition,
for $25.9 million and other consideration which included an interest in
Atchafalaya Bay Field (where we already owned an interest) and seismic over that
area. At December 31, 2002, Laurel Field had approximately 7.4 MMBbls of proved
reserves. In March 2003, we sold the Bentonia and Glazer fields for
approximately $1.6 million. The proceeds from the sale of Laurel Field were used
to reduce our bank debt.
67
Denbury Resources Inc.
Notes to Consolidated Financial Statements
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 acquired
properties, and we allocated $30.0 million of the purchase price as 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 $11.6
million of the original $30.0 million to developed property as of December 31,
2003. Denbury's financial statements include the operations of Matrix from July
1, 2001.
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, as well as to other
commercial customers.
Note 3. Related Party Transactions - Genesis
On May 14, 2002, a newly formed subsidiary of Denbury acquired Genesis
Energy, L.L.C. (which was susequently converted to Genesis Energy, Inc.), the
general partner of Genesis, a publicly traded master limited partnership, for
total consideration, including expenses and commissions, of approximately $2.2
million. Genesis has two primary lines of business: crude oil gathering and
marketing and pipeline transportation, primarily in Mississippi, Texas, Alabama
and Florida. In November 2003, through our subsidiary general partner, we
purchased an additional 689,000 partnership common units and 14,000 general
partner units of Genesis for $7.15 per unit, with an aggregate purchase price of
approximately $5.0 million. With these additional units, our ownership interest
increased to approximately 9.25% (2.0% general partner ownership and 7.25%
limited partner ownership).
We are accounting for our 9.25% ownership in Genesis under the equity
method of accounting as we have significant influence over the limited
partnership; however, our control is limited under the limited partnership
agreement and therefore we do not consolidate Genesis. Our equity in Genesis'
net income for 2003 was $256,000 and for 2002 was $55,000, representing 2% of
Genesis' net income for the period from May 14, 2002 through October 31, 2003
and 9.25%
68
Denbury Resources Inc.
Notes to Consolidated Financial Statements
of Genesis' net income for the period from November 1, 2003 through December 31,
2003. Genesis Energy, Inc., the general partner of which we own 100%, has
guaranteed the bank debt of Genesis, which was $7.0 million as of December 31,
2003, and also included $21.6 million in letters of credit of which $12.5
million are for Denbury's benefit to secure purchases of oil 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 in Genesis of $7.2 million
exceeded our percentage of net equity in the limited partnership at the time of
acquisition by approximately $2.2 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. At December
31, 2003 and 2002, we had a production receivable from Genesis of $6.9 million
and $3.3 million, respectively. For the year ended December 31, 2003, we
recorded oil sales to Genesis of $48.9 million. Our oil sales to Genesis from
the period May 14, 2002 through December 31, 2002 were $22.9 million. Denbury
received other miscellaneous payments from Genesis during 2003, including
$120,000 in director fees for certain executive officers of Denbury that are
board members of Genesis, and $57,000 in pro rata dividend distributions from
Genesis.
CO2 Volumetric Production Payment
In November 2003, we sold 167.5 Bcf of CO2 to Genesis for $24.9 million
($23.9 million as adjusted for interim cash flows from the September 1, 2003
effective date and transaction costs) under a volumetric production payment
("VPP"). This sale included the assignment of three of our existing long-term
commercial CO2 supply agreements with our industrial customers, which
represented approximately 60% of our then current industrial CO2 sales volumes.
Pursuant to the VPP, Genesis may take up to 52.5 MMcf/d through 2009, 43.0
MMcf/d from 2010 through 2012, and 25.2 MMcf/d to the end of the term. We have
recorded the net proceeds as deferred revenue and will recognize such revenue as
CO2 is delivered during the term of the VPP. At December 31, 2003, $23.6 million
was recorded as deferred income ($2.1 million in current liabilities and $21.5
million long term). During 2003, we recognized deferred revenue of $322,000 for
deliveries under the VPP. We will continue to provide Genesis with certain
processing and transportation services in connection with this agreement for a
fee of $0.16 per Mcf of CO2 delivered to their industrial customers.
Summarized financial information of Genesis Energy, L.P.
Year Ended Year Ended
December 31, December 31,
Amounts in Thousands 2003 2002
----------- ----------
Revenues...................................... $ 657,897 $ 652,628
Cost of sales................................. 644,157 636,042
Other expenses................................ 14,159 15,576
Income from discontinued operations........... 13,741 4,082
---------- ---------
Net income ................................ $ 13,322 $ 5,092
========== =========
December 31, December 31,
2003 2002
----------- ----------
Current assets................................ $ 88,211 $ 92,097
Non-current assets............................ 58,904 45,440
---------- ---------
Total assets............................... $ 147,115 $ 137,537
========== =========
Current liabilities........................... $ 87,244 $ 96,220
Non-current liabilities....................... 7,000 5,500
Partners' capital............................. 52,871 35,817
---------- ---------
Total liabilities and partners' capital.... $ 147,115 $ 137,537
========== =========
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Denbury Resources Inc.
