EXHIBIT 13
DENBURY RESOURCES, INC.
PAGE 1 AND PAGES 6 THROUGH 47, INCLUSIVE, OF THE COMPANY'S ANNUAL REPORT TO
SHAREHOLDERS FOR THE YEAR ENDED DECEMBER 31, 1997, 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.
Financial Highlights
YEAR ENDED DECEMBER 31,
-------------------------------------------------------------- AVERAGE
AMOUNTS IN THOUSANDS OF U.S. ANNUAL
DOLLARS UNLESS NOTED 1997 1996 1995 1994 1993 GROWTH (2)
- ---------------------------------------------------------------------------------------------------------------------
PRODUCTION (DAILY)
Oil (Bbls) 7,902 4,099 1,995 1,340 858 74%
Gas (Mcf) 36,319 24,406 13,271 9,113 2,013 106%
BOE (6:1) 13,955 8,167 4,207 2,858 1,193 85%
REVENUE (NET OF ROYALTIES)
Oil sales 49,748 28,475 10,852 6,767 4,356 84%
Gas sales 35,585 24,405 9,180 5,925 1,512 120%
Total 85,333 52,880 20,032 12,692 5,868 95%
UNIT SALES PRICE
Oil (per Bbl) 17.25 18.98 14.90 13.84 13.91 6%
Gas (per Mcf) 2.68 2.73 1.90 1.78 2.06 7%
CASH FLOW FROM OPERATIONS (1) 56,607 34,140 9,394 6,185 3,030 108%
NET INCOME 14,903 8,744 714 1,163 1,735 71%
AVERAGE COMMON SHARES OUTSTANDING 20,224 13,104 6,870 6,240 4,990 42%
PER SHARE:
Cash flow from operations: (1)
Basic 2.80 2.51 1.37 0.99 0.61 47%
Fully diluted 2.57 2.07 1.37 0.99 0.61 43%
Net income:
Basic 0.74 0.67 0.10 0.19 0.35 21%
Fully diluted 0.70 0.62 0.10 0.19 0.35 19%
OIL AND GAS CAPITAL INVESTMENTS 305,427 86,857 28,524 16,903 29,855 79%
TOTAL ASSETS 447,548 166,505 77,641 48,964 35,978 88%
LONG-TERM LIABILITIES 256,637 7,481 5,077 17,768 6,633 149%
SHAREHOLDERS' EQUITY AND
PREFERRED STOCK 160,223 142,504 68,501 25,962 24,431 60%
PROVEN RESERVES
Oil (MBbls) 52,018 15,052 6,292 4,230 3,583 95%
Gas (MMcf) 77,191 74,102 48,116 42,046 13,029 56%
MBOE (6:1) 64,883 27,403 14,312 11,237 5,755 83%
Discounted future cash flow - 10% 361,329 316,098 96,952 52,691 28,638 88%
PER BOE DATA (6:1)
Revenue 16.75 17.69 13.05 12.17 13.47 6%
Production expenses (4.36) (4.51) (4.42) (4.13) (4.75) (2)%
- ---------------------------------------------------------------------------------------------------------------------
Production netback 12.39 13.18 8.63 8.04 8.72 9%
General and administrative expenses (1.30) (1.50) (1.25) (1.12) (1.80) (8)%
Interest and other income (expense) 0.02 (0.26) (1.26) (0.99) 0.04 (16)%
- ---------------------------------------------------------------------------------------------------------------------
CASH FLOW (1) 11.11 11.42 6.12 5.93 6.96 12%
- ---------------------------------------------------------------------------------------------------------------------
<FN>
(1) Exclusive of the net change in non-cash working capital balances.
(2) Computed using 1993 as a base year.
</FN>
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 are converted to equivalent barrels at
6:1.
1
Selected Operating Data
OIL AND GAS RESERVES
The reserves at December 31, 1997, 1996 and 1995 were estimated by Netherland,
Sewell & Associates, Inc., an independent Dallas-based engineering firm. 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 31st 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 the net revenue interest (after royalties) of the Company.
AS OF DECEMBER 31,
-----------------------------
1997 1996 1995
--------- -------- -------
ESTIMATED PROVED RESERVES:
Oil (MBbls)............................. 52,108 15,052 6,292
Natural Gas (MMcf)...................... 77,191 74,102 48,116
Oil Equivalent (MBOE)................... 64,883 27,403 14,311
PERCENTAGE OF MBOE:
Proved producing........................ 40% 45% 38%
Proved non-producing.................... 26% 39% 40%
Proved undeveloped...................... 34% 16% 22%
REPRESENTATIVE OIL AND GAS PRICES: (1)
West Texas Intermediate.................$ 16.18 $ 23.39 $ 18.00
NYMEX Henry Hub......................... 2.58 3.90 2.24
PRESENT VALUES:
Discounted estimated future net cash
flow before income taxes (PV10 Value)
(thousands) (2).........................$361,329(3) $316,098(4) $ 96,965
Standardized measure of discounted
estimated future net cash flow after net
income taxes (thousands)...............$335,308 $241,872 $ 81,164
- ---------------
<FN>
(1) The oil prices as of each respective year-end were based on West Texas
Intermediate "WTI" posted prices per barrel 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.
(3) For comparative purposes the Company also prepared a reserve report as of
December 31, 1997 using the prices used in the December 31, 1996 reserve
report. The PV10 Value in this report was $633.4 million with 67.8 MMBOE of
proved reserves. Of the PV10 Value $206.7 million was attributable to the
Chevron Acquisition. As opposed to a PV10 Value of $109.4 million using
December 31, 1997 prices.
(4) For comparative purposes the Company prepared a December 31, 1996 reserve
report using a WTI price of $21.00 per Bbl and a NYMEX price of $2.40 per
MMBtu with these prices also adjusted by field. The PV10 Value in this
report was $213.7 million with 27.0 MMBOE of proved reserves. For the year
ended December 31, 1997, the average WTI price was approximately $18.62 per
Bbl and the average NYMEX price was approximately $2.59 per MMBtu.
</FN>
CAPITAL EXPENDITURES
Denbury's commitment to future growth is best demonstrated by its reinvestment
levels. The major components of the Company's capital expenditure programs over
the last three years are as follows:
(Amounts in Thousands) Year Ended December 31,
-------------------------------
1997 1996 1995
--------- --------- ---------
Property acquisition................... $ 226,809 $ 48,856 $ 17,198
Exploration............................ 20,734 4,592 1,687
Development............................ 57,884 33,409 9,639
--------- --------- ---------
TOTAL CAPITAL EXPENDITURES $ 305,427 $ 86,857 $ 28,524
========= ========= =========
FINDING COST
Finding costs are one of the primary critical factors in determining a company's
profitability. Excluding the recent Chevron Acquisition approximately one-half
of the Company's reserves have come from acquisitions and one-half of its
reserves from exploitation and development. The finding cost for each of these
activities can vary widely depending on market conditions, drilling costs, etc.
In addition, one must also look at the type of reserves acquired as the cost per
BOE will vary depending on the
6
netbacks, timing of cash flow, etc. In the finding cost calculation all oil and
gas expenditures incurred, including capital expenditures which will benefit
future years such as seismic surveys, prospect costs and undeveloped properties
have been included in the calculations. The forecasted future development costs
as outlined in the independent engineer's reserve forecast have not been
included in the calculation. The reserves are obtained from the unescalated SEC
price case using the Company's net revenue interest plus applicable historical
production, BOE equivalents are calculated using six Mcf per one barrel of oil.
THREE YEAR INCEPTION
AVERAGE TO
1997 1995-1997 DATE
- ----------------------------------------------------------------------------
Total capitalized costs (millions) $ 305.4 $ 420.8 $ 471.6
Proved reserve additions and production (MMBOE) 42.6 63.3 76.1
- ----------------------------------------------------------------------------
AVERAGE FINDING COST PER BOE (6:1) $ 7.17 $ 6.65 $ 6.20
- ----------------------------------------------------------------------------
The above table includes $75 million of cost relating to the Chevron Acquisition
which was allocated to unevaluated properties as of December 31, 1997. The
average finding cost per BOE would be $5.41, $5.47 and $5.21 for 1997, the
three-year average and inception to date amounts respectively if the $75 million
were excluded from the calculation.
FIELD SUMMARIES
Denbury operates in two core areas, Louisiana and Mississippi. The eight largest
fields owned by the Company constitute approximately 85% and 82%, respectively,
of its total proved reserves on a BOE and PV10 Value basis. Within these eight
fields the Company owns an average 91% working interest and operates 85% of the
wells which comprise 71% of the Company's PV10 Value. These eight largest fields
are located in three adjacent counties in Mississippi and one parish in
Louisiana. The concentration of value in a relatively small number of fields
allows the Company to benefit substantially from any operating cost reductions
or production enhancements and allows the Company to effectively manage the
properties from its two field offices in Houma, Louisiana and Laurel,
Mississippi.
1997 Average
Proved Reserves as of December 31, 1997 (1) Average Production (2) Net
-------------------------------------------- --------------------- Gross Revenue
Oil Natural Gas PV10 Value PV10 Value Oil Natural Gas Productive Interest
(MBbls) (MMcf) (000's) % of Total (Bbls/d) (Mcf/d) Wells (3) (3)
- ------------------------------------------------------------------------------------------------------------------------------------
LOUISIANA
Lirette 289 27,746 $ 44,668 12.4% 174 10,880 18 63.0%
Bayou Rambio 69 11,353 18,205 5.0% 46 3,492 3 59.1%
Gibson 302 6,631 12,658 3.5% 251 4,988 3 57.8%
South Chauvin 135 7,333 9,734 2.7% 51 2,736 4 73.4%
Other Louisiana 1,423 15,048 33,192 9.2% 1,218 11,378 82 48.7%
- ------------------------------------------------------------------------------------------------------------------------------------
Total Louisiana 2,218 68,111 118,457 32.8% 1,740 33,474 110 51.5%
- ------------------------------------------------------------------------------------------------------------------------------------
MISSISSIPPI
Heidelberg (4) 30,171 2,517 118,973 32.9% -(4) -(4) 122 81.0%
Eucutta 8,967 -- 58,657 16.2% 1,959 -- 45 75.3%
Quitman 3,032 -- 19,064 5.3% 1,470 -- 18 60.7%
Davis 2,660 -- 13,348 3.7% 1,181 -- 25 90.5%
Other Mississippi 4,834 5,597 29,667 8.2% 1,474 2,437 87 53.1%
- ------------------------------------------------------------------------------------------------------------------------------------
Total Mississippi 49,664 8,114 239,709 66.3% 6,084 2,437 297 66.5%
- ------------------------------------------------------------------------------------------------------------------------------------
OTHER 136 966 3,163 0.9% 78 408 -- -%
- ------------------------------------------------------------------------------------------------------------------------------------
COMPANY TOTAL 52,018 77,191 $361,329 100.0% 7,902 36,319 407 60.7%
====================================================================================================================================
<FN>
(1) The reserves were prepared using constant prices and costs in accordance
with the guidelines of the SEC, based on the prices received on a
field-by-field basis as of December 31, 1997. The oil price at that date
was WTI $16.18 per Bbl adjusted by field and a NYMEX natural gas price
average of $2.58 per MMBtu, also adjusted by field.
(2) This table does not include production on the properties acquired in the
Chevron Acquisition on December 30, 1997.
(3) Includes only productive wells in which the Company has a working interest
as of December 31, 1997.
(4) Property acquired in the Chevron Acquisition plus three other minor
acquisitions. The average net production on the properties acquired in the
Chevron Acquisition from October 1, 1997 through December 31, 1997 was
2,800 Bbls/d and 650 MCF/d.
</FN>
7
[ONE ILLUSTRATION, NOT INCORPORATED BY REFERENCE - SEE PREFACING COMMENT ON
EXHIBIT 13 COVER PAGE]
8
ACQUISITIONS OF OIL AND NATURAL GAS PROPERTIES
The Company regularly seeks to acquire properties that complement its
operations, provide exploitation, exploration and development opportunities and
have cost reduction potential. During 1997, Denbury completed a total of 17
separate acquisitions for a total expenditure of $224.1 million, of which 14 of
these acquisitions were in Mississippi and 3 were in Louisiana. The largest
acquisition of the Company to date was the purchase of the Heidelberg Field from
Chevron (the "Chevron Acquisition") which was completed at year-end 1997. Other
less significant acquisitions during 1997 included the acquisition of additional
interest at the Lirette Field in Louisiana and the Davis Field in Mississippi,
plus new interest at the Crawford Creek Field, also in Mississippi.
Chevron Property Acquisition
On December 30, 1997, the Company acquired oil properties in the Heidelberg
Field, Jasper County, Mississippi, from Chevron for approximately $202 million.
The Chevron Acquisition represents the largest acquisition by the Company to
date. The Heidelberg Field is adjacent to the Company's other primary oil
properties in Mississippi and includes 122 producing wells, 96 of which the
Company will operate. The Company purchased an average working interest of 94%
and an average net revenue interest of 81% in these 96 wells, which wells
account for approximately 99% of the field's average net daily production. The
average net daily production from these properties during the fourth quarter of
1997 was approximately 2,800 Bbls/d and 650 Mcf/d.
The Chevron Acquisition added proved reserves as of December 31, 1997 of
approximately 27.2 MMBbls and 2.5 Bcf, or approximately 27.6 MMBOE. As a result
of the significant amount of future development and exploitation to be performed
on these properties and the increase in future reserves and production that the
Company expects to result from such development and exploitation, the Company
has attributed $75 million of the purchase price to unevaluated properties.
The Company has scheduled several potential development projects for 1998 during
its initial evaluation of the Heidelberg Field. These include initiating a
waterflood project, upgrading lift capacity in over 12 wells, recompleting 30
wells in new zones and drilling 41 wells. Horizontal wells drilled by the
Company in 1997 at nearby Davis, Quitman and Eucutta Fields improved daily
production rates significantly as compared to vertical wells drilled in the same
fields. Consequently, the Company anticipates that 31 of the 41 proposed wells
in the Heidelberg Field will be horizontal wells. The Company's total 1998
development budget for the Heidelberg Field is approximately $30 million.
Update on 1996 Acquisitions
The Company completed several property acquisitions during 1996, the largest of
which was the acquisition of producing oil and natural gas properties in
Mississippi, Louisiana and Alabama, plus certain overriding royalty interests in
Ohio, for approximately $37.2 million from Amerada Hess, effective May 1, 1996
(the "Hess Acquisition"). The average daily production from the properties
included in the Hess Acquisition during May and June 1996, the first two months
of ownership, was approximately 2,945 BOE/d. The average daily production on
these properties had increased to 5,373 BOE/d by the fourth quarter of 1997 and
had further increased to approximately 8,400 BOE/d during the month of January
1998.
