EXHIBIT 13
PAGE 2, PAGES 8 THROUGH 11 INCLUSIVE, PAGES 14 THROUGH 15 INCLUSIVE, PAGES 18
THROUGH 19 INCLUSIVE, PAGES 22 THROUGH 25 INCLUSIVE AND PAGES 28 THROUGH 81
INCLUSIVE, OF THE COMPANY'S ANNUAL REPORT TO SHAREHOLDERS FOR THE YEAR ENDED
DECEMBER 31, 2001, BUT EXCLUDING PHOTOGRAPHS AND ILLUSTRATIONS SET FORTH ON
THESE PAGES, NONE OF WHICH SUPPLEMENTS THE TEXT AND WHICH ARE NOT OTHERWISE
REQUIRED TO BE DISCLOSED IN THIS ANNUAL REPORT ON FORM 10-K.
EX 13-1
Financial Highlights
YEAR ENDED DECEMBER 31,
--------------------------------------------------------
AVERAGE
ANNUAL
AMOUNTS IN THOUSANDS OF U.S. DOLLARS UNLESS NOTED 2001 2000 1999 1998 1997 GROWTH (2)
- ------------------------------------------------------------------------------------------------------------------------
PRODUCTION (DAILY)
Oil (Bbls) 16,978 15,219 12,090 13,603 7,902 21%
Natural Gas (Mcf) 85,238 37,078 27,948 36,605 36,319 24%
BOE (6:1) 31,185 21,399 16,748 19,704 13,955 22%
REVENUES 285,111 181,651 82,990 83,506 86,456 35%
UNIT SALES PRICE (excluding hedges)
Oil (per Bbl) 21.34 25.89 15.03 10.29 17.25 5%
Natural Gas (per Mcf) 4.12 4.45 2.42 2.31 2.68 11%
UNIT SALES PRICE (including hedges)
Oil (per Bbl) 21.65 23.50 13.08 10.29 17.25 6%
Natural Gas (per Mcf) 4.66 3.57 2.34 2.32 2.68 15%
CASH FLOW FROM OPERATIONS (1) 186,801 111,555 31,619 30,096 56,607 35%
NET INCOME (LOSS) 56,550 142,227 4,614 (287,145) 14,903 40%
AVERAGE COMMON SHARES OUTSTANDING 49,325 45,823 39,928 25,926 20,224 25%
PER SHARE
Cash flow from operations (1)
Basic 3.79 2.43 0.79 1.16 2.80 8%
Diluted 3.71 2.41 0.79 1.15 2.64 9%
Net income (loss)
Basic 1.15 3.10 0.12 (11.08) 0.74 12%
Diluted 1.12 3.07 0.12 (11.08) 0.70 12%
OIL AND GAS CAPITAL INVESTMENTS 327,175 134,021 54,967 102,652 305,427 2%
CO2 CAPITAL INVESTMENTS 45,555 - - - - -
TOTAL ASSETS 789,988 457,379 252,566 212,859 447,548 15%
LONG-TERM LIABILITIES 360,882 202,428 154,976 226,436 256,637 9%
STOCKHOLDERS' EQUITY (DEFICIT) 349,168 216,165 72,428 (32,265) 160,223 22%
PROVED RESERVES
Oil (MBbls) 76,490 70,667 51,832 28,250 52,018 10%
Natural Gas (MMcf) 198,277 100,550 50,438 48,803 77,191 27%
MBOE (6:1) 109,536 87,425 60,238 36,383 64,883 14%
Discounted future cash flow - 10% 574,328 1,158,969 462,870 115,019 361,329 12%
PER BOE DATA (6:1)
Oil and natural gas revenues 22.88 26.13 14.88 11.36 16.75 8%
Gain (loss) on settlements of derivative contracts 1.64 (3.23) (1.54) 0.02 - -
Lease operating costs (4.84) (4.94) (4.25) (3.49) (3.54) 8%
Production taxes and marketing expense (0.96) (1.02) (0.60) (0.56) (0.82) 4%
- ------------------------------------------------------------------------------------------------------------------------
Production netback 18.72 16.94 8.49 7.33 12.39 11%
Operating cash flow from CO2 operations 0.38 - - - - -
General and administrative expense (0.89) (1.09) (1.21) (1.02) (1.30) 9%
Net cash interest (expense) income (1.74) (1.54) (2.22) (2.13) 0.02 -
Current income taxes and other (0.06) (0.07) 0.11 - - -
- ------------------------------------------------------------------------------------------------------------------------
CASH FLOW FROM OPERATIONS (1) 16.41 14.24 5.17 4.18 11.11 10%
- ------------------------------------------------------------------------------------------------------------------------
(1) Exclusive of the net change in non-cash working capital balances.
(2) Four year compounded annual growth rate computed using 1997 as a base year.
Reporting Format
Unless otherwise noted, the disclosures in this report have (i) dollar amounts
presented in U.S. dollars, (ii) production volumes expressed on a net revenue
interest basis, and (iii) gas volumes converted to equivalent barrels at 6:1.
EX 13-2
Selected Operating Data
OIL AND GAS RESERVES
Estimates of our net proved oil and natural gas reserves as of December 31, 2001
and 2000, have been prepared by DeGolyer and MacNaughton, and the estimates as
of December 31, 1999 were prepared by Netherland, Sewell and Associates, Inc.,
both independent petroleum engineers located in Dallas, Texas. The reserves were
prepared using constant prices and costs in accordance with the guidelines of
the Securities and Exchange Commission ("SEC"), based on the prices received on
a field-by-field basis as of December 31 of each year. The reserves do not
include any value for probable or possible reserves which may exist, nor do they
include any value for undeveloped acreage. The reserve estimates represent our
net revenue interest in our properties.
Our proved non-producing reserves primarily relate to additional potential
producing 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 non-producing reserves.
Reserves associated with our CO2 operations in West Mississippi and our
Heidelberg waterfloods in East Mississippi account for approximately 80% 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 there is minimal reservoir risk
associated with these reserves since the reservoir has already been defined by
drilling of wells during primary production. All of these reserves are
associated with secondary recovery and tertiary recovery operations in fields
and reservoirs that produced substantial volumes of oil under primary
production. The primary reason they are classified as undeveloped is because
they require significant additional capital associated with drilling wells and
additional facilities in order to produce the reserves. The remaining 20% or our
undeveloped oil reserves are located well within the currently producing regions
of our fields, many of which are up-dip to existing production.
Our proved undeveloped natural gas reserves are not as concentrated as our oil
reserves. The properties we acquired in the Matrix acquisition account for
approximately 60% of our proved undeveloped natural gas reserves. These reserves
are typically located up-dip to existing wells that ceased producing due to
water encroachment. These natural gas reserves are confirmed not only by
sub-surface geology but also by 3D seismic that covers these areas. An
additional 16% of our proved undeveloped natural gas reserves are located in
Heidelberg Field where we continue to have success in-fill drilling the Selma
Chalk formation. The remaining significant undeveloped natural gas reserves are
in our Thornwell/Lakeside area, primarily associated with the Bol Perc
reservoir. We drilled and completed five additional wells there in 2001 without
a dry hole. The remaining undeveloped natural gas reserves are again located
well within our currently producing reservoirs, many of which are up-dip to
existing production. Our current plans for 2002 include development of all of
the proved undeveloped natural gas reserves, excluding the offshore reserves. We
believe the development of offshore natural gas reserves in a pricing
environment of less than $2.50 per Mcf is not warranted and plan to develop
these reserves beginning in 2003, assuming prices are above that.
EX 13-8
Year Ended December 31,
-------------------------------------------
2001 2000 1999
------------ ------------ ------------
ESTIMATED PROVED RESERVES:
Oil (MBbls)................................................ 76,490 70,667 51,832
Natural gas (MMcf)......................................... 198,277 100,550 50,438
Oil equivalent (MBOE)...................................... 109,536 87,425 60,238
PERCENTAGE OF TOTAL MBOE:
Proved producing........................................... 53% 57% 41%
Proved non-producing....................................... 23% 18% 25%
Proved undeveloped......................................... 24% 25% 34%
REPRESENTATIVE OIL AND GAS PRICES: (1)
Oil - NYMEX................................................$ 19.84 $ 26.80 $ 25.60
Natural gas - NYMEX Henry Hub.............................. 2.57 9.78 2.12
PRESENT VALUES:(2)
Discounted estimated future net cash flow before
income taxes ("PV10 Value") (thousands)................$ 574,328 $ 1,158,969 $ 462,870
Standardized measure of discounted estimated future net
cash flow after income taxes (thousands)...............$ 505,795 $ 841,299 $ 448,374
- ---------------
(1) The oil prices as of each respective year-end were based on NYMEX prices per
Bbl and NYMEX Henry Hub ("NYMEX") prices per MMBtu, with these representative
prices adjusted by field to arrive at the appropriate corporate net price.
(2) Determined based on year-end unescalated prices and costs in accordance with
the guidelines of the SEC, discounted at 10% per annum.
EX 13-9
FIELD SUMMARIES
Denbury operates in four primary core areas, Louisiana, offshore Gulf of Mexico,
Eastern Mississippi and Western Mississippi. Our 13 largest fields constitute
approximately 85% of our total proved reserves on a BOE basis and 80% on a PV10
Value basis. Within these 13 fields we own an average 82% 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.
2001
Proved Reserves as of December 31, 2001 (1) Average Daily Production
------------------------------------------------------ ------------------------
Average Net
Oil Natural Gas MMBOE's BOE PV10 Valu Oil Natural Gas Revenue
(MBbls) (MMcf) (000's) % of Total (000's) (Bbls/d) (Mcf/d) Interest(2)
- -----------------------------------------------------------------------------------------------------------------------------------
Louisiana
Lirette ........................ 348 16,905 3,165 2.9% 33,053 379 13,007 54%
Thornwell ...................... 797 11,905 2,781 2.5% 30,330 626 21,895 49%
S.Chauvin ...................... 392 11,408 2,293 2.1% 20,526 70 1,426 41%
Other Louisiana ................ 927 23,364 4,822 4.4% 43,027 794 8,064 20%
------ ------- ------- ----- ------- ------ ------ ------
Total Louisiana 2,464 63,582 13,061 11.9% 126,936 1,869 44,392 38%
------ ------- ------- ----- ------- ------ ------ ------
Offshore Gulf of Mexico
W.Delta 27 (3) ................. 1,677 21,676 5,290 4.9% 40,223 264 5,480 56%
South Marsh Island 48 (3) ...... 169 26,294 4,552 4.2% 43,131 21 2,463 83%
Brazos A-22 (3) ................ 104 12,826 2,242 2.0% 12,355 17 1,286 37%
West Cameron 192 (3) ........... 18 8,708 1,469 1.3% 12,216 8 1,976 25%
E. Cameron 33 (3) .............. 36 6,980 1,199 1.1% 12,899 25 4,591 42%
Other offshore ................. 96 23,970 4,090 3.7% 36,244 84 15,841 18%
------ ------- ------- ----- ------- ------ ------ ------
Total offshore .............. 2,100 100,454 18,842 17.2% 157,068 419 31,637 36%
------ ------- ------- ----- ------- ------ ------ ------
Eastern Mississippi
Heidelberg ..................... 39,835 26,877 44,315 40.5% 121,381 6,671 7,425 80%
Eucutta ........................ 4,460 285 4,508 4.1% 22,315 1,888 116 77%
King Bee ....................... 3,108 -- 3,108 2.8% 11,524 813 -- 82%
Other E. Mississippi ........... 4,667 3,648 5,274 4.8% 24,472 2,682 1,023 48%
------ ------- ------- ----- ------- ------ ------ ------
Total E. Missisissippi ...... 52,070 30,810 57,205 52.2% 179,692 12,054 8,564 74%
------ ------- ------- ----- ------- ------ ------ ------
Western Mississippi
Mallalieu ...................... 10,435 -- 10,435 9.6% 37,847 57 -- 80%
Little Creek ................... 7,562 -- 7,562 6.9% 62,042 2,441 -- 83%
Other .......................... 1,667 -- 1,667 1.5% 5,045 62 -- 80%
------ ------- ------- ----- ------- ------ ------ ------
Total W. Missisissippi ...... 19,664 -- 19,664 18.0% 104,934 2,560 -- 82%
------ ------- ------- ----- ------- ------ ------ ------
Other ............................. 192 3,431 764 0.7% 5,698 76 645 69%
------ ------- ------- ----- ------- ------ ------ ------
Company Total ..................... 76,490 198,277 109,536 100.0% 574,328 16,978 85,238 64%
====== ======= ======= ===== ======= ====== ====== ======
(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-fieldbasis as of December 31, 2001. The prices at that date were a NYMEX oil price of $19.84 per Bbl adjusted
by field and a NYMEX natural gas price average of $2.57 per MMBtu also adjusted by field.
(2) Only includes wells in which the Company has a working interest as of December 31, 2001.
(3) These fields were acquired during 2001. The average production during the period they were owned by the Company was 14.0 MMcfe/d
at W. Delta 27, 5.1 MMcfe/d at S. Marsh Island 48, 2.8 MMcfe/d at Brazos A-22, 4.0 MMcfe/d at W. Cameron 192, and 9.4 MMcfe/d at
E. Cameron 33.
EX 13-10
Oil and Gas Acreage
The following table sets forth Denbury's acreage position at December 31, 2001:
Developed Undeveloped
---------------------------------- ---------------------------------
Gross Net Gross Net
-------------- --------------- --------------- -------------
Louisiana.................... 21,037 13,563 27,899 16,335
Mississippi.................. 49,892 43,773 60,396 39,538
Offshore Gulf Coast . . . 113,048 56,645 46,716 46,716
Texas........................ 1,890 1,624 19,618 16,610
-------------- --------------- --------------- -------------
Total............ 185,867 115,605 154,629 119,199
============== =============== =============== =============
Productive Wells
This table sets forth both the gross and net productive wells of the Company at December 31, 2001:
Producing Oil Producing Natural
Wells Gas Wells Total
--------------------------- --------------------------- ----------------------------
Gross Net Gross Net Gross Net
----------- ---------- ----------- ----------- ----------- -----------
Louisiana.................. 23 7.5 71 32.3 94 39.8
Mississippi................ 369 284.5 61 40.0 430 324.5
Offshore Gulf Coast ....... 4 1.8 86 31.0 90 32.8
Texas...................... - - 4 2.8 4 2.8
----------- ---------- --------- ----------- --------- -----------
Total............... 396 293.8 222 106.1 618 399.9
=========== ========== ========= =========== ========= ===========
Drilling Activity
The following table sets forth the results of drilling activities during each of the three fiscal years in the period ended
December 31, 2001:
Year Ended December 31,
--------------------------------------------------------------
2001 2000 1999
------------------- ------------------ -------------------
Gross Net Gross Net Gross Net
-------- -------- -------- -------- -------- --------
Exploratory Wells: (1)
Productive (2)........................ 15 8.2 3 1.1 3 1.0
Nonproductive (3)..................... 3 1.2 1 0.2 1 1.0
Development Wells: (1)
Productive (2)........................ 60 37.9 38 26.5 12 11.9
Nonproductive (3)(4).................. - - 2 0.2 - -
-------- -------- -------- -------- -------- --------
Total........................... 78 47.3 44 28.0 16 13.9
======== ======== ======== ======== ======== ========
(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 2001, 2000 and 1999, an additional 24, 12 and 4 wells, respectively, were drilled for water or CO2 injection purposes.
EX 13-11
OPERATIONS SECTION OF ANNUAL REPORT
[Map Graphic Omitted]
South Louisiana
Denbury operates on the land and in the marshes of South Louisiana,
including state waters. Denbury owns interests in 94 wells and operates 60 of
these wells (64%) from its regional office in Houma, Louisiana. This region
produces a significant portion of our natural gas, averaging 39.4 MMcf/d net to
us in the 4th quarter of 2001, approximately 39% of our total natural gas
production. We anticipate future increases in our capital budget for this region
as we attempt to increase the percentage of natural gas production Company-wide.
The majority of our onshore fields lie in the Houma embayment area of
Terrebonne Parish, including Lirette, Bayou Rambio and South Chauvin 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 550 square miles of 3D data, and plan to expand our data
ownership. A portion of this data, the first 3D seismic shot in these swampy
areas, was instrumental in our drilling of two successful step- out wells at
Lirette in 1999, and one very successful exploration well in 2000. We continued
our success in Terrebonne Parish with the drilling of two successful wells in
2001. The first well, Laterre #C-6 (South Chauvin Field), averaged 3.2 MMcf/d
and 100 Bbls/d net to the Company during January 2002. The second well, Harry
Bourg #4 (Bayou Rambio Field) was drilled very late in 2001 and has just
recently been completed. In 2002, we plan to drill three to four additional
wells in the Terrebonne Parish area using the same 3D interpretation techniques.
We were very active in Thornwell Field, located in Cameron and Jeff Davis
Parishes, during 2001. This field, purchased in late 2000, produced an average
of 25.7 MMcfe/d net to our interest during 2001. Our primary interest in
purchasing this field was the substantial upside potential that exists in
continued development of the existing producing zones (Bol Perc), and the
exploration potential of several deeper zones (Marg Howeii and Camerina). These
prospects are all defined by a recent 110 square mile 3D seismic survey. During
2001 we were successful in the continued development of the Bol Perc sands, with
the drilling of five Bol Perc wells without any dryholes. We also participated
in the drilling of one successful Camerina well, SL 15223 #1, which produced 13
MMcfe/d during the fourth quarter of 2001, 2 MMcfe/d net to us. This well
appears to have set up at least four additional Camerina prospects in the
immediate area. We intend to maintain our level of activity in this area in
2002, with current plans to drill at least three to four Bol Perc wells, two to
four Camerina wells and one to two Marg Howeii wells.
EX 13-14
Offshore Gulf of Mexico
Denbury's offshore focus is exclusively on the Gulf of Mexico shelf, using
the same 3D seismic techniques we have applied onshore. Denbury owns an interest
in 90 wells and operates 65 of these wells (72%) from its regional office in
Covington, Louisiana. Based on our early success in the Gulf of Mexico, we
agreed to purchase Matrix Oil & Gas Inc. in June 2001. Matrix followed our same
strategy of acquiring offshore fields from the major oil and gas companies that
had produced large quantities of oil and natural gas. We believe large fields
that have produced hundreds of millions of barrels of oil and hundreds of
billions of cubic feet of natural gas generally have an additional 10% to 15% of
additional reserves which can be produced when detailed geology and engineering
work is applied. The purchase of Matrix added approximately 42 MMcfe/d to our
third and fourth quarter production volumes. By the end of 2001, including
Matrix, we drilled, recompleted or sidetracked 12 wells offshore without a dry
hole. Offshore production started at near zero at the beginning of 2001 and
averaged 55.6 MMcfe/d during the 4th quarter of 2001. Due to the downturn in
natural gas prices that occurred late in 2001, we expect to have less activity
offshore in 2002 than we did in 2001. Currently we have plans to drill one to
three wells offshore during 2002.
We have developed a significant inventory of internal offshore projects as
part of the Matrix acquisition. Prior to this acquisition we were focusing on
lower risk amplitude plays with expected reserves of 5 to 10 Bcf. Our current
inventory of projects has numerous of these projects and after the Matrix
acquisition, now includes several prospects with potential in the 50 to 150 Bcf
range. The majority of these opportunities will be pursued when, and if, natural
gas prices increase.
[Map Graphic Omitted]
EX 13-15
[Map Graphic Omitted]
Heidelberg and East Mississippi
In the Eastern part of the Mississippi salt basin, we operate 397 wells out
of 430 (92%) from our office in Laurel, Mississippi. These fields produced an
average of 11,434 Bbls/d and 8.2 MMcf/d during the 4th quarter of 2001. The
largest field in the region, and our largest field, is Heidelberg Field, which
for the fourth quarter of 2001 produced an average of 7,814 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.
Our strategy has been to increase reserves and production in and around
existing fields. The fields in this region are characterized by structural traps
that generate prolific production from stacked or multiple pay sands. As such,
they provide opportunities to increase reserves through infield drilling,
recompletions, improvements in production efficiency, and in some cases, by
water flooding producing reservoirs. Most of our wells produce large amounts of
saltwater and require large pumps, which increases the operating costs per
barrel relative to our properties in Louisiana that are predominantly natural
gas producers. We plan to continue our basic strategy in the region,
supplemented by additional waterflooding (secondary recovery) and eventually
carbon dioxide ("CO2") flooding (tertiary recovery).
