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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
--------------------------
Form 10-K
(Mark one)
[ X ] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1994
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transaction period from ________ to ________
Commission file number 1-10509
___________________
SNYDER OIL CORPORATION
(Exact name of registrant as specified in its charter)
Delaware 75-2306158
(State or other jurisdiction of (IRS Employer
incorporation or organization) Identification No.)
777 Main Street 76102
Fort Worth, Texas (Zip Code)
(Address of principal executive offices)
Registrant's telephone number, including area code (817) 338-4043
Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange
Title of each class on which registered
---------------------------- ---------------------------
Common Stock New York Stock Exchange
$6.00 Convertible Exchangeable
Preferred Stock New York Stock Exchange
7% Convertible Subordinated Notes New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
None
(Title of class)
Indicate by check mark whether the registrant (1) has filed all
reports required to be filed by Section 13 or 15(d) of the Securities
Exchange Act of 1934 during the preceding 12 months (or for such
shorter period that the registrant was required to file such
reports), and (2) has been subject to such filing requirements for
the past 90 days.
Yes / No
---- ----
Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of Regulation S-K is not contained herein, and
will not be contained, to the best of registrant's knowledge, in
definitive proxy or information statements incorporated by reference
in Part III of this Form 10-K or any amendment to this Form 10-K. [X]
Aggregate market value of the common stock held by
non-affiliates of the registrant
as of March 9, 1995. . . . . . . . . . . . $377,910,848
Number of shares of common stock outstanding
as of March 9, 1995. . . . . . . . . . . . . 30,240,567
DOCUMENTS INCORPORATED BY REFERENCE
Part III of this Report is incorporated by reference to the
Registrant's definitive Proxy Statement relating to its Annual
Meeting of Stockholders, which will be filed with the Commission no
later than April 30, 1995.
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SNYDER OIL CORPORATION
Annual Report on Form 10-K
December 31, 1994
PART I
ITEM 1. BUSINESS
General
Snyder Oil Corporation (the "Company") is engaged in the
acquisition and development of oil and gas properties primarily in
the Rocky Mountain and Gulf Coast regions of the United States. The
Company also gathers, transports, processes and markets natural gas
generally in proximity to its principal producing properties. Over
the past five years, revenues have increased from $84.3 million to
$262.3 million, net income rose from $3.2 million to $12.4 million
and net cash provided by operations grew from $22.5 million to $86.5
million. At December 31, 1994, the Company's net proved reserves
totalled 120.2 million barrels of oil equivalent("MMBOE"), having a
pretax present value at constant prices of $414.4 million.
Approximately 71% of the reserves were natural gas.
The Company's reserves are concentrated in five major producing
areas located in Colorado, Wyoming and Texas, which collectively
account for more than 86% of the present value of its reserves. The
Company owns properties in 15 states and the Gulf of Mexico,
including 5,269 gross (2,651 net) producing wells and nine gas
transportation and processing facilities. The Company operates more
than 2,600 wells which account for almost 90% of its developed
reserves. The Company also participates in several international
exploration and development projects through a wholly owned
subsidiary and its 29% owned Australian affiliate, Command Petroleum
Limited. At December 31, 1994, the Company held undeveloped acreage
totaling 1.4 million gross acres (962,000 net) domestically and 5.7
million gross acres (2.8 million net) internationally.
Over the past four years, the Company has pursued a balanced
strategy of development drilling and acquisitions, focusing on
enhancing operating efficiency and reducing capital costs through the
concentration of assets in selected geographic areas or "hubs."
Currently, the Company's primary emphasis is on development drilling
in several Rocky Mountain basins and in southeast Texas. Prior
to 1994, drilling was focused in the Wattenberg Field of the Denver-
Julesburg Basin ("DJ Basin") of Colorado where the Company has
drilled over 1,000 wells since 1991. This drilling increased the
Company's Wattenberg production more than sixfold, from an average of
2.6 MBOE per day in 1991 to 15.9 MBOE in 1994. Beginning in 1994,
a growing percentage of drilling expenditures was directed towards
developing a series of projects outside Wattenberg. To date,
projects have been successfully initiated in the Greater Green River,
Piceance and Uinta Basins of the Rocky Mountains and in the Giddings
Field of southeast Texas. In 1994, 370 wells were drilled in
Wattenberg. In late 1994, the Company curtailed drilling in
Wattenberg as the result of declining gas prices and disappointing
drilling results in certain outlying areas of the Field. Based on
current gas prices, the Company expects to drill less than 100 wells
in Wattenberg in 1995 and to concentrate on oil development and those
gas development projects which are less sensitive to low gas prices.
The experience gained in Wattenberg has assisted the Company in
developing other large scale drilling projects in the Rockies and the
Gulf Coast. By yearend 1994, these projects (including certain
fields in northern Wyoming acquired in late 1992) accounted for 60.7
MMBOE, or more than half, of the Company's proved reserves. In the
East Washakie and Deep Green River areas of the Washakie Basin of
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southern Wyoming (collectively, Greater Green River), the Company
drilled 39 wells during 1994 with production reaching 4,400 BOE per
day in December 1994. The Company operates 153 wells and holds a
significant inventory of potential drilling locations, including 102
locations classified as proved undeveloped at December 31, 1994.
The Western Slope Project incorporates portions of the Piceance Basin
of western Colorado and the Uinta Basin of Utah. In 1994, the
Company drilled 25 wells in the Piceance Basin with production
reaching nearly 2,000 BOE per day by yearend. A total of 9 wells
were drilled in late 1994 in the Uinta Basin with production
remaining modest at yearend. The Company operates 143 wells in these
two Basins and holds a significant inventory of potential drilling
locations, including 70 locations that were classified as proved
undeveloped at December 31, 1994. In the Giddings Field in
southeast Texas, the Company placed 23 horizontal oil wells on sales
during 1994, increasing its production to 3,600 BOE per day by
yearend. It also added to its inventory of potential locations in
the Field, including 20 locations that were classified as proved at
yearend 1994.
In view of the low current gas prices, the Company
plans to limit its 1995 development expenditures to $70 million.
This level of expenditure is expected to fund the drilling of up to
150 wells, 70 of which are planned for Wattenberg, 22 in the Greater
Green River area, 36 in the Western Slope Project and 20 in the
Giddings Field, where oil is the primary objective. Gas wells slated
for drilling in 1995 have been limited to those expected to yield a
high rate of return even at current prices or those which help
evaluate or hold material acreage positions. The Company intends to
continue to purchase acreage to establish new development projects
and to seek to acquire properties which strengthen its existing asset
base or secure a foothold in new geographic areas. The Company also
expects to be able to continue to pursue various international
projects at a limited capital cost. The overall objective is to
maintain a superior record of growth without taking undue financial
risk in the current adverse climate. Every effort is being made to
retain and enhance the Company's ability to accelerate drilling if
gas prices recover.
Development
General. Since 1990, development drilling has been the
Company's primary focus. The Company's existing properties have
extensive development drilling and enhancement potential, primarily
in the DJ Basin of Colorado, the Washakie and Green River Basins in
southern Wyoming, the Piceance and Uinta Basins in western Colorado
and Utah and in the Giddings Field in southeast Texas. The Company
designs its major drilling programs to reduce risk, create synergies
with its gas management operations and exploit the potential for
continuous cost improvement. Owing to the low current gas prices,
the Company expects to drill only 150 wells in 1995, including 70
wells in Wattenberg, as opposed to over 500 wells drilled during
1994, 370 of which were in Wattenberg. Emphasis will be placed on
drilling for oil, with over 40% of development expenditure slated for
development of projects, primarily in the Giddings Field and the
Uinta Basin., where oil is the primary objective.
In its large scale development projects, the Company attempts to
acquire and maintain a sizeable inventory of potential drilling
locations, many of which may not be economic at current cost and
price levels, but which may prove attractive if reservoir assumptions
are validated and well economics improve over the life of the project
through cost reductions or price increases.
Assuming no material changes in energy prices, the Company plans
to spend $70 million on development drilling in 1995. Such
expenditures totalled $90.6 million in 1993 and $156.9 million in
1994.
DJ Basin
Wattenberg Field. Wattenberg is the Company's largest base of
operations, representing approximately 45% of total proved reserves
at December 31, 1994. Over the past four years, a total of 1,037
wells have been drilled in Wattenberg, including 370 wells drilled in
1994. At yearend, the Company had interests in more than 1,800
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producing wells, of which it operated 1,500. Owing primarily to
depressed gas prices, the Company expects to drill less than 100
wells and to undertake 60 recompletions in Wattenberg in 1995. The
Company has numerous Wattenberg locations which would be attractive
to drill at higher gas prices. If gas prices increase, the Company
would expect to materially increase its drilling in the Field.
At yearend 1994, the net proved reserves attributed to the
Wattenberg properties were 12.2 million barrels of oil and 178.7 Bcf
of gas. Proved reserve quantities were significantly reduced by low
year-end gas prices (approximately $1.69 per Mcf) prevailing in
Wattenberg. The reserves were attributable to 1,847 producing wells,
63 wells in progress, 340 proved undeveloped locations and
approximately 323 proved behind pipe zones. The number of proved
undeveloped locations is sensitive to the prevailing level of gas
prices, and could increase significantly if prices return to historic
levels. The Company expects proved reserves to be assigned to
additional locations as drilling progresses.
The Codell formation, traditionally the primary objective of the
drilling, is a blanket siltstone formation that exists under much of
the Wattenberg acreage at depths of 6,700 to 7,500 feet. Codell
reserves generally have a high degree of predictability due to
uniform deposition and gradual transition from high to low gas/oil
ratio areas. The Company frequently dually completes the Niobrara
chalk formation, which lies immediately above the Codell, to enhance
drilling economics. The Codell/Niobrara wells produce most
prolifically in the first six to twelve months, after which
production declines to a fraction of initial rates. More than half
of a typical well's reserves are recovered in the first three years
of production. As a result, each well contributes significantly more
production in its first year than in subsequent years.
During 1994, the Company continued to expand its drilling
targets to include both deeper and shallower formations. The J sand
lies approximately 400 feet below the Codell. It is a low
permeability sandstone generally found to be productive throughout
the DJ Basin, with performance varying with porosity and thickness
and much greater variability outside the heart of the Wattenberg
Field. The Dakota formation lies approximately 150 feet below the J
sand. It is a low permeability sand occasionally naturally fractured
with less predictable commercial accumulations and varied performance
results. During 1994, the Company had some success in using 3-D
seismic technology for mapping the Dakota in the southern parts of
the Field. The Sussex formation is at average depths of 4,500 feet.
The Sussex sands were deposited in bars and exhibit variable
reservoir quality with a moderate degree of predictability.
Because the Codell, Niobrara and J formations are continuous
reservoirs over a large portion of the DJ Basin, the Company believes
that drilling, at least in the heart of the Wattenberg Field, is
relatively low risk. Of the 1,037 wells drilled between 1991 and
1994, only 15 were classified as dry holes, and most of these have
been in outlying areas of the Basin. Dry holes in the Basin cost an
average of $110,000 per well. The average cost of a completed well
approximated $204,000 in 1994.
In early 1994, an agreement was finalized with Union Pacific
Resource Company ("UPRC") under which the Company has the right for
up to six years to drill wells on UPRC's undeveloped acreage in the
Wattenberg area. As compensation, UPRC was granted warrants to
purchase two million shares of Common Stock. During 1994, the
Company drilled 77 wells on acreage committed under the venture. As
the result of disappointing drilling in certain outlying areas
covered by the venture, the Company paid UPRC $400,000 in early 1995
for an extension of the time period to drill the commitment wells and
released a portion of the outlying acreage committed to the venture.
The Company has undertaken to drill 55 wells during the last three
quarters of 1995, 85 wells from January 1, 1996 through February 28,
1997 and of 70 wells from March 1, 1997 through February 28,
1998. Thereafter, the Company can, at its option, extend the venture
for up to two additional years by committing to drill 150 wells per
year. There is no limit on the number of wells to drilled, and wells
in excess of the minimum reduce the number of wells required in the
following year by up to 50%. If the Company drills less than the
minimum number of wells, it is required to pay UPRC $20,000 per well
for the shortfall. On mineral acreage, UPRC retains a 15% royalty and
has the option to receive an additional 10% royalty after pay-out or
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to participate as a 50% working interest owner. On leasehold
acreage, UPRC does not have the right to participate but retains a
royalty that results in a total royalty burden of 25%.
Cheyenne. During 1994, 10 wells were placed on stream in a
shallow gas producing area on the northeast flank of the DJ Basin.
This project, known as the Cheyenne Project, began with the
acquisition of five shut-in gas wells in 1990 when the Company
determined that it could capitalize on new open access rules of the
Federal Energy Regulatory Commission ("FERC") by constructing a
gathering system to transport gas to a nearby interstate pipeline.
After acquiring almost 50,000 acres of leases in the area and selling
an approximate 27.5% interest to other parties on a promoted basis,
the Company has drilled 64 successful wells and eight dry holes in
the area and constructed a gathering system having a capacity of 10
MMcf per day to transport the gas to the interstate pipeline. The
Company currently operates 72 wells in this area that produce from
the Niobrara formation.
Greater Green River
East Washakie. Since the mid-1980's, the Company's properties
in the Barrel Springs Unit and the Blue Gap Field of southern
Wyoming, together with its gas gathering and transportation
facilities there, have been one of its most significant assets.
During 1994, the Company continued to develop fluvial Mesaverde sands
in the eastern Washakie Basin near these properties. Twenty-five
wells were completed in this area in 1994 at depths ranging from
7,500 to 11,000 feet, developing net proved reserves of 3.6 MMBOE.
Acquisitions, including the repurchase of a 50% net profits interest
in the Barrel Springs Unit,added another 6.6 MMBOE. By yearend, net
production of gas, which accounts for approximately 90% of the
reserves, had reached 21.4 MMcf per day, up from 9.2 MMcf per day one
year earlier. An environmental impact statement covering the
Company's southern and eastern lands was approved in October 1994,
allowing the drilling of up to 250 locations. Two additional
environmental impact statements covering the north and west areas
should be approved during 1995 and 1996., allowing up to 500
additional locations by the Company and other producers in these
areas. The Company expects to drill 16 wells in East Washakie during
1995.
The Company currently operates 130 wells in this area and
holds over 800 potential drilling locations, 101 of which were
classified as proved undeveloped at yearend 1994. The Company holds
interests in approximately 102,000 gross (78,000 net) undeveloped
acres in the Washakie Basin. This includes 36,000 gross (24,000 net)
undeveloped acres added during 1994.
Deep Green River. During 1994, the Company initiated a major
project to develop fluvial Lance sands in the deep portion of the
Green River Basin. The Company participated in five wells during the
fourth quarter of 1994, with encouraging results. Production
commenced in the fourth quarter and had reached 4.9 MMcf per day by
yearend. An eight well program is planned for 1995 in strategic
locations to earn acreage and further evaluate potential recoveries.
The Company holds interests in approximately 95,000 gross (79,000
net) undeveloped acres in this project. The Company believes that
there are in excess of 500 potential drilling locations on this
acreage. At the end of 1994, only four locations were classified as
proved undeveloped.
Western Slope
Development of the Western Slope Project, encompassing portions
of the Piceance Basin on the western slope of Colorado and the Uinta
Basin in northeastern Utah, continued during 1994. In the southeast
corner of the Piceance Basin, the 9,000 acre Grass Mesa Unit was
formed adjacent to the 53,000 acre Hunter Mesa Unit that the Company
operates. At yearend, the Company owned approximately 110,000 gross
(83,000 net) acres in this portion of the Piceance Basin. In the
Douglas Creek Arch area of the Piceance Basin, the Company holds an
additional 29,600 net acres. Subsequent to yearend, an agreement was
reached to sell most of this acreage at a profit. In the Uinta
Basin, the Company holds interests in approximately 104,000 gross
(85,000 net) acres. During 1995, the Company expects to reduce its
drilling program for gas reserves and to put greater emphasis on
drilling oil reserves in the Uinta Basin, with eight wells expected
in the Piceance Basin and, depending on further evaluation of
recently drilled wells, up to 25 wells planned in the Uinta Basin.
5
During 1994, 25 new wells were drilled to test the Hunter Mesa
and Grass Mesa Units. Most of the wells were placed on production in
December, with the remaining wells being completed in early 1995. Net
production from the Hunter Mesa, Grass Mesa and Divide Creek Units
averaged 11.7 MMcf per day during December 1994, and had reached 16.2
MMcf per day by February 1995. During 1994, the Company acquired or
installed 33 miles of gathering lines. These lines provide access to
the Rocky Mountain Natural Gas System, which compliments the existing
connection to the Questar System. Although this affords greater
transportation capacity and flexibility, the extent to which the
Company will be able to continue to develop the Piceance Basin is in
part dependent on arranging additional gathering and transportation
at a reasonable cost. The Company is exploring options for gathering
and transporting future gas production, including the possibility of
constructing additional Company owned facilities.
