SNYDER OIL CORPORATION
Annual Report on Form 10-K
December 31, 1993
PART I
ITEM 1. BUSINESS
General
Snyder Oil Corporation (the "Company") is engaged in the
development and acquisition of oil and gas properties primarily in
the Rocky Mountain region of the United States. In addition, the
Company gathers, transports, processes and markets natural gas
generally in proximity to its principal producing properties. In
1992, an international exploration and development program was
initiated. At December 31, 1993, the Company's net proved reserves
totalled 103.6 million barrels of oil equivalents ("BOE"), having a
pretax present value at constant prices of $390.4 million. The
Company's properties are located in 15 states and the Gulf of Mexico
and include 5,122 gross (2,187 net) producing wells and nine gas
transportation and processing facilities. At December 31, 1993, the
Company held undeveloped acreage totalling 539,000 gross (326,000
net) domestic acres and 4.3 million gross (3.3 million net)
international acres. Approximately 90% of the present value of
proved reserves is concentrated in five major producing areas located
in Colorado, Wyoming and Texas. The Company operates more than 2,100
wells which account for more than 90% of its developed reserves.
Headquartered in Fort Worth, Texas, the Company maintains
administrative offices in Denver and New York and has eight field
offices in Colorado, Wyoming, Texas, New Mexico and Nebraska. At
yearend 1993, the Company had 327 employees.
Between 1983 and 1990, the Company grew rapidly through a series
of acquisitions. The strategy was to accumulate a critical mass of
assets during a period of industry distress. This phase of the
Company's growth culminated in 1990 with the acquisition of a
publicly traded limited partnership formed by the Company in 1983.
This transaction added 35.9 million BOE of proved reserves. Since
then, the Company has pursued a balanced strategy of development
drilling and acquisitions, focusing on operating efficiency and
enhanced profitability through the concentration of assets in
selected geographic areas or "hubs." During this eleven-year period,
revenues rose from $2.5 million to $229.9 million, net income
increased from $.3 million to $25.7 million and cash flow grew from
$1.1 million to $84.1 million.
Development drilling in the Rockies is currently the primary
emphasis of the Company's growth strategy. In its largest area of
operations, the Wattenberg Field in the Denver-Julesburg Basin ("DJ
Basin") of Colorado, the Company drilled over 300 wells in 1993.
That brought the total number of producing wells there to over 1,400.
Aggressive cost cutting, the creative application of technology and
the advantages of expanding gas facilities in the area have, together
with acquisitions, leasing and a joint venture with Union Pacific
Resources Company ("UPRC"), brought the inventory of potential
drilling locations in the Basin to over 6,000. The Company expects
that more than half of these locations will ultimately prove
attractive to develop. The Company expects to drill approximately
500 Wattenberg wells in 1994 and to maintain that pace for the next
several years.
The Company has embarked on a program to apply the experience
gained in Wattenberg to other large scale gas development projects in
the Rockies. By the end of 1993, the Company had established two
such projects. In the East Washakie Project, which builds on
existing gas properties and facilities in southern Wyoming, the
Company holds approximately 1,200 potential drilling locations. The
Western Slope Project covers portions of the Piceance Basin of
Colorado and the Uinta Basin in northeastern Utah where the Company
controls approximately 1,000 drilling locations. Each of these
projects are expected to become significant development drilling
projects over the next few years.
During 1993, the Company made substantial progress in building
its international exploration and development effort. The
international effort is expected to eventually provide significant
growth potential for the Company. The Company's Russian venture
received government approval and is expected to commence operations
in the first half of 1994. A production sharing agreement covering
2.8 million gross acres was signed with the government of Mongolia
and the seismic program on the Tunisian concession was completed.
The Company also acquired a significant interest in a publicly traded
Australian company whose international exploration experience should
complement the Company's development and acquisition expertise.
During 1994, the Company intends to continue to emphasize
development drilling. The drilling will continue to be focused in
the DJ Basin along with increasing activity in the East Washakie and
the Western Slope projects. It is expected that the continuing
aggressive use of technology and cost saving techniques along with
the capture of downstream margins via the Company's gas facilities
will steadily improve the economics of existing properties and open
new areas of opportunities. Acquisitions will continue to be used to
strengthen the existing asset base and secure footholds in new areas.
Finally, the effort to bring a variety of international projects to
fruition will continue.
Development
General. Since 1990, development drilling has become the
primary focus of the Company's growth strategy. The Company believes
that its existing properties have extensive development drilling and
enhancement potential, primarily in the DJ Basin of Colorado, the
Washakie Basin in southern Wyoming, the Piceance and Uinta Basins in
western Colorado and Utah and in the Giddings Field in southern
Texas. The Company designs its major drilling programs to assure low
risk, synergies with its gas management operations and the potential
for continuous cost improvement. Flexibility is crucial as changing
product prices and drilling results affect economics. The Company
expects to continue to drill approximately 500 wells per year in the
Wattenberg Field, where the size of its operations enables it to
continue to refine the application of new drilling, completion and
operating techniques, and to apply the experience gained there to
establish other large scale development projects in the Rockies.
Assuming no material changes in product prices and capital
availability, the Company estimates that it will expend from $150 to
$200 million per year on development activities over the next three
to five years. Development expenditures totalled $53.7 million in
1992 and $90.2 million in 1993, primarily in the Wattenberg Field.
DJ Basin
Wattenberg Field. The Wattenberg Field is the Company's largest
base of operations, representing over 60% of total proved reserves.
Between 1991 and 1993, the Company drilled a total of 667 wells in
Wattenberg, of which 323 were drilled during 1993. At yearend, the
Company had interests in more than 1,400 producing wells, of which
over 1,100 were operated. Through complementary acquisitions, an
extensive leasing program and a major joint venture with UPRC, the
inventory of potential Wattenberg drilling locations currently
exceeds 6,000 sites. The Company expects that over half of these
sites will ultimately prove attractive to develop. The Company
expects to drill approximately 500 wells per year in the Wattenberg
Field for the foreseeable future.
At yearend 1993, the net proved reserves attributed to the
Wattenberg properties were 16.9 million barrels of oil and 229.9 Bcf
of gas. The reserves were attributable to 1,437 producing wells, 51
wells in progress, 1,102 proved undeveloped locations and
approximately 387 proved behind pipe zones. The Company expects
proved reserves to be assigned to other locations as drilling
progresses.
The Company acquired its first properties in Wattenberg during
1986. In 1990, it substantially increased its acreage position by
acquiring rights to the Codell and Niobrara formations underlying
32,985 net acres from Amoco Production Company ("Amoco") for $14.4
million. Several farm-ins from Amoco in 1992, financed primarily
through a transfer of Section 29 tax credits, resulted in earning
additional Codell/Niobrara rights as well as rights to the Sussex, J-
Sand and Dakota formations in a number of locations.
During 1993, a series of purchases added nearly 9 million BOE at
a net cost of under $3.50 per barrel as well as several pipeline and
processing facilities that complement existing facilities. In the
largest of these acquisitions, the Company paid $19.7 million and,
after an exchange of interests with a third party, acquired an
approximate 80% working interest in 153 producing wells and 284
undeveloped locations having total proved reserves estimated to
exceed 7 million BOE. A portion of the value of the transaction lay
in the large volume of undedicated gas located in close proximity to
the Company's gas lines.
In early 1994, the Company finalized an agreement with UPRC
under which the Company has the right for up to six years to drill
wells on locations of its choosing on UPRC's previously uncommitted
undeveloped acreage throughout the Wattenberg area. This transaction
substantially increased Wattenberg's undeveloped acreage inventory.
Many of the locations have the potential for improved economics
through completion in one or more of the Shannon, Sussex, J-Sand or
Dakota formations, as well as the Codell and Niobrara. During the
venture's initial three-year term, the Company is required to drill
a minimum of 120, 120 and 60 wells per year. After the initial
period, the Company can, at its option, extend the venture annually
for up to three additional years by drilling at least 150 wells per
year. There is no limit on the maximum number of wells that can be
drilled, and wells in excess of the required minimum in any year will
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 each
well that is drilled on UPRC's mineral acreage under the venture,
UPRC retains a 15% mineral owner royalty and has the option either to
receive an additional 10% royalty interest after pay-out or to
participate in the well as a 50% working interest owner. On
leasehold acreage, UPRC does not have the right to participate in the
well but will retain a royalty interest that will result in a total
royalty burden of 25%. As compensation for committing its acreage
position to the Company, UPRC was granted warrants to purchase two
million shares of the Company's common stock at a premium to market
value. See "Management's Discussion and Analysis of Financial
Condition and Results of Operations - Development, Acquisition and
Exploration."
Drilling. The Company began drilling operations in Wattenberg
in early 1991. From 1991 to December 1993, the Company expended
$149.7 million to drill 667 wells, of which 323 were drilled in 1993.
At yearend, 609 of these wells were producing, 51 were in various
stages of drilling and completion and seven were dry holes.
The size of the Wattenberg drilling program has resulted in
numerous advantages. The Company acts as operator on all its
development sites in the Wattenberg Field and much of the acreage is
held by production. As a result, the Company has significant
operational control over the timing of the development program. The
actual drilling locations and schedule are selected to minimize costs
associated with rig moves, surface facilities, location preparation
and gathering system and pipeline connections and to evaluate and
quantify incremental reserve potential across the acreage position.
The Company's success in continuing to reduce its costs of
drilling and operations, as well as applying new technology, will be
important to the full development of its undeveloped acreage in
Wattenberg. The Company has selected procedures for drilling and
completing wells that it believes maximize recoverable reserves and
economics. The Company has also been able to reduce its costs of
drilling, completing and operating wells significantly by negotiating
favorable prices with suppliers of drilling and completion services
because of the size of its drilling program. These cost reductions
allow the Company to earn an attractive rate of return even on lower
reserve wells. The reductions have been achieved by several methods.
One of the most significant is the formation of alliances with
selected vendors who work with Company personnel to improve
coordination and reduce both parties' costs. The resultant
reductions are credited wholly or in large part to the Company while
vendors' margins are maintained or increased.
In addition to cost reduction, the Company seeks to employ new
technology or to creatively apply existing technology to reduce costs
or to produce reserves that would otherwise remain unrecovered. One
example is the drilling of four or more wells from a single drilling
pad in residential areas, under reservoirs and on inaccessible
acreage.
The Codell formation, which is 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 have a high degree of predictability due to uniform
deposition and gradual transition from high to low gas/oil ratio
areas. The Company generally 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. However, the
declining production of individual wells is expected to be offset by
continuing development drilling.
During 1992 and 1993, the Company expanded 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 proportionately with porosity and thickness.
The Dakota formation lies approximately 150 feet below the J. It is
a low permeability sand occasionally naturally fractured with less
predictable commercial accumulations and varied performance results.
The Sussex formation is at average depths of 4,500 feet. The Sussex
sands were deposited as 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 in the Wattenberg Field is relatively low risk. In
addition, the Company has compiled a comprehensive geologic and
production database for approximately 12,000 wells within a 4,350
square mile area between Denver and the Wyoming border and has had
considerable success in predicting variations in thickness, porosity,
gas/oil ratios and productivity. Of the 667 wells drilled between
1991 and 1993, only seven have been dry holes. Dry holes cost an
average of only $65,000 per well. The average net cost of a
completed well approximated $193,000 during 1993 with only 30 days
usually elapsing between spud date and initial production.
The Company plans to develop the Wattenberg acreage within
seasonal agriculture constraints which has historically reduced
access to farmland between April and September. However, the
expanded inventory includes a number of non-farm drillsites, which
provides greater flexibility for summer drilling.
Marketing and Gas Management. A portion of the gas produced in
the Wattenberg Field is gathered, processed or both by third parties
under long-term contractual dedications. However, the Company's gas
facilities, including a processing plant and over 600 miles of
gathering systems have reduced costs and afforded flexibility. These
facilities, as well as gas marketing expertise, are expected to
provide greater advantages in the future as the Company capitalizes
on the cost savings and flexibility afforded by the recent expansion
of its gathering and processing facilities and assumes marketing
responsibility for gas previously committed to others.
The gas produced from the majority of the new Wattenberg wells
drilled on acreage acquired from Amoco is dedicated for the life of
the lease to at Amoco's Wattenberg gas processing plant. If Amoco
were to release the Company from supplying gas to its plant for any
reason, including a shut-down of the plant, such release would have
an short-term adverse impact on the Company. The Company has
expanded its processing facilities in Wattenberg in order to process
Company and third party gas that is not dedicated to Amoco. The
Company intends to continue to expand its facilities during 1994 to
handle additional gas developed though continued drilling activity.
These facilities will enable the Company to partially mitigate the
effects of frequent shut-downs at the Amoco plant. See "Gas
Management - Colorado Facilities."
In 1993, the Company extended its gathering system to collect
gas from the Company and third parties, in order to control or reduce
gathering costs and avoid curtailments in production caused by high
line pressure on existing gathering systems. This expansion, called
the Enterprise system, complements the processing and other gathering
facilities in the area. While future gathering rates on the systems
owned by others are expected to rise, the majority of the Company's
gas will be gathered on its own gathering system. To the extent that
a portion of the Company's gas remains on the KN Energy, Inc. ("KN")
Wattenberg gathering system, the largest gathering system in the
area, the applicable gathering rate is covered by an agreement
between Amoco and KN which provides some protection from future rate
increases. See "Gas Management - Colorado Facilities."
Through yearend, Amoco had been responsible for marketing all
residue gas and liquids attributable to the Company's gas processed
through its Wattenberg plant. Historically, this arrangement has
provided for average prices in excess of spot due to participation in
certain fixed price contracts, many of which are expected to expire
over the next two years. Under the contract with Amoco, the Company
elected to market substantially all its gas and liquid products
processed through the Wattenberg plant effective January 1, 1994.
The Company believes that it can obtain pricing comparable to that
which would have been obtainable through Amoco. Oil is sold at the
average of the posted prices of Amoco, Total and Conoco in northeast
Colorado.
Cheyenne. During 1993, 29 wells were placed on stream in
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 54 successful wells and six 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 61 wells in this area that produce from the
Niobrara formation and plans to drill approximately 20 additional
wells during 1994.
East Washakie
During 1993, the Company initiated a major project to apply the
cost-cutting and improved drilling and completion techniques learned
in Wattenberg to develop fluvial Mesaverde sands in the eastern
Washakie Basin. An eleven well pilot project was completed in 1993
to validate reduced cost levels and test drilling and completion
techniques. A second drilling program is being initiated in March
1994. After final evaluation of the drilling, the Company may
initiate a large scale drilling program in this area upon completion
of a required environmental impact statement. The environmental
impact statement was filed in October 1993, and completion is
expected in the second half of 1994. Depending on the timing of
environmental clearance and continued evaluation of drilling results,
the Company expects to drill up to 60 wells in East Washakie during
1994.
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. See "Properties - Significant
Properties" and "Gas Management - Wyoming Properties." The Company
currently operates 128 wells in this area and has approximately 1,200
potential drilling locations, 98 of which were classified as proven
at yearend 1993. More than half of the potential locations could
ultimately prove attractive to develop. The Company currently holds
interests in 95,000 gross (76,000 net) undeveloped acres in the
Basin. This includes 36,000 gross (32,000 net) undeveloped acres
added during 1993.
Western Slope
During 1993, the Company established a sizable position in the
Piceance Basin on the Western Slope of Colorado and in the Uinta
Basin in northeastern Utah. The Company formed the 53,000 acre
Hunter Mesa Unit in the southeast corner of the Piceance Basin.
Through purchases and farmouts, the Company obtained a majority
interest and acts as unit operator. Immediately adjacent to the
Hunter Mesa Unit, a 100% working interest was purchased in the 26,000
acre Divide Creek Unit for $6.2 million. The acquisition of this
Unit, which has six wells producing from the Mesaverde and Cameo Coal
formations, added 17.6 Bcf of proved gas reserves as well as an
established operating base and access to gas transportation. Near
yearend, the Company also purchased interests in 122 producing wells,
29 non-producing wells and 69 proved undeveloped locations. In total,
this purchase included 55,000 net acres in various fields in the
Piceance and Uinta Basins.
Through these purchases, farmouts and a leasing program, the
Company currently holds over 1,000 potential drilling locations, of
which 40% could ultimately prove be attractive to develop. Of these
locations, 101 were classified as proven at yearend 1993. The
development of the Upper Mesaverde sands in the Piceance Basin began
with the spudding of the initial test well near the end of 1993. The
development will continue with a 10 well test program during 1994 to
validate cost reductions and improved recovery techniques. If
successful, the Company may drill up to 30 wells in 1994 and
approximately 100 wells per year thereafter. A key issue in the
Piceance Basin is the ability to profitably transport production to
market. The Company is exploring options for gathering and
transporting future gas production, including the possibility of
constructing Company owned facilities.
Other Development
At the end of 1992, the Company acquired interests in four large
producing fields in central Wyoming from a major oil company at a
cost of $56.1 million. Two of the fields, the Hamilton Dome and
Riverton Dome Fields, are operated by the Company. During 1993, the
Company evaluated opportunities in the fields and instituted programs
to enhance production in the latter part of the year. In the Hamilton
Dome Field, improvement of the water injection system and completion
of two new wells increased daily production 8% above the levels
projected at the time of the acquisition. A third well should be
completed in the second quarter of 1994. In the Riverton Dome Field,
workovers and recompletions increased daily production over 10% above
the levels projected at the time of the acquisition. Additional
workovers and development drilling are scheduled for both fields
during 1994. The Company is attempting to work with the major oil
companies that operate the other two fields purchased, both of which
are producing slightly below acquisition projections.
The Company operates the Adair waterflood property in Gaines
County, Texas, which it purchased in September 1991. Initial
development of the Adair Unit in 1992 cost approximately $1.7 million
net to the Company. Based on production response from the initial
phase of development, the Company spent an additional $.9 million in
1993 to conduct a pilot program which reduced well spacing on a
portion of the Unit. This program increased the unit production from
150 barrels per day to 260 barrels per day. The Company plans to
spend an additional $1.1 million to implement an infill development
program throughout the Unit. Once fully developed, the Adair Unit is
expected to contain 52 wells operated by the Company.
In the Giddings Field in Southeast Texas, the Company has
undertaken a horizontal drilling program to further exploit exising
properties in the area. During 1993, the Company spent $2.2 million
to re-enter or drill 10 wells, of which nine were completed and one
abandoned. The Company is encouraged by the results to date and
plans to increase its expenditures in the field during 1994. At
yearend, 25 locations were classified as having proved undeveloped
reserves.
Acquisition Program
The Company believes that acquisitions continue to be an
attractive method of increasing its reserve base and cash flow. In
its acquisition efforts, the Company plans to focus on purchasing
properties that strengthen its strategic position and complement its
large-scale gas development projects in the Rockies, as well as
provide opportunities to establish meaningful positions in new areas.
From 1983 through 1993 the Company, on behalf of itself, its
affiliates and other investors, purchased oil and gas properties and
related assets with an aggregate cost of nearly $650 million. The
Company actively seeks to acquire incremental interests in existing
properties, acreage with development potential, gas gathering,
transportation and processing facilities and related assets,
particularly in proximity to existing properties. Purchases of
incremental interests or adjacent properties are generally small in
size but in aggregate represent a sizeable opportunity that is
relatively easy to pursue.
Due to its rate of return requirements and the high cost of
pursuing potential acquisitions, the Company generally prefers
negotiated transactions to auctions. Complex deals involving legal,
financial or operational difficulties have frequently permitted
purchase of assets at favorable prices. Past acquisitions of
corporations laid the groundwork for the Wattenberg hub, and may in
the future provide opportunities to expand in other areas.
Acquisitions of incremental interests are being given particular
emphasis to take advantage of systems and operational knowledge
already in place. The Company has extensive experience in completing
numerous types of acquisitions using varied financing sources in
addition to internal cash flow.
During 1993 domestic acquisitions having a total cost of $51.0
million were completed, primarily to strengthen Wattenberg and
establish two new projects, each of which has the potential to
develop into a large scale gas development program. In Wattenberg a
series of purchases added nearly 9 million BOE of proved reserves at
a net cost of under $3.50 per barrel as well as several pipeline and
processing facilities that complement the Company's existing
gathering systems. In the largest of these acquisitions, the Company
paid $19.7 million and, after an exchange of interests with a third
party, acquired an approximate 80% working interest in 153 producing
wells and 284 undeveloped locations having total proved reserves
estimated to exceed 7 million BOE. A portion of the value of the
transaction lay in the large volume of undedicated gas located in
close proximity to the Company's gas lines.
In the Washakie Basin, the Company expended over $7.8 million to
acquire a 25% incremental interest in its Barrel Springs properties
and interests in 44 producing wells and 7 undeveloped locations, as
well as a gathering system that expands the existing gathering
infrastructure in the area. These acquisitions added approximately
3.6 million BOE of proved reserves and, together with an active
leasing program, formed the basis for the East Washakie Project, the
Company's second operating hub in the Rockies. See "Development -
East Washakie Project."
Through three purchases, farmouts and leasing, the Company
established a substantial position in the Piceance and Uinta Basins
during 1993, forming the foundation of the Western Slope Project, a
third gas development hub in the Rockies. A $6.2 million purchase
gave the Company a 100% working interest in the 26,000 acre Divide
Creek Unit in the southeast Piceance Basin. The Company also formed
the adjacent 53,000 acre Hunter Mesa Unit and through purchases and
farmouts obtained a majority working interest position and became
unit operator. Near yearend the Company also acquired interests in
122 producing wells, 29 non-producing wells and 69 undeveloped
locations in various fields in the Uinta and Piceance Basins. See
"Development - Western Slope Project."
The following table summarizes acquisition activity since 1983:
<TABLE>
<CAPTION>
Purchase Price
Year Major Assets Acquired Company Affiliates Total
<S> <C> <C> <C> <C>
1983 Louisiana gas pipeline $ 3.5 $ - $3.5
1984 Various producing properties 27.8 - 27.8
1985 Utah, Texas and Oklahoma properties 56.1 - 56.1
1986 Colorado and Wyoming properties 61.8 15.4 77.2
1987 Mississippi and Colorado properties, Roggen
gas plant, Wyoming gas facilities 71.0 - 71.0
1988 Various producing properties 33.8 18.5 52.3
1989 Various producing properties 12.3 56.9 69.2
1990 Wattenberg properties, incremental interests 161.2 (a) - 161.2
1991 Waterflood properties, incremental interests 9.9 - 9.9
1992 Wyoming properties, incremental interests 63.6 - 63.6
1993 Colorado and Wyoming properties,
incremental interests, acreage 51.0 - 51.0
Total $ 552.0 $ 90.8 $ 637.8
<FN>
(a) Includes the acquisition of Snyder Oil Partners L.P., a publicly traded
partnership formed by the Company in 1983.
</TABLE>
Gas Management
General. The Company expanded its gas gathering and
processing capacity during 1993 with the construction of the
Enterprise system and expansion of the Roggen plant in Wattenberg, as
well as the acquisition of additional gas facilities in Wattenberg
and in Wyoming. By yearend, operated processing capacity had
increased to more than 80 MMcf per day and gathering system capacity
was increased to more than 200 MMcf per day, while marketed net
volumes reached 100 MMcf per day. The gas management unit
complements the Company's development and acquisition activities by
providing additional cash flow and enhancing return. The segment is
also increasingly profitable in its own right. During 1993,
operating cash flow increased by approximately 23% to $10 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 processing plant, and a number of minor facilities. By
yearend 1993, the Roggen plant capacity had reached 60 MMcf per day.
During the fourth quarter of 1993, average throughput had reached 54
MMcf per day. The expanded plant is expected to process gas from
currently undeveloped locations, new third party sources and
permanently released locations on acreage acquired from Amoco, plus
additional gas from current suppliers. Gas developed through the UPRC
joint venture is not dedicated to a processing plant and will
significantly increase furture volumes of gas available to be
processed in the Company's facilities.
At the Roggen plant, 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. During 1993, CIG
constructed approximately 14 miles of pipeline from the Roggen plant
to expand residue capacity. Residue capacity is currently believed
to be capable of handling 50 MMcf per day under normal conditions.
A liquids line permits the direct sale of Roggen's liquids products
through an Amoco line to the major interchange at Conway, Kansas. In
addition, Phillips Petroleum began reactivation of an old
interconnect, which should be operational by the end of the second
quarter of 1994, which will connect the Roggen plant to the Phillips
Powder River liquids pipeline.
The Company's Wattenberg gathering systems include over 600
miles of pipeline which collect, compress and deliver gas from over
1,400 wells to the Roggen plant. During 1993, 443 new wells,
including 335 Company wells, were connected to these pipelines. The
Company acquired a pipeline which expands its gathering potential to
the north and which could be converted to a residue line allowing for
the delivery of residue gas from the tailgate of Roggen to the
Williams Natural Gas System. The Company also constructed a nine
mile 16" pipeline loop on the western portion of the system, which
came on line in October 1993, to provide pressure relief in the area
and additional capacity for further development in the area. Gas
from wells in which the Company owns an interest currently accounts
for approximately 86% of the gathered volumes.
The Company earns fees from transportation on its gathering
lines and processing at the Roggen plant under two arrangements.
Most gas is gathered and processed under arrangements whereby the
Company retains for its own use or sale a significant part of the
liquids products recovered at the plants as well as a portion of the
residue gas. The remainder of the gas is transported and processed
for a fixed amount per unit.
During 1993, the Company substantially expanded its
gathering system. This expansion is known as the Enterprise system.
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 ("CDP's") plus several
newly drilled wells. Approximately eight miles of lower pressure 20"
main trunk pipeline and ten miles of laterals connecting 11 CDP's
were added during 1993, along with additional compression facilities,
at a cost of $9.1 million. The Enterprise system has the capacity to
deliver 75 MMcf per day to the Amoco Wattenberg plant.
In conjunction with the construction of the Enterprise
system, CIG constructed a high pressure 16" line which connects
Enterprise to an existing CIG 16" pipeline which redelivers the gas
to Amoco's Wattenberg plant. Prior to completion of the CIG line in
May 1993, a portion of the Company's Wattenberg gas connected to
Enterprise was delivered and processed at the Roggen plant.
The Company has negotiated a transportation arrangement with
CIG that, in conjunction with the gathering fees to be charged on the
Enterprise system, allows the delivery of gas to the Amoco Wattenberg
plant at a favorable rate. In addition to containing current and
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 Roggen plant 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 Roggen plant and, to a
lesser degree, two other plants in the area, enabled the Company to
produce significant volumes that would have otherwise been curtailed.
Given the continued expansion of the Company's drilling
program in 1994 and beyond and the potential for third party
connections, the Company is continuing to explore opportunities to
expand its Wattenberg gas facilities. Subsequent to yearend, the
decision was made to double the Company's processing capacity through
the construction of a new plant on the west side of the field. The
new plant is scheduled to be operational in late 1994.
Wyoming Facilities. The Company operates two pipeline
systems in Wyoming that enhance its ability to market gas produced
from its Carbon County properties. Wyoming Gathering and Production
Company ("WYGAP") gathers gas produced from 53 operated wells in the
Barrel Springs Unit. The system has a capacity of 26 MMcf per day.
Throughput averaged 10 MMcf and 14 MMcf per day during 1992 and 1993.
WYGAP delivers gas to Western Transmission Corporation ("Westrans"),
a Company-owned interstate pipeline system which operates under FERC
jurisdiction. At the beginning of 1993, the Company assumed
operations of CIG's Carbon County Blue Gap gathering system pursuant
to a lease. The Company has exercised an option to acquire the
system subject to regulatory approval. The Company also purchased
Blue Gap gathering facilities formerly owned by Williams Field
Services. Both systems extend the Company's transportation
capabilities to the south.
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 which was completed in
February 1992 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 90% of its volumes, Westrans
transports volumes from other operated wells and third parties. The
capacity of Westrans is 65 MMcf per day. Throughput volumes
generally vary from 13 to 20 MMcf per day. Daily throughput averaged
15 MMcf during 1992 and 1993. If the planned acceleration of
drilling in East Washakie occurs, volumes of gas on the Company's gas
pipeline in the area may be substantially increased. As the East
Washakie project progresses, the Company expects to further expand
its gathering network in the area.