Our primary interests at Heidelberg Field were acquired from Chevron in
December 1997. This field was discovered in 1944 and has produced an estimated
196 MMBbls of oil and 39 Bcf of gas since its discovery. The Field is a large
salt-cored anticline that is divided into western and eastern segments due to
subsequent faulting. Production is from a series of normally pressured
Cretaceous and Jurassic Age sandstone formations situated between 3,500 feet and
11,500 feet. There are 11 producing formations in the Heidelberg Field
containing 40 individual reservoirs, with the majority of the past and current
production coming from the Eutaw and Christmas sands at depths of 4,000 to 5,000
feet.
We continue to employ the latest technological advances in artificial lift,
open-hole and cased-hole logging techniques, and most recently, hydraulic
fracturing techniques. When we acquired the property, production was
approximately 2,800 BOE/d. As a result of our subsequent development work,
production for 1998 averaged 3,760 BOE/d, for 1999 averaged 5,708 BOE/d, for
2000 averaged 7,310 BOE/d and for 2001 averaged 7,908 BOE/d.
We currently operate five waterflood units at Heidelberg: four on the east
side and one expanded unit on the west. These water-
EX 13-18
flood units produce from the shallow (approximately 4,400 feet) Eutaw formation.
The cumulative production from these five units since their initial discovery is
estimated at 73.5 million barrels, or approximately 25% of the original oil
estimated to be in place. We believe that properly designed and executed
waterflood programs should increase the recovery factor to 40%, similar to our
expectations from the nearby analogous Eucutta Field.
During 2001, we continued our development of the Selma Chalk formation in
Heidelberg, which produces natural gas at a depth of 3,700 feet. Previous
operators only partially developed this formation in order to provide fuel gas
for the rest of the field. We drilled 13 wells in 2001 that effectively reduced
the well spacing down to 40 acres in East Heidelberg. Using modern hydraulic
fracturing techniques, we increased the natural gas production at Heidelberg to
over 10 MMcf/d. We believe that there may be opportunities to extend this plan
and further reduce the well spacing. However, this will probably be delayed
until natural gas prices recover.
We believe that there may also be additional potential in several zones
below the Eutaw formation, including the Christmas, Tuscaloosa, Paluxy, Rodessa,
Hosston, and Cotton Valley formations. These formations have produced a combined
81 MMBbls and 20 Bcf from inception through late 2001.
Denbury has pursued the same strategy at its other significant fields in
East Mississippi; Eucutta, Quitman, Davis, Sandersville and King Bee Fields.
After we acquired each of these oil fields, we initiated a rework program to
increase production and reserves. Davis Field, one of our oldest fields, is an
example of our strategy in Mississippi. This field was producing approximately
600 Bbls/d and had reserves of approximately 1.8 MMBbls when we acquired it in
1993. Since then, the field has produced at various rates, with a monthly high
of approximately 1,700 Bbls/d, and a fourth quarter 2001 average rate of 538
Bbls/d. Over the eight years since its acquisition, we have produced in excess
of 2.0 MMBbls of oil.
We have just completed the first 3D seismic survey ever shot over King Bee
Field (Cypress Creek Dome), a field we acquired from Fina in 1999. King Bee
Field is a salt dome field with relatively few wells drilled over the years,
since it underlies a national forest and a US Military bombing range. Due to
these surface restrictions, wells have to be drilled from sites outside of the
bombing area, and thus well costs are higher than normal. The higher costs of
drilling and the steeply dipping beds of the producing formations make it
imperative to have a very good geologic picture of the subsurface prior to
drilling. Fina and prior operators attempted to drill wells here based on a few
scattered 2D seismic lines with mixed success.
Several relatively large accumulations of oil (5 to 12 MMBbls) have been
found around Cypress Creek Dome with a large portion of the eastern flank being
untested. We own this proprietary 3D seismic survey and have high expectations
for reserve additions in the coming years. Since we acquired this field,
production has increased slightly through only a minor amount of capital
expenditures. Our 2002 plans include the drilling of one well to begin pressure
maintenance operations in a Lower Tuscaloosa fault block that we believe could
contain up to 11 MMBbls of oil in place. This fault block produced an average of
800 Bbls/d from two wells during 2001.
EX 13-19
[Map Graphic Omitted]
West Mississippi and our CO2 Assets
Denbury began its activities in this part of the basin in September 1999
with the purchase of Little Creek Field, now our 2nd largest field based on PV10
values at December 31, 2001. In February 2001, we acquired CO2 reserves and
producing wells near Jackson, Mississippi, which included a 183-mile pipeline
that transports CO2 to Little Creek Field in the southwestern part of the state.
This acquisition allowed us to expand our tertiary CO2 gas flooding at Little
Creek Field Unit into West Little Creek Field and Lazy Creek Field Unit, as well
as begin CO2 flooding at West Mallalieu Field Unit, a field we acquired in May
2001.
Carbon dioxide injection for tertiary recovery purposes has been used
extensively in the Permian Basin Region of West Texas, because of the
availability of large reserves of CO2. Carbon dioxide injection is one of the
most efficient tertiary recovery mechanism for crude oil, but its application is
limited by the availability of large quantities of CO2, which had been
restricted to West Texas, Mississippi and other isolated areas. The carbon
dioxide acts as a type of solvent for the oil, removing it from the formation as
the CO2 is produced. For example, in a typical oil field, between 40% and 50% of
the oil in place can be extracted by primary and secondary (waterflooding)
recovery. An additional amount of oil (17% at Little Creek) can be recovered by
injecting CO2 into certain wells and then recovering oil and CO2 from other
wells.
In Mississippi, CO2 reserves have been discovered around Jackson dome, a
volcanic intrusive which was emplaced about 80 million years ago. The CO2
reserves in this area are found in structural traps in the Buckner, Smackover
and Norphlet formations at depths of about 15,000 feet. Some estimates have
suggested that there are 12 Tcf of usable CO2 in this area. Our acquisition
included 10 producing CO2 wells, which were originally drilled by Shell to
supply CO2 to Little Creek Field, with an estimated 815 Bcf of proved producing
CO2 reserves. During the fourth quarter of 2001, we sold an average of 41 MMcf/d
to commercial users and we used an average of 52 MMcf/d for our tertiary
activities.
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 reserves may be available in
fields in this part of the state.
EX 13-22
Obviously, a great deal of work is required before these reserves can be
recorded as proved reserves, such as acquiring properties, leasing, reworking
and reentering wells and installing production facilities; however, preliminary
indications suggest that there is considerable potential for us in this part of
Mississippi.
As of March 15, 2002, we currently have leased or own eight fields in this
area with the potential of 20 to 35 MMBbls of additional reserves, beyond our
current proved reserves of 19.7 MMBbls, based on the 17% recovery factor that we
have at Little Creek Field. Our total acquisition cost to date for these
additional fields is approximately $2.4 million. Since most of these fields in
the area are depleted or nearly depleted, the acquisition cost is minimal. We
will continue to pursue additional acquisitions in the area around our pipeline
to use in our tertiary recovery operations.
EX 13-23
[Map Graphic Omitted]
Little Creek and Mallalieu Field
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 (which are merely distinct areas of the field)
of the field began in 1985. When we acquired the field in 1999, these first two
phases were substantially complete and Phase III was in process. We have
completed Phase III and Phase IV and initiated CO2 injection into Phase V. Our
plans in 2002 are to finish Phase V and further expand into areas beyond the
original patterned areas in Phases III, IV and V. Currently there are 44
producing wells and 29 injection wells at Little Creek. Based on the results of
the two earliest phases of CO2 flooding at Little Creek, tertiary recovery has
increased the ultimate recovery factor in that portion of the field by
approximately 17%, as compared to approximately 20% for primary recovery and 18%
for secondary recovery. The field has produced a cumulative 57.8 MMBbls of light
sweet crude and we currently estimate that an additional 9.5 MMBbls will be
recovered.
Production from Little Creek Field was approximately 1,350 Bbls/d when we
acquired it in 1999. During the fourth quarter of 2001, production had increased
to an average of 3,052 BOE/d, up from 2,206 BOE/d in the fourth quarter of 2000.
We expect the production from Little Creek to increase throughout 2002 and peak
during 2003 at an estimated net rate of 4,500 to 5,000 BOE/d.
We expanded our CO2 flooding operations following our purchase of the CO2
source field. During 2001 we formed two additional units offsetting Little Creek
Field: West Little Creek Field Unit and Lazy Creek Field Unit. These areas were
previously developed and abandoned following primary production. These two units
can be CO2 flooded with the existing infrastructure at Little Creek, and thus
the cost for facilities will be dramatically reduced. During January 2002, the
West Little Creek Unit began responding to CO2 injection and was producing
approximately 425 Bbls/d. The Lazy Creek Unit had not responded as of January,
2002.
In addition to our expansion activities at Little Creek, we purchased West
Mallalieu Field Unit for $4.0 million in May 2001. West Mallalieu Field Unit was
originally unitized by Shell Oil Company, and a subsequent pilot project was
commenced in 1986. The pilot project, consisting of four 5-spot patterns,
produced approximately 2.1 MMBbls of oil as a result of CO2 flooding. We
expanded the pilot project by adding an additional four patterns during
EX 13-24
2001 and expect response to occur during the latter part of 2002. In contrast to
Little Creek Field, West Mallalieu Field was not waterflooded prior to CO2
injection. Therefore, the tertiary recovery of oil from West Mallalieu Field
Unit as a result of CO2 injection could exceed the 17% of original oil in place
that is expected from Little Creek Field.
At December 31, 2001, we had proved reserves of 10.4 MMBOE at Mallalieu,
for an acquisition cost of less than $0.40 per BOE. This field's future
development costs are between $3.00 and $4.00 per BOE, which we believe is
typical for fields in this area. With all-in finding and development costs of
approximately $4.00 per BOE and anticipated operating costs of around $10.00 per
BOE, these tertiary recovery operations in West Mississippi along our pipeline
are very profitable at $18 to $20 oil prices, as they produce light sweet oil
that receives near NYMEX pricing. Through December 31, 2001, we had spent a
total of $51.8 million on fields in this area, primarily Little Creek and
Mallalieu Field, have received $28.7 million in net operating income, leaving us
a balance of $23.1 million to recover for payout. This compares to a PV10 value,
using December 31, 2001 SEC pricing of $19.84 per Bbl, of $104.9 million.
Barnett Shale
Denbury also owns about 20,000 acres of leases in the Fort Worth Basin
which is prospective for the Barnett Shale. Five wells have been drilled in
2001, two of which were producing at year end and three others were awaiting
completion. The Company plans to drill a minimal number of wells in this play
until gas prices recover to above $3.00 per Mcf.
EX 13-25
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.
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.
Mcf/d One thousand cubic feet of natural gas 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.
PV10 Value When used with respect to oil and natural gas reserves, PV10 Value means the
estimated future gross revenue to be generated from the production of proved reserves,
net of estimated production and future development costs, using prices and costs in
effect at the determination date, 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 that can be expected to be recovered through existing wells with existing equipment
Reserves and operating methods.
Proved Reserves The estimated quantities of crude oil, natural gas and natural gas liquids which
geological and engineering data demonstrate with reasonable certainty to be recoverable in future
years from known reservoirs under existing economic and operating conditions.
Proved Undeveloped Reserves that are expected to be recovered from new wells on undrilled acreage or from existing
Reserves wells where a relatively major expenditure is required.
Tcf One trillion cubic feet of natural gas.
EX 13-28
Management's Discussion and Analysis of Financial Condition and Results of
Operations
We are a growing independent oil and gas company engaged in acquisition,
development and exploration activities in the U.S. Gulf Coast region. We are the
largest oil and natural gas producer in Mississippi, hold key operating acreage
onshore Louisiana and have a growing presence in the offshore Gulf of Mexico
areas. Our goal is to increase the value of acquired properties through a
combination of exploitation, drilling, and proven engineering extraction
processes. Our corporate headquarters are in Dallas, Texas, and we have three
primary field offices located in Houma and Covington, Louisiana, and Laurel,
Mississippi.
2001 ACQUISITIONS
Carbon Dioxide Acquisition
In February 2001, we acquired carbon dioxide ("CO2") reserves, production and
associated assets from a unit of Airgas, Inc., for $42.0 million. This
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 recovery operations at Little Creek Field, a
field we purchased in August 1999, and Mallalieu Field, a field we purchased in
May 2001, as well as to other commercial users. We acquired nearly 100% of the
working interest in the producing CO2 wells and we operate the properties. As of
December 31, 2001, based on a report prepared by DeGolyer and MacNaughton, we
believe that these wells have approximately 815 billion cubic feet of usable CO2
reserves, net to our working interest.
Our CO2 production has increased gradually since we acquired the property. We
have increased the CO2 that we use in our operations due to further expansion of
the tertiary recovery project at Little Creek Field and initiation of a new
tertiary recovery project at Mallalieu Field late in 2001. Our sales to our
industrial customers also increased slightly throughout the year. During the
fourth quarter of 2001, CO2 production averaged approximately 92.9 million cubic
feet of CO2 per day, of which about 51.6 million cubic feet per day was used for
injection at our two tertiary recovery operations, with the remainder of about
41.3 million cubic feet per day sold under long-term contracts to commercial CO2
users.
We estimate that the CO2 production capacity of the acquired wells is
approximately 110 million cubic feet of CO2 per day, but believe that production
could be increased to about 250 million cubic feet of CO2 per day by adding
compression facilities. An associated pipeline purchased in the acquisition is
capable of transporting over 700 million cubic feet of CO2 per day with
additional facilities and increased compression. We plan to continue to expand
our CO2 operations through acquisitions of additional oil fields, particularly
along our pipeline, and implementing new tertiary floods there for the next
several years, as our ownership of the CO2 source wells, pipeline and facilities
assures us that CO2 will be available to us when we need it at a reasonable and
predictable cost. We anticipate that we will spend between 25% and 50% of our
annual development budget on these projects, at least for the next few years,
unless there is a significant drop in oil prices or our economics change for
some unforeseen reason. In addition to the oil fields near our pipeline that we
can potentially acquire and flood, there is also the potential to expand our
pipeline farther south in Louisiana or east in Mississippi, where we believe
there are other potential tertiary recovery projects. We believe that the
ownership of these CO2 reserves provides us a significant strategic advantage in
the acquisition of other properties in Mississippi and Louisiana that could be
further exploited through tertiary recovery.
EX 13-29
Matrix Acquisition
On July 10, 2001, we acquired Matrix Oil & Gas, Inc., an independent oil and gas
company based in Covington, Louisiana. The primary reasons for the acquisition
were (i) that the assets, older complex fields that have produced significant
amounts of oil and natural gas, appear to have significant potential incremental
reserves, and (ii) that the acquisition increased our natural gas production,
bringing our oil and natural gas production ratio to approximately 50/50. Most
of the Matrix properties and activities are in the offshore Gulf of Mexico, with
an interest in 19 offshore blocks and two onshore fields. At June 30, 2001,
based on a reserve report prepared by DeGolyer and MacNaughton, Matrix had
estimated proved reserves of 11.9 MMBOE (71.6 Bcfe), 92% of which was natural
gas and 78% of which was proved developed. By year-end, based on DeGolyer and
MacNaughton's reserve report, we had increased their reserves 35% to 16.1 MMBOE
(96.6 Bcfe), or a 46% increase when you adjust for the production from July to
December, 2001. These reserve additions (32.7 Bcfe) came from the $24.6 million
invested in development and exploration projects on these properties since they
were acquired in July.
In our acquisition of Matrix we paid approximately $158.5 million, comprised of
$99.3 million (63%) in cash and $59.2 million (37%) in the form of 6.6 million
shares of our common stock. We funded the cash portion of the purchase price
with available cash and $95.0 million drawn under our bank credit facility. At
the time of the acquisition, we recorded $30.0 million of the purchase price as
unevaluated property costs to reflect the significant probable and possible
reserves that we had identified. At year-end, we reduced our unevaluated
property costs by $5.0 million based on the results of our drilling activity and
the reserves added since the acquisition. We believe that there are significant
additional potential reserves on these properties.
As with other recent acquisitions, we purchased commodity hedges to protect our
investment when we acquired Matrix. These hedges, in the form of price floors,
covered nearly all of the forecasted production from the acquired properties for
two and one-half years 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 in 2001.
Unfortunately, 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, which included the claim for
the price floors and minor natural gas production receivables, collecting net
proceeds of approximately $9.2 million. In total, we collected approximately
$21.9 million from our price floors relating to the Matrix acquisition, a net
cash gain of approximately $3.9 million over the cost of the floors, but have
suffered an opportunity loss in light of the drop in natural gas prices since
the date of the Matrix acquisition and the loss of our 2002 and 2003 hedges.
Since the Enron bankruptcy we have purchased additional hedges to protect
against any further deterioration in natural gas prices. See "Market Risk
Management" below for further information regarding these hedges and the
accounting treatment related to the former Enron hedges.
CAPITAL RESOURCES AND LIQUIDITY
ELEMENTS OF INCREASED CASH FLOW AND PRE-TAX EARNINGS IN 2001. We had record
pre-tax earnings and cash flow from operations in 2001 primarily because of our
46% increase in average daily production and near record average commodity
prices. We generated $186.8 million in cash flow from operations (excluding the
net change in non-cash working capital balances), 67% higher than our prior high
in 2000. You may find more details about these items in the section "Results of
Operations" below.
EX 13-30
INCREASED PRODUCTION. Our production increased approximately 46% between 2000
and 2001. The most significant factor in this increase was the purchase of
Matrix in early July 2001. This acquisition added 3,524 BOE/d, primarily natural
gas, to our average 2001 production, representing approximately 36% of the
increase. The remainder of the increase came from our development and
exploitation projects on existing fields and other smaller acquisitions.
COMMODITY PRICES. NYMEX oil prices were at historic lows in the $12.00 per Bbl
range at year-end 1998, but increased steadily during the next two years to an
average of approximately $30.25 per Bbl during 2000. During 2001, NYMEX oil
prices declined to an average of $26.00 (as compared to a net corporate average
price received of $21.34 per Bbl for 2001 before the positive impact of
hedging).
Graph depicting the NYMEX crude oil price listings by month from January 1999
through December 2001:
Jan-99 Feb-99 Mar-99 Apr-99 May-99 Jun-99 Jul-99 Aug-99 Sep-99 Oct-99 Nov-99 Dec-99
12.49 12.02 14.68 17.30 17.77 17.92 20.10 21.28 23.79 22.67 24.77 26.09
Jan-00 Feb-00 Mar-00 Apr-00 May-00 Jun-00 Jul-00 Aug-00 Sep-00 Oct-00 Nov-00 Dec-00
26.88 29.37 30.06 25.64 28.95 31.46 30.05 31.17 33.76 32.90 34.40 28.35
Jan-01 Feb-01 Mar-01 Apr-01 May-01 Jun-01 Jul-01 Aug-01 Sep-01 Oct-01 Nov-01 Dec-01
29.32 29.76 27.29 27.63 28.70 27.62 26.57 27.31 26.45 22.21 19.67 19.46
Natural gas prices increased dramatically during 2000 and early 2001, from a
NYMEX price of approximately $2.35 per Mcf at year-end 1999, to an average price
of approximately $3.90 per Mcf for 2000, and an average of $4.26 in 2001 (as
compared to a net corporate average price received of $4.12 per Mcf for 2001
before the positive impact of hedging). The biggest fluctuation in natural gas
prices during the three year period was in late 2000 and early 2001 when natural
gas prices were around $10.00 per Mcf for a brief period of time. Throughout the
remainder of 2001 they declined, dropping to a December 31, 2001 year-end price
of $2.57 per Mcf. On a price per BOE basis (before the impact of hedges), our
average commodity prices dropped 12% in 2001 from 2000 levels.
Graph depicting the NYMEX natural gas price listings by month from January 1999
through December 2001:
Jan-99 Feb-99 Mar-99 Apr-99 May-99 Jun-99 Jul-99 Aug-99 Sep-99 Oct-99 Nov-99 Dec-99
1.80 1.81 1.64 1.88 2.35 2.23 2.28 2.62 2.90 2.55 3.06 2.14
Jan-00 Feb-00 Mar-00 Apr-00 May-00 Jun-00 Jul-00 Aug-00 Sep-00 Oct-00 Nov-00 Dec-00
2.36 2.61 2.61 2.88 3.08 4.37 4.36 3.83 4.62 5.29 4.50 6.02
Jan-01 Feb-01 Mar-01 Apr-01 May-01 Jun-01 Jul-01 Aug-01 Sep-01 Oct-01 Nov-01 Dec-01
9.91 6.22 5.03 5.35 4.87 3.73 3.16 3.19 2.34 1.86 3.16 2.28
DEBT. Our total debt level increased from $199.0 million as of December 31, 2000
to $340.9 million (excluding the unamortized issue discount) as of December 31,
2001, primarily as a result of the debt incurred to fund the Matrix and CO2
acquisitions, as our other capital spending was funded with cash flow from
operations. The cash portion of the Matrix acquisition was approximately $100
million and the CO2 acquisition cost us about $42 million.
