EXHIBIT 13
PAGE 3 AND PAGES 8 THROUGH 47, INCLUSIVE, OF THE COMPANY'S ANNUAL REPORT TO
SHAREHOLDERS FOR THE YEAR ENDED DECEMBER 31, 1996, 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.
1
FINANCIAL HIGHLIGHTS
YEAR ENDED DECEMBER 31, AVERAGE
ANNUAL
GROWTH (2)
-------------------------------------------------------- -----------
AMOUNTS IN THOUSANDS OF U.S. DOLLARS UNLESS NOTE 1996 1995 1994 1993 1992
- -------------------------------------------------------------------------------------------------------------------
PRODUCTION (DAILY)
Oil (Bbls) 4,099 1,995 1,340 858 221 108%
Gas (Mcf) 24,406 13,271 9,113 2,013 1,288 109%
BOE (6:1) 8,167 4,207 2,858 1,193 436 108%
REVENUE (NET OF ROYALTIES)
Oil sales 28,475 10,852 6,767 4,356 1,244 119%
Gas sales 24,405 9,180 5,925 1,512 668 146%
Total 52,880 20,032 12,692 5,868 1,912 129%
UNIT SALES PRICE
Oil (per Bbl) 18.98 14.90 13.84 13.91 15.36 5%
Gas (per Mcf) 2.73 1.90 1.78 2.06 1.42 18%
CASH FLOW FROM OPERATIONS (1) 34,140 9,394 6,185 3,030 354 213%
NET INCOME 8,744 714 1,163 1,735 (335) 126%
AVERAGE COMMON SHARES OUTSTANDING 13,104 6,870 6,240 4,990 2,949 45%
PER SHARE:
PER SHARE:
Cash flow from operations: (1)
Primary 2.51 1.37 0.99 0.61 0.12 114%
Fully diluted 2.07 1.37 0.99 0.61 0.12 106%
Net income:
Primary 0.67 0.10 0.19 0.35 (0.11) 83%
Fully diluted 0.62 0.10 0.19 0.35 (0.11) 82%
OIL AND GAS CAPITAL INVESTMENTS 86,857 28,524 16,903 29,855 6,189 94%
TOTAL ASSETS 166,505 77,641 48,964 35,978 8,225 112%
LONG-TERM LIABILITIES 7,481 5,077 17,768 6,633 205 146%
SHAREHOLDERS' EQUITY AND
PREFERRED STOCK 142,504 68,501 25,962 24,431 7,548 108%
PROVEN RESERVES
Oil (MBbls) 15,052 6,292 4,230 3,583 1,243 87%
Gas (MMcf) 74,102 48,116 42,046 13,029 2,895 125%
BOE (6:1) 27,403 14,312 11,237 5,755 1,725 100%
Discounted future cash flow - 10% 316,098 96,965 52,691 28,638 8,512 147%
PER BOE DATA (6:1)
Revenue 17.69 13.05 12.17 13.47 11.99 10%
Production expenses (4.51) (4.42) (4.13) (4.75) (3.97) 3%
- -------------------------------------------------------------------------------------------------------------------
Production netback 13.18 8.63 8.04 8.72 8.02 13%
General and administrative expenses (1.50) (1.25) (1.12) (1.80) (5.99) (29)%
Interest expenses (0.26) (1.26) (0.99) 0.04 0.19 8%
- -------------------------------------------------------------------------------------------------------------------
CASH FLOW (1) 11.42 6.12 5.93 6.96 2.22 51%
- -------------------------------------------------------------------------------------------------------------------
<FN>
(1) Exclusive of the net change in non-cash working capital balances.
(2) Computed using 1992 as a base year.
</FN>
----------------------------------------------------------------------
Reporting Format
During 1995, the Company began reporting its financial results in a format more
consistent with U.S. presentations. 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, (iii) gas volumes are
converted to equivalent barrels at 6:1.
3
Selected Operating Data
OIL AND GAS RESERVES
The reserves at December 31, 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 31 of each year. The reserves do not
include any value for probable or possible reserves which may exist, nor do they
include any value for undeveloped acreage. The reserve estimates represent the
net revenue interest (after royalties) of the Company. The 1994 reserves were
prepared by the Scotia Group.
AS OF DECEMBER 31,
-------------------------------------------
1996 1995 1994
------------- ------------ ------------
ESTIMATED PROVED RESERVES:
Oil (MBbls)................................................ 15,052 6,292 4,230
Natural Gas (MMcf)......................................... 74,102 48,116 42,047
Oil Equivalent (MBOE)...................................... 27,403 14,311 11,238
PERCENTAGE OF MBOE:
Proved producing........................................... 45% 38% 44%
Proved non-producing....................................... 39% 40% 42%
Proved undeveloped......................................... 16% 22% 14%
REPRESENTATIVE OIL AND GAS PRICES: (1)
West Texas Intermediate $ 23.39 $ 18.00 $ 15.48
NYMEX Henry Hub 3.90 2.24 1.66
PRESENT VALUES:
Discounted estimated future net cash flow before
income taxes (PV10 Value) (thousands) (2)..............$ 316,098 (3)$ 96,965 $ 52,691
Standardized measure of discounted estimated future net
cash flow after net income taxes (thousands)..............$ 241,872 $ 81,164 $ 46,928
---------------
<FN>
(1) The oil prices as of each respective year-end were based on West Texas
Intermediate "WTI"prices per barrel and NYMEX Henry Hub 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) Since December 31, 1996, the oil and natural gas prices have significantly
declined which reduce not only the PV10 value, but may also reduce the
reserve quantities. 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.
</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,
----------------------------------------------
1996 1995 1994
------------- ------------- -------------
Property acquisition.................................... $ 48,856 $ 17,198 $ 6,736
Exploration............................................. 4,592 1,687 1,796
Development............................................. 33,409 9,639 8,371
------------- ------------- -------------
TOTAL CAPITAL EXPENDITURES $ 86,857 $ 28,524 $ 16,903
============= ============= =============
8
FINDING COST
Finding costs are one of the primary critical factors in determining a company's
profitability. During 1996, the Company spent almost 56% of its capital
expenditures on acquisitions. This helps provide the base for future growth but
often carries a higher unit cost per barrel until after the Company has had an
opportunity to better evaluate the properties and determine their ultimate
potential. In addition, one must also look at the type of reserves acquired as
the cost per BOE will vary depending on the 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
1996 1994-1996 DATE
- ----------------------------------------------------------------------------------------------------------
Total capitalized costs (millions) $ 86.9 $ 132.4 $ 166.1
Proved reserve additions and production (MMBOE) 16.1 27.2 33.5
- ----------------------------------------------------------------------------------------------------------
AVERAGE FINDING COST PER BOE (6:1) $ 5.40 $ 4.87 $ 4.96
- ----------------------------------------------------------------------------------------------------------
FIELD SUMMARIES
1996
PROVED RESERVES AS OF DECEMBER 31, 1996 AVERAGE PRODUCTION (1)
-------------------------------------------- ----------------------- AVERAGE
NATURAL NATURAL GROSS NET
OIL GAS PV10 VALUE PV10 VALUE OIL GAS PRODUCTIVE REVENUE
(MBBLS) (MMCF) (000'S) % OF TOTAL (BBLS/D) (MCF/D) WELLS (2) INTEREST(2)
------------------------------------------------------------------------------------------ ----------
LOUISIANA
Lirette.......... 255 26,854 $ 70,285 22.2% 164 9,188 16 61.0%
Gibson........... 285 7,591 23,449 7.4% 180 4,080 2 53.8%
Lake Chicot...... 253 6,761 21,272 6.7% 20 5 6 37.6%
South Chauvin.... 244 8,711 20,798 6.6% 10 381 4 72.9%
Bayou Rambio..... 45 6,022 15,559 4.9% 20 1,548 1 72.1%
Lapeyrouse....... 128 2,593 8,657 2.7% 3 68 3 61.8%
Other Louisiana.. 1,435 10,807 41,888 13.4% 615 6,202 78 42.5%
-------- ---------- ---------- ---------- --------- --------- ---------- ----------
Total Louisiana 2,645 69,339 201,908 63.9% 1,012 21,472 110 46.6%
-------- ---------- ---------- ---------- --------- --------- ---------- ----------
MISSISSIPPI
Eucutta.......... 4,131 - 33,472 10.6% 776 - 34 74.7%
Davis............ 2,670 - 23,979 7.6% 764 - 24 72.3%
Quitman.......... 2,289 - 19,498 6.2% 224 - 15 77.6%
Dexter........... - 3,503 7,438 2.4% 1 2,027 7 51.7%
West Yellow Creek 1,054 - 7,381 2.3% 268 - 7 78.2%
S. Thompson Creek 379 - 4,493 1.4% 257 - 4 80.2%
Other Mississippi 1,754 696 14,357 4.5% 721 376 79 40.8%
-------- ---------- ---------- ---------- --------- --------- ---------- ----------
Total Mississippi 12,277 4,199 110,618 35.0% 3,011 2,403 170 58.2%
-------- ---------- ---------- ---------- --------- --------- ---------- ----------
OTHER............... 130 564 3,572 1.1% 76 531 16 36.7%
-------- ---------- ---------- ---------- --------- --------- ---------- ----------
COMPANY TOTAL 15,052 74,102 $ 316,098 100.0% 4,099 24,406 296 52.7%
======== ========== ========== ========== ========= ========= ========== ==========
<FN>
(1) Average production during the period from January 1, 1996 through December
31, 1996. Certain properties, including those purchased in the Hess and
Ottawa Acquisitions, were acquired during 1996. This table only includes
production during the periods when such properties were owned by the
Company.