Notes to Consolidated Financial Statements
Note 4. Asset Retirement Obligations
On January 1, 2003, we adopted the provisions of SFAS No. 143, "Accounting
for Asset Retirement Obligations." In general, our future asset retirement
obligations relate to future costs associated with plugging and abandonment of
our oil and natural gas wells, dismantling our offshore production platforms,
and removal of equipment and facilities from leased acreage and returning such
land to its original condition. SFAS 143 requires that the fair value of a
liability for an asset retirement obligation be recorded in the period in which
it is incurred, discounted to its present value using our credit adjusted
risk-free interest rate, and a corresponding amount capitalized by increasing
the carrying amount of the related long-lived asset. The liability is accreted
each period, and the capitalized cost is depreciated over the useful life of the
related asset. Prior to the adoption of this new standard, we recognized a
provision for our asset retirement obligations each period as part of our
depletion and depreciation calculation, based on the unit-of-production method.
The adoption of SFAS No. 143 on January 1, 2003, required us to record (i)
a $41.0 million liability for our future asset retirement obligations (an
increase of $34.1 million in our liability for asset retirement obligations that
we had recorded at December 31, 2002), (ii) a $34.4 million increase in oil and
natural gas properties, (iii) a $3.9 million decrease in accumulated
depreciation and depletion, and (iv) a $2.6 million gain as a cumulative effect
adjustment of a change in accounting principle, net of taxes.
The following pro forma data summarizes Denbury's net income and net income
per common share as if we had applied the provisions of SFAS No. 143 in prior
periods, and as if we had removed the first quarter 2003 cumulative effect
adjustment for the adoption of SFAS No. 143:
Year Ended December 31,
---------------------------------------
Amounts in Thousands Except Per Share Amounts 2003 2002 2001
---------- ---------- ---------
Net income, as reported ........................ $ 56,553 $ 46,795 $ 56,550
Pro forma adjustments to reflect retroactive
adoption of SFAS 143........................ (2,612) 473 503
---------- ---------- ---------
Pro forma net income....................... $ 53,941 $ 47,268 $ 57,053
========== ========== =========
Net income per common share:
As reported:
Basic...................................... $ 1.05 $ 0.88 $ 1.15
Diluted.................................... 1.02 0.86 1.12
Pro forma:
Basic...................................... $ 1.00 $ 0.89 $ 1.16
Diluted.................................... 0.97 0.87 1.13
The following table summarizes the changes in our asset retirement
obligations for the year ended December 31, 2003.
Year Ended
Amounts in Thousands December 31, 2003
-----------------
Beginning asset retirement obligation, as of December 31, 2002........... $ 6,845
Cumulative effect adjustment for SFAS No. 143, January 1, 2003........ 34,110
Liabilities incurred during period.................................... 3,405
Liabilities settled during period..................................... (1,007)
Liabilities sold during period........................................ (2,393)
Accretion expense..................................................... 2,852
-----------------
Ending asset retirement obligation....................................... $43,812
=================
At December 31, 2003, $2.1 million of our asset retirement obligation was
classified in "Accounts payable and accrued liabilities" under current
liabilities in our Consolidated Balance Sheet. We have escrow accounts that are
legally restricted for certain of our asset retirement obligations. The balances
of these escrow accounts were $9.5 million at December 31, 2003, and $8.7
million at December 31, 2002, and are included in "Other assets" in our
Consolidated Balance Sheets. If we
70
Denbury Resources Inc.
Notes to Consolidated Financial Statements
had adopted SFAS No. 143 as of January 1, 2002, we estimate that our asset
retirement obligations at that date would have been $34.1 million, based on the
same assumptions used in our calculation of our obligations at January 1, 2003.
Note 5. Property and Equipment
December 31,
Amounts in Thousands -----------------------------------
2003 2002
-------------- --------------
Oil and natural gas properties:
Proved properties................................... $ 1,409,579 $ 1,245,896
Unevaluated properties.............................. 46,065 45,736
-------------- --------------
Total........................................... 1,455,644 1,291,632
Accumulated depletion and depreciation................ (690,395) (606,488)
-------------- --------------
Net oil and natural gas properties................. 765,249 685,144
-------------- --------------
CO2 properties........................................ 85,467 62,370
Accumulated depletion and depreciation................ (5,971) (3,429)
-------------- --------------
Net CO2 properties................................. 79,496 58,941
-------------- --------------
Net property and equipment............................ $ 844,745 $ 744,085
============== ==============
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 natural gas properties being amortized at December 31,
2003 and 2002 and the year in which they were incurred follows:
December 31, 2003 December 31, 2002
--------------------------------------------- --------------------------------------------
Costs Incurred During: Costs Incurred During:
--------------------------------- ---------------------------------
Amounts in Thousands 2003 2002 2001 Total 2002 2001 2000 Total
--------- ---------- ---------- --------- ---------- ----------- -------- ---------
Property acquisition costs.. $ 3,640 $ 6,301 $ 21,169 $ 31,110 $ 7,459 $ 27,128 $ 228 $ 34,815
Exploration costs........... 6,528 5,291 3,136 14,955 7,526 2,938 457 10,921
--------- ---------- ---------- --------- ---------- ----------- -------- ---------
Total................... $ 10,168 $ 11,592 $ 24,305 $ 46,065 $ 14,985 $ 30,066 $ 685 $ 45,736
========= ========== ========== ========= ========== =========== ======== =========
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, 2003, approximately $25.1 million of
the total unevaluated property balance relates to offshore properties, of which
of $18.4 million relates to the original $30.0 million classified as unevaluated
properties in 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 two to three years.