Other Facilities. The Company expanded its gathering system
in southern Nebraska during 1993 to gather gas produced from newly
developed Cheyenne County properties for delivery to various markets
accessible through KN. The Cheyenne system includes 9.5 miles of 4"
to 6" trunkline and 6 miles of 3" lateral gathering lines. During
the fourth quarter of 1993, throughput averaged 3 MMcf per day of gas
from 60 producing wells. Included in the December 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 8 MMcf per day from the 28 producing wells in the
Riverton Dome Field.
In conjunction with the growing level of acquisition and
development activity in the Piceance and Uinta Basins, the Company is
actively exploring alternatives to gather and transport future gas
production in those areas. In this connection, the possibility of
constructing a Company-owned gathering and transportation line is
being investigated. Traditionally, the lack of sufficient pipeline
capacity has been a major deterrent to development in the Piceance
Basin.
International Activities
During 1993, the Company made significant progress in
building its international exploration and development effort into a
vehicle having significant future growth potential. During the year,
the Company's Russian venture received government approval. The
Company signed a production sharing agreement with the government of
Mongolia and completed its seismic work program in Tunisia. Finally,
the Company acquired a 42.8% interest in a publicly traded Australian
exploration company that has significant international exploration
experience and an extensive inventory of projects that greatly
enhance the Company's international efforts.
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 equity 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 the Company's
international operations. During 1993, the Company purchased from
Edward T. Story, President of SOCO International, the 10% of SOCO
International held by him and canceled Mr. Story's option to purchase
an additional 20% of the company. In connection with the purchase,
the Company granted Mr. Story an option to purchase 10% of SOCO
International through April 1998 for $600,000. The option price is
subject to adjustment, in certain circumstances.
Russian Joint Venture. In early 1993, the Company formed
Permtex, a joint drilling venture with Permneft, a Russian oil and
gas company, to develop four major proven oil fields located in the
Volga-Urals Basin of the Perm Region of Russia, approximately 800
miles east of Moscow. During 1993, Permtex was registered by the
Russian authorities, representing governmental approval of the terms
of the joint venture and authorization for Permtex to commence
business. In early 1994, the Company executed a finance and insurance
protocol with the Overseas Private Investment Corporation, an agency
of the United States government that provides financing and political
risk insurance for American investment in developing countries,
related to the financing of Permtex.
Permtex holds exploration and development rights to over
300,000 acres in the Volga-Urals Basin. The contract area contains
four major fields and four minor fields as well as a number of
prospects. The Company estimates that the four major fields could
ultimately produce 115 million barrels of oil. The major fields have
been delineated through 45 previously drilled wells, none of which
had been placed on production as of yearend 1993. It is anticipated
that 25 of the existing wells will be placed on production, of which
four should go on stream in the first half of 1994, and that 400
additional development wells will be drilled over the next five to
ten years. The joint venture will primarily utilize Russian
personnel and equipment and Western technology under joint
Russian/American management.
As of March 1, 1994, the Company holds a 28.1% interest in
Permtex, after giving effect to the subscriptions by each of Command
Petroleum Holdings NL ("Command"), the Company's Australian
affiliate, and Holland Sea Search NV ("HSSH"), a Dutch affiliate of
Command, to purchase 6.25% interests in Permtex. Recently, a major
Japanese trading company has also committed to purchase a 10 to 20%
interest in Permtex, which would reduce the Company's interest to
20.6% if the full amount is purchased.
Command Petroleum Holdings NL. In May 1993, the Company
purchased 42.8% of the outstanding shares of Command for
approximately $18.2 million. At the time of the purchase, Thomas J.
Edelman, President of the Company, Edward T. Story, President of SOCO
International, and two other designees were elected to Command's
eight-person board of directors. Command is an exploration and
production company based in Sydney, Australia and listed on the
Australian Stock Exchange. At yearend 1993, Command had working
capital of $35 million and no debt. Its current market
capitalization approximates US$150 million. Command currently holds
interests in more than 20 exploration permits and production licenses
primarily in the Southwestern Pacific Rim including Australia and
Papua New Guinea. Until recently, Command held a 28.7% interest in
HSSH, a publicly traded Dutch exploration and production company
whose primary assets are an interest in the North Sea's Markham gas
field. After yearend 1993, Command increased its position in HSSH to
nearly 48%. Recently, Command purchased a 6.25% interest in Permtex,
acquired an interest in an offshore Tunisian permit operated by
Marathon and acquired an 11.4% interest in the East Shabwa Contract
Area in Yemen. Command funded the expenditures with a portion of a
$16.4 million privately placed equity offering which reduced the
Company's ownership to 35.7%. If as expected, all of Command's
warrants expiring in November 1994 are exercised, the Company's
ownership would be decreased to 29.6%.
The Company believes that Command's exploration expertise,
experienced technical staff and inventory of prospects complement the
Company's acquisition and development expertise and position the
Company to play a larger role in overseas development of oil and gas
reserves. In addition, Command and HSSH provide access to
international capital markets which could provide additional sources
of financing for international projects.
Mongolia. The Company further expanded its international
efforts by entering into a production sharing agreement with Mongol
Petroleum Company, the national oil company of Mongolia. The Company
believes this agreement is the first such contract ever awarded by
Mongolia. The agreement covers 11,400 square kilometers, or
approximately 2.8 million gross acres in the Tamstag Basin of
northeastern Mongolia. In addition, the Company received a right of
first refusal from Mongol Petroleum for the adjacent block which
covers 11,130 square kilometers. As a consequence, the Company
controls over 5 million acres in this basin which, although
previously unexplored and remote from existing markets, is highly
prospective. These concessions offset the Hailar Basin of China, a
portion of which is included in the China National Petroleum
Corporation's round of invitations for bidding in 1994. During 1993,
the Company initiated seismic work to broadly define the subsurface.
This work is expected to continue into 1995 at relatively modest
cost.
Tunisia. During 1993 the Company completed its 400
kilometer seismic acquisition program in the Fejaj Permit area of
central Tunisia. The permit area encompasses approximately 1.2
million gross acres and is predominately onshore, with a small
portion extending into the Gulf of Gabes. After the Company
integrates the newly acquired seismic work with over 1,400 kilometers
of reprocessed data and extensive geological field information, the
Company will seek industry partners for a 1995 exploratory 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, 1993.
(Dollars in thousands, except price and per barrel expenses)
<TABLE>
<CAPTION>
December 31,
1989 1990 1991 1992 1993
<S> <C> <C> <C> <C> <C>
Production
Oil (MBbl) 277 1,049 1,487 1,776 3,451
Gas (MMcf) 4,027 12,769 18,382 23,090 35,080
MBOE (c) 948 3,497 4,937 5,989 9,297
Revenues
Oil production $ 5,069 $ 24,806 $ 30,667 $ 33,512 $ 53,174
Gas production (a) 7,410 24,997 34,677 43,851 71,467
Subtotal 12,479 49,803 65,344 77,363 124,641
Transportation, processing
and marketing 10,885 29,442 21,459 38,611 94,839
Interest and other 3,179 2,928 5,698 4,198 10,405
Total $ 26,543 $ 82,173 $ 92,501 $120,172 $229,885
Operating expenses
Production $ 4,930 $ 18,088 $ 24,882 $ 28,057 $ 44,901
Transportation, processing
and marketing 9,168 24,103 14,202 30,469 84,840
$ 14,098 $ 42,191 $ 39,084 $ 58,526 $129,741
Gross margin $ 12,445 $ 39,982 $ 53,417 $ 61,646 $100,144
Production data
Average sales price (b)
Oil (Bbl) $ 18.30 $ 23.65 $ 20.62 $ 18.87 $ 15.41
Gas (Mcf) (a) (c) 1.65 1.69 1.68 1.74 1.94
BOE (c) 12.97 14.18 13.24 12.92 13.41
Average operating expense/BOE$ 5.20 $ 5.17 $ 5.04 $ 4.68 $ 4.83
<FN>
(a) Sales of natural gas liquids are included in gas revenues. Gas revenues for the year ended
December 31, 1989 and 1990 include nonrecurring receipts of $183,000 and $219,000,
respectively, in settlement of contract claims, which have been excluded from average
sales price computations.
(b) The Company estimates that its composite net wellhead prices at December 31, 1993 were
approximately $2.27 per Mcf of gas and $12.54 per barrel of oil.
(c) Gas production is converted to oil equivalents at the rate of 6 Mcf per barrel, except
for Thomasville Field gas which through 1992 was converted based on its price equivalency
to the Company's other gas. Average gas prices exclude Thomasville production.
</TABLE>
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.
<TABLE>
<CAPTION>
1991 1992 1993
<S> <C> <C> <C>
Development wells
Productive
Gross 143.0 241.0 384.0
Net 117.2 207.5 318.0
Dry
Gross 3.0 6.0 16.0
Net 2.8 2.7 8.8
Exploratory wells
Productive
Gross 5.0 - -
Net 1.8 - -
Dry
Gross 5.0 - -
Net 1.5 - -
(/table>
As of December 31, 1993, the Company had 61 gross (50.9 net)
development wells in progress. Between yearend and February 28,
1994, the Company spudded 118 wells. At that date 135 gross (116.7
net) wells, including wells in progress at yearend, had been
completed, two wells (1.5 net) had been abandoned and 42 gross (36.3
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 follows:
</TABLE>
<TABLE>
<CAPTION>
Operated
Location Wells
<S> <C>
Evans, Colorado 1,124
Rifle, Colorado 9
Dalton, Nebraska 60
Farmington, New Mexico 196
Fort Worth, Texas 175(a)
Giddings, Texas 73
Midland, Texas 163
Baggs, Wyoming 235
Hamilton Dome, Wyoming 141
Total 2,176
<FN>
(a) Pennsylvania wells for which field activities are subcontracted.
</TABLE>
As operator, the Company charges overhead fees to all working
interest owners according to the applicable operating agreements. As
of the end of 1991, 1992 and 1993, respectively, the Company operated
1,442, 1,745 and 2,176 wells. The Company received overhead
reimbursements for operations and drilling of $10.1 million,
$12.9 million and $15.5 million during 1991, 1992 and 1993,
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
refiners and others having pipeline facilities near its properties.
Where there is no access to gathering systems, crude oil is trucked
to storage facilities. In 1992 and 1993, Amoco accounted for
approximately 27% and 12% of revenues, respectively, as the result of
the contractual dedication of a portion of the Company's natural gas
and natural gas liquids produced from certain of its Wattenberg
acreage. The Company exercised its option to release its natural gas
and natural gas liquids and began marketing its production beginning
January 1, 1994. See "Development - D J Basin - Wattenberg Field."
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.
In addition to marketing a significant portion of its own gas,
in 1992 the Company initiated an effort to supplement its cash flow
through the purchase and resale of gas owned by third parties. Gross
margins during 1992 and 1993 from third party marketing activities
was $.6 million and $1.2 million, respectively, as average third
party volumes increased from 58.7 to 89.9 MMcf per day. The Company
expects, to continue increasing its role in third party gas
marketing.
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
facility has firm fifteen-year sales agreements with a utility
company for electricity and with a tire manufacturer for steam. The
effect of this contract depends on market prices for gas and its
choice of alternative sources of gas (including the spot market) to
meet its supply commitments. Gross margin generated from the
contract was approximately $1.5 million for both 1991 and 1992. A
contractual limitation of the contract sales price and rising gas
purchase cost, resulted in a net loss of $267,000 on the contract
during 1993. At present gas price levels, the Company foresees
continued negative or breakeven margins for this contract through
July 1994. At that time, the share of the sales price minimum
attributable to gas will increase from 45% to 65% and margins should
improve.
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
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
will be implemented on a pipeline-by-pipeline basis through
negotiations in individual pipeline proceedings. Although Order 636
does not regulate any of the Company's material gas operations, FERC
has stated that Order 636 is intended to foster increased competition
in all phases of the natural gas industry. Industry commentators
have predicted profound effects (which vary from commentator to
commentator) on various segments of the industry as a result of this
competition. Order 636 is being implemented on a pipeline-by-pipeline
basis through negotiated settlements in independent pipeline service
restructuring proceedings designed specifically to "unbundle" the
pipelines' services (e.g., transportation, sales and storage) so that
producers, marketers and end-users of natural gas may secure services
from the most economical source.
The restructuring proceedings continued throughout 1993, with
the majority of pipelines having received FERC orders approving their
compliance filings, subject to conditions, so that the 1993-1994
winter heating season is the first period during which FERC Order 636
procedures have been operative. To date, management of the Company
believes the Order 636 procedures have not had any significant effect
on the Company. Because the restructuring involved wholesale changes
in the operating procedures of pipelines, however, the Company is not
able to predict the long term effect of the new procedures. Also, the
Order and many of the pipeline procedures adopted in response
thereto, will be subject to lengthy administrative and judicial
review, which may result in procedures that are significantly
different from those currently in effect.
When it issued Order 636, FERC recognized that in an effort to
enable non-pipeline gas sellers to compete more effectively with
pipelines, it should not allow pipelines to be penalized as
competitors by any of their existing contracts which required the
pipelines to pay above-market prices for natural gas. FERC
recognized that it did not have authority to nullify these contracts,
and instead encouraged pipelines and producers to negotiate in good
faith to terminate or amend these contracts to align them with market
conditions. During 1993, the Company renegotiated its contract with
Southern Natural Gas Company ("SONAT") under which SONAT had
purchased the Company's gas from the Thomasville Field at prices
substantially above market value. As a result of the renegotiation,
the Company received a $14 million payment and beginning January 1,
1994 the Company will receive a price that, while somewhat above
current prices, will be substantially lower that the average 1993
contract price of $12.16 per Mcf.
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.
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.
During the current session of the Colorado legislature, the
Colorado Department of Natural Resources has prepared a bill ("SB
177"), which gives additional authority to the Colorado Oil and Gas
Conservation Commission ("COGCC") in their regulation of the oil and
gas industry. The bill has currently passed the Senate Agricultural
Committee and will be presented to the full legislature in March.
This bill is very similar to legislation proposed during the 1993
legislature session. Legislation of this type could increase the
cost of the Company's operations and erode the traditional rights of
the oil and gas industry in Colorado to make reasonable use of the
surface to conduct drilling and development activities. In addition,
a coalition of oil and gas industry and agriculture are working on a
Surface Damage Compensation bill. The group will try to have the
bill sponsored and passed in this session of the legislature. This
bill, if enacted, would also increase the Company's cost of doing
business.
Also at the statewide level, the surface owner groups have
indicated that they may seek a statewide ballot initiative to
overturn the traditional real property concept of the dominance of
the mineral estate and put the surface estate as the dominate estate.
These same groups are also active at the local level, 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 has increased following a recent 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 COGCC, but that they could limit those
activities under their land use authority. Under these decisions,
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. Although numerous changes are expected in light of the
recently adopted and pending regulatory initiatives, management is
not able to predict the final form of these initiatives or their
impact on the Company.
In December 1992, COGCC instituted a review of "slimhole"
completions (i.e., completions using pipe having a diameter of less
than 4-1/2") and expressed concerns that slimhole completions could
result in the loss of reserves, cause environmental damage and result
in increased abandonment costs to the State. Hearings on the matter
were scheduled for February 1994. Following meetings of
representatives of the Company and other major Wattenberg operators
with the COGCC at which the operators discussed slimhole techniques,
the hearings were postponed until May. Although the Company believes
that slimhole completion is a safe and economically viable completion
method, the Company is unable to predict what, if any regulations
might be adopted by the COGCC or their effect on the Company.
Regulations that imposed significant restrictions on slimhole
completions, however, could increase the cost of the Company's
drilling operations and could cause certain locations to become
uneconomic.
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 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.
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 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.
Officers
In early 1993, the Company restructured its organization,
dividing operations into four separate business units and
decentralized a number of staff functions. Each business unit has
bottom line responsibility in order to reduce administrative costs,
increase efficiency and increase focus on enhancing asset value. The
flatter organization structure should also assist the Company in
capitalizing on opportunities that may result in significant growth,
including acquisitions and additional enhancement projects.
Listed below are the officers and a summary of their recent
business experience.
<TABLE>
<CAPTION>
Name Position
<S> <C>
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
Robert J. Clark Vice President - Gas Management; President, SOCO Gas Systems Inc.
Gary R. Haefele Vice President - DJ Basin
Peter E. Lorenzen Vice President - General Counsel and Secretary
James H. Shonsey, Jr. Vice President - Corporate Services and Controller
Edward T. Story Vice President - International; President, SOCO International, Inc.
Diana K. Ten Eyck Vice President - Investor Relations
Rodney L. Waller Vice President - Special Projects
Richard A. Wollin Vice President - Asset Rationalization
</TABLE>
John C. Snyder (52), 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 Fort Worth Country Day School.
Thomas J. Edelman (43), 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 Holdings NL, 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 and Total Energy Services
Corporation.
John A. Fanning (54), 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 (47), 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.
Steven M. Burr (37), 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.
Robert J. Clark (49), President of SOCO Gas Systems Inc. and
Vice President - Gas Management of the Company, joined the Company in
1988. From 1985 to 1988, Mr. Clark was Vice President - Natural Gas
for Ladd Petroleum Corporation, a subsidiary of General Electric
Company. From 1967 to 1985, Mr. Clark served in various management
capacities with Northern Illinois Gas Company, NICOR Exploration
Company and Reliance Pipeline Company, all of which were subsidiaries
of NICOR, Inc. Mr. Clark received his Bachelor of Science Degree in
Accounting from Bradley University and his Masters Degree in Business
Administration from Northern Illinois University.
Gary R. Haefele (51), Vice President - DJ Basin, rejoined the
Company in 1993. Mr. Haefele was a consultant to the Company in
1992. From 1981 to 1991, Mr. Haefele worked for the Company as
Senior Vice President, Production. Mr. Haefele served as Vice
President, Engineering and International Operations for Hamilton
Brothers from 1979 to 1981. Mr. Haefele held various production and
reservoir engineering positions for Chevron from 1965 to 1979. Mr.
Haefele has a Bachelor of Science Degree in Petroleum Engineering
from the University of Wyoming.
Peter E. Lorenzen (44), 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 Johns Hopkins
University.
James H. Shonsey (42), Vice President - Controller, 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.
Edward T. Story (50), President of SOCO International, Inc. and
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 Holdings NL, 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 (47), 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.
Rodney L. Waller (44), 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 (41), Vice President - Asset Rationalization,
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 director of Oxford Consolidated, Inc., a public oil and
gas company, and a member of the Minnesota Bar Association.
ITEM 2. PROPERTIES
General
The Company's reserves are concentrated in several major
producing areas. These include the Wattenberg Field in Colorado,
central and southern Wyoming, the Piceance and Uinta Basins in the
Western Slope of Colorado and Utah, the Giddings area in South Texas,
the Spraberry Trend in West Texas, waterflood units in Texas, and the
Appalachian Basin in eastern Ohio and Pennsylvania. See "Significant
Properties."
At December 31, 1993, the Company had interests in 5,122 gross
(2,187 net) producing oil and gas wells located in 15 states and in
the Gulf of Mexico. As of December 31, 1993, estimated proved
reserves totalled 31.9 million barrels of oil and 430.1 Bcf of gas.
In addition to its oil and gas reserves, the Company holds interests
in nine gas transportation and processing facilities. See "Business
- - Gas Management."
Proved Reserves
The following table sets forth estimated yearend proved
reserves for the three years ended December 31, 1993.
<TABLE>
<CAPTION>
December 31,
1991 1992 1993
<S> <C> <C> <C>
Crude oil and liquids (MBbl)
Developed 9,094 21,116 18,032
Undeveloped 10,584 11,086 13,898
Total 19,678 32,202 31,930
Natural gas (MMcf)
Developed 136,229 194,621 268,349
Undeveloped 110,940 93,037 161,740
Total 247,169 287,658 430,089
Total MBOE (a) 66,641 84,393 103,612
<FN>
(a) Natural gas reserves are converted to oil equivalents at the rate of 6 Mcf per barrel, except
Thomasville Field gas reserves, which prior to 1993 were converted based on their price equivalency
to the Company's other gas.
</TABLE>
The following table sets forth pretax future net revenues
from the production of proved reserves and the Pretax PW10% Value of
such revenues.
<TABLE>
<CAPTION>
(In thousands) December 31, 1993
Developed Undeveloped(a) Total
<S> <C> <C> <C>
1994 $ 81,401 $(24,109) $ 57,292
1995 59,121 1,220 60,641
1996 47,148 8,472 55,620
Remainder 286,510 228,209 514,719
Total $474,480 $213,792 $688,272
Pretax PW10% Value $297,638 $ 92,771 $390,409 (b)
<FN>
(a) Net of estimated capital costs, including estimated costs of $68.9 during 1994.
(b) The after tax PW10% value of proved reserves totalled $340.5 million at yearend 1993.
</TABLE>
The quantities and values in the preceding tables are based on
prices in effect at December 31, 1993, averaging $12.54 per barrel of
oil and $2.27 per Mcf of gas. Price reductions decrease reserve
values by lowering the future net revenues attributable to the
reserves and will reduce 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 such 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.
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, 1993. Approximately 38% of the
yearend Pretax PW10% Value was estimated internally by the Company
and 62% 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, 1993 relating to the producing wells in which the Company owned
a working interest. The Company also held royalty interests in 240
producing wells. Wells are classified as oil or gas wells according
to their predominant production stream.
<TABLE>
<CAPTION>
Average
Principle Gross Net Working
Product Stream Wells Wells Interest
<S> <C> <C> <C>
Crude oil and liquids 3,026 1,297 43%
Natural gas 2,096 890 42%
Total 5,122 2,187 43%
</TABLE>
Acreage
The following table sets forth certain information at December
31, 1993 relating to acreage held by the Company. Undeveloped
acreage is all a 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.
<TABLE>
<CAPTION>
Gross Net
<S> <C> <C>
Developed (a) 520,000 191,000
Undeveloped
Domestic 539,000 326,000
International
Russia 306,000 86,000
Tunisia 1,200,000 1,140,000
Mongolia 2,800,000 2,100,000
Total undeveloped 4,845,000 3,652,000
Total 5,365,000 3,843,000
<FN>
(a) Developed acreage is acreage assigned to producing wells.
</TABLE>
Significant Properties
Although the Company's properties are widely dispersed
geographically, emphasis has been placed on establishing "hubs" in
certain producing basins. Interests in five producing areas
accounted for approximately 90% of Pretax PW10% Value at December 31,
1993. This concentration of assets results in economic efficiencies
in the management of assets and permits identification of
complementary acquisition candidates. Summary information regarding
reserve concentrations and more detailed information regarding the
four most significant properties are set forth below.
<TABLE>
<CAPTION>
Proved Reserve Quantities
Producing Crude Oil Natural Pretax PW 10% Value
Wells & Liquids Gas Amount Percent
(MMBbl) (MMcf) (000)
<S> <C> <C> <C> <C> <C>
DJ Basin (CO, NE) 1,336 16,984 242,155 $245,617 62.9%
East Washakie (WYO) 135 1,334 72,871 41,903 10.7
Central Wyoming (WYO) 1,042 7,207 28,913 30,905 7.9
Western Slope (CO & UT) 148 439 41,070 22,113 5.7
Giddings Field (TX) 96 752 7,987 10,960 2.8
Subtotal 2,757 26,716 392,996 351,7498 90.0
Other 2,365 5,214 37,093 38,911 10.0
Total 5,122 31,930 430,089 $390,409 100.0%
</table
D J Basin. Interests in the Wattenberg Field account for most
of the Company's interest in the D J Basin and include 1,437
producing wells (including 161 wells in which the Company owns
royalty interests) located principally in Weld County in northern
Colorado, of which 1,124 wells are operated by the Company. Major
producing zones are the Codell Sandstone and Niobrara Carbonates,
although the Company has expanded drilling targets to include the "J"
Sandstone and the Sussex Sandstone and, to a lesser degree, other
formations. The producing zones vary in depth from 4,500 to 7,500
feet and include solution gas drive oil reservoirs, gas-condensate or
volatile oil reservoirs and retrograde condensate gas reservoirs.
The reserves are considered to be medium to long-term, with gas
reserves representing the majority of the Pretax PW10% Value at
December 31, 1993. The properties contain approximately 387 proved
developed nonproducing (behind pipe) recompletions and 1,141 proved
undeveloped locations at yearend 1993. Development of these
nonproducing and undeveloped reserves will continue through the late
1990's. Much of the gas from Company wells is delivered to the
Company's pipeline and processing facilities in the area. This
provides a high degree of control over the transportation, processing
and marketing of the DJ Basin production. See "Business -
Development - D J Basin" and "Business - Gas Management."
East Washakie. The Company operates 50 wells in the Barrel
Springs Unit and 78 wells in the Blue Gap Field. The Company also
owns and operates Mexican Flats Service Company, Inc., which owns a
disposal site for water produced from the Company's and other
parties' wells. The major producing reservoir of both the Barrel
Springs Unit and Blue Gap Field is the Mesaverde, which ranges in
depth from 8,000 to 10,000 feet.
Gas production accounts for approximately 95% of the 12.3
million BOE of reserves for the Carbon County wells, with condensate
accounting for the remaining 5%. The economic life of these wells is
generally projected to be 30 to 40 years. The Company holds 95,000
gross (76,000 net) undeveloped acres in the area, including
approximately 1,200 potential locations. See "Business - Development
- - East Washakie Project."
A subsidiary of the Company, is the major gas purchaser for the
Carbon County, Wyoming properties, and Total Petroleum Inc., an
unrelated party, purchases the condensate. In the past, the Barrel
Springs Unit was shut-in or severely curtailed due to lack of a
market for its gas. The Blue Gap Field has historically been
curtailed in the summer due to the lack of an acceptable gas price.
Curtailment did not occur to any significant degree in either field
during 1993.
Central Wyoming. In December 1992, the Company acquired four
large producing fields and several smaller fields from Atlantic
Richfield Company ("ARCO"). 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.
The production from the Riverton Dome field is processed by a
plant included in the 1992 purchase by the Company. The Company
operates the Hamilton Dome and Riverton Dome fields. Approximately
87% of the 16.0 million BOE of reserves are classified as proved
producing. Oil accounts for almost 78% of the reserves. There are
10 Hamilton Dome and Riverton Dome drilling locations to which proved
undeveloped reserves have been attributed. There reserves are
planned for development over the next year. If successful,
additional locations could be booked as proved. See "Business -
Development - Other."
Western Slope. The Company has an interest in 148 producing
wells, of which 58 wells are operated by the Company, in the Piceance
and Uinta Basins. Major producing zones include the Uinta, Green
River, Wasatch, Mesaverde, Dakota, Morrison, Cozzette and Corcoran
formations. Producing zones vary in depth from 3,000 to 9,000 feet.
Gas reserves represent the majority of the Pretax PW 10% value at
December 31, 1993. The Properties contain approximately 20 proved
nonproducing (behind pipe) recompletions and 101 proved undeveloped
locations at yearend 1993. In total, the Company holds over 1,000
potential drilling location in these areas. See "Business -
Development - Western Slope Project."
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 1993.
<PAGE>
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S SECURITIES AND RELATED
SECURITY HOLDER MATTERS
The Company's stock is listed on the New York Stock Exchange.
The common stock began trading under the symbol "SNY" in March 1990.
The Company's $4.00 Convertible Exchangeable Preferred Stock ("$ 4
Convertible Preferred Stock") began trading on the New York Stock
Exchange under the symbol "SNY Pr" in November 1991. Depositary
shares representing a quarter interest in the Company's $6.00
Convertible Exchangeable Preferred Stock ("$6 Convertible Preferred
Stock") began trading on the New York Stock Exchange under the symbol
"SNY Pr A" on April 14, 1993. Prior to those dates, there were no
markets for the these securities. The following table sets forth,
for 1992 and 1993, 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.