Activities in the Uinta Basin during 1994 included the drilling
of three wells in the Southman Canyon Mesaverde gas project area, one
well in the Horseshoe 'B' gas project area and seven wells in the
Green River oil fairway project. Two of the Southman Canyon wells
were completed and the third Southman Canyon well and the Horseshoe 'B'
were completed in early 1995. Three of the Green River oil wells are
on production. Although production rates have not yet stabilized,
early tests are encouraging and, if sustained, could lead to a 20 to
25 well drilling program during 1995.
The Company believes there are up to 1,400 potentially drillable
locations on its holdings in the Piceance and Uinta Basins. Depths
of producing formations range form 3,000 to 9,000 feet, with
producing formations including the Uinta 'B', Green River, Wasatch,
Mesaverde and Dakota. At yearend 1994 there were 231 proved
producing wells, 23 proved non-producing zones and 66 proved
undeveloped locations. Proven reserves at yearend were 72.9 Bcf of
gas and 1.6 million barrels of oil.
Northern Wyoming
In 1992, the Company acquired four large producing fields from
Atlantic Richfield Company. At yearend 1994, proved reserves in
these fields totalled 16.2 MMBOE, including 10.9 million barrels of
oil and 31.6 Bcf of gas. The Pitchfork and Hamilton Dome fields
produce sour crude oil primarily from the Tensleep, Madison and
Phosphoria formations at depths of 2,500 to 4,000 feet. The Salt
Creek field produces sweet crude oil from the Wall Creek formation at
depths of 2,000 to 2,900 feet. The Riverton Dome field produces
primarily gas from the Frontier and Dakota tight sands formations at
8,000 to 10,000 feet with some sour crude oil production from the
Tensleep and Phosphoria. Production from this field is processed at
a Company-owned plant.
The Company operates the Hamilton Dome Field, located in the Big
Horn Basin, and the Riverton Dome Field, located in the Wind River
Basin. Since the acquisition, the Company has focused on enhancing
value through reducing operating expenses, waterflood optimization,
workovers and recompletions and limited additional drilling. In 1994
the Company initiated stepout drilling in the Riverton Dome Field,
where two successful wells were completed in the Frontier and Dakota
formations. A third well was completed early in 1995. One successful
Tensleep infill well was drilled in Hamilton Dome during late 1994.
Production from the Riverton Dome and Hamilton Dome Fields exceeded
levels projected at the time of the acquisition by 11% during 1994,
and is expected to exceed the originally projected amounts by 28%
during 1995. While production have been increased, the Company
has reduced its lease operating expenses in these fields
by approximately $400,000 per year.
The Company initiated two new exploitation projects in northern
Wyoming during 1995. In the Wind River Basin, the Company has
assembled approximately 73,000 net acres. Plans are to continue
leasing through mid-1995, with initial drilling expected in early
1996. In the Big Horn Basin, the Company had assembled
approximately 43,000 net acres through February 1995. Additional
leasing is expected to continue through the second half of 1995.
Initial drilling on the project is targeted for the fourth quarter of
1995.
Gulf Coast Area
In the Giddings Field in southeast Texas, the Company continued
expanding its horizontal drilling program. Horizontal drilling
entails risks in that the technology is still relatively new and
rapidly evolving, costs are relatively high (with dry hole costs
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ranging from $900,000 to $1.45 million for a new well and $350,000 to
$750,000 for a re-entry well) and high initial production, while
leading to high rates of return on successful wells, makes ultimate
recoveries difficult to predict. The Company's program has been
successful to date, and increasing emphasis is being placed on
horizontal drilling in Giddings. During 1994, the Company
drilled 33 wells in the Field and at yearend had placed 23 wells on
sales with nine wells in progress. One well was abandoned. Daily
net production averaged 3,600 BOE during December 1994, or nearly 10%
of total Company production, compared to 1,500 BOE a year earlier.
Proved reserves are 38% oil and 62% gas and exceeded 7.1 MMBOE
at yearend. Based on attractive economics of the program to date,
the Company acquired approximately 30,000 net undeveloped acres in
the Austin Chalk Trend, including the Giddings Field in 1994, and
plans to continue its horizontal drilling activity during 1995, with
plans to drill up to 20 wells and complete the nine wells in progress
at yearend. Oil is expected to be nearly 60% of production from the
locations to be drilled in 1995. Based on currently budgeted capital
expenditures, drilling in the Giddings Field will be the Company's
largest single project during 1995. The Company has 50 locations
classified as proved undeveloped, and believes that the total number
of potential drillable locations may ultimately be twice that number.
During 1994, the Company also acquired for $4.3 million working
interests in 10 producing wells in Brazos County which the Company
believes may have additional horizontal development potential.
The Company acquired overriding royalty interests in
approximately 250 producing wells and 330,000 net mineral acres,
primarily in north Louisiana, in 1994 for a price of $9.7 million.
The Company also entered into lease option agreements covering an
additional 373,000 net acres in north Louisiana. The transactions
also included access to over 5,000 miles of seismic data, which the
Company is currently reviewing to seek acquisition opportunities and
to develop exploitation and exploration prospects to drill or to
promote to industry partners. During 1994 the Company drilled 14
wells, 3 of which were placed on production and 11 of which were
abandoned, to test the shallow Wilcox formation. The cost of the
abandoned wells averaged approximately $60,000 per well. Several
formations are productive in the area, including the Wilcox, Hosston
and Cotton Valley trends, and the Company expects to develop
prospects covering one or more of these formations.
In late 1994, the Company acquired 51% of the common stock of
DelMar Petroleum, Inc., a closely-held company headquartered in
Houston, Texas, for $6.6 million. DelMar owns interests in and
operates 22 platforms in the Gulf of Mexico and manages investment
programs for institutional partners. During the last quarter or 1994,
DelMar acquired the interests of one of its institutional partners for
approximately $3.5 million and implemented a development program at
its Main Pass prospect. At yearend four wells had been completed and
were producing at an aggregate rate of 65 MMcf per day. DelMar's
interest in the Main Pass couples is currently less than 1%. The
Company believes its ownership position in DelMar will enable it to
expand its position in the Gulf of Mexico through acquisitions,
development and, to a much lesser extent, exploration. Such
expansion may be pursued through DelMar or directly.
Gas Management
General. The Company expanded its gas gathering and processing
capacity during 1994 with the construction of additional gathering
facilities and construction of the West Plant in Wattenberg. By
yearend, operated processing capacity had increased to more than 160
MMcf per day and gathering system capacity was increased to more than
250 MMcf per day. The gas management unit complements the Company's
development and acquisition activities by providing additional cash
flow and enhancing returns. The segment is also increasingly
profitable in its own right. During 1994, gross margin increased by
approximately 42% to $13.1 million. See "Customers and Marketing."
Colorado Facilities. The largest concentration of gas
facilities is in the Wattenberg area. These facilities include two
major gathering systems, the Enterprise system and Energy Pipeline,
the Roggen and West Plant processing plants, and a number of minor
facilities. By yearend 1994, plant capacity had reached 140 MMcf
per day, as the result of completion of the West Plant in late
October. During the fourth quarter of 1994, average throughput
reached 72 MMcf per day.
7
The gas produced from most wells drilled on acreage acquired
from Amoco is dedicated for the life of the lease to Amoco's
Wattenberg gas processing plant. If Amoco were unable to process
Company production at its plant for any reason, including a shut-down
of the plant, it would have a short-term adverse impact on the
Company. The Wattenberg plants enable the Company to mitigate
the effects of any downtime at the Amoco plant.
At the Wattenberg plants, gas is processed to recover gas
liquids, primarily propane and a butane/gasoline mix, from gas
supplied by the Company and third parties. The liquids are then sold
separately from the residue gas. The liquids are marketed to local
and regional distributors and the residue gas is sold to utilities,
independent marketers and end users through an intrastate system and
the Colorado Interstate Gas ("CIG") pipeline. Two liquids lines
permit the direct sale of liquids products through either an Amoco
line to the major interchange at Conway, Kansas or to the Phillips
Petroleum line which connects the plants to the Phillips Powder River
liquids pipeline.
The Company's Wattenberg gathering systems include over 900
miles of pipeline that collect, compress and deliver gas from over
1,850 wells to the Wattenberg plants. During 1994, the Company
substantially increased the capacity of its gathering systems through
the expansion of existing facilities and the acquisition of new
facilities. Enterprise collects a portion of the Company's gas
produced from acreage acquired from Amoco and delivers it to the
Amoco Wattenberg plant. Enterprise includes 26 miles of 20" diameter
trunk and 29 miles of associated lateral gathering lines connecting
20 of the Company's existing central delivery points. As a result of
the completion of the second phase, the Enterprise system has the
capacity to deliver 75 MMcf per day to the Amoco Wattenberg plant.
The Company has negotiated a transportation arrangement with CIG
that, in conjunction with the gathering fees to be charged on the
Company's gathering systems, allows the delivery of gas to the Amoco
Wattenberg plant at a favorable rate. In addition to reducing the
Company's exposure to future escalation in gathering costs applicable
to the Company's production, Enterprise provides an enhanced degree
of operational control. Because the Enterprise system interconnects
with the Company's other Colorado facilities, the Company's plants
and other plants in the area can serve as a backup for processing a
portion of the Company's gas in the event of any curtailment at the
Amoco Wattenberg plant. While shut downs of Amoco's plant reduce the
Company's production, diversion of gas to the Company's plants and,
to a lesser degree, two other plants in the area, enabled the Company
to produce significant volumes that would have otherwise been
curtailed.
Subsequent to yearend 1994, the Company announced that it was
considering the sale of its Wattenberg gas facilities.
Wyoming Facilities. The Company operates two pipeline systems
in Wyoming that enhance its ability to market gas produced from its
properties in the Washakie Basin. Wyoming Gathering and Production
Company ("WYGAP") gathers gas produced from approximately 150
operated wells in the Barrel Springs Unit and the Blue Gap area. The
system has a capacity of 26 MMcf per day. Throughput averaged 14
MMcf and 19 MMcf per day during 1993 and 1994, respectively. WYGAP
delivers gas to Western Transmission Corporation ("Westrans"), a
Company-owned interstate pipeline system which operates under FERC
jurisdiction.
The Westrans system consists of a 26-mile main pipeline, a
smaller 9.2 mile line and related gathering facilities. The system
gathers and transports gas under open access transportation service
agreements on an interruptible basis. The main line extends from the
Washakie Basin area of Carbon County, Wyoming to connections with
Williams' and CIG's interstate pipelines in Sweetwater County,
Wyoming. Gas transported on Westrans also has access to California
markets through the Kern River Pipeline via interconnects with CIG
and Williams. Westrans is located near several other interstate
pipelines, providing the potential for additional interconnects that
offer alternative transportation routes to end markets. In addition
to the gas from WYGAP, which accounts for over 85% of its volumes,
Westrans transports volumes from other operated wells and third
parties. The capacity of Westrans is 65 MMcf per day. Daily
throughput averaged 15 MMcf during 1993 and 22 MMcf during 1994. As
the East Washakie project progresses, the Company expects to further
expand its gathering network in the area.
8
Other Facilities. The Company expanded its gathering system in
southern Nebraska during 1994 to gather gas produced from newly
developed Cheyenne County properties for delivery to various markets
accessible through an interstate pipeline. The Cheyenne system
includes 14 miles of 4" to 6" trunkline and 10 miles of 3" lateral
gathering lines. During the fourth quarter of 1994, throughput
averaged over 4 MMcf per day of gas from 70 producing wells.
Included in the 1992 acquisition of Wyoming properties was a gas
processing plant in Fremont County, Wyoming. The plant has a 20 MMcf
per day capacity with current throughput of 7 MMcf per day from wells
in the Riverton Dome Field.
In conjunction with the growing level of acquisition and
development activity in the Western Slope Project, the Company is
actively exploring alternatives to gather and transport future gas
production, including the possible construction of a Company-owned
gathering and transportation line. Traditionally, the lack of
sufficient pipeline capacity has been a major deterrent to
development in the Piceance Basin. During 1994, the Company acquired
or installed 33 miles of pipeline systems in the area. These systems
provide access to the Rocky Mountain Natural Gas System, which
compliments the existing connection to the Questar System.
International Activities
The Company's strategy internationally is to develop projects
that have the potential for a major impact in the future. The
Company attempts to structure the projects to limit its financial
exposure and mitigate political risk by minimizing financial
commitments in the early phases of a project and seeking industry
partners and investors to fund the majority of the equity capital.
A wholly owned subsidiary of the Company, SOCO International, Inc.,
is the holding company for all international operations. Edward T.
Story, President of SOCO International holds an option to purchase
10% of the currently outstanding shares of SOCO International,
through April 1998.
Russian Joint Venture. Permtex, a joint drilling venture formed
in 1993 with Permneft, a Russian oil and gas company, officially
began operations in mid 1994. The venture was formed to develop
proven oil fields located in the Volga-Urals Basin of the Perm Region
of Russia, approximately 800 miles east of Moscow. Permtex holds
exploration and development rights to over 300,000 acres in the
Volga-Urals Basin, in a contract area containing four major and four
minor fields as well as other potential prospects. The Company
estimates that the four major fields could ultimately produce 115
million barrels of oil, of which approximately 30% was classified as
proved at yearend, with the remaining reserves expected to be
ultimately recovered through implementation of waterflood projects.
The joint venture utilizes primarily Russian personnel and equipment
and Western technology under joint Russian/American management.
The major fields were previously delineated through 45
previously drilled wells. Four of these wells were placed on
production during 1994 with production averaging 1,000 barrels per
day. Through the end of 1994, the venture produced approximately
80,000 barrels of oil. It is anticipated that 25 of the existing
wells will ultimately be placed on production, and that up to 400
additional development wells will be drilled over the next five to
ten years. An 18-mile pipeline extension linking the Logovskoye
field with refineries in Perm was completed in 1994 and a pump
station is now being installed. Upon completion of the pipeline and
approval by the state inspection committee, three new development
wells drilled during 1994 will be placed on production, which should
increase production by 1,000 barrels per day.
The venture successfully exported three shipments of oil
totalling 69,000 barrels of oil with payment in U.S. dollars during
1994. Also, the venture has received an exemption from excise taxes
and has applied for exemption from the export tariff, which is
currently equivalent to $4.00 per barrel (based on an exchange rate
of .75 European Currency Units per Dollar).
Based on currently expected rig availability in the area, the
venture plans to drill approximately 18 new wells during 1995. In
addition, several of the previously existing wells are scheduled to
be brought on stream through rework and perforation upon completion
of the pipeline pump station.
During 1994, Command, the Company's Australian affiliate,
Holland Sea Search NV ("HSSH"), a Dutch affiliate of Command, and
ITOCHU, a major Japanese trading company which has agreed to purchase
9
oil from the venture for export, purchased equity interests in
Permtex for aggregate contributions of $11.25 million, of which $8.5
million was received during 1994. As the result of these
contributions, the Company's interest in Permtex decreased from 37.5%
to 20.6%. The Company also received a commitment from the Overseas
Private Investment Corporation ("OPIC"), an agency of the United
States Government, to provide political risk insurance and up to $40
million in financing to fund Permtex's initial operations. Closing
on the OPIC financing, which would be guaranteed in certain respects
by the Company, is expected in late spring 1995 with drawings expected
to commence in mid-summer.
Command Petroleum Limited. In 1993, the Company purchased 42.8%
of the outstanding shares of Command for approximately $18.2 million.
Due to shares subsequently issued by Command in a series of
transactions, the Company's current interest in Command is 29%.
Command is an exploration and production company based in Sydney,
Australia and listed on the Australian Stock Exchange. At yearend
1994 Command had a market capitalization of $100 million, working capital of
$36 million and no debt. Command currently holds interests in more
than 14 exploration permits and production licenses primarily in the
Southwestern Pacific Rim including Australia and Papua New Guinea,
Tunisia, Yemen and India. Command also holds a 48% interest in
HSSH, a publicly traded Dutch exploration and production company
whose primary asset is an interest in the North Sea's Markham gas
field.
During 1994 Command and its industry partners signed a
production sharing contract with the government of India to develop
the Ravva Field in the Bay of Bengal. Command owns 22.5% of the
venture and is the operator for the project. Command, together with
HSSH, also purchased a 12.5% interest in Permtex, the Company's
Russian venture. In 1995, Command purchased the Company's concession
rights in Tunisia in return for Command stock and purchased a 10%
interest in the Company's Mongolian venture.
Mongolia. The Company further expanded its Mongolian venture
during 1994 and early 1995. In 1993, the Company entered into a
production sharing agreement with Mongol Petroleum Company, the
national oil company of Mongolia covering a block of 11,400 square
kilometers, or approximately 2.8 million gross acres, in the Tamtsag
Basin of northeastern Mongolia. In late 1994 an adjacent block was
acquired, increasing the Company's acreage to 5.3 million acres, in
exchange for a 1.25% overriding royalty interest in both blocks.