EX 13-31
During August 2001, we issued an additional $75 million of subordinated debt in
a private placement at 91.371% of face amount, for an effective yield of
10.875%. The notes were issued under a separate indenture but on terms
substantially identical to our existing 9% Senior Subordinated Notes due 2008.
We used the net proceeds of $65.9 million to reduce our existing bank debt.
These notes were subsequently exchanged for a like principal amount of
publically registered notes.
The remaining debt increase during 2001 was bank debt. As of December 31, 2001,
we owed the banks approximately $141 million, with a borrowing base of $220
million. This compares to total bank debt of $74 million a year earlier with a
$150 million borrowing base. In summary, we had approximately the same
availability under our bank credit line at year-end 2001 as we did a year ago.
The increase in the borrowing base in 2001 was a result of the increase in our
proved reserves throughout the year, particularly from the acquired Matrix
properties, partially offset by the higher subordinated debt outstanding.
Our bank credit facility provides for a semi-annual redetermination of our
borrowing base on April 1st and October 1st. In keeping with our fiscal policy
during the last three years, we plan to reserve our credit line primarily for
potential acquisitions. Our next scheduled borrowing base redetermination will
be as of April 1, 2002. We do not anticipate any significant change in our
borrowing base, although the borrowing base can always be reduced at the banks'
discretion, which can be based in part upon external factors over which we have
no control.
Graph depicting the Company's debt to total capitalization (in millions of
dollars):
December 31,
-----------------------------------------------------------
1998 1999 2000 2001
----------- ---------- ------------ -----------
Debt 225.0 152.5 199.0 334.8
Total Capitalization 192.7 224.9 415.2 683.9
CAPITAL SPENDING AND RESOURCES. Our leverage at year-end 2001, as measured on a
debt to cash flow basis, was almost the same as a year earlier. At December 31,
2001, our total debt was $340.9 million (excluding the unamortized issue
discount), approximately 1.8 times our 2001 cash flow from operations (before
the change in other assets and liabilities), essentially the same as the prior
year-end computed on the same basis. However, we were in a rising commodity
price environment at the end of 2000 and just the opposite at the end of 2001,
which means that this debt ratio is likely to increase during 2002. Both oil and
natural gas prices were at long-term average prices as of the end of 2001,
continued to fall during the first month or two of 2002, but were back above
year-end levels by early March 2002.
With the reduced commodity prices, our debt level has risen to around three
times our anticipated 2002 cash flow based on futures prices as of early March
2002. While this projected debt to cash flow ratio is higher than it was in
2001, in our opinion it is not high when compared to our peer group, and we do
not anticipate any problems in the foreseeable future with our debt levels or
liquidity. During the last few years, we have had wide swings in commodity
prices, in response to which we adjust our spending and plans accordingly and
attempt to mitigate some of the price dips with our hedging program. To help
protect our balance sheet in this most recent drop in commodity prices, we have
taken the following steps consistent with our corporate strategy:
EX 13-32
1) We purchased additional natural gas hedges for 2002 after the Enron
bankruptcy that cover approximately 75% of our forecasted natural gas
production, with a price floor of $2.50 per MMBtu. We also have oil hedges in
place that cover approximately 60% of our forecasted 2002 oil production, with a
price floor of $21.00 per Bbl. Therefore, even though prices have continued to
deteriorate during the first part of 2002 and both commodities have dropped, at
least a portion of the time below our price floors, the effect of such drops on
us is limited to the unhedged portion of our production. With our balanced
production mix of oil and natural gas, we also have a type of natural hedge in
that the two commodity prices do not always move in tandem.
2) Our original capital budget for 2002 was approximately $120 million. With the
loss of the Enron hedges, we immediately lowered our budget to approximately $95
million to compensate for the loss of expected revenue from these hedges. While
this capital budget could be slightly higher than our anticipated cash flow for
2002, depending on the price forecast that is used, when coupled with the $9.2
million that we received in February 2002 by selling our claim against Enron, we
will have the ability to complete our 2002 development and exploration plan
without incurring significant additional debt. This is consistent with our
strategy in recent years to generally attempt to match our anticipated cash flow
with our capital spending program (excluding acquisitions). We will also review
our 2002 budget on a quarterly basis and make adjustments if necessary.
3) For the last three years we have reserved our bank credit line for
acquisitions. We plan to continue this strategy. As of March 15, 2002, we had
approximately $74 million available on our credit line. While this amount could
be adjusted at the April 1st redetermination, we do not expect our borrowing
base to change materially, if at all. We continue to pursue acquisitions which,
if accomplished, should be accretive to our operating results. We cannot be
certain that we will identify any suitable acquisitions in the future or that
any such acquisitions will be successful in achieving our desired profitability
objectives. We have a significant inventory of development and exploration
projects in-house, but on a long-term basis we will need further acquisitions to
replace our production. We may also consider the sale of some of our more mature
properties from time to time with the intention of replacing them with
properties that we can further exploit.
Graph depicting development and exploration expenditures vs. cash flow from
operations (in millions of dollars):
Year Ended December 31,
------------------------------------------
1999 2000 2001
------------ ------------ -------------
Development and exploration expenditures $ 34.5 $ 73.7 $ 170.1
Cash flow from operations (1) 31.6 111.6 186.8
(1)Excluding the net change in non-cash working capital balances.
Our capital budget for 2002, excluding acquisitions, is currently set at $95
million. Approximately 25% of the projected 2002 expenditures are targeted for
our East Mississippi properties (primarily Heidelberg Field), 25% for Little
Creek and Mallalieu Fields and other CO2 floods, 25% for the recently acquired
Thornwell Field and other fields in onshore Louisiana, 10% for offshore
activities, and the balance for various other fields, capitalized overhead,
land, seismic, and discretionary expenditures. Of the total budget,
approximately 12% is related to exploratory drilling, seismic or other
exploratory expenditures. We will continue to review our budget each quarter and
make
EX 13-33
adjustments for changes in commodity prices, oilfield service and equipment
costs, and our drilling results. With the recent decline in commodity prices, we
are experiencing some declines in oilfield service and equipment costs, which
may allow us to undertake more projects than we originally anticipated for the
same dollars. In contrast, during 2000 and 2001, we were faced with rising
oilfield service and equipment costs which required us to increase our budget
several times solely for cost inflation.
At our current capital spending level and the current level of commodity prices,
we expect our production to average approximately 35,250 BOE/d in 2002, a 13%
increase over our 2001 average, but only a slight increase over the rate of
production during the fourth quarter of 2001. For 2002, 15% to 20% of our
capital expenditures are allocated to new tertiary recovery operations that are
not expected to respond until late 2002. We believe that the balance of our
capital expenditures of $75 million to $80 million is sufficient to generate
modest production growth throughout the year.
We have no significant off balance sheet arrangement, special purpose entities,
financing partnerships or guarantees, nor any debt or equity triggers based upon
our stock or commodity prices. Our bank debt is not due until December 31, 2003,
a date we expect to extend, and our subordinated debt is due in March 2008. Our
only other obligations that are not currently recorded on our balance sheet are
our operating leases, which primarily relate to our office space and minor
equipment leases, and various spending obligations for development and
exploratory expenditures arising from purchase agreements or other transactions
common to our industry. Our operating lease obligations total $12.5 million in
the aggregate and $1.7 million for 2002. Our capital spending obligations total
approximately $13.6 million over the next four years, none of which is required
in 2002. 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 will occur during the
subsequent six months and are part of our annual budget process. We also have an
obligation to deliver approximately 90 Bcf of CO2 to our industrial customers.
Based on the size of our proven CO2 reserves and our current production
capabilities, we are confident we can meet these delivery obligations. At
December 31, 2001, we had a total of $370,000 outstanding in letters of credit.
We do not have any material transactions with related parties.
Graph depicting capital expenditures (in millions of dollars):
Year Ended December 31,
------------------------------------------
1999 2000 2001
------------ ------------ ------------
Acquisitions $ 20.5 $ 60.3 $ 157.1
Development and exploration expenditures 34.5 73.7 170.1
SOURCES AND USES OF FUNDS. 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.
EX 13-34
During 2000, we spent approximately $73.7 million on exploration and development
activities and approximately $60.3 million on acquisitions. These exploration
and development expenditures included approximately $37.8 million spent on
drilling, $8.5 million of geological, geophysical and acreage expenditures and
$27.4 million spent on facilities and recompletion costs. We funded these
exploration and development expenditures with cash flow from operations and
funded our acquisitions with cash flow and net incremental bank debt of $46.5
million.
During 1999, we spent approximately $34.5 million on exploration and development
activities and approximately $20.5 million on acquisitions. Our exploration and
development expenditures included approximately $8.6 million spent on drilling,
$5.7 million of geological, geophysical and acreage expenditures and $20.2
million spent on facilities and recompletion costs. These exploration and
development expenditures were funded primarily by our cash flow from operations
and the acquisitions were funded with both cash flow and incremental bank debt
of $17.9 million.
RESULTS OF OPERATIONS
Operating Income
Cash flow from operations has improved each year since 1998 because of the
improved commodity prices and higher production levels. Net income has generally
tracked cash flow if you adjust for certain non- recurring entries that affect
the bottom line, such as the reversal of the valuation allowance on our deferred
tax assets in 2000 and the write-off of the Enron hedges in 2001. Each of these
factors is more fully described below.
Year Ended December 31,
- -----------------------------------------------------------------------------------------------------------
Amounts in Thousands Except Per Share Amounts 2001 2000 1999
- -----------------------------------------------------------------------------------------------------------
Net income $ 56,550 $ 142,227 $ 4,614
Net income per common share:
Basic $ 1.15 $ 3.10 $ 0.12
Diluted 1.12 3.07 0.12
- -----------------------------------------------------------------------------------------------------------
Cash flow from operations (1) $ 186,801 $ 111,555 $ 31,619
- -----------------------------------------------------------------------------------------------------------
(1) Represents cash flow provided by operations, exclusive of the net change in
non-cash working capital balances.
Graph depicting cash flow from operations, excluding the net change in non-cash
working capital balances, by quarter (in millions of dollars):
1999 2000 2001
Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4
$2.5 $6.6 $9.5 $13.0 $19.6 $21.3 $27.5 $43.2 $55.0 $45.2 $48.7 $37.9
EX 13-35
During 2001, we set company records for production, revenue, cash flow and
pre-tax net income. Certain of our operating statistics are set forth in the
following chart.
Year Ended December 31,
- -----------------------------------------------------------------------------------------------------------
2001 2000 1999
- -----------------------------------------------------------------------------------------------------------
AVERAGE DAILY PRODUCTION VOLUME
Bbls 16,978 15,219 12,090
Mcf 85,238 37,078 27,948
BOE(1) 31,185 21,399 16,748
- -----------------------------------------------------------------------------------------------------------
OPERATING REVENUES AND EXPENSES (THOUSANDS)
Oil sales $ 132,219 $ 144,230 $ 66,330
Natural gas sales 128,179 60,406 24,661
Gain (loss) on settlements of derivative contracts (2) 18,654 (25,264) (9,416)
- -----------------------------------------------------------------------------------------------------------
Total oil and natural gas revenues 279,052 179,372 81,575
- -----------------------------------------------------------------------------------------------------------
Lease operating costs 55,049 38,676 26,029
Production taxes and marketing expenses 10,963 8,051 3,662
- -----------------------------------------------------------------------------------------------------------
Total production expenses 66,012 46,727 29,691
- -----------------------------------------------------------------------------------------------------------
Production netback $ 213,040 $ 132,645 $ 51,884
===========================================================================================================
UNIT PRICES-INCLUDING IMPACT OF HEDGES(2)
Oil price per Bbl $ 21.65 $ 23.50 $ 13.08
Gas price per Mcf 4.66 3.57 2.34
UNIT PRICES-EXCLUDING IMPACT OF HEDGES(2)
Oil price per Bbl 21.34 25.89 15.03
Gas price per Mcf 4.12 4.45 2.42
- -----------------------------------------------------------------------------------------------------------
NETBACK PER BOE (1)
Oil and natural gas revenues $ 24.52 $ 22.90 $ 13.34
- -----------------------------------------------------------------------------------------------------------
Lease operating costs 4.84 4.94 4.25
Production taxes and marketing expenses 0.96 1.02 0.60
- -----------------------------------------------------------------------------------------------------------
Total production expenses $ 5.80 $ 5.96 $ 4.85
============================================================================================================
(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.
Production. From the first quarter of 1999 through the third quarter of 2001,
our average daily production increased each quarter, with production in the
fourth quarter of 2001 being only slightly less than our third quarter peak.
Prior to 1999, we had severely curtailed our development and exploration program
due to the historically low oil prices in 1998. As oil prices began to gradually
increase in early 1999, we correspondingly resumed our development program. The
production increases since that time have resulted from a combination of
acquisitions, development, exploration and exploitation activities. From time to
time, we have also experienced significant production increases from our
waterflood and tertiary recovery operations. These production responses
generally do not correspond directly with our related capital spending, as it
typically takes six to twelve months to see any production response after the
injection of water or carbon dioxide begins.
EX 13-36
Graph depicting production by quarter (average MBOE per day):
1999 2000 2001
-----------------------------------------------------------------------------------------------------
Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4
-----------------------------------------------------------------------------------------------------
Oil 10.3 11.5 12.5 14.0 14.4 14.8 15.4 16.3 16.3 16.4 16.9 18.3
Natural Gas 5.1 4.5 4.5 4.5 4.7 4.8 5.1 10.0 10.3 11.5 18.2 16.7
-------------------------------------------------------------------------------------------------------
Total 15.4 16.0 17.0 18.5 19.1 19.6 20.5 26.3 26.6 27.9 35.1 35.0
Since our December 1997 $202 million acquisition of Heidelberg Field from
Chevron, our significant acquisitions of oil and natural gas properties have
been the $4.9 million acquisition of King Bee Field in May 1999, the $12.3
million acquisition of Little Creek Field in August 1999, the $56.5 million
acquisitions of Thornwell, Porte Barre and Iberia Fields in the fourth quarter
of 2000, the $4.0 million acquisition of Mallalieu Field in May 2001 and the
$158.5 million corporate acquisition of Matrix in July 2001 (see "Matrix
Acquisition" above).
At the time of its acquisition in December 1997, Heidelberg Field was producing
approximately 2,800 BOE/d. Production under our ownership has subsequently
averaged 3,760 BOE/d, 5,708 BOE/d, 7,310 BOE/d, and 7,908 BOE/d for 1998, 1999,
2000 and 2001. During 1998, our primary emphasis was implementation of the
field's largest waterflood unit, the East Heidelberg Waterflood Unit, plus other
developmental drilling. During 1999, we began to see response from our
waterflood efforts. We added other waterflood units during 1999 and 2000 and
also expanded our drilling for natural gas at Heidelberg in the Selma Chalk
formation during the second half of 1999. As a result, the natural gas
production at Heidelberg has increased from 0.5 MMcf/d in 1998 to 1.0 MMcf/d in
1999, 3.8 MMcf/d in 2000 and 7.4 MMcf/d in 2001. We believe that our production
at Heidelberg has peaked, but it should remain relatively stable for another
year or two before there are any significant declines.
Production at King Bee Field averaged 415 BOE/d for 1999 (as we owned the field
for only seven months of the year), 738 BOE/d in 2000 and 813 BOE/d in 2001.
Production at Little Creek Field has also increased since we acquired it in
August 1999. At the time of acquisition, Little Creek was producing
approximately 1,350 BOE/d, with a 1999 annual average production rate of 587
BOE/d, due to the partial year ownership. Since acquiring the field, we have
completed Phase III of the CO2 flood and implemented Phases IV and V, resulting
in gradual production increases. Production from Little Creek Field averaged
2,018 BOE/d for 2000 and 2,441 BOE/d for 2001, averaging 3,052 BOE/d during the
fourth quarter of 2001. We are continuing to expand our tertiary recovery
operations at Little Creek and anticipate that production will continue to
increase at this field throughout 2002 and perhaps into 2003.
During the fourth quarter of 2000, we completed the $56.5 million acquisition of
the Thornwell, Porte Barre and Iberia Fields located in Southwestern Louisiana,
where the wells principally produce natural gas. The largest of these fields,
Thornwell Field, contributed 1,053 BOE/d to our average production rate for 2000
and approximately 4,190 BOE/d to our 2000 fourth quarter average production
volumes. Even though Thornwell Field had a relatively short expected life of
approximately
EX 13-37
three years, based on initial estimates of its proven reserves, and thus was
expected to rapidly decline, through our development and exploratory drilling
program, the field's production increased in 2001, with an average rate of 4,275
BOE/d and an exit rate in the fourth quarter of 2001 of 4,902 BOE/d.
In total, our production increased 9,786 BOE/d, or 46%, between 2000 and 2001.
The most significant factor in this increase was the purchase of Matrix in early
July 2001. Production from the Matrix properties averaged approximately 7,000
BOE/d during the six months that we owned Matrix, contributing 3,524 BOE/d to
our annual average, or approximately 36% of the increase year-over-year. The
Matrix properties were producing approximately 6,667 BOE/d at the time of
acquisition. Other significant increases are the changes outlined above at
Heidelberg (598 BOE/d), King Bee (75 BOE/d), Little Creek (423 BOE/d) and
Thornwell Fields (3,222 BOE/d). Another significant increase in production came
from development and exploration drilling at Lirette Field, which increased 809
BOE/d in 2001.
REVENUE. Our oil and natural gas revenues more than doubled between 1999 and
2000, and further increased an additional 56% in 2001. Between 1999 and 2000,
revenues increased 120% as both commodity prices and production increased
substantially, partially offset by cash payments on our hedges. The overall
increase in production volumes contributed $25.5 million or 26% of the increase,
and the increase in commodity prices contributed $88.1 million or 90% of the
increase, partially offset by $15.8 million in incremental cash payments we made
on hedges (or a negative 16%). Between 2000 and 2001, revenues increased 56%,
primarily from higher production levels. The overall increase in production
volumes contributed $92.8 million or 93% of the increase, and the incremental
cash receipts from hedges contributed $43.9 million or 44% of the increase,
partially offset by an overall decrease of $37.0 million in commodity prices (or
a negative 37%).
During 1999, we paid out $8.6 million for losses on our oil hedges ($1.95 per
Bbl) and $126,000 for losses on our natural gas hedges, and we expensed $672,000
in 1999 that we paid to buy out a portion of our natural gas hedges for the next
year. During 2000, we paid out $13.3 million ($2.39 per Bbl) on our oil hedges
and $11.9 million ($0.88 per Mcf) on our natural gas hedges. In contrast, during
2001, we collected $1.9 million ($0.31 per Bbl) on our oil hedges and $16.7
million ($0.54 per Mcf) on our natural gas hedges. See "Market Risk Management"
for a further discussion of our hedging activities.
OPERATING EXPENSES. Between 1999 and 2000, our oil and natural gas lease
operating expenses, including production taxes and marketing expenses, increased
23% on a per BOE basis, primarily due to an increase in production taxes related
to higher product prices, the addition of Little Creek Field during the third
quarter of 1999 (which has higher operating costs per barrel due to tertiary
recovery operations), and overall increases in the number of wells and in the
cost of equipment and services.
Oil and natural gas lease operating expenses decreased 2% on a per BOE basis
between 2000 and 2001, as a result of the addition of the Matrix natural gas
properties in July 2001 and savings resulting from our ownership of CO2
purchased in February 2001. These savings were partially offset by overall
higher service and equipment costs in the industry during the year. The Matrix
acquisition added
EX 13-38
predominately natural gas, which typically has a lower per unit operating cost
than oil properties. Operating expenses per BOE averaged $4.06 for the Matrix
properties during the six months of ownership, which was less than our overall
average of $4.84 for 2001.