</TABLE>
<TABLE>
<CAPTION>
Common Stock
1992 1993
High Low High Low
<S> <C> <C> <C> <C>
First Quarter $6-7/8 $5-7/8 $16-1/8 $10
Second Quarter 7-3/8 6-1/8 20-1/4 15
Third Quarter 10-1/2 6-3/8 23 16-5/8
Fourth Quarter 10-1/8 8-5/8 23 14-3/4
</TABLE>
<TABLE>
<CAPTION>
$4 Convertible Preferred Stock
1992 1993
High Low High Low
<S> <C> <C> <C> <C>
First Quarter $50 $46-1/4 $93-1/2 $64
Second Quarter 50-5/8 46-1/2 112 85
Third Quarter 65-3/4 50 126-1/4 100-1/2
Fourth Quarter 64 57-3/4 123-1/4 100
</TABLE>
<TABLE>
<CAPTION>
$6 Convertible Preferred Stock (Depositary Shares)
1992 1993
High Low High Low
<S> <C> <C> <C> <C>
First Quarter - - - -
Second Quarter - - $29 $25
Third Quarter - - 31-3/4 25
Fourth Quarter - - 31-3/4 25
</TABLE>
On March 9, 1994, the closing price of the common stock was
$19-1/2. Dividends were paid quarterly at the rate of $.05 per share
in 1992. Due to revised payment timing, two payments were made at
the $.05 rate in the second quarter of 1992. Dividends were paid at
the rate of $.05 per share in the first and second quarter of 1993.
In the third quarter of 1993, dividends were increased to $.06 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
the Company's preferred stock, capital expenditures and other
factors. On December 31, 1993, there were approximately 3,500
holders of record of the common stock and 23.3 million shares
outstanding.
On March 9, 1994 the closing price of the $4 Convertible
Preferred Stock was $106. Shares of $4 Convertible Preferred Stock
receive quarterly dividends of $1.00 if declared by the Board of
Directors. Any cumulative dividends in arrears must be paid prior to
payment of any dividends on the common stock. On December 31, 1993,
there were 24 holders of record of the $4 Convertible Preferred Stock
and 1.2 million shares outstanding. The $4 Convertible Preferred
Stock may be called beginning on January 1, 1995 at a price of $52.50
per share.
On March 9, 1994 the closing price of the depositary shares
representing the $6 Convertible Preferred Stock was $27-7/8. Each
depositary share represents a one-quarter interest in a share of $100
liquidation value $6 Convertible Preferred Stock. Shares of $6
Convertible Preferred Stock receive quarterly dividends of $1.50
($.375 per depositary share) if declared by the Board of Directors.
A dividend was paid June 30, 1993 at the rate of $1.17 per share
($.29 per depositary share), reflecting a partial rate since issuance
in April 1993. Any cumulative dividends in arrears must be paid
prior to payment of any dividends on the common stock. On December
31, 1993 there were 43 holders of records of the $6 Convertible
Preferred Stock and 4.1 million depositary shares outstanding. The
$6 Convertible Preferred Stock may be called beginning on March 31,
1996 at a price of $104.10 per share ($26.05 per depositary share).
ITEM 6. SELECTED FINANCIAL DATA
The following table presents selected financial and operating
information for each of the five years ended December 31, 1993.
Share and per share amounts refer to common shares. The following
information should be read in conjunction with the financial
statements presented elsewhere herein.
<TABLE>
<caption
(In thousands, except per share data) As of or for the Year Ended December 31,
1989 1990 1991 1992 1993
<S> <C> <C> <C> <C> <C>
Income Statement
Revenues $ 26,543 $ 82,173 $ 92,501 $120,172 $229,885
Income before accounting change
and extraordinary items 4,832 7,515 8,811 16,875 27,608
Per share .43 .36 .37 .53 .80
Net income 6,921 7,515 8,811 20,638 25,664
Per share .62 .36 .37 .70 .72
Dividends Per share .11 .16 .20 .25(a) .22
Average shares outstanding 11,135 20,620 22,839 22,722 23,096
Cash Flow
Net cash provided by operations $ 11,129 $ 22,512 $ 37,738 $ 47,911 $ 68,293
Capital expenditures 14,216 171,767(b) 48,385 130,375 166,726
Balance Sheet
Working capital $ 3,499 $ 12,087 $ 17,259 $ 7,619 $ 1,291
Oil and gas properties, net 29,904 179,902 196,206 287,094 388,361
Total assets 56,669 227,198 252,241 346,737 479,536
Senior debt 2,325 56,172 17,108 96,568(c) 114,952
Subordinated notes, net 2,477(d) 25,000 25,000 18,750 -
Stockholders' equity 31,149 115,187 174,696 184,393 297,241
<FN>
(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.
(d) Represents exchangeable preferred equity which was converted into
subordinated notes in May 1990.
</TABLE>
<PAGE>
The following table sets forth unaudited summary financial
results on a quarterly basis for the two most recent years.
<TABLE>
<CAPTION>
(In thousands, except per share data) 1992 Quarters
First Second Third Fourth
<S> <C> <C> <C> <C>
Revenues $ 26,913 $ 27,949 $ 29,956 $ 35,354
Gross margin 13,741 14,708 15,125 18,072
Depletion, depreciation and amortization 7,490 8,213 7,290 8,951
Income before effect of accounting change 3,304 3,040 4,519 6,012
Per share .09 .08 .15 .21
Net income 7,067 3,040 4,519 6,012
Per share .26 .08 .15 .21
</TABLE>
<TABLE>
<CAPTION>
1993 Quarters
First Second Third Fourth
<S> <C> <C> <C> <C>
Revenues $ 44,873 $ 58,276 $ 61,288 $65,448
Gross margin 22,201 25,342 26,818 25,783
Depletion, depreciation and amortization 11,831 14,562 11,412 13,379
Income before extraordinary item 6,367 6,537 6,623 8,081
Per share (a) .23 .18 .17 .23
Net income 5,983 6,537 6,161 6,983
Per share (a) .21 .18 .15 .19
<FN>
(a) Quarters do not equal year-to-date totals due to rounding.
</TABLE>
<PAGE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
Results of Operations
Comparison of 1993 results to 1992. Total revenues rose 91% in
1993 to $229.9 million. Net income before taxes and extraordinary
items more than doubled to reach $34.9 million in 1993. The increase
was led by a rapid rise in production and assisted by an increase in
gas processing and transportation margins. Before the effect of a
favorable $3.8 million income tax accounting change in 1992 and a
$1.9 million 1993 extraordinary charge on early retirement of debt,
earnings per common share were $.80 in 1993 compared to $.53 in 1992,
a 51% increase.
The gross margin from production operations for 1993 increased 62%
to $79.7 million, which was primarily related to a 65% growth in oil
and gas production. The price received per equivalent barrel
decreased by 3% to $13.41. Total operating expenses including
production taxes increased 60% during 1993 although operating cost
per equivalent barrel ("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 1993 operating
costs averaged $7.45 per BOE.
For the year ended December 31, 1993, average daily production per
BOE was 25,472 Bbls, a 65% increase from 1992. Average daily
production in the fourth quarter of 1993 climbed to 10,314 barrels
and 105.6 MMcf (27,917 barrels of oil equivalent). The production
increases resulted primarily from acquisitions and continuing
development drilling in the DJ Basin of Colorado. Domestically,
$51.0 million in properties were acquired in 1993, primarily in and
around existing hubs in Colorado and Wyoming. The acquisitions
included a significant number of development locations and should
continue to add to production into 1994. In 1993, 311 wells were
placed on production in the DJ Basin, with 51 wells in various stages
of drilling and completion at yearend. Because the majority of the
wells were added in the latter part of the year, production will not
be fully impacted until 1994. Additionally, significant downtime was
experienced in the fourth quarter at the major processing plant in
the area and much of the gas had to be diverted, which increased line
pressures and hampered production. To a lesser extent, this
situation continued into early 1994.
The gross margin from gas processing, transportation and marketing
activities for 1993 increased 23% to $10.0 million from $8.1 million
in 1992. The increase was primarily attributable to a $3.0 million
(33%) rise in transportation and processing margins as a result of
additional DJ Basin production and the recent 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. In 1993 the net
contract margin was a loss of $267,000, which was $1.8 million less
than 1992. At present gas price levels, the Company foresees
continued negative or breakeven margins for the cogeneration contract
through July 1994. At that time, the share of the sales price
minimum attributable to gas will increase from 45% to 65% and the
margin should improve. The cogeneration margin reduction was
partially offset by a $667,000 (126%) rise in other gas marketing
margins resulting from increased third party marketing.
Other income was $10.4 million during 1993, compared to $4.2
million in 1992. The $6.2 million increase resulted from a $3.5
million gas contract settlement received in April, a $1.7 million
litigation judgment and greater gains on the sales of securities.
General and administrative expenses, net of reimbursements, for 1993
represented 3% of revenues compared to 5.6% in 1992 as expenses were
held essentially flat while revenues grew 91%. Interest and other
expenses increased 28% primarily as a result of a rise in outstanding
debt balances. Senior debt was paid down in April 1993 with proceeds
from a preferred offering, but increased through yearend as a result
of development expenditures, acquisitions, the investment in Command
Petroleum and the retirement of the $25.0 million in subordinated
debt.
Depletion, depreciation and amortization during 1993 increased 60%
from the prior year. The increase was the direct result of the 65%
rise in equivalent production between years. The producing depletion
rate per equivalent barrel for 1993 was reduced to $4.75 from $4.79
in 1992. The rate was reduced by an ongoing drilling cost reduction
program, partially offset by an increase from the discontinuation of
converting Thomasville production to equivalent quantities based on
relative gas prices.
The Company adopted FASB Statement No. 109, "Accounting for Income
Taxes," effective January 1, 1992. Net income for 1992 was increased
by $3.8 million for the cumulative effect of the change in method of
accounting for income taxes. In 1992 the income tax provision was
reduced from the statutory rate of 34% by $5.5 million due to the
elimination of deferred taxes as a result of tax basis in excess of
financial basis. In 1993 the income tax provision was reduced from
the newly enacted rate of 35% by $4.7 million upon full realization
of the excess basis benefit. The Company anticipates deferred taxes
will be provided in 1994 and beyond based on the full statutory rate.
Comparison of 1992 results to 1991. Revenues rose 30% in 1992 to
$120.2 million, compared to $92.5 million in 1991. Net income for
1992 was $20.6 million, a 134% jump from the $8.8 million in 1991.
The increases resulted from greater oil and gas production volumes,
lower interest expense, reduced general and administrative expenses
and a $3.8 million reversal of the cumulative effect of prior year
deferred taxes with the adoption of a change in the method of
accounting for income taxes.
Average daily production for 1992 rose 24% to 15,408 equivalent
barrels due mostly to development drilling in the DJ Basin of
Colorado as 189 wells were placed on production there. As a result,
the gross margin from production increased 22% to $49.3 million in
1992. The price per equivalent barrel of oil and gas production
decreased 4% during 1992.
The gross margin from gas processing, transportation and marketing
activities for 1992 increased 12% to $8.1 million from $7.3 million
in 1991. The growth was primarily the result of increased marketing
of third party gas in New Mexico, Colorado and Wyoming. Gas
processing and transportation margins increased moderately as volumes
were increased late in the year by expansions of pipeline and plant
facilities to take advantage of increasing DJ Basin production.
Other income for 1992 decreased 26% to $4.2 million from a reduction
in gains on sales of securities and lower interest on notes
receivable.
Direct operating expenses including production taxes increased
only 13% during 1992 as the operating cost per equivalent barrel
decreased to $4.99 from $5.47 in 1991, due to increased DJ Basin
production where operating costs have been significantly lower than
average. General and administrative expenses, net of reimbursements,
for 1992 represented less than 6% of revenues compared to 8% in 1991,
as revenues rose 30%. Interest and other expenses dropped 39% in
1992 due to lower average outstanding senior debt after the
application of proceeds from a preferred stock offering in late 1991.
Development, Acquisition and Exploration
During 1993 the Company incurred $93.1 million for oil and gas
property development and exploration, $51.0 million for acquisitions
and $22.6 million for gas facility expansion and other assets, for a
total of $166.7 million in property and equipment expenditures.
Additionally, the Company made an $18.2 million investment in an
Australian based exploration and production company.
The Company has concentrated a significant portion of its
development activities in the DJ Basin of Colorado. Capital
expenditures for DJ Basin development totalled $75.4 million during
1993. A total of 311 newly drilled wells were placed on production
there in 1993 and 51 were in progress at yearend. Additionally, 42
recompletions were performed in 1993, with seven in process at
yearend. In December 1993, 16 drilling rigs were in operation in the
DJ Basin. The Company anticipates putting 500 or more wells per year
on production in the DJ Basin for the next few years. With
additional leasing activity and through drilling costs reductions
that add infill locations as proven as they become economic, the
Company has increased the inventory of available drillsites. In
December, the Company entered into a letter of intent with Union
Pacific Resources Corporation whereby the Company will gain the right
to drill wells on UPRC's previously uncommitted acreage throughout
the Wattenberg area. This transaction significantly increased the
Company's undeveloped Wattenberg inventory. UPRC will retain a
royalty and the right to participate as a 50% working interest owner
in each well, and received grants for warrants to purchase two
million shares of Company stock. Of the warrants, one million expire
three years from the date of grant, and are exercisable at $25 per
share, while the other one million expire in four years and are
exercisable at $27 per share. One year from the date of grant
(February 8, 1994), the exercise prices may be reduced to 120% of the
average closing price of the Company stock for the preceding 20
consecutive trading days, but not to lower than an exercise price of
$21.60 per share. At that time the expiration date of the warrants
may also be extended one year if the average closing price over the
20 day trading period is less than $16.50 per share.
The Company expended $14.8 million for other development and
recompletion projects and $2.9 million for exploration during 1993.
In Nebraska, 29 wells were added to production in 1993 as an
extension of a drilling program initiated in 1992. An additional 20
wells are planned in Nebraska for 1994. In southern Wyoming, 11
wells in the East Washakie Basin development program were
successfully drilled and completed during the last half of 1993 with
three in process at yearend. In this program, significant cost-
cutting measures were applied based on the experience gained in the
DJ Basin. In central Wyoming on the properties acquired from ARCO in
late 1992, efforts have been focused on increasing operating
efficiency with limited development drilling and workover activity.
In 1993, three successful wells were drilled in the fourth quarter
and selected development and recompletion activity is scheduled for
1994. In the Piceance Basin of western Colorado, a three well test
program was started in December of 1993 on acreage acquired there
during the year, with one well undergoing completion, the second in
progress and a third scheduled for early 1994. Current plans include
a minimum of 25 wells in the basin during 1994. In South Texas, a
combined operated and non-operated program was initiated, with nine
wells completed in 1993 and one well abandoned. A total of 25
additional horizontal locations have been identified and drilling
should continue with as many as 15 wells planned in 1994. In its
domestic exploration efforts, the Company initiated a seismic program
in Louisiana and began drilling early in the fourth quarter.
Advanced seismic techniques are being used to identify further
prospects in Louisiana and expectations are to drill up to 20 wells
in 1994.
A total of $51.0 million in domestic acquisitions were completed
in 1993. In May 1993, the Company purchased an interest in 121
producing wells and over 70 drilling locations in the DJ Basin area
for $3.3 million. In July, an incremental 25% interest in the
Company's Barrel Springs and Duck Lake Fields in Wyoming was
purchased for $6.1 million. The properties are 90% gas and include
44 producing wells and 46 undeveloped locations. In August, the
Company acquired interests in 225 producing wells and 272 proved
undeveloped locations in the DJ Basin for $19.7 million. The proved
reserves are 70% gas with more than two-thirds requiring future
development to produce. Late in the year, two acquisitions were
completed in the Piceance and Uinta Basins of Western Colorado for a
total of $12.5 million. The majority of the value was in undeveloped
locations as only 128 wells were currently producing. Numerous other
producing and undeveloped acquisitions totalling $9.4 million were
completed, mostly in or close to the Company's principal operating
areas.
The Company's gas gathering and processing facilities have been
undergoing significant transformation since late 1992. In 1993, the
Company expended $20.1 million to further develop its gas related
assets. The Company spent $9.4 million toward the second phase of
its DJ Basin gathering expansion to construct a high pressure line to
deliver gas directly to the major gas processing plant in the area
and expand its gathering network for the increased drilling activity.
An additional $2.6 million was expended to expand the Roggen Plant
for the production increases. A total of $5.6 million in additional
transportation and gathering facilities were constructed in the DJ
Basin including a nine mile 16" interconnect line completed in
October to relieve high line pressures, a 20" western gathering
extension and numerous other extensions and connections. A gathering
system that delivers third party gas to the Roggen Plant was
purchased for $703,000. The Company expended $1.4 million to
complete construction of a system to gather gas from its Nebraska
drilling project. These projects are intended to take advantage of
the significant increase in drilling activity in these areas.
In the international arena, progress continues as well. In May
1993, the Company acquired 42.8% of the outstanding shares of Command
Petroleum Holdings N.L., an Australian exploration and production
company, for $18.2 million. The Sydney based company is listed on
the Australian Stock Exchange, and at December 31, 1993 had 950,000
barrels of proven oil reserves and $19.9 million of working capital.
In addition, it holds interests in more than 20 exploration permits
and licenses and a 28.7% interest in a Netherlands exploration and
production company whose assets are located primarily in the North
Sea. In Russia, the Permtex joint venture received central
government approval in August and the Company executed a finance and
insurance protocol with the Overseas Private Investment Corporation
("OPIC"), a United States government agency. Current plans call for
25 of the existing 45 shut-in wells to be placed on production in
1994, and that 400 development wells will be drilled over the next
ten years. Extensive seismic work began in the fourth quarter of
1993 for 400 kilometers of data in Tunisia and 500 kilometers in
Mongolia.
Financial Condition and Capital Resources
At December 31, 1993, the Company had total assets of $480 million
and working capital of $1.3 million. Total capitalization was $412
million, of which 28% was represented by senior debt and the
remainder by stockholders' equity. During 1993, the Company fully
retired its $25 million of 13.5% subordinated notes and the related
cumulative participating interests. During 1993, cash provided by
operations was $68.3 million, an increase of 43% over 1992. As of
December 31, 1993, commitments for capital expenditures totalled $7.5
million, primarily for DJ Basin drilling. The level of 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, proceeds from property dispositions and existing credit
facilities. In addition, joint ventures or future public and private
offerings of securities may be utilized.
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 October 1992, and at first
payout in June 1993 the second contribution of $1.5 million was
received. An additional $1.5 million was received in October 1993.
This transaction should increase the Company's cash flow and net
income through 1994. 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 $3.8 million of this
revenue during 1993. Discussions are in progress to expand this
transaction so that the benefits would be extended through at least
1996.
In April 1993, the Company sold 4.1 million depositary shares
(each representing a one quarter interest in one share of $100
liquidation value stock) of convertible preferred stock through an
underwriting for $103.5 million. A portion of the net proceeds of
$99.3 million was used to retire the entire outstanding balance under
the revolving credit facility at that time. The preferred stock pays
a 6% dividend and is convertible into common stock at $21.00 per
share. At the Company's option, the preferred stock is exchangeable
into 6% convertible debentures on any dividend payment date on or
after March 31, 1994. The stock is redeemable at the option of the
Company on or after March 31, 1996.
Effective July 1, 1993, the Company renegotiated its bank credit
facility and increased it from $150 million to $300 million. The new
facility is divided into a $50 million short-term portion and a $250
million long-term portion that expires on December 31, 1997.
However, management's policy is to renew the facility annually.
Credit availability is adjusted semiannually to reflect changes in
reserves and asset values. At December 31, 1993, the elected
borrowing base was $150 million. The majority of the borrowings
currently bear interest at LIBOR plus 1.25% with the remainder at
prime. The Company also has the option to select CD plus 1.375%.
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. Based on such limitations, $86.5 million would have
been available for the payment of dividends and other restricted
payments as of December 31, 1993. The Company does not currently
plan to make, and is not committed to make, any advances or
contributions to unrestricted subsidiaries that would materially
affect its ability to pay dividends under this limitation.
During 1993, the Company fully retired its $25.0 million of 13.5%
subordinated notes and the related cumulative participating
interests. An extraordinary charge to earnings of $1.9 million (net
of income taxes) was made in 1993, representing the amount paid in
excess of principal and accrued interest through the retirement
dates. These notes were retired early in order to reduce the
Company's ongoing cost of debt.
The Company maintains a program to divest marginal properties and
assets which do not fit its long range plans. For 1992 and 1993,
proceeds from these sales were $3.0 million and $5.5 million,
respectively. Included in the 1993 proceeds were $4.0 million of
cash receipts previously accrued for late 1992 sales. The Company
intends to continue to evaluate and dispose of nonstrategic assets.
In 1990, the Company was granted a judgment in litigation
regarding a leasehold assignment from the early 1980's. The Oklahoma
Supreme Court refused certiorari and the judgment was upheld. As a
result, a total of $1.7 million was accrued and reported in other
income in 1993. The full amount was collected in January 1994. In
April 1992, a jury found for the plaintiffs in a gas contract dispute
related to an offshore property. In April 1993, the dispute was
settled by an agreement to pay the Company a net of $5.3 million.
The initial $3.5 million was received and reflected as other income
in second quarter 1993. The remaining $1.8 million was received in
third quarter 1993, but reflected as a reserve for possible
contingencies. 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 financial
statements reflect these judgments only upon receipt of cash or final
judicial determination.
The Company believes that its capital resources are more than
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. While
such fluctuations have had, and will continue to have a material
effect, the Company is unable to predict them.
The following table indicates the average oil and gas prices
received over the last five years and highlights the price
fluctuations by quarter for 1992 and 1993. Average gas prices
exclude the Thomasville gas production. During 1993, the Company
renegotiated its Thomasville gas contract and beginning in January
1994, the Company will receive a somewhat higher than market price
for its Thomasville gas sales, significantly below its 1993 average
price of $12.16 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. Equivalent
prices prior to 1993 have been restated to reflect elimination of the
conversion of Thomasville gas volumes based on its price relative to
the Company's other gas production.
<TABLE>
<CAPTION>
Average Prices
Crude Oil Per
and Natural Equivalent
Liquids Gas Barrel
(Per Bbl) (Per Mcf)
<S> <C> <C> <C>
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
Quarterly
1992
First $ 17.80 $ 1.56 $ 12.66
Second 19.72 1.53 13.28
Third 20.18 1.70 13.94
Fourth 17.98 2.13 14.96
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
</TABLE>
In December 1993, the Company was receiving an average of $12.54
per barrel and $2.27 per Mcf (excluding the Thomasville contract) for
its production. Beginning in December 1992, the average oil price
was effectively reduced by the oil production added from the Wyoming
acquisition, which sells at a significant discount to West Texas
Intermediate posting due to the presence of low gravity sour crude in
two of the fields.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTAL DATA
Reference is made to the Index to Financial Statements on page
35 for financial statements and notes thereto. Supplementary
schedules are presented at the end of Part III following page 55.
Quarterly financial data is presented on page 28 of this Form 10-K.
Schedules I, III, IV, VII, VIII, IX, XI, XII, and XIII 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.
<PAGE>
<TABLE>
<caption
SNYDER OIL CORPORATION
INDEX TO FINANCIAL STATEMENTS AND SCHEDULES
Page
<S> <C>
Report of Independent Public Accountants . . . . . . . . . . . . . 36
Consolidated Balance Sheets as of December 31, 1992 and 1993 . . . 37
Consolidated Statements of Operations for the years ended
December 31, 1991, 1992 and 1993 . . . . . . . . . . . . . . . . 38
Consolidated Statements of Changes in Stockholders' Equity
for the years ended December 31, 1991, 1992 and 1993 . . . . . . 39
Consolidated Statements of Cash Flows
for the years ended December 31, 1991, 1992 and 1993 . . . . . . 40
Notes to Consolidated Financial Statements . . . . . . . . . . . . 41
Schedules:
Schedule II - Amounts Receivable From Employees and Related
Parties. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 55
Schedule V - Property. . . . . . . . . . . . . . . . . . . . . . 56
Schedule VI - Accumulated Depletion, Depreciation and
Amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . 57
Schedule X - Supplementary Income Statement Information . . . . 58
</TABLE>
<PAGE>
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 1992, 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,
1993. These financial statements and the schedules referred to below
are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements
and schedules 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
1992, and the results of their operations and their cash flows for
each of the three years in the period ended December 31, 1993, in
conformity with generally accepted accounting principles.
As explained in Note 7 to the financial statements, effective
January 1, 1992, the Company changed its method of accounting for
income taxes.
Our audits were made for the purpose of forming an opinion on
the basic financial statements taken as a whole. The schedules
listed in the index to financial statements and schedules are
presented for purposes of complying with the Securities and Exchange
Commission's rules and are not a part of the basic financial
statements. These schedules have been subjected to the auditing
procedures applied in our audits of the basic financial statements
and, in our opinion, fairly state in all material respects the
financial data required to be set forth therein in relation to the
basic financial statements taken as a whole.
ARTHUR ANDERSEN & CO.
Forth Worth, Texas
February 25, 1994
<PAGE>
<TABLE>
<CAPTION>
SNYDER OIL CORPORATION
CONSOLIDATED BALANCE SHEETS (Notes 1 and 2)
(In thousands)
December 31,
1992 1993
ASSETS
<S> <C> <C>
Current assets
Cash and equivalents $ 20,485 $ 10,913
Accounts receivable 31,219 47,472
Other 553 3,407
52,257 61,792
Investments (Note 4) 7,386 29,383
Oil and gas properties, full cost method (Note 5) 338,908 468,764
Accumulated depletion, depreciation and amortization (82,005) (126,123)
256,903 342,641
Gas processing and transportation facilities (Note 5) 37,420 60,015
Accumulated depreciation (7,229) (14,295)
30,191 45,720
$ 346,737 $ 479,536
</TABLE>
LIABILITIES AND STOCKHOLDERS' EQUITY
<TABLE>
<S> <C> <C>
Current liabilities
Accounts payable $ 25,512 $ 37,247
Accrued liabilities 12,861 23,239
Current portion of debt (Note 3) 6,265 15
44,638 60,501
Other liabilities 574 458
Senior debt, net (Notes 3 and 5) 96,568 114,952
Subordinated notes (Note 3) 18,750 -
Deferred taxes and credits (Note 9) 1,814 6,384
Commitments and contingencies (Note 10)
Stockholders' equity (Note 6)
Preferred stock, $.01 par, 10,000,000 shares authorized,
8% preferred stock, 1,200,000 and 1,186,005 shares
issued and outstanding 12 12
6% preferred stock, none and 1,035,000 shares
issued and outstanding - 10
Common stock, $.01 par, 75,000,000 shares authorized,
22,873,743 and 23,259,658 issued and outstanding 229 233
Capital in excess of par value 148,670 250,574
Retained earnings 35,482 46,954
Foreign currency translation - (542)
184,393 297,241
$ 346,737 $ 479,536
<FN>
The accompanying notes are an integral part of these statments.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
SNYDER OIL CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS (Notes 1 and 2)
(In thousands except per share data)
Year Ended December 31,
1991 1992 1993
<S> <C> <C> <C>
Revenues (Note 8)
Oil and gas sales $ 65,344 $ 77,363 $ 124,641
Gas processing and transportation 21,459 38,611 94,839
Other 5,698 4,198 10,405
92,501 120,172 229,885
Expenses
Direct operating 24,882 28,057 44,901
Cost of gas and transportation 14,202 30,469 84,840
General and administrative 7,259 6,704 6,780
Interest and other 9,327 5,693 7,271
Depletion, depreciation and amortization 25,392 31,944 51,184
Income before taxes, accounting change
and extraordinary item 11,439 17,305 34,909
Provision for income taxes (Note 7)
Current 230 430 -
Deferred 2,398 - 7,301
2,628 430 7,301
Income before accounting change
and extraordinary item 8,811 16,875 27,608
Cumulative effect of change in
accounting for income taxes (Note 7) - 3,763 -
Extraordinary item - early extinguishment of debt,
net of taxes of $1,038 (Note 3) - - (1,944)
Net income 8,811 20,638 25,664
Dividends on preferred stock (453) (4,800) (9,100)
Net income available to common $ 8,358 $ 15,838 $ 16,564
Net income per share (Note 2)
Before accounting change and extraordinary item $ .37$ .53$ .80
Accounting change and extraordinary item - .17 (.08)
Total $ .37$ .70$ .72
Weighted average shares outstanding (Note 6) 22,839 22,722 23,096
<FN>
The accoumpnaying notes are an integral part of these statements.