(2) Includes only productive wells in which the Company had a working interest
as of December 31, 1996.
</FN>
9
ACQUISITIONS OF OIL AND NATURAL GAS PROPERTIES
The Company regularly seeks to acquire properties that complement its
operations, that provide exploitation, exploration and development opportunities
and that have cost reduction potential. The Company has purchased the majority
of its current producing wells and has increased production by a variety of
techniques, including development drilling, increasing fluid withdrawal and
reworking existing wells. These acquisitions have also balanced the Company's
reserve mix between oil and natural gas, increased the scale of its operations
in the onshore Gulf Coast area and provided the Company with a significant base
of operations within its area of geographic focus. Since 1993, aggregate
expenditures to acquire producing properties were approximately $91.9 million.
During 1996, the Company spent approximately $45 million on its two largest
acquisitions. These two acquisitions are discussed below.
Hess Acquisition
The largest acquisition by the Company to date, which occurred during the first
half of 1996, was the acquisition of producing oil and natural gas properties in
Mississippi, Louisiana, and Alabama for approximately $37.2 million from Amerada
Hess (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. By December 1996, the Company had
increased the production on these properties to approximately 3,400 BOE/d. In
the Company's December 31, 1996 independent reserve report (the "December
Report"), the properties in this acquisition had estimated net proved reserves
of approximately 9.5 MMBOE with a discounted present value using a 10% discount
rate ("PV10 Value") of $96.1 million. This compares to approximately 5.9 MMBOE
and a $43.1 million PV10 Value as of July 1, 1996 in the Company's mid-year
independent reserve report (the "July Report").
Prices were calculated in the December Report based on a West Texas Intermediate
("WTI") price of $23.39 per Bbl and a NYMEX Henry Hub price of $3.90 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. For comparative purposes the Company also
prepared a December 31, 1996 report using a WTI price of $21.00 per Bbl and
NYMEX price of $2.40 per MMBTU, with these prices also adjusted by field (the
"Modified Report"). The PV10 Value in the Modified Report was $72.0 million for
the properties acquired in the Hess Acquisition.
Three fields, out of a total of 60 fields, comprise over 75% of the total Hess
Acquisition PV10 Value as of December 31, 1996. The two largest fields in
Mississippi, Eucutta and Quitman Fields, make up approximately 55% of the total
PV10 Value. Both fields are in the same vicinity as the Company's existing
Mississippi core properties, with the Eucutta Field located in Wayne County,
Mississippi between the Company's Sandersville and West Yellow Creek existing
production. The Quitman Field is located in Clarke County, Mississippi, adjacent
to the Company's Davis and Frances Creek existing production. The largest field
in Louisiana is the Lake Chicot Field, which comprises approximately 22% of the
total PV10 Value. Lake Chicot is in St. Martin Parish, just Northwest of
Terrebonne Parish where the majority of the Company's existing Louisiana
production is located.
Ottawa and other 1996 Acquisitions
In addition to the Hess Acquisition, the Company completed other acquisitions
during 1996 totaling $11.2 million. The largest of these was an acquisition of
additional working interests in five Mississippi oil and natural gas properties
in which the Company already owned an interest, plus certain overriding royalty
interests in other areas, which were acquired during April 1996 for
approximately $7.5 million (the "Ottawa Acquisition"). The average daily
production from the Ottawa Acquisition during April, May and June 1996,
10
the first three months of ownership, was approximately 600 BOE/d. By December,
1996, the Company had increased the net production on these properties to
approximately 650 BOE/d.
In addition to the Ottawa Acquisition, the Company spent an additional $3.7
million on nine other acquisitions, primarily in Louisiana. The properties in
these nine acquisitions were producing approximately 360 BOE/d as of December
1996. The Company's estimated net proved reserves in the December Report for all
of these other acquisitions, including the Ottawa Acquisition, totaled
approximately 4.0 MMBOE, with a PV10 Value of $47.4 million. This compares to
approximately 3.3 MMBOE and a $24.1 million PV10 Value in the July Report. The
PV10 Value in the Modified Report was $29.4 million for these same properties.
Denbury operates in two core areas, Louisiana and Mississippi. The Company
operates 62 wells in Louisiana from an office in Houma and 119 wells in
Mississippi from an office in Laurel. Twelve of the Company's largest oil and
natural gas fields as outlined on page 9 constitute approximately 80% of its
total reserves on both a BOE and PV10 Value basis Within these 12 fields,
Denbury owns an average 84% working interest and operates 82% of the wells,
which comprise 65% of the Company's PV10 Value. This 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.
These two core areas are similar in that the major trapping mechanisms for oil
and natural gas accumulations are structural features usually related to
deep-seated salt or shale movement. Both areas typically feature mostly multiple
sandstone reservoirs with strong water-drive characteristics. However, the two
areas differ significantly in drilling costs, risks and the size of potential
reserves. In Mississippi, the producing zones are generally shallower than in
Louisiana and therefore drilling and workover costs are lower. However, the
geological complexity of southern Louisiana, which is more expensive to exploit,
creates the potential for larger discoveries, particularly of natural gas. The
Company's production in Louisiana is predominately natural gas, while
Mississippi is predominately oil.
(One illustration, not incorporated by reference - see prefacing comment on
Exhibit 13 Cover Page.)
11
(One illustration, not incorporated by reference - see prefacing comment on
Exhibit 13 Cover Page.)
12
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 areas 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 believes that the first generation
of 3-D data acquired in these swampy areas has the potential to identify
significant exploration prospects, particularly in the deeper geopressured
sections below 12,000 feet.
Lirette
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 early 1995 to increase the Company's
ownership to its current average 78% working interest.
As a result of two workovers and two wells drilled during 1996, net production
had increased during December 1996 to 11.0 MMcf/d and 167 Bbls/d from 13 wells.
During the latter half of 1996, the Lirette Field was covered by a 3-D survey
which is currently being processed and evaluated. It is anticipated that
drilling projects created out of this seismic work will probably be drilled in
late 1997 or 1998.
Gibson/Humphreys
In late 1994, Denbury acquired minor working interests in five wells in the
Gibson and Humphreys Fields located in Terrebonne Parish, 20 miles northwest of
the Lirette Field, in the northern part of the Houma embayment. The Gibson
Field, discovered in 1937, has produced over 813 Bcf and 14 MMBbls while the
Humphreys Field, discovered in 1956, has produced 527 Bcf and 6 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 majority 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
December 1996, net production in these two fields averaged approximately 5.1
MMcf/d and 90 Bbls/d. Two additional wells are currently planned in this area
during 1997.
South Chauvin
In February 1996, Denbury 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
three currently producing wells at Chauvin, Denbury owns an average 95% working
interest. During December 1996,
13
(One illustration, not incorporated by reference - see prefacing comment on
Exhibit 13 Cover Page.)
these three wells produced at an average net rate of 1.0 MMcf/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. Assuming the seismic interpretation is
favorable, the Company plans to drill two wells in 1997.
Bayou Rambio
Production at the Bayou Rambio Field was established in 1955 and has exceeded
150 Bcf and 920 MBbls to date. Denbury operates one producing well in the field,
the Kelly #2 which is located in Terrebonne Parish about 15 miles west of
Lirette Field. During December 1996, the Kelly #2 produced at an average net
rate of approximately 0.7 MMcf/d and 9 Bbls/d. The Company is currently
evaluating 15 square miles of 3-D seismic data covering this area. Based upon
this evaluation, two development locations are tentatively scheduled to be
drilled during 1997. This field has historically produced from 25 different pay
zones.
Lapeyrouse
The Lapeyrouse Field is a large structural feature which has produced over 2 Tcf
and 10 MMBbls since its discovery in 1941. Denbury currently operates one
producing well and one shut-in well and has a small interest in one other
producing well in the Lapeyrouse field. Net production from this area was
relatively minor during December 1996, averaging 0.1 MMcf/d and 2 Bbls/d.
However, this area is part of the Lirette 3-D joint venture and also will be
covered by the 147 square mile 3-D survey conducted in late 1996. The Company
believes considerable potential exists in the section below 15,000 feet which
has produced 8 Bcf from one well in the field. The Company is planning two
workovers and two additional wells in 1997, pending the evaluation of the 3-D
seismic data.
Bayou Des Allemands
The Company has a 50% working interest in 17 operated producing wells in the
Bayou Des
14
(One illustration, not incorporated by reference - see prefacing comment on
Exhibit 13 Cover Page.)