These concessions offset the Hailar Basin of China. The venture also
has applications for production sharing contracts pending as a co-
applicant with the Mongolian government for an additional five
million acres on two blocks adjacent to the venture's current blocks.
If these concessions are awarded, the venture's acreage would cover
the entire Tamtsag Basin in Mongolia.
During 1994, the venture continued its seismic acquisition program.
Seismic acquisition to date has identified the presence of large
structures which seem analogous to the Songliao Basin of China which
contains the Daqing field. The first well to test the acreage is
expected to begin drilling in the second quarter of 1995. In late
1994 a consortium was formed with PT BIP Energimas ("BIP"), the oil
and gas subsidiary of PT Bhuwanatala Indah Permai, a publicly listed
Indonesian company, whereby BIP acquired an interest in the venture
in exchange for committing to drill two 3,400 meter wells. Command
also acquired a 10% interest at yearend 1994. The Company's
interest in the venture is 49.5%, which will be reduced to 38% upon
completion of the required seismic program by one of the Company's
co-venturers.
Although the prospective potential of the previously unexplored
Tamtsag Basin has long been recognized, the lack of an outlet for
production has prevented exploration in the Basin. In early 1995,
the venture entered into an agreement with China National United Oil
Corporation ("CNUOC"), under which CNUOC agreed to purchase crude oil
produced by the venture at a mutually-agreed Mongolian/Chinese border
point at world market prices, less $2 per barrel. CNUOC is a joint
venture between China National Petroleum Corporation and SINOCHEM,
both state-owned entities.
Tunisia. In early 1995, the Company transferred its interests
in the Fejaj Permit area to Command, which already holds interests in
that country. In exchange for the transfer, the Company received
4.7 million shares of Command stock having a market value
approximating the Company's investment in Tunisia and will receive an
additional 4.7 million shares if a commercial discovery is made as
the result of the initial 4,000 meter drilling commitment.
Depending on Command's success in locating farmout partners to drill
10
the first well on the concession, the Company has agreed to pay up to
$750,000 of the costs incurred by Command in drilling such well.
Production, Revenue and Price History
The following table sets forth information regarding net
production of crude oil and liquids and natural gas, revenues and
expenses attributable to such production and to natural gas
transportation, processing and marketing and certain price and cost
information for the five years ended December 31, 1994.
December 31,
----------------------------------------------------------------
1990 1991 1992 1993 1994
---------- ---------- ---------- ---------- ----------
(Dollars in thousands, except price and per barrel expenses)
Production
Oil (MBbl) 1,049 1,487 1,776 3,451 4,366
Gas (MMcf) 12,769 18,382 23,090 35,080 43,809
MBOE (a) 3,497 4,937 5,989 9,297 11,668
Revenues
Oil production $ 24,806 $ 30,667 $ 33,512 $ 53,174 $ 64,625
Gas production (b) 24,997 34,677 43,851 71,467 73,233
---------- ---------- ---------- ---------- ----------
Subtotal 49,803 65,344 77,363 124,641 137,858
---------- ---------- ---------- ---------- ----------
Transportation, processing
and marketing 29,442 21,459 38,611 94,839 107,247
Interest and other 5,058 (163) 2,996 9,372 17,223
---------- ---------- ---------- ---------- ----------
Total $ 84,303 $ 86,640 $118,970 $228,852 $262,328
========== ========== ========== ========== ==========
Operating expenses
Production $ 18,088 $ 24,882 $ 28,057 $ 44,901 $ 50,067
Transportation, processing
and marketing 24,103 14,202 30,469 85,640 94,177
Exploration 2,016 2,294 1,515 2,960 6,505
---------- ---------- ---------- ---------- ----------
$ 44,207 $ 41,378 $ 60,041 $133,501 $150,749
========== ========== ========== ========== ==========
Gross margin $ 40,096 $ 45,262 $ 58,929 $ 95,351 $111,579
========== ========== ========== ========== ==========
Production data
Average sales price (c)
Oil (Bbl) $ 23.65 $ 20.62 $ 18.87 $ 15.41 $ 14.80
Gas (Mcf) (a) (b) 1.69 1.68 1.74 1.94 1.67
BOE (a) 14.18 13.24 12.92 13.41 11.82
Average operating expense/BOE $ 5.17 $ 5.04 $ 4.68 $ 4.83 $ 4.29
<f/n>
_________________________
(a) Gas production is converted to oil equivalents at the rate of 6
Mcf per barrel, except for certain high priced gas which through
1992 was converted based on its price equivalency to the Company's
other gas. Average gas prices exclude this high priced gas
production.
(b) Sales of natural gas liquids are included in gas revenues.
(c) The Company estimates that its composite net wellhead prices at
December 31, 1994 were approximately $1.56 per Mcf of gas and
$15.25 per barrel of oil.
11
Drilling Results
The following table sets forth information with respect to
wells drilled during the past three years. The information should
not be considered indicative of future performance, nor should it be
assumed that there is necessarily any correlation between the number
of productive wells drilled, quantities of reserves found or economic
value. Productive wells are those that produce commercial quantities
of hydrocarbons whether or not they produce a reasonable rate of
return.
1992 1993 1994
------ ------ ------
Development wells
Productive
Gross 241.0 382.0 466.0
Net 207.5 316.0 390.6
Dry
Gross 6.0 10.0 12.0
Net 2.7 5.5 11.1
Exploratory wells
Productive
Gross - 2.0 -
Net - 2.0 -
Dry
Gross - 6.0 13.0 (a)
Net - 3.3 10.5
<f/n>
_________________________
(a) Ten (8.75 net) of the dry holes were drilled to test shallow
formations in North Louisiana at an approximate cost of $60,000 per
well. See "Development - Gulf Coast Area."
As of December 31, 1994, the Company had 92 gross (75.9 net)
development wells in progress. Between yearend and February 28,
1995, the Company spudded 28 wells. At that date 78 gross (73.0 net)
wells, including wells in progress at yearend, had been completed,
one well (1.0 net) had been abandoned and 52 gross (45.9 net)
development wells were in progress.
Field Operations
In its capacity as operator, the Company supervises day-to-day
field activities, generally employing a combination of its personnel
and contract pumpers. The Company maintains eight district field
offices and one division office.
As operator, the Company charges overhead fees to all working
interest owners according to the applicable operating agreements. As
of the end of 1992, 1993 and 1994, respectively, the Company operated
1,745, 2,176 and 2,634 wells. The Company received overhead
reimbursements for operations and drilling of $12.9 million,
$17.0 million and $23.9 million during 1992, 1993 and 1994,
respectively (including reimbursements attributable to the Company's
interest). The increase in reimbursements is attributable to the
increase in operated drilling and producing wells and contractual
escalations. Based on the time allocated to operations, these
reimbursements in aggregate generally have exceeded the costs of such
activities.
Customers and Marketing
The Company's oil and gas production is principally sold to end
users, marketers and other purchasers having access to pipeline
facilities near its properties. Where there is no access to
pipelines, crude oil is trucked to storage facilities. In 1993 and
1994, Amoco accounted for approximately 12% and 11% of revenues,
12
respectively. The marketing of oil and gas by the Company can be
affected by a number of factors that are beyond its control and whose
future effect cannot be accurately predicted. The Company does not
believe, however, that the loss of any of its customers would have a
material adverse effect on its operations.
Primarily due to reduced margins resulting from decreases
in the differential between Rocky Mountain gas prices and prices in
the Mid-Continent and Gulf Coast regions, the Company discontinued
third party marketing during the last half of 1994 and began to
concentrate its marketing efforts on maximizing value received for
equity gas. As a results, gross margins during 1994 from third party
marketing activities decreased from $1.2 million to $.6 million.
In June 1991, the Company entered into a contract to supply gas
to a cogeneration facility through August 2004. The contract calls
for the Company to supply 10,000 MMBtu per day. This plant, which
requires up to 24,500 MMBtu per day of gas, began operations in 1989
and is located at a manufacturing facility in Oklahoma City. The
effect of this contract depends on market prices for gas and the
local utility's choice of alternative sources of fuel to meet its
supply commitments. Gross margin generated from the contract was
approximately $1.5 million for both 1991 and 1992. Contractual
limitations resulted in a net loss of $267,000 from this contract
during 1993. During 1994, the gross margin was $.4 million.
During 1994, the Company began a program to manage risk
associated with gas prices in the Rocky Mountain region. Beginning
September 1, 1994, the Company entered into a ten-year 20,000 MMBtu
per day basis swap to lock in the differential between prices for
Rocky Mountain region gas as compared to gas prices in the Gulf Coast
market. The Company is continuing to develop an overall strategy to
manage the risk associated with volatile prices in markets for its
products.
Competition
The oil and gas industry is highly competitive in all its
phases. Competition is particularly intense with respect to the
acquisition of producing properties. There is also competition for
the acquisition of oil and gas leases, in the hiring of experienced
personnel and from other industries in supplying alternative sources
of energy.
Competitors in acquisitions, exploration, development and
production include the major oil companies in addition to numerous
independent oil companies, individual proprietors, drilling and
acquisition programs and others. Many of these competitors possess
financial and personnel resources substantially in excess of those
available to the Company. Such competitors may be able to pay more
for desirable leases and to evaluate, bid for and purchase a greater
number of properties than the financial or personnel resources of the
Company permit. The ability of the Company to increase reserves in
the future will be dependent on its ability to select and acquire
suitable producing properties and prospects for future exploration
and development.
Title to Properties
Title to the properties is subject to royalty, overriding
royalty, carried and other similar interests and contractual
arrangements customary in the oil and gas industry, to liens incident
to operating agreements and for current taxes not yet due and other
comparatively minor encumbrances. The majority of the value of the
Company's properties is mortgaged to secure borrowings under the bank
credit agreement.
As is customary in the oil and gas industry, only a perfunctory
investigation as to ownership is conducted at the time undeveloped
properties believed to be suitable for drilling are acquired. Prior
to the commencement of drilling on a tract, a detailed title
examination is conducted and curative work is performed with respect
to known significant defects.
Regulation
The Company's operations are affected by political developments
and federal and state laws and regulations. Oil and gas industry
legislation and administrative regulations are periodically changed
for a variety of political, economic and other reasons. Numerous
departments and agencies, federal, state, local and Indian, issue
13
rules and regulations binding on the oil and gas industry, some of
which carry substantial penalties for failure to comply. The
regulatory burden on the oil and gas industry increases the Company's
cost of doing business, decreases flexibility in the timing of
operations and may adversely affect the economics of capital
projects.
In the past, the federal government has regulated the prices at
which oil and gas could be sold. Prices of oil and gas sold by the
Company are not currently regulated. There can be no assurance,
however, that sales of the Company's production will not be subject
to federal regulation in the future.
The following discussion of various statutes, rules,
regulations or governmental orders to which the Company's operations
may be subject is necessarily brief and is not intended to be a
complete discussion thereof.
Federal Regulation of Natural Gas. Historically, the sale and
transportation of natural gas in interstate commerce have been
regulated under various federal and state laws including, but not
limited to, the Natural Gas Act of 1938, as amended ("NGA") and the
Natural Gas Policy Act of 1978 ("NGPA"), both of which are
administered by FERC. However, regulation of first sales, including
the certificate and abandonment requirements and price regulation,
was phased out during the late 1980's and all remaining wellhead
price ceilings terminated on January 1, 1993.
FERC continues to have jurisdiction over transportation and
sales other than first sales. Commencing in the mid-1980's, FERC
promulgated several orders designed to correct perceived market
distortions resulting from the traditional role of major interstate
pipeline companies as wholesalers of gas and to make gas markets more
competitive by removing transportation and other barriers to market
access. These orders have had and will continue to have a
significant influence on natural gas markets in the United States and
have, among other things, allowed non-pipeline companies, including
the Company, to market gas and fostered the development of a large
spot market for gas. These orders have gone through various
permutations, due in significant part to FERC's response to court
review of these orders. Parts of these orders remain subject to
judicial review, and the Company is unable to predict the impact on
its natural gas production and marketing operations of judicial
review of these orders.
In April 1992, FERC issued Order 636, a rule designed to
restructure the interstate natural gas transportation and marketing
system to remove various barriers and practices that have
historically limited non-pipeline gas sellers, including producers,
from effectively competing with pipelines. The restructuring process
required the "unbundling" of pipeline services (e.g., transportation,
sales and storage) so that producers, marketers and end users of
natural gas contract only for those services which they need and may
obtain each service from the most economical source. The 1993-1994
winter heating season was the first period during which FERC Order
636 procedures were operative. To date, as management of the Company
believes the Order 636 procedures have not had any significant effect
on the Company.
State Regulation of Transportation of Natural Gas. Some states
have adopted open-access transportation rules or policies requiring
intrastate pipelines or local distribution companies to transport
natural gas to the extent of available capacity. These rules or
policies, like federal rules, are designed to increase competition in
natural gas markets. The economic impact on the Company and gas
producers generally of these rules and policies is uncertain.
14
State Regulation of Drilling and Production. State regulatory
authorities have established rules and regulations requiring permits
for drilling, reclamation and plugging bonds and reports concerning
operations, among other matters. Most states in which the Company
operates also have statutes and regulations governing a number of
environmental and conservation matters, including the unitization or
pooling of oil and gas properties and establishment of maximum rates
of production from oil and gas wells. Some states also restrict
production to the market demand for oil and gas. Such statutes and
regulations may limit the rate at which oil and gas could otherwise
be produced from the Company's properties. Some states have enacted
statutes prescribing ceiling prices for gas sold within the state.
In Colorado surface owner groups have been active at both the
state and local levels, and there have been a number of city and
county governments who have either enacted new regulations or are
considering doing so. The incidence of such local regulation
increased following a decision of the Colorado Supreme Court which
held that local governments could not prohibit the conduct of
drilling activities which were the subject of permits issued by the
Colorado Oil and Gas Conservation Commission ("COGCC"), but that they
could limit those activities under their land use authority. Under
this decision, local municipalities and counties may take the
position that they have the authority to impose restrictions or
conditions on the conduct of such operations which could materially
increase the cost of such operations or even render them entirely
uneconomic. The Company is not able to predict which jurisdictions
may adopt such regulations, what form they may take, or the ultimate
effects of such enactments on its operations. In general, however,
these ordinances are aimed at increasing the involvement of local
governments in the permitting of oil and gas operations, requiring
additional restrictions or conditions on the conduct of operations,
to reduce the impact on the surrounding community and increasing
financial assurance requirements. Accordingly, the ordinances have
the potential to delay and increase the cost, or in some cases, to
prohibit entirely the conduct of drilling operations.
In response to the concerns of surface owners, during 1993 the
COGCC adopted, regulations for the DJ Basin governing notice to and
consultation with surface owners prior to the conduct of drilling
operations, imposing specific reclamation requirements on operators
upon the conclusion of operations and containing bonding requirements
for the protection of surface owners and enhanced financial assurance
requirements.
During 1994, the Colorado legislature enacted Senate Bill
940177, which gave additional authority to the COGCC to promote not
only the development of oil and gas, but also to consider the health,
safety and welfare of the public in its decision-making process.
There are currently in effect or proposed five rule making task
forces to study such matters as reclamation, well control procedures,
financial assurances and protection of water quality. Although
industry is a participant on the task forces, it is possible that
additional restrictions could be imposed that could add to the cost
of oil and gas operations in Colorado.
Environmental Regulations. Operations of the Company are
subject to numerous laws and regulations governing the discharge of
materials into the environment or otherwise relating to environmental
protection. These laws and regulations may require the acquisition of
a permit before drilling commences, prohibit drilling activities on
certain lands lying within wilderness and other protected areas and
impose substantial liabilities for pollution resulting from drilling
operations. Such laws and regulations also restrict air or other
pollution and disposal of wastes resulting from the operation of gas
processing plants, pipeline systems and other facilities owned
directly or indirectly by the Company.
In connection with its most significant acquisitions, the
Company has performed environmental assessments and found no material
environmental noncompliance or clean-up liabilities requiring action
in the near or intermediate future, although some matters identified
in the environmental assessments are subject to ongoing review. The
Company has assumed responsibility for some of the matters
identified. Some of the Company's properties, particularly larger
units that have been in operation for several decades, may require
significant costs for reclamation and restoration when operations
eventually cease. Environmental assessments have not been performed
on all of the Company's properties. To date, expenditures for
environmental control facilities and for remediation have not been
significant to the Company. The Company believes, however, that it
is reasonably likely that the trend toward stricter standards in
environmental legislation and regulations will continue. For
instance, efforts have been made in Congress to amend the Resource
Conservation and Recovery Act to reclassify oil and gas production
wastes as "hazardous waste," the effect of which would be to further
regulate the handling, transportation and disposal of such waste. If
such legislation were to pass, it could have a significant adverse
impact on the Company's operating costs, as well as the oil and gas
industry in general.