</TABLE>
<PAGE>
<TABLE>
<caption
SNYDER OIL CORPORATION
CONSOLIDATED STATEMENTS OF CHANGES IN
STOCKHOLDERS' EQUITY (Notes 1, 2 and 6)
(In thousands)
Capital in
Preferred Stock Common Stock Excess of Retained
Shares Amount Shares Amount Par Value Earnings
<S> <C> <C> <C> <C> <C> <C>
Balance, December 31, 1990 - - 23,131 $ 231 $ 93,420 $ 21,536
Issuance of preferred 1,200 12 - - 57,396 -
Issuance of common - - 68 - 104 -
Repurchase of common - - (344) (3) (1,797) -
Dividends - - - - - (5,014)
Net income - - - - - 8,811
Balance, December 31, 1991 1,200 12 22,855 228 149,123 25,333
Issuance of common - - 234 2 807 -
Repurchase of common - - (215) (1) (1,260) -
Dividends - - - - - (10,489)
Net income - - - - - 20,638
Balance, December 31, 1992 1,200 12 22,874 229 148,670 35,482
Issuance of preferred 1,035 10 - - 99,315 -
Common stock grants and
exercise of options - - 309 3 2,590 -
Conversion of preferred
to common (14) - 77 1 (1) -
Dividends - - - - - (14,192)
Net income - - - - - 25,664
Balance, December 31, 1993 2,221$ 22 23,260$ 233$ 250,574 $ 46,954
<FN>
The accompanying notes are an integral part of these statements.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
SNYDER OIL CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS (Notes 1 and 2)
(In thousands)
Year Ended December 31,
1991 1992 1993
>s> <C> <C> <C> >
Operating activities
Net income $ 8,811 $ 20,638 $ 25,664
Adjustments to reconcile net income to net cash
provided by operations
Depletion, depreciation and amortization 25,392 31,944 51,184
Deferred taxes 2,398 - 7,301
Extraordinary item - early extinguishment of debt - - 1,944
Change in accounting for income taxes - (3,763) -
Gain on sale of securities (1,626) (777) (2,283)
Amortization of deferred credits - (780) (3,846)
Changes in operating assets and liabilities
Decrease (increase) in
Accounts receivable 1,623 (4,669) (22,397)
Other current assets 161 211 (3,354)
Increase (decrease) in
Accounts payable 553 6,395 11,953
Accrued liabilities 1,067 (1,352) 2,227
Other liabilities (663) (63) (116)
Other 22 127 16
Net cash provided by operations 37,738 47,911 68,293
Investing activities
Acquisition, development and exploration (46,557) (78,165) (193,829)
Proceeds from investments 2,895 3,582 8,378
Outlays for investments (2,383) (1,626) (27,594)
Sale of properties 4,925 2,992 5,547
Net cash used by investing (41,120) (73,217) (207,498)
Financing activities
Issuance of common 104 722 1,528
Issuance of preferred 57,486 - 99,325
Increase in indebtedness 27 29,700 68,159
Repayments of indebtedness (39,380) (187) (25,000)
Premium on debt extinguishment - - (2,983)
Dividends (5,053) (10,489) (14,192)
Deferred credits - 2,594 2,796
Repurchase of common (1,916) (1,261) -
Net cash realized by financing 11,268 21,079 129,633
Increase (decrease) in cash 7,886 (4,227) (9,572)
Cash and equivalents, beginning of year 16,826 24,712 20,485
Cash and equivalents, end of year $ 24,712 $ 20,485 $ 10,913
<FN>
The accompanying notes are an integral part of these statements.
</TABLE>
SNYDER OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) ORGANIZATION AND NATURE OF BUSINESS
Snyder Oil Corporation (the "Company") is engaged in the
acquisition, production, development and to a lesser degree
exploration of primarily domestic oil and gas properties. The
Company is also involved in gas processing, transportation, gathering
and marketing. The Company, a Delaware corporation, is the successor
to a company formed in 1978. 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.
(2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The consolidated financial statements include the accounts of
Snyder Oil Corporation and its subsidiaries (collectively, the
"Company"). 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.
The Company follows the "full cost" accounting method. All costs
of exploration and development are capitalized as incurred.
Depletion, depreciation and amortization ("depletion") is provided on
the unit-of-production method based on proved reserves. Gas is
converted to equivalent barrels at the rate of six Mcf per barrel.
The depletion rates per equivalent barrel produced were $4.68, $4.79
and $4.75, respectively, in 1991, 1992 and 1993. In 1993, the
practice of converting Thomasville production to equivalent
quantities based on its price relative to other gas production was
discontinued. No gains or losses are recognized upon the disposition
of oil and gas properties except in extraordinary transactions.
Proceeds are credited to the carrying value of the properties.
Maintenance and repairs are expensed. Expenditures which enhance the
value of the properties are capitalized. Depreciation on gas
processing and transportation facilities is generally provided on a
straight-line basis over 15 years.
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
received. The affiliate's functional currency is the Australian
dollar. The reported foreign currency translation adjustment is the
result of the translation of the Australian balance sheet into United
States dollars at year-end and the related impact of exchange rates
subsequent to purchase.
All highly liquid investments with a maturity of three months or
less are considered to be cash equivalents. Earnings per share are
computed based on the weighted average number of common shares
outstanding. Differences between primary and fully diluted earnings
per share were insignificant for all periods presented. General and
administrative expenses are reduced by reimbursements for well
operations, drilling and management of partnerships. Reimbursements
amounted to $11.1 million, $14.3 million and $17.8 million,
respectively, in 1991, 1992 and 1993.
Certain amounts in the 1991 and 1992 financial statements have
been reclassified to conform with the 1993 presentation.
(3) INDEBTEDNESS
The following indebtedness was outstanding on the respective
dates:
<TABLE>
<CAPTION>
December 31,
1992 1993
(In thousands)
<S> <C> <C>
Revolving credit facility $ 46,700 $ 114,901
Other 49,883 66
96,583 114,967
Less current portion (15) (15)
Senior debt, net $ 96,568 $ 114,952
Subordinated notes 25,000 -
Less current portion (6,250) -
Subordinated debt, net $ 18,750 $ -
</TABLE>
The Company maintains a $300 million revolving credit facility.
The facility is divided into a $250 million long-term portion and a
$50 million short-term portion. However, management's policy is to
renew the facility annually. The elected borrowing base available
under the facility at December 31, 1993 was $150 million. The
majority of the borrowings currently bear interest at LIBOR plus
1.25% with the remainder at prime. During 1993, the average
borrowing cost was 4.9%. The Company pays certain fees based on the
borrowing base and outstanding loans. 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. At December 31, 1992, the Company
recorded the $49.8 million Wyoming acquisition commitment as other
senior debt. The cash flow statement did not reflect the commitment
as an increase in indebtedness until final payment was disbursed in
February 1993.
The subordinated notes bore interest at 13.5% and were due in four
annual payments commencing November 15, 1993. The notes were subject
to optional redemption at 102% of principal after November 1994 and
at par after November 1995. Cumulative rights to receive additional
interest based on net cash flow above certain minimum levels were
issued in connection with the notes. Cash flow has substantially
exceeded the minimum since 1991, and the Company has since made the
maximum payments. At December 31, 1992, based on existing market
rates the subordinated notes and cumulative interest rights had a
combined fair value of $27.7 million, which the Company believes
approximated its cost of funds for notes with similar terms. In
March 1993, the Company retired 40% of the cumulative rights. The
portion of the payment representing prepaid interest was expensed as
an extraordinary item, net of income taxes, for $384,000. In August
1993, the Company retired $10 million (40%) of the subordinated
notes. The portion of the payment representing prepaid interest was
expensed as an extraordinary item, net of income taxes, for $462,000.
In November 1993, the Company retired the remaining $15 million of
the subordinated notes and the related 60% of cumulative rights, with
the portion of the payment representing prepaid interest expensed as
an extraordinary item, net of income taxes, for $1.1 million. The
Company expensed $1.1 million, $1.1 million and $516,000 as interest
expense for cumulative rights in 1991, 1992 and 1993, respectively.
Scheduled maturities of indebtedness are $15,000 for 1994, $17,000
for 1995 and 1996, and $114.9 million in 1997. The long-term portion
of the revolving credit facility is scheduled to expire in 1997;
however, management's policy is to renew the facility annually.
Cash payments for interest expense were $7.9 million, $5.4 million
and $9.2 million, respectively, for 1991, 1992 and 1993.
(4) INVESTMENTS
The Company has investments in foreign and domestic energy
companies and notes receivable, which at December 31, 1992 and 1993,
had a total book value of $7.4 million and $29.4 million,
respectively, with corresponding fair market values of $9.8 million
and $54.2 million.
In May 1993, the Company acquired 92 million (42.8%) of the
outstanding shares of Command Petroleum Holdings N.L. ("Command"), an
Australian exploration and production company, for $18.2 million.
The Sydney based company is listed on the Australian Stock Exchange,
and holds interests in more than 20 exploration permits and licenses
as well as a 28.7% interest in a publicly traded Netherlands
exploration and production company whose assets are located primarily
in the North Sea. The market value of the Company's investment in
Command based on Command's closing price at December 31, 1993 was
$39.1 million. The investment is accounted for by the equity method.
Command has outstanding stock options covering the issuance of up to
53.3 million common shares that expire November 30, 1994. Given that
the exercise price of the options is 44% below the year-end stock
price, the Company assumes they will be exercised. In January 1994,
Command completed an offering of 43 million of its common shares. As
a result of this offering, the Company's ownership was reduced to
35.7%. If, as expected, all of the November 1994 options were
exercised, the Company's ownership would be reduced to 29.6%.
The Company has investments in securities of publicly traded
domestic energy companies, not accounted for by the equity method,
having a book value and total cost at December 31, 1992 and 1993 of
$680,000 and $9.7 million, respectively. The market value of these
securities at December 31, 1992 and 1993 approximated $2.9 million
and $13.3 million, respectively. In the first quarter of 1994, the
Company will be required to adopt SFAS No. 115, "Accounting for
Certain Investments in Debt and Equity Securities." Under the
provisions of SFAS No. 115, at December 31, 1993 the Company would
have increased its investments by $3.6 million and increased
stockholders' equity by $2.3 million and deferred tax liability by
$1.3 million.
The Company holds $1.8 million in notes receivable due from
privately held corporations. All notes are secured by certain
assets, including stock and oil and gas properties. At December 31,
1992 and 1993, the fair value of the notes receivable, based on
existing market conditions and the anticipated future net cash flow
related to the notes, was believed to be equal to their book value.
(5) OIL AND GAS PROPERTIES
The cost of oil and gas properties at December 31, 1992 and 1993
includes $4.0 million and $9.8 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:
<TABLE>
<CAPTION>
1991 1992 1993
<S> <C> <C> <C>
Acquisition $ 9,910 $ 63,629 $ 50,997
Development 32,163 53,665 90,182
Gas processing, transportation and other 4,442 11,158 22,595
Exploration 1,870 1,923 2,952
$ 48,385 $ 130,375 $ 166,726
</TABLE>
In December 1992, the Company acquired certain producing
properties located in north central Wyoming from a major oil company
for $56.1 million. An initial cash payment of $6.3 million was made
in December 1992. The remaining $49.8 million was recorded as senior
debt on the consolidated balance sheet at December 31, 1992, but not
reflected on the Company's cash flow statement as an acquisition
until payment was made in February 1993. Costs incurred above also
differ from the cash flow statement as a result of certain cost
recoveries and accrual items. The remaining 1992 acquisitions were
primarily for producing properties in Wyoming, North Dakota and
Texas. In May 1993, the Company purchased an interest in 121
producing wells and over 70 drilling locations in the DJ Basin of
Colorado for $3.3 million. In July 1993, an incremental 25% interest
in the Company's Barrel Springs and Duck Lake Fields was purchased
for $6.1 million. In August 1993, the Company acquired interests in
225 producing wells and 272 undeveloped locations in the DJ Basin for
$19.7 million. In late 1993, two acquisitions were completed in the
Piceance and Uinta Basins of Western Colorado for a total of $12.5
million. A number of other producing and undeveloped acquisitions
totalling $9.4 million were completed during 1993 as well, mostly in
or close to the Company's principal operating areas. In late 1992,
the Company initiated projects to further develop its gas gathering
and processing facilities. A $4.5 million DJ Basin low pressure
gathering system expansion was completed to provide new sources of
inlet gas to the Roggen plant. Simultaneously, a $2.0 million
expansion at Roggen raised plant capacity by 60% to 55 MMcf per day.
An additional $848,000 was expended in 1992 to acquire a Roggen net
profits interest and a pipeline in the area. In 1993, the Company
expended $9.4 million toward the second phase of its DJ Basin
gathering expansion to construct a high pressure line to deliver gas
directly to the major gas processing plant in the area and expand its
gathering network for the increased drilling activity. A total of
$5.6 million in additional transportation and gathering facilities
were constructed in 1993 in the DJ Basin including a nine mile 16"
diameter interconnect line completed in October to relieve high line
pressures, a 20" diameter western gathering extension and numerous
other extensions and connections. In 1993, the Roggen plant was
further enhanced with $2.6 million of capital expenditures. The
Company expended $1.4 million to complete construction of a system to
gather gas from its Nebraska drilling project. A number of lesser
facilities were purchased in 1993 to expand the Company's gathering
and processing capabilities in its active hub areas.
Acquisitions are accounted for utilizing the purchase method. The
following unaudited pro forma information shows the effect on the
consolidated statements of operations assuming that the 1992
significant acquisitions were consummated as of January 1, 1992.
Individual 1993 acquisitions did not meet the significance test,
therefore no 1993 pro forma information is presented. Future results
may differ substantially from pro forma results due to changes in oil
and gas prices, production declines and other factors. Therefore,
pro forma statements cannot be considered indicative of future
operations.
<TABLE>
<CAPTION>
(In thousands, except per share data) Year Ended
December31,
1992
(Unaudited)
<S> <C>
Revenues $ 152,739
Net income 26,992
Income per share before accounting change .81
Net income per share .98
Weighted average shares outstanding 22,722
</TABLE>
(6) STOCKHOLDERS' EQUITY
A total of 75 million common shares, $.01 par value, are
authorized of which 23.3 million were issued and outstanding at
December 31, 1993. In 1992, the Company issued 234,000 shares and
repurchased 215,000 shares. 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. The Company made five quarterly dividend
payments of $.05 per share in 1992 due to an acceleration in the
quarterly payment date. In 1993, the Company paid first and second
quarter dividends of $.05 per share and increased dividends to $.06
per share in the third and fourth quarters.
A total of 10 million preferred shares, $.01 par value, are
authorized. In December 1991, 1.2 million shares of convertible
exchangeable preferred stock were sold through an underwriting. The
net proceeds were $57.4 million. The preferred stock carries an 8%
dividend and is convertible into common stock at $9.07 per share.
The stock is exchangeable at the option of the Company for 8%
convertible subordinated debentures on any dividend payment date.
The stock is redeemable at the option of the Company on or after
December 31, 1994. The liquidation preference is $50.00 per share,
plus accrued and unpaid dividends. During 1995, the stock is
redeemable at $52.50 per share if the closing price exceeds 150% of
the prevailing conversion price (currently $13.61 per share) for 20
of the preceding 30 trading days. After 1995, no minimum stock price
is required. The redemption price declines $.50 per year to $50.00
per share in 2000. In 1993, 14,000 preferred shares were converted
into 77,000 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 convertible preferred stock were sold through an underwriting.
The net proceeds were $99.3 million. The preferred stock carries a
6% dividend and is convertible into common stock at $21.00 per share.
The stock is exchangeable at the option of the Company for 6%
convertible subordinated debentures on any dividend payment date on
or after March 31, 1994. The 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 $4.8 million and $9.1 million, respectively, in
preferred dividends during 1992 and 1993.
The Company maintains a stock option plan for Company employees
providing for the issuance of options at prices not less than fair
market value. Options to acquire up to 3 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, 1993, 1.4 million options were outstanding under
both plans at exercise prices of $4.53 to $19.25 per share. At
December 31, 1993, a total of 600,000 of such options were vested
having exercise prices of $4.53 to $13.00 per share. During 1992,
223,000 options were exercised at prices of $3.02 to $6.00 per share,
and 52,000 were forfeited. During 1993, 309,000 options were
exercised at prices of $4.53 to $9.13 per share, and 23,000 were
forfeited.
(7) FEDERAL INCOME TAXES
The Company adopted FASB Statement No. 109, "Accounting for Income
Taxes," effective January 1, 1992. Net income for 1992 was increased
by $3.8 million for the cumulative effect of the change in method of
accounting for income taxes as a result of tax basis in excess of
financial basis. At December 31, 1993, 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:
<TABLE>
<CAPTION>
1991 1992 1993
<S> <C> <C> <C>
Federal statutory rate 34% 34% 35%
Utilization of net deferred tax asset - (32%) (13%)
Excess basis amortization and other (11%) - (1%)
Effective income tax rate 23% 2% 21%
</TABLE>
For book purposes the components of the Company's net deferred
asset and liability at December 31, 1992 and 1993, respectively,
were:
<TABLE>
<CAPTION>
1992 1993
<S> <C> <C>
Deferred tax assets
NOL carryforwards $ 12,466 $ 24,193
AMT credit carryforwards 1,350 1,350
Reserves and other 115 1,522
13,931 27,065
Deferred tax liabilities
Depreciable and depletable property (7,267) (32,544)
Accruals and other (1,977) (141)
(9,244) (32,685)
Deferred asset (liability) 4,687 (5,620)
Valuation allowance (4,687) -
Net deferred asset (liability) $ - $ (5,620)
</TABLE>
For tax purposes, the Company had net operating loss
carryforwards of $69.1 million at December 31, 1993. These
carryforwards expire between 1997 and 2008. At December 31, 1993,
the Company had alternative minimum tax credit carryforwards of $1.4
million and depletion carryforwards of $1.1 million, both of which
are available indefinitely. Current income taxes shown in the
financial statements reflect estimates of alternative minimum taxes
due. Cash payments during 1992 and 1993 were $1.0 million and
$75,000, respectively.
(8) SALES TO MAJOR CUSTOMERS
In 1991, 1992 and 1993, Amoco Production Company accounted for
17%, 27% and 12%, 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.
(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 October 1992, and at first
payout in June 1993 the second contribution of $1.5 million was
received. An additional $1.5 million was received in October 1993.
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 of this revenue during
1992 and $3.8 million during 1993.
(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 $2.1 million for 1994, $2.2
million for 1995, $2.3 million for 1996 and 1997, and $2.1 million
for 1998.
In 1990, the Company was granted a judgment in litigation
regarding a disputed leasehold assignment from the early 1980's. The
Oklahoma Supreme Court refused certiorari and the judgment was
upheld. As a result, a total of $1.7 million was accrued and
reported in other income in 1993. The full amount was collected in
January 1994. In April 1992, the Company was granted a judgment in
a gas contract dispute related to an offshore property. The dispute
was settled in April 1993 by an agreement to pay the Company a net of
$5.3 million. The Company received theses monies in 1993 and
reflected $3.5 million as other income with the remaining $1.8
million recorded as a liability for possible contingencies. 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 or final judicial determination.
(11) UNAUDITED SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION:
Independent petroleum consultants directly evaluated 51%,
74%, and 62% of proved reserves at December 31, 1991, 1992 and 1993,
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.
<TABLE>
<CAPTION>
Quantities of Proved Reserves - Crude Oil Natural Gas
(MBbl) (MMcf)
<S> <C> <C>
Balance, December 31, 1990 19,414 241,163
Revisions ( 3,653) (22,105)
Extensions, discoveries and additions 3,070 50,065
Production (1,487) (18,382)
Purchases 2,663 1,354
Sales (329) (4,926)
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
</TABLE>
<TABLE>
<caption
Proved Developed Reserves - Crude Natural
Oil Gas
(MBbl) (MMcf)
<S> <C> <C>
December 31, 1990 9,571 128,282
December 31, 1991 9,094 136,229
December 31, 1992 21,116 194,621
December 31, 1993 18,032 268,349
</TABLE>
<TABLE>
<CAPTION>
Standardized Measure - December 31,
1992 1993
(In thousands)
<S> <C> <C>
Future cash inflows $ 1,129,376 $ 1,272,649
Future costs:
Production (a) (430,507) (415,867)
Development (140,734) (168,510)
Future net cash flows 558,135 688,272
10% discount factor (231,853) (297,863)
Discounted future net cash flows 326,282 390,409
Discounted income taxes (42,710) (49,891)
Standardized measure $ 283,572 $ 340,518
<FN>
(a) Future production costs have been reduced by $6.1 million and $937,000 as of
December 31, 1992 and 1993, 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.
</TABLE>
<TABLE>
<CAPTION>
Changes in Standardized Measure -
Year Ended December 31,
1991 1992 1993
(In thousands)
<S> <C> <C> <C>
Standardized measure, beginning of year $ 248,409 $ 210,903 $ 283,572
Revisions:
Prices and costs (90,380) (a) (624) (70,433) (a)
Quantities (25,176) (a) (22,760) 6,632 (a)
Development costs (1,852) 6,952 16,379
Accretion of discount 24,841 21,090 28,357
Income taxes 29,175 (10,043) (7,181)
Production rates and other (9,200) (7,443) (14,281)
Net revisions (72,592) (12,828) (40,527)
Extensions, discoveries and additions 48,302 48,417 57,782
Production (38,647) (50,965) (85,700)
Future development costs incurred 21,150 33,846 67,959
Purchases (b) 11,311 62,007 60,752
Sales (c) (7,030) (7,808) (3,320)
Standardized measure, end of year $ 210,903 $ 283,572 $ 340,518
<FN>
(a) In 1991 and 1993 $24.5 million and $27.0 million, respectively, in revisions were included under
"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.
</TABLE>
<PAGE>
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S SECURITIES AND RELATED
SECURITY HOLDER MATTERS
The Company's stock is listed on the New York Stock Exchange.
The common stock began trading under the symbol "SNY" in March 1990.
The Company's $4.00 Convertible Exchangeable Preferred Stock
("$ 4 Convertible Preferred Stock") began trading on the New York
Stock Exchange under the symbol "SNY Pr" in November 1991.
Depositary shares representing a quarter interest in the Company's $6.00
Convertible Exchangeable Preferred Stock ("$6 Convertible Preferred Stock")
began trading on the New York Stock Exchange under the symbol "SNY Pr A"
on April 14, 1993. Prior to those dates, there were no markets for these
securities. The following table sets forth, for 1992 and 1993,
the high and low sales prices for the Company's securities for New York
Stock Exchange composite transactions reported by The Wall Street Journal.
<TABLE>
<CAPTION>
Common Stock
1992 1993
High Low High Low
<S> <C> <C> <C> <C>
First Quarter $6-7/8 $5-7/8 $16-1/8 $10
Second Quarter 7-3/8 6-1/8 20-1/4 15
Third Quarter 10-1/2 6-3/8 23 16-5/8
Fourth Quarter 10-1/8 8-5/8 23 14-3/4
</TABLE>
<TABLE>
<CAPTION>
$4 Convertible Preferred Stock
1992 1993
High Low High Low
<S> <C> <C> <C> <C>
First Quarter $50 $46-1/4 $93-1/2 $64
Second Quarter 50-5/8 46-1/2 112 85
Third Quarter 65-3/4 50 126-1/4 100-1/2
Fourth Quarter 64 57-3/4 123-1/4 100
</TABLE>
<TABLE>
<CAPTION>
$6 Convertible Preferred Stock (Depositary Shares)
1992 1993
High Low High Low
<S> <C> <C> <C> <C>
First Quarter - - - -
Second Quarter - - $29 $25
Third Quarter - - 31-3/4 25
Fourth Quarter - - 31-3/4 25
</TABLE>
On March 9, 1994, the closing price of the common stock was
$19-1/2. Dividends were paid quarterly at the rate of $.05 per share
in 1992. Due to revised payment timing, two payments were made at
the $.05 rate in the second quarter of 1992. Dividends were paid at
the rate of $.05 per share in the first and second quarter of 1993.
In the third quarter of 1993, dividends were increased to $.06 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
the Company's preferred stock, capital expenditures and other
factors. On December 31, 1993, there were approximately 3,500
holders of record of the common stock and 23.3 million shares
outstanding.
On March 9, 1994 the closing price of the $4 Convertible
Preferred Stock was $106. Shares of $4 Convertible Preferred Stock
receive quarterly dividends of $1.00 if declared by the Board of
Directors. Any cumulative dividends in arrears must be paid prior to
payment of any dividends on the common stock. On December 31, 1993,
there were 24 holders of record of the $4 Convertible Preferred Stock
and 1.2 million shares outstanding. The $4 Convertible Preferred
Stock may be called beginning on January 1, 1995 at a price of $52.50
per share.
On March 9, 1994 the closing price of the depositary shares
representing the $6 Convertible Preferred Stock was $27-7/8. Each
depositary share represents a one-quarter interest in a share of $100
liquidation value $6 Convertible Preferred Stock. Shares of $6
Convertible Preferred Stock receive quarterly dividends of $1.50
($.375 per depositary share) if declared by the Board of Directors.
A dividend was paid June 30, 1993 at the rate of $1.17 per share
($.29 per depositary share), reflecting a partial rate since issuance
in April 1993. Any cumulative dividends in arrears must be paid
prior to payment of any dividends on the common stock. On December
31, 1993 there were 43 holders of records of the $6 Convertible
Preferred Stock and 4.1 million depositary shares outstanding. The
$6 Convertible Preferred Stock may be called beginning on March 31,
1996 at a price of $104.10 per share ($26.05 per depositary share).
ITEM 6. SELECTED FINANCIAL DATA
The following table presents selected financial and operating
information for each of the five years ended December 31, 1993.
Share and per share amounts refer to common shares. The following
information should be read in conjunction with the financial
statements presented elsewhere herein.
<TABLE>
<caption
(In thousands, except per share data) As of or for the Year Ended December 31,
1989 1990 1991 1992 1993
<S> <C> <C> <C> <C> <C>
Income Statement
Revenues $ 26,543 $ 82,173 $ 92,501 $120,172 $229,885
Income before accounting change
and extraordinary items 4,832 7,515 8,811 16,875 27,608
Per share .43 .36 .37 .53 .80
Net income 6,921 7,515 8,811 20,638 25,664
Per share .62 .36 .37 .70 .72
Dividends Per share .11 .16 .20 .25(a) .22
Average shares outstanding 11,135 20,620 22,839 22,722 23,096
Cash Flow
Net cash provided by operations $ 11,129 $ 22,512 $ 37,738 $ 47,911 $ 68,293
Capital expenditures 14,216 171,767(b) 48,385 130,375 166,726
Balance Sheet
Working capital $ 3,499 $ 12,087 $ 17,259 $ 7,619 $ 1,291
Oil and gas properties, net 29,904 179,902 196,206 287,094 388,361
Total assets 56,669 227,198 252,241 346,737 479,536
Senior debt 2,325 56,172 17,108 96,568(c) 114,952
Subordinated notes, net 2,477(d) 25,000 25,000 18,750 -
Stockholders' equity 31,149 115,187 174,696 184,393 297,241
<FN>
(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.
(d) Represents exchangeable preferred equity which was converted into
subordinated notes in May 1990.
</TABLE>
<PAGE>
The following table sets forth unaudited summary financial
results on a quarterly basis for the two most recent years.
<TABLE>
<CAPTION>
(In thousands, except per share data) 1992 Quarters
First Second Third Fourth
<S> <C> <C> <C> <C>
Revenues $ 26,913 $ 27,949 $ 29,956 $ 35,354
Gross margin 13,741 14,708 15,125 18,072
Depletion, depreciation and amortization 7,490 8,213 7,290 8,951
Income before effect of accounting change 3,304 3,040 4,519 6,012
Per share .09 .08 .15 .21
Net income 7,067 3,040 4,519 6,012
Per share .26 .08 .15 .21
</TABLE>
<TABLE>
<CAPTION>
1993 Quarters
First Second Third Fourth
<S> <C> <C> <C> <C>
Revenues $ 44,873 $ 58,276 $ 61,288 $65,448
Gross margin 22,201 25,342 26,818 25,783
Depletion, depreciation and amortization 11,831 14,562 11,412 13,379
Income before extraordinary item 6,367 6,537 6,623 8,081
Per share (a) .23 .18 .17 .23
Net income 5,983 6,537 6,161 6,983
Per share (a) .21 .18 .15 .19
<FN>
(a) Quarters do not equal year-to-date totals due to rounding.