Allemands Field, located in the LaFourche and St. Charles Parishes. This field
was acquired as part of the Hess Acquisition. During December 1996, net
production from this field averaged 0.1 MMcf/d and 207 Bbls/d. Production in
this field is from discrete sand intervals located from 3,700 feet to 11,500
feet in depth. Over 30 behind pipe sands have been identified for future
completion as the present zones deplete. Additional potential may exist in updip
locations in producing fault blocks, in untested fault blocks and in deeper
horizons. A 3-D seismic survey is planned during 1997 to help identify any
upside potential.
(One illustration, not incorporated by reference - see prefacing comment on
Exhibit 13 Cover Page.)
Lake Chicot
The Company also acquired Lake Chicot Field in St. Martin Parish, Louisiana as
part of the Hess Acquisition and has a 50% working interest in 12 wells. Only
three wells are currently producing, although the Company is in the process of
returning another nine wells to production. The Company plans to drill four
wells in this area in 1997 based upon the interpretation of an existing 3-D
seismic grid over the field.
Other Louisiana
During 1996, Denbury drilled a horizontal well in the Breton Sound Blocks 12 and
13 located in Louisiana State water approximately 70 miles southeast of New
Orleans. During December, 1996 net production from this well averaged 0.3 MMcf/d
and 145 Bbls/d.
In addition the company operates wells at Bully Camp, Delarge, N. Bougere,
Atchafalaya Bay, Garden City, Grand Lake and Live Oak Fields.
Southern Louisiana 3-D Acquisitions
During 1995, the Company acquired approximately 46 square miles of 3-D seismic
data over five of its existing fields in southern Louisiana consisting of Bayou
Rambio, DeLarge, North Deep Lake, Gibson and Humphreys. During 1996, the Company
entered into a joint venture agreement with two industry partners to acquire
approximately 147 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 will own a one-third interest in any new prospects
discovered through this joint venture, which currently owns rights to over
35,000 acres within the survey area. The Company will be responsible for
one-third of the cost of both the 3-D seismic survey and any wells drilled. The
Company anticipates that the 3-D seismic survey should be completed and the data
analyzed by the fall of 1997.
15
(One illustration, not incorporated by reference - see prefacing comment on
Exhibit 13 Cover Page.)
16
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.
Eucutta
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 recent Hess
Acquisition and currently operates 31 producing oil wells and 16 saltwater
injection wells.
(One illustration, not incorporated by reference - see prefacing comment on
Exhibit 13 Cover Page.)
The field is divided into a shallow Eutaw sand unit in which the Company has a
76% working interest and the deeper Tuscaloosa sand zones in which the Company
has a 100% working interest. The Eucutta Field traps oil in multiple sandstones
in a highly faulted anticline. At present, seven different sands are productive
at depths between 5,000 feet and 11,000 feet. Most of the wells produce oil with
large amounts of saltwater, which require pumping. During December 1996, net
production from this field averaged 1,328 Bbls/d.
The Company plans a capital expenditure program at Eucutta Field which will
include upgrading production facilities, drilling wells and a 3-D seismic
evaluation. The Company believes that through a combination of these
investments, production can be increased and operating costs reduced. Eight
wells are planned to be drilled in 1997. Consideration is being given to
acquiring a 3-D seismic survey over the field and, if pursued, most likely would
occur in 1997.
Davis/Frances Creek
The Davis Field and nearby Frances Creek Field are located 42 miles northeast of
Laurel in the northern part of the Mississippi salt basin. Denbury operates 19
producing wells within the area and owns minor non-operated interests in eight
other wells. The net average production from these wells during December 1996
was approximately 1,254 Bbls/d. 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.
Both the Davis and Frances Creek Fields are relatively mature fields and produce
large amounts of saltwater. During December 1996, these fields 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 these fields
17
Operations in Mississippi
to minimize the cost of saltwater disposal and pumping equipment.
Bar graph showing the Ultimate Proved Reserves at Davis Field in thousands of
BOE from the time of acquisition by the Company.
1993 1994 1995 1996
--------- ---------- ---------- ----------
Remaining Reserves 2,605 2,906 3,473 3,387
Cumulative Production - 358 747 1,100
--------- ---------- ---------- ----------
Total 2,605 3,264 4,220 4,487
========= ========== ========== ==========
Since acquiring the majority of the field in 1993, Denbury has undertaken an
active redevelopment program including numerous workovers and two 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 with an additional well planned for 1997.
Quitman
The Quitman Field is located in Clarke County, Mississippi, 31 miles northeast
of Laurel and near the Davis and Frances Creek Fields. The Company acquired the
field as part of the Hess Acquisition and now operates seven producing wells and
13 shut-in wells. The Company owns an average working interest of 82%. In
December 1996, net production from these wells averaged 641 Bbls/d.
The Quitman Field was discovered in 1966 and has produced approximately 21
MMBbls from 18 separate reservoirs between 7,500 feet and 12,000 feet. The
principal producing zones at Quitman are the Smackover formation and several
sands in the Cotton Valley formation.
Denbury has identified 24 prospective zones behind pipe in existing shut-in
wells. Testing of these zones will begin during the second half of 1996. The
Company also plans to upgrade production and saltwater disposal facilities in an
attempt to lower operating costs.
In 1997, the Company plans to evaluate the Quitman Field and the immediate
vicinity, including Davis and Frances Creek Fields, with a 3-D seismic survey.
The Company believes that this survey will aid in the accurate evaluation of the
existing reservoir and could lead to the discovery of new producing horizons.
(One illustration, not incorporated by reference - see prefacing comment on
Exhibit 13 Cover Page.)
South Thompson Creek
The South Thompson Creek Field is located in Wayne County, Mississippi, about 23
miles southeast of Laurel. Denbury operates three wells in the field with a 100%
working interest. The South Thompson Creek Field is an anticline which has
produced a total of 3.9 MMBbls since its discovery in 1960 from sandstone
reservoirs in the Hosston, Rodessa and Tuscaloosa formations.
Denbury first acquired an interest in the field in 1993 and increased its
ownership in 1995 by acquiring the apex of the field. Subsequently, in 1995, the
Company drilled
18
Operations in Mississippi
its first horizontal well and in April 1996, Denbury acquired the remaining
interest in the field as part of the Ottawa Acquisition. A second horizontal
well was drilled in May 1996. During December 1996, the field produced an
average of 290 Bbls/d and 2,000 barrels of saltwater per day.
In 1997, the Company may drill a third horizontal well in the field pending
continued evaluation of the first two horizontal wells. In addition, there are
two shut-in wells which have recompletion potential.
West Yellow Creek
The West Yellow Creek Field is located 28 miles west of Laurel in Wayne County,
Mississippi. Denbury operates seven producing oil wells and two saltwater
disposal wells, with an average working interest of 97%. During December 1996,
net production from the field averaged 264 Bbls/d.
The Company's production is located in the central part of West Yellow Creek
Field which has produced over 34 MMBbls since 1947, with most of the production
being from the Eutaw formation at 5,000 feet. Production also occurs from
multiple sands in the Tuscaloosa and Washita-Fredericksburg formations. This
Tuscaloosa and Washita-Fredericksburg production, discovered in 1966, was
essentially abandoned prior to 1993, when the Company acquired its first
interests in the field. The Company began a drilling program in 1993 which
continued through 1994. By a combination of successful drilling and additional
production acquisitions, the Company was able to increase its net production
from 40 Bbls/d in 1993 to 250 Bbls/d in 1995. In 1996, the Company acquired an
additional 50% working interest in the operated wells through the Ottawa
Acquisition.
Sandersville
The Sandersville Field is located about 12 miles northeast of Laurel,
Mississippi. The field produces heavy oil from shallow sands of the Eutaw and
Christmas formations along with large amounts of saltwater. The Sandersville
Field was first purchased in late 1994 when Denbury acquired a 97% working
interest in 15 active and inactive wells. During 1996, the Company completed a
rework of six producing wells and two saltwater disposal wells, and net
production in December 1996 averaged 229 Bbls/d. Sandersville Field is a
four-mile-long structure with oil trapped in multiple sands at around 5,000
feet. Historically, the recovery of oil has been low and may be enhanced by
horizontal drilling. The Company plans to drill these horizontal wells at
Sandersville during 1997.
Richton Dome
In late 1996, Denbury entered into an agreement with another Company to drill a
horizontal well into an oil reservoir at Richton Dome, located in Perry County,
Mississippi. Denbury will have 50% working interest in the project, which will
test a heavy oil section in the Eutaw at 6,000 feet. Depending upon the success
of the first well, several additional drill sites could be feasible.
Other Mississippi
The Company currently owns interests in eight outside operated wells at Dexter
Field, with an average 56% working interest. These interests were acquired in
several transactions between 1992 and 1996. During December 1996, average net
production from these wells was 2.2 MMcf/d. The Company plans to drill a
development well in this field in 1997.
Denbury operates seven wells in the Puckett Field with an average working
interest of 94%. In December 1996, average net production from these wells was
97 Bbls/d. Current plans are to produce the current zones and then recomplete
these wells into uphole horizons. There are presently 13 zones identified behind
pipe for future development.
In addition, Denbury operates wells in North Clara, Diamond, Lake Utopia, Bolton
and Edwards Fields.