New initiatives regulating the disposal of oil and gas waste
are also pending in certain states, including states in which the
Company conducts operations, and these various initiatives could have
a similar impact on the Company. The COGCC has enacted rules
regarding the regulation of disposal of oil field waste. These rules
establish significant new permitting, record-keeping and compliance
procedures relating to the operation of pits, the disposal of
produced water, and the disposal and/or treatment of oil field waste,
including waste currently exempt from federal regulation. These
rules may require the addition of technical personnel to perform the
15
necessary record-keeping and compliance and may require the
termination of production from some of the Company's marginal wells,
for which the cost of compliance would exceed the value of remaining
production. In addition, as indicated above, the COGCC has enacted
regulations imposing specific reclamation requirements on operators
upon the conclusion of their operations. Management believes that
compliance with current applicable laws and regulations will not have
a material adverse impact on the Company.
During 1995, the COGCC has scheduled rulemaking proceedings to
consider, among other things, groundwater protection. It is expected
that unlined pits, including buried concrete tanks, will be a focus
of the proceedings. It is possible that the COGCC will prohibit new
unlined pits and may require closure of unlined pits and buried
concrete tanks in areas that are considered sensitive. The Company
estimates that it has approximately 400 sites in Wattenberg that
could be affected if the COGCC requires closure of unlined pits and
buried concrete tanks throughout the Wattenberg area. The Company is
unable to predict when and if the rules will be adopted and, if
adopted, the number of facilities that will be affected, the period
over which closure would be required or the procedures involved.
A number of states have recently established more stringent
environmental regulations to ensure compliance with federal
regulations, and have either proposed or are considering regulations
to implement the Federal Clean Air Act. These new regulations are
not expected to have a significant impact on the Company or its
operation. In the longer term, regulations under the Federal Clean
Air Act may increase the number and type of Company facilities that
require permits, which could increase the Company's cost of
operations and restrict its activities in certain areas.
Federal Leases. The Company conducts operations under federal
oil and gas leases. These operations must be conducted in accordance
with permits issued by the Bureau of Land Management ("BLM") and are
subject to a number of other regulatory restrictions. Multi-well
drilling projects on federal leases may require preparation of an
environmental assessment or environmental impact statement before
drilling may commence. Moreover, on certain federal leases, prior
approval of drill site locations must be obtained from the
Environmental Protection Agency.
Royalty Payments and Production Taxes. The federal government
and many states regulate the manner of calculating and payment of
royalties to the owners of mineral interests and production and
severance taxes to state and local entities. The regulations
governing these payments are complex and often provide for penalties
for late payments and underpayments. The BLM has assessed SOCO
approximately $660,000, including late payment penalties through
yearend 1994, for additional royalties for production from the Barrel
Springs Unit during 1986 through 1990, claiming that fees charged by
a Company-owned pipeline for transporting gas from the Unit
constitute fees for gathering, which are not deductible in computing
royalties, rather than fees for transportation. The State of Wyoming
has assessed the Company approximately $500,000, including late fees
and penalties, for additional severance tax, nearly all of which is
due to deduction of costs of transporting gas on Company-owned and
third party pipelines, for production from 1986 through 1989 from
Barrel Springs and other fields in southern Wyoming. The amount of
the assessment has been paid under protest. Additional county
production taxes would also be payable if the State is successful in
asserting its claim. The Company believes that the transportation
charges are properly deductible under applicable law and is
contesting both assessments.
In December 1994 the Supreme Court of Colorado held that post-
production costs incurred by working interest owners to make natural
gas "marketable" are not deductible in computing payments due owners
of royalty and overriding royalty owners if the instrument creating
the royalty is silent on the matter. This holding is contrary to
what had generally been regarded as industry custom in Colorado. The
decision was decided on a certification of a legal question from a
federal district court, and the court did not address a number of
crucial issues that could limit or expand significantly the effect of
the holding. As a result, the Company cannot currently predict the
effect of the decision on its operations.
16
Officers
Listed below are the officers and a summary of their recent
business experience.
Name Position
John C. Snyder Chairman and Director
Thomas J. Edelman President and Director
John A. Fanning Executive Vice President and Director
Charles A. Brown Vice President - Emerging Assets
Steven M. Burr Vice President - Planning and Engineering
Peter E. Lorenzen Vice President - General Counsel
David M. Posner Vice President - Gas Management
James H. Shonsey Vice President - Finance
George Steel Vice President
Edward T. Story Vice President - International
Diana K. Ten Eyck Vice President - Investor Relations
Stephen G. Tillman Vice President - Greater Green River/DJ Basin
Rodney L. Waller Vice President - Special Projects
Richard A. Wollin Vice President - Gulf Coast
John C. Snyder (53), a director and Chairman, founded the
Company's predecessor in 1978. From 1973 to 1977, Mr. Snyder was an
independent oil operator in Texas and Oklahoma. Previously, he was
a director and the Executive Vice President of May Petroleum Inc.
where he served from 1971 to 1973. Mr. Snyder was the first
president of Canadian-American Resources Fund, Inc., which he founded
in 1969. From 1964 to 1966, Mr. Snyder was employed by Humble Oil
and Refining Company (currently Exxon Co., USA) as a petroleum
engineer. Mr. Snyder received his Bachelor of Science Degree in
Petroleum Engineering from the University of Oklahoma and his Masters
Degree in Business Administration from the Harvard University
Graduate School of Business Administration. Mr. Snyder is a director
of the Community Enrichment Center, Inc., Fort Worth.
Thomas J. Edelman (44), a director and President, co-founded
the Company. Prior to joining the Company in 1981, he was a Vice
President of The First Boston Corporation. From 1975 through 1980,
Mr. Edelman was with Lehman Brothers Kuhn Loeb Incorporated. Mr.
Edelman received his Bachelor of Arts Degree from Princeton
University and his Masters Degree in Finance from the Harvard
University Graduate School of Business Administration. Mr. Edelman
is a director of Command Petroleum Limited, an affiliate of the
Company. In addition, Mr. Edelman serves as chairman of the board of
Lomak Petroleum, Inc. and as a director of Petroleum Heat & Power
Co., Inc., Wolverine Exploration Company, Enterra Corporation and
Star Gas Corporation.
John A. Fanning (55), a director and Executive Vice President,
joined the Company in 1987 and has been a director since 1982.
Between 1985 and 1987, Mr. Fanning was a private investor. He was a
director, President and Chief Executive Officer of The Western
Company of North America, which provides drilling and technical
services to the oil industry, until 1985. Mr. Fanning joined The
Western Company in 1968 and served in various capacities including
Director of Planning, Division Manager, President of Western
Petroleum Services and Executive Vice President. From 1965 through
1968, he was a Planning and Financial Analyst with The Cabot
Corporation. Mr. Fanning received his Bachelor of Science Degree in
Physics from Holy Cross College and his Masters Degree in Industrial
Management from Massachusetts Institute of Technology. Mr. Fanning
is a director of TNP Enterprises Inc, a public utility holding
company.
Charles A. Brown (48), Vice President - Emerging Assets, joined
the Company in 1987. He was a petroleum engineering consultant from
1986 to 1987. He served as President of CBW Services, Inc., a
petroleum engineering consulting firm, from 1979 to 1986 and was
employed by KN from 1971 to 1979 and Amerada Hess Corporation from
1969 to 1971. Mr. Brown received his Bachelor of Science Degree in
Petroleum Engineering from the Colorado School of Mines.
17
Steven M. Burr (38), Vice President - Planning and Engineering,
joined the Company in 1987. From 1982 to 1987, he was a Vice
President with the petroleum engineering consulting firm of
Netherland, Sewell & Associates, Inc. ("NSAI"). From 1978 to 1982,
Mr. Burr was employed by Exxon Company, U.S.A. in the Production
Department. Mr. Burr received his Bachelor of Science Degree in
Civil Engineering from Tulane University.
Peter E. Lorenzen (45), Vice President - General Counsel and
Secretary, joined the Company in 1991. From 1983 through 1991, he
was a shareholder in the Dallas law firm of Johnson & Gibbs, P.C.
Prior to that, Mr. Lorenzen was an associate with Cravath, Swaine &
Moore. Mr. Lorenzen received his law degree from New York University
School of Law and his Bachelor of Arts Degree from The Johns Hopkins
University.
David M. Posner (41), Vice President - Gas Management, joined
the Company in 1991. From 1980 to 1991, he held various positions
with Ladd Petroleum Corporation (a subsidiary of the General Electric
Company) including Vice President of Gas Gathering, Processing and
Marketing. Mr. Posner received his Bachelor of Arts from Brown
University and his Master of Science in Mineral Economics from the
Colorado School of Mines.
James H. Shonsey (43), Vice President - Finance, joined the
Company in 1991. From 1987 to 1991, Mr. Shonsey served in various
capacities including Director of Operations Accounting for Apache
Corporation. From 1976 to 1987 he held various positions with
Deloitte & Touche, Quantum Resources Corporation, Flare Energy
Corporation and Mizel Petro Resources, Inc. Mr. Shonsey received his
CPA certificate from the state of Colorado, his Bachelor of Science
Degree in Accounting from Regis University and his Master of Science
Degree in Accounting from the University of Denver.
George Steel (48), Vice President, joined the Company in 1994.
Previously, he was President of Halliburton Geophysical Services, a
leading worldwide provider of oil field services. From 1969 to 1989
Mr. Steel served the predecessor company of Halliburton Geophysical
in various international assignments. Mr. Steel is a B.Sc. graduate
of St. Andrews, Scotland.
Edward T. Story (51), Vice President - International of the
Company, joined the Company in 1991. From 1990 to 1991, Mr. Story
was Chairman of the Board of a jointly-owned Thai/US company, Thaitex
Petroleum Company. Mr. Story was co-founder, Vice Chairman of the
Board and Chief Financial Officer of Conquest Exploration Company
from 1981 to 1990. He served as Vice President Finance and Chief
Financial Officer of Superior Oil Company from 1979 to 1981. Mr.
Story held the positions of Exploration and Production Controller and
Refining Controller with Exxon U.S.A. from 1975 to 1979. He held
various positions in Esso Standard's international companies from
1966 to 1975. Mr. Story received a Bachelor of Science Degree in
Accounting from Trinity University, San Antonio, Texas and a Masters
of Business Administration from The University of Texas in Austin,
Texas. Mr. Story is a director of Command Petroleum Limited, an
affiliate of the Company. In addition, Mr. Story serves as a
director of Bank Texas, Inc., a bank holding company and Hi/Lo
Automotive, Inc., a distributor of automobile parts.
Diana K. Ten Eyck (48), Vice President - Investor Relations,
joined the Company in 1993. From 1990 to 1993, Ms. Ten Eyck held
various positions with Gerrity Oil & Gas Corporation, including
Director, Senior Vice President, Chief Operating Officer, Chief
Financial Officer, Chief Administrative Officer and Corporate
Secretary. From 1988 to 1990, Ms. Ten Eyck held various positions
with The Robert Gerrity Company including Director, Senior Vice
President, Chief Operating, Chief Financial Officer and Corporate
Secretary. Ms. Ten Eyck received a Bachelor of Arts Degree in
Mathematics from the University of Colorado at Boulder and a Ph.D. in
Mineral Economics from the Colorado School of Mines.
Stephen G. Tillman (48), Vice President - Greater Green
River/DJ Basin, joined the Company in 1994. Between 1990 and 1994,
Mr. Tillman was a private investor. He was Senior Vice President and
District Manager of TXO Production Corporation (Texas Oil & Gas
Corp.) in Denver between 1981 and 1990. Mr. Tillman joined Texas Oil
& Gas Corp. in 1974 and served in various capacities including
Petroleum Engineer, Drilling & Production Manager and District
Manager in Houston and in Wichita, Kansas. From 1968 through 1974,
18
he held various engineering positions with Texaco Inc. in Texas. Mr.
Tillman is a 1969 graduate of Texas A&M University with a Bachelor of
Science Degree in Petroleum Engineering.
Rodney L. Waller (45), Vice President - Special Projects,
joined the Company in 1977. Previously, Mr. Waller was employed by
Arthur Andersen & Co. Mr. Waller received his Bachelor of Arts
Degree from Harding University. Mr. Waller serves as a director of
Wolverine Exploration Company.
Richard A. Wollin (42), Vice President - Gulf Coast, joined the
Company in 1990. From 1983 to 1989, Mr. Wollin served in various
management capacities including Executive Vice President of Quinoco
Petroleum, Inc. with primary responsibility for acquisition,
divestiture and corporate finance activities. From 1976 to 1983, he
was employed in various capacities for The St. Paul Companies, Inc.,
including Senior Vice President of St. Paul Oil & Gas Corp. Mr.
Wollin received his Bachelor of Science Degree from St. Olaf College
and his law degree from the University of Minnesota Law School. Mr.
Wollin is a member of the Minnesota Bar Association.
19
ITEM 2. PROPERTIES
General
The Company's reserves are concentrated in several major
producing areas. These include the Wattenberg Field in Colorado,
northern and southern Wyoming, the Piceance and Uinta Basins in the
Western Slope of Colorado and Utah and, the Giddings area in
southeast Texas.
At December 31, 1994, the Company had interests in 5,269 gross
(2,651 net) producing oil and gas wells located in 15 states and in
the Gulf of Mexico. As of December 31, 1994, estimated proved
reserves totalled 120.2 MMBOE, including 35.0 million barrels of oil
and 511.3 Bcf of gas. In addition to its oil and gas reserves, the
Company holds interests in nine gas transportation and processing
facilities.
Proved Reserves
The following table sets forth estimated yearend proved
reserves for the three years ended December 31, 1994.
December 31,
-------------------------------------
1992 1993 1994
---------- ---------- ----------
Crude oil and liquids (MBbl)
Developed 21,116 18,032 26,104
Undeveloped 11,086 13,898 8,873
--------- --------- ---------
Total 32,202 31,930 34,977
========= ========= =========
Natural gas (MMcf)
Developed 194,621 268,349 353,930
Undeveloped 93,037 161,740 157,321
---------- ---------- ---------
Total 287,658 430,089 511,251
========== ========== =========
Total MBOE 80,145 103,612 120,186
========== ========== =========
The following table sets forth pretax future net revenues
from the production of proved reserves and the Pretax PW10% Value of
such revenues.
(In thousand December 31, 1994
---------------------------------------------
Developed Undeveloped(a) Total
------------ --------------- ------------
1995 $ 94,939 $(20,886) $ 74,053
1996 72,707 (1,752) 70,955
1997 58,712 12,983 71,695
Remainder 333,472 161,613 495,085
---------- ----------- ----------
Total $559,830 $151,958 $711,788
========== =========== ==========
Pretax PW10% Value $355,076 $ 59,291 $414,367(b)
========== =========== ==========
<f/n>
_________________________
(a) Net of estimated capital costs, including estimated costs of $55.9
during 1995.
(b) The after tax PW10% value of proved reserves totalled $361.7 million
at yearend 1994.
The quantities and values in the preceding tables are based on
prices in effect at December 31, 1994, averaging $15.25 per barrel of
oil and $1.56 per Mcf of gas. Price reductions decrease reserve
values by lowering the future net revenues attributable to the
reserves and also by reducing the quantities of reserves that are
recoverable on an economic basis. Price increases have the opposite
effect. Any significant decline in prices of oil or gas could have a
material adverse effect on the Company's financial condition and
results of operations.
Proved developed reserves are proved reserves that are
expected to be recovered from existing wells with existing equipment
and operating methods. Proved undeveloped reserves are proved
reserves that are expected to be recovered from new wells drilled to
known reservoirs on undrilled acreage for which the existence and
recoverability of such reserves can be estimated with reasonable
certainty, or from existing wells where a relatively major
expenditure is required to establish production.
Future prices received for production and future production
costs may vary, perhaps significantly, from the prices and costs
assumed for purposes of these estimates. There can be no assurance
that the proved reserves will be developed within the periods
indicated or that prices and costs will remain constant. With respect
to certain properties that historically have experienced seasonal
curtailment, the reserve estimates assume that the seasonal pattern
of such curtailment will continue in the future. There can be no
assurance that actual production will equal the estimated amounts
used in the preparation of reserve projections.
20
The present values shown should not be construed as the
current market value of the reserves. The 10% discount factor used to
calculate present value, which is specified by the Securities and
Exchange Commission ("SEC"), is not necessarily the most appropriate
discount rate, and present value, no matter what discount rate is
used, is materially affected by assumptions as to timing of future
production, which may prove to be inaccurate. For properties operated
by the Company, expenses exclude the Company's share of overhead
charges. In addition, the calculation of estimated future net
revenues does not take into account the effect of various cash
outlays, including, among other things, general and administrative
costs and interest expense.