As of December 31, 1997, in the Company's independent reserve report (the
"December Report"), the properties in the Hess Acquisition had estimated net
proved reserves of approximately 14.2 MMBOE with a PV10 Value of $95.1 million.
This compares to approximately 5.9 MMBOE of net proved reserves and a $43.1
million PV10 Value on these same properties as reported in the Company's
independent reserve report dated July 1, 1996 (the "July Report"). The December
Report was calculated using year-end prices which were based on a WTI price of
$16.18 per Bbl and a NYMEX price of $2.58 per Mcf, with these representative
prices adjusted by field to arrive at the appropriate corporate net price, as
compared to oil and gas prices of $20.00 and $2.65, respectively, in the July
Report. In addition to the increase in proved reserves, the Company produced
approximately 2.6 MMBOE from July 1, 1996 through December 31, 1997 with total
net operating income of $30.5 million. As of December 31, 1997, the Company had
a remaining net investment in these properties of approximately $43.4 million.
9
Company Business Strategy
The Company seeks to: (i) achieve attractive returns on capital through prudent
acquisitions, development and exploratory drilling and efficient operations;
(ii) maintain a conservative balance sheet to preserve maximum financial and
operational flexibility; and (iii) create strong employee incentives through
equity ownership. The Company believes that its growth to date in proved
reserves, production and cash flow is a direct result of its adherence to the
following fundamental principles which are at the core of the Company's
long-term growth strategy:
Experienced and Incentivized Personnel
The Company intends to maintain a highly competitive team of experienced and
technically proficient employees and motivate them through a positive work
environment and stock ownership in the Company. The Company's 29 geological and
engineering professionals have an average of over 15 years of experience in the
Gulf Coast region. The Company believes that employee ownership, which is
encouraged through the Company's stock option and stock purchase plans, is
essential for attracting, retaining and motivating quality personnel. The
Company believes that all employees are important to the success of the Company
and as such grants bonuses and stock options to both management and employees on
a basis roughly proportional to salaries.
Regional Focus
By focusing its efforts in the Gulf Coast region, primarily Louisiana and
Mississippi, the Company has been able to accumulate substantial geological and
reservoir data and operating experience which it believes provides it with
significant competitive advantages. The Company believes the Gulf Coast
represents one of the most attractive regions in North America given the
region's prolific production history, complex geology (with multiple producing
horizons) and the opportunities that have been created by advanced technologies
such as 3-D seismic and various drilling, completion and recovery techniques.
Disciplined Acquisition Strategy
The Company intends to continue to acquire properties where it believes
significant additional value can be created. Such properties are typically
characterized by: (i) long production histories; (ii) complex geological
formations with multiple producing horizons and substantial exploitation
potential; (iii) a history of limited operational focus and capital investment,
often due to their relatively small size and limited strategic importance to the
previous owner; and (iv) the potential for the Company to gain control of
operations. The Company believes that due to continuing rationalization of
properties, primarily by major integrated and independent energy companies,
future acquisition opportunities should continue to be available. In addition,
the Company seeks to maintain a well-balanced portfolio of oil and natural gas
development, exploitation and exploration projects in order to minimize the
overall risk profile of its investment opportunities while still providing
significant upside potential.
Operation of High Working Interest Properties
The Company intends to continue to acquire working interest positions that give
it operational control or that the Company believes may lead to operational
control. Once a property is acquired, the Company employs its technical and
operational expertise to fully evaluate a field's future potential. If
favorable, it will consolidate its working interest positions, primarily through
negotiated transactions, which tend to be attractively priced compared to
acquisitions available in competitive situations. The consolidation of ownership
allows the Company to: (i) enhance the effectiveness of its technical staff by
concentrating on relatively few wells; (ii) increase production while adding
virtually no additional personnel; and (iii) increase ownership in a property so
that the potential benefits of value enhancement activities justify the
allocation of Company resources.
Exploitation of Properties
The Company intends to maximize the value of its properties through a
combination of increasing production, increasing recoverable reserves or
reducing operating costs. During 1997, the Company's primary methodology for
achieving these objectives was the use of horizontal drilling, which it also
intends to emphasize in 1998. Horizontal drilling has historically produced oil
at faster rates and with lower operating costs on a BOE basis than traditional
vertical drilling. The Company also utilizes a variety of other techniques to
maximize property values, including: (i) undertaking surface improvements such
as rationalizing, upgrading or redesigning production facilities; (ii) making
downhole improvements such as resizing downhole pumps or reperforating existing
production zones; (iii) reworking existing wells into new production zones with
additional potential; and (iv) utilizing exploratory drilling, which is
frequently based on various advanced technologies such as 3-D seismic.
10
(One illustration, not incorporated by reference - see prefacing comment on
Exhibit 13 Cover Page.)
11
Operations in Southern Louisiana
The Company's southern Louisiana producing fields are typically large structural
features containing multiple sandstone reservoirs. Current production depths
range from 7,000 feet to 16,000 feet with potential throughout the area for even
deeper production. The region produces predominantly natural gas, with most
reservoirs producing with a water-drive mechanism.
The majority of the Company's southern Louisiana fields lie in the Houma
embayment area of Terrebonne and LaFourche Parishes. The area is characterized
by complex geological structures which have produced prolific reserves, typical
of the lower Gulf Coast geosyncline. Given the swampy conditions of southern
Louisiana, 3-D seismic has only recently become feasible for this area as
improvements in field recording techniques have made the process more
economical. 3-D seismic has become a valuable tool in exploration and
development throughout the onshore Gulf Coast and has been pivotal in
discovering significant reserves. The Company currently owns or has license to
work on over 300 square miles of 3-D seismic data and plans to continue to
expand its data ownership. The Company believes that this 3-D seismic data, some
of which is the first 3-D shot in these swampy areas, has the potential to
identify significant exploration prospects, particularly in the deeper
geopressured sections below 12,000 feet.
During 1995, the Company acquired approximately 46 square miles of 3-D seismic
data over five of its existing fields in Southern Louisiana, namely Bayou
Rambio, De Large, North Deep Lake, Gibson and Humphreys. During 1996, the
Company entered into a joint venture agreement with two industry partners and
shot approximately 158 square miles of 3-D seismic data in the Terrebonne Parish
area, which includes three of the Company's existing fields, Lirette, Lapeyrouse
and North Lapeyrouse. The Company's existing productive zones are excluded from
the joint venture. Denbury owns a one-third interest in any new prospects
discovered through this joint venture that currently owns rights to over 35,000
acres within the survey area. The 3-D seismic survey is complete and two wells
have been drilled to date based on the results of the survey. One was a dry hole
and the other a successful well in the Lirette Field area. There are currently
10 identified prospect areas which have been generated as a result of the
survey, of which three should be drilled during the first half of 1998. The 3-D
seismic survey is still being reviewed for additional drilling opportunities.
Lirette Field
The Lirette structure is a large salt-cored anticline located about 10 miles
south of Houma, Louisiana, which has produced over one Tcf of natural gas from
multiple reservoirs. The field is located in six to ten feet of inland water and
produces from depths of 8,000 feet to 16,000 feet. The field was discovered in
1937, but in 1993, when the Company first acquired a 23% working interest in the
field, gross production had declined to less than 3 MMcf/d. By January 1995,
following a series of workovers of existing wells, gross production had grown to
approximately 13.2 MMcf/d and 360 Bbls/d (6.5 MMcf/d and 150 Bbls/d net).
Additional interests were acquired in 1995 and 1997 to increase the Company's
ownership to its current average 82% working interest. During January 1998 the
net production from this field averaged approximately 10.6 MMcf/d and 177 Bbls/d
from 18 wells.
During the latter half of 1996, the Lirette Field was covered by a 3-D seismic
survey which is currently being evaluated. One well was drilled in the Lirette
area in 1997, the Scana No. 1 Laterre, as a result of this 3-D seismic survey.
This well established two pay sands in the prolific Tex W interval in a southern
untested fault block and should commence production in the first half of 1998.
Two additional untested fault blocks have been identified on the Lirette
structure and are scheduled for drilling during 1998.
Gibson Field
In late 1994, Denbury acquired minor working interests in five wells in the
Gibson and adjacent Humphreys Fields located in Terrebonne Parish, 20 miles
northwest of the Lirette Field, in the northern part of the Houma embayment. The
Gibson Field, since its discovery in 1937, has produced over 813 Bcf and 14
MMBbls. During 1995, the Company acquired and processed 38 square miles of 3-D
seismic data covering these fields and in November 1995 acquired a additional
working interest in these fields. By December 1995, Denbury's acreage position
had grown to 3,165 net acres with interests in six active wells and eight
inactive wells. During January 1998, the net production in this field averaged
approximately
12
5.2 Mmcf/d and 83Bbls/d. Denbury drilled two wells in this area in 1997, one of
which was successful. This well, the Pelican A-12 found two productive intervals
and was completed in the lower most formation. This well produced at an average
rate of 460 Mcf/d net to the Company, during the month of January 1998. No wells
are currently plannned in this field for 1998.
South Chauvin Field
In February 1996, the Company purchased interests in two producing wells and
four non-producing wells in South Chauvin Field located in the Houma embayment
area, about four miles south of Houma and six miles northwest of Lirette Field.
Of the four currently producing wells at Chauvin, the Company owns an average
94% working interest. During January 1998, the net production from this field
average 2.5 MMcf/d and 29 Bbls/d. In late 1996, the Company acquired 13.7 square
miles of 3-D seismic data covering the field and is currently evaluating the
data. The Company drilled one well in this area in 1997 which produced at an
average rate of 1.3 MMcf/d and 17 Bbls/d, net to the Company, during the month
of January 1998. One well, a sidetrack of an existing well, is currently planned
in this field for 1998.
Bayou Rambio Field
Production at the Bayou Rambio Field was established in 1955 and has exceeded
150 Bcf and 920 MBbls to date. The Company operates three producing wells in the
field, which is located in Terrebonne Parish about 15 miles west of Lirette
Field. During January 1998, the net production from this field averaged 6.3
Mmcf/d and 59 Bbls/d. Two of these producing wells were drilled in 1997 based on
a review of 3-D seismic data. The Company has one additional well planned for
the first half of 1998 which will attempt to accelerate the production of the
established reserves and increase the field's PV10 Value, while also testing a
deeper sand interval which may establish additional pay sands.
Other Louisiana Fields
In addition to the above fields, the Company owns an interest in wells at 39
other fields in Louisiana, which in the aggregate averaged approximately 15.1
MMcf/d and 995 Bbls/d of net production during January 1998.
(One illustration, not incorporated by reference - see prefacing comment on
Exhibit 13 Cover Page.)
13
(One illustration, not incorporated by reference - see prefacing comment on
Exhibit 13 Cover Page.)
14
Operations in Mississippi
In Mississippi, most of the Company's production is oil, produced largely from
depths of less than 10,000 feet. Fields in this region are characterized by
relatively small geographic areas which generate prolific production from
multiple pay sands. The Company's Mississippi production is usually associated
with large amounts of saltwater, which must be disposed of in saltwater disposal
wells, and almost all wells require pumping. These factors increase the
operating costs on a per barrel basis as compared to Louisiana. The Company
places considerable emphasis on reducing these costs in order to maximize the
cash flow from this area. The Company has increased its emphasis in horizontal
drilling based on its apparent success during the past year. These horizontal
wells have contributed to the reduction of operating costs on a BOE basis during
the last twelve months, as these wells typically produce oil more efficiently,
resulting in higher production rates and better recovery efficiency.
The Company drilled its first horizontal well in 1995 at the South Thompson
Creek Field in Mississippi and drilled a subsequent horizontal well in this
field during 1996. Both of these wells were completed as producers. During the
last quarter of 1996 and through the end of 1997, the Company drilled and
completed twelve horizontal wells at an average cost of $1.05 million. These
wells produced at an average production rate of 420 Bbls/d in their initial
month of production. Although horizontal wells typically decline rapidly from
their initial production rates, these twelve wells had an average production
rate of 280 Bbls/d for the month of December 1997 and have been producing for an
average of seven months. These horizontal wells typically have a higher internal
rate of return than a comparable vertical well, reduce operating costs per BOE
and reduce the number of wells required to drain the reservoir. The Company
plans to drill over 50 horizontal wells in 1998 in Mississippi.
Heidelberg Field
Heidelberg field was discovered in 1944 and has produced an estimated 191 MMBbls
and 36 Bcf since its discovery. This Field is a large salt-cored anticline which
is divided by faulting into western and eastern segments. Production is from a
series of normally pressured Cretaceous and Jurassic sandstone horizons situated
between 4,500 feet and 11,500 feet. There are 11 producing formations in the
Heidelberg Field containing over 40 individual reservoir intervals, with the
majority of the current production coming from the Eutaw and Christmas sands at
depths of approximately 5,000 feet.
The West Heidelberg Eutaw sands have been unitized and water injection began
late in 1996 in order to increase the bottom hole pressure and improve
recoveries from the formation. A production response to the injection is
expected during 1998. The Eutaw East One Fault Block Oil Pool Unit (Eutaw
formation in East Heidelberg) was recently unitized and injection is projected
to commence in March 1998. These waterflood projects, particularly the East
Unit, comprise a significant portion of the potential reserves at Heidelberg.
The Company has a 78% working interest in the East Unit, 59% of which was
acquired in the Chevron Acquisition and the remaining 19% of which was acquired
over a three-month period from three other entities. The Company operates a
similar Eutaw unit at its East Eucutta Field, located approximately nine miles
to the southeast, with production from sands with similar porosity,
permeability, thickness, oil characteristics and drive mechanisms.
The Company has scheduled several potential development projects for 1998 during
its initial evaluation of the Heidelberg Field. These include initiating a
waterflood project, upgrading lift capacity in over 12 wells, recompleting 30
wells in new zones and drilling 41 wells. Horizontal wells drilled by the
Company in 1997 at nearby Davis, Quitman and Eucutta Fields improved daily
production rates significantly as compared to vertical wells drilled in the same
fields. Consequently, the Company anticipates that 31 of the 41 proposed wells
will be horizontal wells. The Company's total 1998 development budget for the
Heidelberg Field is approximately $30 million. During January 1998, the net
production averaged approximately 2,750 Bbls/d.
