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. The Company also
gathers, transports, processes and markets natural gas generally in
proximity to its principal producing properties. Over the five year
period from 1988 to 1993, revenues increased from $14.7 million to
$229.9 million, net income increased from $5.1 million to $25.7
million and net cash provided by operations increased from $8.1
million to $68.3 million. At December 31, 1993, the Company's net
proved reserves totaled 103.6 million barrels of oil equivalent
("MMBOE"), having a pretax present value at constant prices of $390.4
million. Approximately 69% of its proved reserves are natural gas.
Approximately 90% of the present value of the Company's proved
reserves is concentrated in five major producing areas located in
Colorado, Wyoming and Texas. In total, 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. The Company operates more than 2,100 wells
which account for over 90% of its developed reserves. In addition to
its domestic operations, the Company is also participating in several
international exploration and development projects through its wholly
owned subsidiary, SOCO International, Inc., and through its 36% owned
affiliate, Command Petroleum Holdings NL. At December 31, 1993, the
Company held undeveloped acreage totaling 539,000 gross acres
(326,000 net) domestically and 4.3 million gross acres (3.3 million
net) internationally.
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." Currently, the primary emphasis
of the Company's growth strategy is development drilling in the
Rockies, mainly the Wattenberg Field in the Denver-Julesburg Basin
("DJ Basin") of Colorado where the Company drilled 323 wells in 1993.
In implementing this strategy in the Wattenberg Field over the past
three years, the Company has achieved the following: (i) drilled
approximately 667 wells, 660 of which are currently producing; (ii)
increased production more than five times, from an average of 2.6
MBOE per day in 1991 to an average of 13.3 MBOE per day in 1993;
(iii) increased proved reserves nearly 50% from 37.9 MMBOE at yearend
1991 to 55.2 MMBOE at yearend 1993; and (iv) generally reduced
drilling and completion costs by over 30% through a combination of
aggressive cost cutting, economies of scale and technological
improvements. Through a major joint venture with Union Pacific
Resources Company, as well as acquisitions and leasing, the Company
has accumulated a substantial inventory of potential drilling
locations, including 1,102 locations that were classified as proved
undeveloped at December 31, 1993.
In 1993, the Company embarked on a program to apply the
experience gained in the Wattenberg Field to two other large scale
gas developments in the Rockies. In the Washakie Basin of southern
Wyoming (the "East Washakie Project"), the Company currently operates
128 wells and holds a significant inventory of potential drilling
locations, including 98 locations that were classified as proved
undeveloped at December 31, 1993. The Company has also initiated the
development of a third hub in the Rockies through three purchase
transactions, as well as farmouts and leasing. As a result, the
Company currently holds a significant inventory of potential drilling
locations in the Piceance and Uinta Basins of Colorado and Utah
(collectively, the "Western Slope Project"), including 101 locations
that were classified as proved undeveloped at December 31, 1993.
During 1994, the Company intends to continue development in the
DJ Basin and to increase activity in the East Washakie and Western
Slope Projects. The Company expects to spend $175 to $200 million for
development drilling and expansion of gas facilities in 1994,
including the drilling of over 650 wells, 500 of which are planned
for the Wattenberg Field and up to 90 for the East Washakie and
Western Slope Projects. As part of this program, the Company will
emphasize the improvement of well economics through the use of
technological improvements and cost saving drilling techniques, as
well as the capture of downstream margins via the Company's gas
facilities. In addition to development drilling in the Rockies, the
Company intends to pursue acquisitions to strengthen its existing
asset base and secure a foothold in new geographic areas and to
continue progress in bringing its international projects to fruition.
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 reduce
risk, create synergies with its gas management operations and exploit
the potential for continuous cost improvement. In 1994, the Company
expects to drill over 650 wells, including approximately 500 wells 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.
In its large scale development projects, the Company also
attempts to acquire and maintain a sizeable inventory of potential
drilling locations, many of which may not be economic at current cost
and price levels, but which the Company believes may ultimately prove
attractive to develop if reservoir assumptions are validated and well
economics improve over the life of the project through cost
reductions or price increases. No assurances can be given that such
conditions will be satisfied and, accordingly, that such locations
will be drilled.