There are numerous uncertainties inherent in estimating
quantities of proved reserves and in projecting future rates of
production and timing of development expenditures. The data in the
above tables represent estimates only. Oil and gas reserve
engineering must be recognized as a subjective process of estimating
underground accumulations of oil and gas that cannot be measured in
an exact way, and estimates of other engineers might differ
materially from those shown above. The accuracy of any reserve
estimate is a function of the quality of available data and
engineering and geological interpretation and judgment. Results of
drilling, testing and production after the date of the estimate may
justify revisions. Accordingly, reserve estimates are often
materially different from the quantities of oil and gas that are
ultimately recovered.
Netherland, Sewell & Associates, Inc. ("NSAI"), independent
petroleum consultants, prepared estimates of or audited the Company's
proved reserves which collectively represent more than 80% of Pretax
PW10% Value as of December 31, 1994. Approximately 58% was estimated
independently by NSAI. No estimates of the Company's reserves
comparable to those included herein have been included in reports to
any federal agency other than the SEC.
Producing Wells
The following table sets forth certain information at December
31, 1994 relating to the producing wells in which the Company owned
a working interest. The Company also held royalty interests in 757
producing wells. Wells are classified as oil or gas wells according
to their predominant production stream.
Average
Principle Gross Net Working
Product Stream Wells Wells Interest
-------------- ----- ----- --------
Crude oil and liquids 3,109 1,590 51%
Natural gas 2,160 1,061 49%
----- -----
Total 5,269 2,651 50%
===== =====
21
Acreage
The following table sets forth certain information at December
31, 1994 relating to acreage held by the Company. Undeveloped
acreage is acreage held under lease, permit, contract, or option that
is not in a spacing unit for a producing well, including leasehold
interests identified for development or exploratory drilling.
Gross Net
------------- ------------
Domestic
Developed (a) 529,000 234,000
=========== ==========
Undeveloped 1,354,000 962,000
=========== ==========
International (b)
Undeveloped
Russia 306,000 63,000
Mongolia 5,300,000 2,597,000
Thailand 150,000 150,000
---------- ----------
5,756,000 2,810,000
========== ==========
<f/n>
_________________________
(a) Developed acreage is acreage assigned to producing wells.
(b) Excludes 1,200,000 gross (1,140,000 net) acres in Tunisia that
were sold early in 1995.
Significant Properties
Emphasis has been placed on establishing hubs in certain
producing basins. Interests in five producing areas accounted for
approximately 86% of Pretax PW10% Value at December 31, 1994. This
concentration of assets permits economic efficiencies in the
management of assets and permits identification of complementary
acquisition candidates. Summary information regarding reserve
concentrations of the five most significant properties are set forth
below. More detailed information is set forth under "Business -
Development."
Proved Reserve Quantities
-------------------------
Producing Crude Oil Natural Pretax PW 10% Value
Wells & Liquids Gas Amount Percent
--------- --------- --------- -------- -------
(MBbl) (MMcf) (000)
DJ Basin (CO, NE) 1,703 12,274 186,792 $192,385 46.4%
Greater Green River (WY) 170 1,567 132,745 56,046 13.5
Northern Wyoming (WY) 1,042 10,903 31,648 47,225 11.4
Western Slope (CO & UT) 231 1,562 72,863 31,682 7.7
Giddings Field (TX) 114 2,712 26,708 30,615 7.4
------- ------- ------- -------- ----
Subtotal 3,260 29,018 450,756 357,953 86.4
Other 2,009 5,959 60,495 56,414 13.6
------ ------- ------- -------- ----
Total 5,269 34,977 511,251 $414,367 100.0%
====== ======= ======= ======== ======
ITEM 3. LEGAL PROCEEDINGS
The Company and its subsidiaries and affiliates are named
defendants in lawsuits and involved from time to time in governmental
proceedings, all arising in the ordinary course of business.
Although the outcome of these lawsuits and proceedings cannot be
predicted with certainty, management does not expect these matters to
have a material adverse effect on the financial position of the
Company.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted for a vote of security holders
during the fourth quarter of 1994.
22
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED
SECURITY HOLDER MATTERS
The Company's stock is listed on the New York Stock Exchange and
trade under the symbol "SNY". The following table sets forth, for
1993 and 1994, the high and low sales prices for the Company's
securities for New York Stock Exchange composite transactions, as
reported by The Wall Street Journal.
1993 1994
---------------------- ---------------------
High Low High Low
-------- -------- -------- --------
First Quarter $16-1/8 $10 $21-3/8 $17-1/2
Second Quarter 20-1/4 15 20-1/2 17-1/2
Third Quarter 23 16-5/8 19-3/4 17-1/8
Fourth Quarter 23 14-3/4 17-7/8 13-5/8
On March 9, 1995, the closing price of the common stock
was $14. Dividends were paid at the rate of $.06 per share in the
first and second quarters of 1994. In the third quarter of 1994, the
quarterly dividend was increased to $.065 per share. Shares of
common stock receive dividends as, if and when declared by the Board
of Directors. The amount of future dividends will depend on debt
service requirements, dividend requirements on preferred stock,
capital expenditures and other factors. On December 31, 1994, there
were approximately 3,200 holders of record of the common stock and
30.2 million shares outstanding.
23
ITEM 6. SELECTED FINANCIAL DATA
The following table presents selected financial and
operating information for each of the five years ended December 31,
1994. Share and per share amounts refer to common shares. The
following information should be read in conjunction with the
financial statements presented elsewhere herein.
(In thousands, except per share data) As of or for the Year Ended December 31,
--------------------------------------------------------------
1990 1991 1992 1993 1994
---------- ---------- ---------- ---------- ----------
Income Statement
Revenues $ 84,303 $ 86,640 $118,970 $228,852 $262,328
Income before extraordinary items 3,177 3,663 14,597 22,538 12,372
Per share .15 .14 .43 .58 .07
Net income 3,177 3,663 14,597 19,545 12,372
Per share .15 .14 .43 .45 .07
Dividends Per share .16 .20 .25(a) .22 .25
Average shares outstanding 20,620 22,839 22,722 23,096 23,704
Cash Flow
Net cash provided by operations $ 22,512 $ 37,738 $ 48,339 $ 68,728 $ 86,461
Capital expenditures 171,767(b) 48,385 130,803 167,161 279,288
Balance Sheet
Working capital $ 12,087 $ 17,259 $ 7,619 $ 491 $ 708
Oil and gas properties, net 174,199 182,957 271,995 362,126 557,519
Total assets 221,495 238,992 331,638 453,301 673,259
Senior debt 56,172 17,108 96,568(c) 114,952 234,857
Subordinated notes, net 25,000 25,000 18,750 - 83,650
Stockholders' equity 110,849 165,210 168,866 274,734 274,086
<f/n>
________________________
(a) Due to revised timing, five payments were made at the $.05
current quarterly rate in 1992.
(b) Includes $130.7 million related to the acquisition of a publicly
traded limited partnership managed by the Company.
(c) Includes $49.8 million paid in February 1993 for properties
acquired in December 1992.
The following table sets forth unaudited summary financial
results on a quarterly basis for the two most recent years.
(In thousands, except per share data) 1993 Quarters
-----------------------------------------
First Second Third Fourth
-------- -------- -------- --------
Revenues $44,367 $58,041 $61,317 $65,127
Gross margin 21,495 24,667 26,647 25,502
Depletion, depreciation and amortization 13,417 16,060 3,846 15,439
Income before extraordinary item 3,847 4,185 9,006 5,500
Per share (a) .12 .08 .27 .12
Net income 3,254 4,185 8,295 3,811
Per share (a) .09 .08 .24 .05
1994 Quarters
-----------------------------------------
First Second Third Fourth
-------- -------- -------- --------
Revenues $63,456 $64,578 $71,051 $63,243
Gross margin 28,248 28,153 30,002 31,681
Depletion, depreciation and amortization 19,391 18,164 18,742 20,256
Net income 4,578 3,663 2,261 1,870
Per share .08 .04 (.02) (.03)
<f/n>
________________________
(a) Quarters do not equal year-to-date totals due to rounding.
24
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
Results of Operations
Effective December 31, 1994, the Company changed its method of
accounting for oil and gas properties from the full cost method to
the successful efforts method. The change was applied retroactively
and prior periods presented have been restated. The following
discussions of operating results are based on those restated amounts.
Comparison of 1994 results to 1993. Total revenues in 1994 rose 15%
to $262.3 million. The revenue increase was primarily the result of
a 26% growth in oil and gas production calculated in barrels of oil
equivalent ("BOE") and greater gas processing and transportation
throughput. The revenue rise was limited by a 12% decline in the
average price per BOE. This price decline reduced current year
revenues by $18.8 million. Net income for 1994 was $12.4 million,
compared to $19.5 million in 1993. In addition to the price decline,
the decrease resulted from increased expenses for exploration,
interest and depletion. Net income per common share was $.07 in
1994, compared to $.45 in 1993, as higher preferred dividends
compounded the effect of declining earnings. Due to conversion of
the 8% preferred stock at yearend 1994, preferred dividends will drop
44% in 1995.
The gross margin from production in 1994 increased 10% to $87.8
million, due to the rise in oil and gas production. The average
price received for oil production decreased 4% in 1994 to $14.80 per
barrel while gas prices dropped 14% to $1.67 per Mcf. Total
operating expenses increased 12% during 1994, however, operating
costs per BOE decreased to $4.29 from $4.83 in 1993. Of the 11%
decrease, almost half resulted from a reallocation of certain
internal overhead costs from operating expense to general and
administrative expense. The remainder of the expense per BOE
decrease was due to cost efficiencies gained with increasing
production in concentrated hub areas.
Average daily production during 1994 was 31,966 BOE, up 26% from
1993. By December 1994, average daily production had reached 12,351
barrels and 145.6 MMcf (36,618 BOE). The production increase
resulted from continued development activities and acquisitions. In
1994, the Company drilled and completed 466 wells. Of the wells
placed on production, 360 were in the DJ Basin of eastern Colorado,
34 in the Green River Basin of southern Wyoming, 23 in the Giddings
Field of southeast Texas and 20 in the Piceance Basin of western
Colorado. In the DJ Basin, an additional 90 wells were recompleted
to enhance production. The Company completed $44.7 million in
production acquisitions, the majority of which were for incremental
interests in wells in or around current hubs. The significant
decline in natural gas prices since mid-year resulted in the Company
curtailing its gas development plans for 1995. However, 1995
production is expected to grow by more than 15%, despite the reduced
capital budget.
The gross margin from gas processing, transportation and marketing
activities for 1994 increased 42% to $13.1 million from $9.2 million
in 1993. The increase was primarily attributable to a 45% ($3.7
million) rise in processing and transportation margins as a result of
the facilities expansion. In October 1994, operations began at a
newly constructed gas processing plant in the DJ Basin. The plant is
capable of processing 80 MMcf of gas per day and should add to
margins in 1995. During the fourth quarter of 1994, throughput at
the DJ Basin processing facilities averaged 72.0 MMcf per day
compared to a 1993 annual average of 47.9 MMcf. In the Green River
Basin, transportation throughput for fourth quarter 1994 averaged
27.1 MMcf per day compared to 15.3 MMcf for all of 1993. The growth
was a direct result of the development drilling in the area. The
marketing gross margin increased 16% to total $1.1 million in 1994.
However, late in 1994 margins narrowed due to the decrease in price
differentials available with the precipitous decline in spot market
gas prices. The Company has suspended its involvement in third party
marketing until the markets recover.
25
Other income for 1994 was $17.2 million, up $9.4 million from 1993.
The increase resulted from a $3.5 million gain from the sale of a
portion of the Company's interest in the Permtex joint venture in
Russia, a $3.1 million gain from the sale of equity securities by the
Company's Australian affiliate and $2.0 million in gains on sales of
properties. After these transactions, the Company's interests in
Command and Permtex were reduced to 29% and 21%, respectively.
General and administrative expenses, net of reimbursements, were
3.4% of revenues in 1994, compared to 3.0% of revenues in 1993. The
rise was due in part to the previously mentioned change in the
allocation of certain internal overhead costs. Interest and other
expense was $12.5 million in 1994 compared to $7.3 million in 1993.
The increase was the result of a rise in outstanding debt levels due
to capital project expenditures, as well as increasing interest
rates.
Depletion, depreciation and amortization expense for 1994 increased
30% ($17.8 million) from the prior year. Of the increase, $16.4
million was related to the 26% rise in oil and gas production, with
the remainder due to an increase in unevaluated property impairments
as provided under successful efforts.
The Company adopted FASB Statement No. 109, "Accounting for Income
Taxes," effective January 1, 1992. In 1993, the income tax provision
was reduced from the statutory rate of 35% to zero due to the
elimination of deferred taxes upon realization of tax basis in excess
of financial basis. In 1994, the income tax provision was reduced
from the statutory rate by $3.8 million from the realization of the
remaining excess tax basis.
Comparison of 1993 results to 1992. Total revenues rose 92% in 1993
to $228.9 million. Net income before extraordinary items increased
54% to reach $22.5 million in 1993. The increase was lead by a rapid
rise in production and assisted by an increase in gas processing and
transportation margins. After the effect of a $3.0 million 1993
extraordinary charge on early retirement of debt, earnings per
common share were $.45 in 1993, compared to $.43 in 1992.
The gross margin from production operations for 1993 increased 62%
to $79.7 million, which was primarily related to a growth in oil and
gas production. For the year ended December 31, 1993, average daily
production was 25,472 BOE, a 65% increase from 1992. The production
increase resulted primarily from acquisitions and continuing
development drilling in the DJ Basin of Colorado. The price received
per equivalent barrel decreased by 3% to $13.41. Total operating
expenses including production taxes increased 60% during 1993 although
the operating cost per BOE decreased to $4.83 from $4.99 in 1992.
Expense reductions gained from wells added in the DJ Basin,
where operating costs averaged $2.76 per BOE, were partially offset
by the late 1992 acquisition of Wyoming wells from ARCO where
operating costs averaged $7.45 per BOE.
The gross margin from gas processing, transportation and marketing
activities for 1993 increased 13% to $9.2 million from $8.1 million
in 1992. The increase was primarily attributable to a $2.2 million
(36%) rise in transportation and processing margins as a result of
additional DJ Basin production and the expansion of the related
facilities. Gas marketing margins for 1993 decreased by $1.1 million
due to reduced margins on the Oklahoma cogeneration supply contract,
which declined as a result of an imposed limitation of the contract
sales price and rising gas purchase costs. The margin reduction was
partially offset by a $667,000 (126%) rise in gas marketing margins
resulting from increased third party marketing.
Other income was $9.4 million during 1993, compared to $3.0 million
in 1992. The $6.4 million increase resulted from a $3.5 million gas
contract settlement received in April, a $1.7 million litigation
settlement and greater gains on the sales of securities. General and
administrative expenses, net of reimbursements, for 1993 represented
3.0% of revenues compared to 5.6% in 1992 as expenses were held
essentially flat while revenues grew 92%. Interest and other
expenses increased 28%, primarily as a result of a rise in
outstanding debt balances due to development expenditures and
acquisitions.
26
Depletion, depreciation and amortization during 1993 increased 87%
from the prior year, a $27.3 million rise. Of the increase, $22.5
million was a direct result of the 65% rise in equivalent production
between years, while $3.8 million was due to greater depreciation for
plants, pipelines and other equipment. The remaining increase was
the result of property impairments and a rise in the depletion rate
per equivalent barrel.
Development, Acquisition and Exploration
During 1994, the Company incurred $279.3 million in capital
expenditures; including $156.9 million for oil and gas development,
$70.3 million for acquisitions, $41.5 million for gas facility
expansion, $5.5 million for exploration and $5.1 million for field
and office equipment.
Of the total development expenditures, $90.3 million was
concentrated in the DJ Basin of Colorado. A total of 360 wells were
placed on production there in 1994 with 63 in progress at yearend.
Ten wells spudded during the year were plugged and abandoned. The
rate of drilling was lower than had been previously estimated as a
result of delays associated with permitting difficulties, the impact
of declining gas prices and disappointing results on certain outlying
Wattenberg acreage, including part of the lands under option from
Union Pacific Resources. With the continued declines in gas prices
subsequent to yearend 1994, the Company has reduced its DJ Basin
drilling plans for 1995 to less than 100 wells.
The Company expended $66.6 million for other development and
recompletion projects during 1994 as activity was expanded to other
projects. In the Green River Basin of southern Wyoming, 34 wells
were placed on sales with eight in progress at yearend. In the
horizontal drilling program in the Giddings Field of southeast Texas,
23 wells were placed on sales in 1994, with nine in progress at
yearend and one well abandoned. In the Piceance Basin of western
Colorado, 20 wells were placed on sales, with five wells in progress
at yearend and one well abandoned. The Uinta Basin development
program in northeast Utah is still in its early stages with two wells
placed on sales and seven wells in progress at yearend. Anticipated
drilling expenditures for 1995 will be limited to $70 million in the
absence of a rebound in the gas markets.