19
Selected Abbreviations and
Financial Table of Contents
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
Tcf ~ Trillion cubic feet of natural gas
Financial Table of Contents
Management's Discussion & Analysis 21
Independent Auditors' Report 28
Financial Statements 29
Shareholder Information 48
20
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. Since 1993, after having
disposed of its Canadian oil and natural gas properties, the Company has focused
its operations primarily onshore in Louisiana and Mississippi. Over the last
three 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.
Bar graph showing the Company's expenditures on acquisitions (in millions):
1994 1995 1996
---------- ---------- ----------
New acquisitions $ 0.3 $ 14.2 $ 41.4
Incremental acquisitions 6.3 2.6 7.0
---------- ---------- ----------
Total $ 6.6 $ 16.8 $ 48.4
========== ========== ==========
Acquisition of Hess Properties
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. By December, 1996 the Company had
increased the production on these properties to approximately 3,400 BOE/d. As of
December 31, 1996, in the Company's independent reserve report (the "December
Report"), the properties in this acquisition had estimated net proved reserves
of approximately 9.5 MMBOE with a discounted present value using a 10% discount
rate ("PV10 Value") of $96.1 million. This compares to approximately 5.9 MMBOE
of net proved reserves and a $43.1 million PV10 Value on these same properties
as of July 1, 1996 in the Company's mid-year independent reserve report (the
"July Report"). The December Report was calculated using year-end prices which
were based on a West Texas Intermediate ("WTI") price of $23.39 per Bbl and a
NYMEX Henry Hub price of $3.90 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. For
comparative purposes, the Company's independent engineer also 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
"Modified December Report"). The PV10 Value in the Modified December Report was
$72.0 million for the properties acquired in the Hess Acquisition.
Ottawa and Other 1996 Acquisitions
In addition to the Hess Acquisition, the Company completed other acquisitions
totaling $11.2 million. The largest of these was an acquisition of additional
working interests in five Mississippi oil and natural gas properties in which
the Company already owned an interest, plus certain overriding royalty interests
in other areas, which were acquired during April 1996 for approximately $7.5
million (the "Ottawa Acquisition"). The average daily production for the
properties in the Ottawa Acquisition during April, May and June 1996, the first
three months of ownership, was approximately 600 BOE/d. By December, 1996 the
Company had increased the net production on these properties to approximately
650 BOE/d.
In addition to the Ottawa Acquisition, the Company spent an additional $3.7
million on nine other acquisitions, primarily in Louisiana. The properties in
these other acquisitions were producing approximately 360 BOE/d as of December
1996. The Company's estimated net proved reserves in the December Report for all
of these other acquisitions, including the Ottawa Acquisition, totaled
approximately 4.0 MMBOE with a PV10 Value of $47.4 million. This compares to
approximately 3.3 MMBOE and a $24.1 million PV10 Value as of July 1, 1996 in the
July Report. The PV10 Value in the Modified December Report was $29.4 million
for these same properties.
21
Management's Discussion and Analysis of Financial Condition and Results of
Operations
Bar graph comparing the debt and equity of the Company (in thousands):
1994 1995 1996
--------- --------- ----------
Equity $ 25,962 $ 53,501 $ 142,504
Debt 16,376 3,371 125
1996 Capital Adjustments
During 1996, the Company issued 250,000 Common Shares for the conversion of its
6 3/4% Convertible Debentures and 75,000 Common Shares for the exercise of half
of its Cdn. $8.40 Warrants. On October 10, 1996, the Company effected a
one-for-two reverse split of its outstanding Common Shares and effective October
15, 1996, all of the Company's outstanding 9 1/2% Convertible Debentures
("Debentures") were converted by their holders into 316,590 Common Shares. At a
special meeting held on October 9, 1996, the shareholders of the Company
approved an amendment to the terms of the Convertible First Preferred Shares,
Series A ("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 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 to the Company of $12.035 per share as part
of a public offering with net proceeds to the Company of approximately $58.8
million (the "Public Offering"). The Company's largest shareholder, the Texas
Pacific Group ("TPG"), purchased 800,000 of these shares at $12.035 per share.
New Credit Facility
In order to fund the 1996 acquisitions and improve the terms and increase the
size of its previous credit facility, the Company entered into a new $150.0
million Credit Facility during the second quarter of 1996. This new facility had
a borrowing base as of December 31, 1996 of $60.0 million. The Credit Facility
is a two-year revolving credit facility that converts to a three-year term loan
in May 1998, unless renewed or extended. The Credit Facility is secured by
virtually all the Company's oil and natural gas properties and interest is
payable at either the bank's 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 and (iv) a prohibition of most debt and corporate guarantees.
Capital Resources and Liquidity
As outlined in the following table, in each of the last three years, the Company
has made capital expenditures which required additional debt and equity capital
to supplement cash flow from operations.
YEAR ENDED DECEMBER 31,
----------------------------------------
DOLLARS IN THOUSANDS 1996 1995 1994
----------- ----------- ------------
Acquisitions of oil and natural gas properties... $ 48,407 $ 16,763 $ 6,606
Oil and natural gas expenditures................. 38,450 11,761 10,297
----------- ----------- ------------
Total................................... $ 86,857 $ 28,524 $ 16,903
=========== =========== ============
Two pie charts showing the capitalization of the Company (in thousands):
September 30, December 31,
1996 1996
----------------- ---------------
Debt $ 46,867 $ 125
Preferred stock 16,153 -
Common stock 53,213 130,323
Retained earnings 7,777 12,181
22
Management's Discussion and Analysis of Financial Condition and Results of
Operations
Stacked bar graph showing the capital expenditures of the Company (in
thousands):
1994 1995 1996
--------- ----------- -----------
Development $ 10,297 $ 11,761 $ 38,450
Acquisitions 6,606 16,763 48,407
--------- ----------- -----------
Total $ 16,903 $ 28,524 $ 86,857
========= =========== ===========
Since January 1, 1994, the Company has made total capital expenditures of $132.3
million, paid off all but $100,000 of its bank debt and increased its working
capital by approximately $13.9 million. This was funded by the issuance of
equity ($102.9 million, including the Convertible Preferred) and cash generated
by operations ($49.7 million). During 1996, the Company's funds were provided by
operating cash flow and equity, although the Company did use bank debt during
the year. The Company began 1996 with $100,000 of outstanding bank debt,
borrowed $47.9 million during the year, paid off the debt with the proceeds from
the Public Offering in October and ended the year with $100,000 of bank debt
outstanding.
As of December 31, 1996, the Company had working capital of $12.5 million and
virtually no debt outstanding. The Company has budgeted capital expenditures for
1997 of between $60 and $70 million. 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 1997. However, as of December
31, 1996, the Company has an unused borrowing base of $60.0 million to fund any
potential cash flow deficits. 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. Without suitable acquisitions or the capital to fund
such acquisitions, the Company's future growth could be limited or even
eliminated.
New Accounting Pronouncement
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.
Management evaluated such Statement and believes that it will not have a
material effect on the financial position or results of operations of the
Company.
Sources and Uses of Funds
During 1996, the Company spent approximately $33.4 million on oil and natural
gas development expenditures, $48.4 million on the previously discussed 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 the Public Offering.
During 1995, the Company made $28.5 million in capital expenditures, with the
single largest component being a $10.0 million acquisition of seven producing
wells in the Gibson and Humphreys Fields located near the Company's other
properties in suthern 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 drilling four wells
in Mississippi, $1.1 million for acreage, geological and geophysical and delay
rentals, and the balance of $8.1 million for workovers of existing properties.
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 the
private placement of equity with TPG.
23
Management's Discussion and Analysis of Financial Condition and Results of
Operations
Capital expenditures for 1994 were $16.9 million and included $10.3 million of
development costs primarily expended on natural gas properties in Louisiana,
with the balance of $6.6 million expended on acquisitions of properties
primarily in Louisiana, of which $5.5 million was spent on acquiring additional
working interests in existing Company-operated properties. Expenditures in 1994
were principally funded by $6.2 million of cash provided by operations and net
incremental debt of $8.8 million, of which $1.5 million came from the issuance
of unsecured convertible debentures and the balance from bank debt.
RESULTS OF OPERATIONS
Operating Income
During the last three years, operating income has increased significantly as
outlined in the following chart. Oil and gas revenue increased as a result of
the increased oil and gas production and increases in oil and gas product
prices.
Year ended December 31
- -----------------------------------------------------------------------------------------------------------
1996 1995 1994
- -----------------------------------------------------------------------------------------------------------
OPERATING INCOME (THOUSANDS)
Oil sales $ 28,475 $ 10,852 $ 6,767
Natural gas sales 24,405 9,180 5,925
Less production expenses (13,495) (6,789) (4,309)
------------ ---------- -----------
Operating income $ 39,385 $ 13,243 $ 8,383
------------ ---------- -----------
UNIT PRICES
Oil price per Bbl $ 18.98 $ 14.90 $ 13.84
Gas price per Mcf 2.73 1.90 1.78
NETBACK PER BOE
Sales price $ 17.69 $ 13.05 $ 12.17
Production expenses (4.51) (4.42) (4.13)
------------ ---------- -----------
$ 13.18 $ 8.63 $ 8.04
------------ ---------- -----------
AVERAGE DAILY PRODUCTION VOLUME:
Bbls 4,099 1,995 1,340
Mcf 24,406 13,271 9,113
BOE 8,167 4,207 2,858
- -----------------------------------------------------------------------------------------------------------
Bar graph showing the average price received by the Company per barrel of oil:
1994 $ 13.84
1995 14.90
1996 18.98
Production increases have been fueled by both internal growth from the Company's
development and exploration programs and from the acquisition of producing
properties. Production on a BOE/d basis increased 47% between 1994 and 1995 with
approximately 240 BOE/d attributable to the Gibson Acquisition and the balance
of approximately 1,109 BOE/d primarily attributable to internal growth. 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.