Note 6. Notes Payable and Long-Term Indebtedness
December 31,
------------------------
Amounts in Thousands 2003 2002
-------- --------
Senior bank loan.............................................. $ 75,000 $150,000
7.5 % Senior Subordinated Notes due 2013...................... 225,000 -
9% Senior Subordinated Notes due 2008......................... - 125,000
9% Series B Senior Subordinated Notes due 2008................ - 75,000
Discount on Senior Subordinated Notes......................... (1,797) (5,111)
-------- --------
Total debt............................................... $298,203 $344,889
======== ========
71
Denbury Resources Inc.
Notes to Consolidated Financial Statements
Senior Bank Loan
In December 2003, we entered into a Fourth Amended and Restated Credit
Agreement with our banks to restate the existing credit agreement for our
internal reorganization to a holding-company-organizational structure (see Note
1). There were no significant changes to the agreement except to incorporate the
new legal entities into the agreement. Earlier in 2003, we amended certain
provisions of our credit agreement to (i) increase the percentage of our oil and
natural gas production that we are allowed to hedge, setting a maximum of 85% of
our forecasted production from our proved reserves for the current year (as
defined in the amendment and may include up to 18 months), a maximum of 70% of
forecasted production for the subsequent year, a maximum of 55% of forecasted
production for the third year and a maximum of 40% of forecasted production for
the fourth year, and (ii) to allow us to borrow up to $20 million in a bond
issue from a Mississippi governmental authority in order to receive certain
exemptions or reductions in sales and ad valorem taxes on certain qualified
expenditures in Mississippi through May 2005. Any borrowings under this bond
program will be purchased by the banks in our credit facility, will become part
of our outstanding borrowings under our credit line and will accrue interest and
be repaid on the same basis as our bank line. The borrowing base remained at
$220 million, leaving a borrowing capacity of approximately $145 million as of
December 31, 2003.
The bank 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, 2003. 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. Borrowings
under the credit facility are generally in tranches that can have maturities up
to one year. Interest on any borrowings are based on LIBOR plus an applicable
margin as determined by the borrowings outstanding. The facility matures in
April 2006.
As of December 31, 2003, we had $75 million outstanding under the facility,
at a weighted average interest rate of 2.4%, $820,000 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, 2004, based on
December 31, 2003 assets and proved reserves.
Subordinated Debt Issuance of 7.5% Senior Subordinated Notes due 2013
On March 25, 2003, we issued $225 million of 7.5% Senior Subordinated Notes
due 2013. The notes were priced at 99.135% of par and we used most of our $218.4
million of net proceeds from the offering, after underwriting and issuance
costs, to retire our existing $200 million of 9% Senior Subordinated Notes due
2008, including the Series B notes (see "Redemption of 9% Senior Subordinated
Notes due 2008 (Including Series B Notes)" below).
The notes mature on April 1, 2013 and interest on the notes is payable each
April 1 and October 1. We may redeem the notes at our option beginning April 1,
2008 at the following redemption prices: 103.75% after April 1, 2008, 102.5%
after April 1, 2009, 101.25% after April 1, 2010, and 100% after April 1, 2011
and thereafter. In addition, prior to April 1, 2006, we may redeem up to 35% of
the notes at a redemption price of 107.5% with net cash proceeds from a stock
offering. The indenture under which the notes were issued is essentially the
same as the indenture covering our previously outstanding 9% notes. The
indenture contains certain restrictions on our ability to incur additional debt,
pay dividends on our common stock, make investments, create liens on our assets,
engage in transactions with our affiliates, transfer or sell assets, consolidate
or merge, or sell substantially all of our assets. The notes are not subject to
any sinking fund requirements. All of our significant subsidiaries fully and
unconditionally guarantee this debt.
72
Denbury Resources Inc.
Notes to Consolidated Financial Statements
In connection with our internal reorganization to a
holding-company-organizational structure (see Note 1), we entered into a First
Supplemental Indenture dated December 29, 2003, which did not require the
consent of the holders of the 7.5% Senior Subordinated Notes due 2013. The
supplemental indenture made Denbury Resources Inc. and Denbury Onshore, LLC,
co-obligors of this debt. All of our significant subsidiaries continue to fully
and unconditionally guarantee this debt. There were no other significant changes
as part of the amendment.
Redemption of 9% Senior Subordinated Notes due 2008 (Including Series B Notes)
On April 16, 2003, we redeemed our $200 million of 9% Senior Subordinated
Notes due 2008 at an aggregate cost of $209.0 million, including a $9.0 million
call premium. As a result of this early redemption, we recorded a before-tax
charge to earnings in the second quarter of 2003 of $17.6 million ($11.5 million
after income tax), which included the $9.0 million call premium and the
write-off of the remaining discount and debt issuance costs associated with
these notes.
Indebtedness Repayment Schedule
As of December 31, 2003, our indebtedness, excluding the discount on
our senior subordinated debt, is repayable over the next five years and
thereafter as follows:
Amounts in Thousands
2004....................... $ -
2005....................... -
2006....................... 75,000
2007....................... -
2008....................... -
Thereafter................. 225,000
----------
Total indebtedness .... $ 300,000
==========
Note 7. Income Taxes
Our income tax provision (benefit) is as follows: Year Ended December 31,
-----------------------------------
Amounts in Thousands 2003 2002 2001
------ ------ -------
Current income tax expense (benefit)
Federal.......................................... $ (91) $ (419) $ 614
State............................................ - 13 26
------- ------- ------
Total current income tax expense (benefit)..... (91) (406) 640
------- ------- ------
Deferred income tax expense
Federal.......................................... 23,864 21,822 22,637
State............................................ 2,439 2,104 1,547
------- ------- -------
Total deferred income tax expense ............... 26,303 23,926 24,184
------- ------- -------
Total income tax expense ...................... $26,212 $23,520 $24,824
======= ======= =======
Our current income tax expense in 2001 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, 2003, we had net operating loss carryforwards for U.S.
federal income tax purposes of $95.0 million and $14.9 million for alternative
minimum tax purposes. 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
73
Denbury Resources Inc.