Assuming no material changes in product prices and capital
availability, the Company estimates that it will expend from $150 to
$200 million per year for development drilling and gas facilities
over the next three to five years. Such expenditures totalled $64.8
million in 1992 and $112.8 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 55% 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
the Company operated over 1,100. Through a major joint venture with
UPRC, complementary acquisitions and an extensive leasing program,
the Company has accumulated up to 6,000 potential drilling locations
in the Wattenberg Field. 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 at least the next several years.
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 MMBOE at a net cost of under $3.50
per barrel as well as several pipeline and processing facilities that
complement existing facilities. See "Acquisition Program."
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 the Company's Wattenberg 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. 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
$151.1 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
often 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 sand. 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.
Cheyenne. During 1993, 29 wells were placed on stream in a
shallow gas producing area on the northeast flank of the DJ Basin.
This project, known as the Cheyenne Project, began with the
acquisition of five shut-in gas wells in 1990 when the Company
determined that it could capitalize on new open access rules of the
Federal Energy Regulatory Commission ("FERC") by constructing a
gathering system to transport gas to a nearby interstate pipeline.
After acquiring almost 50,000 acres of leases in the area and selling
an approximate 27.5% interest to other parties on a promoted basis,
the Company has drilled 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 the Wattenberg Field to develop fluvial Mesaverde sands in the
eastern Washakie Basin. An eleven well pilot project was completed in
1993 to test drilling and completion techniques and confirm cost
estimates. A second drilling program is currently being initiated.
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 clearance is currently
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 "Gas Management" and
"Properties - Significant Properties." The Company currently
operates 128 wells in this area and holds up to 1,200 potential
drilling locations, 98 of which were classified as proved undeveloped
at yearend 1993. The Company believes that more than half of the
potential locations may ultimately prove attractive to develop. The
Company currently holds interests in 95,000 gross (76,000 net)
undeveloped acres in the Washakie Basin. This includes 36,000 gross
(32,000 net) undeveloped acres added during 1993.
Western Slope
During 1993, the Company initiated the Western Slope Project by
establishing 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. 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 acreage with up to 1,000 potential drilling
locations, of which the Company believes 40% could ultimately prove
to be attractive to develop. Of these locations, 101 were classified
as proved undeveloped at yearend 1993. The development of the
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 confirm cost estimates and
improved recovery techniques. If successful, the Company may drill up
to 30 wells in 1994 and approximately 100 wells per year thereafter.
The Company's ability to continue to develop the Piceance Basin is in
part dependent on arranging gathering and transportation at a
reasonable cost. 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 $.4 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.
In the Giddings Field in Southeast Texas, the Company has
undertaken a horizontal drilling program to further exploit existing
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 transactions 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 hubs that the Company believes have the potential
to develop into large scale gas development projects. 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."
Through three purchase transactions, as well as farmouts and
leasing, the Company established a substantial position in the
Piceance and Uinta Basins during 1993, laying 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 proved undeveloped locations in various fields in the Uinta and
Piceance Basins. See "Development - Western Slope."
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 $ 642.8
</TABLE>
(a) Includes the acquisition of a publicly traded partnership managed
by the Company.
Gas Management
General. The Company expanded its gas gathering and processing
capacity during 1993 with the construction of additional gathering
facilities 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 returns. The segment is also increasingly
profitable in its own right. During 1993, gross margin 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 million cubic
feet ("MMcf") per day. During the fourth quarter of 1993, average
throughput had reached 54 MMcf per day. The 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 future volumes of gas available to be
processed in the Company's facilities.
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 Amoco's Wattenberg gas processing plant. If Amoco were
unable to process Company production at its plant for any reason,
including a shut-down of the plant, it would have a short-term
adverse impact on the Company. The 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 through continued drilling activity. These facilities
will also enable the Company to partially mitigate the effects of
significant downtime at the Amoco plant.
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. 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 that collect, compress and deliver gas from over
1,400 wells to the Roggen plant. During 1993, the Company
substantially increased the capacity of its gathering systems through
the expansion of existing facilities and the acquisition of new
facilities. The Company also completed the second phase of the
Enterprise system during 1993. Enterprise collects a portion of the
Company's gas produced from acreage acquired from Amoco and delivers
it to the Amoco Wattenberg plant. Enterprise includes 26 miles of 20"
diameter trunk and 29 miles of associated lateral gathering lines
connecting 20 of the Company's existing central delivery points. As
a result of the completion of the second phase, the Enterprise system
has the capacity to deliver 75 MMcf per day to the Amoco Wattenberg
plant.