Based on its experience in other fields in the same area, particularly with
regard to the Mississippi properties acquired in the Hess Acquisition, the
Company believes that significant additional reserve potential may exist beyond
the identified proven reserves. The development budget in 1998 and ensuing years
is expected, in part, to be used to evaluate this potential which is summarized
below:
Higher oil recovery in the Eutaw sand waterfloods
Since discovery of the Heidelberg Field, total cumulative production in the
Eutaw formation through December 1997 has been 80 MMBbls, which, based upon
geological and engineering analysis, the Company estimates has recovered 22% of
the original oil in place. Based upon a similar analysis, the Company estimates
that historical cumulative production from the
15
Eutaw formation under waterflood at nearby East Eucutta Field has recovered an
estimated 34% of the oil in place. The Company believes that similar recovery
factors may be achievable at Heidelberg Field based on the geological conditions
that appear to be analogous. The Company will also attempt to improve the
recovery factors through the use of horizontal drilling and may also employ
tertiary recovery methods such as carbon dioxide injection. The Company
currently is evaluating the feasibility of such methods.
Higher oil recovery in the Christmas sands
Because of the success of the Company's horizontal drilling program in other
fields in the area, the Company intends to develop the Christmas sands primarily
through horizontal drilling. Since its discovery, the Christmas sands have
produced approximately 67 MMBbls through December 1997. The Company believes
these sands are ideal for horizontal development due to the strong natural water
drive of these reservoirs. Recent horizontal drilling by the Company has
produced oil at higher rates and reduced operating costs on a BOE basis as
compared to vertical drilling. Although Denbury believes that horizontal
drilling should ultimately increase the amount of oil recovered from the
Christmas sands, to date the Company does not have enough production history to
determine if, and to the extent, oil recoveries will increase.
Further drilling in deeper zones
The zones below the Christmas formation, including the Tuscaloosa, Paluxy,
Rodessa, Hosston, Cotton Valley and Smackover formations, have produced on a
cumulative basis a combined 44 MMBbls and 14 Bcf through December 1997. The
Company believes that additional reserve potential may exist for extensions of
existing reservoirs and potential new reservoirs in these zones within the
Heidelberg Field area. A 36-square-mile 3-D seismic program over the field was
shot by Chevron in 1993 and will be acquired under license by Denbury. The
Company intends to reprocess the 3-D seismic data to evaluate this potential.
Eucutta Field
The Eucutta Field is located about 18 miles east of Laurel, Mississippi. Since
its discovery in 1943, this field has produced 63 MMBbls and 4.7 Bcf. Denbury
acquired the majority of its interests in this field as part of the Hess
Acquisition and currently operates 45 producing oil wells and 3 saltwater
injection wells.
The Eucutta Field is divided into a shallow Eutaw sand unit in which the Company
has a 78% working interest and the deeper Tuscaloosa, Wash-Fred, Paluxy,
Rodessa, Sligo and Hosston sand zones in which the Company has an average
working interest of 99%. The Eucutta Field traps oil in multiple sandstone
reservoirs from the Eutaw to the Hosston formations in this highly faulted
anticline from depths of 5,000 to 11,000 feet. Denbury recently established new
production in the Paluxy interval in a series of six stacked sands. As of
February 28, 1998, two additional vertical delineation wells and five horizontal
wells have been drilled and completed for this Paluxy interval, with an
additional four either in progress or planned for 1998. These recently completed
horizontal wells had average initial production rates of approximately 1,300
Bbls/d. Although these wells are expected to have high initial decline rates, at
the current rate, these wells should pay out in approximately three months. The
deeper intervals of the Cotton Valley and Smackover formations have yet to be
tested in crestal positions on this structure although these two horizons have
proven to be highly productive throughout the Mississippi Salt Basin.
Bar graph illustrating Mississippi portion of Hess Acquisition
1996 1997
--------------------- ---------------------
Proved Daily Proved Daily
Reserves Production Reserves Production
--------- --------- --------- ---------
Third Quarter 4.2 1,580 First Quarter (1) 2,769
Fourth Quarter 6.8 2,323 Second Quarter (1) 3,364
Third Quarter (1) 4,079
Fourth Quarter 12.6 4,514
(1) Not available
Since its acquisition in May 1996, the Company has implemented a capital
expenditure program at Eucutta Field which included upgrading production
facilities, recompletions and drilling wells. At the time of acquisition,
production from this field was approximately 1,100 Bbls/d. All seven wells
drilled in 1997 were successful, two of which were horizontal wells. As a result
of these wells and other development work, during January 1998 the net
production increased to an average of 5,255 Bbls/d. The Company plans to shoot a
3-D seismic survey over the field and have it processed by late 1998. During
1998, the Company also plans to drill 16 wells, of which nine will be horizontal
wells.
16
Davis Field.
The Davis Field is located 42 miles northeast of Laurel in the northern part of
the Mississippi salt basin. Denbury operates 36 producing wells within the area.
Davis is a compact anticline that has produced over 21 MMBbls since its
discovery by Conoco in 1969. Over 30 sands have produced oil between the
intervals of 5,000 feet and 8,000 feet. At the time of acquisition in 1993, the
gross production from this field was approximately 700 Bbls/d. During the month
of January 1998, the gross production was approximately 920 Bbls/d with net
production of 823 Bbls/d.
The Davis Field is a relatively mature field and produces large amounts of
saltwater. During January 1998, the field produced an average of approximately
50,000 barrels of saltwater per day, all of which were re-injected into the
ground. The Company places considerable emphasis on controlling operating costs
in this field by minimizing the cost of saltwater disposal and pumping
equipment.
Since acquiring the majority of the Davis Field in 1993, Denbury has undertaken
an active redevelopment program including numerous workovers and several
development wells. As a result of this work and continued reductions in
operating costs, the Company has been able to steadily increase the proven
reserves every year. During 1996, the Company drilled two successful horizontal
wells to improve withdrawal efficiency and drilled an additional three
horizontal wells in 1997, with one additional well in progress as of December
31, 1997. The Company plans to drill three to five wells in this field during
1998, of which all but one will be horizontal wells.
Quitman Field
The Quitman Field is located in Clarke County, Mississippi, 31 miles northeast
of Laurel and near the Davis Field. The Company acquired the field as part of
the Hess Acquisition and now operates 18 producing wells. The Company owns an
average working interest of 93%. The Quitman Field was discovered in 1966 and
has since produced approximately 21 MMBbls from 18 separate reservoirs between
7,500 feet and 12,000 feet. The principal producing zones at Quitman Field are
the Smackover formation and several sands in the Cotton Valley formation.
Since its acquisition in May 1996, the Company has implemented a capital
expenditure program at Quitman Field which has included upgrading production
facilities and drilling wells. At the time of acquisition, the net production
from this field was approximately 200 Bbls/d. During January 1998, the net
production averaged 1,495 Bbls/d. All five wells drilled in 1997 were
successful, of which two were horizontal wells. During 1998, the Company plans
to drill four wells, of which three will be horizontal wells.
Other Mississippi Fields
In addition to the above fields, Denbury owns an interest in wells in 35 other
fields in Mississippi, which in the aggregate averaged approximately 1,819
Bbls/d and 2.6 MMcf/d of net production during January 1998.
(One illustration, not incorporated by reference - see prefacing comment on
Exhibit 13 Cover Page.)
17
Selected Abbreviations
Bbls ~ Barrels of oil
Bbl/d ~ Barrels of oil produced per day
Bcf ~ Billion cubic feet of natural gas
BOE ~ Barrel of oil equivalent
using the ratio of one barrel of
crude oil to 6 Mcf of
natural gas
BOE/d ~ Barrel of oil equivalent
produced per day
Btu ~ British thermal unit
MBbls ~ Thousand barrels of oil
MBOE ~ Thousand BOE
MBOE/d ~ Thousand barrels of oil
equivalent produced per day
MBtu ~ Thousand Btu
Mcf ~ Thousand cubic feet of natural gas
Mcf/d ~ One thousand cubic feet
of natural gas produced per day
MMBbls ~ Million barrels of oil
MMBOE ~ Million BOE
MMBtu ~ Million Btu
MMcf ~ Million cubic feet of natural gas
MMcf/d ~ Million cubic feet of
natural gas produced per day
PV10 Value ~ Estimated future revenue to be generated from the production of
proved reserves, net of estimated production and development
costs, using prices in effect awt the determination date,
without giving effect to non-property related expenses such as
general and administrative expenses, debt service and future
income taxes or to depreciation and amortization, discounted to
present value using an annual discount rate of 10% in
accordance with the guidelines of the Securities and Exchange
Commission.
Tcf ~ Trillion cubic feet of
natural gas
Financial Table of Contents
Management's Discussion &
Analysis 19
Independent Auditors' Report 27
Financial Statements 28
Shareholder Information 48
18
Management's Discussion and Analysis of Financial
Condition and Results of Operations
Denbury is an independent energy company engaged in acquisition, development and
exploration activities in the U.S. Gulf Coast region, primarily onshore in
Louisiana and Mississippi. Over the last four years, the Company has achieved
rapid growth in proved reserves, production and cash flow by concentrating on
the acquisition of properties which it believes have significant upside
potential and through the efficient development, enhancement and operation of
those properties.
Acquisition of Chevron Properties
On December 30, 1997, the Company acquired oil properties in the Heidelberg
Field, Jasper County, Mississippi, from Chevron for approximately $202 million
(the "Chevron Acquisition"). The Chevron Acquisition represents the largest
acquisition by the Company to date. The Heidelberg Field is adjacent to the
Company's other primary oil properties in Mississippi and includes 122 producing
wells, 96 of which the Company will operate. The Company purchased an average
working interest of 94% and an average net revenue interest of 81% in these 96
wells, which wells account for approximately 99% of the field's average net
daily production. The average net daily production from these properties during
the fourth quarter of 1997 was approximately 2,800 Bbls/d and 650 Mcf/d.
The Chevron Acquisition added proved reserves as of December 31, 1997 of
approximately 27.2 MMBbls and 2.5 Bcf, or approximately 27.6 MMBOE. As a result
of the significant amount of future development and exploitation to be performed
on these properties and the increase in future reserves and production that the
Company expects to result from such development and exploitation, the Company
has attributed $75 million of the purchase price to unevaluated properties.
The Company has scheduled several potential development projects for 1998 during
its initial evaluation of the Heidelberg Field. These include initiating a
waterflood project, upgrading lift capacity in over 12 wells, recompleting 30
wells in new zones and drilling 41 new wells. Horizontal wells drilled by the
Company in 1997 at nearby Davis, Quitman and Eucutta Fields improved daily
production rates significantly as compared to vertical wells drilled in the same
fields. Consequently, the Company anticipates that 31 of the 41 proposed wells
in the Heidelberg Field will be horizontal wells. The Company's total 1998
development budget for the Heidelberg Field is approximately $30 million.
Bar graph illustrating Acquisition Expenditures (in millions of dollars)
1995 1996 1997
----- ----- ------
New $2.6 $41.4 $216.4
Incremental 14.2 7.0 7.7
Update on 1996 Hess Acquisition
The Company completed several property acquisitions during 1996, the largest of
which was the acquisition of producing oil and natural gas properties,
principally in Mississippi and Louisiana, for approximately $37.2 million from
Amerada Hess, effective May 1, 1996 (the "Hess Acquisition"). The average daily
production from the properties included in the Hess Acquisition during May and
June 1996, the first two months of ownership, was approximately 2,945 BOE/d. The
average daily production on these properties had increased to 5,969 BOE/d by the
fourth quarter of 1997.
As of December 31, 1997, in the Company's independent reserve report (the
"December Report"), the properties in the Hess Acquisition had estimated net
proved reserves of approximately 14.2 MMBOE with a PV10 Value of $95 million.
This compares to approximately 5.9 MMBOE of net proved reserves and a $43.1
million PV10 Value on these same properties as reported in the Company's
independent reserve report dated July 1, 1996 (the "July Report"). The December
Report was calculated using year-end prices which were based on a West Texas
Intermediate ("WTI") price of $16.18 per Bbl and a NYMEX Henry Hub price of
$2.58 per MMBtu, with these representative prices adjusted by field to arrive at
the appropriate corporate net price, as compared to oil and gas prices of $20.00
and $2.65, respectively, in the July Report. In addition to the increase in
proved reserves, the Company produced approximately 2.6 MMBOE from July 1, 1996
through December 31, 1997 with total net operating income during the period of
$32.1 million. The Company has incurred $38.3 million of capital cost during the
same period, leaving a net investment as of December 31, 1997 of $43.4 million.
19
Management's Discussion and Analysis of Financial
Condition and Results of Operations
1998 Public Debt and Equity Offering
On February 26, 1998, the Company closed its public sale of 5,240,780 Common
Shares (which included the underwriter's over-allotment option of 683,580 Common
Shares) at a price of $16.75 per share and a net price to the Company of $15.955
per share (the "Equity Offering"). Concurrently with the Equity Offering,
affiliates of the Texas Pacific Group ("TPG"), the Company's largest
shareholder, purchased 313,400 Common Shares from the Company at $15.955 per
share, equal to the price to the public per share less underwriting discounts
and commissions (the "TPG Purchase"). The net proceeds to the Company from the
Equity Offering and TPG Purchase were approximately $88.6 million, before
offering expenses.
Concurrently with the Equity Offering and TPG Purchase, Denbury Management Inc.,
a wholly-owned subsidiary of the Company, issued $125 million in aggregate
principal amount of 9% Senior Subordinated Notes Due 2008 (the "Debt Offering"
and the "Notes"). These Notes contain certain debt covenants, including
covenants that limit (i) indebtedness, (ii) certain 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.
The total net proceeds from the debt and equity offerings were approximately
$209.8 million after deducting the estimated offering expenses of $600,000. The
Company used these proceeds to reduce outstanding borrowings under the Company's
bank credit facility, the majority of which had been borrowed to fund the $202
million Chevron Acquisition.
Pie Charts illustrating Capitalization
In Millions of Dollars 12/31/97 02/28/98
-------- --------
Bank 240 40
Common 133 221
Subordinated Debt - 125
Retained Earnings 27 27*
* 12/31 Amount
Restated Credit Facility
The Company has a credit facility (the "Credit Facility") with NationsBank of
Texas, N.A., as agent for a group of eight other banks. The Credit Facility was
increased in size from $150 million to $300 million in December 1997 and the
borrowing base was increased to $260 million in order to fund the Chevron
Acquisition. As of December 31, 1997, the Company had an outstanding balance on
this facility of $240 million. This balance was reduced to $40 million as of
February 28, 1998 after application of the net proceeds from the Debt and Equity
Offerings and the TPG Purchase (collectively the "Capital Transactions"), net of
$9.8 million of additional borrowings. The Credit Facility consists of a
five-year revolving credit facility with a borrowing base (after the Capital
Transactions) of $165 million. This borrowing base is subject to review every
six months and the Credit Facility is secured by substantially all of the
Company's oil and natural gas properties, except for those acquired in the
Chevron Acquisition. Interest is payable on the revolving credit facility at
either the prime rate or, depending on the percentage of the borrowing base that
is outstanding, at rates ranging from LIBOR plus 7/8% to LIBOR plus 13/8%. The
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 in
the Credit Agreement); (iv) a minimum interest coverage test; and (v) a
prohibition on most debt, lien and corporate guarantees.