Notes to Consolidated Financial Statements
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:
Amounts in Thousands Income Alternative
Tax Minimum Tax
------- -----------
Year
2018 ................................. $54,698 $ -
2019 ................................. 21,356 12,054
2020 ................................. 10,187 2,154
2021 ................................. 8,467 213
2022 ................................. 30 -
2023 ................................. 217 524
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 are approximately $16.6 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, 2003 and 2002 balance sheet
dates. At December 31, 2003 and 2002, our deferred tax assets and liabilities
were as follows:
December 31,
------------------------
Amounts in Thousands 2003 2002
--------- ---------
Deferred tax assets:
Loss carryforwards................................ $ 35,998 $ 32,266
Tax credit carryover.............................. 978 1,069
Enhanced oil recovery credit carryforwards........ 16,578 9,927
Derivative hedging contracts...................... 16,617 11,822
Other............................................. 90 79
--------- ---------
Total deferred tax assets................... 70,261 55,163
--------- ---------
Deferred tax liabilities:
Property and equipment............................ (112,200) (76,940)
Asset retirement obligations...................... (1,600) -
--------- ---------
Total deferred tax liabilities............... (113,800) (76,940)
--------- ---------
Total net deferred tax liability................... $ (43,539) $ (21,777)
========= =========
Our income tax provision 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 2003 2002 2001
------- ------- -------
Income tax provision calculated using the
federal statutory income tax rate.................... $28,054 $24,587 $28,481
State income taxes...................................... 2,398 2,121 1,623
Enhanced oil recovery credits........................... (4,687) (3,394) (5,280)
Other................................................... 447 206 -
------- ------- -------
Total income tax expense .......................... $26,212 $23,520 $24,824
======= ======= =======
Note 8. 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.
74
Denbury Resources Inc.
Notes to Consolidated Financial Statements
Stock Repurchase Plan
In August 2003, we adopted a stock repurchase plan ("Plan") to purchase
shares of our common stock on the NYSE in order for such repurchased shares to
be reissued to our employees who participate in Denbury's Employee Stock
Purchase Plan (see Employee Stock Purchase Plan below). The Plan provides for
purchases through an independent broker of 50,000 shares of Denbury's common
stock per fiscal quarter for a period of approximately twelve months, or a total
of 200,000 shares, beginning August 13, 2003 and ending on July 31, 2004.
Purchases are to be made at prices and times determined at the discretion of the
independent broker, provided however that no purchases may be made during the
last ten business days of a fiscal quarter. During 2003, we purchased 100,000
shares at an average cost of $12.77 per share. On September 30, 2003 and
December 31, 2003, we reissued 48,013 and 43,825, respectively, of these shares
under Denbury's Employee Stock Purchase Plan.
Stock Option Plan
As of December 31, 2003, we had a total of 8,195,587 shares of common stock
authorized for issuance pursuant to our Stock Option Plan, of which 1,040,530
shares were available for issuance. 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,
----------------------------------------------------------------------------------
2003 2002 2001
-------------------------- ------------------------- ------------------------
Weighted Weighted Weighted
Number Average Number Average Number Average
of Options Price of Options Price of Options Price
---------- -------- ---------- -------- ---------- --------
Outstanding at beginning of year.. 4,997,475 $ 8.46 4,616,333 $ 8.40 3,802,122 $8.03
Granted........................... 956,384 11.33 921,341 7.50 1,222,141 9.00
Exercised......................... (550,090) 5.77 (370,120) 4.51 (209,600) 5.00
Forfeited......................... (29,567) 7.72 (170,079) 10.30 (198,330) 8.53
--------- ------ --------- ------ --------- -----
Outstanding at end of year........ 5,374,202 $ 9.25 4,997,475 $ 8.46 4,616,333 $8.40
========= ====== ========= ====== ========= =====
Exercisable at end of year........ 2,311,834 $10.21 2,267,497 $10.26 1,858,072 $9.49
========= ====== ========= ====== ========= =====
The following is a summary of stock options outstanding at December 31, 2003:
Options Outstanding Options Exercisable
----------------------------------------- ----------------------------
Weighted
Number Average Weighted Number Weighted
of Options Remaining Average of Options Average
Outstanding Contractual Exercise Exercisable at Exercise
Range of Exercise Prices at 12/31/03 Life Price 12/31/03 Price
--------------------------- ----------- ----------- -------- -------------- --------
$ 3.77 - 5.50 1,203,973 5.4 $ 4.13 736,784 $ 4.23
$ 5.51 - 8.00 957,217 7.1 7.06 175,258 6.94
$ 8.01 - 11.50 2,176,331 7.7 10.09 411,252 9.42
$11.51 - 14.50 602,679 3.5 13.34 554,538 13.38
$14.51 - 22.25 434,002 3.8 18.38 434,002 18.38
--------- --- ---------- --------- -------
5,374,202 6.3 $ 9.25 2,311,834 $ 10.21
========= === ========== ========= =======
75
Denbury Resources Inc.