During 1993, the Company also expanded its gathering system by
constructing a nine mile 16" pipeline loop on the western portion of
its Energy Pipeline system, which came on line in October 1993. This
expansion provides pressure relief and additional capacity for
further development in the area. In addition, the Company acquired a
pipeline that expands its gathering capacity to the north of the
Roggen plant, which may be converted to a residue line allowing for
the delivery of residue gas from the tailgate of the Roggen plant to
the Williams Natural Gas System.
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 reducing the Company's
exposure to future escalation in gathering costs applicable to the
Company's production, Enterprise provides an enhanced degree of
operational control. Because the Enterprise system interconnects with
the Company's other Colorado facilities, the 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
properties in the Washakie Basin. 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,
respectively. 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 an interstate pipeline. 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 Western Slope Project, the Company is
actively exploring alternatives to gather and transport future gas
production, including the possible construction of a Company-owned
gathering and transportation line. Traditionally, the lack of
sufficient pipeline capacity has been a major deterrent to
development in the Piceance Basin.
International Activities
The Company's strategy internationally is to develop projects
that have the potential for a major impact in the future. The Company
attempts to structure the projects to limit its financial exposure
and mitigate political risk by minimizing financial commitments in
the early phases of a project and seeking industry partners and
investors to fund the majority of the equity capital. A wholly owned
subsidiary of the Company, SOCO International, Inc., is the holding
company for all 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 the currently outstanding shares of SOCO
International, which is financed primarily by Company loans, 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 OPIC, 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 purchases by each of Command, the
Company's Australian affiliate, and Holland Sea Search NV ("HSSH"),
a Dutch affiliate of Command, of 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. Following a private placement of equity
securities in early 1994, 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 asset
is 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 Oil Company 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
and this work is expected to continue into 1995.
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.
<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
</TABLE>
(a) 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. See
"Management's Discussion and Analysis of Financial Condition and
Results of Operations."
(b) 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.
(c) The Company estimates that its composite net wellhead prices at
December 31, 1993 were approximately $2.11 per Mcf of gas and $11.49
per barrel of oil.
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 143.0 241.0 382.0
Net 117.2 207.5 316.0
Dry
Gross 3.0 6.0 10.0
Net 2.8 2.7 5.5
Exploratory wells
Productive
Gross 5.0 - 2.0
Net 1.8 - 2.0
Dry
Gross 5.0 - 6.0
Net 1.5 - 3.3
(/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 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, which terminated at the end of 1993, of
a portion of the Company's natural gas and natural gas liquids
produced from certain of its Wattenberg acreage. Historically, this
arrangement 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. The Company exercised its
option to release its natural gas and natural gas liquids and began
marketing its production beginning January 1, 1994. The Company
believes, however, that it can obtain pricing comparable to that
which would have been obtainable through Amoco. 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 costs
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,
a change in the pricing formula should result in improved margins.
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.
Name Position
John C. Snyder Chairman and Director
Thomas J. Edelman President and Director
John A. Fanning Executive Vice President and Director
Charles A. Brown Vice President - Emerging Assets
Steven M. Burr Vice President - Planning and Engineering
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
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.
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>
<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
</TABLE>
(a) Natural gas reserves are converted to oil equivalents at the
rate of 6 Mcf per barrel, except Thomasville Field gas reserves prior
to 1993. See "Management's Discussion and Analysis of Financial
Condition and Results of Operations."
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 59,421 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)
</TABLE>
(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.
The quantities and values in the preceding tables are based on
prices in effect at December 31, 1993, averaging $11.49 per barrel of
oil and $2.11 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 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
Gross Net
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
</TABLE>
(a) Developed acreage is acreage assigned to producing wells.
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 26,716 392,996 351,498 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 1,102 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. 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 86% of the
12.0 million BOE of reserves are classified as proved producing. Oil
accounts for almost 60% of the reserves. There are 10 Hamilton Dome
and Riverton Dome drilling locations to which proved undeveloped
reserves have been attributed. These 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 locations in these areas. See "Business -
Development - Western Slope Project."