Oil and gas revenue has increased not only because of the large increase in
production, but also due to improved product prices. Between 1994 and 1995,
product prices increases were relatively modest with an 8% increase in oil
prices and a 7% increase in natural gas prices. The Company also realized an
$800,000 gas hedging gain during 1995 which added $.17 per Mcf to its average
natural gas price. The Company did not have any oil or natural gas hedges in
place during 1996, nor does it have any currently in place due to the relatively
strong commodity prices and the reduced debt levels of the Company. 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 $16.5 million of the increase
was related to properties acquired in the Hess
Bar graph showing the average price received by the Company per Mcf of natural
gas:
1994 $ 1.78
1995 1.90
1996 2.73
and Ottawa Acquisitions, approximately $5.4 million to properties acquired in
the Gibson Acquisition, 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.
Production expenses increased each year along with the increases in production.
On a BOE basis, production expenses increased 7% from 1994 to 1995 and increased
2% from 1995 to 1996. The increases were largely attributable to the changes 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. For the year (May through December,
1996) production expenses on these properties averaged $5.35 per BOE.
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,
- --------------------------------------------------------------------------------------------------------
1996 1995 1994
- --------------------------------------------------------------------------------------------------------
NET G&A EXPENSES (THOUSANDS)
Gross expenses $ 8,407 $ 3,900 $ 2,475
State franchise taxes 213 100 65
Operator recoveries (2,916) (1,438) (890)
Capitalized exploration expenses (1,224) (630) (480)
---------------------------------------------
Net expenses $ 4,480 $ 1,932 $ 1,170
---------------------------------------------
Average G&A cost per BOE $ 1.50 $ 1.25 $ 1.12
Employees as of December 31 122 51 27
- --------------------------------------------------------------------------------------------------------
On a BOE basis, these costs increased 12% from 1994 to 1995 and increased 20%
from 1995 to 1996. Part of the increase in 1995 was attributable to $190,000 of
costs ($0.12 per BOE) related to non-recurring personnel changes. 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,
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.
Stacked bar graph showing the cash flow, interest, G&A and production costs of
the Company per BOE:
1994 1995 1996
---------- ------------- -------------
Revenue $ 12.17 $ 13.05 $ 17.69
Production expense (4.13) (4.42) (4.51)
G&A (1.12) (1.25) (1.50)
Interest expense (0.99) (1.26) (0.26)
---------- ------------- -------------
Cash flow $ 5.93 6.12 $ 11.42
========== ============= =============
24
Management's Discussion and Analysis of Financial Condition and Results of
Operations
Interest and Financing Expenses
YEAR ENDED DECEMBER 31,
- --------------------------------------------------------------------------------------------------------
AMOUNTS IN THOUSANDS EXCEPT PER UNIT AMOUNTS 1996 1995 1994
- --------------------------------------------------------------------------------------------------------
Interest expense $ 1,993 $ 2,085 $ 1,146
Non-cash interest expense (459) (90) (86)
--------------------------------------
Cash interest expense 1,534 1,995 1,060
Interest and other income (769) (77) (23)
--------------------------------------
Net interest expense $ 765 $ 1,918 $ 1,037
- --------------------------------------------------------------------------------------------------------
Average interest cost per BOE $ 0.26 $ 1.26 $ 0.99
Average debt outstanding $ 19,500 $ 21,400 $ 12,200
Average interest rate 7.9% 9.3% 8.7%
Ratio of earnings to fixed charges 4.6 1.5 2.6
- --------------------------------------------------------------------------------------------------------
Imputed preferred dividend $ 1,281 $ - $ -
Loss on early extinguishment of debt 440 200 -
- --------------------------------------------------------------------------------------------------------
During both 1995 and 1996, the Company incurred bank debt in order to fund
property acquisitions. However, in both years this debt was retired before
year-end. In 1995, the bank debt was repaid with proceeds from the private
placement of equity with TPG and in 1996 with proceeds from the Public Offering.
The private placement of equity in December 1995 with TPG included 1.5 million
shares of Convertible Preferred. 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, as previously discussed. 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.
Depletion, Depreciation and Site Restoration
Depletion, depreciation and amortization ("DD&A") has increased along with the
additional capitalized cost and increased production. DD&A per BOE has increased
30% from 1994 to 1995 and 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 had a higher per unit cost for the Company than those
reserves added by development expenditures. The Company also provides
25
Management's Discussion and Analysis of Financial Condition and Results of
Operations
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 1996 1995 1994
- --------------------------------------------------------------------------------------------------------
Depletion and depreciation $ 17,533 $ 7,918 $ 4,177
Site restoration provision 371 104 32
--------------------------------------
Total amortization $ 17,904 $ 8,022 $ 4,209
--------------------------------------
Average DD&A cost per BOE $ 5.99 $ 5.22 $ 4.03
- --------------------------------------------------------------------------------------------------------
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 tax provision. The deferred tax provision
as a percentage of net income has varied depending on the mix of Canadian and
U.S. expenses. The rate declined from 1994 to 1995 as there were less Canadian
expenses, but increased again slightly in 1996 due to the non-deductible imputed
preferred dividend and interest on the subordinated debt.
YEAR ENDED DECEMBER 31,
- --------------------------------------------------------------------------------------------------------
1996 1995 1994
- --------------------------------------------------------------------------------------------------------
Deferred income taxes (thousands) $ 5,312 $ 367 $ 718
Average income tax costs per BOE $ 1.78 $ 0.24 $ 0.69
Effective tax rate 38% 34% 38%
- --------------------------------------------------------------------------------------------------------
Net Income
Primarily as a result of increased production and improved product prices, net
income and cash flow from operations increased substantially between 1995 and
1996 as outlined below. Between 1994 and 1995, net income decreased 39% as a
result of certain nonrecurring charges and a disproportionate increase in DD&A
as compared to the increase in revenue.
YEAR ENDED DECEMBER 31,
- --------------------------------------------------------------------------------------------------------
AMOUNTS IN THOUSAND EXCEPT PER SHARE AMOUNTS 1996 1995 1994
- --------------------------------------------------------------------------------------------------------
Net income $ 8,744 $ 714 $ 1,163
Net income per common share:
Primary $ 0.67 $ 0.10 $ 0.19
Fully diluted 0.62 0.10 0.19
Cash flow from operations (1) $ 34,140 $ 9,394 $ 6,185
- --------------------------------------------------------------------------------------------------------
<FN>
(1) Represents cash flow provided by operations, exclusive of the net change in
non-cash working capital balances.
</FN>
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, 1996 and 1995 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, 1996. 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, 1996
and 1995 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, 1996, in accordance with accounting principles generally accepted
in Canada.
Deloitte & Touche
Chartered Accountants
Calgary, Alberta
February 21, 1997
27
CONSOLIDATED BALANCE SHEETS
AMOUNTS IN THOUSANDS OF U.S. DOLLARS DECEMBER 31,
-----------------------------
1996 1995
------------- -------------
CURRENT ASSETS
Cash and cash equivalents........................................ $ 13,453 $ 6,553
Accrued production receivable.................................... 11,906 3,212
Trade and other receivables...................................... 3,643 1,160
------------- -------------
Total current assets .................................. 29,002 10,925
------------- -------------
PROPERTY AND EQUIPMENT (USING FULL COST ACCOUNTING)
Oil and natural gas properties................................... 159,724 72,510
Unevaluated oil and natural gas properties....................... 6,413 7,085
Less accumulated depreciation and depletion...................... (31,141) (13,982)
------------- -------------
Net property and equipment................................ 134,996 65,613
------------- -------------
OTHER ASSETS........................................................ 2,507 1,103
------------- -------------
TOTAL ASSETS............................................. $ 166,505 $ 77,641
============= =============
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable and accrued liabilities..................... $ 10,903 $ 2,872
Oil and gas production payable............................... 5,550 1,014
Current portion of long-term debt ........................... 67 177
------------- -------------
Total current liabilities................................ 16,520 4,063
------------- -------------
LONG-TERM LIABILITIES
Long-term debt................................................... 125 3,474
Provision for site reclamation costs............................. 613 242
Deferred income taxes and other.................................. 6,743 1,361
------------- -------------
Total long-term liabilities.............................. 7,481 5,077
------------- -------------
CONVERTIBLE FIRST PREFERRED SHARES, SERIES A
1,500,000 shares authorized, issued and
outstanding at December 31, 1995................................. - 15,000
------------- -------------
SHAREHOLDERS' EQUITY
Common shares, no par value, unlimited shares authorized;
outstanding - 20,055,757 and 11,428,809 shares at
December 31, 1996 and December 31, 1995 respectively......... 130,323 50,064
Retained earnings................................................ 12,181 3,437
------------- -------------
Total shareholders' equity............................... 142,504 53,501
------------- -------------
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY............... $ 166,505 $ 77,641
============= =============
Approved by the Board:
/s/ Gareth Roberts /s/ Wieland F. Wettstein
- --------------------- -------------------------
Gareth Roberts Wieland F. 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) 1996 1995 1994
----------- ---------- ----------
REVENUES
Oil, natural gas and related product sales................... $ 52,880 $ 20,032 $ 12,692
Interest income.............................................. 769 77 23
----------- ---------- ----------
Total revenues......................................... 53,649 20,109 12,715
----------- ---------- ----------
EXPENSES
Production................................................... 13,495 6,789 4,309
General and administrative................................... 4,267 1,832 1,105
Interest..................................................... 1,993 2,085 1,146
Imputed preferred dividends.................................. 1,281 - -
Loss on early extinguishment of debt......................... 440 200 -
Depletion and depreciation................................... 17,904 8,022 4,209
Franchise taxes.............................................. 213 100 65
----------- ---------- ----------
Total expenses........................................ 39,593 19,028 10,834
----------- ---------- ----------
Income before income taxes........................................ 14,056 1,081 1,881
Provision for federal income taxes................................ (5,312) (367) (718)
----------- ---------- ----------
NET INCOME........................................................ $ 8,744 $ 714 $ 1,163
=========== ========== ==========
NET INCOME PER COMMON SHARE.......................................