Notes to Consolidated Financial Statements
Employee 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, 2003,
there are 406,466 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 $997,000, $822,000 and $666,000 for the
years ended December 31, 2003, 2002 and 2001, 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 2003, 2002 and
2001, Denbury's matching contributions were $1,067,000, $884,000 and $670,000,
respectively, to the 401(k) Plan.
Note 9. 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 up to 75% of our
anticipated production each year (depending on our overall debt level) to
provide us with a reasonably certain amount of cash flow to cover a majority 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 predominantly
with collars, although for the 2002 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,
------------------------------------------
Amounts in Thousands 2003 2002 2001
-------- ------ -------
Oil Hedge Contracts $(20,337) $ (598) $ 1,925
Gas Hedge Contracts (41,873) 1,530 16,729
-------- ------ -------
Net gain (loss) $(62,210) $ 932 $18,654
======== ====== =======
Some of our derivative contracts require us to pay a premium that 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, 2003 and 2002, we
recorded premium amortization expense of $1.2 million and $9.7 million,
respectively. Also, for the year ended December 31, 2003, we reclassified $5.1
million related to our former Enron hedges (discussed below) out of accumulated
other comprehensive income into income and recorded hedge ineffectiveness of
$282,000 which is also included in "Amortization of derivative contracts and
other non-cash hedging adjustments."
76
Denbury Resources Inc.
Notes to Consolidated Financial Statements
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, we would not have collected anything on the price floors relating to 2003,
even if Enron had not filed bankruptcy, as the natural gas NYMEX prices during
2003 were above $3.75 (the floor price for 2003). We calculate 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.
When Enron filed for bankruptcy during the fourth quarter of 2001, these
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 recognized pre-tax income during 2003 of
approximately $5.1 million. The three-year total pre-tax net loss on the Enron
hedges was approximately $5.9 million, which approximates the difference between
the amount collected and paid for the Enron portion of the associated price
floors.
Hedging Contracts at December 31, 2003
Crude Oil Contracts:
- --------------------
NYMEX Contract Prices Per Bbl
------------------------------------------------------
Collar Prices Estimated
-------------------- Fair Value at
Type of Contract and Period Bbls/d Swap Price Floor Price Floor Ceiling December 31, 2003
- --------------------------- ------ ---------- ----------- ----- ------- -----------------
Swap Contracts
Jan. 2004 - Dec. 2004 2,500 $22.89 $ - $ - $ - $ (6,625)
Jan. 2004 - Dec. 2004 4,500 23.00 - - - (11,746)
Jan. 2004 - Dec. 2004 2,500 23.08 - - - (6,453)
Natural Gas Contracts:
- ----------------------
NYMEX Contract Prices Per MMBtu
------------------------------------------------------
Collar Prices Estimated
-------------------- Fair Value at
Type of Contract and Period MMBtu/d Swap Price Floor Price Floor Ceiling December 31, 2003
- --------------------------- ------- ---------- ----------- ----- ------- -----------------
Swap Contracts
Jan. 2004 - Dec. 2004 30,000 $ - $ - $3.50 $4.45 $(12,527)
Jan. 2004 - Dec. 2004 15,000 - - 3.00 5.87 (2,285)
Jan. 2004 - Dec. 2004 15,000 - - 3.00 5.82 (2,374)
Jan. 2005 - Dec. 2005 15,000 - - 3.00 5.50 (2,603)
77
Denbury Resources Inc.
Notes to Consolidated Financial Statements
At December 31, 2003, our derivative contracts were recorded at their fair
value, which was a net liability of $44.6 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 $27.1 million at December 31, 2003,
represents the deficit in the fair market value of our derivative contracts as
compared to the cost of our hedges, net of income taxes. Of the $27.1 million in
accumulated other comprehensive loss as of December 31, 2003, $25.5 million
relates to current hedging contracts that will expire within the next 12 months
and $1.6 million relates to contracts that expire after December 31, 2004.
Note 10. Commitments and Contingencies
We have operating leases for the rental of office space, equipment, and
vehicles that totaled $16.6 million, $1.7 million and $1.6 million for the years
ended December 31, 2003, 2002 and 2001, respectively. In August 2003, we entered
into a $6.0 million lease financing arrangement for certain equipment at our CO2
processing facility at Mallalieu Field. This lease term is for seven years with
monthly payments of approximately $81,000 per month. At December 31, 2003,
long-term commitments for these items require the following future minimum
rental payments:
Amounts in Thousands
2004.........................$ 2,664
2005......................... 2,784
2006......................... 2,786
2007......................... 2,781
2008......................... 2,670
Thereafter .................. 2,936
-------
Total lease commitments $16,621
=======
Long-term contracts require us to deliver CO2 to our industrial CO2
customers at various contracted prices, plus we have a CO2 delivery obligation
to Genesis related to a VPP entered into during 2003 (see "Genesis Transactions"
above). Based upon the maximum amounts deliverable as stated in the contracts
and the volumetric production payment, we estimate that we may be obligated to
deliver up to 412 Bcf of CO2 to these customers over the next 18 years; however,
based on the current level of deliveries, our commitment would likely be reduced
to approximately 310 Bcf. The maximum volume required in any given year is
approximately 97 MMcf/d, although based on our current level of deliveries, this
would likely be reduced to approximately 70 MMcf/d. Given the size of our proven
CO2 reserves at December 31, 2003 (approximately 1.6 Tcf before deducting
approximately 162.6 Bcf for the VPP), our current production capabilities and
our projected levels of CO2 usage for our own tertiary flooding program, we
believe that we can meet these delivery obligations.