We reduced operating expenses by approximately $2.6 million during 2001 because
of our CO2 acquisition in February 2001. Prior to the acquisition, we were
paying approximately $0.25 per thousand cubic feet for CO2 that we used in our
tertiary recovery operations at Little Creek Field. Now that we own the CO2, our
cost is now our proportional share of the operating expenses of the CO2 field
and pipeline, allocated based on the volumes of CO2 sold to commercial users and
used for our own account. During 2001, this translated into an average operating
cost of approximately $0.07 for each thousand cubic feet of CO2 produced, a
savings of approximately $0.18 per thousand cubic feet of CO2. Our estimated
total "all-in" cost per thousand cubic feet of CO2 is approximately $0.15 per
thousand cubic feet after inclusion of the non-cash depreciation and
amortization expense.
Operating costs at Little Creek Field averaged $12.45, $11.89 and $9.80 per BOE
for 1999, 2000 and 2001 respectively. These costs per barrel are almost double
the average for our operating costs on our other properties. While we were able
to lower costs in 2001 because of our CO2 acquisition in February, we expect
operating expenses to remain relatively high on this field, particularly in the
near future, as we are initiating additional phases of tertiary recovery. Over
the life of the property, we anticipate that operating expenses will average a
bit less than the current levels, as we expect production to increase and we
will ultimately reduce the amount of CO2 that we inject. Our other tertiary
recovery operations are also expected to have a higher than average operating
cost. However, even though operating expenses for these floods are higher than
average, since the oil production from these fields is light, sweet oil that
commands a premium price, the net operating income from these tertiary recovery
operations is almost the same as our net operating income from our biggest
field, Heidelberg Field.
Production taxes and marketing expenses decreased $0.06 per BOE (6%) in 2001 due
to slightly lower commodity prices and the addition of the Matrix properties, a
portion of which are tax exempt due to their offshore location, partially offset
by higher marketing expenses on the offshore properties primarily relating to
incremental processing and transportation costs.
CO2 OPERATIONS: In addition to using CO2 for our own account, we sell CO2 to
third party industrial users under long-term contracts. Our net operating cash
flow from these sales was $4.3 million during 2001. Our average CO2 production
during 2001 was approximately 84 million cubic feet per day, of which
approximately 53% was used in our tertiary recovery operations and the balance
sold to other third parties for industrial use.
General and Administrative Expenses
We lowered our general and administrative ("G&A") expenses on a per BOE basis in
both 2000 and 2001. Our gross G&A expense increased each year, but with the
significant production increases, G&A expense on a per BOE basis declined.
EX 13-39
Year Ended December 31,
- -------------------------------------------------------------------------------------------------------------
Amounts in Thousands Except Per BOE and Employee Data 2001 2000 1999
- -------------------------------------------------------------------------------------------------------------
Gross G&A expense $ 33,727 $ 24,941 $ 20,119
State franchise taxes 877 467 346
Operator overhead charges (20,328) (13,684) (10,278)
Capitalized exploration expense (4,102) (3,202) (2,812)
- -------------------------------------------------------------------------------------------------------------
Net G&A expense $ 10,174 $ 8,522 $ 7,375
=============================================================================================================
Average G&A expense per BOE $ 0.89 $ 1.09 $ 1.21
Employees as of December 31 320 242 220
- -------------------------------------------------------------------------------------------------------------
Our overall activity level has increased each year since 1998. As a result, we
have had general increases in consultant fees, hired additional personnel, moved
to a new office building in 1999, and have given salary increases and bonuses
each year. The bonuses, as authorized by our board of directors, were at the
midpoint of the bonus range in 1999, but were at the upper end of the range in
2000 and 2001, based primarily on our overall financial and operating results.
Partially offsetting the overall increase in gross G&A costs are the increases
in operator overhead charges and capitalized exploration expenses. The
respective well operating agreements allow us, when we are the operator, to
charge a specified overhead rate during the drilling phase and to charge a
monthly fixed overhead rate for each producing well. As a result of the general
escalation in activity each year and the addition of more operated wells from
our recent acquisitions, this recovery of G&A increased from $10.3 million in
1999 to $13.7 million in 2000 and to $20.3 million in 2001. As a result, net G&A
expense increased only 16% in 2000 and 19% in 2001, even though gross G&A
expense increased 24% and 35% respectively.
On a per BOE basis, G&A costs decreased 10% in 2000 and an additional 18% in
2001 due to a higher percentage increase in production than in net G&A expense.
Interest and Financing Expenses
Year Ended December 31,
- ---------------------------------------------------------------------------------------------------------
Amounts in Thousands Except Per BOE Data 2001 2000 1999
- ---------------------------------------------------------------------------------------------------------
Interest expense $ 22,335 $ 15,255 $ 15,795
Non-cash interest expense (1,665) (945) (834)
- ---------------------------------------------------------------------------------------------------------
Cash interest expense 20,670 14,310 14,961
Interest and other income (849) (2,279) (1,415)
- ---------------------------------------------------------------------------------------------------------
Net cash interest expense $ 19,821 $ 12,031 $ 13,546
=========================================================================================================
Average net cash interest expense per BOE $ 1.74 $ 1.54 $ 2.22
Average debt outstanding $ 264,792 $ 160,884 $ 172,010
Average interest rate (1) 7.8% 8.9% 8.7%
- ---------------------------------------------------------------------------------------------------------
(1) Includes commitment fees but excludes amortization of debt issue costs.
We began 1999 with $225 million of total debt and further increased this to
$234.6 million by the end of the first quarter. This debt was reduced by $100
million in April 1999 with the proceeds from the sale of common shares to
affiliates of the Texas Pacific Group. We borrowed an additional $17.9 million
during the second and third quarters to fund acquisitions, bringing total bank
debt to $27.5 million and total outstanding debt to $152.5 million as of
December 31, 1999.
EX 13-40
During 2000, we made small reductions in our bank debt during the first three
quarters, reducing total debt outstanding by $6.5 million during the first nine
months. During the fourth quarter of 2000, we borrowed $61 million to fund
property acquisitions and related hedges, but repaid $8.0 million from cash
flow, ending the year with $199 million of long-term debt outstanding. The net
effect was a 6% average lower level of debt in 2000 as compared to 1999,
although the debt was at slightly higher average interest rates. During 2000 we
generated $864,000 of other income, which also helped reduce our net cash
interest expense. Overall, we had an 11% reduction in net cash interest expense
between 1999 and 2000 with a 31% reduction on a BOE basis due to the increase in
production levels during 2000.
During 2001, we had total bank borrowings of $146.0 million, primarily to fund
our acquisition of Matrix ($100.0 million) and the CO2 acquisition ($42.0
million). We repaid a total of $79.1 million during the year, of which (i) $13.0
million related to excess cash flow generated from operations early in the year
given the unusually high natural gas prices and (ii) $65.9 million represented
the net proceeds of our issuance of Series B 9% Senior Subordinated Notes due
2008 in August 2001. These notes were issued at a discount with an estimated
yield to maturity of 10 7/8%. Our total outstanding debt increased from $199
million as of December 31, 2000, to $340.9 million as of December 31, 2001
(excluding the unamortized issue discount), a 71% increase. Our average interest
rate decreased in 2001 due to an overall drop in interest rates, even though we
issued an additional $75 million of subordinated debt in August at a relatively
high interest rate. Overall, we had a 65% increase in net cash interest expense
in 2001, but only a 13% increase on a BOE basis due to the overall production
increases.
Depletion, Depreciation and Site Restoration
Depletion, depreciation and amortization ("DD&A") was at its lowest rate on a
per BOE basis in our history in 1999 as a result of the full cost pool
writedowns in 1998. Since that time, our DD&A rate has increased each year as
our overall finding cost has been greater than the abnormally low rate in 1999,
particularly the finding cost of our recent acquisitions.
Year Ended December 31,
- --------------------------------------------------------------------------------------------------------
Amounts in Thousands Except Per BOE Data 2001 2000 1999
- --------------------------------------------------------------------------------------------------------
Depletion and depreciation $ 66,402 $ 34,530 $ 24,277
Depreciation of CO2 assets 1,572 - -
Site restoration provision 1,946 560 384
Depreciation of other fixed assets 1,425 1,124 854
- --------------------------------------------------------------------------------------------------------
Total DD&A $ 71,345 $ 36,214 $ 25,515
========================================================================================================
Average DD&A cost per BOE $ 6.27 $ 4.62 $ 4.17
========================================================================================================
The NYMEX oil price used for our reserve report increased slightly from $25.60
per Bbl as of December 31, 1999, to $26.80 per Bbl as of December 31, 2000,
although natural gas prices increased almost fivefold, from $2.12 per Mcf in
1999 to $9.78 per Mcf in 2000. However, since the economic lives of most of our
natural gas properties are generally not as sensitive to changes in commodity
price, this change in price only increased our proved reserve quantities by
730,000 BOE between the two respective year-ends. During 2000, we also added
34.9 MMBOEs from acquisitions, other development work, and upward revisions.
Consequently, our total proved reserve quantities increased 45% from 60.2 MMBOE
as of December 31, 1999, to 87.4 MMBOE as of December 31, 2000.
EX 13-41
Graph depicting our proved reserves (MMBOE):
December 31,
------------------------------------------
1999 2000 2001
------------ ------------ ------------
Oil 51.8 70.7 76.5
Natural Gas 8.4 16.7 33.0
------------ ------------ ------------
Total MMBOE 60.2 87.4 109.5
------------ ------------ ------------
Between 2000 and 2001, the NYMEX oil price used for our reserve report decreased
from $26.80 per Bbl as of December 31, 2000, to $19.84 per Bbl as of December
31, 2001. Natural gas prices dropped almost fourfold, from $9.78 per Mcf in 2000
to $2.57 per Mcf in 2001. These declines in commodity prices, particularly oil,
reduced the economic lives of our properties and reduced reserve quantities by
8.3 MMBOE. Overall, we showed a 25% increase in reserve quantities during 2001,
as we added 41.8 MMBOEs from acquisitions, other development work, and upward
revisions. Our total proved reserve quantities increased from 87.4 MMBOE as of
December 31, 2000, to 109.5 MMBOE as of December 31, 2001.
Our DD&A rate increase from $4.17 per BOE in 1999 to $4.62 per BOE in 2000 was
primarily a result of our property acquisition in the fourth quarter of 2000 at
a higher than average cost per BOE. Because of the high commodity price
environment, our average acquisition cost in 2000 was $11.94 per BOE,
significantly higher than our average historical acquisition or finding cost per
BOE and higher than the prior year's DD&A rate per BOE. Even though the high
cost per BOE of these acquisitions increased our DD&A rate, thus far we have
made a good rate of return on these properties. As of December 31, 2001, all but
$5.1 million of the acquisition cost had been recovered (excluding the income
from related natural gas hedges during the year), and these properties have a
PV10 value as of December 31, 2001 of $30.3 million.
Similar to 2000, in 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 also had a higher than average cost per
BOE ($13.28 per BOE including unevaluated property costs) because of the high
commodity price environment. We attempted to protect this acquisition with the
purchase of natural gas price floors through 2003; however, the hedges for 2002
and 2003 were purchased from Enron, which declared bankruptcy in December 2001
(see "Market Risk Management" below for a discussion about these floors). Even
so, we have increased our reserve quantities from this acquisition since July
2001 by 35% (or 46% by adding back production) and we still have most of the
probable and possible reserves to exploit. Although our PV10 value at December
31, 2001 is approximately $31.9 million less than our net unrecovered cost, we
believe that this acquisition will provide us a reasonable rate of return if
natural gas prices recover somewhat and we are able to further exploit these
properties.
We provide for the estimated future costs of well abandonment and site
reclamation, net of any anticipated salvage, on a unit-of-production basis. This
provision is included in DD&A expense and has increased each year along with the
general increase in the number of our properties, especially the acquisition of
our offshore properties.
EX 13-42
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 1999, 2000 or 2001. However, as of December 31, 2001 the excess
value under our ceiling test was quite small, and thus it is possible that we
could be required to writedown our full cost pool in forthcoming periods if
commodity prices do not recover or if they deteriorate.
Income Taxes
For the year ended December 31, 1999, a normal deferred tax provision would have
resulted in a deferred income tax provision of $1.7 million. However, we
utilized a portion of our deferred tax asset and its corresponding valuation
allowance to offset this provision, leaving a net deferred tax asset as of
December 31, 1999 of $95.1 million. At that time we believed that it was more
likely than not that future taxable income would not be sufficient to realize
the benefit from our deferred tax assets, so the deferred tax asset was left
fully impaired, as it was at the prior year-end.
For the year ended December 31, 2000, we had taxable income of $27.6 million,
but were able to offset this income with our tax net operating loss
carryforwards ("NOLs"). We did incur $558,000 of current income tax expense
during 2000 which related to alternative minimum taxes that could not be offset
by NOLs. For the year ended December 31, 2000, a normal tax provision would have
resulted in income tax expense of $27.7 million. However, we utilized a portion
of our deferred tax assets and its corresponding valuation allowance to offset
this provision. We also reevaluated the remaining balance of $67.9 million
relating to our net deferred tax asset as of December 31, 2000. We concluded
that it is more likely than not that there will be sufficient future taxable
income to be able to realize the tax benefits of our deferred tax asset,
resulting in a deferred tax benefit of $67.9 million and a net deferred tax
asset balance as of December 31, 2001 of $67.9 million, none of which was
impaired.
With the adjustment to deferred taxes in 2000, we began booking a normal tax
provision in 2001. In 2001, we began to recognize the amount of enhanced oil
recovery credits that we had earned to date from our tertiary projects which
totaled $5.3 million at year-end 2001. As a result of these credits, our
effective tax provision for 2001 was lowered from 37% to 30.5%. Most of this
provision was deferred as we were able to offset our taxable income with our
NOLs. The current portion of the tax provision relates to alternative minimum
taxes that cannot be offset by NOLs.
Year Ended December 31,
- --------------------------------------------------------------------------------------------------------
Amounts in Thousands Except Per Unit Amounts 2001 2000 1999
- --------------------------------------------------------------------------------------------------------
Current income tax expense $ 640 $ 558 $ -
Deferred income tax provision (benefit) 24,184 (67,852) -
- --------------------------------------------------------------------------------------------------------
Total income tax provision (benefit) $ 24,824 $ (67,294) $ -
========================================================================================================
Average income tax provision (benefit) per BOE $ 2.18 $ (8.59) $ -
Net operating loss carryforwards 91,220 112,690 139,859
========================================================================================================
Net deferred tax asset (liability) $ (17,433) $ 67,852 $ 95,137
Valuation allowance - - (95,137)
- --------------------------------------------------------------------------------------------------------
Total net deferred tax asset (liability) $ (17,433) $ 67,852 $ -
========================================================================================================
EX 13-43
Results of Operations on a BOE Basis
The following table summarizes the cash flow, DD&A and results of operations on
a BOE basis for the comparative periods. Each of the individual components is
discussed above.
Year Ended December 31,
- --------------------------------------------------------------------------------------------------------
Per BOE Data 2001 2000 1999
- --------------------------------------------------------------------------------------------------------
Oil and natural gas revenues $22.88 $26.13 $14.88
Gain (loss) on settlements of derivative contracts 1.64 (3.23) (1.54)
Lease operating costs (4.84) (4.94) (4.25)
Production taxes and marketing expense (0.96) (1.02) (0.60)
- --------------------------------------------------------------------------------------------------------
Production netback 18.72 16.94 8.49
Operating cash flow from CO2 operations 0.38 - -
General and administrative expense (0.89) (1.09) (1.21)
Net cash interest expense (1.74) (1.54) (2.22)
Current income taxes and other (0.06) (0.07) 0.11
- --------------------------------------------------------------------------------------------------------
Cash flow from operations (1) 16.41 14.24 5.17
DD&A (6.27) (4.62) (4.17)
Deferred income taxes (2.12) 8.66 -
Amortization of derivative contracts and other
non-cash hedging adjustments (2.90) - -
Other non-cash items (0.15) (0.12) (0.25)
- --------------------------------------------------------------------------------------------------------
Net income $ 4.97 $18.16 $ 0.75
========================================================================================================
(1) Represents cash flow provided by operations, exclusive of the net change in
non-cash working capital balances.
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. We do not hold or issue derivative financial
instruments for trading purposes.
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 Total Fair
Amounts in Thousands 2002 2003 2004-2007 2008 Value Value
- -----------------------------------------------------------------------------------------------------------------------
Variable rate debt:
Bank debt $ - $ 140,870 $ - $ - $ 140,870 $ 140,870
The average interest rate on the bank debt at December 31, 2001 is 4.2%.
Fixed rate debt:
Subordinated debt $ - $ - $ - $ 200,000 $ 200,000 $ 188,000
The interest rate on the subordinated debt is a fixed rate of 9%.
- -----------------------------------------------------------------------------------------------------------------------
EX 13-44
We enter into various financial contracts to hedge our exposure to commodity
price risk associated with anticipated future oil and natural gas production.
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 budget without incurring significant debt.
When we make an acquisition, we attempt to hedge 75% to 100% of the forecasted
production for the next year or two following the acquisition in order to help
provide us with a minimum return on our investment. Most of our recent hedging
activity has been the purchase of puts or price floors; however, we will also
use instruments like collars if we think that the ceiling prices are high enough
that we are not giving up a significant portion of the potential upside. 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.
Oil Hedges Historical Data
During March and April 1999, we entered into two no-cost contracts to hedge a
portion of our oil production. The first contract was a fixed price swap for
3,000 Bbls/d from April through December 1999 at a price of $14.24 per Bbl. The
second contract was a collar to hedge 3,000 Bbls/d from May 1999 through
December 2000 with a floor price of $14.00 per Bbl and a ceiling price of $18.05
per Bbl. During 1999, we paid out approximately $8.6 million on these contracts
and during 2000, we paid out $13.3 million relating to these oil collars.
During 2000, we purchased a $22.00 price floor on our 2001 production covering
12,800 Bbls/d at an aggregate cost of $1.8 million. This contract covered
approximately 75% of our anticipated 2001 oil production, excluding any
anticipated production from acquisitions. During 2001, we collected $1.9 million
on this price floor.
During July 2001, we acquired a $21.00 price floor on 10,000 Bbls/d for 2002
production at an aggregate cost of approximately $4.7 million. This price floor
covers approximately 60% of our anticipated oil production for 2002.
Natural Gas Hedges Historical Data
As of January 1, 1999, we had no-cost financial contracts ("collars") in place
that hedged a total of 40 MMcf/d through August 1999 and 30 MMcf/d thereafter
through December 2000. The first set of contracts had a weighted average ceiling
price of approximately $2.95 per MMBtu and the second set of contracts had a
ceiling price of $2.58 per MMBtu. Both contracts had a price floor of $1.90 per
MMBtu. During 1999, we paid out a net of $0.8 million on these contracts,
including $0.7 million paid to retire a portion of the hedge. During 2000, we
paid out $11.9 million relating to these same natural gas collars.
During 2000, we purchased a $2.80 price floor on our 2001 production covering
37,500 MMBtu/d at an aggregate cost of $0.8 million. This contract covered
approximately 75% of our anticipated 2001 natural gas production, excluding any
anticipated production from acquisitions. During 2001, we collected $1.8 million
on this price floor.
EX 13-45
At the same time that we acquired Thornwell Field, we purchased price floors for
these predominately natural gas properties that we acquired in the fourth
quarter of 2000. The price floors covered nearly all of the anticipated proven
natural gas production from these properties for 2001 and 2002. These floors
cost $2.5 million with varying volumes and price floors each quarter for 2001
and 2002. During 2001, we collected $2.2 million from these price floors.
For the Matrix properties we acquired in July 2001 (see also "Matrix
Acquisition" above), we attempted to protect our investment with the purchase of
price floors covering nearly all of the forecasted proven natural gas production
through December 2003, with a minimum price of $4.25 per MMBtu for July 2001
through December 2002 and $3.75 per MMBtu for all of 2003, at a total cost of
$18.0 million. Subsequent to the acquisition, natural gas prices began to
decline and we were paid approximately $12.7 million on these price floors
during 2001. Unfortunately, the price floors relating to 2002 and 2003 were
purchased from Enron, which filed bankruptcy in December 2001. We sold our
bankruptcy claim against Enron in February 2002 for approximately $9.2 million.
In total, we collected approximately $21.9 million from our price floors
relating to the Matrix acquisition, a net cash gain of approximately $3.9
million, although we have suffered an opportunity loss in light of the drop in
natural gas prices since the date of acquisition and the loss of our 2002 and
2003 hedges.