</TABLE>
<PAGE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
Results of Operations
Comparison of 1993 results to 1992. Total revenues rose 91% in
1993 to $229.9 million. Net income before taxes and extraordinary
items more than doubled to reach $34.9 million in 1993. The increase
was led by a rapid rise in production and assisted by an increase in
gas processing and transportation margins. Before the effect of a
favorable $3.8 million income tax accounting change in 1992 and a
$1.9 million 1993 extraordinary charge on early retirement of debt,
earnings per common share were $.80 in 1993 compared to $.53 in 1992,
a 51% increase.
The gross margin from production operations for 1993 increased 62%
to $79.7 million, which was primarily related to a 65% growth in oil
and gas production. The price received per equivalent barrel
decreased by 3% to $13.41. Total operating expenses including
production taxes increased 60% during 1993 although operating cost
per equivalent barrel ("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 1993 operating
costs averaged $7.45 per BOE.
For the year ended December 31, 1993, average daily production per
BOE was 25,472 Bbls, a 65% increase from 1992. Average daily
production in the fourth quarter of 1993 climbed to 10,314 barrels
and 105.6 MMcf (27,917 barrels of oil equivalent). The production
increases resulted primarily from acquisitions and continuing
development drilling in the DJ Basin of Colorado. Domestically,
$51.0 million in properties were acquired in 1993, primarily in and
around existing hubs in Colorado and Wyoming. The acquisitions
included a significant number of development locations and should
continue to add to production into 1994. In 1993, 311 wells were
placed on production in the DJ Basin, with 51 wells in various stages
of drilling and completion at yearend. Because the majority of the
wells were added in the latter part of the year, production will not
be fully impacted until 1994. Additionally, significant downtime was
experienced in the fourth quarter at the major processing plant in
the area and much of the gas had to be diverted, which increased line
pressures and hampered production. To a lesser extent, this
situation continued into early 1994.
The gross margin from gas processing, transportation and marketing
activities for 1993 increased 23% to $10.0 million from $8.1 million
in 1992. The increase was primarily attributable to a $3.0 million
(33%) rise in transportation and processing margins as a result of
additional DJ Basin production and the recent 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. In 1993 the net
contract margin was a loss of $267,000, which was $1.8 million less
than 1992. At present gas price levels, the Company foresees
continued negative or breakeven margins for the cogeneration contract
through July 1994. At that time, the share of the sales price
minimum attributable to gas will increase from 45% to 65% and the
margin should improve. The cogeneration margin reduction was
partially offset by a $667,000 (126%) rise in other gas marketing
margins resulting from increased third party marketing.
Other income was $10.4 million during 1993, compared to $4.2
million in 1992. The $6.2 million increase resulted from a $3.5
million gas contract settlement received in April, a $1.7 million
litigation judgment and greater gains on the sales of securities.
General and administrative expenses, net of reimbursements, for 1993
represented 3% of revenues compared to 5.6% in 1992 as expenses were
held essentially flat while revenues grew 91%. Interest and other
expenses increased 28% primarily as a result of a rise in outstanding
debt balances. Senior debt was paid down in April 1993 with proceeds
from a preferred offering, but increased through yearend as a result
of development expenditures, acquisitions, the investment in Command
Petroleum and the retirement of the $25.0 million in subordinated
debt.
Depletion, depreciation and amortization during 1993 increased 60%
from the prior year. The increase was the direct result of the 65%
rise in equivalent production between years. The producing depletion
rate per equivalent barrel for 1993 was reduced to $4.75 from $4.79
in 1992. The rate was reduced by an ongoing drilling cost reduction
program, partially offset by an increase from the discontinuation of
converting Thomasville production to equivalent quantities based on
relative gas prices.
The Company adopted FASB Statement No. 109, "Accounting for Income
Taxes," effective January 1, 1992. Net income for 1992 was increased
by $3.8 million for the cumulative effect of the change in method of
accounting for income taxes. In 1992 the income tax provision was
reduced from the statutory rate of 34% by $5.5 million due to the
elimination of deferred taxes as a result of tax basis in excess of
financial basis. In 1993 the income tax provision was reduced from
the newly enacted rate of 35% by $4.7 million upon full realization
of the excess basis benefit. The Company anticipates deferred taxes
will be provided in 1994 and beyond based on the full statutory rate.
Comparison of 1992 results to 1991. Revenues rose 30% in 1992 to
$120.2 million, compared to $92.5 million in 1991. Net income for
1992 was $20.6 million, a 134% jump from the $8.8 million in 1991.
The increases resulted from greater oil and gas production volumes,
lower interest expense, reduced general and administrative expenses
and a $3.8 million reversal of the cumulative effect of prior year
deferred taxes with the adoption of a change in the method of
accounting for income taxes.
Average daily production for 1992 rose 24% to 15,408 equivalent
barrels due mostly to development drilling in the DJ Basin of
Colorado as 189 wells were placed on production there. As a result,
the gross margin from production increased 22% to $49.3 million in
1992. The price per equivalent barrel of oil and gas production
decreased 4% during 1992.
The gross margin from gas processing, transportation and marketing
activities for 1992 increased 12% to $8.1 million from $7.3 million
in 1991. The growth was primarily the result of increased marketing
of third party gas in New Mexico, Colorado and Wyoming. Gas
processing and transportation margins increased moderately as volumes
were increased late in the year by expansions of pipeline and plant
facilities to take advantage of increasing DJ Basin production.
Other income for 1992 decreased 26% to $4.2 million from a reduction
in gains on sales of securities and lower interest on notes
receivable.
Direct operating expenses including production taxes increased
only 13% during 1992 as the operating cost per equivalent barrel
decreased to $4.99 from $5.47 in 1991, due to increased DJ Basin
production where operating costs have been significantly lower than
average. General and administrative expenses, net of reimbursements,
for 1992 represented less than 6% of revenues compared to 8% in 1991,
as revenues rose 30%. Interest and other expenses dropped 39% in
1992 due to lower average outstanding senior debt after the
application of proceeds from a preferred stock offering in late 1991.
Development, Acquisition and Exploration
During 1993 the Company incurred $93.1 million for oil and gas
property development and exploration, $51.0 million for acquisitions
and $22.6 million for gas facility expansion and other assets, for a
total of $166.7 million in property and equipment expenditures.
Additionally, the Company made an $18.2 million investment in an
Australian based exploration and production company.
The Company has concentrated a significant portion of its
development activities in the DJ Basin of Colorado. Capital
expenditures for DJ Basin development totalled $75.4 million during
1993. A total of 311 newly drilled wells were placed on production
there in 1993 and 51 were in progress at yearend. Additionally, 42
recompletions were performed in 1993, with seven in process at
yearend. In December 1993, 16 drilling rigs were in operation in the
DJ Basin. The Company anticipates putting 500 or more wells per year
on production in the DJ Basin for the next few years. With
additional leasing activity and through drilling costs reductions
that add infill locations as proven as they become economic, the
Company has increased the inventory of available drillsites. In
December, the Company entered into a letter of intent with Union
Pacific Resources Corporation whereby the Company will gain the right
to drill wells on UPRC's previously uncommitted acreage throughout
the Wattenberg area. This transaction significantly increased the
Company's undeveloped Wattenberg inventory. UPRC will retain a
royalty and the right to participate as a 50% working interest owner
in each well, and received grants for warrants to purchase two
million shares of Company stock. Of the warrants, one million expire
three years from the date of grant, and are exercisable at $25 per
share, while the other one million expire in four years and are
exercisable at $27 per share. One year from the date of grant
(February 8, 1994), the exercise prices may be reduced to 120% of the
average closing price of the Company stock for the preceding 20
consecutive trading days, but not to lower than an exercise price of
$21.60 per share. At that time the expiration date of the warrants
may also be extended one year if the average closing price over the
20 day trading period is less than $16.50 per share.
The Company expended $14.8 million for other development and
recompletion projects and $2.9 million for exploration during 1993.
In Nebraska, 29 wells were added to production in 1993 as an
extension of a drilling program initiated in 1992. An additional 20
wells are planned in Nebraska for 1994. In southern Wyoming, 11
wells in the East Washakie Basin development program were
successfully drilled and completed during the last half of 1993 with
three in process at yearend. In this program, significant cost-
cutting measures were applied based on the experience gained in the
DJ Basin. In central Wyoming on the properties acquired from ARCO in
late 1992, efforts have been focused on increasing operating
efficiency with limited development drilling and workover activity.
In 1993, three successful wells were drilled in the fourth quarter
and selected development and recompletion activity is scheduled for
1994. In the Piceance Basin of western Colorado, a three well test
program was started in December of 1993 on acreage acquired there
during the year, with one well undergoing completion, the second in
progress and a third scheduled for early 1994. Current plans include
a minimum of 25 wells in the basin during 1994. In South Texas, a
combined operated and non-operated program was initiated, with nine
wells completed in 1993 and one well abandoned. A total of 25
additional horizontal locations have been identified and drilling
should continue with as many as 15 wells planned in 1994. In its
domestic exploration efforts, the Company initiated a seismic program
in Louisiana and began drilling early in the fourth quarter.
Advanced seismic techniques are being used to identify further
prospects in Louisiana and expectations are to drill up to 20 wells
in 1994.
A total of $51.0 million in domestic acquisitions were completed
in 1993. In May 1993, the Company purchased an interest in 121
producing wells and over 70 drilling locations in the DJ Basin area
for $3.3 million. In July, an incremental 25% interest in the
Company's Barrel Springs and Duck Lake Fields in Wyoming was
purchased for $6.1 million. The properties are 90% gas and include
44 producing wells and 46 undeveloped locations. In August, the
Company acquired interests in 225 producing wells and 272 proved
undeveloped locations in the DJ Basin for $19.7 million. The proved
reserves are 70% gas with more than two-thirds requiring future
development to produce. Late in the year, two acquisitions were
completed in the Piceance and Uinta Basins of Western Colorado for a
total of $12.5 million. The majority of the value was in undeveloped
locations as only 128 wells were currently producing. Numerous other
producing and undeveloped acquisitions totalling $9.4 million were
completed, mostly in or close to the Company's principal operating
areas.
The Company's gas gathering and processing facilities have been
undergoing significant transformation since late 1992. In 1993, the
Company expended $20.1 million to further develop its gas related
assets. The Company spent $9.4 million toward the second phase of
its DJ Basin gathering expansion to construct a high pressure line to
deliver gas directly to the major gas processing plant in the area
and expand its gathering network for the increased drilling activity.
An additional $2.6 million was expended to expand the Roggen Plant
for the production increases. A total of $5.6 million in additional
transportation and gathering facilities were constructed in the DJ
Basin including a nine mile 16" interconnect line completed in
October to relieve high line pressures, a 20" western gathering
extension and numerous other extensions and connections. A gathering
system that delivers third party gas to the Roggen Plant was
purchased for $703,000. The Company expended $1.4 million to
complete construction of a system to gather gas from its Nebraska
drilling project. These projects are intended to take advantage of
the significant increase in drilling activity in these areas.
In the international arena, progress continues as well. In May
1993, the Company acquired 42.8% of the outstanding shares of Command
Petroleum Holdings N.L., an Australian exploration and production
company, for $18.2 million. The Sydney based company is listed on
the Australian Stock Exchange, and at December 31, 1993 had 950,000
barrels of proven oil reserves and $19.9 million of working capital.
In addition, it holds interests in more than 20 exploration permits
and licenses and a 28.7% interest in a Netherlands exploration and
production company whose assets are located primarily in the North
Sea. In Russia, the Permtex joint venture received central
government approval in August and the Company executed a finance and
insurance protocol with the Overseas Private Investment Corporation
("OPIC"), a United States government agency. Current plans call for
25 of the existing 45 shut-in wells to be placed on production in
1994, and that 400 development wells will be drilled over the next
ten years. Extensive seismic work began in the fourth quarter of
1993 for 400 kilometers of data in Tunisia and 500 kilometers in
Mongolia.
Financial Condition and Capital Resources
At December 31, 1993, the Company had total assets of $480 million
and working capital of $1.3 million. Total capitalization was $412
million, of which 28% was represented by senior debt and the
remainder by stockholders' equity. During 1993, the Company fully
retired its $25 million of 13.5% subordinated notes and the related
cumulative participating interests. During 1993, cash provided by
operations was $68.3 million, an increase of 43% over 1992. As of
December 31, 1993, commitments for capital expenditures totalled $7.5
million, primarily for DJ Basin drilling. The level of 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, proceeds from property dispositions and existing credit
facilities. In addition, joint ventures or future public and private
offerings of securities may be utilized.
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 October 1992, and at first
payout in June 1993 the second contribution of $1.5 million was
received. An additional $1.5 million was received in October 1993.
This transaction should increase the Company's cash flow and net
income through 1994. 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 $3.8 million of this
revenue during 1993. Discussions are in progress to expand this
transaction so that the benefits would be extended through at least
1996.
In April 1993, the Company sold 4.1 million depositary shares
(each representing a one quarter interest in one share of $100
liquidation value stock) of convertible preferred stock through an
underwriting for $103.5 million. A portion of the net proceeds of
$99.3 million was used to retire the entire outstanding balance under
the revolving credit facility at that time. The preferred stock pays
a 6% dividend and is convertible into common stock at $21.00 per
share. At the Company's option, the preferred stock is exchangeable
into 6% convertible debentures on any dividend payment date on or
after March 31, 1994. The stock is redeemable at the option of the
Company on or after March 31, 1996.
Effective July 1, 1993, the Company renegotiated its bank credit
facility and increased it from $150 million to $300 million. The new
facility is divided into a $50 million short-term portion and a $250
million long-term portion that expires on December 31, 1997.
However, management's policy is to renew the facility annually.
Credit availability is adjusted semiannually to reflect changes in
reserves and asset values. At December 31, 1993, the elected
borrowing base was $150 million. The majority of the borrowings
currently bear interest at LIBOR plus 1.25% with the remainder at
prime. The Company also has the option to select CD plus 1.375%.
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. Based on such limitations, $86.5 million would have
been available for the payment of dividends and other restricted
payments as of December 31, 1993. The Company does not currently
plan to make, and is not committed to make, any advances or
contributions to unrestricted subsidiaries that would materially
affect its ability to pay dividends under this limitation.
During 1993, the Company fully retired its $25.0 million of 13.5%
subordinated notes and the related cumulative participating
interests. An extraordinary charge to earnings of $1.9 million (net
of income taxes) was made in 1993, representing the amount paid in
excess of principal and accrued interest through the retirement
dates. These notes were retired early in order to reduce the
Company's ongoing cost of debt.
The Company maintains a program to divest marginal properties and
assets which do not fit its long range plans. For 1992 and 1993,
proceeds from these sales were $3.0 million and $5.5 million,
respectively. Included in the 1993 proceeds were $4.0 million of
cash receipts previously accrued for late 1992 sales. The Company
intends to continue to evaluate and dispose of nonstrategic assets.
In 1990, the Company was granted a judgment in litigation
regarding a leasehold assignment from the early 1980's. The Oklahoma
Supreme Court refused certiorari and the judgment was upheld. As a
result, a total of $1.7 million was accrued and reported in other
income in 1993. The full amount was collected in January 1994. In
April 1992, a jury found for the plaintiffs in a gas contract dispute
related to an offshore property. In April 1993, the dispute was
settled by an agreement to pay the Company a net of $5.3 million.
The initial $3.5 million was received and reflected as other income
in second quarter 1993. The remaining $1.8 million was received in
third quarter 1993, but reflected as a reserve for possible
contingencies. 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 financial
statements reflect these judgments only upon receipt of cash or final
judicial determination.
The Company believes that its capital resources are more than
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. While
such fluctuations have had, and will continue to have a material
effect, the Company is unable to predict them.
The following table indicates the average oil and gas prices
received over the last five years and highlights the price
fluctuations by quarter for 1992 and 1993. Average gas prices
exclude the Thomasville gas production. During 1993, the Company
renegotiated its Thomasville gas contract and beginning in January
1994, the Company will receive a somewhat higher than market price
for its Thomasville gas sales, significantly below its 1993 average
price of $12.16 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. Equivalent
prices prior to 1993 have been restated to reflect elimination of the
conversion of Thomasville gas volumes based on its price relative to
the Company's other gas production.
<TABLE>
<CAPTION>
Average Prices
Crude Oil Per
and Natural Equivalent
Liquids Gas Barrel
(Per Bbl) (Per Mcf)
<S> <C> <C> <C>
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
Quarterly
1992
First $ 17.80 $ 1.56 $ 12.66
Second 19.72 1.53 13.28
Third 20.18 1.70 13.94
Fourth 17.98 2.13 14.96
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
</TABLE>
In December 1993, the Company was receiving an average of $12.54
per barrel and $2.27 per Mcf (excluding the Thomasville contract) for
its production. Beginning in December 1992, the average oil price
was effectively reduced by the oil production added from the Wyoming
acquisition, which sells at a significant discount to West Texas
Intermediate posting due to the presence of low gravity sour crude in
two of the fields.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTAL DATA
Reference is made to the Index to Financial Statements on page
35 for financial statements and notes thereto. Supplementary
schedules are presented at the end of Part III following page 55.
Quarterly financial data is presented on page 28 of this Form 10-K.
Schedules I, III, IV, VII, VIII, IX, XI, XII, and XIII 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.
<PAGE>
<TABLE>
<caption
SNYDER OIL CORPORATION
INDEX TO FINANCIAL STATEMENTS AND SCHEDULES
Page
<S> <C>
Report of Independent Public Accountants . . . . . . . . . . . . . 36
Consolidated Balance Sheets as of December 31, 1992 and 1993 . . . 37
Consolidated Statements of Operations for the years ended
December 31, 1991, 1992 and 1993 . . . . . . . . . . . . . . . . 38
Consolidated Statements of Changes in Stockholders' Equity
for the years ended December 31, 1991, 1992 and 1993 . . . . . . 39
Consolidated Statements of Cash Flows
for the years ended December 31, 1991, 1992 and 1993 . . . . . . 40
Notes to Consolidated Financial Statements . . . . . . . . . . . . 41
Schedules:
Schedule II - Amounts Receivable From Employees and Related
Parties. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 55
Schedule V - Property. . . . . . . . . . . . . . . . . . . . . . 56
Schedule VI - Accumulated Depletion, Depreciation and
Amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . 57
Schedule X - Supplementary Income Statement Information . . . . 58
</TABLE>
<PAGE>
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 1992, 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,
1993. These financial statements and the schedules referred to below
are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements
and schedules 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
1992, and the results of their operations and their cash flows for
each of the three years in the period ended December 31, 1993, in
conformity with generally accepted accounting principles.
As explained in Note 7 to the financial statements, effective
January 1, 1992, the Company changed its method of accounting for
income taxes.
Our audits were made for the purpose of forming an opinion on
the basic financial statements taken as a whole. The schedules
listed in the index to financial statements and schedules are
presented for purposes of complying with the Securities and Exchange
Commission's rules and are not a part of the basic financial
statements. These schedules have been subjected to the auditing
procedures applied in our audits of the basic financial statements
and, in our opinion, fairly state in all material respects the
financial data required to be set forth therein in relation to the
basic financial statements taken as a whole.
ARTHUR ANDERSEN & CO.
Forth Worth, Texas
February 25, 1994
<PAGE>
<TABLE>
<CAPTION>
SNYDER OIL CORPORATION
CONSOLIDATED BALANCE SHEETS (Notes 1 and 2)
(In thousands)
December 31,
1992 1993
ASSETS
<S> <C> <C>
Current assets
Cash and equivalents $ 20,485 $ 10,913
Accounts receivable 31,219 47,472
Other 553 3,407
52,257 61,792
Investments (Note 4) 7,386 29,383
Oil and gas properties, full cost method (Note 5) 338,908 468,764
Accumulated depletion, depreciation and amortization (82,005) (126,123)
256,903 342,641
Gas processing and transportation facilities (Note 5) 37,420 60,015
Accumulated depreciation (7,229) (14,295)
30,191 45,720
$ 346,737 $ 479,536
</TABLE>
LIABILITIES AND STOCKHOLDERS' EQUITY
<TABLE>
<S> <C> <C>
Current liabilities
Accounts payable $ 25,512 $ 37,247
Accrued liabilities 12,861 23,239
Current portion of debt (Note 3) 6,265 15
44,638 60,501
Other liabilities 574 458
Senior debt, net (Notes 3 and 5) 96,568 114,952
Subordinated notes (Note 3) 18,750 -
Deferred taxes and credits (Note 9) 1,814 6,384
Commitments and contingencies (Note 10)
Stockholders' equity (Note 6)
Preferred stock, $.01 par, 10,000,000 shares authorized,
8% preferred stock, 1,200,000 and 1,186,005 shares
issued and outstanding 12 12
6% preferred stock, none and 1,035,000 shares
issued and outstanding - 10
Common stock, $.01 par, 75,000,000 shares authorized,
22,873,743 and 23,259,658 issued and outstanding 229 233
Capital in excess of par value 148,670 250,574
Retained earnings 35,482 46,954
Foreign currency translation - (542)
184,393 297,241
$ 346,737 $ 479,536
<FN>
The accompanying notes are an integral part of these statments.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
SNYDER OIL CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS (Notes 1 and 2)
(In thousands except per share data)
Year Ended December 31,
1991 1992 1993
<S> <C> <C> <C>
Revenues (Note 8)
Oil and gas sales $ 65,344 $ 77,363 $ 124,641
Gas processing and transportation 21,459 38,611 94,839
Other 5,698 4,198 10,405
92,501 120,172 229,885
Expenses
Direct operating 24,882 28,057 44,901
Cost of gas and transportation 14,202 30,469 84,840
General and administrative 7,259 6,704 6,780
Interest and other 9,327 5,693 7,271
Depletion, depreciation and amortization 25,392 31,944 51,184
Income before taxes, accounting change
and extraordinary item 11,439 17,305 34,909
Provision for income taxes (Note 7)
Current 230 430 -
Deferred 2,398 - 7,301
2,628 430 7,301
Income before accounting change
and extraordinary item 8,811 16,875 27,608
Cumulative effect of change in
accounting for income taxes (Note 7) - 3,763 -
Extraordinary item - early extinguishment of debt,
net of taxes of $1,038 (Note 3) - - (1,944)
Net income 8,811 20,638 25,664
Dividends on preferred stock (453) (4,800) (9,100)
Net income available to common $ 8,358 $ 15,838 $ 16,564
Net income per share (Note 2)
Before accounting change and extraordinary item $ .37$ .53$ .80
Accounting change and extraordinary item - .17 (.08)
Total $ .37$ .70$ .72
Weighted average shares outstanding (Note 6) 22,839 22,722 23,096
<FN>
The accoumpnaying notes are an integral part of these statements.
</TABLE>
<PAGE>
<TABLE>
<caption
SNYDER OIL CORPORATION
CONSOLIDATED STATEMENTS OF CHANGES IN
STOCKHOLDERS' EQUITY (Notes 1, 2 and 6)
(In thousands)
Capital in
Preferred Stock Common Stock Excess of Retained
Shares Amount Shares Amount Par Value Earnings
<S> <C> <C> <C> <C> <C> <C>
Balance, December 31, 1990 - - 23,131 $ 231 $ 93,420 $ 21,536
Issuance of preferred 1,200 12 - - 57,396 -
Issuance of common - - 68 - 104 -
Repurchase of common - - (344) (3) (1,797) -
Dividends - - - - - (5,014)
Net income - - - - - 8,811
Balance, December 31, 1991 1,200 12 22,855 228 149,123 25,333
Issuance of common - - 234 2 807 -
Repurchase of common - - (215) (1) (1,260) -
Dividends - - - - - (10,489)
Net income - - - - - 20,638
Balance, December 31, 1992 1,200 12 22,874 229 148,670 35,482
Issuance of preferred 1,035 10 - - 99,315 -
Common stock grants and
exercise of options - - 309 3 2,590 -
Conversion of preferred
to common (14) - 77 1 (1) -
Dividends - - - - - (14,192)
Net income - - - - - 25,664
Balance, December 31, 1993 2,221$ 22 23,260$ 233$ 250,574 $ 46,954
<FN>
The accompanying notes are an integral part of these statements.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
SNYDER OIL CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS (Notes 1 and 2)
(In thousands)
Year Ended December 31,
1991 1992 1993
>s> <C> <C> <C> >
Operating activities
Net income $ 8,811 $ 20,638 $ 25,664
Adjustments to reconcile net income to net cash
provided by operations
Depletion, depreciation and amortization 25,392 31,944 51,184
Deferred taxes 2,398 - 7,301
Extraordinary item -
early extinguishment of debt - - 1,944
Change in accounting for income taxes - (3,763) -
Gain on sale of securities (1,626) (777) (2,283)
Amortization of deferred credits - (780) (3,846)
Changes in operating assets and liabilities
Decrease (increase) in
Accounts receivable 1,623 (4,669) (22,397)
Other current assets 161 211 (3,354)
Increase (decrease) in
Accounts payable 553 6,395 11,953
Accrued liabilities 1,067 (1,352) 2,227
Other liabilities (663) (63) (116)
Other 22 127 16
Net cash provided by operations 37,738 47,911 68,293
Investing activities
Acquisition, development and exploration (46,557) (78,165) (193,829)
Proceeds from investments 2,895 3,582 8,378
Outlays for investments (2,383) (1,626) (27,594)
Sale of properties 4,925 2,992 5,547
Net cash used by investing (41,120) (73,217) (207,498)
Financing activities
Issuance of common 104 722 1,528
Issuance of preferred 57,486 - 99,325
Increase in indebtedness 27 29,700 68,159
Repayments of indebtedness (39,380) (187) (25,000)
Premium on debt extinguishment - - (2,983)
Dividends (5,053) (10,489) (14,192)
Deferred credits - 2,594 2,796
Repurchase of common (1,916) (1,261) -
Net cash realized by financing 11,268 21,079 129,633
Increase (decrease) in cash 7,886 (4,227) (9,572)
Cash and equivalents, beginning of year 16,826 24,712 20,485
Cash and equivalents, end of year $ 24,712 $ 20,485 $ 10,913
<FN>
The accompanying notes are an integral part of these statements.
</TABLE>
SNYDER OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) ORGANIZATION AND NATURE OF BUSINESS
Snyder Oil Corporation (the "Company") is engaged in the
acquisition, production, development and to a lesser degree
exploration of primarily domestic oil and gas properties. The
Company is also involved in gas processing, transportation, gathering
and marketing. The Company, a Delaware corporation, is the successor
to a company formed in 1978. 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.
(2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The consolidated financial statements include the accounts of
Snyder Oil Corporation and its subsidiaries (collectively, the
"Company"). 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.
The Company follows the "full cost" accounting method. All costs
of exploration and development are capitalized as incurred.
Depletion, depreciation and amortization ("depletion") is provided on
the unit-of-production method based on proved reserves. Gas is
converted to equivalent barrels at the rate of six Mcf per barrel.
The depletion rates per equivalent barrel produced were $4.68, $4.79
and $4.75, respectively, in 1991, 1992 and 1993. In 1993, the
practice of converting Thomasville production to equivalent
quantities based on its price relative to other gas production was
discontinued. No gains or losses are recognized upon the disposition
of oil and gas properties except in extraordinary transactions.
Proceeds are credited to the carrying value of the properties.
Maintenance and repairs are expensed. Expenditures which enhance the
value of the properties are capitalized. Depreciation on gas
processing and transportation facilities is generally provided on a
straight-line basis over 15 years.
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
received. The affiliate's functional currency is the Australian
dollar. The reported foreign currency translation adjustment is the
result of the translation of the Australian balance sheet into United
States dollars at year-end and the related impact of exchange rates
subsequent to purchase.
All highly liquid investments with a maturity of three months or
less are considered to be cash equivalents. Earnings per share are
computed based on the weighted average number of common shares
outstanding. Differences between primary and fully diluted earnings
per share were insignificant for all periods presented. General and
administrative expenses are reduced by reimbursements for well
operations, drilling and management of partnerships. Reimbursements
amounted to $11.1 million, $14.3 million and $17.8 million,
respectively, in 1991, 1992 and 1993.
Certain amounts in the 1991 and 1992 financial statements have
been reclassified to conform with the 1993 presentation.