Denbury is subject to various possible contingencies that 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.
78
Denbury Resources Inc.
Notes to Consolidated Financial Statements
Note 11. 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, 2003, we had two significant purchasers that each
accounted for 10% or more of our oil and natural gas revenues: Hunt Refining
(15%) and Genesis (12%). For the year ended December 31, 2002, two purchasers
each accounted for 10% or more of our 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%).
Accounts Payable and Accrued Liabilities
Year Ended December 31,
-----------------------
Amounts in Thousands 2003 2002
------- -------
Accounts payable............................. $33,321 $26,243
Accrued exploration and development costs.... 7,546 3,984
Accrued interest............................. 4,272 6,248
Advances payable............................. 4,430 5,951
Accrued compensation......................... 2,806 3,633
Asset retirement obligations - current....... 2,101 -
Deferred revenues - Genesis................. 2,105 -
Other........................................ 5,768 3,222
------- -------
Total.................................... $62,349 $49,281
======= =======
Supplemental Cash Flow Information
Year Ended December 31,
-------------------------------
Amounts in Thousands 2003 2002 2001
------- ------- ------
Interest paid........................... $23,525 $24,636 $17,451
Income taxes paid (refunded)............ 184 (1,304) 2,482
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,
-----------------------------------------------
2003 2002
---------------------- ----------------------
Carrying Estimated Carrying Estimated
Amounts in Thousands Amount Fair Value Amount Fair Value
-------- ---------- -------- ----------
Senior bank debt.................................. $ 75,000 $ 75,000 $150,000 $150,000
7.5% Senior Subordinated notes due 2013........... 223,203 232,875 - -
9% Senior Subordinated Notes due 2008............. - - 125,000 129,113
9% Series B Senior Subordinated Notes due 2008.... - - 69,889 77,468
As of December 31, 2003 and 2002, 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
79
Denbury Resources Inc.
Notes to Consolidated Financial Statements
primarily of cash, cash equivalents, short-term receivables and payables that
approximate fair value due to the nature of the instrument and the relatively
short maturities.
Note 12. 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. Costs incurred in oil and natural gas activities were
as follows:
Year Ended December 31,
--------------------------------------
Amounts in Thousands 2003 2002 2001
-------- -------- --------
Property acquisitions:
Proved (1)..................... $ 22,307 $ 56,364 $127,066
Unevaluated.................... 3,955 4,342 37,051
Exploration........................ 34,050 29,985 36,836
Development........................ 98,132 64,946 126,222
Asset retirement obligations....... 3,405 - -
-------- -------- --------
Total costs incurred (2)..... $161,849 $155,637 $327,175
======== ======== ========
(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 $5.5 million, $5.3 million and
$4.1 million for the years ended December 31, 2003, 2002 and 2001,
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 2003 2002 2001
-------- -------- --------
Oil, natural gas and related product sales......................... $385,463 $274,894 $260,398
Gain (loss) on settlements of derivative contracts................. (62,210) 932 18,654
-------- -------- --------
Total revenues............................................... 323,253 275,826 279,052
-------- -------- --------
Lease operating costs.............................................. 89,439 71,188 55,049
Production taxes and marketing expenses............................ 14,819 11,902 10,963
Depletion, depreciation and accretion.............................. 90,694 90,679 68,348
Loss on Enron related assets....................................... - - 25,164
Amortization of derivative contracts and other non-cash hedging
adjustments.................................................... (3,578) (3,093) 7,816
-------- -------- --------
Net operating income.......................................... 131,879 105,150 111,712
Income tax provision............................................... 45,427 36,563 36,053
-------- -------- --------
Results of operations from oil and natural gas producing activities $ 86,452 $ 68,587 $ 75,659
======== ======== ========
Depletion, depreciation and accretion per BOE...................... $ 7.16 $ 6.98 $ 6.01
======== ======== ========
80
Denbury Resources Inc.
Notes to Consolidated Financial Statements
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 until we have committed to perform the required development operations,
the majority of which we generally expect to commence within the next year. We
also have a corporate policy whereby proved undeveloped reserves must be
economic at prices significantly lower than the year-end prices used in our
reserve report, at prices closer to historical averages.
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.
Estimated Quantities of Reserves
Year Ended December 31,
-------------------------------------------------------------------
2003 2002 2001
------------------ ------------------ -------------------
Oil Gas Oil Gas Oil Gas
(MBbl) (MMcf) (MBbl) (MMcf) (MBbl) (MMcf)
------ ------- ------ ------- ------ -------
Balance at beginning of year................ 97,203 200,947 76,490 198,277 70,667 100,550
Revisions of previous estimates........ 2,958 (25,451) (408) (22,975) 4,344 (631)
Revisions due to price changes......... 50 (152) 3,020 2,660 (7,800) (2,745)
Extensions and discoveries............. 1,059 68,408 2,326 51,819 2,308 66,448
Improved recovery (1).................. 4,009 - - - 1,667 -
Production............................. (6,896) (34,623) (6,874) (36,662) (6,197) (31,112)
Acquisition of minerals in place....... 838 14,541 23,383 9,360 11,501 65,767
Sales of minerals in place............. (7,955) (1,783) (734) (1,532) - -
------ ------- ------ ------- ------ -------
Balance at end of year...................... 91,266 221,887 97,203 200,947 76,490 198,277
====== ======= ====== ======= ====== =======
Proved developed reserves
Balance at beginning of year........... 62,398 142,812 54,722 169,897 52,353 77,358
Balance at end of year................. 53,804 144,750 62,398 142,812 54,722 169,897
(1) Improved recovery additions result from the application of secondary recovery methods such as water-flooding 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 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
81
Denbury Resources Inc.