When Enron filed for bankruptcy during the fourth quarter of 2001 these Enron
hedges ceased to qualify for hedge accounting treatment. Therefore, as required
by Financial Accounting Standards No. 133, the accounting treatment changed at
that point in time. The result is that any future changes in the current market
value of these assets must be reflected in our income statement and any
remaining other comprehensive income (part of equity) left at the time of the
accounting change must be amortized over the original expected life of the
hedges. To adjust the Enron hedges down to the current market value, which we
determined to be the amount that we sold the claims for in February 2002, we
took a pre-tax write down of $24.4 million in the fourth quarter of 2001. The
other comprehensive income previously recorded as part of the mark-to-market
value adjustment each quarter remained to be amortized over 2002 and 2003, the
periods during which these hedges would have expired. The result is that we will
have pre-tax income attributable to these Enron hedges during 2002 of
approximately $13.4 million and pre-tax income during 2003 of approximately $5.1
million as we reverse the September 30, 2001 balance of other comprehensive
income relating to these hedges. The three year total pre-tax net loss will be
approximately $5.9 million, which approximates the difference between the amount
collected and paid for the Enron portion of the Matrix price floors.
Subsequent to the Enron bankruptcy, we purchased additional hedges to protect
against any further deterioration in natural gas prices. These have a floor
price of $2.50 per MMBtu and an average ceiling price of around $4.15 per MMBtu
and cover not only the anticipated gas production from the Matrix properties,
but a substantial portion of our other natural gas production as well. Overall,
these hedges, which were purchased from four different financial institutions,
cover approximately 75% of our forecasted total 2002 natural gas production.
Summary
During 1999, we paid out $8.6 million for losses on our oil hedges ($1.95 per
Bbl) and $126,000 for losses on our natural gas hedges, plus we expensed
$672,000 in 1999 that we paid to buy out a portion of our natural gas hedges for
the next year. During 2000, we paid out $13.3 million ($2.39
EX 13-46
per Bbl) on our oil hedges and $11.9 million ($0.88 per Mcf) on our natural gas
hedges. In contrast, during 2001, we collected $1.9 million ($0.31 per Bbl) on
our oil hedges and $16.7 million ($0.54 per Mcf) on our natural gas hedges.
Hedges as of December 31, 2001
The following table lists all of our individual hedges in place as of December
31, 2001.
Volume Floor Volume Floor Ceiling
Period Per Day Price Period Per Day Price Price
- -------------------------------------------- -------------------------------------------------------
Oil Price Floors (Bbls/d): Gas Price Collars (MMBtu/d):
2002 10,000 $21.00 2002 20,000 $2.50 $4.10
2002 20,000 $2.50 $4.10
2002 25,000 $2.50 $4.20
Gas Price Floors (MMBtu/d): 2002 25,000 $2.50 $4.17
Q1 -2002 5,269 $3.65
Q2 -2002 3,775 $3.40
Q3 -2002 2,873 $3.38
Q4 -2002 2,135 $3.38
In February 2002 we acquired no-cost collars covering 70 MMcf/d during calendar
2003 with a floor price of $2.75 per MMBtu and a weighted average ceiling price
of $4.025 per MMBtu. Although we have not completed our forecast for 2003, we
expect that these hedges will cover between 50% and 75% of our anticipated 2003
natural gas production.
Including the Enron hedges discussed above, at December 31, 2001, the fair value
of our derivative contracts was approximately $23.5 million, an increase of
approximately $18.4 million over the $5.1 million recorded as of December 31,
2000, which represented the cost of hedges in existence at that time before the
adoption of SFAS No. 133. The increase is due to both additional funds spent in
2001 to purchase hedges and to an increase in the fair market value of these
hedges due to a decline in commodity prices between the time of the purchase and
year-end 2001. The balance in other comprehensive income represents the excess
of fair market value over cost related to our hedges, net of related income
taxes, and also includes the remaining other comprehensive income booked as of
September 30, 2001 relating to the Enron hedges, as these assets are no longer
accounted for with hedge accounting treatment due to the Enron bankruptcy. The
other comprehensive income relating to these Enron hedges will be reversed in
2002 and 2003, during the periods that the hedges would have otherwise expired.
The adjustment to their current market value was a $24.4 million expense in the
fourth quarter of 2001. All but $3.2 million of the $14.2 million in accumulated
other comprehensive income as of December 31, 2001 relates to contracts that
will expire within the next 12 months, including $8.4 million related to the
Enron hedges, and will be reclassified out of other comprehensive income during
2002. During 2001 we reclassified approximately $1.0 million out of other
comprehensive income and into derivative contracts fair value loss in the
consolidated statements of operations, relating to the adjustment made at
January 1, 2001 as part of the adoption of SFAS No. 133. In addition, we
expensed approximately $5.3 million during the year relating to the amortization
of the cost of the price floors.
EX 13-47
Based on futures market prices at December 31, 2001, we would expect to receive
approximately $0.9 million on our natural gas floor contracts and $2.2 million
on our oil floor contracts, all of which expire as of the end of 2002. If the
natural gas futures market prices were to decline by 10%, the amount expected to
be received under our natural gas floor contracts during 2002 would increase to
approximately $3.5 million, and if natural gas futures market prices were to
increase by 10%, the amount expected to be received under our natural gas floor
contracts would decrease to approximately $0.6 million. If crude oil prices were
to decrease by 10%, we would expect to receive approximately $9.7 million on our
oil floor contracts, and if crude oil prices were to increase by 10%, we would
not expect to receive any payment on our oil floor contracts.
CRITICAL ACCOUNTING POLICIES
Our significant accounting policies are included in Note 1 to the Consolidated
Financial Statements. These policies, along with the underlying assumptions and
judgments by our management in their application, have a significant impact on
our consolidated financial statements. We consider our most critical accounting
policies are those related to property and equipment and hedging activities.
Property, Plant and Equipment
We follow the full-cost method of accounting for oil and natural gas properties.
Under this method of accounting, the estimated quantities of proved oil and
natural gas reserves used to compute depletion and the related present value of
estimated future net cash flows therefrom used to perform the full-cost ceiling
test have a significant impact on the underlying financial statements. The
process of estimating oil and natural gas reserves is very complex, requiring
significant decisions in the evaluation of all available geological,
geophysical, engineering and economic data. The data for a given field may also
change substantially over time as a result of numerous factors, including
additional development activity, evolving production history and continued
reassessment of the viability of production under varying economic conditions.
As a result, material revisions to existing reserve estimates may occur from
time to time. Although every reasonable effort is made to ensure that the
reported reserve estimates represent the most accurate assessments possible,
including the hiring of independent engineers to prepare the report, the
subjective decisions and variances in available data for various fields make
these estimates generally less precise than other estimates included in the
financial statement disclosures. Changes in the reserve data could have a
significant impact on our financial statements.
Hedging Activities
We enter into derivative contracts (i.e. hedges) to mitigate our exposure to
commodity price risk associated with future oil and natural gas production.
These contracts have historically consisted of options, in the form of price
floors or collars, and fixed price swaps. With the adoption of SFAS No. 133 in
2001, every derivative instrument must be recorded on the balance sheet as
either an asset or a liability measured at its fair value. If the derivative
does not qualify as a hedge or is not designated as a hedge, the change in fair
value of the derivative is recognized currently in earnings. If the derivative
qualifies for hedge accounting, the change in fair value of the derivative is
recognized in other comprehensive income (equity), assuming that the hedge is
effective.
EX 13-48
In order to qualify for hedge accounting, the changes in fair value or cash
flows of the hedging instruments and the hedged items must have a high degree of
correlation (i.e. be effective). We measure and compute the hedge effectiveness
on a quarterly basis. If a hedging instrument becomes ineffective, the 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 that it is
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 one hedge with Enron that initially qualified for
hedge accounting, but its status changed when Enron filed bankruptcy, causing us
to change our accounting treatment of this asset before the hedge would have
expired. Due to the volatility during the year in the market value of our hedges
caused primarily by changing commodity prices, the related asset values on our
balance sheet can change dramatically. If a hedge ceases to qualify for hedge
accounting as did the hedges purchased from Enron, the adjustments in market
value are recorded in the income statement rather than as part of equity. These
adjustments can be material to our financial statements.
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.
RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS
In July 2001, the Financial Accounting Standards Board ("FASB") issued Statement
of Financial Accounting Standards No. 141 ("SFAS No. 141"), "Business
Combinations," Statement of Financial Accounting Standards No. 142 ("SFAS No.
142"), "Goodwill and Other Intangible Assets," and Statement of Financial
Accounting Standards No. 143 ("SFAS No. 143"), "Accounting for Asset Retirement
Obligations."
SFAS No. 141 requires that the purchase method of accounting be used for all
business combinations initiated or completed after June 30, 2001. SFAS No. 141
also specified criteria that intangible assets acquired in a purchase method
business combination must be recognized and reported apart from goodwill. The
adoption of SFAS No. 141 as of July 1, 2001 did not have an impact on our
consolidated financial statements.
SFAS No. 142 requires that goodwill as well as other intangible assets with
indefinite lives not be amortized but tested annually for impairment. The
adoption of SFAS No. 142 will not have an impact on our consolidated financial
statements.
SFAS No. 143 requires that the fair value of a liability for an asset retirement
obligation be recorded in the period in which it is incurred and the
corresponding cost capitalized by increasing the carrying amount of the related
long-lived asset. The liability is accreted to its present value each period,
EX 13-49
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,
a gain or loss is recognized. The standard is effective for us beginning in
2003, but earlier adoption is encouraged. Adoption of the standard will result
in recording a cumulative effect of a change in accounting principle in the
period of adoption. We have not yet determined the impact of this new standard
or when we will adopt this new standard.
In August 2001, the FASB issued Statement of Financial Accounting Standards No.
144 ("SFAS No. 144"), "Accounting for the Impairment or Disposal of Long-Lived
Assets." SFAS No. 144 addresses the financial accounting and reporting for the
impairment or disposal of long-lived assets. SFAS No. 144 supersedes SFAS No.
121 but retains its fundamental provisions for the (a) recognition/measurement
of impairment of long-lived assets to be held and used and (b) measurement of
long-lived assets to be disposed of by sale. SFAS No. 144 also supersedes other
pronouncements which currently do not affect our financial statements. SFAS No.
144 became effective for us beginning in 2002 and we do not expect this
statement to have an impact on our consolidated financial statements.
FORWARD-LOOKING INFORMATION
The statements contained in this Annual Report on Form 10-K that are not
historical facts, including, but not limited to, statements found in this
Management's Discussion and Analysis of Financial Condition and Results of
Operations, are forward-looking statements, as that term is defined in Section
21E of the Securities and Exchange Act of 1934, as amended, that involve a
number of risks and uncertainties. Such forward- looking statements may be or
may concern, among other things, capital expenditures, drilling activity,
acquisition plans and proposals and dispositions, development activities, cost
savings, production efforts and volumes, hydrocarbon reserves, hydrocarbon
prices, liquidity, regulatory matters, mark-to-market values, and competition.
Such forward-looking statements generally are accompanied by words such as
"plan," "estimate," "expect," "predict," "anticipate," "projected," "should,"
"assume," "believe" or other words that convey the uncertainty of future events
or outcomes. Such forward-looking information is based upon management's current
plans, expectations, estimates and assumptions and is subject to a number of
risks and uncertainties that could significantly affect current plans,
anticipated actions, the timing of such actions and the Company's financial
condition and results of operations. As a consequence, actual results may differ
materially from expectations, estimates or assumptions expressed in or implied
by any forward-looking statements made by or on behalf of the Company. Among the
factors that could cause actual results to differ materially are: fluctuations
of the prices received or demand for the Company's oil and natural gas, the
uncertainty of drilling results and reserve estimates, operating hazards,
acquisition risks, requirements for capital, general economic conditions,
competition and government regulations, as well as the risks and uncertainties
discussed in this annual report, including, without limitation, the portions
referenced above, and the uncertainties set forth from time to time in the
Company's other public reports, filings and public statements.
EX 13-50
Independent Auditors' Report
To the Stockholders of Denbury Resources Inc.
We have audited the consolidated balance sheets of Denbury Resources Inc. as of
December 31, 2001 and 2000 and the related consolidated statements of
operations, stockholders' equity (deficit) and cash flows for each of the three
years in the period ended December 31, 2001. These consolidated financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these consolidated financial
statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States of America. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly in all
material respects, the financial position of the Company as of December 31, 2001
and 2000 and the results of its operations and its cash flows for each of the
three years in the period ended December 31, 2001, in conformity with accounting
principles generally accepted in the United States of America.
/s/ Deloitte & Touche LLP
Dallas, Texas
February 25, 2002
EX 13-51
Consolidated Balance Sheets
AMOUNTS IN THOUSANDS DECEMBER 31,
----------------------------
2001 2000
------------- -----------
ASSETS
CURRENT ASSETS
Cash and cash equivalents $ 23,496 $ 22,293
Accrued production receivables 22,823 37,527
Trade and other receivables, net of allowance of $233 and $227 32,512 5,739
Derivative assets 23,458 4,305
Deferred tax asset 989 28,126
- -----------------------------------------------------------------------------------------------------------
Total current assets 103,278 97,990
- -----------------------------------------------------------------------------------------------------------
PROPERTY AND EQUIPMENT
Oil and natural gas properties (using full cost accounting)
Proved 1,098,263 746,062
Unevaluated 44,521 13,810
CO2 properties and equipment 45,555 --
Less accumulated depletion and depreciation (520,332) (452,358)
- -----------------------------------------------------------------------------------------------------------
Net property and equipment 668,007 307,514
- -----------------------------------------------------------------------------------------------------------
OTHER ASSETS 18,703 12,149
NONCURRENT DEFERRED TAX ASSET -- 39,726
- -----------------------------------------------------------------------------------------------------------
TOTAL ASSETS $ 789,988 $ 457,379
===========================================================================================================
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable and accrued liabilities $ 66,491 $ 26,628
Oil and gas production payable 13,447 12,158
- -----------------------------------------------------------------------------------------------------------
Total current liabilities 79,938 38,786
- -----------------------------------------------------------------------------------------------------------
LONG-TERM LIABILITIES
Long-term debt 334,769 199,000
Provision for site reclamation costs 4,318 2,770
Deferred tax liability 18,422 --
Other 3,373 658
- -----------------------------------------------------------------------------------------------------------
Total long-term liabilities 360,882 202,428
- -----------------------------------------------------------------------------------------------------------
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;
52,956,825 and 45,979,981 shares issued and outstanding at
December 31, 2001 and December 31, 2000, respectively 53 46
Paid-in capital in excess of par 391,557 329,339
Accumulated deficit (56,670) (113,220)
Accumulated other comprehensive income 14,228 --
- -----------------------------------------------------------------------------------------------------------
Total stockholders' equity 349,168 216,165
- -----------------------------------------------------------------------------------------------------------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 789,988 $ 457,379
===========================================================================================================
See Notes to Consolidated Financial Statements.
EX 13-52
Consolidated Statements of Operations
YEAR ENDED DECEMBER 31,
------------------------------------
AMOUNTS IN THOUSANDS EXCEPT PER SHARE AMOUNTS 2001 2000 1999
- ----------------------------------------------------------------------------------------------------
REVENUES
Oil, natural gas and related product sales $ 260,398 $ 204,636 $ 90,991
CO2 sales 5,210 -- --
Gain (loss) on settlements of derivative contracts 18,654 (25,264) (9,416)
Interest income and other 849 2,279 1,415
- ----------------------------------------------------------------------------------------------------
Total revenues 285,111 181,651 82,990
- ----------------------------------------------------------------------------------------------------
EXPENSES
Lease operating costs 55,049 38,676 26,029
Production taxes and marketing expenses 10,963 8,051 3,662
CO2 operating costs 891 -- --
General and administrative 9,297 8,055 7,029
Interest 22,335 15,255 15,795
Depletion and depreciation 71,345 36,214 25,515
Franchise taxes 877 467 346
Loss on Enron related assets 25,164 -- --
Amortization of derivative contracts and other
non-cash heding adjustments 7,816 -- --
- ----------------------------------------------------------------------------------------------------
Total expenses 203,737 106,718 78,376
- ----------------------------------------------------------------------------------------------------
Income before income taxes 81,374 74,933 4,614
Income tax provision (benefit)
Current income taxes 640 558 --
Deferred income taxes 24,184 (67,852) --
- ----------------------------------------------------------------------------------------------------
NET INCOME $ 56,550 $ 142,227 $ 4,614
====================================================================================================
NET INCOME PER COMMON SHARE
Basic $ 1.15 $ 3.10 $ 0.12
Diluted 1.12 3.07 0.12
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING
Basic 49,325 45,823 39,928
Diluted 50,361 46,352 39,987
See Notes to Consolidated Financial Statements.
EX 13-53
Consolidated Statements of Cash Flows
YEAR ENDED DECEMBER 31,
--------------------------------------
AMOUNTS IN THOUSANDS 2001 2000 1999
- -----------------------------------------------------------------------------------------------------
CASH FLOW FROM OPERATING ACTIVITIES:
Net income $ 56,550 $ 142,227 $ 4,614
Adjustments needed to reconcile to net
cash flow provided by operations:
Depletion and depreciation 71,345 36,214 25,515
Deferred income taxes 24,184 (67,852) --
Non-cash loss on Enron related assets 25,164 -- --
Amortization of derivative contracts and
other non-cash hedging adjustments 7,816 -- --
Other 1,742 966 1,490
- -----------------------------------------------------------------------------------------------------
186,801 111,555 31,619
Changes in working capital items relating to operations:
Accrued production receivables 19,987 (21,691) (10,341)
Trade and other receivables (16,371) (2,797) 13,448
Derivative assets (28,043) -- --
Other assets (976) (5,109) --
Accounts payable and accrued liabilities 23,560 8,586 4,472
Oil and gas production payable (2,213) 5,038 2,002
Other liabilities 2,302 390 --
- -----------------------------------------------------------------------------------------------------
NET CASH PROVIDED BY OPERATING ACTIVITIES 185,047 95,972 41,200
- -----------------------------------------------------------------------------------------------------
CASH FLOW USED FOR INVESTING ACTIVITIES:
Oil and natural gas expenditures (170,109) (73,736) (34,479)
Acquisitions of oil and gas properties and
Matrix, net of cash acquired (97,871) (60,285) (20,488)
Acquisition of CO2 assets and capital expenditures (45,555) -- --
Net purchases of other assets (1,799) (1,629) (1,381)
Increase in cash restricted for future site reclamation (3,496) (322) (2,347)
Disposition of oil and gas properties -- 2,932 400
- -----------------------------------------------------------------------------------------------------
NET CASH USED FOR INVESTING ACTIVITIES (318,830) (133,040) (58,295)
- -----------------------------------------------------------------------------------------------------
CASH FLOW FROM FINANCING ACTIVITIES:
Bank repayments (79,130) (14,500) (100,000)
Bank borrowings 146,000 61,000 27,500
Issuance of subordinated debt 68,528 -- --
Net proceeds from issuance of common stock 2,594 1,491 100,079
Costs of debt financing (3,026) (398) (765)
Other 20 -- --
- -----------------------------------------------------------------------------------------------------
NET CASH PROVIDED BY FINANCING ACTIVITIES 134,986 47,593 26,814
- -----------------------------------------------------------------------------------------------------
NET INCREASE IN CASH AND CASH EQUIVALENTS 1,203 10,525 9,719
Cash and cash equivalents at beginning of year 22,293 11,768 2,049
- -----------------------------------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS AT END OF YEAR $ 23,496 $ 22,293 $ 11,768
=====================================================================================================
See Notes to Consolidated Financial Statements.
EX 13-54
Consolidated Statement of Changes in Stockholders' Equity (Deficit)
Paid-In Retained
Common Stock Capital Earnings Other
($.001 Par Value) in Excess (Accumulated Comprehensive
DOLLAR AMOUNTS IN THOUSANDS Shares Amount of Par Deficit) Income Total
----------------------------------------------------------------------------------------------------------------------
BALANCE - JANUARY 1, 1999 26,801,680 $ 27 $ 227,769 $ (260,061) $ -- $ (32,265)
----------------------------------------------------------------------------------------------------------------------
Issued pursuant to employee stock
purchase plan 363,930 -- 1,544 -- -- 1,544
Sale of common stock to TPG 18,552,876 19 98,516 -- -- 98,535
Net income -- -- -- 4,614 -- 4,614
-------------------------------------------------------------------------------------------------------- ----------
BALANCE - DECEMBER 31, 1999 45,718,486 46 327,829 (255,447) -- 72,428
-------------------------------------------------------------------------------------------------------- ----------
Issued pursuant to employee stock
purchase plan 218,493 -- 1,305 -- -- 1,305
Issued pursuant to employee stock
option plan 40,458 -- 186 -- -- 186
Issued pursuant to directors
compensation plan 2,544 -- 19 -- -- 19
Net income -- -- -- 142,227 -- 142,227
-------------------------------------------------------------------------------------------------------- ----------
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
Other comprehensive income -- -- -- -- 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
============================================================================================================ ==========
See Notes to Consolidated Financial Statements.