Capital Resources and Liquidity
As discussed below, in each of the last three years, the Company's capital
expenditures required additional debt and equity capital to supplement cash flow
from operations.
YEAR ENDED DECEMBER 31,
---------------------------
DOLLARS IN THOUSANDS 1997 1996 1995
------- -------- --------
Acquisitions of oil and natural $224,145 $48,407 $16,763
gas properties
Oil and natural gas expenditures 81,282 38,450 11,761
- ---------------------------------------------------------------
Total $305,427 $86,857 $28,524
- ---------------------------------------------------------------
From January 1, 1995, through December 31, 1997, the Company has made total
capital expenditures of $420.8 million. These capital expenditures were funded
by the issuance of equity ($105.3 million), bank debt ($225.1 million) and cash
generated by operations ($90.4 million). As of December 31, 1997, the Company
had minimal working capital with approximately $240 million of bank debt
outstanding. On February 26, 1998, $200 million of the bank debt was repaid with
proceeds from the Capital Transactions, leaving the Company with a total debt
balance of $165 million ($40 million of bank debt and $125 million of Notes).
20
Management's Discussion and Analysis of Financial
Condition and Results of Operations
Bar graph illustrating Capital Expenditures (in millions of dollars)
1995 1996 1997
------ ------ ------
Development 11.7 38.5 81.3
Acquisitions 16.8 48.4 224.1
Although the Company is still reviewing its budget, particularly in light of the
recent Chevron Acquisition, the Company is currently budgeting capital
expenditures for 1998 of approximately $95 million, of which approximately $30
million is allocated for the properties included in the Chevron Acquisition.
Although the Company's projected cash flow is highly variable and difficult to
predict as it is dependent on product prices, drilling success and other
factors, these projected expenditures are expected to exceed the Company's cash
flow during 1998. Even though the recent reduction in oil product prices has
significantly reduced the Company's projected 1998 cash flow and net income, as
of February 28, 1998, the Company had an unused borrowing base of $125 million
under the Credit Facility to fund any potential cash flow deficits. Furthermore,
if external capital resources are limited or reduced in the future, the Company
can also adjust its capital expenditure program accordingly. However, such
adjustments could limit, or even eliminate, the Company's future growth.
In addition to its internal capital expenditure program, the Company has
historically required capital for the acquisition of producing properties, which
have been a major factor in the Company's rapid growth during recent years.
There can be no assurance that suitable acquisitions will be identified in the
future or that any such acquisitions will be successful in achieving desired
profitability objectives. Although the Company does not anticipate that the
recent reduction in oil prices will require the Company to reduce its planned
development program, it could limit the amount of funds available for
acquisitions. Without suitable acquisitions or the capital to fund such
acquisitions, the Company's future growth could be limited or even eliminated.
Sources and Uses of Funds
During 1997, the Company spent approximately $81.3 million on exploration and
development expenditures and approximately $224.1 million on acquisitions, the
majority of which related to the $202 million Chevron Acquisition. The
exploration and development expenditures included approximately $55.9 million
spent on drilling, $9 million on geological, geophysical and acreage
expenditures and $16.4 million on workover costs. These expenditures were funded
by available cash, bank debt and cash flow from operations.
During 1996, the Company spent approximately $33.4 million on oil and natural
gas development expenditures, $37.2 million on the Hess Acquisition, $7.5
million on properties acquired in April 1996 (the "Ottawa Acquisition"), $3.7
million on other minor oil and natural gas acquisitions, and approximately $5.1
million on geological, geophysical and acreage expenditures. The development
expenditures included $15.5 million spent on drilling and the balance of $17.9
million was spent on workover costs. These expenditures were funded during the
year by bank debt, available cash and cash flow from operations, although the
bank debt was retired with the proceeds from a public offering of Common Shares
in October 1996.
During 1995, the Company made $28.5 million in capital expenditures, with the
single largest component being a $10 million acquisition of seven producing
wells in the Gibson and Humphreys Fields located near the Company's other
properties in southern Louisiana (the "Gibson Acquisition"). The balance of 1995
acquisition expenditures were for additional interests in the Company's Lirette
Field in Louisiana ($2.9 million), interests in the Bully Camp Field, also in
Louisiana ($2.1 million), and a few smaller acquisitions in both Mississippi and
Louisiana. During 1995, the Company also spent $1.9 million on drilling, $1.1
million for acreage and geological and geophysical expenditures, and the balance
of $8.1 million on workovers costs. The 1995 expenditures were funded on an
interim basis with cash flow from operations ($9.4 million) and bank debt ($19.4
million), which was repaid in December 1995 with a portion of the $39.5 million
of net proceeds from a private placement of equity with TPG.
21
Management's Discussion and Analysis of Financial
Condition and Results of Operations
RESULTS OF OPERATIONS
Operating Income
During the last three years, operating income has increased significantly as
outlined in the following table. Oil and natural gas revenue increased as a
result of the increased oil and natural gas production and strong oil and
natural gas product prices.
Year ended December 31,
- ------------------------------------ -------------------------
1997 1996 1995
- ------------------------------------ -------------------------
OPERATING INCOME (THOUSANDS)
Oil sales $49,748 $28,475 $10,852
Natural gas sales 35,585 24,405 9,180
Less production expenses (22,218) (13,495) (6,789)
- ------------------------------------ -------------------------
Operating income $63,115 $39,385 $13,243
- ------------------------------------ -------------------------
UNIT PRICES
Oil price per Bbl $ 17.25 $18.98 $ 14.90
Gas price per Mcf 2.68 2.73 1.90
- ------------------------------------ -------------------------
NETBACK PER BOE
Sales price $ 16.75 $ 17.69 $ 13.05
Production expenses (4.36) (4.51) (4.42)
- ------------------------------------ -------------------------
$12.39 $13.18 $8.63
- ------------------------------------ -------------------------
AVERAGE DAILY PRODUCTION VOLUME:
Bbls 7,902 4,099 1,995
Mcf 36,319 24,406 13,271
BOE 13,955 8,167 4,207
- ------------------------------------ -------------------------
Bar graph illustration of average daily oil & natural gas production by quarter
(BOE basis):
1993 1994 1995 1996 1997
------ ------ ------ ------ -------
First Quarter 756 2,384 3,800 5,453 12,256
Second Quarter 848 2,527 3,885 7,841 13,404
Third Quarter 1,473 2,981 4,062 9,208 14,195
Fourth Quarter 1,682 3,528 5,067 10,132 15,922
Historically, the Company has grown from both acquisitions and internal
development and exploitation of the acquired properties. This is best evidenced
by the fact that approximately 52% of the Company's historical reserves have
been obtained from acquisitions and the remaining 48% from internal development
(excluding the Chevron Acquisition on December 30, 1997). Although the
production increases do not necessarily always directly correlate with reserve
additions, production increases have also been fueled by both internal growth
from the Company's development and exploitation programs and from the property
acquisitions. Between 1995 and 1996, production increased 94% with approximately
2,550 BOE/d attributable to the properties included in the Hess and Ottawa
Acquisitions and 750 BOE/d attributable to properties included in the Gibson
Acquisition. The balance of approximately 660 BOE/d was attributable to internal
growth on other properties. However, between 1996 and 1997, production
22
Management's Discussion and Analysis of Financial
Condition and Results of Operations
increased 71% with approximately 94% of the increase from internal growth and
the balance from acquisitions. Most of this internal growth is attributable to
the properties acquired in the Hess Acquisition in 1996 as production has
increased from 2,945 BOE/d during the first two months of ownership (May and
June, 1996) to approximately 5,969 BOE/d during the fourth quarter of 1997.
Bar graph illustrating oil prices
Dollars per Bbl 1995 1996 1997
----- ----- -----
14.90 18.98 17.25
Oil and natural gas revenue has increased not only because of the large
increases in production, but also due to improved product prices since 1995.
During 1996, product prices increased substantially with a 27% increase in the
average oil price and a 44% increase in the average natural gas price. Coupled
with the production increases, the Company's oil and natural gas revenue
increased 164%, or $32.8 million, from 1995 to 1996. Approximately $21.9 million
of the increase was related to properties acquired in the Hess, Ottawa and
Gibson Acquisitions, approximately $7.7 million due to the increase in product
prices and the balance of approximately $3.2 million due to increased production
from internal growth on other properties. Between 1996 and 1997, oil and natural
gas revenue increased 61%, primarily as a result of the increased production (on
a BOE basis), as oil and natural gas prices decreased 5% on a BOE basis. This
price change consisted of a 9% decline in oil prices and a more modest decline
of 2% in natural gas prices. Only $1.4 million of the revenue increase during
1997 was related to acquisitions during the year.
Bar graph illustrating natural gas prices
Dollars per Mcf 1995 1996 1997
----- ----- -----
1.90 2.73 2.68
Total production expenses increased each year along with the increases in
production, although on a BOE basis, production expenses increased only 2% from
1995 to 1996 and decreased 3% from 1996 to 1997. The 1996 increase was largely
attributable to a change in the mix of properties as the Mississippi oil
properties tend to have a higher operating cost per BOE than the Louisiana gas
properties. During the first two months of ownership (May and June 1996), the
production expenses averaged $6.27 per BOE on the Hess Acquisition properties
which were more heavily weighted toward Mississippi oil than Louisiana gas.
After assuming operations, these averages were brought more in line with the
Company averages through cost savings and increased production levels and for
the seven months ended December 31, 1996, production expenses on these
properties averaged $5.35 per BOE.
During 1997, the Company was able to lower operating costs per BOE through its
cost savings efforts and by increasing production without a corresponding
increase in the number of properties. For the properties acquired in the Hess
Acquisition, operating expenses declined 15% from the 1996 level of $5.35 per
BOE to an average of $4.56 per BOE. The Company's recent emphasis on horizontal
drilling contributed to these production increases and resultant savings, even
though the Company's production became even more weighted towards oil (which has
higher operating costs) with 57% of the 1997 BOE production coming from oil as
compared to 50% of the Company's 1996 BOE production coming from oil.
General and Administrative Expenses
General and administrative ("G & A") expenses have increased as outlined below
along with the Company's growth.
Year ended December 31,
- ----------------------------------------------------------
1997 1996 1995
- ----------------------------------------------------------
NET G&A EXPENSES (THOUSANDS)
Gross expenses $ 13,909 $8,407 $3,900
State franchise taxes 428 213 100
Operator overhead charges (5,502) (2,916) (1,438)
Capitalized exploration expenses (2,225) (1,224) (630)
- ----------------------------------------------------------
Net expenses $ 6,610 $4,480 $1,932
- ----------------------------------------------------------
Average G&A cost per BOE $ 1.30 $ 1.50 $ 1.25
Employees as of December 31 157 122 51
- ----------------------------------------------------------
On a BOE basis, these costs increased 20% from 1995 to 1996 but decreased 13%
from 1996 to 1997, almost returning to the 1995 level. As a result of improved
financial results during the first quarter of 1996 and other factors, the
Company conducted a review of salaries and awarded increases and bonuses in
February 1996 to its employees. Bonuses, including related payroll taxes,
23
Management's Discussion and Analysis of Financial
Condition and Results of Operations
amounted to approximately $225,000 ($.08 per BOE). During 1996, the Company also
accrued $545,000 ($.18 per BOE) for bonuses which were awarded in February 1997.
In addition, the Company began to increase its staff levels during the second
quarter of 1996 to handle the Hess Acquisition, but was not entitled to any
operator's overhead recovery on these properties until July 15, 1996, further
fueling an increase in general and administrative cost per BOE, as Amerada Hess
remained the operator of record until that date.
The decrease in G&A expense on a BOE basis during 1997 was partially
attributable to the increased production on both an absolute and per well basis.
Furthermore, the respective well operating agreements allow the Company, when it
is the operator, to charge a well with a specified overhead rate during the
drilling phase. As a result of the increased drilling activity in 1997 (44 wells
drilled during 1997 versus 10 wells drilled during 1996), the percentage of
gross G&A recovered through these types of allocations (listed in the above
table as "Operator overhead charges") increased when compared to the
corresponding periods of 1996. During 1996, approximately 35% was recovered by
operator overhead charges, while during 1997 this recovery increased to 40%.
Bar graph illustrating dollars per BOE.
1995 1996 1997
----- ------ -----
Cash flow 6.12 11.42 11.11
Interest 1.26 .26 -
G&A 1.25 1.50 1.30
Production 4.42 4.51 4.36
Interest and Financing Expenses
YEAR ENDED DECEMBER 31,
- ------------------------------------ -------------------------
AMOUNTS IN THOUSANDS EXCEPT PER
UNIT AMOUNTS 1997 1996 1995
- ------------------------------------ -------------------------
Interest expense $ 1,111 $1,993 $2,085
Non-cash interest expense (91) (459) (90)
- ------------------------------------ -------------------------
Cash interest expense 1,020 1,534 1,995
Interest and other income (1,123) (769) (77)
- ------------------------------------ -------------------------
Net interest expense (income) $ (103) $ 765 $ 1,918
- ------------------------------------ -------------------------
Average interest expense (income)
per BOE $ (0.02) $ 0.26 $ 1.26
Average debt outstanding $12,700 $19,500 $21,400
Average interest rate 6.9% 7.9% 9.3%
Ratio of earnings to fixed charges 19.9 4.6 1.5
- --------------------------------------------------------------
Imputed preferred dividend $ - $ 1,281 $ -
Loss on early extinguishment of debt - 440 200
- --------------------------------------------------------------
During the first half of 1996 and 1997, the Company had minimal debt outstanding
as virtually all of the bank debt had been retired during the previous fourth
quarter. In 1995, the bank debt was repaid with proceeds from the December 1995
private placement of equity with TPG and in 1996 with proceeds from a public
offering of Common Shares completed in October 1996. However, in 1996, the
Company did incur debt late in the second quarter to fund property acquisitions,
the largest of which was the Hess Acquisition, and during 1997, the Company
borrowed $202 million of its December 31, 1997 balance of $240 million late in
the fourth quarter to fund the Chevron Acquisition.
The private placement of equity in December 1995 with TPG included 1.5 million
Convertible Preferred Shares. During 1996, the Company recognized $1.3 million
of charges representing the imputed preferred dividend until October 30, 1996
when the Convertible Preferred was converted into 2.8 million Common Shares.
Under Canadian generally accepted accounting principles ("GAAP"), this dividend
was reported as an operating expense, while under U.S. GAAP this would not be an
expense but it would be deducted from net income to arrive at net income
attributable to the common shareholders. In addition to paying off its bank debt
and converting the Convertible Preferred into common equity during 1996, the
Company also converted its remaining subordinated debt into common equity,
leaving the Company essentially debt-free as of December 31, 1996.