Primary................................................ $ 0.67 $ 0.10 $ 0.19
Fully-diluted.......................................... $ 0.62 $ 0.10 $ 0.19
Average number of common shares outstanding....................... 13,104 6,870 6,240
=========== ========== ==========
See Notes to Consolidated Financial Statements
29
Consolidated Statements of Cash Flows
YEAR ENDED DECEMBER 31,
--------------------------------------
AMOUNTS IN THOUSANDS OF U.S. DOLLARS 1996 1995 1994
---------- ----------- -----------
CASH FLOW FROM OPERATING ACTIVITIES:
Net income.................................................. $ 8,744 $ 714 $ 1,163
Adjustments needed to reconcile to net cash flow provided
by operations:
Depreciation, depletion and amortization................ 17,904 8,113 4,304
Deferred income taxes................................... 5,312 367 718
Imputed preferred dividend.............................. 1,281 - -
Loss on early extinguishment of debt.................... 440 200 -
Other................................................... 459 - -
----------- ----------- ------------
34,140 9,394 6,185
Changes in working capital items relating to operations:
Accrued production receivable........................... (8,694) (1,303) (986)
Trade and other receivables............................. (1,508) (168) (124)
Accounts payable and accrued liabilities................ 6,711 (1,660) 1,581
Oil and gas production payable.................... 4,536 490 261
---------- ----------- -----------
NET CASH FLOW PROVIDED BY OPERATIONS........................... 35,185 6,753 6,917
---------- ----------- -----------
CASH FLOW USED FOR INVESTING ACTIVITIES:
Oil and natural gas expenditures........................ (38,450) (11,761) (10,297)
Acquisition of oil and natural gas properties........... (48,407) (16,763) (6,606)
Net purchases of other assets........................... (1,726) (560) (122)
Acquisition of subsidiary, net of cash acquired......... 209 - -
---------- ----------- -----------
NET CASH USED FOR INVESTING ACTIVITIES......................... (88,374) (29,084) (17,025)
---------- ----------- -----------
CASH FLOW FROM FINANCING ACTIVITIES:
Bank borrowings......................................... 47,900 19,350 9,835
Bank repayments......................................... (47,900) (34,200) (2,485)
Issuance of subordinated debt........................... - 1,772 1,451
Issuance of common stock................................ 60,664 26,825 367
Issuance of preferred stock............................. - 15,000 -
Costs of debt financing................................. (411) (493) (122)
Other................................................... (164) (82) 62
---------- ----------- -----------
NET CASH PROVIDED BY FINANCING ACTIVITIES...................... 60,089 28,172 9,108
---------- ----------- -----------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS........... 6,900 5,841 (1,000)
Cash and cash equivalents at beginning of year................. 6,553 712 1,712
---------- ----------- -----------
CASH AND CASH EQUIVALENTS AT END OF YEAR....................... $ 13,453 $ 6,553 $ 712
========== =========== ===========
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid during the year for interest................. $ 1,621 $ 2,127 $ 1,027
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)
------------ ------------ RETAINED
DOLLAR AMOUNTS IN THOUSANDS OF U.S. DOLLARS SHARES AMOUNT EARNINGS TOTAL
------------ ------------ ----------- ----------
BALANCE - JANUARY 1, 1994 $ 6,208,417 $ 22,872 $ 1,560 $ 24,432
------------ ------------ ----------- ----------
Issued pursuant to employee stock option plan......... 96,250 367 - 367
Net income............................................ - - 1,163 1,163
------------ ------------ ----------- ----------
BALANCE - DECEMBER 31, 1994 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
============ ============ =========== ==========
See Notes to Consolidated Financial Statements
31
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994
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. All of the Canadian
operations were sold effective September 1, 1993.
The Company's name was changed on June 7, 1994, from Canadian Newscope Resources
Inc. to Newscope Resources Ltd. and again on December 21, 1995 to Denbury
Resources Inc.
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, Brymore Energy Corporation ("Brymore").
The Company acquired the remaining 50% of Brymore effective May 1, 1996 and
began consolidating all of Brymore as of that date. 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 non-productive
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
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.
32
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994
FOREIGN CURRENCY TRANSLATION
Since 1993 when the Company sold its Canadian oil and natural gas properties,
virtually all of the Company's assets are located in the United States. These
assets and the United States 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. 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 year ended December 31, 1996 and were assumed to be converted
or exercised as of the first of the year with the proceeds used to reduce
interest expense. For the prior years, these instruments were either
anti-dilutive or immaterial.
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, 1996 and
1995, 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.
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.
33
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994
Fair Value of Financial Instruments
As of December 31, 1996 and December 31, 1995, 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.
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, 1996 and 1995 and the year in which they were incurred follows:
December 31, 1996 December 31, 1995
---------------------------------- ------------------------------------------------
Costs Incurred During: Costs Incurred During:
---------------------- -----------------------------------
1996 1995 Total 1995 1994 1993 Total
---------- ---------- --------- --------- -------- --------- ----------
AMOUNTS IN THOUSANDS
Property acquisition cost. $ 2,614 $ 252 $ 2,866 $ 2,909 $ 1,230 $ 1,151 $ 5,290
Exploration costs......... 3,460 87 3,547 649 1,146 - 1,795
---------- ---------- --------- --------- -------- --------- ----------
Total................. $ 6,074 $ 339 $ 6,413 $ 3,558 $ 2,376 $ 1,151 $ 7,085
========== ========== ========= ========= ======== ========= ==========
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
$1,224,000, $630,000 and $480,000 for the years ended December 31, 1996, 1995
and 1994, respectively. Amortization per BOE was $5.99, $5.22, $4.03 for the
years ended December 31, 1996, 1995 and 1994, respectively.
NOTE 3. NOTES PAYABLE AND LONG-TERM INDEBTEDNESS
December 31,
----------------------------
1996 1995
------------ ------------
AMOUNTS IN THOUSANDS
Senior bank loan...................................$ 100 $ 100
Convertible debentures............................. - 3,296
Other notes payable................................ 92 255
------------ ------------
192 3,651
Less portion due within one year................... (67) (177)
------------ ------------
Total long-term debt......................$ 125 $ 3,474
============ ============
Banks
During 1996 the Company entered into a new $150 million credit facility with
NationsBank of Texas ("NationsBank"). This refinancing closed on May 31, 1996
and has a borrowing base as of December 31, 1996 of $60 million.
NationsBank is the agent bank and the facility includes two other banks. The
credit facility is a two-year revolving credit facility that converts to a three
year term loan in May 1998, unless renewed or extended. The credit facility is
secured by virtually all the Company's oil and natural gas properties and
interest is payable at either the bank's prime rate or, depending on the
percentage of the borrowing base that is outstanding, ranging from LIBOR plus
7/8% to LIBOR plus 13/8%. This credit facility also 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, and (iv) a prohibition of most debt and
corporate guarantees. As of December 31, 1996, the Company had $100,000
outstanding on this line of credit and $645,000 of letters of credit
outstanding.
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.
$2,500,000 principal amount of 9 1/2% unsecured convertible debentures. These
debentures were converted into 566,590 Common Shares during 1996.