(3) INDEBTEDNESS
The following indebtedness was outstanding on the respective
dates:
<TABLE>
<CAPTION>
December 31,
1992 1993
(In thousands)
<S> <C> <C>
Revolving credit facility $ 46,700 $ 114,901
Other 49,883 66
96,583 114,967
Less current portion (15) (15)
Senior debt, net $ 96,568 $ 114,952
Subordinated notes 25,000 -
Less current portion (6,250) -
Subordinated debt, net $ 18,750 $ -
</TABLE>
The Company maintains a $300 million revolving credit facility.
The facility is divided into a $250 million long-term portion and a
$50 million short-term portion. However, management's policy is to
renew the facility annually. The elected borrowing base available
under the facility at December 31, 1993 was $150 million. The
majority of the borrowings currently bear interest at LIBOR plus
1.25% with the remainder at prime. During 1993, the average
borrowing cost was 4.9%. The Company pays certain fees based on the
borrowing base and outstanding loans. 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. At December 31, 1992, the Company
recorded the $49.8 million Wyoming acquisition commitment as other
senior debt. The cash flow statement did not reflect the commitment
as an increase in indebtedness until final payment was disbursed in
February 1993.
The subordinated notes bore interest at 13.5% and were due in four
annual payments commencing November 15, 1993. The notes were subject
to optional redemption at 102% of principal after November 1994 and
at par after November 1995. Cumulative rights to receive additional
interest based on net cash flow above certain minimum levels were
issued in connection with the notes. Cash flow has substantially
exceeded the minimum since 1991, and the Company has since made the
maximum payments. At December 31, 1992, based on existing market
rates the subordinated notes and cumulative interest rights had a
combined fair value of $27.7 million, which the Company believes
approximated its cost of funds for notes with similar terms. In
March 1993, the Company retired 40% of the cumulative rights. The
portion of the payment representing prepaid interest was expensed as
an extraordinary item, net of income taxes, for $384,000. In August
1993, the Company retired $10 million (40%) of the subordinated
notes. The portion of the payment representing prepaid interest was
expensed as an extraordinary item, net of income taxes, for $462,000.
In November 1993, the Company retired the remaining $15 million of
the subordinated notes and the related 60% of cumulative rights, with
the portion of the payment representing prepaid interest expensed as
an extraordinary item, net of income taxes, for $1.1 million. The
Company expensed $1.1 million, $1.1 million and $516,000 as interest
expense for cumulative rights in 1991, 1992 and 1993, respectively.
Scheduled maturities of indebtedness are $15,000 for 1994, $17,000
for 1995 and 1996, and $114.9 million in 1997. The long-term portion
of the revolving credit facility is scheduled to expire in 1997;
however, management's policy is to renew the facility annually.
Cash payments for interest expense were $7.9 million, $5.4 million
and $9.2 million, respectively, for 1991, 1992 and 1993.
(4) INVESTMENTS
The Company has investments in foreign and domestic energy
companies and notes receivable, which at December 31, 1992 and 1993,
had a total book value of $7.4 million and $29.4 million,
respectively, with corresponding fair market values of $9.8 million
and $54.2 million.
In May 1993, the Company acquired 92 million (42.8%) of the
outstanding shares of Command Petroleum Holdings N.L. ("Command"), an
Australian exploration and production company, for $18.2 million.
The Sydney based company is listed on the Australian Stock Exchange,
and holds interests in more than 20 exploration permits and licenses
as well as a 28.7% interest in a publicly traded Netherlands
exploration and production company whose assets are located primarily
in the North Sea. The market value of the Company's investment in
Command based on Command's closing price at December 31, 1993 was
$39.1 million. The investment is accounted for by the equity method.
Command has outstanding stock options covering the issuance of up to
53.3 million common shares that expire November 30, 1994. Given that
the exercise price of the options is 44% below the year-end stock
price, the Company assumes they will be exercised. In January 1994,
Command completed an offering of 43 million of its common shares. As
a result of this offering, the Company's ownership was reduced to
35.7%. If, as expected, all of the November 1994 options were
exercised, the Company's ownership would be reduced to 29.6%.
The Company has investments in securities of publicly traded
domestic energy companies, not accounted for by the equity method,
having a book value and total cost at December 31, 1992 and 1993 of
$680,000 and $9.7 million, respectively. The market value of these
securities at December 31, 1992 and 1993 approximated $2.9 million
and $13.3 million, respectively. In the first quarter of 1994, the
Company will be required to adopt SFAS No. 115, "Accounting for
Certain Investments in Debt and Equity Securities." Under the
provisions of SFAS No. 115, at December 31, 1993 the Company would
have increased its investments by $3.6 million and increased
stockholders' equity by $2.3 million and deferred tax liability by
$1.3 million.
The Company holds $1.8 million in notes receivable due from
privately held corporations. All notes are secured by certain
assets, including stock and oil and gas properties. At December 31,
1992 and 1993, the fair value of the notes receivable, based on
existing market conditions and the anticipated future net cash flow
related to the notes, was believed to be equal to their book value.
(5) OIL AND GAS PROPERTIES
The cost of oil and gas properties at December 31, 1992 and 1993
includes $4.0 million and $9.8 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:
<TABLE>
<CAPTION>
1991 1992 1993
<S> <C> <C> <C>
Acquisition $ 9,910 $ 63,629 $ 50,997
Development 32,163 53,665 90,182
Gas processing, transportation and other 4,442 11,158 22,595
Exploration 1,870 1,923 2,952
$ 48,385 $ 130,375 $ 166,726
</TABLE>
In December 1992, the Company acquired certain producing
properties located in north central Wyoming from a major oil company
for $56.1 million. An initial cash payment of $6.3 million was made
in December 1992. The remaining $49.8 million was recorded as senior
debt on the consolidated balance sheet at December 31, 1992, but not
reflected on the Company's cash flow statement as an acquisition
until payment was made in February 1993. Costs incurred above also
differ from the cash flow statement as a result of certain cost
recoveries and accrual items. The remaining 1992 acquisitions were
primarily for producing properties in Wyoming, North Dakota and
Texas. In May 1993, the Company purchased an interest in 121
producing wells and over 70 drilling locations in the DJ Basin of
Colorado for $3.3 million. In July 1993, an incremental 25% interest
in the Company's Barrel Springs and Duck Lake Fields was purchased
for $6.1 million. In August 1993, the Company acquired interests in
225 producing wells and 272 undeveloped locations in the DJ Basin for
$19.7 million. In late 1993, two acquisitions were completed in the
Piceance and Uinta Basins of Western Colorado for a total of $12.5
million. A number of other producing and undeveloped acquisitions
totalling $9.4 million were completed during 1993 as well, mostly in
or close to the Company's principal operating areas. In late 1992,
the Company initiated projects to further develop its gas gathering
and processing facilities. A $4.5 million DJ Basin low pressure
gathering system expansion was completed to provide new sources of
inlet gas to the Roggen plant. Simultaneously, a $2.0 million
expansion at Roggen raised plant capacity by 60% to 55 MMcf per day.
An additional $848,000 was expended in 1992 to acquire a Roggen net
profits interest and a pipeline in the area. In 1993, the Company
expended $9.4 million toward the second phase of its DJ Basin
gathering expansion to construct a high pressure line to deliver gas
directly to the major gas processing plant in the area and expand its
gathering network for the increased drilling activity. A total of
$5.6 million in additional transportation and gathering facilities
were constructed in 1993 in the DJ Basin including a nine mile 16"
diameter interconnect line completed in October to relieve high line
pressures, a 20" diameter western gathering extension and numerous
other extensions and connections. In 1993, the Roggen plant was
further enhanced with $2.6 million of capital expenditures. The
Company expended $1.4 million to complete construction of a system to
gather gas from its Nebraska drilling project. A number of lesser
facilities were purchased in 1993 to expand the Company's gathering
and processing capabilities in its active hub areas.
Acquisitions are accounted for utilizing the purchase method. The
following unaudited pro forma information shows the effect on the
consolidated statements of operations assuming that the 1992
significant acquisitions were consummated as of January 1, 1992.
Individual 1993 acquisitions did not meet the significance test,
therefore no 1993 pro forma information is presented. Future results
may differ substantially from pro forma results due to changes in oil
and gas prices, production declines and other factors. Therefore,
pro forma statements cannot be considered indicative of future
operations.
<TABLE>
<CAPTION>
(In thousands, except per share data) Year Ended
December31,
1992
(Unaudited)
<S> <C>
Revenues $ 152,739
Net income 26,992
Income per share before accounting change .81
Net income per share .98
Weighted average shares outstanding 22,722
</TABLE>
(6) STOCKHOLDERS' EQUITY
A total of 75 million common shares, $.01 par value, are
authorized of which 23.3 million were issued and outstanding at
December 31, 1993. In 1992, the Company issued 234,000 shares and
repurchased 215,000 shares. 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. The Company made five quarterly dividend
payments of $.05 per share in 1992 due to an acceleration in the
quarterly payment date. In 1993, the Company paid first and second
quarter dividends of $.05 per share and increased dividends to $.06
per share in the third and fourth quarters.
A total of 10 million preferred shares, $.01 par value, are
authorized. In December 1991, 1.2 million shares of convertible
exchangeable preferred stock were sold through an underwriting. The
net proceeds were $57.4 million. The preferred stock carries an 8%
dividend and is convertible into common stock at $9.07 per share.
The stock is exchangeable at the option of the Company for 8%
convertible subordinated debentures on any dividend payment date.
The stock is redeemable at the option of the Company on or after
December 31, 1994. The liquidation preference is $50.00 per share,
plus accrued and unpaid dividends. During 1995, the stock is
redeemable at $52.50 per share if the closing price exceeds 150% of
the prevailing conversion price (currently $13.61 per share) for 20
of the preceding 30 trading days. After 1995, no minimum stock price
is required. The redemption price declines $.50 per year to $50.00
per share in 2000. In 1993, 14,000 preferred shares were converted
into 77,000 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 convertible preferred stock were sold through an underwriting.
The net proceeds were $99.3 million. The preferred stock carries a
6% dividend and is convertible into common stock at $21.00 per share.
The stock is exchangeable at the option of the Company for 6%
convertible subordinated debentures on any dividend payment date on
or after March 31, 1994. The 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 $4.8 million and $9.1 million, respectively, in
preferred dividends during 1992 and 1993.
The Company maintains a stock option plan for Company employees
providing for the issuance of options at prices not less than fair
market value. Options to acquire up to 3 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, 1993, 1.4 million options were outstanding under
both plans at exercise prices of $4.53 to $19.25 per share. At
December 31, 1993, a total of 600,000 of such options were vested
having exercise prices of $4.53 to $13.00 per share. During 1992,
223,000 options were exercised at prices of $3.02 to $6.00 per share,
and 52,000 were forfeited. During 1993, 309,000 options were
exercised at prices of $4.53 to $9.13 per share, and 23,000 were
forfeited.
(7) FEDERAL INCOME TAXES
The Company adopted FASB Statement No. 109, "Accounting for Income
Taxes," effective January 1, 1992. Net income for 1992 was increased
by $3.8 million for the cumulative effect of the change in method of
accounting for income taxes as a result of tax basis in excess of
financial basis. At December 31, 1993, 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:
<TABLE>
<CAPTION>
1991 1992 1993
<S> <C> <C> <C>
Federal statutory rate 34% 34% 35%
Utilization of net deferred tax asset - (32%) (13%)
Excess basis amortization and other (11%) - (1%)
Effective income tax rate 23% 2% 21%
</TABLE>
For book purposes the components of the Company's net deferred
asset and liability at December 31, 1992 and 1993, respectively,
were:
<TABLE>
<CAPTION>
1992 1993
<S> <C> <C>
Deferred tax assets
NOL carryforwards $ 12,466 $ 24,193
AMT credit carryforwards 1,350 1,350
Reserves and other 115 1,522
13,931 27,065
Deferred tax liabilities
Depreciable and depletable property (7,267) (32,544)
Accruals and other (1,977) (141)
(9,244) (32,685)
Deferred asset (liability) 4,687 (5,620)
Valuation allowance (4,687) -
Net deferred asset (liability) $ - $ (5,620)
</TABLE>
For tax purposes, the Company had net operating loss
carryforwards of $69.1 million at December 31, 1993. These
carryforwards expire between 1997 and 2008. At December 31, 1993,
the Company had alternative minimum tax credit carryforwards of $1.4
million and depletion carryforwards of $1.1 million, both of which
are available indefinitely. Current income taxes shown in the
financial statements reflect estimates of alternative minimum taxes
due. Cash payments during 1992 and 1993 were $1.0 million and
$75,000, respectively.
(8) SALES TO MAJOR CUSTOMERS
In 1991, 1992 and 1993, Amoco Production Company accounted for
17%, 27% and 12%, 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.
(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 October 1992, and at first
payout in June 1993 the second contribution of $1.5 million was
received. An additional $1.5 million was received in October 1993.
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 of this revenue during
1992 and $3.8 million during 1993.
(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 $2.1 million for 1994, $2.2
million for 1995, $2.3 million for 1996 and 1997, and $2.1 million
for 1998.
In 1990, the Company was granted a judgment in litigation
regarding a disputed leasehold assignment from the early 1980's. The
Oklahoma Supreme Court refused certiorari and the judgment was
upheld. As a result, a total of $1.7 million was accrued and
reported in other income in 1993. The full amount was collected in
January 1994. In April 1992, the Company was granted a judgment in
a gas contract dispute related to an offshore property. The dispute
was settled in April 1993 by an agreement to pay the Company a net of
$5.3 million. The Company received theses monies in 1993 and
reflected $3.5 million as other income with the remaining $1.8
million recorded as a liability for possible contingencies. 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 or final judicial determination.
(11) UNAUDITED SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION:
Independent petroleum consultants directly evaluated 51%,
74%, and 62% of proved reserves at December 31, 1991, 1992 and 1993,
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.
<TABLE>
<CAPTION>
Quantities of Proved Reserves - Crude Oil Natural Gas
(MBbl) (MMcf)
<S> <C> <C>
Balance, December 31, 1990 19,414 241,163
Revisions ( 3,653) (22,105)
Extensions, discoveries and additions 3,070 50,065
Production (1,487) (18,382)
Purchases 2,663 1,354
Sales (329) (4,926)
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
</TABLE>
<TABLE>
<caption
Proved Developed Reserves - Crude Natural
Oil Gas
(MBbl) (MMcf)
<S> <C> <C>
December 31, 1990 9,571 128,282
December 31, 1991 9,094 136,229
December 31, 1992 21,116 194,621
December 31, 1993 18,032 268,349
</TABLE>
<TABLE>
<CAPTION>
Standardized Measure - December 31,
1992 1993
(In thousands)
<S> <C> <C>
Future cash inflows $ 1,129,376 $ 1,272,649
Future costs:
Production (a) (430,507) (415,867)
Development (140,734) (168,510)
Future net cash flows 558,135 688,272
10% discount factor (231,853) (297,863)
Discounted future net cash flows 326,282 390,409
Discounted income taxes (42,710) (49,891)
Standardized measure $ 283,572 $ 340,518
<FN>
(a) Future production costs have been reduced by $6.1 million and $937,000 as of
December 31, 1992 and 1993, 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.
</TABLE>
<TABLE>
<CAPTION>
Changes in Standardized Measure -
Year Ended December 31,
1991 1992 1993
(In thousands)
<S> <C> <C> <C>
Standardized measure, beginning of year $ 248,409 $ 210,903 $ 283,572
Revisions:
Prices and costs (90,380) (a) (624) (70,433) (a)
Quantities (25,176) (a) (22,760) 6,632 (a)
Development costs (1,852) 6,952 16,379
Accretion of discount 24,841 21,090 28,357
Income taxes 29,175 (10,043) (7,181)
Production rates and other (9,200) (7,443) (14,281)
Net revisions (72,592) (12,828) (40,527)
Extensions, discoveries and additions 48,302 48,417 57,782
Production (38,647) (50,965) (85,700)
Future development costs incurred 21,150 33,846 67,959
Purchases (b) 11,311 62,007 60,752
Sales (c) (7,030) (7,808) (3,320)
Standardized measure, end of year $ 210,903 $ 283,572 $ 340,518
<FN>
(a) In 1991 and 1993 $24.5 million and $27.0 million, respectively, in revisions were included under
"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.
</TABLE>
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
*
ITEM 11. MANAGEMENT AND REMUNERATION
*
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT
*
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
*
*The information required in these four items is incorporated by reference
to the Company's definitive Proxy Statement for its 1994 Annual Meeting
of Stockholders, which will be filed with the SEC no later than April
30, 1994.
<PAGE>
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 beenomitted 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
to the Registrant's Registration Statement on Form S-4
(Registration No.33-33455).
4.1.3 - Certificate of Amendment to Certificate ofIncorporation of
Registrant filed May 22, 1991 -incorporated by reference from
Exibit 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 ofIncorporation 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 - Certificate of Designations, Powers, Preferences and
Rights of the Registrant's $4.00 Convertible Exchange
Preferred Stock - incorporated by reference from Exhibit 3.1.3
to the Registrant's Annual Report on Form 10-K
for the year ended December 31, 1991 (File No.1-10509).
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 nonemployee
Directors - incorporated by reference from Exhibit 10.4 to the
Retistrant's Registration Statment 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 Quartly Report on Form 10-Q
for the quarterended 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).
<PAGE>
10.3 - SOCO Holdings Inc. 1984 Stock Option Plan -incorporated by
reference from Exhibit 10.6 to the Registrant's Registration
Statement of Form S-4 (Registration No. 33-33455).
10.3.1 - Amendment to SOCO Holdings Inc. 1984 Stock Option Plan
dated July 18, 1985 - incorporated by reference
from Exhibit 10.6.1 to the Registrant's Registration Statement
on Form S-4 (Registration No. 33-33455).
10.3.2 - Amendment to SOCO Holdings Inc. 1984 Stock Option Plan
dated May 24, 1988 - incorporated by reference from Exhibit
10.6.2 to the Registrant's Registration Statement on Form S-4
(Registration No. 33-33455).
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).
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 Quartly Report
on Form 10-Q forthe 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.*
10.9 - Purchase and Sale Agreement dated December 11, 1992
between Atlantic Richfield Company and Registrant -
incorporated by reference to the Report on 8-K dated
December 11, 1992 (File No. 1-8440).
10.10 - Warrant dated February 8, 1994 issued by Registrant to
Union Pacific Resource Company.*
11.1 - Computation of Per Share Earnings.*
22.1 - Subsidiaries of the Registrant - incorporated byreference
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 & Co.*
23.2 - Consent of Netherland, Sewell & Associates, Inc.*
28.1 - Report of Netherland, Sewell & Associates, Inc. dated
February 10, 1994 relating to certain of the Registrant's
property interest.*
28.2 - 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 1993
* Filed herewith.
<PAGE>
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the Registrant has duly caused the
report to be signed on its behalf by the undersigned
thereunto duly authorized.
/s/ John C. Snyder Director and Chairman of the Board
John C. Snyder (Principal Executive Officer) March 11, 1994
/s/ Thomas J. Edelman Director and President
Thomas J. Edelman Principal Financial Officer) March 11, 1994
/s/ John A. Fanning Director and Executive
John A. Fanning Vice President March 11, 1994
/s/ Roger W. Brittain Director
Roger W. Brittain March 11, 1994
/s/ John A. Hill Director
John A. Hill March 11, 1994
/s/ B. J. Kellenberger Director
B. J. Kellenberger March 11, 1994
/s/ John H. Lichtblau Director
John H. Lichtblau March 11, 1994
/s/ James E. McCormick Director
James E. McCormick March 11, 1994
/s/ Alfred M. Micallef Director
Alfred M. Micallef March 11, 1994
/s/ James H. Shonsey Vice President and Controller
James H. Shonsey Principal Accounting Officer) March 11, 1994
<PAGE>
<TABLE>
Schedule II
SNYDER OIL CORPORATION
AMOUNTS RECEIVABLE FROM EMPLOYEES AND RELATED PARTIES
For the Years Ended December 31, 1991, 1992 and 1993
(In thousands)
<CAPTION>
Balance at
Balance at Deductions End of Period
Beginning Amounts Amounts Not
of Period Additions Collected written Off Current Current
<S> <C> <C> <C> <C> <C> <C>
For the year ended December 31, 1991
Thomas J. Edelman $ 100 (a)$ - $ 21 $ - $ 24 $ 55
John A. Fanning 153 (b) - 21 - 26 106
B. J. Kellenberger - 800 (c) - - 20 780
$ 253 $ 800 $ 42 $ - $ 70 $ 941
For the year ended December 31, 1992
Thomas J. Edelman $ 79 $ 680 (d)$ 79$ - $ 600 $ 80
John A. Fanning 132 - 132 - - -
B. J. Kellenberger 800 - 33 - 200 567
$ 1,011 $ 680 $ 244 $ - $ 800 $ 647
For the year ended December 31, 1993
Thomas J. Edelman $ 680 $ - $ 680 $ - $ - $ -
John A. Fanning - - - - - -
B.J. Kellenberger 767 - 767 - - -
$ 1,447 $ - $ 1,447 $ - $ - $ -
<FN>
(a)10% per annum note due October 1994 with annual principal and interest payments
(b)10% per annum note due June 1996 with monthly principal and interest payments
(c)12% per annum notes:
$400,000 due October 1994 with monthly principal and interest payments
$400,000 due November 1994 with monthly interest payments
(d) 7% per annum notes:
$600,000 with principal and interest due March 1993
$80,000 due October 1995 with quarterly interest payments
</TABLE>
<PAGE>
<TABLE>
Schedule V
SNYDER OIL CORPORATION
PROPERTY
For the Years Ended December 31, 1991, 1992 and 1993
(In thousands)
<CAPTION>
Other
Balance at Additions Retirements Changes Balance at
Beginning of Period At Cost Or Sales Add (Deduct) End of Period
<S> <C> <C> <C> <C> <C>
For the year ended
December 31, 1991
Oil and gas properties $ 189,988 $ 43,943 $ (6,693) $ - $ 227,238
Processing and
transportation
facilities 21,820 4,442 - - 26,262
$ 211,808 $ 48,385 $ (6,693) $ - $ 253,500
For the year ended
December 31, 1992
Oil and gas properties $ 227,238 $ 119,217 $ (7,547) $ - $ 338,908
Processing and
transportation
facilities 26,262 11,158 - - 37,420
$ 253,500 $ 130,375 $ (7,547) $ - $ 376,328
For the year ended
December 31, 1993
Oil and gas properties $ 338,908 $ 144,131 $ (14,275) $ - $ 468,764
Processing and
transportation
facilities 37,420 22,595 - - 60,015
$ 376,328 $ 166,726 $ (14,275) $ - $ 528,779
</TABLE>
<PAGE>
<TABLE>
Schedule VI
SNYDER OIL CORPORATION
ACCUMULATED DEPLETION, DEPRECIATION AND AMORTIZATION
For the Years Ended December 31, 1991, 1992 and 1993
(In thousands)
<CAPTION>
Other
Balance at Additions Retirements Changes Balance at
Beginning of Period At Cost Or Sales Add (Deduct) End of Period
<S> <C> <C> <C> <C> <C>
For the year ended December 31, 1991
Oil and gas properties $ 29,895 $ 23,115 $ - $ - $ 53,010
Processing and transportation
facilities 2,011 2,273 - - 4,284
$ 31,906 $ 25,388 $ - $ - $ 57,294
For the year ended December 31, 1992
Oil and gas properties $ 53,010 $ 28,693 $ - $ 302 $ 82,005
Processing and transportation
facilities 4,284 3,247 - (302) 7,229
$ 57,294 $ 31,940 $ - $ - $ 89,234
For the year ended December 31, 1993
Oil and gas properties $ 82,005 $ 44,118 $ - $ - $ 126,123
Processing and transportation
facilities 7,229 7,066 - - 14,295
$ 89,234 $ 51,184 $ - $ - $ 140,418
</TABLE>
<PAGE>
<TABLE>
Schedule X
SNYDER OIL CORPORATION
SUPPLEMENTARY INCOME STATEMENT INFORMATION
For the Years Ended December 31, 1991, 1992 and 1993
(In thousands)
<CAPTION>
Charged to Expense
1991 1992 1993
<S> <C> <C> <C>
Taxes, other than payroll and income taxes-
Production and ad valorem taxes $ 4,923 $ 6,621 $ 10,229
</TABLE>
AGREEMENT dated as of April 30, 1993
between SNYDER OIL CORPORATION, a Delaware corporation
("SOCO"), and Edward T. Story ("Story")
SOCO and Story are parties to a letter agreement dated July 19, 1991
and an agreement dated November 15, 1991 (the "Prior Agreements") ,
relating to the capitalization and management of SOCO International,
Inc., a Delaware corporation ("International"). Pursuant to the Prior
Agreements:
SOCO owns 900 shares of common stock, and Story owns 100 shares
of common stock (the "Story Shares"), of International,
constituting all the outstanding shares of International.
Story has the option (the "Story Option") to purchase from SOCO
additional shares of common stock of International representing
up to 25% of the outstanding shares of common stock of
International.
Story holds a note (the "Story Note") dated November 15, 1991 of
International in the principal amount of $100,000, under which
Story has advanced $27,778 to International.
SOCO holds a note (the "SOCO Note") dated November 15, 1991 of
International in the principal amount of $900,000, under which
SOCO has made an initial advance of $250,000 and has from time
to time advanced additional sums to International.
Story and SOCO have each agreed to make additional loans to
International under the Story Note and the SOCO Note at the
request of International.
SOCO and Story wish to modify the arrangements provided for in the
initial agreements as set forth herein.
Accordingly, SOCO and Story agree as follows:
1. Purchase of Story Shares and Story Note; Cancellation of Story
Option and Prior Agreements. On May 20, 1993 or such other mutually
acceptable day not later than 30 days after approval of this
Agreement by the Board of Directors of SOCO, but effective April 30,
1993, SOCO will purchase the Story Shares and the Story Note for an
aggregate purchase price of $27,878. In that regard, (a) SOCO will
deliver a check payable to Story in the amount of $27,878 and (b)
Story is delivering a certificate representing the Story Shares and
the Story Note to SOCO, in each case duly endorsed for transfer to
SOCO. Simultaneously with such deliveries, and without any further
action on the part of SOCO or Story, the Prior Agreements, including
the Story Option, will be canceled and will no longer have any force
or effect.
2. Issuance of New Option. Subject to the purchase of the Story
Shares and Story Note pursuant to Section 1, SOCO hereby grants to
Story an option to purchase from SOCO 100 of the shares of common
stock of International (being equal to 10% of the shares of common
stock held by SOCO immediately after giving effect to the purchase of
the Story Shares) at an aggregate exercise price of $590,500 on the
following terms:
(a) The option shall expire at the close of business on April
30, 1998 (the "Expiration Time"). The option may be exercised by
Story in whole but not in part, by written notice to SOCO
received by SOCO prior to the Expiration Time. Any such notice
shall be accompanied by (i) a certified or bank check payable to
SOCO in the amount of the exercise price and (ii) a statement
that Story is acquiring the shares for his own account for
purposes of investment, and that Story recognizes that the
shares are not registered under the federal Securities Act of
1993, as amended, that the shares cannot be sold unless so
registered or pursuant to an exemption from such registration
requirement and that the certificate representing the shares
will bear a legend to that effect.
(b) If International makes a dividend payable in the form of
shares of common stock, or combines or subdivides the
outstanding shares of common stock, the number of shares subject
to the option shall be adjusted so that the number of shares
subject to the option after such event shall be equal to the
number of shares of common stock Story would have been entitled
to receive had the option been exercised immediately prior to
the record date of such dividend or effective date of such
combination or subdivision. SOCO will give Story prompt notice
of any adjustments pursuant to this paragraph.
(c) If International (i) makes a distribution on the common
stock in the form of debt instruments, cash (except dividends
out of retained earnings) or other assets or (ii) consolidates
with or merges with any person (except any consolidation or
merger which does not result in the exchange or cancellation of
the common stock of International), sells all or substantially
all its assets or liquidates, SOCO will give notice thereof to
Story at least 30 days before the record date of such
distribution or the effective date of such consolidation, merger
or sale. Unless Story exercises the option prior to such record
date or effective date, as the case may be, Story shall have no
right to receive any of the debt instruments, cash or other
assets distributed or consideration received in such merger,
consolidation, sale or liquidation and, in if an event described
in clause (ii) of the preceding sentence occurs, the option will
terminate.