During 1996, the Company had a $440,000 charge relating to a loss on early
extinguishment of debt. These costs related to the remaining unamortized debt
issue costs of the Company's prior credit facility which was replaced in May
1996. The Company also had a charge of $200,000 during the first half of 1995
for the same type of expense relating to a previous bank refinancing. Under U.S.
GAAP, a loss on early extinguishment of debt would be an extraordinary item
rather than a normal operating expense as required by Canadian GAAP.
24
Management's Discussion and Analysis of Financial
Condition and Results of Operations
Depletion, Depreciation, Amortization and Site Restoration
Depletion, depreciation and amortization ("DD&A") has increased along with the
additional capitalized cost and increased production. DD&A per BOE increased 15%
from 1995 to 1996 primarily due to 59% of the 1995 capital expenditures and 56%
of the 1996 expenditures relating to property acquisitions, which often have a
higher per unit cost than those reserves added by development expenditures.
The oil prices used in the December 31, 1996 reserve report were based on a WTI
price of $23.39 per Bbl, with these representative prices adjusted by field to
arrive at the appropriate corporate net price in accordance with the rules of
the Securities and Exchange Commission while the comparable WTI price in the
December 31, 1997 reserve report was $16.18 per Bbl. Using 1996 prices, the
Company's proved oil reserves would have been 2.1 MMBOE higher (excluding the
properties acquired in the Chevron Acquisition). This loss of reserves due to
product price decreases caused DD&A to increase approximately $0.29 per BOE
during 1997. Overall, DD&A increased $0.43 per BOE during 1997 (7%) with the
balance of the increase resulting from rising drilling costs, particularly in
Louisiana.
Bar graph illustrating proven reserves. (in millions of BOE)
1995 1996 1997
---- ---- ----
Chevron - - 27.6
Oil 6.3 15.0 24.8
Natural Gas 8.0 12.4 12.5
The Company also provides 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 the DD&A expense and has increased each year along
with an increase in the number of properties owned by the Company.
YEAR ENDED DECEMBER 31,
- ------------------------------------ -------------------------
AMOUNTS IN THOUSANDS EXCEPT PER
UNIT AMOUNTS 1997 1996 1995
- ------------------------------------ -------------------------
Depletion and depreciation $32,311 $17,533 $7,918
Site restoration provision 408 371 104
- ------------------------------------ -------------------------
Total amortization $32,719 $17,904 $8,022
- ------------------------------------ -------------------------
Average DD&A cost per BOE $ 6.42 $ 5.99 $ 5.22
- ------------------------------------ -------------------------
Income Taxes
Due to a net operating loss of the U.S. subsidiary each year for tax purposes,
the Company does not have any current income tax provision. The deferred income
tax provision as a percentage of net income has varied depending on the mix of
Canadian and U.S. expenses. The 1996 rate was highest of the three years
outlined below due to the non-deductible imputed preferred dividend and interest
on the subordinated debt during that year.
YEAR ENDED DECEMBER 31,
- ------------------------------------ ------------------------
1997 1996 1995
- ------------------------------------ ------- ------- -------
Deferred income taxes (thousands) $ 8,895 $ 5,312 $ 367
Average income tax costs per BOE $ 1.75 $ 1.78 $ 0.24
Effective tax rate 37% 38% 34%
- ------------------------------------ ------- ------- -------
Bar graphs illustrating cash flow and net income. (in millions of dollars)
1995 1996 1997 1995 1996 1997
----- ---- ----- ---- ---- ----
Cash flow from operations
excluding the change in
working capital items 9.4 34.1 56.6 Net Income 0.7 8.7 14.9
25
Management's Discussion and Analysis of Financial
Condition and Results of Operations
Net Income
Primarily as a result of increased production and strong product prices, net
income and cash flow from operations increased substantially from 1995 through
1997 as outlined below.
YEAR ENDED DECEMBER 31,
- ------------------------------------ -------------------------
AMOUNTS IN THOUSAND EXCEPT PER
SHARE AMOUNTS 1997 1996 1995
- ------------------------------------ ------- ------- -------
Net income $14,903 $ 8,744 $ 714
Net income per common share:
Basic $ 0.74 $0.67 $ 0.10
Fully diluted 0.70 0.62 0.10
Cash flow from operations (a) $56,607 $34,140 $ 9,394
- ------------------------------------ ------- ------- -------
<FN>
(a) Represents cash flow provided by operations, exclusive of the net change in
non-cash working capital balances.
</FN>
The following table summarizes the cash flow, DD&A and net income on a BOE basis
for the comparative periods. Each of the individual components are discussed
above.
YEAR ENDED DECEMBER 31,
- ------------------------------------ ---------------------------
Per BOE Data 1997 1996 1995
- ------------------------------------ ---------------------------
Revenue $16.75 $17.69 $13.05
Production expenses (4.36) (4.51) (4.42)
- ---------------------------------------------------------------------
Production netback 12.39 13.18 8.63
General and administrative (1.30) (1.50) (1.25)
Interest and other income (expense) 0.02 (0.26) (1.26)
- ---------------------------------------------------------------------
Cash flow from operations (a) 11.11 11.42 6.12
DD&A (6.42) (5.99) (5.22)
Deferred income taxes (1.75) (1.78) (0.24)
Other non-cash items (0.01) (0.72) (0.19)
- ---------------------------------------------------------------------
Net income $ 2.93 $ 2.93 $ 0.47
- ---------------------------------------------------------------------
<FN>
(a) Represents cash flow provided by operations, exclusive of the net change in
non-cash working capital balances.
</FN>
Year 2000 Modifications
The Company is currently reviewing its computer systems in order to evaluate
necessary modifications for the year 2000 and is also making inquiries with
regard to the systems used by its oil and natural gas purchasers and other third
parties that the Company relies on as part of its normal business. The Company
does not believe that it will incur any material expenditures, nor require any
significant modifications to make its internal systems year 2000 compliant;
however, it has not yet fully evaluated the status of third-party systems and
the effect, if any, on the Company if third-party systems are not year 2000
compliant.
Recently Issued Accounting Standards
See discussion of Recently Issued Accounting Standards in Note 8 of the
Consolidated Financial Statements.
26
Independent Auditors' Report
To the Shareholders of Denbury Resources Inc.
We have audited the consolidated balance sheets of Denbury Resources Inc. as at
December 31, 1997 and 1996 and the consolidated statements of income, changes in
shareholders' equity and cash flows for each of the years in the three year
period ended December 31, 1997. 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 Canada and the United States of America. Those standards require that we plan
and perform the audit to obtain reasonable assurance 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.
In our opinion, these consolidated financial statements present fairly in all
material respects, the financial position of the Company as at December 31, 1997
and 1996 and the results of its operations and the changes in shareholders'
equity and cash flows for each of the years in the three year period ended
December 31, 1997, in accordance with accounting principles generally accepted
in Canada.
Deloitte & Touche
Chartered Accountants
Calgary, Alberta
February 27, 1998
27
Consolidated Balance Sheets
AMOUNTS IN THOUSANDS OF U.S. DOLLARS DECEMBER 31,
--------------------
1997 1996
-------- ---------
ASSETS
CURRENT ASSETS
Cash and cash equivalents................... $ 9,326 $ 13,453
Accrued production receivable............... 8,692 11,906
Trade and other receivables................. 15,362 3,643
-------- ---------
Total current assets ............. 33,380 29,002
-------- ---------
PROPERTY AND EQUIPMENT (USING FULL COST
ACCOUNTING)
Oil and natural gas properties.............. 388,766 159,724
Unevaluated oil and natural gas properties.. 82,798 6,413
Less accumulated depreciation and depletion. (62,732) (31,141)
-------- ---------
Net property and equipment........... 408,832 134,996
-------- ---------
OTHER ASSETS................................... 5,336 2,507
-------- ---------
TOTAL ASSETS........................ $447,548 $ 166,505
======== =========
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable and accrued liabilities.... $ 24,616 $ 10,903
Oil and gas production payable.............. 6,052 5,550
Current portion of long-term debt .......... 20 67
-------- ---------
Total current liabilities........... 30,688 16,520
-------- ---------
LONG-TERM LIABILITIES
Long-term debt.............................. 240,000 125
Provision for site reclamation costs........ 1,017 613
Deferred income taxes and other............. 15,620 6,743
-------- ---------
Total long-term liabilities......... 256,637 7,481
-------- ---------
SHAREHOLDERS' EQUITY
Common shares, no par value, unlimited
shares authorized; outstanding - 20,388,683
and 20,055,757 shares at December 31, 1997
and December 31, 1996, respectively....... 133,139 130,323
Retained earnings........................... 27,084 12,181
-------- ---------
Total shareholders' equity.......... 160,223 142,504
-------- ---------
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $447,548 $ 166,505
======== =========
Approved by the Board:
/s/ Gareth Roberts /s/ Wieland F. Wettstein
- ------------------------- -----------------------------
Gareth Roberts Wieland Wettstein
Director Director
See Notes to Consolidated Financial Statements
28
Consolidated Statements of Income
YEAR ENDED DECEMBER 31,
-------------------------
AMOUNTS IN THOUSANDS EXCEPT PER SHARE
AMOUNTS (U.S. DOLLARS) 1997 1996 1995
------- ------- -------
REVENUES
Oil, natural gas and related product
sales................................ $85,333 $52,880 $20,032
Interest income and other............... 1,123 769 77
------- ------- -------
Total revenues.................... 86,456 53,649 20,109
------- ------- -------
EXPENSES
Production.............................. 22,218 13,495 6,789
General and administrative.............. 6,182 4,267 1,832
Interest................................ 1,111 1,993 2,085
Imputed preferred dividends............. - 1,281 -
Loss on early extinguishment of debt.... - 440 200
Depletion and depreciation.............. 32,719 17,904 8,022
Franchise taxes......................... 428 213 100
------- ------- -------
Total expenses................... 62,658 39,593 19,028
------- ------- -------
Income before income taxes................... 23,798 14,056 1,081
Provision for income taxes................... (8,895) (5,312) (367)
------- ------- -------
NET INCOME................................... $14,903 $ 8,744 $ 714
======= ======= =======
NET INCOME PER COMMON SHARE..................
Basic..................................... $ 0.74 $ 0.67 $ 0.10
Fully diluted............................. $ 0.70 $ 0.62 $ 0.10
Average number of common shares outstanding.. 20,224 13,104 6,870
======= ======= =======
See Notes to Consolidated Financial Statements
29
Consolidated Statements of Cash Flows
YEAR ENDED DECEMBER 31,
--------------------------
AMOUNTS IN THOUSANDS OF U.S. DOLLARS 1997 1996 1995
------- ------- --------
CASH FLOW FROM OPERATING ACTIVITIES:
Net income.................................. $14,903 $ 8,744 $ 714
Adjustments needed to reconcile to net
cash flow provided by operations:
Depreciation, depletion and amortization. 32,719 17,904 8,113
Deferred income taxes.................... 8,895 5,312 367
Imputed preferred dividend............... - 1,281 -
Loss on early extinguishment of debt..... - 440 200
Other.................................... 90 459 -
------- ------- --------
56,607 34,140 9,394
Changes in working capital items relating
to operations:
Accrued production receivable............ 3,214 (8,694) (1,303)
Trade and other receivables.............. (11,719) (1,508) (168)
Accounts payable and accrued liabilities. 13,713 6,711 (1,660)
Oil and gas production payable........... 502 4,536 490
------- ------- --------
NET CASH FLOW PROVIDED BY OPERATIONS............ 62,317 35,185 6,753
------- ------- --------
CASH FLOW USED FOR INVESTING ACTIVITIES:
Oil and natural gas expenditures......... (81,282) (38,450) (11,761)
Acquisition of oil and natural gas
properties............................ (224,145) (48,407) (16,763)
Net purchases of other assets............ (2,132) (1,726) (560)
Acquisition of subsidiary, net of
cash acquired......................... - 209 -
------- ------- --------
NET CASH USED FOR INVESTING ACTIVITIES......... (307,559) (88,374) (29,084)
------- ------- --------
CASH FLOW FROM FINANCING ACTIVITIES:
Bank borrowings.......................... 239,900 47,900 19,350
Bank repayments.......................... - (47,900) (34,200)
Issuance of subordinated debt............ - - 1,772
Issuance of common stock................. 2,816 60,664 26,825
Issuance of preferred stock.............. - - 15,000
Costs of debt financing.................. (1,511) (411) (493)
Other.................................... (90) (164) (82)
------- ------- --------
NET CASH PROVIDED BY FINANCING ACTIVITIES....... 241,115 60,089 28,172
------- ------- --------
NET INCREASE (DECREASE) IN CASH AND CASH
EQUIVALENTS................................ (4,127) 6,900 5,841
Cash and cash equivalents at beginning of year.. 13,453 6,553 712
------- ------- --------
CASH AND CASH EQUIVALENTS AT END OF YEAR........ $ 9,326 $13,453 $ 6,553
======= ======= ========
SUPPLEMENTAL DISCLOSURE OF CASH FLOW
INFORMATION:
Cash paid during the year for interest.... $ 447 $ 1,621 $ 2,127
SUPPLEMENTAL DISCLOSURE OF FINANCING ACTIVITIES:
Conversion of subordinated debt to
common stock......................... - $ 3,314 -
Conversion of preferred stock to
common stock......................... - 16,281 -
Assumption of liabilities in
acquisition.......................... - 1,321 -
See Notes to Consolidated Financial Statements
30
Consolidated Statement of Changes in Shareholders' Equity
COMMON SHARES
(NO PAR VALUE)
Dollar Amounts in Thousands of U.S. ------------------ RETAINED
Dollars Shares Amounts EARNINGS TOTAL
--------- -------- ------- -------
BALANCE - JANUARY 1, 1995 6,304,667 $ 23,239 $ 2,723 $25,962
--------- -------- ------- -------
Issued pursuant to employee stock
option plan..................... 10,000 54 - 54
Private placement of Special Warrants
exchanged....................... 614,143 2,314 - 2,314
Private placement of common shares... 4,499,999 24,457 - 24,457
Net income........................... - - 714 714
--------- -------- ------- -------
BALANCE - DECEMBER 31, 1995 11,428,809 50,064 3,437 53,501
--------- -------- ------- -------
Issued pursuant to employee stock
option plan..................... 197,675 1,070 - 1,070
Issued pursuant to employee stock
purchase plan................... 31,311 358 - 358
Public placement of common shares.... 4,940,000 58,776 - 58,776
Conversion of preferred stock........ 2,816,372 16,281 - 16,281
Conversion of warrants............... 75,000 460 - 460
Conversion of subordinated debt...... 566,590 3,314 - 3,314
Net income........................... - - 8,744 8,744
---------- -------- ------- -------
BALANCE - DECEMBER 31, 1996 20,055,757 130,323 12,181 142,504
---------- -------- ------- -------
Issued pursuant to employee stock
option plan...................... 280,656 1,916 - 1,916
Issued pursuant to employee stock
purchase plan................... 52,270 900 - 900
Net income........................... - - 14,903 14,903
---------- -------- ------- --------
BALANCE - DECEMBER 31, 1997 20,388,683 $133,139 $27,084 $160,223
========== ======== ======= ========
See Notes to Consolidated Financial Statements
31
Notes to Consolidated Financial Statements
NOTE 1. SIGNIFICANT ACCOUNTING POLICIES
The Company's operating activities are related to exploration, development and
production of oil and natural gas in the United States.