In 1994, the Company expended $70.3 million for domestic
acquisitions, of which $44.7 million was for producing properties and
$25.6 million for acreage. The most notable producing acquisitions
were $13.9 million for a 50% interest in properties the Company
operates in the Green River Basin, $6.6 million for properties in the
Piceance Basin, $5.0 million in the DJ Basin, $4.3 million in the
Giddings area of southeast Texas and $6.6 million for a controlling
interest in DelMar Petroleum, Inc., a company that owns and operates
properties in the Gulf of Mexico. In October 1994, the Company
closed a $9.7 million acquisition in northeast Louisiana of which
$3.0 million was proven and $6.7 million was for 330,000 net mineral
acres. The remaining producing interests were acquired mostly in
existing Company hub areas. The remaining unproved acreage was also
predominantly in or around our existing hubs.
The Company's gas gathering and processing facility operations
continue to grow with $41.5 million of capital expenditures in 1994.
The work was heavily concentrated in the Wattenberg area of the DJ
Basin. Construction of a new $21.3 million gas processing plant on
the west end of the Wattenberg Field began operations in October
1994. The project was financed with a capital lease. A total of
$8.7 million was expended to increase the Company's gathering systems
in the DJ Basin to add pipelines, feeder lines, an additional
compressor and new well connections for the continuing drilling
activity in the area. At the Roggen Wattenberg plant, $2.9 million
was expended to add a new de-ethanizer station, improve metering and
boost compression, among other projects. In the Piceance Basin in
western Colorado, a $5.0 million gathering system was constructed.
The other $3.6 million in expenditures were for system expansions in
the Washakie Basin, Nebraska and Utah. Subsequent to yearend 1994,
the Company announced that it is considering the sale of its
Wattenberg gas facilities to increase its financial flexibility.
27
Exploration costs for 1994 were $5.5 million, primarily for
geological and other studies on the newly acquired undeveloped
acreage. Only $213,000 was expended on international projects. In
Russia, commercial production began late in the year with pipeline
construction still in progress in the southernmost field in the
contract area. Three industry partners committed $11.25 million to
the joint venture to fully fund the western participants' anticipated
equity requirements, of which $8.5 million was received in 1994. In
June 1994, a commitment letter was executed with the Overseas Private
Investment Corporation ("OPIC") whereby OPIC will commit $40 million
to the Russian Permtex project. It is expected that the final OPIC
agreement and associated debt financing will be put in place during
the second quarter of 1995. In Mongolia and Tunisia, seismic
acquisition and processing continues. In January 1995, agreements
were reached whereby 100% of the Tunisia project was sold to Command
for stock and 10% of the Mongolia properties were sold for cash at
gains of $602,000 and $456,000, respectively. In Tunisia, the gain
recorded in 1995 could increase by up to $750,000 if a farm out on
certain of the acreage is completed. Additionally, an exploratory
well is planned and the Company will receive additional proceeds if
reserves are discovered. In Mongolia, the Company has a carried
interest in two exploratory wells.
Financial Condition and Capital Resources
At December 31, 1994, the Company had total assets of $673.2
million. Total capitalization was $595.8 million, of which 46% was
represented by stockholder's equity, 36% by senior debt, 17% by
subordinated debt and the remainder by deferred taxes. During 1994,
cash provided by operations was $86.5 million, an increase of 26%
over 1993. As of December 31, 1994, commitments for capital
expenditures totalled $9.9 million. The Company anticipates that
1995 expenditures for development drilling and gas facilities will
approximate $80 million. The level of these and other future
expenditures is largely discretionary, and the amount of funds
devoted to any particular activity may increase or decrease
significantly, depending on available opportunities and market
conditions. The Company plans to finance its ongoing development,
acquisition and exploration expenditures using internally generated
cash flow, asset sales proceeds and existing credit facilities. In
addition, joint ventures or future public and private offerings of
debt or equity securities may be utilized.
In 1994, the Company renegotiated its bank credit facility and
increased it to $500 million. The new facility is divided into a
$100 million short-term portion and a $400 million long-term portion
that expires on December 31, 1998. Management's policy is to renew
the facility on a regular basis. Credit availability is adjusted
semiannually to reflect changes in reserves and asset values. The
borrowing base was increased to $250 million in the fourth quarter of
1994. The majority of the borrowings currently bear interest at
LIBOR plus .75% with the remainder at prime. The Company also has
the option to select CD plus .75%. The margin on LIBOR or CD loans
will increase to 1% if the Company's consolidated senior debt becomes
greater than 80% of its tangible net worth. During 1994 the average
interest rate on the revolver was 5.5%. Financial covenants limit
debt, require maintenance of minimum working capital and restrict
certain payments, including stock repurchases, dividends and
contributions or advances to unrestricted subsidiaries. Such
restricted payments are limited by a formula that includes
underwriting proceeds, cash flow and other items. Based on such
limitations, more than $100 million was available for the payment of
dividends and other restricted payments as of December 31, 1994.
In May 1994, the Company issued $86.4 million of 7% Convertible
Subordinated Notes due 2001 in an underwritten public offering for
net proceeds of $83.6 million. The net proceeds of the offering were
used to repay a portion of the borrowings under the bank credit
facility.
In early 1994, the Company executed an agreement with Union Pacific
Resources Corporation ("UPRC") whereby the Company gained the right
to drill wells on UPRC's previously uncommitted acreage in the
Wattenberg area. The transaction significantly increased the
Company's inventory of undeveloped Wattenberg acreage. UPRC retained
a royalty and the right to participate as a 50% working interest
owner in each well, and received warrants to purchase two million
shares of Company stock. On February 8, 1995, the exercise prices
were reset to $21.60 per share and their expiration extended one
year. One million of the warrants expire in February 1998 and the
other million expire in February 1999. For financial reporting
purposes, the warrants were valued at $3.5 million, which was
recorded as an increase to oil and gas properties and capital in
28
excess of par value. In early 1995, the Company paid UPRC $400,000
for an extension of the time period to drill the commitment wells and
released a portion of the outlying acreage committed to the venture.
In 1992, an institutional investor agreed to contribute $7 million
to a partnership formed to monetize Section 29 tax credits to be
realized from the Company's properties, mainly in the DJ Basin. The
initial $3 million was contributed in 1992, an additional $3 million
contributed during 1993 and $1 million received in March 1994. In
June 1994, the arrangement was extended and an additional $1.8 million
was received. In early 1995, a second investor was added and the
limited partners committed to contribute an additional $5.0 million.
As a result, this transaction is anticipated to increase cash flow and
net income through 1996. A revenue increase of more than $.40 per Mcf
is realized on production generated from qualified Section 29 properties
in this partnership. The Company recognized $780,000, $3.8 million and
$3.0 million, respectively, of this revenue during 1992, 1993 and 1994.
The Company maintains a program to divest marginal properties and
assets which do not fit its long range plans. During 1993 and 1994,
the Company received $5.5 million and $2.8 million, respectively, in
proceeds from sales of properties. The 1993 proceeds included $4.0
million of cash receipts previously accrued for late 1992 sales.
Subsequent to yearend 1994, the Company announced that it is
considering the sale of its Wattenberg gas facilities and certain
non-strategic assets.
The Company believes that its capital resources are adequate to meet
the requirements of its business. However, future cash flows are
subject to a number of variables including the level of production
and oil and gas prices, and there can be no assurance that operations
and other capital resources will provide cash in sufficient amounts
to maintain planned levels of capital expenditures or that increased
capital expenditures will not be undertaken.
Inflation and Changes in Prices
While certain of its costs are affected by the general level of
inflation, factors unique to the petroleum industry result in
independent price fluctuations. Over the past five years,
significant fluctuations have occurred in oil and gas prices.
Although it is particularly difficult to estimate future prices of
oil and gas, price fluctuations have had, and will continue to have,
a material effect on the Company.
The following table indicates the average oil and gas prices
received over the last five years and highlights the price
fluctuations by quarter for 1993 and 1994. Average gas prices prior
to 1994 exclude Mississippi gas production sold under a high price
contract. During 1993, the Company renegotiated the gas contract and
received a substantial payment. As of January 1994, the Company
still receives a higher than market price for the Mississippi gas
sales, however the price is significantly below the previously
received average price of over $12.00 per Mcf. Average price
computations exclude contract settlements and other nonrecurring
items to provide comparability. Average prices per equivalent barrel
indicate the composite impact of changes in oil and gas prices.
Natural gas production is converted to oil equivalents at the rate of
6 Mcf per barrel.
29
Average Prices
----------------------------------------
Crude Oil Per
and Natural Equivalent
Liquids Gas Barrel
------------- ---------- ------------
(Per Bbl) (Per Mcf)
Annual
------
1989 $ 18.30 $ 1.65 $ 12.84
1990 23.65 1.69 15.61
1991 20.62 1.68 14.36
1992 18.87 1.74 13.76
1993 15.41 1.94 13.41
1994 14.80 1.67 11.82
Quarterly
---------
1993
----
First $ 16.62 $ 2.05 $ 14.25
Second 16.76 1.87 13.65
Third 14.78 1.85 12.73
Fourth 13.80 2.02 13.12
1994
----
First $ 12.02 $ 1.98 $ 11.93
Second 15.55 1.65 12.20
Third 16.21 1.53 11.83
Fourth 15.30 1.56 11.39
In December 1994, the Company received an average of $14.87 per
barrel and $1.63 per Mcf for its production.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTAL DATA
Reference is made to the Index to Financial Statements on
page 32 for financial statements and notes thereto. Quarterly
financial data is presented on page 24 of this Form 10-K.
Supplementary schedules have been omitted as not required or not
applicable because the information required to be presented is
included in the financial statements and related notes.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURES.
None.
30
INDEX TO FINANCIAL STATEMENTS
Page
Report of Independent Public Accountants . . . . . . . . . . . . .32
Consolidated Balance Sheets as of December 31, 1993 and 1994 . . .33
Consolidated Statements of Operations for the years ended
December 31, 1992, 1993 and 1994 . . . . . . . . . . . . . .34
Consolidated Statements of Changes in Stockholders' Equity
for the years ended December 31, 1992, 1993 and 1994 . . . .35
Consolidated Statements of Cash Flows
for the years ended December 31, 1992, 1993 and 1994 . . . .36
Notes to Consolidated Financial Statements . . . . . . . . . . . .37
31
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Stockholders of Snyder Oil Corporation:
We have audited the accompanying consolidated balance sheets of
Snyder Oil Corporation (a Delaware corporation) and subsidiaries as
of December 31, 1993 and 1994, and the related consolidated
statements of operations, changes in stockholders' equity, and cash
flows for each of the three years in the period ended December 31,
1994. These financial statements are the responsibility of the
Company's management. Our responsibility is to express an opinion on
these financial statements based on our audits.
We conducted our audits in accordance with generally accepted
auditing standards. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements. An audit also
includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide
a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present
fairly, in all material respects, the financial position of Snyder
Oil Corporation and subsidiaries as of December 31, 1993 and 1994,
and the results of their operations and their cash flows for each of
the three years in the period ended December 31, 1994, in conformity
with generally accepted accounting principles.
As explained in Note 2 to the financial statements, in 1994, the
Company changed its method of accounting for its oil and gas
properties from "full cost" to "successful efforts." All prior
period financial statements presented have been restated.
ARTHUR ANDERSEN LLP
Fort Worth, Texas,
March 3, 1995
32
SNYDER OIL CORPORATION
CONSOLIDATED BALANCE SHEETS (Notes 1 and 2)
(In thousands)
December 31,
-------------------------
1993 1994
---------- -----------
ASSETS
Current assets
Cash and equivalents $ 10,913 $ 21,733
Accounts receivable 47,472 37,055
Inventory and other 3,407 13,651
---------- ----------
61,792 72,439
---------- ----------
Investments (Note 4) 29,383 43,301
---------- ----------
Oil and gas properties, successful efforts method (Note 5) 454,876 680,215
Accumulated depletion, depreciation and amortization (138,470) (207,976)
---------- ----------
316,406 472,239
---------- ----------
Gas processing and transportation facilities (Note 5) 60,015 106,622
Accumulated depreciation (14,295) (21,342)
---------- ----------
45,720 85,280
---------- ----------
$ 453,301 $ 673,259
========== ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities
Accounts payable $ 38,047 $ 44,874
Accrued liabilities 23,239 25,112
Current portion of long term debt (Note 3) 15 1,745
---------- ----------
61,301 71,731
---------- ----------
Senior debt, net (Note 3) 114,952 216,034
Convertible subordinated notes (Note 3) - 83,650
Capital lease, net (Note 3) - 18,823
Deferred taxes and other (Notes 7 and 9) 2,314 3,211
Minority interest - 5,724
Commitments and contingencies (Note 10)
Stockholders' equity (Note 6)
Preferred stock, $.01 par, 10,000,000 shares authorized,
8% Convertible preferred stock, 1,186,005 and
-0- shares issued and outstanding 12 -
6% Convertible preferred stock, 1,035,000 shares
issued and outstanding 10 10
Common stock, $.01 par, 75,000,000 shares authorized,
23,259,658 and 30,209,197 issued 233 302
Capital in excess of par value 249,713 255,961
Retained earnings 25,308 20,959
Common stock held in treasury, 122,018 shares at cost - (2,288)
Foreign currency translation gain(loss) (542) 1,222
Unrealized loss on investments (Note 4) - (2,080)
---------- ----------
274,734 274,086
---------- ----------
$ 453,301 $ 673,259
========== ==========
<f/n> The accompanying notes are an integral part of these statements.
33
SNYDER OIL CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS (Notes 1 and 2)
(In thousands except per share data)
Year Ended December 31,
----------------------------------
1992 1993 1994
--------- --------- ---------
Revenues (Note 8)
Oil and gas sales $ 77,363 $124,641 $137,858
Gas processing, transportation and marketing 38,611 94,839 107,247
Other 2,996 9,372 17,223
--------- --------- ---------
118,970 228,852 262,328
Expenses
Direct operating 28,057 44,901 50,067
Cost of gas and transportation 30,469 85,640 94,177
Exploration 1,515 2,960 6,505
General and administrative 6,704 6,780 9,053
Interest and other 5,693 7,271 12,463
Depletion, depreciation and amortization 31,505 58,762 76,553
--------- --------- ---------
Income before taxes, minority interest
and extraordinary item 15,027 22,538 13,510
Provision for income taxes (Note 7)
Current 430 - -
Deferred - - 967
--------- --------- ---------
430 - 967
--------- --------- ---------
Minority interest (Note 2) - - (171)
--------- --------- ---------
Income before extraordinary item 14,597 22,538 12,372
Extraordinary item - early extinguishment
of debt (Note 3) - (2,993) -
--------- --------- ---------
Net income $ 14,597 $ 19,545 $ 12,372
========= ========= =========
Net income per common share (Note 6)
Before extraordinary item $ .43 $ .58 $ .07
Extraordinary item - (.13) -
--------- --------- ---------
Total $ .43 $ .45 $ .07
========= ========= =========
Weighted average shares outstanding (Note 6) 22,722 23,096 23,704
========= ========= =========
<f/n> The accompanying notes are an integral part of these statements.
34
SNYDER OIL CORPORATION
CONSOLIDATED STATEMENTS OF CHANGES IN
STOCKHOLDERS' EQUITY (Notes 1, 2 and 6)
(In thousands)
Preferred Stock Common Stock Capital in
----------------- --------------- Excess of Retained
Shares Amount Shares Amount Par Value Earnings
------- ------- ------- ------ ----------- ----------
Balance, December 31, 1991 1,200 $ 12 22,855 $ 228 $ 149,123 $ 25,333
Cumulative effect of
accounting change - - - - - (9,486)
Issuance of common - - 234 2 807 -
Repurchase of common - - (215) (1) (1,260) -
Dividends - - - - - (10,489)
Net income - - - - - 14,597
-------- -------- -------- ------ --------- ----------
Balance, December 31, 1992 1,200 12 22,874 229 148,670 19,955
Issuance of preferred 1,035 10 - - 99,315 -
Common stock grants and
exercise of options - - 309 3 1,729 -
Conversion of preferred
to common (14) - 77 1 (1) -
Dividends - - - - - (14,192)
Net income - - - - - 19,545
------- ------ ------- ------- ---------- ----------
Balance, December 31, 1993 2,221 22 23,260 233 249,713 25,308
Common stock grants and
exercise of options - - 414 4 2,851 -
Conversion of preferred
to common (1,186) (12) 6,535 65 (53) -
Issuance of warrants - - - - 3,450 -
Dividends - - - - - (16,721)
Net income - - - - - 12,372
------ ------ -------- ------ --------- ----------
Balance, December 31, 1994 1,035 $ 10 30,209 $ 302 $ 255,961 $ 20,959
====== ====== ======== ====== ========= ==========
<f/n> The accompanying notes are an integral part of these statements.