EX 13-55
Notes to Consolidated Financial Statements
NOTE 1. SIGNIFICANT ACCOUNTING POLICIES
Organization and Nature of Operations
Denbury Resources Inc. ("Denbury" or the "Company") is a Delaware corporation,
organized under Delaware General Corporation Law, engaged in the acquisition,
development, operation and exploration of oil and natural gas properties. The
Company operates as one business segment, with its operating activities related
to the exploration, development and production of oil and natural gas in the
U.S. Gulf Coast region. In 2001 the Company acquired carbon dioxide ("CO2" )
reserves that are used in the Company's tertiary oil recovery operations. In
addition, the Company sells some CO2 to third parties for industrial uses.
Principles of Reporting and Consolidation
The consolidated financial statements herein have been prepared in accordance
with generally accepted accounting principles ("GAAP") in the United States and
include the accounts of the Company and its subsidiaries, all of which are
wholly owned. All material intercompany balances and transactions have been
eliminated.
Oil and Natural Gas Operations
A) CAPITALIZED COSTS. The Company follows 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 the Company's
activities undertaken exclusively in the United States. Such costs include lease
acquisition costs, geological and geophysical expenditures, lease rentals on
undeveloped properties, costs of drilling both productive and non-productive
wells and general and administrative expenses directly related to exploration
and development activities and do not include any costs related to production,
general corporate overhead or similar activities. Proceeds received from
disposals are credited against accumulated costs except when the sale represents
a significant disposal of reserves, in which case a gain or loss is recognized.
B) DEPLETION AND DEPRECIATION. The costs capitalized, including production
equipment, are depleted or depreciated on the unit-of-production method, based
on proved oil and natural gas reserves as determined by independent petroleum
engineers. Oil and natural gas reserves are converted to equivalent units based
upon the relative energy content which is six thousand cubic feet of natural gas
to one barrel of crude oil.
C) SITE RECLAMATION. Estimated future costs of well abandonment and site
reclamation, including the removal of production facilities at the end of their
useful life, are provided for on a unit-of-production basis. Costs are based on
engineering estimates of the anticipated method and extent of site restoration,
valued at year-end prices, net of estimated salvage value, and in accordance
with the current legislation and industry practice. The annual provision for
future site reclamation costs is included in depletion and depreciation expense
and reported under long-term liabilities in the Consolidated Balance Sheets as
"Provision for site reclamation costs."
D) CEILING TEST. The net capitalized costs of oil and natural gas properties are
limited to the lower of unamortized cost or the cost center ceiling. The cost
center ceiling is defined as the sum of (i) the present value of estimated
future net revenues from proved reserves (discounted at 10%), based on
EX 13-56
Notes to Consolidated Financial Statements
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 the Company's oil and natural
gas exploration and production activities are conducted jointly with others.
These financial statements reflect only the Company's proportionate interest in
such activities and any amounts due from other partners are included in trade
receivables.
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.
The Company follows the "sales method" of accounting for its oil and natural gas
revenue, whereby the Company recognizes sales revenue on all oil or natural gas
sold to its purchasers, regardless of whether the sales are proportionate to the
Company's ownership in the property. A receivable or liability is recognized
only to the extent that the Company has an imbalance on a specific property
greater than the expected remaining proved reserves. As of December 31, 2001 and
2000, the Company's aggregate oil and natural gas imbalances were not material
to its consolidated financial statements.
The Company recognizes revenue and expenses of purchased producing properties
commencing from the closing or agreement date, at which time the Company also
assumes control.
Derivative Instruments and Hedging Activities
The Company enters into derivative contracts to mitigate its 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, the Company
adopted Statement of Financial Accounting Standards No. 133 ("SFAS No. 133"),
"Accounting for Derivative Instruments and Hedging Activities," as amended. SFAS
No. 133 requires that every derivative instrument be recorded on the balance
sheet as either an asset or a liability measured at fair value. If the
derivative does not qualify as a hedge or is not designated as a hedge, the
change in fair value of the derivative is recognized currently in earnings. If
the derivative qualifies for hedge accounting, the change in fair value of the
derivative is recognized either currently in earnings or deferred in other
comprehensive income (equity) depending on the type of hedge and to what extent
the hedge is effective. All of the Company's current derivative hedging
instruments are cash flow hedges.
As a result of the adoption of SFAS No. 133 on January 1, 2001, the Company
recognized a $1.6 million increase in its derivative assets for the increase in
fair value over the cost of hedging contracts in place at that time. The Company
also recorded a corresponding increase to accumulated other comprehensive income
of approximately $1.0 million, after tax, in the transition adjustment which was
reclassified out of accumulated other comprehensive income to earnings over the
remainder of 2001. A summary of the Company's comprehensive income for the year
ended December 31, 2001 and balance in accumulated other comprehensive income at
December 31, 2001 is included in Note 8 to the consolidated financial
statements.
EX 13-57
Notes to Consolidated Financial Statements
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. The Company measures
hedge effectiveness on a quarterly basis. Hedge accounting is discontinued
prospectively when a hedging instrument becomes ineffective. The Company
assesses 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 the Company determines that it is probable that a
hedged forecasted transaction will not occur, deferred gains or losses on the
hedging instrument are recognized in earnings immediately.
Gains or losses on settlements of the Company's derivative hedging instruments
are recorded in "Gain (loss) on settlements of derivative contracts" included in
revenues in the Company's Consolidated Statements of Operations. The Company
applies Derivative Implementation Group Issue G20 in accounting for its net
purchased and zero cost collars which allows the Company to amortize the cost of
net purchased options over the period of the hedge. The Company records this
amortization and other 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. The Company's
hedging activities are further discussed in Note 7 to the consolidated financial
statements.
Financial Instruments with Off-Balance-Sheet Risk and Concentrations of Credit
Risk
The Company's 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.
The Company's cash equivalents represent high-quality securities placed with
various investment grade institutions. This investment practice limits the
Company's exposure to concentrations of credit risk. The Company's trade and
accrued production receivables are dispersed among various customers and
purchasers; therefore, concentrations of credit risk are limited. Also, the
Company's more 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. The Company attempts to
minimize its credit risk exposure to counterparties of its derivative hedging
contracts through formal credit policies, monitoring procedures and
diversification.
CO2 Operations
The Company owns CO2 reserves that it uses for its own tertiary oil recovery
operations, and in addition sells a portion to third party industrial users. The
Company records revenue from sales of CO2 to third parties when it is produced
and sold. CO2 used for the Company's tertiary oil recovery operations is not
recorded as revenue in the Company's Consolidated Statements of Operations.
Expenses related to the production of CO2 are allocated between volumes sold to
third parties and volumes used for the Company's own use. The expenses related
to third party sales are recorded in "CO2 operating costs" and the expenses
related to the Company's own uses are recorded in "Lease operating costs" in the
Company's Consolidated Statements of Operations.
EX 13-58
Notes to Consolidated Financial Statements
The Company capitalizes acquisitions and the costs of exploring and developing
CO2 reserves. The costs capitalized are depleted or depreciated on the
unit-of-production method, based on proved CO2 reserves as determined by
independent engineers.
Cash Equivalents
The Company considers 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, 2001 and 2000, the Company had approximately $7.8 million and
$2.7 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, 2001, 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 income per common share
computations:
YEAR ENDED DECEMBER 31,
---------------------------------------------
AMOUNTS IN THOUSANDS 2001 2000 1999
- -----------------------------------------------------------------------------------------------
Weighted average common shares - basic 49,325 45,823 39,928
Effect of diluted securities:
Stock options . 1,036 529 59
- -----------------------------------------------------------------------------------------------
Weighted average common shares - diluted 50,361 46,352 39,987
===============================================================================================
Options to purchase 1.8 million shares of common stock in 2001, 1.6 million
shares of common stock in 2000 and 1.6 million shares of common stock in 1999
were excluded from the diluted net income per common share computation as the
exercise prices of these options exceeded the average market price of the
Company's common stock during the respective periods. Warrants representing
75,000 shares of common stock were also excluded from the 1999 diluted net
income per share computation as the exercise price exceeded the average market
price of the Company's common stock.
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.
EX 13-59
Notes to Consolidated Financial Statements
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 the Company's estimates. Significant
estimates underlying these financial statements include the fair value of
financial derivative instruments and the estimated quantities of proved oil and
natural gas reserves used to compute depletion of oil and natural gas properties
and the related present value of estimated future net cash flows therefrom.
Reclassifications
To conform to the current year presentation, the Company reclassified losses on
settlements of derivative contracts of $25.3 million in 2000 and $9.4 million in
1999 which were previously reported in "Oil, natural gas and related product
sales" to "Gain (loss) on settlements of derivative contracts" in the
Consolidated Statements of Operations. These reclassifications had no impact on
the total revenues reported by the Company.
Recently Issued Accounting Pronouncements
In July 2001, the Financial Accounting Standards Board ("FASB") issued Statement
of Financial Accounting Standards No. 141 ("SFAS No. 141"), "Business
Combinations," Statement of Financial Accounting Standards No. 142 ("SFAS No.
142"), "Goodwill and Other Intangible Assets," and Statement of Financial
Accounting Standards No. 143 ("SFAS No. 143"), "Accounting for Asset Retirement
Obligations."
SFAS No. 141 requires that the purchase method of accounting be used for all
business combinations initiated or completed after June 30, 2001. SFAS No. 141
also specified criteria that intangible assets acquired in a purchase method
business combination must be recognized and reported apart from goodwill. The
adoption of SFAS No. 141 as of July 1, 2001 did not have an impact on the
Company's consolidated financial statements.
SFAS No. 142 requires that goodwill as well as other intangible assets with
indefinite lives not be amortized but tested annually for impairment. The
adoption of SFAS No. 142 will not have an impact on the Company's consolidated
financial statements.
SFAS No. 143 requires that the fair value of a liability for an asset retirement
obligation be recorded in the period in which it is incurred and the
corresponding cost capitalized by increasing the carrying amount of the related
long-lived asset. The liability is accreted to its present value each period,
and the capitalized cost is depreciated over the useful life of the related
asset. If the liability is settled for an amount other than the recorded amount,
a gain or loss is recognized. The standard is effective for the Company
beginning in 2003, but earlier adoption is encouraged. Adoption of the standard
will result in recording a cumulative effect of a change in accounting principle
in the period of adoption. The Company has not yet determined the impact of this
new standard or when the Company will adopt this new standard.
EX 13-60
Notes to Consolidated Financial Statements
In August 2001, the FASB issued Statement of Financial Accounting Standards No.
144 ("SFAS No. 144"), "Accounting for the Impairment or Disposal of Long-Lived
Assets." SFAS No. 144 addresses the financial accounting and reporting for the
impairment or disposal of long-lived assets. SFAS No. 144 supersedes SFAS No.
121 but retains its fundamental provisions for the (a) recognition/measurement
of impairment of long-lived assets to be held and used and (b) measurement of
long-lived assets to be disposed of by sale. SFAS No. 144 also supersedes other
pronouncements which currently do not affect the Company. SFAS No. 144 became
effective for the Company beginning in 2002 and is not expected to have an
impact on the Company's consolidated financial statements.
NOTE 2. ACQUISITIONS
Matrix Oil and Gas, Inc.
On July 10, 2001, the Company completed the acquisition of Matrix Oil & Gas,
Inc.("Matrix"), an independent oil and gas company based in Covington,
Louisiana. Under the merger agreement, Denbury paid a total of approximately
$158.5 million, comprised of $99.3 million (63%) in cash and $59.2 million (37%)
in the form of 6.6 million shares of Denbury's common stock. The cash portion of
the purchase was funded with available cash and borrowings of $95.0 million from
Denbury's bank credit facility. 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.
The Company 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. In addition, the Company recorded a deferred
income tax liability of $53.1 million to reflect the difference between the book
and tax basis of the properties acquired. Although not expected, the purchase
price allocation could still change as additional information becomes available.
The Company reclassified $5.0 million of the unevaluated property cost to
developed properties at year-end 2001 based on the results of drilling activity
and the reserves added since July, leaving a balance of $25.0 million as of
December 31, 2001 relating to Matrix. The Company's financial statements include
the operations of Matrix from July 1, 2001.
In conjunction with the acquisition of Matrix, Denbury purchased commodity
hedges to protect its investment. These hedges, in the form of price floors,
covered nearly all of the forecasted production from the acquired properties for
two and one-half years 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, the Company collected approximately $12.7 million on these hedges.
Unfortunately, the price floors relating to 2002 and 2003 were purchased from
Enron Corporation, which filed bankruptcy in December 2001. Denbury sold their
bankruptcy claim against Enron in February 2002 for net proceeds of
approximately $9.2 million. In total, Denbury collected approximately $21.9
million from the price floors relating to the Matrix acquisition, a net cash
gain of approximately $3.9 million over the cost of the floors, but has suffered
an opportunity loss in light of the drop in natural gas prices since the date of
acquisition and the loss of the 2002 and 2003 hedges. See Note 7 to the
consolidated financial statements for further information regarding the
Company's hedging activities.
EX 13-61
Notes to Consolidated Financial Statements
The following pro forma information gives effect to the acquisition of Matrix on
the Company's historical consolidated statement of operations as if the merger
had occurred at the beginning of the periods presented. The effects of other
acquisitions in 2001 were not significant for inclusion in the pro forma
presentation. Pro forma amounts are not necessarily indicative of actual
results.
YEAR ENDED DECEMBER 31,
AMOUNTS IN THOUSANDS EXCEPT PER SHARE AMOUNTS 2001 2000
- -----------------------------------------------------------------------------------------------------
Revenues $ 324,401 $ 214,473
Expenses 234,097 147,409
Net income 62,243 137,387
- -----------------------------------------------------------------------------------------------------
Income per common share:
Basic $ 1.18 $ 2.62
Diluted 1.16 2.60
- -----------------------------------------------------------------------------------------------------
CO2 Acquisition
On February 2, 2001, the Company purchased certain CO2 reserves, production and
associated assets from a division of Airgas, Inc. for $42 million. The cost of
the acquisition was funded by available cash and $21 million borrowed under the
Company's bank credit facility. 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 Denbury's tertiary
recovery operation at Little Creek Field, as well as to other commercial
customers.
Other 2001 Acquisitions
During 2001 the Company completed other minor acquisitions totaling
approximately $5.0 million.
2000 Acquisitions
During the fourth quarter of 2000, the Company completed acquisitions totaling
$56.5 million in the Thornwell, Porte Barre and Iberia Fields located in
southwestern Louisiana. Approximately $10.0 million of these acquisition costs
were initially recorded as unevaluated property costs at December 31, 2000. The
Company also completed other minor acquisitions totaling $3.8 million during
2000.
1999 Acquisitions
During 1999, the Company completed acquisitions totaling $20.5 million,
primarily comprised of a $12.3 million acquisition of a tertiary recovery oil
field (Little Creek) in southern Mississippi and a $4.9 million acquisition of
the King Bee Field, also in Mississippi.
EX 13-62
Notes to Consolidated Financial Statements
NOTE 3. PROPERTY AND EQUIPMENT
Property and equipment at December 31, 2001 and 2000 consisted of the following:
DECEMBER 31,
AMOUNTS IN THOUSANDS 2001 2000
- ---------------------------------------------------------------------------------------------------------
Oil and natural gas properties
Proved properties $ 1,098,263 $ 746,062
Unevaluated properties 44,521 13,810
- ---------------------------------------------------------------------------------------------------------
Total 1,142,784 759,872
Accumulated depletion and depreciation (518,760) (452,358)
- ---------------------------------------------------------------------------------------------------------
Net oil and natural gas properties 624,024 307,514
- ---------------------------------------------------------------------------------------------------------
CO2 properties 45,555 -
Accumulated depletion and depreciation (1,572) -
- ---------------------------------------------------------------------------------------------------------
Net CO2 properties 43,983 -
- ---------------------------------------------------------------------------------------------------------
Net property and equipment $ 668,007 $ 307,514
=========================================================================================================
Unevaluated Oil and Natural Gas Properties Excluded From Depletion
Under full cost accounting, the Company 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, 2001 and 2000 and the year in which they were incurred follows:
DECEMBER 31, 2001 DECEMBER 31, 2000
- -----------------------------------------------------------------------------------------------------------
Costs Incurred During Costs Incurred During
- -----------------------------------------------------------------------------------------------------------
AMOUNTS IN THOUSANDS 2001 2000 Total 2000 1999 1998 Total
- -----------------------------------------------------------------------------------------------------------
Property acquisition costs $ 34,195 $ 3,688 $ 37,883 $ 10,709 $ 750 $ 65 $ 11,524
Exploration costs 5,395 1,243 6,638 1,332 193 761 2,286
- -----------------------------------------------------------------------------------------------------------
Total $ 39,590 $ 4,931 $ 44,521 $ 12,041 $ 943 $ 826 $ 13,810
===========================================================================================================
Costs are transferred into the amortization base on an ongoing basis as the
projects are evaluated and proved reserves established or impairment determined.
Pending determination of proved reserves attributable to the above costs, the
Company cannot assess the future impact on the amortization rate. As of December
31, 2001, approximately $25.0 million of the total unevaluated property balance
of $44.5 million related to the Matrix acquisition. These costs will be
transferred into the amortization base as the undeveloped areas are tested. The
Company anticipates that the majority of this activity should be completed over
the next three to five years.
Capitalized Costs
Capitalized general and administrative costs that directly relate to exploration
and development activities were $4.1 million, $3.2 million and $2.8 million for
the years ended December 31, 2001, 2000 and 1999, respectively.
Amortization per BOE was $6.27, $4.62 and $4.17 for the years ended December 31,
2001, 2000 and 1999, respectively.
EX 13-63
Notes to Consolidated Financial Statements
NOTE 4. NOTES PAYABLE AND LONG-TERM INDEBTEDNESS
DECEMBER 31,
AMOUNTS IN THOUSANDS 2001 2000
- ----------------------------------------------------------------------------------------------
Senior bank loan $ 140,870 $ 74,000
9% Senior Subordinated Notes due 2008 125,000 125,000
9% Series B Senior Subordinated Notes due 2008 75,000 -
Discount on 9% Series B Subordinated Notes due 2008 (6,101) -
- ----------------------------------------------------------------------------------------------
Total long-term debt $ 334,769 $ 199,000
==============================================================================================
Senior Bank Loan
The Company has a credit facility with Bank of America, as agent for a group of
nine other banks. The credit facility is secured by substantially all of the
Company's producing oil and natural gas properties and matures on December 31,
2003. This credit facility has 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. The Company's bank credit facility provides for a
semi-annual redetermination of the borrowing base on April 1st and October 1st.
At the April 2001 redetermination, the Company's borrowing base was increased
from $150 million to $200 million and further increased at the October 2001
redetermination to $220 million.
As of December 31, 2001, the Company had $140.9 million outstanding under the
facility, at a weighted average interest rate of 4.2%, $370,000 of letters of
credit outstanding and a borrowing base of $220 million. The next scheduled
redetermination of the borrowing base will be as of April 1, 2002, based on
December 31, 2001 assets and proved reserves.
Subordinated Debt
On February 26, 1998, Denbury Management Inc. ("DMI"), a wholly owned subsidiary
of the Company at that time, issued $125 million in aggregate principal amount
of 9% Senior Subordinated Notes due 2008 which require only semi-annual interest
payments until maturity. In April 1999, DMI was merged into Denbury Resources
Inc., which expressly assumed all liabilities of DMI, including the 9% Senior
Subordinated Notes. These notes contain certain debt covenants, including
covenants that limit (i) indebtedness, (ii) certain restricted payments
including dividends, (iii) sale/leaseback transactions, (iv) transactions with
affiliates, (v) liens, (vi) asset sales and (vii) mergers and consolidations.
The net proceeds to the Company from the debt offering were approximately $121.8
million, before offering expenses.