Notes to Consolidated Financial Statements
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,
------------------------------------
2003 2002 2001
------ ------ ------
Oil (NYMEX)............................ $32.52 $31.20 $19.84
Natural Gas (NYMEX Henry Hub).......... 6.19 4.79 2.57
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.
December 31,
-------------------------------------------
Amounts in Thousands 2003 2002 2001
------------ ------------ ----------
Future cash inflows................................................... $ $4,059,424 $ 3,787,077 $1,786,884
Future production costs............................................... (1,120,741) (1,044,193) (655,363)
Future development costs.............................................. (300,981) (268,269) (178,546)
------------ ------------ ----------
Future net cash flows before taxes ............................... 2,637,702 2,474,615 952,975
10% annual discount for estimated timing of cash flows................ (1,071,331) (1,048,395) (378,647)
------------ ------------ ----------
Discounted future net cash flows before taxes..................... 1,566,371 1,426,220 574,328
Discounted future income taxes........................................ (442,244) (397,244) (68,533)
------------ ------------ ----------
Standardized measure of discounted future net cash flows.......... $ 1,124,127 $ 1,028,976 $ 505,795
============ ============ ==========
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:
December 31,
-------------------------------------------
Amounts in Thousands 2003 2002 2001
------------ ------------ ----------
Beginning of year.................................................... $ 1,028,976 $ $505,795 $ 841,299
Sales of oil and natural gas produced, net of production costs....... (281,205) (191,803) (194,386)
Net changes in sales prices.......................................... 141,932 694,646 (838,124)
Extensions and discoveries, less applicable future development
and production costs............................................... 235,228 151,926 123,214
Improved recovery (1)................................................ 40,663 - 5,045
Previously estimated development costs incurred...................... 52,874 34,931 64,072
Revisions of previous estimates, including revised estimates of
development costs, reserves and rates of production................ (157,989) (50,855) (13,290)
Accretion of discount................................................ 142,622 57,433 115,897
Acquisition of minerals in place..................................... 44,856 160,899 152,931
Sales of minerals in place........................................... (78,830) (5,285) -
Net change in income taxes........................................... (45,000) (328,711) 249,137
------------ ------------ ----------
End of year.......................................................... $ 1,124,127 $ 1,028,976 $ 505,795
============ ============ ==========
(1) Improved recovery additions result from the application of secondary recovery methods such as water flooding 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, 2003 (includes 162.6 Bcf of reserves dedicated to a volumetric
production payment), 1.6 Tcf at December 31, 2002, and 815 Bcf at December 31,
2001.
82
Denbury Resources Inc.
Notes to Consolidated Financial Statements
Note 13. Condensed Consolidating Financial Information
On December 29, 2003, we amended the indenture for our 7.5% Senior
Subordinated Notes due 2013 to reflect our new holding company organizational
structure (see Note 1 and Note 6). As part of this restructuring our indenture
was amended so that both Denbury Resources Inc. and Denbury Onshore, LLC became
co-obligors of our subordinated debt. Prior to this restructure, Denbury
Resources Inc. was the sole obligor. Our subordinated debt is fully and
unconditionally guaranteed by Denbury Resources Inc.'s significant subsidiaries.
Genesis Energy, Inc., the subsidiary that holds the Company's investment in
Genesis Energy, L.P., is not a guarantor of our subordinated debt. The results
of our equity interest in Genesis is reflected through the equity method by one
of our significant subsidiaries, Denbury Gathering & Marketing. The following is
condensed consolidating financial information for Denbury Resources Inc.,
Denbury Onshore, LLC, and significant subsidiaries:
Condensed Consolidating Balance Sheets
December 31, 2003
----------------------------------------------------------------------------
Denbury
Denbury Onshore,
Resources Inc. LLC Denbury
(Parent and (Issuer and Guarantor Resources Inc.
Amounts in Thousands Co-obligor) Co-obligor) Subsidiaries Eliminations Consolidated
-------------- ------------ ------------ ------------ --------------
ASSETS
Current assets.................................. 1 $ 85,109 $ 23,045 $ - $108,155
Property and equipment.......................... - 553,205 291,540 - 844,745
Investment in subsidiaries (equity method)...... $ 421,201 - 210,803 (624,554) 7,450
Other assets.................................... - 18,019 4,252 - 22,271
--------- -------- --------- --------- --------
Total assets................................ $ 421,202 $656,333 $ 529,640 $(624,554) $982,621
========= ======== ========= ========= ========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities............................. $ - $119,364 $ 7,210 $ - $126,574
Long-term liabilities........................... - 333,616 101,229 - 434,845
Stockholders' equity............................ 421,202 203,353 421,201 (624,554) 421,202
--------- -------- --------- --------- --------
Total liabilities and stockholders' equity.. $ 421,202 $656,333 $ 529,640 $(624,554) $982,621
========= ======== ========= ========= ========
December 31, 2002
------------------------------------------------------------
Denbury
Resources Inc. Denbury
(Parent and Guarantor Resources Inc.
Amounts in Thousands 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
========= ======== ========= =========
83
Denbury Resources Inc.