(d) If any or all of the shares of common stock held by SOCO
are to be redeemed by International or sold by SOCO (it being
understood that SOCO shall have the absolute right to sell any
or all its shares or other investment in International, subject
only to SOCO's obligations under this paragraph), SOCO will give
Story written notice thereof at least 30 days before such event
occurs. If Story exercises the option prior to the time such
event occurs, he shall have the right and, if requested by SOCO,
the obligation to participate proportionately with SOCO in such
redemption or sale (i.e., assuming Story participates in all
future sales of International stock to SOCO pursuant to Section
3 of this Agreement, 90% of the shares redeemed or sold shall
have been owned by SOCO and 10% of the shares redeemed or sold
shall have been owned by Story).
(e) As long as the option remains exercisable, services
provided by SOCO and its affiliates to International and other
transactions between SOCO and its affiliates and International
will be on terms that SOCO in good faith believes to be
commercially reasonable under the circumstances. All loans or
advances made by SOCO or its affiliates to International will
bear simple interest at the rate of 1% per month.
3. Right to Participate in Certain Stock Sales. If, in its
discretion, SOCO elects to invest additional equity into
International through the purchase of additional shares of common
stock, SOCO will determine the terms of such purchase based on SOCO's
assessment of the "fair value" of the shares at the time of the
investment. SOCO will give Story 30 days' written notice of any such
proposed purchase of additional shares of common stock of
International, which notice will set forth the number of shares to be
purchased, the purchase price per share and the date of the purchase.
Story will have the right, which may be exercised by irrevocable
written notice from Story to SOCO received not less than 15 days
before the date of purchase specified in SOCO's notice, to
participate in such purchase and purchase 10% of the number of
additional shares to be purchased by SOCO at the purchase price per
share specified in SOCO's notice. By written notice to Story at any
time prior to the completion of the proposed purchase, SOCO will have
the right to alter the terms of, or cancel, the purchase, provided
that, if Story shall have elected to participate in the purchase and
SOCO shall have increased the aggregate purchase price of the shares
to be purchased (by increasing the number of shares, the price per
share, or both), Story will have the right, for five business days
after the receipt of such notice, to elect, by written notice to
SOCO, to withdraw from participation in the purchase.
4. Special Bonus. SOCO agrees that if SOCO Tunisia, Inc. sells all
or part of its interest in its Tunisian concession for cash prior to
August 1, 1993, SOCO will cause International to pay a special bonus
to Story equal to 25% of the excess of International's share (95%) of
the actual cash proceeds received by SOCO Tunisia from such sale over
the transaction costs incurred in connection with such sale and all
costs incurred prior to such sale by International and SOCO Tunisia
related to such concession.
5. Compensation Arrangements. At the May 1993 meeting of SOCO's
Board of Directors, SOCO's management will recommend that (i) Story's
salary be reviewed to assure that it reflects his position in the
SOCO organization and, if the Board determines that a modification is
appropriate, recommend to International that Story's salary be
modified in accordance with the Board's recommendation, (ii) the
Board recommend that International adopt a bonus program for Story
and that International coordinate such bonus program with SOCO's
annual bonus program and (iii) International become a participating
subsidiary in SOCO's 401-k savings and profit sharing plan.
Management will also recommend at such meeting that the Compensation
Committee of SOCO's Board of Directors grant Story options to
purchase shares of common stock of SOCO under SOCO's 1989 Stock
Option Plan in line with Story's position in the SOCO organization
and that, in the discretion of the Compensation Committee, Story be
eligible to receive additional grants from time to time while he is
employed by International. Nothing in this Agreement shall be deemed
a contract of employment or a guarantee of employment or continued
employment.
6. Representations of Story. Story represents that (a) upon
payment therefore in accordance with this Agreement, SOCO will
receive good and marketable title to the Story Shares and the Story
Note and (b) neither the execution, delivery or performance of this
Agreement by Story will violate any contract, agreement, judgment or
order applicable to Story.
7. Representations of SOCO. SOCO represents that (a) upon approval
of this Agreement by SOCO's Board of Directors, this Agreement will
have been duly authorized, executed and delivered by SOCO, (b)
neither the execution, delivery or performance of this Agreement by
SOCO will violate any contract, agreement, judgment or order
applicable to SOCO and (c) upon exercise of the option by Story and
payment of the exercise price, Story will receive good and marketable
title to the shares of International acquired pursuant to such
exercise.
8. No Assignment. This Agreement and the rights, interests and
benefits of Story hereunder may not be assigned, transferred or
hypothecated in any way by Story without the express written consent
of SOCO, except that Story's right to exercise the option provided
for in Section 2 may be transferred by will or the laws of descent.
Any assignment, transfer, hypothecation or delegation contrary to the
foregoing provisions shall be void.
9. Notices. Any notices, payments, revocations or demands under
this Agreement shall be made by hand delivery or certified mail at
the following addresses:
<PAGE>
If to Story, at
Edward T. Story
944 Rochow
Houston, Texas 77019
If to the Company, at
Snyder Oil Corporation
595 Madison Avenue, 27th Floor
New York, New York 10022
Attention: Thomas J. Edelman
and
Snyder Oil Corporation
777 Main Street, Suite 2500
Fort Worth, Texas 76102
Attention: Peter E. Lorenzen
10. Miscellaneous. This Agreement is made or to be performed in
whole or in part, or both, in Texas and shall be governed by, and
shall be construed in accordance with, the laws of the State of Texas
applicable to contracts made and to be performed entirely within such
State. Any claim under or relating to this Agreement shall be filed
only in the courts of Tarrant County, Texas. The waiver by any party
hereto of a breach of any provision of this Agreement by any other
party shall not operate as, or be construed as, a waiver of any other
provision or of any subsequent breach. If any provision of this
Agreement shall be held to be unenforceable or invalid, as contrary
to public policy, law or otherwise, then such provision, or the
invalidity or unenforceability thereof, shall in no way affect the
validity of any other provisions hereof. This Agreement contains the
entire agreement of the parties with respect to the subject matter
hereof, and supersedes any prior agreements, written or oral, between
the parties with respect to such subject matter. This Agreement may
be amended only in writing signed by both parties.
SNYDER OIL CORPORATION EDWARD T. STORY
by John C. Snyder Edward T. Story
John C. Snyder
Chairman
Date: May 19, 1993 Date: May 19, 1993
Neither this Warrant nor the shares of Common Stock issuable
upon exercise of this Warrant have been registered under the
Securities Act of 1933, and this Warrant cannot be exercised, sold or
transferred, and the shares of Common Stock issuable upon exercise of
this Warrant cannot be sold or transferred, unless and until they are
so registered or unless exemption from registration is then
available.
COMMON STOCK PURCHASE WARRANT
To Subscribe for and Purchase the Common Stock of
SNYDER OIL CORPORATION
THIS CERTIFIES that, for value received, UNION PACIFIC RESOURCES
COMPANY, a Delaware corporation ("UPRC"), or its registered assigns
(UPRC and each such assign hereinafter referred to individually as a
"Holder"), is entitled to purchase, subject to the provisions of this
Warrant, from SNYDER OIL CORPORATION, a Delaware corporation
("Snyder"), at any time on or after the date hereof and on or before
the applicable Expiration Date (as defined below), up to an aggregate
amount of 2,000,000 fully paid and nonassessable shares of Common
Stock, par value $.01 per share of Snyder ("Common Stock") at a
purchase price equal to the applicable Warrant Price (as defined
below). This Warrant has been issued in connection with and in
consideration of the transactions contemplated by that certain Joint
Venture Agreement, dated as of February 8, 1994, between UPRC and
Snyder.
This Warrant is subject to the following provisions, terms and
conditions:
Section 1. Exercise of Warrant. Subject to the provisions
hereof, the rights represented by this Warrant may be exercised, in
whole or in part (but not as to a fractional share of Common Stock),
at any time on or after the date hereof and on or before the
Expiration Date, by presentation and surrender hereof at the office
or agency of Snyder maintained for that purpose (the "Warrant office
or agency"), with the Purchase Form annexed hereto duly executed and
accompanied by payment to Snyder or for the account of Snyder, of the
applicable Warrant Price for the number of shares specified in such
form. Snyder shall keep at the Warrant office or agency a register
for the registration and registration of transfer of Warrants. The
Warrant Price for the number of shares of Common Stock specified in
the Purchase Form shall be payable in United States dollars by bank
check or wire transfer of immediately available funds to an account
designated by Snyder for this purpose.
Upon receipt by Snyder of this Warrant at the Warrant office or
agency, in proper form for exercise, the Holder shall be deemed to be
the holder of record of the shares of Common Stock issuable upon such
exercise, as of the close of business on the date on which this
Warrant shall have been surrendered and payment made for the shares
of Common Stock as aforesaid, notwithstanding that the stock transfer
books of Snyder shall then be closed or that certificates
representing such shares of Common Stock shall not then be actually
delivered to the Holder. Snyder shall pay all expenses, and any and
all stamp or similar taxes, that may be payable in connection with
the preparation, issuance and delivery of stock certificates under
this Section 1, except that Snyder shall not be required to pay any
tax which may be payable in respect of any transfer involved in the
issue and delivery of shares of Common Stock in a name other than
that of the Holder who shall have surrendered this warrant in
exercise of the subscription right evidenced hereby and no such
issuance or delivery shall be made unless and until the person
requesting such issuance has paid to Snyder such tax or has
established to the satisfaction of Snyder that such tax has been
paid. All shares of Common Stock issued by Snyder upon exercise of
this Warrant shall be duly authorized and validly issued, fully paid
and nonassessable and free from all taxes, liens and charges with
respect to the issue thereof.
Certificates for the shares of Common Stock purchased pursuant
hereto shall be delivered by Snyder to the Holder hereof within a
reasonable time, not exceeding ten days, after the rights represented
by this Warrant shall have been exercised, and, unless this Warrant
shall have expired or all shares of Common Stock covered hereby shall
have been purchased in accordance herewith, a new Warrant
representing the number of shares, if any, with respect to which this
Warrant shall not then have been exercised shall also be delivered to
the Holder hereof within such time.
Section 2. Reservation of Shares; Preservation of Rights of
Holder. Snyder hereby agrees that, during the period in which the
rights represented by this Warrant may be exercised, there shall be
reserved for issuance and/or delivery upon exercise of this Warrant,
free from preemptive rights, such number of shares of authorized but
unissued or treasury shares of Common Stock as shall be required for
issuance or delivery upon exercise of this Warrant. Snyder further
agrees that it will not, by amendment of its Certificate of
Incorporation or through reorganization, consolidation, merger,
dissolution or sale of assets, or by any other voluntary act, avoid
or seek to avoid the observance or performance of any of the
covenants, stipulations or conditions to be observed or performed
hereunder by Snyder. Without limiting the generality of the
foregoing, Snyder agrees that before taking any action which would
cause an adjustment reducing the Warrant Price below the then par
value of Common Stock issuable upon exercise hereof, Snyder will from
time to time take all such action which may be necessary in order
that Snyder may validly and legally issue fully paid and
nonassessable shares of such Common Stock at the Warrant Price as so
adjusted. Snyder will take all such action as may be necessary to
assure that the shares of Common Stock issued or delivered hereunder
are so issued or delivered without violation of any applicable law or
regulation or of any requirement of any securities exchange upon
which the Common Stock may be listed. Snyder will not take any
action that would result in any adjustment of the Warrant Price if
the total number of shares of Common Stock issuable upon the full
exercise of this Warrant and any other warrants and all shares of
Common Stock issuable upon the exercise of any rights or warrants
issued by Snyder or upon conversion of all stock or securities
convertible into Common Stock then outstanding, would exceed the
total number of shares of Common Stock then authorized by Snyder's
Certificate of Incorporation.
Section 3. Fractional Shares. Snyder shall not be required to
issue fractional shares of Common Stock upon exercise of this Warrant
but shall pay for any such fraction of a share in cash or by
certified or official bank check at the Warrant Price applicable
thereto.
Section 4. Loss of Warrant. Upon receipt by Snyder of evidence
reasonably satisfactory to it of the loss, theft, destruction or
mutilation of this Warrant, and (in the case of loss, theft or
destruction) of reasonably satisfactory indemnification, and upon
surrender and cancellation of this Warrant, if mutilated, Snyder will
execute and deliver a new Warrant of like tenor and date. Any such
new Warrant executed and delivered shall constitute an additional
contractual obligation on the part of Snyder, whether or not this
Warrant so lost, stolen, destroyed or mutilated shall be at any time
enforceable by anyone.
Section 5. Rights of Holder. The Holder shall not, by virtue
hereof, be entitled to any rights as a shareholder of Snyder.
Section 6. Expiration Date. This Warrant shall expire and the
subscription rights provided for herein shall terminate (a) on
February 8, 1997 with respect to one-half of the Warrant Number (as
defined below) of shares of Common Stock issuable hereunder (the "3-
Year Shares"), and (b) on February 8, 1998 with respect to the
remaining one-half of the Warrant Number of shares of Common Stock
issuable hereunder (the "4-Year Shares"); provided that if the market
price per share (determined as provided below) of the Common Stock as
of February 8, 1995 is less than $16.50 per share, the foregoing
dates shall be extended to February 8, 1998 and February 8, 1999 for
the 3-Year Shares and 4-Year Shares, respectively. The Expiration
Dates applicable to the 3-Year Shares and the 4-Year Shares may not
be accelerated for any reason.
Section 7. Initial Warrant Price and Adjustments. The initial
purchase price for the shares of Common Stock issuable hereunder
shall be $25.00 per share for the 3-Year Shares and $27.00 per share
for the 4-Year Shares; provided that each such purchase price shall
be subject to adjustment as provided in the next succeeding sentence
and in Section 8 hereof (each such price or prices as last adjusted,
as the case may be, being referred to herein as the "Warrant Price").
Subject to Section 8, on February 8, 1995 the Warrant Price for both
the 3-Year Shares and for the 4-Year Shares shall be adjusted to
equal the market price per share (determined as provided below) of
the Common Stock as of such date multiplied by 120%; provided,
however, that in no event shall such adjustment cause the Warrant
Price for the 3-Year Shares or the 4-Year Shares to exceed the
respective purchase price for such shares specified in the first
sentence of this Section 7 or to be less than $21.60 per share. In
the event of any adjustment in the Warrant Price pursuant to Section
8, the maximum and minimum prices in the preceding sentence shall be
adjusted accordingly.
Section 8. Antidilution Provisions. The Warrant Price shall be
subject to further adjustment from time to time as provided in this
Section 8.
8A. Distribution of Other Shares or Securities. In case Snyder
shall pay a dividend or make a distribution on its Common Stock that
is paid or made (1) in other shares of stock of Snyder or (2) in
rights to purchase stock or other securities if such rights are not
separable from the Common Stock except upon the occurrence of a
contingency, then in each such case this Warrant shall be adjusted
retroactively so that the Holder of this Warrant shall, upon exercise
thereof, be entitled to receive the number of other shares and rights
to purchase stock or other securities (or, in the event of the
redemption of any such shares or rights, any cash, property or
securities paid in respect of such redemption) which such Holder
would have owned or have been entitled to receive after the happening
of any event described above had such Warrant been exercised
immediately prior to the happening of such event. An adjustment made
pursuant to this Subsection 8A shall become effective immediately
after the record date in the case of such a dividend or distribution.
8B. Issuance of Rights or Warrants to Common Stockholders. In
case Snyder shall issue rights or warrants to all holders of its
Common Stock entitling them (for a period expiring within 45 days
after the date fixed for determination mentioned below) to subscribe
for or purchase shares of Common Stock at a price per share less than
the market price per share (determined as provided below) of the
Common Stock on the date fixed for the determination of stockholders
entitled to receive such rights or warrants, then the Warrant Price
in effect at the opening of business on the day following the date
fixed for such determination shall be decreased by multiplying such
Warrant Price by a fraction of which the denominator shall be the
number of shares of Common Stock outstanding at the close of business
on the date fixed for such determination plus the number of shares of
Common Stock so offered for subscription or purchase and the
numerator shall be the number of shares of Common Stock outstanding
at the close of business on the date fixed for such determination
plus the number of shares of Common Stock which the aggregate of the
offering price of the total number of shares of Common Stock so
offered for subscription or purchase would purchase at such market
price, such decrease to become effective immediately after the
opening of business on the day following the date fixed for such
determination; provided, however, that in the event that all the
shares of Common Stock offered for subscription or purchase are not
delivered upon the exercise of such rights or warrants, upon the
expiration of such rights or warrants the Warrant Price shall be
readjusted to the Warrant Price which would have been in effect had
the denominator and the numerator of the foregoing fraction and the
resulting adjustment been made based upon the number of shares of
Common Stock actually delivered upon the exercise of such rights or
warrants rather than upon the number of shares of Common Stock
offered for subscription or purchase. For the purpose of this
Subsection 8B, the number of shares of Common Stock at any time
outstanding shall not include shares held in the treasury of Snyder.
8C. Other Dividends or Distributions. In case Snyder shall, by
dividend or otherwise, distribute to all holders of its Common Stock
evidences of its indebtedness, cash (excluding ordinary cash
dividends paid out of retained earnings of Snyder), other assets or
rights or warrants to subscribe for or purchase any security
(excluding those referred to in Subsections 8A and 8B above), then in
each such case the Warrant Price shall be reduced retroactively so
that the same shall equal the amount determined by multiplying the
Warrant Price in effect immediately prior to the close of business on
the date fixed for the determination of stockholders entitled to
receive such distribution by a fraction of which the denominator
shall be the market price per share (determined as provided below) of
the Common Stock on the date fixed for such determination and the
numerator shall be such market price per share of the Common Stock
less the amount of cash and the then fair market value (as determined
in good faith by the Board of Directors of Snyder) of the portion of
the assets, rights or evidences of indebtedness so distributed
applicable to one share of Common Stock, such adjustment to become
effective immediately prior to the opening of business on the day
following the date fixed for the determination of stockholders
entitled to receive such distribution.
8D. Calculation of Market Price. For the purpose of any
computation hereunder, the market price per share of Common Stock on
any date shall be deemed to be the average of the daily closing
prices for the 20 consecutive trading days commencing with the 30th
trading day before the day in question. The closing price for each
day shall be the reported last sales price regular way or, in case no
such reported sale takes place on such day, the average of the
reported closing bid and asked prices regular way, in either case on
the New York Stock Exchange or, if the Common Stock is not listed or
admitted to trading on such Exchange, on the principal national
securities exchange on which the Common Stock is listed or admitted
to trading (based on the aggregate dollar value of all securities
listed or admitted to trading) or, if not listed or admitted to
trading on any national securities exchange, on the NASDAQ National
Market System or, if the Common Stock is not listed or admitted to
trading on any national securities exchange or quoted on the NASDAQ
National Market System, the average of the closing bid and asked
prices in the over-the-counter market as furnished by any New York
Stock Exchange member firm selected from time to time by Snyder for
that purpose, or, if such prices are not available, the fair market
value set by, or in a manner established by, the Board of Directors
of the Corporation in good faith. The term "trading day" shall
mean a day on which the national securities exchange or the NASDAQ
National Market System used to determine the closing price is open
for the transaction of business or the reporting of trades or, if the
closing price is not so determined, a day on which the New York Stock
Exchange is open for the transaction of business.
8E. Distribution of Common Stock, Subdivisions and
Combinations. In case Snyder shall pay a dividend or make a
distribution on its Common Stock in additional shares of Common
Stock, then the Warrant Price shall be adjusted by multiplying such
Warrant Price by a fraction of which the denominator shall be the
number of shares outstanding on the record date for such dividend or
distribution plus the number of shares to be distributed and the
numerator shall be the number of shares outstanding on the record
date of such dividend or distribution. In case Snyder shall at any
time subdivide its outstanding shares of Common Stock into a greater
number of shares, the Warrant Price in effect immediately prior to
such subdivision shall be proportionately reduced, and conversely, in
case the outstanding shares of Common Stock of Snyder shall be
combined into a smaller number of shares, the Warrant Price in effect
immediately prior to such combination shall be proportionately
increased. For purpose of this Subsection 8E, the number of shares
of Common Stock at any time outstanding shall not include shares of
Common Stock held in the treasury of Snyder.
8F. Minimum Adjustments. No adjustment in the Warrant Price
under this Section 8 shall be required unless such adjustment would
equal at least $.05 per share; provided, however, that Snyder may
make any such adjustment at its election; and provided, further, that
any adjustments which by reason of this Subsection 8F are not made
shall be carried forward and taken into account in any subsequent
adjustment. All calculations under this Section 8 shall be made to
the nearest cent or to the nearest one-hundredth of a share, as the
case may be.
8G. Adjustments to Warrant Number. Whenever there shall be any
change in the Warrant Price under this Section 8, then there shall be
an adjustment (to the nearest hundredth of a share) in the number of
shares of Common Stock purchasable at such Warrant Price upon
exercise of this Warrant (the "Warrant Number"), which adjustment
shall become effective at the time such change in the Warrant Price
applicable thereto becomes effective and shall be made by multiplying
the Warrant Number in effect immediately before such change in the
Warrant Price applicable thereto by a fraction the numerator of which
is such Warrant Price immediately before such change and the
denominator of which is such Warrant Price immediately after such
change.
8H. Other Adjustments. In the event that at any time, as a
result of any adjustment made pursuant to this Section 8, the Holder
of this Warrant shall become entitled to receive any shares of Snyder
other than shares of Common Stock or to receive any other securities,
the Warrant Price and number of such other shares or securities so
receivable upon exercise of this Warrant shall be subject to
adjustment from time to time in a manner and on terms as nearly
equivalent as practicable to the provisions contained in this Section
8 with respect to the Common Stock.
8I. Reclassifications, Consolidations, Mergers, etc. In case
of any reclassification of the Common Stock, any consolidation of
Snyder with, or merger of Snyder into, any other Person (as defined
below), any merger of another Person into Snyder (other than a merger
which does not result in any reclassification, conversion, exchange
or cancellation of outstanding shares of Common Stock of Snyder), any
sale or transfer of all or substantially all of the assets of Snyder
or any compulsory share exchange, pursuant to which share exchange
the Common Stock is converted into other securities, cash or other
property, then lawful provision shall be made as part of the terms of
such transaction whereby the Holder of this Warrant shall have the
right thereafter, during the period this Warrant shall be
exercisable, to exercise this Warrant to acquire only the kind and
amount of securities, cash and other property receivable upon such
reclassification, consolidation, merger, sale, transfer or share
exchange by a holder of the number of shares of Common Stock of
Snyder issuable upon exercise of this Warrant immediately prior to
such reclassification, consolidation, merger, sale, transfer or share
exchange. Snyder will not effect any such consolidation, merger or
sale, unless prior to the consummation thereof the successor
corporation (if other than Snyder) resulting from such consolidation
or merger or the Person purchasing such assets shall assume by
written instrument (in form reasonably satisfactory to the Holder)
executed and mailed or delivered to the Holder at the last address of
such Holder appearing on the books of Snyder, the obligation to
deliver to such Holder such securities, cash or other property as, in
accordance with the foregoing provisions, such Holder may be entitled
to acquire. If a purchase, tender or exchange offer is made to and
accepted by the holders of more than 50% of the outstanding shares of
Common Stock of Snyder, Snyder shall not effect any consolidation,
merger or sale with the Person having made such offer or with any
Affiliate (as defined below) of such Person, unless prior to the
consummation of such consolidation, merger or sale the Holder shall
have been given a reasonable opportunity to then elect to receive
upon the exercise of this Warrant either the securities, cash or
other property then issuable with respect to the Common Stock of
Snyder or the securities, cash or other property, or the equivalent,
issued to previous holders of the Common Stock in accordance with
such offer. The term "Person" as used in this Subsection 8I shall
mean and include an individual, a partnership, a corporation, a
trust, a joint venture, an unincorporated organization and a
government or any department or agency thereof. For the purposes of
this Subsection 8I, an "Affiliate" of any Person shall mean any
Person directly or indirectly controlling, controlled by or under
direct or indirect common control with, such other Person. A Person
shall be deemed to control a corporation if such Person possesses,
directly or indirectly, the power to direct or cause the direction of
the management and policies of such corporation, whether through the
ownership of voting securities, by contract or otherwise. The above
provisions shall similarly apply to successive reclassifications,
consolidations, mergers, sales, transfers or share exchanges.
8J. Separate Adjustments to Warrant Price. To the extent a
different Warrant Price shall be in effect for the 3-Year Shares and
the 4-Year Shares, adjustments to each such Warrant Price shall be
separately calculated as if each such Warrant Price were the only
Warrant Price in effect under the Warrant.
Section 9. Notice of Adjustment. Upon any adjustment of the
Warrant Price, then and in each such case Snyder shall give written
notice thereof, by first-class mail, postage prepaid, addressed to
the Holder at the address of such Holder as shown on the books of
Snyder, which notice shall state the Warrant Price resulting from
such adjustment and the increase or decrease, if any, in the Warrant
Number, setting forth in reasonable detail the method of calculation
and the facts upon which such calculation is based.
Section 10. Other Notices. In case at any time:
(1) Snyder shall declare any cash dividend upon its Common
Stock payable at a rate which exceeds the rate of the last cash
dividend theretofore paid by more than $.01 per share;
(2) Snyder shall declare any dividend upon its Common
Stock payable in stock or make any special dividend or other
distribution (other than regular cash dividends) to the holders
of its Common Stock;
(3) Snyder shall authorize the granting or issuance to the
holders of its Common Stock of rights or warrants to subscribe
for or purchase any shares of stock of any class or other
rights;
(4) Snyder obtains knowledge of any offer to purchase
(including any tender offer) any shares of any class of its
stock from Snyder or the holders of such shares;
(5) there shall be any capital reorganization, or
reclassification of the capital stock of Snyder, or
consolidation or merger of Snyder with, or sale of all or
substantially all of its assets to, another corporation; or
(6) there shall be a voluntary or involuntary dissolution,
liquidation or winding-up of Snyder;
then, in any one or more of said cases, Snyder shall give, by first-
class mail, postage prepaid, addressed to the Holder at the address
of such Holder as shown on the books of Snyder (a) at least 15 days'
prior written notice of the date on which the books of Snyder shall
close or a record shall be taken for such dividend, distribution or
subscription or purchase rights or for determining rights to vote in
respect of any such reorganization, reclassification, consolidation,
merger, sale, dissolution, liquidation or winding-up, (b) in the case
of any such reorganization, reclassification, consolidation, merger,
sale, dissolution, liquidation or winding-up, at least 15 days' prior
written notice of the date when the same shall take place, and (c)
promptly upon obtaining knowledge of any such offer to purchase
shares of any class of its stock. Such notice in accordance with the
foregoing clause (a) shall also specify, in the case of any such
dividend, distribution or subscription rights, the date on which the
holders of Common Stock shall be entitled thereto, such notice in
accordance with the foregoing clause (b) shall also specify the date
on which the holders of Common Stock shall be entitled to exchange
their Common Stock for securities or other property deliverable upon
such reorganization, reclassification, consolidation, merger, sale,
dissolution, liquidation or winding-up, as the case may be, and such
notice in accordance with the foregoing clause (c) shall also specify
in reasonable detail the terms of the offer to purchase.
Section 11. Registration. If any shares of Common Stock
required to be reserved for purposes of exercise of this Warrant
require registration with or approval of any governmental authority
under any Federal or State law, or listing on any domestic securities
exchange, before such shares may be issued upon exercise, Snyder
will, at its expense, as expeditiously as possible, use its best
efforts to cause such shares to be duly registered or approved or
listed on the relevant domestic securities exchange, as the case may
be.
Section 12. Closing of Books. Snyder will at no time close its
transfer books against the transfer of this Warrant or of any shares
of Common Stock issued or issuable upon the exercise of this Warrant
in any manner which interferes with the timely exercise of this
Warrant.
Section 13. Registration Rights. The rights set forth in this
Section 13 may be exercised by the Holder at any time or from time to
time during the period commencing on February 8, 1995 and ending on
the date which is 36 months after the final date on which any right
to purchase Common Stock hereunder is exercised by the Holder.