Indebtedness Repayment Schedule
The Company's indebtedness is repayable as follows:
DECEMBER 31, 1996
------------------------------------------------
OTHER NOTES
AMOUNTS IN THOUSANDS BANK LOAN PAYABLE TOTAL
- -------------------------------------------------- ---------------- -----------
YEAR
1997 ..............................$ - $ 67 $ 67
1998 .............................. 17 23 40
1999 .............................. 33 2 35
2000 .............................. 33 - 33
2001 .............................. 17 - 17
------------- ---------------- -----------
Total indebtedness $ 100 $ 92 $ 192
============= ================ ===========
NOTE 4. INCOME TAXES
The Company's tax provision is as follows:
YEAR ENDED DECEMBER 31,
--------------------------------------
AMOUNTS IN THOUSANDS EXCEPT PER UNIT AMOUNTS 1996 1995 1994
---------- --------- ----------
Deferred
Federal..........................................$ 5,312 $ 367 $ 718
State............................................ - - -
---------- --------- ----------
Total tax provision.................................$ 5,312 $ 367 $ 718
========== ========= ==========
35
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994
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 1996 1995 1994
---------- ---------- ----------
Deferred income tax provision calculated using
the Canadian federal and provincial
statutory combined tax rate of 44.34%.... $ 6,233 $ 479 $ 834
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......................... (1,586) (112) (116)
---------- ---------- ----------
Total tax provision $ 5,312 $ 367 $ 718
========== ========== ==========
The Company at December 31, 1996 had net operating loss carryforwards for U.S.
tax purposes of approximately $14,417,000 and approximately $12,760,000 for
alternative minimum tax purposes. The net operating losses are scheduled to
expire as follows:
ALTERNATIVE
INCOME MINIMUM
AMOUNTS IN THOUSANDS TAX TAX
- ----------------------------------------------------- ---------------
YEAR
2004 .................................$ 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 ................................. 1,149 984
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.
36
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994
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 First Preferred Shares,
Series A ("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 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
"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 Company may force conversion of the $7.40 warrants issued in the TPG
Placement after December 21, 1997, if the price of the Common Stock exceeds
$10.00 per share for a period of 40 consecutive days.
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 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 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.
37
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994
Warrants
At December 31, 1996, 75,000 warrants were outstanding at an exercise price of
Cdn. $8.40 expiring on May 5, 2000 and 625,000 warrants were outstanding 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 Company has the option after December 21, 1997 to
require exercise of the 625,000 warrants if the weighted average trading price
of the Common Stock exceeds $10.00 per share for a period of 40 consecutive
trading days. 75,000 of the Cdn. $8.40 warrants were exercised during 1996.
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
of Denbury on August 11, 1995.
Stock Option and Stock Purchase Plans
The Company maintains a Stock Option Plan which authorizes the grant of options
of up to 1,050,000 of Common Shares. Under the plan, incentive and non-qualified
options may be issued to officers, key employees and consultants. The plan is
administered by the Stock Option Committee of the Board. The Board of Directors
of the Company have amended the Company's Stock Option Plan to (i) remove the
243,525 previously issued options which have been exercised from the plan and
(ii) to increase the number of option shares authorized to be issued under the
Plan from 1,050,000 to 2,000,000. This amendment is subject to shareholder and
regulatory approval.
Following is a summary of stock option activity during the years ended December
31, 1996, 1995 and 1994:
YEAR ENDED DECEMBER 31,
----------------------------------------------------------------------------------
1996 1995 1994
--------------------------- ----------------------- --------------------------
Weighted Weighted Weighted
Average Average Average
Number Price Number Price Number Price
---------- ---------- ----------- ---------- ---------- -----------
OUTSTANDING AT BEGINNING OF YEAR.... 731,925 $ 6.11 557,312 $ 6.30 541,312 $ 6.68
Granted............................. 525,500 8.96 274,500 5.89 138,750 5.64
Terminated.......................... (6,750) 6.28 (89,887) 7.79 (26,500) 9.35
Exercised........................... (197,675) 5.42 (10,000) 5.42 (96,250) 3.74
Expired............................. - - - - - -
---------- ---------- ----------- ---------- ---------- -----------
OUTSTANDING AT END OF PERIOD........ 1,053,000 $ 7.63 731,925 $ 6.11 557,312 $ 6.30
========== ========== =========== ========== ========== ===========
Options exercisable at end of year 532,375 $ 6.82 539,675 $ 6.19 487,937 $ 6.39
========== ========== =========== ========== ========== ===========
Weighted Weighted
OPTIONS OUTSTANDING AS OF Options Average Weighted Average Exercisable Average
DECEMBER 31, 1996: Outstanding Price Remaining Life (yrs.) Options Price
- --------------------------------- ------------ ---------- ----------------------- ------------ ----------
Exercise price of:
$3.65 to $6.99 372,000 $ 5.79 4.3 305,250 $ 5.77
$7.00 to $9.99 444,625 7.78 6.5 175,906 7.70
$10.00 to $14.87 236,375 10.23 9.4 51,219 10.09
38
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994
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
with at least six months of service. 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 for 1996 totaled $147,000. This plan is
administered by the Stock Purchase Plan Committee of the Board.
NOTE 6. PRODUCT PRICE HEDGING CONTRACTS
In October 1994, the Company entered into two financial contracts ("collars") to
hedge 10,000 Mcf/d of natural gas production for calendar year 1995. The first
natural gas contract for 8,000 Mcf/d of natural gas had a floor of $1.845 per
MMBtu and a ceiling of $2.095 per MMBtu. The second natural gas contract was for
2,000 Mcf/d and had a floor of $1.775 per MMBtu and a ceiling of $1.885 per
MMBtu. These contracts covered 75% of the Company's net revenue interest
production in 1995 and increased oil and natural gas revenues by approximately
$800,000 during such period.
In addition, 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 $47,000 during such
period.
The Company does not have any hedge contracts in place as of December 31, 1996.
NOTE 7. COMMITMENTS AND CONTINGENCIES
The Company has operating leases for the rental of office space, office
equipment, and vehicles. At December 31, 1996, long-term commitments for these
items require the following future minimum rental payments:
December 31,
AMOUNTS IN THOUSANDS 1996
--------------
1997 .........................$ 442
1998 ......................... 411
1999 ......................... 166
2000 ......................... -
2001 ......................... -
--------------
Total lease commitments $ 1,019
==============
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.
The Company is not currently a party to any litigation which would have a
material impact on its consolidated financial statements. However, due to the
nature of its business, certain legal or administrative proceedings may arise in
the ordinary course of its business.
39
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994
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 and 1995 under
U.S. GAAP would be $10,025,000 and $714,000, respectively, while under Canadian
GAAP the amounts reported were $8,744,000 and $714,000, respectively.
Earnings Per Share
In addition, the methodology for computing earnings per common share is not
consistent between the two countries. For Canadian purposes, dilutive securities
are only considered in the fully diluted presentation of earnings per share and
the proceeds from such dilutive securities are used to reduce debt in the
calculation. Under U.S. GAAP, the proceeds from such instruments are used to
repurchase Common Shares, using a slightly different methodology for the primary
and fully diluted calculations. For the years ended December 31, 1994 and 1995,
the stock options, warrants, convertible debt and the conversion of the
Convertible Preferred were either anti-dilutive or immaterial and were not
included in the earnings per share under either GAAP calculation. For the year
ended December 31, 1996, the Convertible Preferred was still anti-dilutive, but
the stock options, convertible debt and warrants were dilutive and included in
the earnings per share calculations, but with different results under the two
respective GAAP's. Under U.S. GAAP for the year ended December 31, 1996, the
primary earnings per share would be $.64 and the fully-diluted earnings per
share would be $.63 as compared to the $.67 and $.62 as reported under Canadian
GAAP.
During 1996, the Company issued 4,940,000 Common Shares in a public offering and
used a portion of the proceeds to retire bank debt. On a pro forma basis using
U.S. GAAP and assuming that the Common Shares had been issued as of January 1,
1996 and the interest expense for 1996 relating to the bank debt was reversed,
the primary earnings per share would be $.57 per share. No interest income was
assumed in the pro forma calculation even though the proceeds from the equity
issuance exceeded the bank debt that was retired.
Stock-Based Compensation
In 1995, the United States Financial Accounting Standards Board issued Statement
of Financial Accounting Standards ("SFAS") No. 123, "Accounting for Stock-Based
Compensation." SFAS No. 123 is effective for fiscal years beginning after
December 31, 1995 and requires companies to use recognized option pricing models
to estimate the fair value of stock-based compensation, including stock options.
The Statement requires additional disclosures based on this fair value based
method of accounting for an employee stock option and encourages, but does not
require, companies to recognize the value of these stock option grants as
additional compensation using the methodology of SFAS No. 123. The Company has
elected to continue recognizing expense as prescribed by APB Opinion No. 25,
"Accounting for Stock Issued to Employees", as allowed under SFAS No. 123 rather
than recognizing compensation expense as calculated under SFAS No. 123. As such,
the adoption of SFAS No. 123 during 1996 did not have any effect on the
Company's consolidated financial statements.
40
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994
The Company has two stock-based compensation plans as more fully described in
Note 5. With regard to its stock option plan, the Company applies APB Opinion
No. 25 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,
-------------------------------
1996 1995
------------ ------------
NET INCOME:
As reported (thousands)....................................................$ 8,744 $ 714
Pro forma (thousands)...................................................... 8,215 503
NET INCOME PER COMMON SHARE:
As reported................................................................$ 0.67 $ 0.10
Pro forma.................................................................. 0.63 0.07
Stock options issued during period (thousands).................................. 526 275
Weighted average exercise price.................................................$ 8.96 $ 5.90
Average per option compensation value of options granted (1).................... 2.95 2.34
Compensation cost (thousands)................................................... 801 320
<FN>
(1) 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 32% 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>
Deferred Income Taxes
Deferred income taxes relate to temporary differences based on tax laws and
statutory rates in effect at the December 31, 1996 and 1995 balance sheet dates.