On October 9, 1996 the shareholders of the Company approved an amendment to the
Articles of Continuance to consolidate the number of issued and outstanding
Common Shares on the basis of one Common Share for each two Common Shares
outstanding. All applicable shares and per share data have been adjusted for the
reverse stock split.
Principles of Consolidation
The consolidated financial statements have been prepared in accordance with
Canadian generally accepted accounting principles and include the accounts of
the Company and its wholly owned subsidiaries, Denbury Holdings Ltd., Denbury
Management, Inc. and Denbury Marine L.L.C. and the Company's equity in the
operation of its 50% owned subsidiary, Denbury Energy Services ("DES"). The
Company acquired the remaining 50% of DES effective May 1, 1996 and began
consolidating all of DES as of that date. Denbury Holdings Ltd. was merged into
Denbury Resources Inc. in December 1997. 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 the
exploration for 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 nonproductive
wells and general and administrative expenses directly related to exploration
and development 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.
D) CEILING TEST The capitalized costs less accumulated depletion, depreciation,
related deferred taxes and site reclamation costs are limited to an amount which
is not greater than the estimated future net revenue from proved reserves using
unescalated period-end prices less estimated future site restoration and
abandonment costs, future production-related general and administrative
expenses, financing costs and income taxes, plus the cost (net of impairments)
of undeveloped properties.
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.
Foreign Currency Translation
In that virtually all of the Company's assets have been located in the United
States since 1993 when the Company sold its Canadian oil and natural gas
properties, the United States assets and operations are accounted for and
reported in U.S. dollars and no translation is necessary. The minor amount of
Canadian assets and liabilities is translated to U.S. dollars using year-end
exchange rates and any Canadian operations, which are principally minor
administrative and interest expenses, are translated using the historical
exchange rate.
Earnings per Share
Net income per common share is computed by dividing the net income attributable
to common shareholders by the weighted average number of shares of common stock
outstanding. In accordance with Canadian generally accepted accounting
principles ("GAAP"), the imputed dividend during 1996 on the Convertible First
Preferred Shares, Series A has been recorded as an
32
Notes to Consolidated Financial Statements
operating expense in the accompanying financial statements and this is deducted
from net income in computing earnings per share. The conversion of the
Convertible First Preferred Shares, Series A ("Convertible Preferred") was
anti-dilutive and was not included in the calculation of earnings per share. In
computing fully diluted earnings per share, the stock options, warrants and
convertible debt instruments were dilutive for the years ended December 31, 1997
and 1996 and were assumed to be converted or exercised as of the beginning of
the respective period with the proceeds used to reduce interest expense. For the
year ended December 31, 1995, these instruments were either anti-dilutive or
immaterial. All of the Convertible Preferred and the convertible debt were
converted into common shares during 1996 and thus were not relevant to the
calculation of earnings per share during 1997.
Statement of Cash Flows
For purposes of the Statement of Cash Flows, cash equivalents include time
deposits, certificates of deposit and all liquid debt instruments with
maturities at the date of purchase of three months or less.
Revenue Recognition
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, 1997 and
1996, 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.
Income Taxes
Income taxes are accounted for using the liability method under which deferred
income taxes are recognized for the tax consequences of "temporary differences"
by applying enacted statutory tax rates applicable to future years to
differences between the financial statement carrying amounts and the tax basis
of existing assets and liabilities. The effect on deferred taxes for a change in
tax rates is recognized in income in the period that includes the enactment
date. During 1997, this liability method for computing income taxes was adopted
as GAAP in Canada. This change to the liability method from the deferral method
did not have a material impact on the Company's financial statements.
Financial Instruments with Off-balance Sheet Risk and Concentrations of Credit
Risk
The Company's product price hedging activities are described in Note 6 to the
consolidated financial statements. Credit risk relating to these hedges is
minimal because of the credit risk standards required for counter-parties and
monthly settlements. The Company has entered into hedging contracts with only
large and financially strong companies.
The Company's financial instruments that are exposed to concentrations of credit
risk consist primarily of cash equivalents, short-term investments and trade and
accrued production receivables. The Company's cash equivalents and short-term
investments 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.
Fair Value of Financial Instruments
As of December 31, 1997 and December 31, 1996, the carrying value of the
Company's debt and other financial instruments approximates its fair market
value. The Company's bank debt is based on a floating interest rate and thus
adjusts to market as interest rates change. 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.
Use of Estimates
The preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions that
affect the reported amount of certain assets, liabilities, revenues and expenses
as of and for the reporting period. Estimates and assumptions are also required
in the disclosure of contingent assets and liabilities as of the date of the
financial statements. Actual results may differ from such estimates.
33
Notes to Consolidated Financial Statements
NOTE 2. PROPERTY AND EQUIPMENT
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, 1997 and 1996 and the year in which they were incurred follows:
December 31, 1997 December 31, 1996
------------------------ --------------------------
Costs Incurred During: Costs Incurred During:
---------------- -----------------
AMOUNTS IN THOUSANDS 1997 1996 Total 1996 1995 Total
------- ------- ------- ------- ------ -------
Property acquisition cost.. $77,238 $ 286 $77,524 $ 2,614 $ 252 $ 2,866
Exploration costs......... 3,817 1,457 5,274 3,460 87 3,547
------- ------- ------- ------- ------ -------
Total................. $81,055 $ 1,743 $82,798 $ 6,074 $ 339 $ 6,413
======= ======= ======= ======= ====== =======
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.
General and administrative costs that directly relate to exploration and
development activities that were capitalized during the period totaled
$2,225,000, $1,224,000 and $630,000 for the years ended December 31, 1997, 1996
and 1995, respectively. Amortization per BOE was $6.42, $5.99 and $5.22 for the
years ended December 31, 1997, 1996 and 1995, respectively.
NOTE 3. NOTES PAYABLE AND LONG-TERM INDEBTEDNESS
December 31,
-------------------
1997 1996
AMOUNTS IN THOUSANDS -------- --------
Senior bank loan...................$240,000 $ 100
Other notes payable................ 20 92
-------- --------
240,020 192
Less portion due within one year... (20) (67)
-------- --------
Total long-term debt.........$240,000 $ 125
======== ========
Banks
In order to fund the Chevron Acquisition (as defined herein), the Company has
revised and restated its credit facility (the "Credit Facility") as of December
29, 1997 with NationsBank of Texas, N.A. ("NationsBank") as agent for a group of
banks and increased the size of the facility from $150 million to $300 million.
As of December 31, 1997, the borrowing base was $260 million, of which
approximately $20 million was available. The Credit Facility includes a five
year revolving credit facility of $165 million, unless renewed or extended, plus
an Acquisition Tranche of $95 million. The borrowing base is subject to review
every six months and the facility is secured by substantially all of the
Company's oil and natural gas properties, except for those acquired in the
Chevron Acquisition.
Interest is payable on the revolving credit facility at either the prime rate
or, depending on the percentage of the borrowing base that is outstanding, at
rates ranging from LIBOR plus 7/8% to LIBOR plus 13/8%; provided that interest
is payable at LIBOR plus 15/8% as long as the Acquisition Tranche is outstanding
with the rate escalating 0.25% each quarter, beginning on March 1, 1998 through
March 31, 1999, unless the Acquisition Tranche is repaid. 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. As of December 31, 1997, the Company had $240 million outstanding on
this line of credit and $145,000 of letters of credit outstanding. The
Acquisition Tranche was repaid during February 1998. As of February 28, 1998,
the Company had $40 million outstanding on this line of credit and $245,000 of
letters of credit outstanding.
34
Notes to Consolidated Financial Statements
Subordinated Debt
On March 23, 1994, Denbury issued Cdn. $2,000,000 principal amount of 6 3/4%
unsecured convertible debentures and on January 17, 1995, Denbury issued Cdn.
$2,500,000 principal amount of 9 1/2% unsecured convertible debentures. These
debentures were converted into 566,590 Common Shares during 1996.
Indebtedness Repayment Schedule
The Company's indebtedness is repayable as follows:
DECEMBER 31, 1997
----------------------------------
OTHER NOTES
AMOUNTS IN THOUSANDS BANK LOAN PAYABLE TOTAL
- ------------------------ --------- ----------- --------
YEAR
1998 ....................$ - $ 20 $ 20
1999 .................... - - -
2000 .................... - - -
2001 .................... - - -
2002 .................... 240,000 - 240,000
--------- ----------- --------
Total indebtedness $ 240,000 $ 20 $240,020
========= =========== ========
NOTE 4. INCOME TAXES
The Company's income tax provision is as follows:
YEAR ENDED DECEMBER 31,
-------------------------
AMOUNTS IN THOUSANDS 1997 1996 1995
------- ------ ------
Deferred
Federal..........................$ 8,589 $5,312 $ 367
State............................ 306 - -
------- ------ ------
Total income tax provision..........$ 8,895 $5,312 $ 367
======= ====== ======
Income tax expense for the year varies from the amount that would result from
applying Canadian federal and provincial tax rates to income before income taxes
as follows:
YEAR ENDED DECEMBER 31,
------------------------
AMOUNTS IN THOUSANDS 1997 1996 1995
------- ------- -------
Deferred income tax provision
calculated using the Canadian federal
and provincial statutory combined
tax rate of 44.34%................... $10,552 $ 6,233 $ 479
Increase resulting from:
Imputed preferred dividend........... - 568 -
Non-deductible Canadian expenses..... - 97 -
Decrease resulting from:
Effect of lower income tax rates on
United States income............... (1,657) (1,586) (112)
------- ------- -------
Total income tax provision $ 8,895 $ 5,312 $ 367
======= ======= =======
35
Notes to Consolidated Financial Statements
The Company at December 31, 1997 had net operating loss carryforwards for U.S.
federal income tax purposes of approximately $44,852,950 and approximately
$38,672,391 for alternative minimum tax purposes. The net operating losses are
scheduled to expire as follows:
ALTERNATIVE
INCOME MINIMUM
AMOUNTS IN THOUSANDS TAX TAX
- ----------------------------- ------- ---------
YEAR
2004 ....................... $ 39 $ -
2005 ....................... 11 -
2006 ....................... 644 500
2007 ....................... 714 99
2008 ....................... 5,016 4,889
2009 ....................... 3,377 2,868
2010 ....................... 3,467 3,420
2011 ....................... 5,061 710
2012 ....................... 26,524 26,186
Deferred income taxes relate to temporary differences based on tax laws and
statutory rates in effect at the December 31, 1997 and 1996 balance sheet dates.
At December 31, 1997 and 1996, all deferred tax assets and liabilities were
computed based on Canadian GAAP amounts and were noncurrent as follows:
December 31,
------------------
AMOUNTS IN THOUSANDS 1997 1996
-------- --------
Deferred tax assets:
Loss carryforwards............ $(15,699) $ (4,902)
Deferred tax liabilities:
Exploration and intangible
development costs.......... 31,319 11,645
-------- --------
Net deferred tax liability....... $ 15,620 $ 6,743
======== ========
NOTE 5. SHAREHOLDERS' EQUITY
Authorized
The Company is authorized to issue an unlimited number of Common Shares with no
par value, First Preferred Shares and Second Preferred Shares. The preferred
shares may be issued in one or more series with rights and conditions as
determined by the Directors.
Common Stock
Each Common Share entitles the holder thereof to one vote on all matters on
which holders are permitted to vote. The Texas Pacific Group ("TPG") was granted
a right of first refusal in the private placement (see below), to maintain
proportionate ownership. No stockholder has any right to convert common stock
into other securities. The holders of shares of common stock are entitled to
dividends when and if declared by the Board of Directors from funds legally
available therefore and, upon liquidation, to a pro rata share in any
distribution to stockholders, subject to prior rights of the holders of the
preferred stock. The Company is restricted from declaring or paying any cash
dividend on the Common Stock by its bank loan agreement.
1996 Capital Adjustments
During 1996, the Company issued 250,000 Common Shares for the conversion of the
6 3/4% Convertible Debentures of the Company and 75,000 Common Shares for the
exercise of half of the Cdn. $8.40 Warrants ("Warrants"). On October 10, 1996,
the Company effected a one-for-two reverse split of its outstanding common
Shares. Effective October 15, 1996, all of the Company's outstanding 9 1/2%
Convertible Debentures ("Debentures") were converted by their holders in
accordance with their terms into 308,642 Common Shares. The holders of the
Debentures also received an additional 7,948 Common Shares in lieu of interest
which would have been due the holders absent an early conversion of the
Debentures. At a special meeting held on October 9, 1996, the shareholders of
the Company approved an amendment to the terms of the Convertible Preferred to
allow the Company to require the conversion of the Convertible Preferred at any
time, provided that the conversion rate in effect as of January 1, 1999 would
apply to any required conversion prior to that date. The Company converted all
of the 1,500,000 shares of Convertible Preferred
36
Notes to Consolidated Financial Statements
on October 30, 1996 into 2,816,372 Common Shares. The Company also issued an
aggregate of 4,940,000 Common Shares on October 30, 1996 and November 1, 1996 at
a net price of $12.035 per share as part of a public offering for net proceeds
to the Company of approximately $58.8 million (the "1996 Public Offering"). TPG
purchased 800,000 of these shares at $12.035 per share.
1995 Private Placement of Securities
In December 1995, the Company closed a $40 million private placement of
securities with partnerships that are affiliated with the Texas Pacific Group
("TPG Placement"). The TPG Placement was comprised of: (i) 4.166 million common
shares issued at $5.85 per share, (ii) 625,000 warrants at a price of $1.00 per
warrant entitling the holder to purchase 625,000 common shares at $7.40 per
share through December 21, 1999 and (iii) 1.5 million shares of $10 stated value
Convertible Preferred. The Convertible Preferred shares were initially
convertible at $7.40 of stated value per common share with such conversion rate
declining 2.5% per quarter. The shares also had a mandatory redemption at a
63.86% premium at December 21, 2000. The Convertible Preferred were converted
into 2,816,372 Common Shares on October 30, 1996. During the period that the
Convertible Preferred were outstanding, the Company made a charge to net income
to accrue the increase during the period in the mandatory redemption premium.