13A. Registration on Request. Upon written notice of a Holder
requesting that Snyder effect the registration under the Securities
Act of 1933, as amended (the "Securities Act"), of all or part of the
shares of Common Stock held by it (collectively, the "Registrable
Stock") which notice shall specify the intended method or methods of
disposition of such Registrable Stock, Snyder will file a
registration statement with the Securities and Exchange Commission
("SEC") (at the earliest possible date and, except as provided
herein, no later than 30 days following receipt of such notice) and
use its reasonable best efforts to effect the registration, under the
Securities Act, of such Registrable Stock for disposition in
accordance with the intended method or methods of disposition stated
in such request, provided that:
(1) if, upon receipt of a registration request pursuant to
this Subsection 13A, Snyder is advised in writing (with a copy
to the requesting Holder) by a recognized independent investment
banking firm selected by the Board of Directors of Snyder that,
in such firm's opinion, a registration at the time and on the
terms requested would adversely affect any public offering of
securities by Snyder (other than in connection with employee
benefit and similar plans) (a "Public Offering") for which a
registration statement had been filed by Snyder prior to
receiving such registration request, Snyder shall not be
required to effect a registration pursuant to this Section 13A
until the earlier of (i) three months after the completion of
such Public Offering, (ii) the termination of any "black out"
period required by the underwriters, if any, to be applicable to
such Holder in connection with such Public Offering, (iii)
promptly after abandonment of such Public Offering or (iv) 135
days after the date of written notice of the Holder requesting
registration; and
(2) if a registration request is made while a merger,
consolidation, acquisition, disposition or other material
development involving Snyder is pending, and the general counsel
of Snyder determines in writing that the filing of a
registration statement would require the disclosure of
information that is material to such transaction or material
development which Snyder has a bona fide business purpose for
preserving as confidential, and Snyder promptly provides the
Holder requesting registration a copy of such determination,
Snyder shall not be required to effect a registration pursuant
to this Subsection 13A until the earlier of (i) the date upon
which such material information is disclosed to the public or
ceases to be material or (ii) 135 days after the date of written
notice by the Holder requesting registration.
13B. Third Person Shares. Snyder shall have the right to cause
the registration of securities for sale for the account of any person
in any registration of Registrable Stock requested pursuant to
Section 13A, provided that Snyder shall not have the right to cause
the registration of such securities if the Holder requesting
registration is advised in writing (with a copy to Snyder) by a
recognized independent investment banking firm selected by the Holder
that, in such firm's opinion, registration of such securities would
adversely affect the offering and sale of the Registrable Stock then
contemplated by the Holder.
13C. Registration Expenses. Snyder shall be responsible for
the payment of all Registration Expenses (as defined below) in
connection with any registration pursuant to Section 13, it being
understood that with respect to any such registration the Holder
shall bear its own legal costs and all underwriting discounts and
dealer fees attributable on a pro rata basis to the shares of
Registrable Stock which such Holder desires to register.
"Registration Expenses," as used herein means all expenses incident
to Snyder's performance of or compliance with the registration
requirements set forth in this Section 13 including, without
limitation, the following: (i) the fees, disbursements and expenses
of Snyder's counsel(s) (United States and foreign) and accountants in
connection with any such registration; (ii) all underwriting
discounts and dealer fees which are not attributable on a pro rata
basis to the shares of Registrable Stock being registered; (iii) all
expenses in connection with the preparation, printing and filing of
the registration statement, any preliminary prospectus or final
prospectus, any other offering document and amendments and
supplements thereto and the mailing and delivering of copies thereof
to the underwriters and dealers; (iv) all fees and expenses incurred
in listing the Registrable Stock on any stock exchange and any
transfer agent or registrar fees; (v) the cost of printing or
producing any agreements(s) among underwriters, underwriting
agreement(s), and blue sky or legal investment memoranda, any selling
agreements and any other documents in connection with the offering,
sale or delivery of Registrable Stock to be disposed of; (vi) all
expenses in connection with the qualification of Registrable Stock to
be disposed of for offering and sale under state securities laws,
including the fees and disbursements of one firm of legal counsel for
the Holders and underwriters in connection with such qualification
and in connection with any blue sky and legal investment surveys; and
(vii) the filing fees incident to securing any required review by the
National Association of Securities Dealers, Inc. of the terms of the
sale of Registrable Stock to be disposed of.
13D. Registration Procedures. If and whenever Snyder is
required to use its reasonable best efforts to effect the
registration of any Registrable Stock under the Securities Act as
provided in Subsection 13A, Snyder will as promptly as is
practicable:
(1) prepare, file and use its reasonable best efforts to
cause to become effective a registration statement on such form
as Snyder reasonably selects under the Securities Act or update
by amendment or supplement a previously filed registration
statement regarding the Registrable Stock to be offered;
(2) prepare and file with the SEC such amendments and
supplements to such registration statement and the prospectus
used in connection therewith as may be necessary to keep such
registration statement effective and to comply with the
provisions of the Securities Act with respect to the disposition
of all Registrable Stock until the earlier of such time as all
of such Registrable Stock has been disposed of in accordance
with the intended methods of disposition by the Holder set forth
in such registration statement or the expiration of twelve
months after such registration statement becomes effective;
(3) furnish to the Holder and to any underwriter of such
Registrable Stock such number of conformed copies of such
registration statement and of each such amendment and supplement
thereto (in each case including all exhibits), such number of
copies of the prospectus included in such registration statement
(including each preliminary prospectus and any summary
prospectus), in conformity with the requirements of the
Securities Act, such documents incorporated by reference in such
registration statement or prospectus, and such other documents
as such Holder or such underwriter may reasonably request;
(4) use its reasonable best efforts to register or qualify
all Registrable Stock covered by such registration statement
under such other securities or blue sky laws of such
jurisdictions, and to list such Registrable Stock on any stock
exchange, as the Holder or any underwriter of such Registrable
Stock shall reasonably request, and do any and all other acts
and things which may be necessary or advisable to enable the
Holder or any underwriter to consummate the disposition in such
jurisdictions of its Registrable Stock covered by such
registration statement, except that Snyder shall not for any
such purpose be required to qualify generally to do business as
a foreign corporation in any jurisdiction wherein it is not so
qualified, or to subject itself to taxation in any such
jurisdiction, or to consent to general service of process in any
such jurisdiction;
(5) in the case of an underwritten offering of Registrable
Securities (i) furnish to the Holder, addressed to it, an
opinion of counsel for Snyder, dated the date of the closing
under the underwriting agreement, and (ii) use its best efforts
to furnish to the Holder, addressed to it, a "cold comfort"
letter signed by the independent public accountants who have
audited Snyder's financial statements included or incorporated
in such registration statement, covering substantially the same
matters with respect to such registration statement (and the
prospectus included therein) and, in the case of such
accountants' letter, with respect to events subsequent to the
date of such financial statements, as are customarily covered in
opinions of issuer's counsel and in accountants' letters
delivered to underwriters in underwritten public offerings of
securities and such other matters as the Holder may reasonably
request; and
(6) immediately notify the Holder at any time when a
prospectus relating to a registration pursuant to Section 13
hereof is required to be delivered under the Securities Act of
the happening of any event as a result of which the prospectus
included in such registration statement, as then in effect,
includes an untrue statement of a material fact or omits to
state any material fact required to be stated therein or
necessary to make the statements therein, in the light of the
circumstances under which they were made, not misleading, and at
the request of the Holder prepare and furnish to the Holder and
any underwriter of the Registrable Stock a reasonable number of
copies of a supplement to or an amendment of such prospectus as
may be necessary so that, as thereafter delivered to the
purchasers of such Registrable Stock, such prospectus shall not
include an untrue statement of a material fact or omit to state
a material fact required to be stated therein or necessary to
make the statements therein, in light of the circumstances under
which they were made, not misleading.
Snyder may require the Holder to furnish such information regarding
the Holder and the distribution of such securities as Snyder may from
time to time reasonably request in writing and as shall be required
by law or by the SEC in connection with any registration.
13E. Underwriting. If requested by the underwriters for any
underwritten offering of Registrable Stock pursuant to a registration
requested hereunder, Snyder will enter into an underwriting agreement
with such underwriters for such offering, such agreement to contain
such representations and warranties by Snyder and such other terms
and provisions as are customarily contained in underwriting
agreements with respect to secondary distributions, including,
without limitation, indemnities and contribution to the effect and to
the extent provided in Subsection 13H hereof and the provision of
opinions of counsel and accountants' letters to the effect and to the
extent provided in Subsection 13D. The Holder(s) on whose behalf
Registrable Stock is to be distributed by such underwriters shall be
parties to any such underwriting agreement and the representations
and warranties by, and the other agreements on the part of, Snyder to
and for the benefit of such underwriters shall also be made to and
for the benefit of such Holder(s).
13F. Blackout Periods. (1) At any time when a registration
statement pursuant to Section 13 relating to Registrable Stock is
effective, upon written notice from Snyder to the Holder that either:
(i) Snyder has determined to engage in a financing
and has been advised in writing (with a copy to such
Holder) by a recognized independent investment banking firm
selected by the Board of Directors of Snyder that, in such
firm's opinion, Snyder's sale of Registrable Stock pursuant
to the registration statement would adversely affect
Snyder's own immediately planned financing (a "Transaction
Blackout"); or
(ii) the general counsel of Snyder determines in good
faith in writing (with a copy to such Holder) that the
Holder's sale of Registrable Stock pursuant to the
registration statement would require disclosure of material
information which Snyder has a bona fide business purpose
for preserving as confidential as a result of a pending
merger, consolidation, acquisition, disposition or other
material development involving Snyder (an "Information
Blackout"),
Snyder shall suspend sales of Registrable Stock pursuant to such
registration statement until the earlier of
(X) (i) in the case of a Transaction Blackout, the
earliest of (A) three months after the completion of
such financing, (B) the termination of any "blackout"
period required by the underwriters to be applicable
to Snyder, if any, in connection with such financing,
(C) abandonment of such financing and (D) 135 days
after the date of Snyder's written notice of a
Transaction Blackout, or (ii) in the case of an
Information Blackout, the earlier of (A) the date upon
which such material information is disclosed to the
public or ceases to be material or (B) 135 days after
receipt of notice by the Holder requesting the
registration, and
(Y) such time as Snyder notifies the Holder that
sales pursuant to such registration statement may be
resumed;
provided, that Snyder may not impose a Transaction Blackout from the
date notice is received from the Holder requesting registration until
90 days after the initial effectiveness hereunder of any registration
statement relating to the Registrable Stock or during any
underwritten public offering of Registrable Stock.
13G. Preparation; Reasonable Investigation. In connection with
the preparation and filing of each registration statement registering
Registrable Stock under the Securities Act, Snyder will give the
Holder and the underwriters, if any, and their respective counsel and
accountants, such reasonable and customary access to its books and
records and such opportunities to discuss the business of Snyder with
its officers and the independent public accountants who have audited
its financial statements as shall be necessary, in the opinion of the
Holder and such underwriters or their respective counsel, to conduct
a reasonable investigation within the meaning of the Securities Act.
13H. Indemnification and Contribution. (1) In the event
of any registration of any Registrable Stock hereunder, Snyder
will enter into customary indemnification arrangements to
indemnify and hold harmless the Holder, its directors and
officers, each person who participates as an underwriter in the
offering or sale of such securities, each officer and director
of each underwriter, and each person, if any, who controls such
seller or any such underwriter within the meaning of the
Securities Act against any losses, claims, damages, liabilities
and expenses, joint or several, to which such person may be
subject under the Securities Act or otherwise insofar as such
losses, claims, damages, liabilities or expenses (or actions or
proceedings in respect thereof) arise out of or are based upon
(i) any untrue statement or alleged untrue statement of any
material fact contained in any registration statement under
which such securities were registered under the Securities Act,
any preliminary prospectus or final prospectus included therein,
or any amendment or supplement thereto, or any document
incorporated by reference therein, or (ii) any omission or
alleged omission to state therein a material fact required to be
stated therein or necessary to make the statements therein not
misleading, and Snyder will reimburse each such person for any
legal or any other expenses reasonably incurred by such person
in connection with investigating or defending any such loss,
claim, liability, action or proceeding; provided that Snyder
shall not be liable in any such case to the extent that any such
loss, claim, damage, liability (or action or proceeding in
respect thereof) or expense arises out of or is based upon an
untrue statement or alleged untrue statement or omission made
in reliance upon and in conformity with written information
furnished by such person to Snyder. Such indemnity shall remain
in full force and effect regardless of any investigation made by
or on behalf of Snyder or any such director, officer or
controlling person and shall survive the transfer of the
registered securities by the Holder. Snyder also shall agree to
provide provision for contribution as shall be reasonably
requested by the Holder or any underwriters in circumstances
where such indemnity is held unenforceable.
(2) The Holder, by virtue of exercising its registration
rights hereunder, agrees and undertakes to enter into customary
indemnification arrangements to indemnify and hold harmless (in
the same manner and to the same extent as set forth in clause
(1) of this Section 13H) each director of Snyder, each officer
of Snyder who shall sign such registration statement, each
person who participates as an underwriter in the offering or
sale of such securities, each officer and director of each
underwriter, and each person, if any, who controls Snyder or any
such underwriter within the meaning of the Securities Act, with
respect to any statement in or omission from such registration
statement, any preliminary prospectus or final prospectus
included therein, or any amendment or supplement thereto, if
such statement or omission was made in reliance upon and in
conformity with written information furnished by it to Snyder.
Such indemnity shall remain in full force and effect regardless
of any investigation made by or on behalf of Snyder or any such
director, officer or controlling person and shall survive the
transfer of the registered securities by the Holder. The Holder
also shall agree to provide provision for contribution as shall
be reasonably requested by Snyder or any underwriters in
circumstances where such indemnity is held unenforceable.
(3) Indemnification and contribution similar to that
specified in the preceding subdivisions of this Subsection 13H
(with appropriate modifications) shall be given by Snyder and
the Holder with respect to any required registration or other
qualification of such Registrable Stock under any federal or
state law or regulation of governmental authority other than the
Securities Act.
Section 14. Warrant Transferable. This Warrant and all rights
hereunder are transferable, in whole or in part, without charge to
the Holder, at the office or agency of Snyder by the Holder in person
or by such Holder's duly authorized attorney, upon surrender of this
Warrant properly endorsed; provided, however, that (A) Snyder shall
have consented in writing to such transfer (which consent shall not
be unreasonably withheld) and (B) each transferee (other than UPRC or
any affiliate of UPRC) of this Warrant and the rights hereunder shall
have acquired the right to purchase at least 200,000 but not more
than 750,000 shares of Common Stock issuable hereunder. It is
understood that Snyder will cause to be placed upon certificates for
shares of Common Stock issued upon the exercise hereof, a legend
applicable to the disposition of such shares, provided that forthwith
upon any such disposition becoming permissible pursuant to a
registration statement filed under Section 13 or otherwise Snyder
will substitute therefor, at its expense, new certificates not
bearing such legend.
Such legend shall read substantially as follows:
"The shares represented by this certificate have not been
registered under the Securities Act of 1933 and such shares
cannot be sold or transferred unless they are so registered or
when exemption from registration is then available."
Section 15. Rights and Obligations Survive Exercise of Warrant.
The rights and obligations of Snyder, the Holder of, and of the
holder of shares of Common Stock issued upon exercise of this
Warrant, contained in Sections 13 and 14 shall survive the exercise
of this Warrant.
Section 16. Warrants Exchangeable for Different Denominations.
This Warrant is exchangeable, upon the surrender hereof by the Holder
at the office or agency of Snyder for new Warrants of like tenor
representing in the aggregate the right to subscribe for and purchase
the number of shares of Common Stock which may be subscribed for and
purchased hereunder, each of such new Warrants to represent the right
to subscribe for and purchase such number of shares of Common Stock
as shall be designated by said Holder at the time of such surrender.
Section 17. Descriptive Headings and Governing Law. The
descriptive headings of the several paragraphs of this Warrant are
inserted for convenience only and do not constitute a part of this
Warrant. This Warrant shall be construed and enforced in accordance
with, and the rights of the parties shall be governed by the law of
the State of New York.
IN WITNESS WHEREOF, Snyder Oil Corporation has caused this
Warrant to be signed by its duly authorized officers under its
corporate seal, and this Warrant to be dated February 8, 1994.
Snyder Oil Corporation
By: John C. Snyder
Chairman
[Corporate Seal]
Attest:
Peter E. Lorenzen
Secretary
<PAGE>
PURCHASE AGREEMENT
___________, 19__
To:
The undersigned, pursuant to the provisions set forth in the
within Warrant, hereby subscribes for and agrees to purchase [___ 3-
Year Shares and ___ 4-year Shares] of the Common Stock covered by
such Warrant, and makes payment herewith in full therefor at the
price per share provided by such Warrant.
Signature
Address
____________
ASSIGNMENT
FOR VALUE RECEIVED ________________________ hereby sells,
assigns and transfers all of the rights of the undersigned under the
within Warrant, with respect to the number of shares of the Common
Stock covered thereby set forth hereinbelow unto:
Name of Assignee Address No. and Type of
Shares
Dated:______________, 19__
Signature
Witness
<TABLE>
<CAPTION>
SNYDER OIL CORPORATION
COMPUTATION OF NET INCOME PER SHARE
FOR THE YEARS ENDED DECEMBER 31, 1991, 1992 AND 1993
(In thousands except per share data)
Year Ended December 31,
1991 1992 1993
<S> <C> <C> <C>
Income before accounting
change and extraordinary item $8,811 $16,875 $27,608
Cumulative effect of change
in accounting for taxes 0 3,763 0
Extraordinary item-early
extinguishment of debt 0 0 (1,944)
Net income 8,811 20,638 25,664
Dividends on preferred stock (453) (4,800) (9,100)
Net income available to common $8,358 $15,838 $16,564
Weight average shares outstanding 22,839 22,722 23,096
Add common stock equivalents 705 6,823 10,389
Weight average common stock and
equivalents outstanding 23,544 29,545 33,486
Primary net income per share:
Income before accounting change and
extraordinary item $.39 $.74 $1.19
Cumulative effect of change in
accounting for taxes 0 .17 0
Extraordinary item-early extinguishment
of debt 0 0 (.08)
Net income .39 .91 1.11
Dividends on preferred stock (.02) (.21) (.39)
Net income available to common $.37 $.70 $.72
Fully diluted net income per share:
Income before accounting change
and extraordinary item $.37 $.57 $.82
Cumulative effect of change
in accounting for taxes 0 .13 0
Extraordinary item-early
extinguishment of debt 0 0 (.05)
Net income .37 .70 .77
Dividends on preferred stock 0 0 0
Net income available to common $.37 $.70 $.77
</TABLE>
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the
incorporation of our report included in this Form 10-K into Snyder
Oil Corporation's previously filed Registration Statements Nos. 33-
35546 and 33-48213.
/s/ Arthur Andesen & Co.
ARTHUR ANDERSEN & CO.
Fort Worth, Texas
February 25, 1994
CONSENT OF INDEPENDENT PETROLEUM CONSULTANTS
As independent petroleum consultants, we hereby consent to the
incorporation of our report included in this Form 10-K into Snyder
Oil Corporation's previously filed Registration Statements Nos. 33-
35546 and 33-48213.
/s/Frederick D. Sewell
Netherland & Sewell
Dallas, Texas
March 11, 1994
February 10, 1994
Mr. John A. Fanning
Snyder Oil Corporation
777 Main Street, Suite 2500
Fort Worth, Texas 76102
Dear Mr. Fanning:
In accordance with your request, we have estimated the proved
reserves and future revenue, as of December 31, 1993, to the Snyder
Oil Corporation (SOCO) interest in certain oil and gas properties
located in Colorado, Texas, and Wyoming as listed in the accompanying
tabulations. As requested, lease and well operating costs
do not include the per-well overhead expenses allowed under joint operating
agreements for those properties operated by SOCO. This report
is based on constant prices and costs in accordance with the guidelines
of the Securities and Exchange Commission (SEC).
As presented in the accompanying summary projections, Tables
I through IV, we estimate the net reserves and future net revenue
to the SOCO interest, as of December 31, 1993, to be:
<TABLE>
<CAPTION>
Net Reserves Future Net Revenue
Oil Gas Present Worth
Category (Barrels) (MCF) Total at 10%
<S> <C> <C> <C> <C>
Proved Developed
Producing 13,566,972 130,353,448 $259,514,400 169,251,400
Non-Producing 1,244,012 9,417,893 24,238,600 14,808,000
Proved Undeveloped 9,721,779 86,004,974 115,153,100 47,791,100
Total Proved 24,532,763 225,776,315 $398,906,100 $231,850,500
The oil reserves shown include crude oil and condensate.
Oil volumes are expressed in barrels which are equivalent to 42 United
States gallons. Gas volumes are expressed in thousands of
standard cubic feet (MCF) at the contract temperature and pressure bases.
As shown in the Table of Contents, the properties in this report have
been subdivided into SOCO's significant property groups behind the appropriate
state tab. Included for each significant property group are summary
projections of reserves and revenue for each reserve category along with one
line summaries of reserves, economics, and basic data lease. For the
purposes of this report, the term "lease" refers to a single economic
projection.
The estimated reserves and future revenue shown in this report are
for proved developed producing, proved developed non-producing,
and proved undeveloped reserves. In accordance with SEC guidelines,
our estimates do not include any value for probable or possible reserves
which may exist for these properties. This report does include not
any value which could be attributed to interests in undeveloped acreage
beyond those tracts for which undeveloped reserves have been estimated.
Future gross revenue to the SOCO interest is prior to deducting
state production taxes and ad valorem taxes. Future net revenue is after
deducting these taxes, future capital costs, and operating expenses, but
bfore consideration of Federal income taxes. In accordance with SEC
guidelines, the future net revenue has been discounted at an annual rate
of 10 percent to determine its "present worth." The present worth is
shown to indicate the effect of time on the value of money and should not
be construed as being the fair market value of the properties.
For the purposes of this report, a field inspection of the
properties has not been performed nor has the mechanical operation or
condition of the wells and their related facilities been examined.
We have not investigated possible environmental liability related
to the properties; therefore, our estimates do not include any costs
which may be incurred due to such possible liability. Also, our
estimates do not include any salvage value for the lease
and well equipment nor the cost of abandoning the properties.
Oil prices used in this report are based on a December 31, 1993
West Texas Intermediate posted price of $12.50 per barrel, adjusted
by significant property group. Gas prices used in this report are
based on average December 1993 prices for each significant property
group. The oil and gas prices are held constant in accordance with
SEC guidelines.
Lease and well operating costs are based on operating expense records
of SOCO. For non-operated properties, these costs include the per-well
overhead expenses allowed under joint operating agreements along with costs
estimated to be incurred at and below the district and field levels.
As requested, lease and well operating costs for the operated properties
include only direct lease and field level costs. Headquarters general
and administrative overhead expenses of SOCO are not included. Lease and
well operating costs are held constant in accordance with SEC guidelines.
Capital costs are included as required for workovers, new development
wells, and production equipment.
We have made no investigation of potential gas volume and value
imbalances which may have resulted from over delivery or underdelivery
to the SOCO interest. Therefore, our estimates of reserves a revenue do
not include adjustments for the settlement of any such imbalances; our
projections are based on SOCO receiving its net revenue interest share
of estimated future gross gas production.
The reserves included in this report are estimates only and should
not be construed as exact quantities. They may or may not be
recovered; if recovered, the revenues therefrom and the costs related
thereto could be more or less than the estimated amounts. The sales rates,
prices received for the reserves, and costs incurred in recovering
may vary from assumptions included in this report due to governmental
policies and uncertainties of supply and demand. Also, estimates of
reserves may increase or decrease as a result of future operations.
In evaluating the information at our disposal concerning this report,
we have excluded from our consideration all matters as to
which legal or accounting, rather than engineering, interpretation may be
controlling. As in all aspects of oil and gas evaluation, there are
uncertainties inherent in the interpretation of engineering data; therefore,
our conclusions necessarily represent only informed professional judgments.
The titles to the properties have not been examined by Netherland,
Sewell & Associates, Inc., nor has the actual degree or type of interest
owned been independently confirmed. The data used in our estimates were
obtained from Snyder Oil Corporation and the nonconfidential files of
Netherland, Sewell & Associates, Inc. and were accepted as accurate.
We are independent petroleum engineers and geologists; we do not own
an interest in these properties and are not employed on a contingent basis.
Basic geologic and field performance data together with our engineering
work sheets are maintained on file in our office.
Very truly yours,
/s/ Federick D. Sewell
Netherland, Sewell & Associates, Inc.
</TABLE>
February 11, 1994
Mr. John A. Fanning
Snyder Oil Corporation
777 Main Street, Suite 2500
Fort Worth, Texas 76102
Dear Mr. Fanning:
In accordance with your request, we have audited the estimates prepared
by Snyder Oil Corporation (SOCO), as of December 31, 1993, of the
proved oil and gas reserves and future net revenue to the SOCO interest
in certain oil and gas properties located in the lUnited States.
SOCO's estimlates are based on constant prices and costs which conform to
the guidelilnes of the Securities and Exchange Commission (SEC). The
followling table sets forth SOCO's estimates of the proved reserves
and future net revenue, as of December 31, 1993, for the audited
properties:
<TABLE>
<CAPTION>
Net Reserves Future Net Revenue
Oil Gas Present Worth
Category (Barrells) (MCF) Total at 10%
<S> <C> <C> <C> <C>
Proved Developed
Producing 15,463,300 236,066,000 $408,420,900 $258,925,700
Non Producing 2,568,100 32,282,800 66,059,500 38,711,900
Proved Undeveloped 13,898,700 161,740,000 213,791,700 92,771,300
Total Proved 31,930,100 430,088,800 $688,272,100 $390,408,900
</TABLE>
In our opinion, the estimates of SOCO's net proved oil and gas reserves, as
shown herein and in certain computer printouts on file in our office, are
in the aggregate reasonable and have been prepared in accordance with
generally accepted petrolleum engineering and evaluation principles as
set forh in the Standards Pertaining to the Estimating and Auditing
of Oil and Gas Reserve Information promulgated by the Society
of Petroleum Engineers. We are satisfied with the methods and
procedures utilized by SOCO in preparing the December 31, 1993
reserve estimates, and we saw nothing of an unusal nature that would
cause us to take exception with the estimates, in the aggregate,
as prepared by SOCO.
The estimated reserves and future revenue shown herein are
for the total proved reserves which include proved developeed
producing, proved developed non-prodlucing, and proved undeveloped
reserves. Our audit did not include consideration of probable or
possible reserves which might be established for these properties,
nor did it include any consideration of undeveloped
acreage beyond those tracts for which proved reserves have
been estimated.
It should be understood that our audit does not constitute a
complete reserve study of SOCO's oil and gas properties. The
complete reserve study consists of properties evaluated
by Netherland, Sewell & Assocliates, Inc. as presented in our
report dated February 10, 1994, representing 61.6 percent of the
total proved present worth discounted at 10 percent, and properties
evaluated by SOCO, representing 19.5 percent of the total
proved present worth. Our audit consisted of a detailed
review of properties making up 81.1 percent of the present worth
for total proved reserves. In our audit, we accepted
without independent verification the accuracy and
completeness of the historical information and data
furnished by SOCO with respect to ownership interest, oil and
gas production, well test data, oil and gas prices,
historical costs of operation and development, and any
agreements relating to current and future operation of the
properties and sales of production. If, however, in the cource
of our examination somethig came to our attention which
brought into question the validity or sufficiency of any such
information or data, we did not rely on such information or
data until we had satisfactorily resolved our questions
relating therto or had independently verified such information or
data.
The above indicated reserve estimates were made in accordance with
guidelines prescribed by the SEC relating to the use of constant
prices and costs. The oil and gas prices for each of SOCO's significant
property garoups are based on West Texas Intermediate posted price of
$12.50 per barrel and average December 1993 gas prices, respectively,
and are held constant throughout the life of the properties. Lease
and well operating costs are held constant at
current levels for the life of the properties. Future capital
costs are included as required for workovers, new development
wells, and producation eqlupmaent and are also held constant until
expenditure.
We are independent petroleum engilneers with respect to SOCO as
provided in the Standards Pertaining to the Estimating
and Auditing of Oil and Gas Reserve Information promulgated by
the Society of Petroleum Engineers. We do not own an interest
in these properties and are not employed on a contingent basis.
We receive the full cooperation of athe engineering, geological,
and accounting personnel of Snyder Oil Corporation during our review.
Plaease let us know if we can be of further assistance in this matter.
Very truly yours
/s/ Federick D. Sewell
Netherland, Sewell & Associates