During August 2001, Denbury issued an additional $75 million of subordinated
debt in a private placement at 91.371% of face amount for an effective yield of
10.875%. The notes were issued under a separate indenture, but on terms
substantially identical to the existing 9% Senior Subordinated Notes due 2008.
The net proceeds to the Company were approximately $65.9 million. These notes
were subsequently exchanged for a like principal amount of publicly registered
notes.
EX 13-64
Notes to Consolidated Financial Statements
Indebtedness Repayment Schedule
The Company's indebtedness as of December 31, 2001 is repayable as follows:
AMOUNTS IN THOUSANDS
- ------------------------------------------------------------
YEAR
2002 $ --
2003 140,870
2004 --
2005 --
2006 --
Thereafter (2008) 200,000
- ------------------------------------------------------------
Total indebtedness $ 340,870
============================================================
NOTE 5. INCOME TAXES
The Company's income tax provision (benefit) is as follows:
YEAR ENDED DECEMBER 31,
AMOUNTS IN THOUSANDS 2001 2000 1999
- --------------------------------------------------------------------------------------------------
Current income tax expense
Federal $ 614 $ 558 $ --
State 26 -- --
- --------------------------------------------------------------------------------------------------
Total current income tax expense 640 558 --
- --------------------------------------------------------------------------------------------------
Deferred income tax expense (benefit)
Federal 24,184 (67,852) --
State -- -- --
- --------------------------------------------------------------------------------------------------
Total deferred income tax expense (benefit) 24,184 (67,852) --
- --------------------------------------------------------------------------------------------------
Total income tax expense (benefit) $ 24,824 $(67,294) $ --
==================================================================================================
The Company's income tax benefit for 2000 is primarily the result of the
elimination of the Company's valuation allowance on its net deferred tax assets
as of December 31, 2000. The valuation allowance on the Company's net deferred
tax assets was initially recorded at December 31, 1998 and the assets remained
fully reserved at December 31, 1999, based upon management's belief that it was
more likely than not that the Company would not be able to generate sufficient
taxable income to realize the benefit of its net deferred tax assets. In
reaching this conclusion, management considered both historical results and its
expectations regarding future taxable income based on oil and gas pricing
consistent with the Company's long-term forecasting and anticipated levels of
capital spending. As a result of the near-term recovery of oil and natural gas
prices that began in the latter part of 1999 and continued throughout 2000, the
Company was able to generate net income for 2000 and taxable income that
utilized approximately $27.2 million of the Company's net operating losses.
Based on expectations at that time regarding current production levels, current
expectations regarding near-term oil and gas prices, current hedging positions,
anticipated capital expenditures, the estimated reversal of book and tax
temporary differences, available tax planning strategies and the Company's
expectations regarding future taxable income, management concluded that the
valuation allowance
EX 13-65
Notes to Consolidated Financial Statements
on its net deferred tax assets was no longer necessary and at December 31, 2000
eliminated the entire valuation allowance. The Company's current income tax
expense in 2000 and 2001 was for alternative minimum taxes that may not be
offset by net operating losses.
At December 31, 2001, the Company had net operating loss carryforwards for U.S.
federal income tax purposes of approximately $91.2 million and approximately
$21.3 million for alternative minimum tax purposes. As a result of the
acquisition of Matrix and other prior ownership changes, the utilization of some
of the Company's net operating loss carryforwards is subject to limitations
imposed by the Internal Revenue Code of 1986. However, the Company does not
expect such limitations to have an effect on its ability to use its net
operating loss carryforwards. The Company's net operating loss carryforwards are
scheduled to expire as follows:
Alternative
Minimum
Amounts in Thousands Income Tax Tax
- -----------------------------------------------------------------------
YEAR
2018 $ 60,217 $ 5,407
2019 21,713 15,585
2020 8,023 193
2021 1,267 127
In 2001, the Company began to recognize a benefit for the amount of enhanced oil
recovery credits earned from its tertiary recovery projects. The total amount of
credits earned to date totals approximately $5.3 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, 2001 and 2000 balance sheet dates.
At December 31, 2001 and 2000, the Company's deferred tax assets and liabilities
were as follows:
December 31,
Amounts in Thousands 2001 2000
- ----------------------------------------------------------------------------
Deferred tax assets:
Loss carryforwards $ 33,751 $ 41,695
Property and equipment -- 26,144
Tax credit carryover 1,403 558
Enhanced oil recovery credit carryforwards 5,280 --
- ----------------------------------------------------------------------------
Total deferred tax assets 40,434 68,397
- ----------------------------------------------------------------------------
Deferred tax liabilities:
Property and equipment (48,978) --
Derivative hedging contracts (8,356) --
Other (533) (545)
- ----------------------------------------------------------------------------
Total deferred tax liabilities (57,867) (545)
- ----------------------------------------------------------------------------
Total net deferred tax asset (liability) $(17,433) $ 67,852
============================================================================
EX 13-66
Notes to Consolidated Financial Statements
The Company's income tax provision (benefit) varies from the amount that would
result from applying the statutory income tax rate to income before income taxes
as follows:
Year Ended December 31,
Amounts in Thousands 2001 2000 1999
- ---------------------------------------------------------------------------------------------------
Income tax provision (benefit) calculated using the
statutory income tax rate $ 28,481 $ 26,227 $ 1,615
State income taxes and other 1,623 1,616 (350)
Change in valuation allowance - (95,137) (1,265)
Enhanced oil recovery credit (5,280) - -
- ---------------------------------------------------------------------------------------------------
Total income tax expense (benefit) $ 24,824 $ (67,294) $ -
===================================================================================================
Note 6. Stockholders' Equity
Authorized
The Company is 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.
1999 Sale of Stock to the Texas Pacific Group
In April 1999, the stockholders approved the sale of 18,552,876 shares of common
stock to an affiliate of the Texas Pacific Group ("TPG") for $100 million or
$5.39 per share. As a result of this transaction, TPG's ownership of the
Company's outstanding common stock increased from approximately 32% to
approximately 60%. The net proceeds from this sale of common stock of
approximately $98.5 million were used to pay down the Company's revolving credit
facility. At December 31, 2001, TPG's ownership of the Company's outstanding
common stock had declined to approximately 52% primarily as a result of the
shares issued in the Matrix acquisition.
Stock Option Plan
As of December 31, 2001, the Company had a total of 5,745,587 shares of common
stock authorized for issuance pursuant to its Stock Option Plan, of which
268,609 shares were available for issuance. The board of directors of the
Company has authorized an additional 1.6 million shares for this plan, subject
to the approval of shareholders at the May 22, 2002 annual meeting. Under the
terms of the plan, incentive and non-qualified options may be issued to
officers, key employees and consultants. Options generally become exercisable
over a four year vesting period with the specific terms of vesting determined by
the board of directors at the time of grant. The options expire over terms not
to exceed ten years from the date of grant, 90 days after termination of
employment or permanent disability or one year after the death of the optionee.
The options are granted at the fair market value at the time of grant, which is
generally defined as the average closing price of the Company's shares of common
stock for the ten trading days prior to issuance. The plan is administered by
the Stock Option Committee of the Board.
EX 13-67
Notes to Consolidated Financial Statements
Following is a summary of stock option activity during the years ended December
31, 2001, 2000 and 1999:
YEAR ENDED DECEMBER 31,
2001 2000 1999
- ------------------------------------------------------------------------------------------------------------------------
Number Weighted Number Weighted Number Weighted
of Options Average Price of Options Average Price of Options Average Price
- ------------------------------------------------------------------------------------------------------------------------
Outstanding at beginning of
year 3,802,122 $ 8.03 3,317,384 $ 8.66 1,890,531 $ 13.04
Granted 1,222,141 9.00 595,635 4.11 1,830,503 4.38
Exercised (209,600) 5.00 (40,458) 4.60 - -
Forfeited . (198,330) 8.53 (70,439) 6.70 (403,650) 9.78
- ------------------------------------------------------------------------------------------------------------------------
Outstanding at end of year 4,616,333 $ 8.40 3,802,122 $ 8.03 3,317,384 $ 8.66
=======================================================================================================================
Exercisable at end of year 1,858,072 $ 9.49 1,310,382 $ 9.35 622,001 $ 9.39
=======================================================================================================================
Weighted average fair value of
options granted $ 5.19 $ 2.26 $ 2.56
- -----------------------------------------------------------------------------------------------------------------------
The Company applies the intrinsic value method in accounting for options granted
under the Stock Option Plan and accordingly no compensation cost is recognized.
Had compensation expense been recognized based on the fair value of the options
on the date they were granted, the Company's net income and net income per
common share would have been reduced to the following pro forma amounts:
Year Ended December 31,
2001 2000 1999
- ----------------------------------------------------------------------------------------------------------------
NET INCOME:
As reported (thousands) $ 56,550 $ 142,227 $ 4,614
Pro forma (thousands) 53,756 139,574 772
NET INCOME PER COMMON SHARE:
As reported:
Basic $ 1.15 $ 3.10 $ 0.12
Diluted 1.12 3.07 0.12
Pro forma:
Basic $ 1.09 $ 3.05 $ 0.02
Diluted 1.09 3.05 0.02
- ----------------------------------------------------------------------------------------------------------------
The Company estimated the fair value of each option grant using the
Black-Scholes option pricing method using the following weighted average
assumptions:
2001 2000 1999
- ----------------------------------------------------------------------------------------------------------------
Risk-free interest rate 4.64% 6.5% 4.7%
Expected life 5 years 5 years 5 years
Expected volatility 63.4% 55.0% 64.7%
Dividend yield - - -
- -----------------------------------------------------------------------------------------------------------------
EX 13-68
Notes to Consolidated Financial Statements
The following table summarizes information on the Company's stock options
outstanding at December 31, 2001:
Options Outstanding Options Exercisable
---------------------------------------------------------------------------------------------------
Weighted
Number Average Weighted Number Weighted
of Options Remaining Average of Options Average
Range of Outstanding Contractual Exercise Exercisable Exercise
Exercise Prices at 12/31/01 Life Price at 12/31/01 Price
---------------------------------------------------------------------------------------------------
$ 3.77 - $ 5.50 1,894,433 7.2 $ 4.18 630,456 $ 4.25
5.51 - 8.00 335,060 5.4 6.75 251,499 6.71
8.01 - 11.50 1,333,230 8.4 9.20 198,830 9.92
11.51 - 14.50 601,938 4.8 13.38 601,938 13.38
14.51 - 22.25 451,672 5.8 18.35 175,349 18.43
---------------------------------------------------------------------------------------------------
$ 3.77 - $22.25 4,616,333 7.0 $ 8.40 1,858,072 $ 9.49
===================================================================================================
Stock Purchase Plan
The Company maintains a Stock Purchase Plan which authorizes the sale of up to
1,250,000 shares of common stock to all full-time employees. The board of
directors of the Company has authorized an additional 500,000 shares for this
plan, subject to the approval of shareholders at the May 22, 2002 annual
meeting. As of December 31, 2001, the Company had 292,950 authorized shares
remaining to issue under the plan. In accordance with the plan, the employees
may contribute up to 10% of their base salary and the Company matches 75% of the
employee contribution. The combined funds are used to purchase previously
unissued common stock of the Company based on its current market value at the
end of each quarter. The Company recognizes compensation expense for the 75%
Company matching portion, which totaled $666,000, $560,000 and $501,000 for the
years ended December 31, 2001, 2000 and 1999, respectively. This plan is
administered by the Stock Purchase Plan Committee of the Board.
401(k) Plan
T
he Company offers a 401(k) Plan to which employees may contribute tax deferred
earnings subject to Internal Revenue Service limitations. The Company matches
75% of employee contributions up to an employee's contribution of 6% of their
salary. This Company match becomes vested over a four year period. During 2001,
2000 and 1999, the Company made matching contributions of $670,000, $427,000 and
$239,000, respectively, to the 401(k) Plan.
NOTE 7. DERIVATIVE HEDGING CONTRACTS
The Company enters into various financial contracts to hedge its exposure to
commodity price risk associated with anticipated future oil and natural gas
production. These contracts have historically consisted of price ceilings and
floors, collars and fixed price swaps.
EX 13-69
Notes to Consolidated Financial Statements
Oil Hedges Historical Data
During March and April 1999, the Company entered into two no-cost contracts to
hedge a portion of its oil production. The first contract was a fixed price swap
for 3,000 Bbls/d from April through December 1999 at a price of $14.24 per Bbl.
The second contract was a collar to hedge 3,000 Bbls/d from May 1999 through
December 2000 with a floor price of $14.00 per Bbl and a ceiling price of $18.05
per Bbl. During 1999, the Company paid out approximately $8.6 million on these
contracts, and during 2000 paid out $13.3 million relating to these oil collars.
During 2000, the Company purchased a $22.00 price floor on 2001 production
covering 12,800 Bbls/d at an aggregate cost of $1.8 million. This contract
covered approximately 75% of the anticipated 2001 oil production, excluding any
anticipated production from acquisitions. During 2001, approximately $1.9
million was collected on this price floor.
During July 2001, the Company acquired a $21.00 price floor on 10,000 Bbls/d for
2002 production at an aggregate cost of approximately $4.7 million. This price
floor covers approximately 60% of the Company's anticipated oil production for
2002.
Natural Gas Hedges Historical Data
As of January 1, 1999, the Company had no-cost financial contracts ("collars")
in place that hedged a total of 40 MMcf/d through August 1999 and 30 MMcf/d
thereafter through December 2000. The first set of contracts had a weighted
average ceiling price of approximately $2.95 per MMBtu and the second set of
contracts had a ceiling price of $2.58 per MMBtu. Both contracts had a price
floor of $1.90 per MMBtu. During 1999, the Company paid out a net of $0.8
million on these contracts, including $0.7 million paid to retire a portion of
the hedge. During 2000, the Company paid out $11.9 million relating to these
same natural gas collars.
During 2000, the Company purchased a $2.80 price floor on 2001 production
covering 37,500 MMBtu/d at an aggregate cost of $0.8 million. This contract
covered approximately 75% of the anticipated 2001 natural gas production,
excluding any anticipated production from acquisitions. During 2001, the Company
collected $1.8 million on this price floor.
Concurrent with the acquisition of Thornwell Field, the Company purchased price
floors for these predominately natural gas properties that were acquired in the
fourth quarter of 2000. The price floors covered nearly all of the anticipated
proven natural gas production from these properties for 2001 and 2002. These
floors cost $2.5 million with varying volumes and price floors for each quarter
for 2001 and 2002. During 2001, the Company collected $2.2 million from these
price floors.
For the Matrix properties acquired in July 2001 (see also "Note 2"), the Company
purchased price floors covering nearly all of the forecasted proven natural gas
production through December 2003, with a minimum price of $4.25 per MMBtu for
July 2001 through December 2002 and $3.75 per MMBtu for all of 2003, at a total
cost of $18.0 million. Subsequent to the acquisition, natural gas prices began
to decline and Denbury was paid approximately $12.7 million on these price
floors during 2001. Unfortunately, the price floors relating to 2002 and 2003
were purchased from Enron, which filed bankruptcy in December 2001. The Company
sold its bankruptcy claim against Enron in February 2002 for approximately $9.2
million. In total, the Company collected approximately $21.9 million from
EX 13-70
Notes to Consolidated Financial Statements
the price floors relating to the Matrix acquisition, a net cash gain of
approximately $3.9 million, although the Company has suffered an opportunity
loss in light of the drop in natural gas prices since the date of acquisition
and the loss of the 2002 and 2003 hedges.
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 current market value, which was determined to be
the amount that Denbury received when it sold the claims in February 2002, the
Company took a pre-tax write down of $24.4 million in the fourth quarter of
2001. The Company 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 the Company's Enron
related assets of $25.2 million. The after-tax balance in accumulated other
comprehensive income related to the these Enron hedges was approximately $11.6
million at the point they no longer qualified for hedge accounting. Accordingly,
this amount will be reclassified out of accumulated other comprehensive income
to the income statement over the periods during which the hedges would have
otherwise expired. The result is that the Company will recognize pre-tax income
attributable to the Enron hedges during 2002 of approximately $13.4 million and
pre-tax income during 2003 of approximately $5.1 million. The three year total
pre-tax net loss on the Enron hedges will be approximately $5.9 million, which
approximates the difference between the amount collected and paid for the Enron
portion of the Matrix price floors.
Subsequent to the Enron bankruptcy, in December 2001, Denbury purchased
additional hedges to protect against any further deterioration in natural gas
prices. These have a floor price of $2.50 per MMBtu and an average ceiling price
of approximately $4.15 per MMBtu and cover not only the anticipated gas
production from the Matrix properties, but a substantial portion of the other
natural gas production as well. Overall, these hedges, which were purchased from
four different financial institutions, cover approximately 75% of the forecasted
total 2002 natural gas production.
Summary of Hedging Results
During 1999, the Company paid out $8.6 million for losses on its oil hedges
($1.95 per Bbl) and $126,000 for losses on its natural gas hedges, and in
addition expensed $672,000 in 1999 that was paid to buy out a portion of our
natural gas hedges for the next year. During 2000, the Company paid out $13.3
million ($2.39 per Bbl) on its oil hedges and $11.9 million ($0.88 per Mcf) on
its natural gas hedges. In contrast, during 2001, the Company collected $1.9
million ($0.31 per Bbl) on its oil hedges and $16.7 million ($0.54 per Mcf) on
its natural gas hedges.
EX 13-71
The following table lists all of the individual floors in place as of December
31, 2001.
Volume Floor Volume Floor Ceiling
Period Per Day Price Period Per Day Price Price
- ------------------------------------------- ----------------------------------------------
Oil Options or "puts" (Bbls/d): Gas Price Collars (MMBtu/d):
2002 10,000 $21.00 2002 20,000 $2.50 $4.10
2002 20,000 $2.50 $4.10
Gas Options or "puts" (MMBtu/d): 2002 25,000 $2.50 $4.20
Q1 - 2002 5,269 $3.65 2002 25,000 $2.50 $4.17
Q2 - 2002 3,775 $3.40
Q3 - 2002 2,873 $3.38
Q4 - 20 02 2,135 $3.38
NOTE 8. COMPREHENSIVE INCOME
The following table presents comprehensive income for the year ended December
31, 2001.
YEAR ENDED
Amounts in Thousands DECEMBER 31, 2001
- --------------------------------------------------------------------------------------------------------------------
Accumulated other comprehensive income - December 31, 2000 $ -
Net income $ 56,550
- --------------------------------------------------------------------------------------------------------------------
Other comprehensive income - net of tax
Cumulative effect of change in accounting principle - January 1, 2001 1,012
Reclassification adjustments related to derivative contracts (1,012)
Change in fair value of outstanding hedging positions 14,228
- --------------------------------------------------------------------------------------------------------------------
Total other comprehensive income 14,228 14,228
- --------------------------------------------------------------------------------------------------------------------
Comprehensive income for the year ended December 31, 2001 $ 70,778
====================================================================================================================
Accumulated other comprehensive income - December 31, 2001 $ 14,228
====================================================================================================================
The Company did not have any items that met the criteria of other comprehensive
income, other than net income, for the years ended December 31, 2000 and 1999.
Based on commodity prices as of December 31, 2001, the Company expects to
reclassify pre-tax gains relating to hedges of $17.5 million ($11.0 million
after tax) to the income statement over the next 12 months from the accumulated
other comprehensive income balance at December 31, 2001.
EX 13-72
Notes to Consolidated Financial Statements
NOTE 9. COMMITMENTS AND CONTINGENCIES
The Company has operating leases for the rental of office space, office
equipment, and vehicles that totaled $1.6 million, $1.4 million and $1.2 million
for the years ended December 31, 2001, 2000 and 1999, respectively. At December
31, 2001, long-term commitments for these items require the following future
minimum rental payments:
AMOUNTS IN THOUSANDS
- ------------------------------------------------
2002 $ 1,719
2003 1,586
2004 1,570
2005 1,681
2006 1,670
Thereafter 4,302
- ------------------------------------------------
Total lease commitments $ 12,528
================================================
The Company has future capital expenditure obligations related to field
development costs that total $13.6 million over the next four years. None of the
$13.6 million is required to be spent in 2002.
The Company is subject to various possible contingencies which arise primarily
from interpretation of federal and state laws and regulations affecting the oil
and natural gas industry. Such contingencies include differing interpretations
as to the prices at which oil and natural gas sales may be made, the prices at
which royalty owners may be paid for production from their leases, environmental
issues and other matters. Although management believes that it has complied with
the various laws and regulations, administrative rulings and interpretations
thereof, adjustments could be required as new interpretations and regulations
are issued. In addition, production rates, marketing and environmental matters
are subject to regulation by various federal and state agencies.