35
SNYDER OIL CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS (Notes 1 and 2)
(In thousands)
Year Ended December 31,
--------------------------------
1992 1993 1994
--------- --------- ---------
Operating activities
Net income $ 14,597 $ 19,545 $ 12,372
Adjustments to reconcile net income to net cash
provided by operations
(Gain) loss on sales of properties 1,202 1,033 (1,969)
Exploration expense 1,515 2,960 6,505
Depletion, depreciation and amortization 31,505 58,762 76,553
Deferred taxes - - 967
Extraordinary item - early extinguishment of debt - 2,993 -
Gains on sale of securities (777) (2,283) (9,747)
Excess of equity in earnings over distributions 41 (189) (1,355)
Amortization of deferred credits (780) (3,846) (2,986)
Changes in operating assets and liabilities
Decrease (increase) in
Accounts receivable (4,669) (22,397) 11,024
Inventory and other 211 (3,354) (9,241)
Increase (decrease) in
Accounts payable 6,395 12,753 1,901
Accrued liabilities (1,352) 2,227 1,841
Other liabilities 365 319 361
Other 86 205 235
--------- --------- ---------
Net cash provided by operations 48,339 68,728 86,461
--------- --------- ---------
Investing activities
Acquisition, development and exploration (78,593) (194,264) (244,353)
Proceeds from investments 3,582 8,378 5,019
Outlays for investments (1,626) (27,594) (8,804)
Sale of properties 2,992 5,547 2,806
--------- --------- ---------
Net cash used by investing (73,645) (207,933) (245,332)
--------- --------- ---------
Financing activities
Issuance of common 722 1,528 922
Issuance of preferred - 99,325 -
Increase in indebtedness 29,700 68,159 187,138
Debt issuance costs - - (2,855)
Repayments of indebtedness (187) (25,000) -
Premium on debt extinguishment - (2,983) -
Dividends (10,489) (14,192) (16,721)
Deferred credits 2,594 2,796 2,356
Repurchase of common (1,261) - (1,149)
--------- --------- ---------
Net cash realized by financing 21,079 129,633 169,691
--------- --------- ---------
Increase (decrease) in cash (4,227) (9,572) 10,820
Cash and equivalents, beginning of year 24,712 20,485 10,913
--------- --------- ---------
Cash and equivalents, end of year $ 20,485 $ 10,913 $ 21,733
========= ========= =========
Noncash investing and financing activities
Gas plant capital lease - - $ 21,000
<f/n> The accompanying notes are an integral part of these statements.
36
SNYDER OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) ORGANIZATION AND NATURE OF BUSINESS
Snyder Oil Corporation (the "Company") is primarily
engaged in the acquisition, production, development and exploration
of domestic oil and gas properties. The Company is also involved in
gas processing, transportation, gathering and marketing. The Company
is engaged to a modest but growing extent in international
acquisition, development and exploration and maintains a number of
special purpose subsidiaries which are engaged in ancillary
activities including gas transmission, water disposal and management
of oil and gas assets on behalf of institutional investors. The
Company, a Delaware corporation, is the successor to a company formed
in 1978.
(2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The consolidated financial statements include the accounts
of Snyder Oil Corporation and its subsidiaries (collectively, the
"Company"). Affiliates in which the Company owns more than 50% are
fully consolidated, with the related minority interest being deducted
from subsidiary earnings and stockholders' equity. The Company
accounts for its interest in joint ventures and partnerships using
the proportionate consolidation method, whereby its share of assets,
liabilities, revenues and expenses are consolidated with other
operations.
In 1994, the Company changed from the full cost to the
successful efforts method of accounting for its oil and gas
properties, in order to more accurately reflect its results as it
continues to expand its development and exploration efforts.
Accordingly, 1992 and 1993 statements of operations and the 1993
balance sheet have been restated to conform to successful efforts.
The cumulative effect was to reduce January 1, 1992, retained
earnings by $9.5 million. For the 1992 and 1993 years previously
reported, the effect of the accounting change restatement, was to
reduce net income by $6.0 million ($.27 per share) and $6.1 million
($.26 per share), respectively. Under successful efforts, oil and
gas leasehold costs are capitalized when incurred. Unproved
properties are assessed periodically on a property-by-property basis
and impairments in value are charged to expense. Exploratory
expenses, including geological and geophysical expenses and delay
rentals, are charged to expense as incurred. Exploratory drilling
costs, including stratigraphic test wells, are initially capitalized,
but charged to expense if and when the well is determined to be
unsuccessful. Costs of productive wells, developmental dry holes and
productive leases are capitalized and amortized on a unit-of-
production basis over the life of the remaining proved reserves. Gas
is converted to equivalent barrels at the rate of 6 Mcf to 1 barrel.
Generally, amortization of capitalized costs is provided on a
property-by-property basis.
Generally, the Company provides an impairment reserve for
significant proved and unproved oil and gas property groups to the
extent that net capitalized costs exceed the undiscounted future
value. During 1992, 1993 and 1994, the Company provided impairment
reserves of $3.4 million, $4.4 million and $5.8 million,
respectively.
The Company's investment in its Australian affiliate is
accounted for using the equity method, whereby the cash basis
investment is increased for equity in earnings and decreased for
dividends, if any were received. The affiliate's functional currency
is the Australian dollar. The foreign currency translation
adjustments reported in the balance sheet are the result of the
translation of the Australian dollar balance sheet into United States
dollars at yearend and the changes in the exchange rate subsequent to
purchase.
37
To a limited extent, the Company enters into commodities
contracts to hedge the price risk of a portion of its production. In
1994, the Company entered into certain gas sales arrangements in
order to lock in the price differential between the Rocky Mountain
and the NYMEX Henry Hub prices to reduce exposure to the Rocky
Mountain spot prices. The contracts included 31,000 MMBtu per day,
20,000 MMBtu for a period of ten years and 11,000 MMBtu through July
1995. At December 31, 1994, the net present value of the contracts
was estimated to be $4.9 million with no recorded carrying value.
All liquid investments with a maturity of three months or
less are considered to be cash equivalents. General and
administrative expenses are reduced by reimbursements for well
operations, drilling, management of partnerships and services
provided to unconsolidated affiliates. Reimbursements amounted to
$14.3 million, $17.8 million and $25.4 million, respectively, in
1992, 1993 and 1994.
Certain amounts in the 1992 and 1993 financial statements
have been reclassified to conform with the 1994 presentation.
(3) INDEBTEDNESS
The following indebtedness was outstanding on the
respective dates:
December 31,
-----------------------
1993 1994
---------- ----------
(In thousands)
Revolving credit facility $ 114,901 $ 216,001
Other 66 50
---------- ----------
114,967 216,051
Less current portion (15) (17)
---------- ----------
Senior debt, net $ 114,952 $ 216,034
========== ==========
Convertible subordinated notes, net $ - $ 83,650
========== ==========
Capital lease - 20,551
Less current portion - (1,728)
---------- ----------
Capital lease, net $ - $ 18,823
========== ==========
The Company maintains a $500 million revolving credit
facility. The facility is divided into a $400 million long-term
portion and a $100 million short-term portion. The borrowing base
available under the facility at December 31, 1994 was $250 million.
The majority of the borrowings under the facility currently bear
interest at LIBOR plus .75% with the remainder at prime, with an
option to select CD plus .75%. The margin on LIBOR or CD will
increase to 1% if the Company's consolidated senior debt becomes
greater than 80% of its tangible net worth. During 1994, the average
interest rate under the revolver was 5.5%. The Company pays certain
fees based on the unused portion of the borrowing base. Covenants
require maintenance of minimum working capital, limit the incurrence
of debt and restrict dividends, stock repurchases, certain
investments, other indebtedness and unrelated business activities.
Such restricted payments are limited by a formula that includes
underwriting proceeds, cash flow and other items. Based on such
limitations, over $100 million was available for the payment of
dividends and other restricted payments as of December 31, 1994.
38
In May 1994, the Company issued $86.3 million of 7%
convertible subordinated notes due May 15, 2001. The net proceeds
were $83.4 million. The notes are convertible into common stock at
$23.16 per share, and are redeemable at the option of the Company on
or after May 15, 1997, initially at 103.51% of principal, and at
prices declining to 100% at May 15, 2000, plus accrued interest. At
December 31, 1994, the fair market value of the notes, based on their
closing price on the New York Stock Exchange, was $75.9 million.
In November 1994, the Company entered into an agreement
with a bank whereby the bank purchased the recently constructed West
Wattenberg Gas Plant from the Company for $21 million and leased it
back. The lease has a term of seven years and includes an option to
repurchase the plant at the end of the lease for $4.2 million. As a
capital lease, the asset and related debt are recorded on the balance
sheet of the Company. At December 31, 1994, the Company's future
minimum rentals under the lease were $24.0 million. At December 31,
1994, the present value of net minimum capital lease payments
recorded as a liability in the accompanying balance sheet was $20.6
million, of which $1.7 million was classified as current.
In 1993, the Company retired $25 million of subordinated
notes and the related cumulative participating rights. The portion
of the payment in excess of principal and accrued interest was
expensed as an extraordinary item for $3.0 million.
Scheduled maturities of indebtedness for the next five
years are $1.7 million in 1995, $2.1 million in 1996, $2.2 million in
1997, $218.5 million in 1998 and $2.5 million in 1999. The long-term
portion of the revolving credit facility is scheduled to expire in
1998; however, it is management's policy to renew the facility and
extend the maturity on a regular basis.
Cash payments for interest were $5.4 million, $9.2 million
and $9.9 million, respectively, for 1992, 1993 and 1994.
(4) INVESTMENTS
The Company has investments in foreign and domestic energy
companies and long term notes receivable, which at December 31, 1993
and 1994, had a book cost of $29.4 million and $46.5 million,
respectively. The corresponding fair market values were $54.2
million and $48.2 million at December 31, 1993 and 1994,
respectively. In 1994, the Company adopted SFAS No. 115, "Accounting
for Certain Investments in Debt and Equity Securities." Per the
pronouncement, investments carried on the cost basis must be adjusted
to their market value with a corresponding increase or decrease to
stockholders' equity. The pronouncement does not apply to
investments accounted for by the equity method.
In May 1993, the Company acquired 42.8% of the outstanding
shares of Command Petroleum Limited ("Command"), an Australian
exploration and production company, for $18.2 million. The
investment is accounted for by the equity method. The Sydney based
company is listed on the Australian Stock Exchange, and holds
interests in various international exploration and production permits
and licenses as well as a 45.4% interest in a publicly traded
Netherlands exploration and production company whose assets are
located primarily in the North Sea. In January 1994, Command
completed an offering of 43 million of its common shares, and in
February 1994 paid $1.1 million in cash and issued 2.5 million of its
common shares in return for an incremental interest in the
Netherlands company. Additionally in 1994, 51.9 million of stock
options were exercised and 4.7 million partly paid shares were
issued. As a result of these transactions, the Company's ownership
in Command was reduced to 29.0% and a $3.1 million gain was
recognized. The market value of the Company's investment in Command
based on Command's closing price at December 31, 1994 was $30.0
million, compared to a cost basis of $25.1 million.
39
In early 1993, the Company formed the Permtex joint
venture to develop proven oil fields in the Volga-Urals Basin of
Russia. To finance its portion of planned development expenditures,
the Company sold a portion of its investment in the project to three
industry participants. As a result, its equity basis investment was
reduced from 50% to 20.6% and a $3.5 million net gain was recorded.
The Russian investment had a cost and fair value at December 31, 1994
of $3.1 million.
The Company has investments in securities of publicly
traded domestic energy companies, not accounted for by the equity
method, with a total cost at December 31, 1993 and 1994 of $9.7
million and $15.4 million, respectively. The market value of these
securities at December 31, 1993 and 1994 approximated $13.3 million
and $12.2 million, respectively. Accordingly, at December 31, 1994,
investments were decreased by $3.2 million, stockholders' equity was
decreased by $2.1 million and deferred taxes payable were decreased
by $1.1 million as required by SFAS No. 115.
The Company holds $2.9 million in long term notes
receivable due from privately held corporations. All notes are
secured by certain assets, including stock and oil and gas
properties. At December 31, 1993 and 1994, the fair value of the
notes receivable, based on existing market conditions and the
anticipated future net cash flow related to the notes, approximated
their book value.
(5) OIL AND GAS PROPERTIES AND GAS FACILITIES
The cost of oil and gas properties at December 31, 1993
and 1994 includes $6.3 million and $23.7 million, respectively, of
unevaluated leasehold. Such properties are held for exploration,
development or resale and are excluded from amortization. The
following table sets forth costs incurred related to oil and gas
properties and gas processing and transportation facilities:
1992 1993 1994
-------- -------- --------
Acquisition $ 62,538 $ 48,162 $ 70,255
Development 54,093 90,617 156,912
Gas processing, transportation and other 11,158 22,595 46,607
Exploration 3,014 5,787 5,514
-------- -------- --------
$130,803 $167,161 $279,288
======== ======== ========
Development expenditures for the year ended December 31,
1994, were concentrated primarily in the DJ Basin of Colorado where
expenditures totalled $90.3 million. A total of 360 wells were
placed on production there in 1994, 90 were recompleted and 63 more
were in progress at December 31. In the Green River Basin of
southern Wyoming, 34 wells were placed on production with eight in
progress at yearend. In the horizontal drilling program in the
Giddings Field of southeast Texas, 23 wells were placed on production
in 1994, with nine in progress at yearend and one well abandoned. In
the Piceance Basin of western Colorado, 20 wells were placed on
production, with five wells in progress at yearend and one well
abandoned. The Uinta Basin development program in northeast Utah is
still in its early stages with two wells placed on production and
seven wells in progress at yearend.
During 1994, the Company expended $70.3 million for
domestic acquisitions, of which $44.7 million was for proven
properties and $25.6 million for unproven acreage. The most notable
production acquisitions were $13.9 million for an incremental
interest in the Barrel Springs unit in Wyoming, $6.6 million for
properties in the Piceance Basin, $5.0 million in the DJ Basin, $4.3
million in the Giddings area of southeast Texas and $6.6 million for
a controlling interest in Del Mar Petroleum, Inc., a company that
owns and operates properties in the Gulf of Mexico. The most
substantial acreage purchase involved a $9.7 million acquisition in
northeast Louisiana, of which $3.0 million related to production and
$6.7 million was for 330,000 net mineral acres which are classified
as unproven. Acquisitions are accounted for utilizing the purchase
method. The pro forma effect of the acquisitions was not material to
the Company's results of operations.
40
The Company's gas facilities expansion continued with
$41.5 million expended during 1994, primarily on facilities in the DJ
Basin. Construction of a new gas processing plant on the west end of
the Wattenberg Field with a cost of $21.3 million was completed in
the fourth quarter. Financing was obtained for the full project cost
under a seven-year capital lease with a fixed 8.2% interest rate. A
total of $8.7 million was expended to increase the Company's
gathering systems in the DJ Basin to add pipelines, feeder lines, an
additional compressor and new well connections for the continuing
drilling activity in the area. At the Roggen plant, $2.9 million was
expended to add a new de-ethanizer station, improve metering and
boost compression, among other projects. Another $8.6 million in
expenditures were for system expansions in the Piceance Basin,
Nebraska and the Washakie Basin.
(6) STOCKHOLDERS' EQUITY
A total of 75 million common shares, $.01 par value, are
authorized of which 30.2 million were issued at December 31, 1994.
In 1993, the Company issued 386,000 shares, with 309,000 shares
issued primarily for the exercise of stock options by employees and
77,000 shares issued on conversion of 14,000 preferred shares. In
1994, the Company issued 6,949,000 shares, with 414,000 shares issued
primarily for the exercise of stock options by employees (for which
122,000 shares were received as consideration in lieu of cash and are
held in treasury) and 6,535,000 shares issued on conversion of all
remaining shares of the 8% preferred. In 1993, the Company paid
first and second quarter dividends at the rate of $.05 per share and
increased the rate to $.06 per share in the third quarter. In the
third quarter of 1994, the dividend rate increased to $.065 per
share.
A total of 10 million preferred shares, $.01 par value,
are authorized. In December 1991, 1.2 million shares of 8%
convertible exchangeable preferred stock were sold through an
underwriting. The net proceeds were $57.4 million. In 1993, 14,000 of
the preferred shares were converted into 77,000 common shares.
Effective December 31, 1994, the remaining 8% convertible preferred
shares were converted into 6,535,000 common shares.
In April 1993, 4.1 million depositary shares (each
representing a one quarter interest in one share of $100 liquidation
value stock) of 6% preferred stock were sold through an underwriting.
The net proceeds were $99.3 million. The stock is convertible into
common stock at $21.00 per share and is exchangeable at the option of
the Company for 6% convertible subordinated debentures on any
dividend payment date. The 6% convertible preferred stock is
redeemable at the option of the Company on or after March 31, 1996.