At December 31, 1996, and 1995, all deferred tax assets and liabilities were
computed based on Canadian GAAP amounts and were noncurrent as follows:
December 31,
----------------------------
AMOUNTS IN THOUSANDS 1996 1995
------------- ------------
Deferred tax assets:
Loss carryforwards...................... $ (4,902) $ (4,511)
Deferred tax liabilities:
Exploration and intangible
development costs....................... 11,645 5,942
------------- ------------
Net deferred tax liability................... $ 6,743 $ 1,431
============= ============
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.
Management evaluated such Statement and believes that it will not have a
material effect on the financial position or results of operations of the
Company.
41
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994
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, 1996, the Company sold 10% or more of its net production of
oil and natural gas to the following purchasers: Natural Gas Clearinghouse
(20%), PennUnion Energy Services (19%), Enron Oil Trading & Transportation
(13%), and Hunt Refining (15%).
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.
Costs incurred in oil and natural gas activities for the years ended December
31, 1996, 1995 and 1994 are as follows:
YEAR ENDED DECEMBER 31,
-----------------------------------------
AMOUNTS IN THOUSANDS 1996 1995 1994
----------- ----------- -----------
Property acquisition................ $ 48,856 $ 17,198 $ 6,736
Exploration......................... 4,592 1,687 1,796
Development......................... 33,409 9,639 8,371
----------- ----------- -----------
Total costs incurred $ 86,857 $ 28,524 $ 16,903
=========== =========== ===========
Property Acquisitions
During April 1996, the Company closed an acquisition of additional working
interests in five Mississippi oil and natural gas properties in which the
Company already owned an interest, plus certain overriding royalty interests in
other areas for approximately $7.5 million (the "Ottawa Acquisition"). The
properties were acquired from Ottawa Energy, Inc., a subsidiary of Highridge
Exploration Ltd.
On April 17, 1996, Denbury entered into a purchase and sale agreement with
Amerada Hess Corporation to purchase producing oil and natural gas properties in
Mississippi, Louisiana and Alabama, plus certain overriding royalty interests in
Ohio, for approximately $37.2 million (the "Hess Acquisition"). The Company
funded this acquisition with bank financing from its NationsBank credit facility
and closed this transaction during June 1996.
These two acquisitions were accounted for under purchase accounting and the
results of operations were consolidated during the second quarter of 1996. Pro
forma results of operations of the Company as if the acquisitions had occurred
at the beginning of each respective period are as follows:
Year Ended December 31,
---------------------------
IN THOUSANDS, EXCEPT PER SHARE AMOUNTS 1996 1995
------------ -----------
Revenues....................................................$ 61,573 $ 41,273
Net income.................................................. 9,820 899
Net income per common share................................. 0.75 0.13
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 $250,000 and $500,000
for 1996 and 1995, respectively, 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 Hess 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,
------------------------------------
AMOUNTS IN THOUSANDS 1996 1995 1994
---------- ---------- ----------
Revenues:
Oil, natural gas and related product sales....... $ 20,165 $ 18,210 $ 17,787
Direct operating expenses:
Lease operating expense......................... 6,302 7,888 6,598
---------- ---------- ----------
Excess of revenues over direct operating expenses...... $ 13,863 $ 10,322 $ 11,189
========== ========== ==========
The following represents the revenues and direct operating expenses attributable
to the net interest acquired in the Ottawa 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,
AMOUNTS IN THOUSANDS 1996
---------------
Revenues:
Oil, natural gas and related product sales................$ 4,215
Direct operating expenses:
Lease operating expense.................................. 760
---------------
Excess of revenues over direct operating expenses...............$ 3,455
===============
In November 1995, the Company acquired seven producing wells and certain
non-producing leases in the Gibson/Humphreys Fields of Terrebonne Parish,
Louisiana for approximately $10.2 million.
NOTE 10. SUPPLEMENTAL RESERVE INFORMATION (UNAUDITED)
Net proved oil and natural gas reserve estimates as of December 31, 1996 and
December 31, 1995 were prepared by Netherland & Sewell and the net oil and
natural gas reserve estimates as of December 31, 1994 were prepared by The
Scotia Group, Inc., both 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
42
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994
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,
-----------------------------------------------------------------------
1996 1995 1994
---------------------- ---------------------- ----------------------
Oil Gas Oil Gas Oil Gas
(MBbl) (MMcf) (MBbl) (MMcf) (MBbl) (MMcf)
--------- ---------- ---------- --------- --------- ----------
BALANCE BEGINNING OF YEAR................... 6,292 48,116 4,230 42,047 3,583 13,029
Revisions of previous estimates........ (490) 3,737 830 (1,620) (48) 2,827
Revisions due to price changes......... 1,053 402 - - - -
Extensions, discoveries and other
additions............................ 3,492 5,480 732 - 640 14,978
Production............................. (1,500) (8,933) (728) (4,844) (489) (3,326)
Acquisition of minerals in place....... 6,205 25,300 1,228 12,533 544 14,539
--------- ---------- ---------- --------- --------- ----------
BALANCE AT END OF YEAR...................... 15,052 74,102 6,292 48,116 4,230 42,047
========= ========== ========== ========= ========= ==========
PROVED DEVELOPED RESERVES:
Balance at beginning of year........... 5,290 34,894 3,755 35,578 3,418 12,303
Balance at end of year................. 13,371 58,634 5,290 34,894 3,755 35,578
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.
43
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994
DECEMBER 31,
----------------------------------------
AMOUNTS IN THOUSANDS 1996 1995 1994
----------- ----------- ------------
Future cash inflows.................................................... $ 627,476 $ 214,932 $ 126,129
Future production costs................................................ (134,986) (56,323) (35,069)
Future development costs............................................... (28,722) (16,154) (7,369)
----------- ----------- ------------
Future net cash flows before taxes .................................... 463,768 142,455 83,691
10% annual discount for estimated timing of cash flows............ (147,670) (45,490) (31,000)
----------- ----------- ------------
Discounted future net cash flows before taxes.......................... 316,098 96,965 52,691
Discounted future income taxes......................................... (74,226) (15,801) (5,763)
----------- ----------- ------------
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS $ 241,872 $ 81,164 $ 46,928
=========== =========== ============
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 1996 1995 1994
----------- ----------- -------------
BEGINNING OF YEAR...................................................... $ 81,164 $ 46,928 $ 28,465
Sales of oil and natural gas produced, net of production costs......... (39,385) (13,243) (8,383)
Net changes in sales prices............................................ 116,587 23,037 863
Extensions and discoveries, less applicable future development
and production costs.............................................. 34,113 1,926 13,416
Previously estimated development costs incurred........................ 5,278 2,193 2,492
Revisions of previous estimates, including revised estimates of
development costs, reserves and rates of production................. 7,747 3,958 (2,914)
Accretion of discount.................................................. 8,116 4,693 2,847
Purchase of minerals in place.......................................... 86,677 21,710 15,732
Net change in income taxes............................................. (58,425) (10,038) (5,590)
----------- ----------- -------------
END OF YEAR............................................................ $ 241,872 $ 81,164 $ 46,928
=========== =========== =============
UNAUDITED QUARTERLY INFORMATION
The following table presents unaudited summary financial information on a
quarterly basis for 1996 and 1995.
IN THOUSANDS EXCEPT PER SHARE AMOUNTS MARCH 31 JUNE 30 SEPT. 30 DECEMBER 31
- ------------------------------------------------- ------------------------------------------------------------------
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) 0.12 0.11 0.14 0.25
Cash flow from operations (b) 6,065 7,238 8,464 12,373
1995
Revenues $ 4,381 $ 4,636 $ 4,841 $ 6,251
Expenses 3,723 4,583 4,554 6,168
Net income 435 35 190 54
Net income per share 0.08 0.00 0.02 0.00
Cash flow from operations (b) 2,112 1,913 2,234 3,135
<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>
44
Quarterly Stock Information
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 NASDAQ and on the TSE
(as reported by such exchange) for each quarterly period for the last two fiscal
years. The trades on NASDAQ are reported in U.S. dollars and the TSE trades are
reported in Canadian dollars. The Company's Common Shares were first listed on
NASDAQ effective August 25, 1995.
As of February 1, 1997, 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 72% 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).
NASDAQ (U.S. $) TSE (CDN $)
HIGH LOW HIGH LOW
- -----------------------------------------------------------------------------------------------------------
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
- -----------------------------------------------------------------------------------------------------------
1995
First quarter - - 7.80 6.60
Second quarter - - 8.70 7.00
Third quarter 6.75 5.32 8.70 7.00
Fourth quarter 6.25 5.50 8.70 7.10
- -----------------------------------------------------------------------------------------------------------
1995 annual 6.75 5.32 8.70 6.60
- -----------------------------------------------------------------------------------------------------------