The Company and its subsidiaries are involved in various lawsuits, claims and
regulatory proceedings incidental to their businesses. In the opinion of
management, the outcome of such matters will not have a material adverse effect
on the Company's business, consolidated financial position, results of
operations or cash flows.
NOTE 10. 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 the Company's operations. For
the year ended December 31, 2001, the Company sold 10% or more of its net
production of oil and natural gas to the following purchasers: Conoco 14%, Hunt
Refining 13%, EOTT Energy 12%, and Dynegy 12%. For the year ended December 31,
2000, four purchasers each accounted for more than 10% of the Company's net
production of oil and natural gas and 67% in the aggregate. For the year ended
December 31, 1999, four purchasers each accounted for more than 10% of the
Company's net production of oil and natural gas and 68% in the aggregate.
EX 13-73
Notes to Consolidated Financial Statements
Supplemental Cash Flow Information
Cash paid for interest and income taxes for each of the three years in the
period ended December 31, 2001 is as follows:
YEAR ENDED DECEMBER 31,
----------------------------------------
AMOUNTS IN THOUSANDS 2001 2000 1999
- --------------------------------------------------------------------------------
Interest paid $17,451 $13,936 $15,805
Income taxes paid 2,482 275 -
- --------------------------------------------------------------------------------
In connection with the Company's acquisition of Matrix, the Company had non-cash
increases to property and equipment resulting from the issuance of the Company's
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
The carrying amounts and estimated fair values of the Company's debt instruments
at December 31, 2001 and 2000 are as follows:
DECEMBER 31,
2001 2000
- ----------------------------------------------------------------------------------------------------
Estimated Estimated
Carrying Fair Carrying Fair
AMOUNTS IN THOUSANDS Amount Value Amount Value
- ----------------------------------------------------------------------------------------------------
Senior bank debt $ 140,870 $ 140,870 $ 74,000 $ 74,000
9% Senior Subordinated Notes due 2008 125,000 117,500 125,000 108,400
9% Series B Senior Subordinated Notes due 2008 68,899 70,500 - -
- ----------------------------------------------------------------------------------------------------
As of December 31, 2001 and 2000, the carrying value of the Company's bank debt
approximated fair value based on the fact that the Company's bank debt is
subject to short-term floating interest rates that approximated the rates
available to the Company at those periods. The fair values of the Company's
senior subordinated notes is based on quoted market prices. The Company's other
financial instruments are primarily cash, cash equivalents, short-term
receivables and payables which approximate fair value due to the nature of the
instrument and the relatively short maturities.
NOTE 11. 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.
EX 13-74
Notes to Consolidated Financial Statements
Costs incurred in oil and natural gas activities for the years ended December
31, 2001, 2000 and 1999 are as follows:
Year Ended December 31,
AMOUNTS IN THOUSANDS 2001 2000 1999
- --------------------------------------------------------------------------------
Property acquisitions:
Proved (1) $ 127,066 $ 50,285 $ 20,488
Unevaluated 37,051 11,741 1,283
Exploration 11,692 6,782 7,672
Development 151,366 65,213 25,524
- --------------------------------------------------------------------------------
Total costs incurred $ 327,175 $ 134,021 $ 54,967
================================================================================
(1) Excludes deferred taxes recorded in the acquisition of Matrix of $53.1
million in 2001.
Oil and Natural Gas Operating Results
Results of operations from oil and natural gas producing activities excluding
corporate overhead and interest costs for the years ended December 31, 2001,
2000 and 1999 are as follows:
Year Ended December 31,
AMOUNTS IN THOUSANDS 2001 2000 1999
- --------------------------------------------------------------------------------------------------------------------------------
Oil, natural gas and related product sales $ 260,398 $ 204,636 $ 90,991
Gain (loss) on settlements of derivative contracts 18,654 (25,264) (9,416)
- --------------------------------------------------------------------------------------------------------------------------------
Total revenues 279,052 179,372 81,575
- --------------------------------------------------------------------------------------------------------------------------------
Lease operating costs 55,049 38,676 26,029
Production taxes and marketing expenses 10,963 8,051 3,662
Depletion and depreciation 69,773 36,214 25,515
Loss on Enron related assets 25,164 - -
Amortization of derivative contracts and other
other non-cash hedging adjustments 7,816 - -
- --------------------------------------------------------------------------------------------------------------------------------
Net operating income 110,287 96,431 26,369
Income tax provision (benefit) 35,526 (67,294) -
- --------------------------------------------------------------------------------------------------------------------------------
Results of operations from oil and natural gas producing activities $ 74,761 $ 163,725 $ 26,369
================================================================================================================================
Oil and Natural Gas Reserves
Net proved oil and natural gas reserve estimates as of December 31, 2001 and
2000 were prepared by DeGolyer and MacNaughton, and as of December 31, 1999 were
prepared by Netherland & Sewell, 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.
EX 13-75
Notes to Consolidated Financial Statements
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 the Company's oil and natural
gas reserves or the costs that would be incurred to obtain equivalent reserves.
All of the reserves are located in the United States.
Estimated Quantities of Reserves
YEAR ENDED DECEMBER 31,
2001 2000 1999
- -------------------------------------------------------------------------------------------------------------------
Oil Gas Oil Gas Oil Gas
(MBbl) (MMcf) (MBbl) (MMcf) (MBbl) (MMcf)
- -------------------------------------------------------------------------------------------------------------------
BALANCE AT BEGINNING OF YEAR 70,667 100,550 51,832 50,438 28,250 48,803
Revisions of previous estimates 4,344 (631) 4,078 8,271 83 418
Revisions due to price changes (7,800) (2,745) 412 1,905 15,884 75
Extensions and discoveries 2,308 66,448 2,746 25,593 4,383 8,910
Improved recovery (1) 1,667 - 16,466 5,613 - -
Production (6,197) (31,112) (5,555) (13,533) (4,413) (10,201)
Acquisition of minerals in place 11,501 65,767 1,182 23,209 7,722 2,693
Sales of minerals in place - - (494) (946) (77) (260)
- -------------------------------------------------------------------------------------------------------------------
BALANCE AT END OF YEAR 76,490 198,277 70,667 100,550 51,832 50,438
===================================================================================================================
PROVED DEVELOPED RESERVES
Balance at beginning of year 52,353 77,358 32,767 41,635 20,357 44,995
Balance at end of year 54,722 169,897 52,353 77,358 32,767 41,635
- -------------------------------------------------------------------------------------------------------------------
(1) For years prior to December 31, 2000, the changes related to improved
recovery were not material and were included with revisions of previous
estimates.
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 the Company's oil and natural
gas properties. An estimate of such value should consider, among other factors,
anticipated future prices of oil and natural gas, the probability of recoveries
in excess of existing proved reserves, the value of probable reserves and
acreage prospects, and perhaps different discount rates. It should be noted that
estimates of reserve quantities, especially from new discoveries, are inherently
imprecise and subject to substantial revision.
Under the Standardized Measure, future cash inflows were estimated by applying
year-end prices, adjusted for fixed and determinable escalations, to the
estimated future production of year-end proved reserves. The product prices used
in calculating these reserves have varied widely during the three year period.
These prices have a significant impact on both the quantities and value of the
proven reserves as the reduced oil price causes wells to reach the end of their
economic life much sooner and can make certain proved undeveloped locations
uneconomical, both of which reduce the reserves. The following representative
oil and natural gas year-end prices were used in the Standardized Measure. These
prices were adjusted by field to arrive at the appropriate corporate net price.
EX 13-76
NOtes to Consolidated Financial Statements
YEAR ENDED DECEMBER 31,
2001 2000 1999
- --------------------------------------------------------------------------------
Oil (NYMEX) $ 19.84 $ 26.80 $ 25.60
Natural Gas (NYMEX Henry Hub) 2.57 9.78 2.12
- --------------------------------------------------------------------------------
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 the Company's 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 2001 2000 1999
- -----------------------------------------------------------------------------------------------------------------------------
Future cash inflows $ 1,786,884 $ 2,609,306 $ 1,222,590
Future production costs (655,363) (600,195) (370,385)
Future development costs (178,546) (95,068) (69,642)
- -----------------------------------------------------------------------------------------------------------------------------
Future net cash flows before taxes 952,975 1,914,043 782,563
10% annual discount for estimated timing of cash flows (378,647) (755,074) (319,693)
- -----------------------------------------------------------------------------------------------------------------------------
Discounted future net cash flows before taxes 574,328 1,158,969 462,870
Discounted future income taxes (68,533) (317,670) (14,496)
- -----------------------------------------------------------------------------------------------------------------------------
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS $ 505,795 $ 841,299 $ 448,374
=============================================================================================================================
The following table sets forth an analysis of changes in the Standardized
Measure of Discounted Future Net Cash Flows from proved oil and natural gas
reserves:
Year Ended December 31,
Amounts in Thousands 2001 2000 1999
- ------------------------------------------------------------------------------------------------------------------------------
BEGINNING OF YEAR $ 841,299 $ 448,374 $ 115,019
Sales of oil and natural gas produced, net of production costs (194,386) (157,909) (61,300)
Net changes in sales prices (838,124) 281,181 262,660
Extensions and discoveries, less applicable future development
and production costs 123,214 200,966 48,918
Improved recovery (1) 5,045 77,702 -
Previously estimated development costs incurred 64,072 20,623 8,402
Revisions of previous estimates, including revised estimates of
development costs, reserves and rates of production (13,290) 48,018 6,433
Accretion of discount 115,897 46,287 11,502
Acquisition of minerals in place 152,931 183,634 71,631
Sales of minerals in place - (4,403) (395)
Net change in income taxes 249,137 (303,174) (14,496)
- ------------------------------------------------------------------------------------------------------------- ---------------
END OF YEAR $ 505,795 $ 841,299 $ 448,374
============================================================================================================= ===============
(1) For years prior to December 31, 2000, the changes related to improved
recovery were not material and were included with revisions of previous
estimates.
EX 13-77
Notes to Consolidated Financial Statements
CO2 Reserves
At December 31, 2001, based on an engineering report prepared by DeGolyer and
MacNaughton, the Company's CO2 reserves, on a working interest basis, were
estimated at 815 Bcf.
NOTE 12. CONDENSED CONSOLIDATING FINANCIAL INFORMATION
As of December 31, 2001, all of the Company's subordinated debt securities are
fully and unconditionally guaranteed by Denbury Resources Inc.'s significant
subsidiaries. Condensed consolidating financial information for Denbury
Resources Inc. and its significant subsidiaries for the years ended December 31,
2001, 2000 and 1999 is as follows:
CONDENSED CONSOLIDATING BALANCE SHEETS
Denbury Denbury
Resources Resources
Inc. (Parent Guarantor Inc.
Amounts in Thousands and Issuer) Subsidiaries Eliminations Consolidated
- ---------------------------------------------------------------------------------------------------------------
DECEMBER 31, 2001
ASSETS
Current assets $ 98,182 $ 5,096 $ - $ 103,278
Property and equipment 445,693 222,314 - 668,007
Investment in subsidiaries (equity method) 164,830 - (164,830) -
Other assets 15,684 3,019 - 18,703
- ---------------------------------------------------------------------------------------------------------------
Total assets $ 724,389 $ 230,429 $ (164,830) $ 789,988
===============================================================================================================
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities $ 68,937 $ 11,001 $ - $ 79,938
Long-term liabilities 306,284 54,598 - 360,882
Stockholders' equity 349,168 164,830 (164,830) 349,168
- ---------------------------------------------------------------------------------------------------------------
Total liabilities and stockholders' equity $ 724,389 $ 230,429 $ (164,830) $ 789,988
===============================================================================================================
DECEMBER 31, 2000
ASSETS
Current assets $ 89,235 $ 8,755 $ - $ 97,990
Property and equipment 307,514 - - 307,514
Investment in subsidiaries (equity method) 5,671 - (5,671) -
Other assets 51,080 795 - 51,875
- ---------------------------------------------------------------------------------------------------------------
Total assets $ 453,500 $ 9,550 $ (5,671) $ 457,379
===============================================================================================================
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities $ 34,907 $ 3,879 $ $ - 38,786
Long-term liabilities 202,428 - - 202,428
Stockholders' equity 216,165 5,671 (5,671) 216,165
- ---------------------------------------------------------------------------------------------------------------
Total liabilities and stockholders' equity $ 453,500 $ 9,550 $ (5,671) $ 457,379
===============================================================================================================
EX 13-78
Notes to Consolidated Financial Statements
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
Denbury Denbury
Resources Resources
Inc. (Parent Guarantor Inc.
Amounts in Thousands and Issuer) Subsidiaries Eliminations Consolidated
- ---------------------------------------------------------------------------------------------------------------
YEAR ENDED DECEMBER 31, 2001
Revenues $ 261,678 $ 23,433 $ - $ 285,111
Expenses 181,346 22,391 - 203,737
- ---------------------------------------------------------------------------------------------------------------
Income before the following: 80,332 1,042 - 81,374
Equity in net earnings of subsidiaries 653 - (653) -
- ---------------------------------------------------------------------------------------------------------------
Income (loss) before income taxes 80,985 1,042 (653) 81,374
Income tax provision 24,435 389 - 24,824
- ---------------------------------------------------------------------------------------------------------------
Net income (loss) $ 56,550 $ 653 $ (653) $ 56,550
===============================================================================================================
YEAR ENDED DECEMBER 31, 2000
Revenues $ 180,538 $ 1,113 $ - $ 181,651
Expenses 106,805 (87) - 106,718
- ---------------------------------------------------------------------------------------------------------------
Income before the following: 73,733 1,200 - 74,933
Equity in net earnings of subsidiaries 1,200 - (1,200) -
- ---------------------------------------------------------------------------------------------------------------
Income before income taxes 74,933 1,200 (1,200) 74,933
Income tax benefit (67,294) - - (67,294)
- ---------------------------------------------------------------------------------------------------------------
Net income (loss) $ 142,227 $ 1,200 $ (1,200) $ 142,227
===============================================================================================================
YEAR ENDED DECEMBER 31, 1999
Revenues $ 82,002 $ 988 $ - $ 82,990
Expenses 78,109 267 - 78,376
- ---------------------------------------------------------------------------------------------------------------
Income before the following: 3,893 721 - 4,614
Equity in net earnings of subsidiaries 721 - (721) -
- ---------------------------------------------------------------------------------------------------------------
Income (loss) before income taxes 4,614 721 (721) 4,614
Income tax provision - - - -
- ---------------------------------------------------------------------------------------------------------------
Net income (loss) $ 4,614 $ 721 $ (721) $ 4,614
===============================================================================================================
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
Denbury Denbury
Resources Inc. Resources
(Parent and Guarantor Inc.
Amounts in Thousands Issuer) Subsidiaries Eliminations Consolidated
- ---------------------------------------------------------------------------------------------------------------
YEAR ENDED DECEMBER 31, 2001
Cash flow from operations $ 154,034 $ 31,013 $ - $ 185,047
Cash flow from investing activities (294,253) (24,577) - (318,830)
Cash flow from financing activities 134,986 - - 134,986
- ---------------------------------------------------------------------------------------------------------------
Net increase (decrease) in cash flow (5,233) 6,436 - 1,203
Cash, beginning of period 22,285 8 - 22,293
- ---------------------------------------------------------------------------------------------------------------
Cash, end of period $ 17,052 $ 6,444 $ - $ 23,496
===============================================================================================================
EX 13-79
Notes to Consolidated Financial Statements
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS (CONTINUED)
Denbury Denbury
Resources Inc. Resources
(Parent and Guarantor Inc.
Amounts in Thousands Issuer) Subsidiaries Eliminations Consolidated
- ---------------------------------------------------------------------------------------------------------------
YEAR ENDED DECEMBER 31, 2000
Cash flow from operations $ 98,004 $ (2,032) $ - $ 95,972
Cash flow from investing activities (133,040) - - (133,040)
Cash flow from financing activities 47,593 - - 47,593
- ---------------------------------------------------------------------------------------------------------------
Net increase (decrease) in cash flow 12,557 (2,032) - 10,525
Cash, beginning of period 9,728 2,040 - 11,768
- ---------------------------------------------------------------------------------------------------------------
Cash, end of period $ 22,285 $ 8 $ - $ 22,293
===============================================================================================================
YEAR ENDED DECEMBER 31, 1999
Cash flow from operations $ 40,376 $ 824 $ - $ 41,200
Cash flow from investing activities (58,295) - - (58,295)
Cash flow from financing activities 26,814 - - 26,814
- ---------------------------------------------------------------------------------------------------------------
Net increase in cash flow 8,895 824 - 9,719
Cash, beginning of period 833 1,216 - 2,049
- ---------------------------------------------------------------------------------------------------------------
Cash, end of period $ 9,728 $ 2,040 $ - $ 11,768
===============================================================================================================
NOTE 13. UNAUDITED QUARTERLY INFORMATION
The following table presents unaudited summary financial information on a
quarterly basis for 2001 and 2000:
In Thousands Except Per Share Amounts March 31 June 30 Sept. 30 December 31
- -------------------------------------------------------------------------------------------------------------------
2001
Revenues $ 79,180 $ 67,407 $ 74,318 $ 64,206
Expenses 37,960 35,484 52,178 78,115
Net income 25,969 20,111 13,948 (3,478)
Net income per share:
Basic 0.56 0.44 0.27 (0.07)
Diluted 0.55 0.42 0.26 (0.07)
Cash flow from operations (a) 54,982 45,194 48,670 37,955
Cash flow used for investing activities 70,391 44,891 139,993 63,555
Cash flow provided by financing activities 8,530 10,820 95,297 20,339
- -------------------------------------------------------------------------------------------------------------------
EX 13-80
Notes to Consolidated Financial Statements
In Thousands Except Per Share Amounts March 31 June 30 Sept. 30 December 31
- ------------------------------------------------ ------------------------------------------------------------------
2000
Revenues $ 35,767 $ 37,550 $ 44,749 $ 63,585
Expenses 24,232 23,927 25,629 32,930
Net income 11,515 13,603 19,039 98,070
Net income per share:
Basic 0.25 0.30 0.42 2.14
Diluted 0.25 0.30 0.41 2.09
Cash flow from operations (a) 19,562 21,340 27,502 43,151
Cash flow used for investing activities 16,088 21,462 24,069 71,421
Cash flow provided by (used for) financing
activities 308 (3,806) (2,131) 53,222
(a) Exclusive of the net change in non-cash working capital balances.
Common Stock Trading Summary
The following table summarizes the high and low last reported sales prices on
days in which there were trades of the Company's common stock on the New York
Stock Exchange ("NYSE"), and on The Toronto Stock Exchange ("TSE") (as reported
by such exchange) for each quarterly period for the last two fiscal years. The
trades on the NYSE are reported in U.S. dollars and the TSE trades are reported
in Canadian dollars. The Company plans to de-list from the TSE effective April
15, 2002.
As of February 1, 2002, to the best of the Company's knowledge, the common stock
was held of record by approximately 1,200 holders, of which approximately 300
were U.S. residents holding approximately 90% of the outstanding common stock of
the Company.
The Company has never paid any dividends on its common stock and currently does
not anticipate paying any dividends in the foreseeable future. The Company is
restricted from declaring or paying any cash dividends on its common stock under
its bank loan agreement.
NYSE (U.S. $) TSE (CDN $)
HIGH LOW HIGH LOW
- ---------------------------------------------------------------------------------------------------------------
2001
First quarter $ 12.00 $ 7.90 $ 19.00 $ 12.22
Second quarter 12.30 7.30 18.78 11.80
Third quarter 9.75 7.50 14.90 11.86
Fourth quarter 8.81 6.00 13.53 9.38
- ---------------------------------------------------------------------------------------------------------------
2001 annual $ 12.30 $ 6.00 $ 19.00 $ 9.38
- ---------------------------------------------------------------------------------------------------------------
2000
First quarter $ 4.56 $ 3.75 $ 7.00 $ 4.80
Second quarter 6.38 3.75 9.50 5.00
Third quarter 8.44 4.31 12.65 5.80
Fourth quarter 11.44 6.31 16.80 9.30
- ---------------------------------------------------------------------------------------------------------------
2000 annual $ 11.44 $ 3.75 $ 16.80 $ 4.80
- ---------------------------------------------------------------------------------------------------------------
EX 13-81