The $7.40 warrants issued in the TPG Placement were converted into 625,000
Common Shares on January 20, 1998.
As part of the TPG Placement, TPG was granted certain "piggyback" registration
rights which allow TPG to include all or part of the Common Shares acquired by
TPG in any registration statement of the Company during the first two years.
After the initial two years and until December 21, 2000, TPG may request and
receive one demand registration statement to register the Common Shares acquired
by TPG. TPG waived their "piggyback" registration rights for the 1996 Public
Offering.
The TPG agreement provides that TPG shall have the right, but not the
obligation, to maintain its pro rata ownership interest (after the assumed
exercise of their warrants and Convertible Preferred) in the equity securities
of the Company, in the event that the Company issues any additional equity
securities or securities convertible into Common Shares of the Company, by
purchasing additional shares of the Company on the same terms and conditions.
However, this right expires should TPG's share holdings represent less than 20%
of the outstanding Common Shares. TPG waived its right to maintain its pro rata
ownership with regard to the 1996 Public Offering.
As part of the TPG Placement, Tortuga Investment Corp. was paid a financial
advisor fee of 333,333 Common Shares of the Company. The sole shareholder of
Tortuga Investment Corp. was appointed to the Board of Directors of the Company
and elected Chairman upon the closing of the TPG Placement.
Warrants
At December 31, 1997, 75,000 warrants were outstanding at an exercise price of
Cdn. $8.40 expiring on May 5, 2000 and TPG held 625,000 warrants at an exercise
price of U.S. $7.40 expiring on December 21, 1999. Each warrant entitles the
holder thereof to purchase one Common Share at any time prior to the expiration
date. The $7.40 warrants held by TPG were converted into 625,000 Common Shares
on January 20, 1998.
Special Warrant Issues
On April 25, 1995, the Company issued 614,143 Special Warrants at a price of
$4.70 (Cdn. $6.50) per Special Warrant for gross proceeds of $2,750,000 (29,036
Common Share Purchase Warrants were issued to Southcoast Capital Corporation, as
placement agent, in partial payment of their fee). Costs of the issue were
$436,000, resulting in net proceeds to the Company of approximately $2,314,000.
Each Special Warrant was exchanged, at no additional cost, for one Common Share
on August 11, 1995.
Stock Option Plan
The Company maintains a Stock Option Plan which authorizes the grant of options
up to 2,000,000 Common Shares. Under the plan, incentive and non-qualified
options may be issued to officers, key employees and consultants. These options
are granted at market value as defined in the plan. The plan is administered by
the Stock Option Committee of the Board.
37
Notes to Consolidated Financial Statements
Following is a summary of stock option activity during the years ended December
31, 1997, 1996 and 1995:
YEAR ENDED DECEMBER 31,
--------------------------------------------------------------
1997 1996 1995
--------------------- ------------------ ------------------
Weighted Weighted Weighted
Average Average Average
Number Price Number Price Number Price
--------- ---------- --------- --------- ------- ---------
Outstanding at beginning
of year............... 1,053,000 $ 7.63 731.925 $ 6.11 557,312 $ 6.30
Granted.................... 797,162 14.13 525,500 8.96 274,500 5.89
Terminated................. (23,250) 11.51 (6,750) 6.28 (89,887) 7.79
Exercised.................. (280,656) 6.95 (197,675) 5.42 (10,000) 5.42
Expired.................... - - - - - -
--------- ---------- --------- --------- ------- ---------
Outstanding at end of
period.................. 1,546,256 $ 11.06 1,053,000 $ 7.63 731,926 $ 6.11
========= ========== ========= ========= ======= =========
Options exercisable at end
of year................. 391,872 $ 7.57 532,375 $ 6.82 539,675 $ 6.19
========= ========== ========= ========== ======= =========
Weighted
Weighted Average Weighted
Options Outstanding as Options Average Remaining Exercisable Average
of December 31, 1997: Outstanding Price Life (yrs.) Options Price
- ---------------------- --------- --------- --------------- ---------- ---------
Exercise price of:
$5.55 to $7.00 384,750 $ 6.42 7.02 183,375 $ 5.88
$7.01 to $13.37 382,419 9.67 8.22 205,504 9.19
$13.38 to $22.24 779,087 14.49 9.23 2,993 13.88
In 1995, the United States Financial Accounting Standards Board issued Statement
of Financial Accounting Standards ("SFAS") No. 123, "Accounting for Stock-Based
Compensation." With regard to its stock option plan, the Company applies APB
Opinion No. 25 as allowed under SFAS 123 in accounting for this plan and
accordingly no compensation cost has been recognized. Had compensation expense
been determined based on the fair value at the grant dates for the stock option
grants consistent with the method of SFAS No. 123, the Company's net income and
net income per common share would have been reduced to the pro forma amounts
indicated below:
YEAR ENDED DECEMBER 31,
------------------------
1997 1996 1995
------ ------ ------
NET INCOME:
As reported (thousands)..........................$14,903 $8,744 $ 714
Pro forma (thousands)............................ 14,130 8,215 503
NET INCOME PER COMMON SHARE:
As reported:
Basic.........................................$ 0.74 $ 0.67 $ 0.10
Fully diluted................................. 0.70 0.62 0.10
Pro forma:
Basic.........................................$ 0.70 $ 0.63 $ 0.07
Fully diluted................................. 0.66 0.59 0.07
Stock options issued during period (thousands)...... 797 526 275
Weighted average exercise price.....................$ 14.13 $ 8.96 $ 5.90
Average per option compensation value of options
granted (a)...................................... 4.02 2.95 2.34
Compensation cost (thousands)....................... 1,227 801 320
<FN>
(a) Calculated in accordance with the Black-Scholes option pricing model, using
the following assumptions: expected volatility computed using, as of the
date of grant, the prior three-year monthly average of the Common Shares as
listed on the TSE, which ranged from 29% to 67%; expected dividend yield -
0%; expected option term - 3 years; and risk-free rate of return as of the
date of grant which ranged from 5.3% to 7.8%, based on the yield of
five-year U.S. treasury securities.
</FN>
38
Notes to Consolidated Financial Statements
Stock Purchase Plan
In February 1996, the Company also implemented a Stock Purchase Plan which
authorizes the sale of up to 250,000 Common Shares to all full-time employees.
Under 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 Shares of the Company based on its
current market value at the end of the each quarter. The Company recognizes
compensation expense for the 75% Company matching portion, which totaled
$383,000 and $147,000 for the years ended December 31, 1997 and 1996,
respectively. This plan is administered by the Stock Purchase Plan Committee of
the Board.
NOTE 6. PRODUCT PRICE HEDGING CONTRACTS
In 1995, the Company entered into two swap contracts for oil. The first oil
contract was for 500 Bbls/d of oil at a price of $17.79 per barrel of oil
commencing on February 1, 1995 and ending on January 31, 1996. The second oil
contract was also for 500 Bbls/d of oil at a price of $18.83, for the period
commencing on April 12, 1995 and ending on December 30, 1995. These contracts
covered 43% of the Company's net revenue interest production for 1995 and
decreased oil and natural gas revenues by approximately $47,000 during such
period.
The Company does not have any hedge contracts in place as of December 31, 1997.
NOTE 7. COMMITMENTS AND CONTINGENCIES
The Company has operating leases for the rental of office space, office
equipment, and vehicles. At December 31, 1997, long-term commitments for these
items require the following future minimum rental payments:
December 31,
AMOUNTS IN THOUSANDS 1997
---------
1998 .................$ 473
1999 ................. 1,076
2000 ................. 1,074
2001 ................. 1,069
2002 ................. 1,055
---------
Total lease commitments $ 4,747
=========
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 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.
From time to time, the Company is a party to legal proceedings in the ordinary
course of its business, including actions for personal injury and property
damage occurring as a result of the operation of wells, and claims for
environmental damage. In June of 1997, a well blow-out occurred at the Lake
Chicot Field, for which the Company is operator, in St. Martin Parish, Louisiana
in which four individuals that were employees of other third party entities were
killed, none of who were employees or contractors of the Company. In connection
with this blow-out, a lawsuit was filed on July 2, 1997, Barbara Trahan, et al
.v. Mallard Bay Drilling L.L.C., Parker Drilling Company and Denbury Management,
Inc., Case No. 58226-G in the 16th Judicial District Court in St. Martin Parish,
Louisiana alleging various defective and dangerous conditions, violation of
certain rules and regulations and acts of negligence. The Company believes that
all litigation to which it is a party is covered by insurance and none of such
legal proceedings can be reasonably expected to have a material adverse effect
on the Company's financial condition, results of operations or cash flows.
39
Notes to Consolidated Financial Statements
NOTE 8. DIFFERENCES IN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES BETWEEN CANADA
AND THE UNITED STATES
The consolidated financial statements have been prepared in accordance with GAAP
in Canada. The primary differences between Canadian and U.S. GAAP affecting the
Company's consolidated financial statements are as discussed below.
Loss on Extinguishment of Debt and Imputed Preferred Dividends
The most significant GAAP difference relates to the presentation of the early
extinguishment of debt and the imputed dividend on the Convertible Preferred.
During 1996, the Company expensed $1,281,000 relating to the imputed preferred
dividend, as required under Canadian GAAP. Under U.S. GAAP, this dividend would
be deducted from net income to compute the net income attributable to the common
shareholders. The Company also expensed its debt issue cost relating to the
Company's prior bank credit agreements totaling $440,000 and $200,000 for 1996
and 1995, respectively. Under Canadian GAAP this is an operating expense, while
under U.S. GAAP a loss on early extinguishment of debt is an extraordinary item.
While net income per common share and all balance sheet accounts are not
affected by these differences in GAAP, the net income for 1996 under U.S. GAAP
would be $10,025,000, while under Canadian GAAP the amount reported was
$8,744,000.
Earnings Per Share
In addition, the methodology for computing fully diluted earnings per common
share is not consistent between the two countries. For Canadian purposes, the
proceeds from dilutive securities are used to reduce debt in the calculation.
Under U.S. GAAP, Statement of Financial Accounting Standards ("SFAS") No. 128
requires the proceeds from such instruments be used to repurchase Common Shares.
Under U.S. GAAP, fully diluted earnings per share would be $0.70, $0.63 and
$0.10 for the years ended December 31, 1997, 1996 and 1995 as compared to the
$0.70, $0.62 and $0.10 reported under Canadian GAAP.
Recently Issued Accounting Standards
The Accounting Standards Executive Committee of the American Institute of
Certified Public Accountants has adopted Statement of Position 96-1,
"Environmental Remediation Liabilities," which provides guidance on the
recognition, measurement, display and disclosure of environmental remediation
liabilities. The Statement is effective for the Company's 1997 fiscal year but
did not have any material effect on the financial position or results of
operations of the Company.
In June 1997, the FASB issued SFAS No. 130, "Reporting Comprehensive Income" and
SFAS No. 131, "Disclosures About Segments of an Enterprise and Related
Information." SFAS No. 130 establishes standards for reporting and display of
comprehensive income in the financial statements. Comprehensive income is the
total of net income and all other non-owner changes in equity. SFAS No. 131
requires that companies disclose segment data based on how management makes
decisions about allocating resources to segments and measuring their
performance. SFAS Nos. 130 and 131 are effective for 1998. Adoption of these
standards is not expected to have an effect on the Company's financial
statements, financial position or results of operations.
NOTE 9. SUPPLEMENTAL INFORMATION
Significant Oil and Natural Gas Purchasers
Oil and natural gas sales are made on a day-to-day basis or under short-term
contracts at the current area market price. The loss of any purchaser would not
be expected to have a material adverse effect upon operations. For the year
ended December 31, 1997, the Company sold 10% or more of its net production of
oil and natural gas to the following purchasers: Hunt Refining (42%), Natural
Gas Clearinghouse (22%) and Columbia Energy Services (10%).
Costs Incurred
The following table summarizes costs incurred 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 revenues in place.
Exploration costs include costs of identifying areas that may warrant
examination and in 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.
40
Notes to Consolidated Financial Statements
Costs incurred in oil and natural gas activities for the years ended December
31, 1997, 1996 and 1995 are as follows:
YEAR ENDED DECEMBER 31,
---------------------------
AMOUNTS IN THOUSANDS 1997 1996 1995
-------- -------- -------
Property acquisition..... $226,809 $ 48,856 $17,198
Exploration.............. 20,734 4,592 1,687
Development.............. 57,884 33,409 9,639
-------- ------- -------
Total costs incurred $305,427 $ 86,857 $28,524
======== ======== =======
Property Acquisitions
On December 30, 1997, Denbury acquired producing oil and natural gas properties
in Mississippi for approximately $202 million (the "Chevron Acquisition"). The
acquisition included 122 wells, of which 96 wells will be Company operated. The
Company funded this acquisition with bank financing from a revised and restated
credit facility.
This acquisition was accounted for under purchase accounting and the results of
operations will be consolidated effective December 31, 1997. Pro forma results
of operations of the Company as if the Chevron Acquisition had occurred at the
beginning of each respective period are as follows:
YEAR ENDED DECEMBER 31,
------------------------
Amounts in thousands except 1997 1996
per share amounts(Unaudited) --------- --------
Revenues.........................$ 104,695 $ 77,311
Net income....................... 9,533 4,909
Net income per common share:
Basic......................... 0.47 0.37
Fully diluted................. 0.46 0.37
In computing the pro forma results, depreciation, depletion and amortization
expense was computed using the units of production method, and an adjustment was
made to interest expense reflecting the bank debt that was required to fund the
acquisitions. The pro forma results reflect an increase of $687,000 in general
and administrative expense for additional personnel and associated costs
relating to the acquired properties, net of anticipated allocations to
operations and capitalization of exploration costs.
The following represents the revenues and direct operating expenses attributable
to the net interest acquired in the Chevron Acquisition by the Company and are
presented on the full cost accrual basis of accounting. Depreciation, depletion
and amortization, allocated general and administrative expenses, interest
expense and income, and income taxes have been excluded because the property
interests acquired represent only a portion of a business and these expenses are
not necessarily indicative of the expenses to be incurred by the Company.
YEAR ENDED DECEMBER 31,
----------------------------
1997 1996 1995
-------- ------- -------
Amount in Thousands (Unaudited)
Revenues:
Oil, natural gas and related
product sales.....................$ 18,239 $23,662 $17,460
Direct operating expenses:
Lease operating expense............. 6,932 6,650 5,825
-------- ------- -------
Excess of revenues over direct operating
expenses..........................$ 11,307 $17,012 $11,635
======== ======= =======
41
Notes to Consolidated Financial Statements
10. CONDENSED CONSOLIDATING FINANCIAL INFORMATION
Denbury Management, Inc. issued debt securities during February 1998 which are
fully and unconditionally guaranteed by Denbury Resources Inc. Denbury Holdings
Ltd. was merged into Denbury Resources Inc. in December 1997 and is not a
guarantor of the debt. Condensed consolidating financial information for Denbury
Resources Inc. and Subsidiaries as of December 31, 1997 and 1996 and for the
years ended December 31, 1997, 1996 and 1995 is as follows:
DENBURY RESOURCES INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEETS
December 31, 1997
--------------------------------------------------------
Denbury Denbury Denbury
Management Resources Resources
Amounts in Thousands Inc. Inc. Inc.