<PAGE>
PART II
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
Results of Operations (a)
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 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 a major oil company where 1993
operating costs averaged $7.45 per BOE.
For the year ended December 31, 1993, average daily production was
25,472 BOE, a 65% increase from 1992. Average daily production in the
fourth quarter of 1993 climbed to 10,314 Bbls and 105.6 MMcf (27,917
BOE). The production increases resulted primarily from acquisitions
and continuing development drilling in the DJ Basin. 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 in 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 DJ Basin, 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
(a) Prior to 1993, production from the Thomasville Field, which was
sold at prices that were significantly above market, was converted to
equivalent barrels based on its price relative to the Company's other
gas production. Beginning in 1993, Thomasville production was
converted to oil equivalents at the rate of 6 Mcf per barrel. In
order to provide comparability between periods, equivalent barrel
information, other than depletion rates, for 1992 and 1991 has been
restated in this section to reflect Thomasville production at the
conversion rate of 6 Mcf per barrel. All equivalent barrel
information presented elsewhere in this Prospectus reflects the
historical method of conversion of Thomasville production used by the
Company in the applicable year.
</page>
of the related facilities. Gas marketing margins for 1993 decreased
by $1.1 million due to reduced margins on the Company's 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, a
change in the pricing formula should result in improved margins. The
cogeneration margin reduction was partially offset by a $667,000
(126%) rise in other gas marketing margins in 1993 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 1993, collection of 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 substantially reduced 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 Holdings NL and the retirement of
$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 BOE 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% to an effective rate of approximately
20% as a result of 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 and accordingly will increase
substantially.
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% increase 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 BOE 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 BOE
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 BOE 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 expended $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. 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 cost reductions that add proved undeveloped
locations as they become economic, the Company has increased the
inventory of available drillsites. In December 1993, the Company
entered into a letter of intent with Union Pacific Resources Company
("UPRC") 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 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. On
February 8, 1995, 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 below $21.60 per share. The
expiration date of the warrants will be extended one year if the
average closing price over such 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 a major oil
company 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 develop further 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 May 1993, the Company acquired 42.8% (currently 35.7%) of the
outstanding shares of Command Petroleum Holdings NL ("Command"), a
Sydney based Australian exploration and production company listed on
the Australian Stock Exchange, for $18.2 million. Command 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. Permtex, the
Company's Russian 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.
The Company from time to time acquires securities of publicly traded
and private oil and gas companies. In addition to its investment in
Command, the Company owns, among other investments, more than 5% of
the common stock of Lomak Petroleum, Inc. and, as the result of
purchases beginning in the third quarter of 1993, American
Exploration Company. The Company is currently evaluating a range of
possible alternatives with respect to its investment in American
Exploration Company, including the possibility of actions to enhance
the value of its common stock.
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 Company anticipates
that it will expend $175 to $200 million for development drilling and
expansion of gas facilities in 1994. The level of these and other
future expenditures is largely discretionary, and the amount of funds
devoted to any particular activity may increase or decrease
significantly, depending on available opportunities and market
conditions. The Company plans to finance its ongoing development,
acquisition and exploration expenditures using internally generated
cash flow, 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 the scope
of this transaction so that the benefits would be continued 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 underwritten
offering 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 preferred 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 request renewal of 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 the CD rate 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.
The Company maintains a program to divest marginal properties and
assets that 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.
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 satisfy debt service requirements and to
maintain planned levels of capital expenditures or that increased
capital expenditures will not be undertaken.
Inflation and Changes in Prices
While certain of its costs are affected by the general level of
inflation, factors unique to the petroleum industry result in
independent price fluctuations. Over the past five years,
significant fluctuations have occurred in oil and gas prices.
Although it is particularly difficult to estimate future prices of
oil and gas, price fluctuations have had, and will continue to have,
a material effect on the Company.
The following table indicates the average oil and gas prices
received over the last five years and highlights the price
fluctuations by quarter for 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>
<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.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM
8-K.
(a) 1. Reference is made to Item 8 on page 34.