The liquidation preference is $25.00 per depositary share, plus
accrued and unpaid dividends. The Company paid $9.1 million and
$10.8 million, respectively, in preferred dividends during 1993 and
1994.
The Company maintains a stock option plan for employees
providing for the issuance of options at prices not less than fair
market value. Options to acquire up to three million shares of
common stock may be outstanding at any given time. The specific
terms of grant and exercise are determinable by a committee of
independent members of the Board of Directors. The majority of
currently outstanding options vest over a three-year period (30%,
60%, 100%) and expire five to seven years from date of grant.
In 1990, the shareholders adopted a stock grant and option
plan (the "Directors' Plan") for non-employee Directors of the
Company. The Directors' Plan provides for each non-employee director
to receive 500 common shares quarterly in payment of their annual
retainer. It also provides for 2,500 options to be granted annually
to each non-employee Director. The options vest over a three-year
period (30%, 60%, 100%) and expire five years from date of grant.
At December 31, 1994, a total of 1.5 million options were
outstanding at exercise prices of $4.53 to $20.38 per share. At
December 31, 1994, a total of 533,000 of such options were vested
having exercise prices of $4.53 to $19.25 per share. During 1993,
309,000 options were exercised at prices of $4.53 to $9.13 per share,
and 23,000 were forfeited. During 1994, 414,000 options were
exercised at prices of $4.53 to $13.00 per share, and 2,000 were
forfeited.
41
Earnings per share are computed by dividing net income,
less dividends on preferred stock, by average common shares
outstanding. Net income available to common for the three years
ended December 31, 1994, was $9.8 million, $10.4 million and $1.6
million, respectively. Differences between primary and fully diluted
earnings per share were insignificant for all periods presented.
(7) FEDERAL INCOME TAXES
The Company adopted FASB Statement No. 109, "Accounting
for Income Taxes," effective January 1, 1992. At December 31, 1994,
the Company had no liability for foreign taxes. A reconciliation of
the United States federal statutory rate to the Company's effective
income tax rate follows:
1992 1993 1994
-------- -------- --------
Federal statutory rate 34% 35% 35%
Utilization of net deferred tax asset (31%) (35%) (27%)
Prior year tax reimbursement - - (1%)
-------- -------- --------
Effective income tax rate 3% - 7%
======== ======== ========
For book purposes the components of the net deferred asset
and liability at December 31, 1993 and 1994, respectively, were:
1993 1994
---------- ----------
Deferred tax assets
NOL carryforwards $ 27,316 $ 56,902
AMT credit carryforwards 1,350 1,350
Reserves and other 1,804 907
---------- ----------
30,470 59,159
---------- ----------
Deferred tax liabilities
Depreciable and depletable property (25,732) (55,601)
Investments - (2,308)
---------- ----------
(25,732) (57,909)
---------- ----------
Deferred asset 4,738 1,250
Valuation allowance (4,738) (1,841)
---------- ----------
Net deferred tax asset (liability) $ - $ (591)
========== ==========
For tax purposes, the Company had net operating loss
carryforwards of $162.6 million at December 31, 1994. These
carryforwards expire between 1997 and 2009. At December 31, 1994,
the Company had alternative minimum tax credit carryforwards of $1.4
million and depletion carryforwards of $1.5 million, both of which
are available indefinitely. Current income taxes shown in the
financial statements reflect estimates of alternative minimum taxes.
Cash payments during 1992, 1993 and 1994 were $1.0 million, $75,000
and $10,000, respectively.
(8) MAJOR CUSTOMERS
In 1992, 1993 and 1994, Amoco Production Company accounted
for 27%, 12% and 11%, respectively, of revenues. Management believes
that the loss of any individual purchaser would not have a material
adverse impact on the financial position or results of operations of
the Company.
42
(9) DEFERRED CREDITS
In 1992, an institutional investor agreed to contribute $7
million to a partnership formed to monetize Section 29 tax credits to
be realized from the Company's properties, mainly in the DJ Basin.
The initial $3 million was contributed in 1992, an additional $3
million contributed during 1993 and $1 million received in March
1994. In June 1994, the arrangement was extended and an additional
$1.8 million was received. In early 1995, a second investor was
added and the limited partners committed to contribute an additional
$5.0 million. As a result, this transaction is anticipated to
increase cash flow and net income through 1996. A revenue increase
of more than $.40 per Mcf is realized on production generated from
qualified Section 29 properties in this partnership. The Company
recognized $780,000, $3.8 million and $3.0 million of this revenue
during 1992, 1993 and 1994, respectively.
(10) COMMITMENTS AND CONTINGENCIES
The Company rents office space and gas compressors at
various locations under non-cancelable operating leases. Minimum
future payments under such leases approximate $2.4 million for 1995,
$2.5 million for 1996 and 1997, $2.4 million for 1998, and $2.0
million for 1999.
In 1993, the Company received a $5.3 million settlement on
a gas contract dispute. Of the proceeds, $3.5 million was reflected
as other income in 1993, with the remaining $1.8 million reflected as
a reserve for possible contingencies. In 1994, $232,000 was paid and
the remaining $1.6 million reported as income. In April 1993, the
Company was granted a $2.7 million judgment in litigation involving
the allocation of proceeds from a pipeline dispute. The judgment has
been appealed. The Company is a party to various other lawsuits
incidental to its business, none of which are anticipated to have a
material adverse impact on its financial position or results of
operations. The financial statements reflect favorable legal
judgments only upon receipt of cash, final judicial determination or
execution of a settlement agreement.
(11) UNAUDITED SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION:
Independent petroleum consultants directly evaluated 74%,
62%, and 58% of proved reserves at December 31, 1992, 1993 and 1994,
respectively, and performed a detailed review of properties which
comprised in excess of 80% of proved reserve value. All reserve
estimates are based on economic and operating conditions at that
time. Future net cash flows as of each year-end were computed by
applying then current prices to estimated future production less
estimated future expenditures (based on current costs) to be incurred
in producing and developing the reserves. All reserves are located
onshore in the United States and in the waters of the Gulf of Mexico.
43
Quantities of Proved Reserves - Crude Oil Natural Gas
-------------- -------------
(MBbl) (MMcf)
Balance, December 31, 1991 19,678 247,169
Revisions (1,474) (21,620)
Extensions, discoveries and additions 3,403 48,802
Production (1,776) (23,090)
Purchases 13,190 41,933
Sales (819) (5,536)
---------- ----------
Balance, December 31, 1992 32,202 287,658
Revisions (4,908) 5,140
Extensions, discoveries and additions 4,022 90,166
Production (3,451) (35,080)
Purchases 4,372 85,850
Sales (307) (3,645)
---------- -----------
Balance, December 31, 1993 31,930 430,089
Revisions (296) (102,871)
Extensions, discoveries and additions 3,981 136,583
Production (4,366) (43,809)
Purchases 3,866 93,334
Sales (138) (2,075)
---------- ----------
Balance, December 31, 1994 34,977 511,251
========== ==========
The Company's interests in the Russian joint venture
(Permtex) and its Australian affiliate (Command) are accounted for
under the equity method. At December 31, 1994, the Company's equity
in Permtex and Command proved reserves was 8,038 MBOE and 5,931 MBOE,
respectively.
44
Proved Developed Reserves - Crude Natural
Oil Gas
------------ ------------
(MBbl) (MMcf)
December 31, 1991 9,094 136,229
============ ============
December 31, 1992 21,116 194,621
============ ============
December 31, 1993 18,032 268,349
============ ============
December 31, 1994 26,104 353,930
============ ============
Standardized Measure - December 31,
-----------------------------
1993 1994
------------ ------------
(In thousands)
Future cash inflows $ 1,272,649 $ 1,332,705
Future costs:
Production (a) (415,867) (469,947)
Development (168,510) (150,970)
------------ ------------
Future net cash flows 688,272 711,788
Undiscounted income taxes (82,202) (88,273)
------------ ------------
After tax net cash flows 606,070 623,515
10% discount factor (265,552) (261,833)
------------ ------------
Standardized measure $ 340,518 $ 361,682
============ ============
<f/n>
(a) Future production costs have been reduced by $937,000 and $1.0 million as of December 31, 1993
and 1994, respectively, to reflect the future revenues from the sale of sulphur, a by-product
of certain gas production. Sulphur is sold under a long-term contract at prevailing market prices.
(b) Standardized measure amounts at December 31, 1994, exclude the 49.9% minority interest in DelMar
Petroleum, Inc. of $3.3 million.
(c) At December 31, 1994, the Company's equity in the net present value of Permtex and Command proved
reserves was $14.2 million and $7.1 million, respectively. These amounts are not included in the
above standardized measure.
45
Changes in Standardized Measure - Year Ended December 31,
------------------------------------------
1992 1993 1994
------------ ------------ ------------
(In thousands)
Standardized measure, beginning of year $ 210,903 $ 283,572 $ 340,518
Revisions:
Prices and costs (624) (70,433)(a) (73,330)(a)
Quantities (22,760) 6,632 (a) (42,260)(a)
Development costs 6,952 16,379 (12,995)
Accretion of discount 21,090 28,357 34,052
Income taxes (10,043) (7,181) 2,195
Production rates and other (7,443) (14,281) (9,506)
----------- ------------ -----------
Net revisions (12,828) (40,527) (101,844)
Extensions, discoveries and additions 48,417 57,782 68,002
Production (50,965) (85,700) (97,330)
Future development costs incurred 33,846 67,959 99,175
Purchases (b) 62,007 60,752 55,072
Sales (c) (7,808) (3,320) (1,911)
----------- ----------- -----------
Standardized measure, end of year $ 283,572 $ 340,518 $ 361,682
=========== =========== ===========
<f/n>
(a) In 1993 and 1994, $27.7 million and $35.6 million, respectively, in revisions were included in "Prices and
Costs" rather than "Quantities," because the reduction was due to reserves being classified as uneconomic at
then current price levels.
(b) "Purchases" includes the present value at the end of the period of properties acquired during the year plus
the cash flow received on such properties during the period, rather than their estimated present value at
the time of the acquisition.
(c) "Sales" represents the present value at the beginning of the period of properties sold, less the cash flow
received on such properties during the period.
46
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON
FORM 8-K.
(a) 1. Reference is made to Item 8 on page 34.
2. Schedules otherwise required by Item 8 have been
omitted as not required or not applicable.
3. Exhibits
4.1.1 - Certificate of Incorporation of Registrant -
incorporated by reference from Exhibit 3.1 to the
Registrant's Registration Statement on Form S-4
(Registration No. 33-33455).
4.1.2 - Certificate of Amendment to Certificate of
Incorporation of Registrant filed February 9, 1990 -
incorporated by reference from Exhibit 3.1.1 to the
Registrant's Registration Statement on Form S-4
(Registration No. 33-33455).
4.1.3 - Certificate of Amendment to Certificate of
Incorporation of Registrant filed May 22, 1991 -
incorporated by reference from Exhibit 3.1.2 to the
Registrant's Registration Statement on Form S-1
(Registration No. 33-43106).
4.1.4 - Certificate of Amendment to Certificate of
Incorporation of Registrant filed May 24, 1993 -
incorporated by reference from Exhibit 3.1.5 to the
Registrant's Form 10-Q for the quarter ended June 30,
1993 (File No. 1-10509)
4.1.5 - Indenture dated as of May 1, 1994 between the
Registrant and Texas Commerce Bank National Association
relating to Registrant's 7% Convertible Subordinated
Notes due 2001.*
4.1.6 - Certificate of Designations of the Registrant's
$6.00 Convertible Exchangeable Preferred Stock -
incorporated by reference from Exhibit 3.1.5 to the
Registrant's Form 10-Q for the quarter ended June 30,
1993 (File No. 1-10509).
10.1 - Snyder Oil Corporation 1990 Stock Option Plan for
Non-Employee Directors - incorporated by reference from
Exhibit 10.4 to the Registrant's Registration Statement
on Form S-4 (Registration No. 33-33455).
10.1.1 - Amendment dated May 20, 1992 to the Registrant's
1990 Stock Plan for Non-Employee Directors - incorporated
by reference to the Registrant's Quarterly Report on Form
10-Q for the quarter ended June 30, 1993 (File No. 1-
10509).
10.2 - Registrant's Restated 1989 Stock Option Plan -
incorporated by reference to the Registrant's Quarterly
Report on Form 10-Q for the quarter ended June 30, 1992
(File No. 1-10509).
10.3 - Regstrant's Deferred Compensation Plan for Select
Employees, adopted effective June 1, 1994.*
10.4 - Registrant's Profit Sharing & Savings Plan and
Trust as amended and restated effective October 1, 1993 -
incorporated by reference to the Registrant's Quarterly
Report on Form 10-Q for the quarter ended September 30,
1993 (File No. 1-10509).
47
10.5 - Form of Indemnification Agreement - incorporated
by reference from Exhibit 10.15 to the Registrant's
Registration Statement on Form S-4 (Registration No.
33-33455).
10.6 - Form of Change in Control Protection Agreement -
incorporated by reference from Exhibit 10.11 to the
Registrant's Registration Statement on Form S-1
(Registration No. 33-43106).
10.7 - Long-term Retention and Incentive Plan and
Agreement between the Registrant and Charles A. Brown -
incorporated by reference to the Registrant's Quarterly
Report on Form 10-Q for the quarter ended June 30, 1993
(File No. 1-10509).
10.8 - Agreement dated as of April 30, 1993 between the
Registrant and Edward T. Story - incorporated by
reference from Exhibit 10.8 to the Registrant's
Annual Report on Form 10-K for the year ended
December 31, 1993 (File No. 1-10509).
10.9 - Purchase and Sale Agreement dated December 11, 1992
between Atlantic Richfield Company and Registrant -
incorporated by reference to Report on 8-K dated
December 11, 1992 (File No. 1-10509).
10.10 - Warrant dated February 8, 1994 issued by
Registrant to Union Pacific Resource Company -
incorporated by reference from Exhibit 10.10 to the
Registrant's Annual Report on Form 10-K for the
year ended December 31, 1993 (File No. 1-10509).
10.11 - Fifth Restated Credit Agreement dated as of June 30,
1994 among the Registrant and the banks party thereto
- incorporated by reference from Exhibit 10.11 to the
Registrant's Quarterly Report on Form 10-Q for the
quarter ended June 30, 1994 (File No. 1-10509).
10.12 - Master Equipment Lease Agreement dated November 3,
1994 between Registrant and NationsBank Leasing
Corporation ("NBL"), together with Equipment
Lease Schedule No. 1 dated November 3, 1994 between
Registrant and NBL and Facility Agreement dated
November 3, 1994 between Registrant and NBL.*
11.1 - Computation of Per Share Earnings.*
12 - Computation of Ratio of Earnings to Fixed Charges
and Ratio of Earnings to Combined Fixed Charges and
Preferred Stock Dividends.*
22.1 - Subsidiaries of the Registrant - incorporated by
reference from Exhibit 22.1 to the Registrant's Annual
Report on Form 10-K for the year ended December 31, 1991
(File No. 1-10509).
23.1 - Consent of Arthur Andersen LLP.*
23.2 - Consent of Netherland, Sewell & Associates, Inc.*
27 - Financial Data Schedule.*
99.1 - Report of Netherland, Sewell & Associates, Inc.
dated February 10, 1994 relating to certain of the
Registrant's property interests.*
99.2 - Report of Netherland, Sewell & Associates, Inc.
dated February 11, 1994 relating to their audit of
reserve estimates.*
(b) No reports on Form 8-K in the fourth quarter of 1994
* Filed herewith.
48
SIGNATURE
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the Registrant has duly caused this
report to be signed on its behalf by the undersigned thereunto duly
authorized.
/s/ John C. Snyder March 14, 1995
- ---------------------
John C. Snyder Director and Chairman of the Board
(Principal Executive Officer)
/s/ Thomas J. Edelman March 14, 1995
- ---------------------
Thomas J. Edelman Director and President
(Principal Financial Officer)
/s/ John A. Fanning March 14, 1995
- ---------------------
John A. Fanning Director and Executive Vice President
/s/ Roger W. Brittain March 14, 1995
- ---------------------
Roger W. Brittain Director
/s/ John A. Hill March 14, 1995
- ---------------------
John A. Hill Director
/s/ William J. Johnson March 14, 1995
- ---------------------
William J. Johnson Director
/s/ B. J. Kellenberger March 14, 1995
- ----------------------
B. J. Kellenberger Director
/s/ John H. Lichtblau March 14, 1995
- ----------------------
John H. Lichtblau Director
/s/ James E. McCormick March 14, 1995
- ----------------------
James E. McCormick Director
/s/ Alfred M. Micallef March 14, 1995
- ----------------------
Alfred M. Micallef Director
/s/ James H. Shonsey March 14, 1995
- ---------------------
James H. Shonsey Vice President - Finance
(Principal Accounting Officer)
49