(Issuer) (Guarantor) Eliminations Consolidated
--------- --------- ------------ ----------
ASSETS
Current assets............................................ $ 33,017 $ 363 $ -- $ 33,380
Property and equipment (using full cost accounting........ 408,832 -- -- 408,832
Investment in subsidiaries (equity method)................ -- 159,892 (159,892) --
Other assets ............................................. 5,234 102 -- 5,336
--------- --------- ------------ ----------
Total assets........................................... $ 447,083 $ 160,357 $ (159,892) $ 447,548
========= ========= ============ ==========
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities....................................... $ 30,554 $ 134 $ -- $ 30,688
Long-term liabilities .................................... 256,637 -- -- 256,637
Shareholders' equity...................................... 159,892 160,223 (159,892) 160,223
--------- --------- ------------ ----------
Total liabilities and shareholders' equity............. $ 447,083 $ 160,357 $ (159,892) $ 447,548
========= ========= ============ ==========
December 31, 1996
-----------------------------------------------------------------------
Denbury Denbury Denbury
Management Denbury Resources Resources
Amounts in Thousands Inc. Holdings Inc. Inc.
(Issuer) Ltd. (Guarantor) Eliminations Consolidated
--------- --------- ---------- ------------ ------------
ASSETS
Current assets........................................... $ 28,722 $ -- $ 280 $ -- $ 29,002
Property and equipment (using full cost accounting)...... 134,996 -- -- -- 134,996
Investment in subsidiaries (equity method)............... -- 142,321 140,763 (283,084) --
Other assets ............................................ 2,505 -- 1,560 (1,558) 2,507
--------- --------- ---------- ------------ ------------
Total assets.......................................... $ 166,223 $ 142,321 $ 142,603 $ (284,642) $ 166,505
========= ========= ========== ============ ============
LIABILITIES AND SHAREHOLDERS'EQUITY
Current liabilities...................................... $ 16,421 $ -- $ 99 $ -- $ 16,520
Long-term liabilities ................................... 7,481 1,558 -- (1,558) 7,481
Shareholders' equity .................................... 142,321 140,763 142,504 (283,084) 142,504
--------- --------- ---------- ------------ ------------
Total liabilities and shareholders' equity............ $ 166,223 $ 142,321 $ 142,603 $ (284,642) $ 166,505
========= ========= ========== ============ ============
42
Notes to Consolidated Financial Statements
DENBURY RESOURCES INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF INCOME
(in thousands of U.S. dollars)
Year Ended December 31, 1997
-----------------------------------------------------------------------
Denbury Denbury Denbury
Management Denbury Resources Resources
Inc. Holdings Inc. Inc.
Amounts in Thousands (Issuer) Ltd. (Guarantor) Eliminations Consolidated
--------- --------- ---------- ------------ ------------
Revenues....................... $ 86,451 $ -- $ 150 $ (145) $ 86,456
Expenses....................... 62,658 -- 145 (145) 62,658
--------- --------- ---------- ------------ ------------
Income before the following: 23,793 -- 5 -- 23,798
Equity in net earnings of
subsidiaries................ -- 14,898 14,898 (29,796) --
--------- --------- ---------- ------------ ------------
Income before income taxes..... 23,793 14,898 14,903 (29,796) 23,798
Provision for income taxes..... (8,895) -- -- -- (8,895)
--------- --------- ---------- ------------ ------------
Net income..................... $ 14,898 $ 14,898 $ 14,903 $ (29,796) $ 14,903
========= ========= ========== ============ ============
Year Ended December 31, 1996
-----------------------------------------------------------------------
Denbury Denbury Denbury
Management Denbury Resources Resources
Inc. Holdings Inc. Inc.
Amounts in Thousands (Issuer) Ltd. (Guarantor) Eliminations Consolidated
--------- --------- ---------- ------------ ------------
Revenues....................... $ 53,631 $ -- $ 179 $ (161) $ 53,649
Expenses....................... 38,008 -- 1,746 (161) 39,593
--------- --------- ---------- ------------ ------------
Income (loss) before the
following: 15,623 -- (1,567) -- 14,056
Equity in net earnings of
subsidiaries................ -- 10,311 10,311 (20,622) --
--------- --------- ---------- ------------ ------------
Income before income taxes..... 15,623 10,311 8,744 (20,622) 14,056
Provision for income taxes..... (5,312) -- -- -- (5,312)
--------- --------- ---------- ------------ ------------
Net income..................... $ 10,311 $ 10,311 $ 8,744 $ (20,622) $ 8,744
========= ========= ========== ============ ============
Year Ended December 31, 1995
-----------------------------------------------------------------------
Denbury Denbury Denbury
Management Denbury Resources Resources
Inc. Holdings Inc. Inc.
Amounts in Thousands (Issuer) Ltd. (Guarantor) Eliminations Consolidated
--------- --------- ---------- ------------ ------------
Revenues....................... $ 20,107 $ -- $ 460 $ (458) $ 20,109
Expenses....................... 19,026 -- 460 (458) 19,028
--------- --------- ---------- ------------ ------------
Income before the following: 1,081 -- -- -- 1,081
Equity in net earnings of
subsidiaries................ -- 714 714 (1,428) --
--------- --------- ---------- ------------ ------------
Income before income taxes..... 1,081 714 714 (1,428) 1,081
Provision for income taxes..... (367) -- -- -- (367)
--------- --------- ---------- ------------ ------------
Net income..................... $ 714 $ 714 $ 714 $ (1,428) $ 714
========= ========= ========== ============ ============
43
Notes to Consolidated Financial Statements
NOTE 11. SUPPLEMENTAL RESERVE INFORMATION (UNAUDITED)
Net proved oil and natural gas reserve estimates as of December 31, 1997, 1996
and 1995 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 except in those instances where the sale is covered by contract, in
which case the applicable contract prices including fixed and determinable
escalations were used for the duration of the contract, and thereafter the last
contract price was used. Operating costs, production and ad valorem taxes and
future development costs were based on current costs with no escalation.
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,
------------------------------------------------
1997 1996 1995
--------------- -------------- ---------------
Oil Gas Oil Gas Oil Gas
(MBbl) (MMcf) (MBbl) (MMcf) (MBbl) (MMcf)
------- ------ ------ ------ ------- ------
BALANCE BEGINNING OF YEAR..... 15,052 74,102 6,292 48,116 4,230 42,047
Revisions of previous
estimates................ 3,398 1,098 (490) 3,737 830 (1,620)
Revisions due to price
changes.................. (1,525) (317) 1,053 402 -- --
Extensions, discoveries
and other additions...... 6,373 11,205 3,492 5,480 732 --
Production................. (2,884)(13,257) (1,500) (8,933) (728) (4,844)
Acquisition of minerals in
place.................... 31,604 4,360 6,205 25,300 1,228 12,533
------- ------ ------ ------ ------- ------
BALANCE AT END OF YEAR........ 52,018 77,191 15,052 74,102 6,292 48,116
======= ====== ====== ====== ======= ======
PROVED DEVELOPED RESERVES:
Balance at beginning of
year..................... 13,371 58,634 5,290 34,894 3,755 35,578
Balance at end of year..... 31,355 69,805 13,371 58,634 5,290 34,894
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. 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.
44
Notes to Consolidated Financial Statements
DECEMBER 31,
----------------------------
AMOUNTS IN THOUSANDS 1997 1996 1995
-------- -------- --------
Future cash inflows.............................. $957,718 $627,476 $214,932
Future production costs.......................... (285,968) (134,986) (56,323)
Future development costs......................... (68,287) (28,722) (16,154)
-------- -------- --------
Future net cash flows before taxes .............. 603,463 463,768 142,455
10% annual discount for estimated timing of
cash flows..................................... (242,134) (147,670) (45,490)
-------- -------- --------
Discounted future net cash flows before taxes.... 361,329 316,098 96,965
Discounted future income taxes................... (26,021) (74,226) (15,801)
-------- -------- --------
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET
CASH FLOWS....................................... $335,308 $241,872 $ 81,164
======== ======== ========
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 1997 1996 1995
-------- -------- --------
BEGINNING OF YEAR................................ $241,872 $ 81,164 $ 46,928
Sales of oil and natural gas produced, net of
production costs.............................. (63,115) (39,385) (13,243)
Net changes in sales prices...................... (132,905) 116,587 23,037
Extensions and discoveries, less applicable
future development and production costs...... 75,632 34,113 1,926
Previously estimated development costs incurred.. 10,088 5,278 2,193
Revisions of previous estimates, including
revised estimates of development costs,
reserves and rates of production.............. 264 7,747 3,958
Accretion of discount............................ 24,187 8,116 4,693
Purchase of minerals in place.................... 131,080 86,677 21,710
Net change in income taxes....................... 48,205 (58,425) (10,038)
-------- -------- --------
END OF YEAR...................................... $335,308 $241,872 $ 81,164
======== ======== ========
NOTE 12. SUBSEQUENT EVENTS
On February 26, 1998, the Company closed on a public offering of 5,240,780
Common Shares (which included the underwriter's over-allotment option of 683,580
Common Shares) at a price to the public of $16.75 per share and a net price to
the Company of $15.955 per share (the "Equity Offering"). Concurrently with the
Equity Offering, affiliates of TPG, the Company's largest shareholder, purchased
313,400 Common Shares from the Company at $15.955 per share, equal to the price
to the public per share less underwriting discounts and commissions (the "TPG
Purchase"). The net proceeds to the Company from the Equity Offering and TPG
Purchase was approximately $88.6 million, before offering expenses.
Concurrently with the Equity Offering and TPG Purchase, Denbury Management Inc.,
a wholly-owned subsidiary of the Company, issued $125 million in aggregate
principal amount of 9% Senior Subordinated Notes Due 2008 (the "Debt Offering"
and the "Notes"). These Notes contain certain debt convents, 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 was approximately $121.8 million,
before offering expenses.
45
Notes to Consolidated Financial Statements
The total net proceeds from the debt and equity offerings were approximately
$209.8 million after deducting the estimated offering expenses of $600,000. The
Company used these proceeds to reduce outstanding borrowings under the Company's
bank credit facility, the majority of which had been borrowed to fund the $202
million Chevron Acquisition. On a pro forma basis using U.S. GAAP and assuming
that the Equity Offering, TPG Purchase and the Debt Offering had closed as of
January 1, 1997 and the interest expense for 1997 relating to the bank debt was
reversed, the basic and fully diluted earnings per share would be $0.32 per
share. No interest income as assumed in the pro forma calculation even though
the proceeds from the offerings exceeded the bank debt retired for most of the
year.
The following table sets forth the actual capitalization of the Company as of
December 31, 1997 and the pro forma capitalization as adjusted for the Equity
Offering, TPG Purchase and Debt Offering:
December 31, 1997
---------------------
Historical Pro forma
--------- ---------
(Unaudited)
Short-term debt:
Other $ 20 $ 20
--------- ---------
Long-term debt:
Credit Facility 240,000 30,200
9% Senior Subordinated Notes due 2008 - 125,000
--------- ---------
Total long-term debt 240,000 155,200
--------- ---------
Shareholders equity:
Common shares 133,139 221,139
Retained earnings 27,084 27,084
--------- ---------
Total shareholders equity 160,223 248,223
--------- ---------
Total capitalization $ 400,243 $ 403,443
========= =========
UNAUDITED QUARTERLY INFORMATION
The following table presents unaudited summary financial information on a
quarterly basis for 1997 and 1996.
IN THOUSANDS EXCEPT PER SHARE AMOUNTS
MARCH 31 JUNE 30 SEPT. 30 DECEMBER 31
- --------------------------------- ----------- ---------- ---------- ------------
1997
Revenues $ 21,653 $ 19,015 $ 20,401 $ 25,387
Expenses 13,375 15,512 15,304 18,467
Net income 5,215 2,207 3,211 4,270
Net income per share:
Basic 0.26 0.11 0.16 0.21
Fully diluted 0.24 0.11 0.15 0.20
Cash flow from operations (b) 14,922 12,001 13,243 16,441
- --------------------------------- ----------------------------------------------
1996
Revenues $ 9,092 $ 11,682 $ 14,359 $ 18,516
Expenses 6,767 9,608 11,486 11,732
Net income 1,380 1,215 1,745 4,404
Net income per share: (a)
Basic 0.12 0.11 0.14 0.25
Fully diluted 0.11 0.11 0.13 0.23
Cash flow from operations (b) 6,065 7,238 8,464 12,373
<FN>
(a) Due to the significant variances between quarters in net income and average
shares outstanding, the combined quarterly income per share does not equal
the reported earnings per share for 1996.
(b) Exclusive of the net change in non-cash working capital balances.
</FN>
46
Notes to Consolidated Financial Statements
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 Common Shares on The New York Stock
Exchange ("NYSE"), NASDAQ 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/ NASDAQ are reported in U.S. dollars and the TSE trades are
reported in Canadian dollars. The Company's Common Shares were listed on NASDAQ
from August 25, 1995 to May 8, 1997. The Common Shares have been listed on the
NYSE since May 8, 1997.
As of February 1, 1998, to the best of the Company's knowledge, the Common
Shares were held of record by approximately 1,200 holders, of which
approximately 150 were U.S. residents holding approximately 70% of the
outstanding Common Shares of the Company.
No Common Share dividends have been paid or are anticipated to be paid. (See
also Note 5 to the Consolidated Financial Statements).
NYSE/NASDAQ (U.S.$) TSE (CDN $)
HIGH LOW HIGH LOW
- -------------------------------------------------------------------------
1997
First quarter 16.00 12.00 21.75 16.40
Second quarter 17.63 13.13 24.50 18.00
Third quarter 23.75 16.13 33.00 22.20
Fourth quarter 24.63 17.88 33.50 25.50
- -------------------------------------------------------------------------
1997 annual 24.63 12.00 33.50 16.40
- -------------------------------------------------------------------------
1996
First quarter 7.88 6.25 10.80 8.30
Second quarter 10.75 8.50 14.50 12.00
Third quarter 13.50 10.00 18.10 12.70
Fourth quarter 15.25 12.50 20.95 17.00
- -------------------------------------------------------------------------
1996 annual 15.25 6.25 20.95 8.30
- -------------------------------------------------------------------------
47