2. Schedules otherwise required by Item 8 have been omitted as
not required or not applicable.
3. Exhibits
4.1.1 Certificate of Incorporation of Registrant - incorporated by
reference from Exhibit 3.1 to the Registrant's Registration
Statement on Form S-4 (Registration No. 33-33455).
4.1.2 Certificate of Amendment to Certificate of Incorporation of
Registrant filed February 9, 1990 - incorporated by reference
from Exhibit 3.1.1 to the Registrant's Registration Statement
on Form S-4 (Registration No. 33-33455).
4.1.3 Certificate of Amendment to Certificate of Incorporation of
Registrant filed May 22, 1991 - incorporated by reference
from Exhibit 3.1.2 to the Registrant's Registration Statement
on Form S-1 (Registration No. 33-43106).
4.1.4 Certificate of Amendment to Certificate of Incorporation of
Registrant filed May 24, 1993 - incorporated by reference
from Exhibit 3.1.5 to the Registrant's Form 10-Q for the
quarter ended June 30, 1993 (File No. 1-10509)
4.1.5 Certificate of Designations, Powers, Preferences and Rights
of the Registrant's $4.00 Convertible Exchangeable 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 Non-
Employee Directors - incorporated by reference from Exhibit
10.4 to the Registrant's Registration Statement on Form S-4
(Registration No. 33-33455).
10.1.1 Amendment dated May 20, 1992 to the Registrant's 1990 Stock
Plan for Non-Employee Directors - incorporated by reference
to the Registrant's Quarterly Report on Form 10-Q for the
quarter ended June 30, 1993 (File No. 1-10509).
10.2 Registrant's Restated 1989 Stock Option Plan - incorporated
by reference to the Registrant's Quarterly Report on Form 10-
Q for the quarter ended June 30, 1992 (File No. 1-10509).
10.3 SOCO Holdings Inc. 1984 Stock Option Plan - incorporated by
reference from Exhibit 10.6 to the Registrant's Registration
Statement on 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 Quarterly Report on Form 10-Q
for the quarter ended June 30, 1993 (File No. 1-10509)
10.8 Agreement dated as of April 30, 1993 between the Registrant
and Edward T. Story.*
10.9 Purchase and Sale Agreement dated December 11, 1992 between
Atlantic Richfield Company and Registrant - incorporated by
reference to Report on 8-K dated December 11, 1992 (File No.
1-10509).
10.10 Warrant dated February 8, 1994 issued by Registrant to Union
Pacific Resource Company.*
10.11 Fourth Restated Credit Agreement dated as of July 1, 1993
amoung the Registrant and the banks party thereto -
incorporated by reference from Exhibit 4.1.4 to the
Registrant's Quarterly Report on Form 10-Q for the quarter
ended June 30, 1993 (File No. 1-10509).
11.1 Computation of Per Share Earnings.*
22.1 Subsidiaries of the Registrant - incorporated by reference
from Exhibit 22.1 to the Registrant's Annual Report on Form
10-K for the year ended December 31, 1991 (File No. 1-10509).
23.1 Consent of Arthur Andersen & Co.*
23.2 Consent of Netherland, Sewell & Associates, Inc.*
99.1 Report of Netherland, Sewell & Associates, Inc. dated
February 10, 1994 relating to certain of the Registrant's
property interests.*
99.2 Report of Netherland, Sewell & Associates, Inc. dated
February 11, 1994 relating to their audit of reserve
estimates.*
(b) No reports on Form 8-K in the fourth quarter of 1993
* Filed as part of Registrant's original Form 10K.
SIGNATURE
The undersigned registrant hereby amends the following items,
financial statements, exhibits or other portions of its Annual Report
on Form 10-K as set forth in the pages attached hereto:
Cover Page
Item 1. Business
Item 2 Properties
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations
Part IV
Item 14. Exhibits, Financial Statement Schedules and
Reports on Form 8-K.
Pursuant to the requirements of the Securities Exchange Act of
1934, the registrant has duly caused this amendment to be signed on
its behalf by the undersigned, thereto duly authorized.
SNYDER OIL CORPORATION
By: /s/ Peter E. Lorenzen
Peter E. Lorenzen
Vice President - General Counsel
Date: April 22, 1994