Notes to Consolidated Financial Statements
Condensed Consolidating Statements of Operations
Year Ended December 31, 2003
-----------------------------------------------------------------------
Denbury
Denbury Onshore,
Resources Inc. LLC Denbury
Amounts in Thousands (Parent and (Issuer and Guarantor Resources Inc.
Co-obligor) Co-obligor) Subsidiaries Eliminations Consolidated
-------------- ----------- ------------ ------------ --------------
Revenues.......................................... $ - $238,072 $94,942 $ - $333,014
Expenses.......................................... - 196,392 56,725 - 253,117
------- -------- ------- -------- --------
Income before the following: - 41,680 38,217 - 79,897
Equity in net earnings of subsidiaries........ 56,553 - 40,667 (96,964) 256
------- -------- ------- -------- --------
Income before income taxes and cumulative
effect of change in accounting principle........ 56,553 41,680 78,884 (96,964) 80,153
Income tax provision.............................. - 5,250 20,962 - 26,212
------- -------- ------- -------- --------
Net income before cumulative effect of change in
accounting principle............................ 56,553 36,430 57,922 (96,964) 53,941
------- -------- ------- -------- --------
Cumulative effect of a change in accounting
principle, net of income tax.................... - 3,981 (1,369) - 2,612
------- -------- ------- -------- -------
Net income (loss)................................. $56,553 $ 40,411 $56,553 $(96,964) $ 56,553
======= ======== ======= ======== ========
Year Ended December 31, 2002
----------------------------------------------------------------
Denbury
Resources Inc. Denbury
(Parent and Guarantor Resources Inc.
Amounts in Thousands 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 benefit............................. 21,003 2,517 - 23,520
-------- ------- -------- --------
Net income (loss).............................. $ 46,795 $ 3,456 $ (3,456) $ 46,795
======== ======= ======== ========
Year Ended December 31, 2001
----------------------------------------------------------------
Denbury
Resources Inc. Denbury
(Parent and Guarantor Resources Inc.
Amounts in Thousands 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
======== ======= ======== ========
84
Denbury Resources Inc.
Notes to Consolidated Financial Statements
Condensed Consolidating Statements of Cash Flows
Year Ended December 31, 2003
----------------------------------------------------------------------
Denbury
Onshore,
Denbury LLC
Resources Inc. (Issuer Denbury
Amounts in Thousands (Parent and and Guarantor Resources Inc.
Co-obligor) Co-obligor) Subsidiaries Eliminations Consolidated
-------------- ----------- ------------ ------------ --------------
Cash flow from operations......................... $ - $146,639 $50,976 $ - $ 197,615
Cash flow from investing activities............... - (81,256) (54,622) - (135,878)
Cash flow from financing activities............... 1 (61,490) - - (61,489)
------- -------- ------- ------- ---------
Net increase (decrease) in cash flow.............. 1 3,893 (3,646) - 248
Cash, beginning of period......................... - 20,281 3,659 - 23,940
------- -------- ------- ------- ---------
Cash, end of period............................... $ 1 $ 24,174 $ 13 $ - $ 24,188
======= ======== ======= ======= =========
Year Ended December 31, 2002
----------------------------------------------------------------
Denbury
Resources Inc. Denbury
(Parent and Guarantor Resources 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)
0ash 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
Resources Inc. Denbury
(Parent and Guarantor Resources 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)
0ash 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
========= ======== ======== =========
85
Denbury Resources Inc.
Notes to Consolidated Financial Statements
Note 14. Unaudited Quarterly Information
-----------------------------------------------------------------------------------------------------------------
In Thousands Except Per Share Amounts March 31 June 30 Sept. 30 December 31
-----------------------------------------------------------------------------------------------------------------
2003
----
Revenues....................................... $ 86,432 $ 84,188 $ 79,415 $ 82,979
Expenses (1)................................... 58,910 76,660 56,691 60,856
Income before accounting change (2)............ 18,453 5,129 15,149 15,210
Net income (2)................................. 21,065 5,129 15,149 15,210
Income per share before accounting change
Basic...................................... 0.34 0.10 0.28 0.28
Diluted.................................... 0.33 0.09 0.27 0.27
Net income per share:
Basic...................................... 0.39 0.10 0.28 0.28
Diluted.................................... 0.38 0.09 0.27 0.27
Cash flow from operations ..................... 35,509 60,542 49,789 51,775
Cash flow used for investing activities........ (18,139) (54,742) (35,495) (27,502)
Cash flow provided by (used for) financing
activities................................. 119,860 (147,622) (5,534) (28,193)
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)
(1) In the second quarter of 2003, we incurred a $17.6 million ($11.5 million net of income tax) loss on early retirement
of debt (see Note 6).
(2) In the first quarter of 2003, we recognized a gain of $2.6 million for the cumulative effect adoption of SFAS No. 143,
"Accounting for Asset Retirement Obligations" (see Note 4).
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 March 1, 2004, to the best of our knowledge, Denbury's common stock was held
of record by approximately 5,700 holders.
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
- ------------------------------------------------------------------------------
High Low
- ------------------------------------------------------------------------------
2003
- ----
First quarter $ 11.59 $ 10.18
Second quarter 13.86 10.25
Third quarter 13.95 11.65
Fourth quarter 14.24 11.23
2003 annual 14.24 10.18
- ------------------------------------------------------------------------------
2002
- ----
First quarter $ 8.50 $ 6.20
Second quarter 10.42 7.91
Third quarter 10.35 7.80
Fourth quarter 11.97 9.45
2002 annual 11.97 6.20
- ------------------------------------------------------------------------------
86