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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
--------------------------
Form 10-K
(Mark one)
[ X ] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1995
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transaction period from ________ to ________
Commission file number 1-10509
___________________
SNYDER OIL CORPORATION
(Exact name of registrant as specified in its charter)
Delaware 75-2306158
(State or other jurisdiction of (IRS Employer
incorporation or organization) Identification No.)
777 Main Street 76102
Fort Worth, Texas (Zip Code)
(Address of principal executive offices)
Registrant's telephone number, including area code (817) 338-4043
Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange
Title of each class on which registered
---------------------------- ---------------------------
Common Stock New York Stock Exchange
$6.00 Convertible Exchangeable
Preferred Stock New York Stock Exchange
7% Convertible Subordinated Notes New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
None
(Title of class)
Indicate by check mark whether the registrant (1) has
filed all reports required to be filed by Section 13 or 15(d) of the
Securities Exchange Act of 1934 during the preceding 12 months (or
for such shorter period that the registrant was required to file such
reports), and (2) has been subject to such filing requirements for
the past 90 days.
Yes / No
---- ----
Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of Regulation S-K is not contained herein, and
will not be contained, to the best of registrant's knowledge, in
definitive proxy or information statements incorporated by reference
in Part III of this Form 10-K or any amendment to this Form 10-K. [ ]
Aggregate market value of the common stock held by
non-affiliates of the registrant
as of March 20, 1996. . . . . . . . . . . . $222,405,285
Number of shares of common stock outstanding
as of March 20, 1996. . . . . . . . . . . . . 31,337,285
DOCUMENTS INCORPORATED BY REFERENCE
Part III of this Report is incorporated by reference to
the
Registrant's definitive Proxy Statement relating to its Annual
Meeting of Stockholders, which will be filed with the Commission no
later than April 30, 1995.
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SNYDER OIL CORPORATION
Annual Report on Form 10-K
December 31, 1995
PART I
ITEM 1. BUSINESS
General
Snyder Oil Corporation (the "Company") is engaged in the
acquisition and development of oil and gas properties primarily in
the Rocky Mountain and Gulf Coast regions of the United States. To
a lesser extent, the Company also gathers, transports and markets
natural gas in proximity to its principal producing properties.
During 1995, the Company's revenues were $202.2 million and cash flow
from operations approximated $70.6 million. At December 31, 1995,
the Company's net proved reserves totalled 90.2 million barrels of oil
equivalent ("MMBOE"), having a pretax present value at 10% based on
constant prices of $372.8 million. Approximately 73% of the reserves
was natural gas.
The Company's reserves are concentrated in six major producing
areas located in Colorado, Wyoming, Texas and the Gulf of Mexico,
which collectively account for more than 84% of the present value of
its reserves. The Company owns properties in 11 states and the Gulf
of Mexico, including 3,777 gross (2,105 net) producing wells and six
gas transportation and processing facilities. The Company operates
more than 2,300 wells which account for almost 80% of its developed
reserves. The Company also participates in several international
exploration and development projects through a wholly owned
subsidiary and its 30% owned Australian affiliate, Command Petroleum
Limited. At December 31, 1995, the Company held undeveloped acreage
totalling 1.3 million gross acres (1.1 million net) domestically and
5.8 million gross acres (2.4 million net) internationally.
The Company pursues a balanced strategy of development drilling
and acquisitions, focusing on enhancing operating efficiency and
reducing capital costs through the concentration of assets in
selected geographic areas or "hubs." Currently, the Company's
primary emphasis is on development drilling in several Rocky Mountain
basins and in southeast Texas, with an increasing emphasis on
drilling and acquisitions in the Gulf Coast. In response to
depressed markets for Rocky Mountain gas, the Company reduced its
development activity significantly in 1995, spending only $62.6
million on drilling and recompletions (of which more than $21 million
related to carryover costs for development activities initiated
in 1994). As operator, the Company drilled 63 wells during 1995.
Of these wells, 25 were in the Wattenberg Field, 11 were commenced
in a horizontal drilling program in south Texas, 5 were in the Gulf
of Mexico and the remainder were drilled, primarily to further test
and to hold or earn additional acreage, in development projects in
the Washakie and Deep Green River Basins in Wyoming, the Piceance
Basin of western Colorado and the Uinta Basin in Utah. By year-end
1995, production from these projects had risen to 8,270 barrels of
oil equivalent ("BOE") per day, representing 27% of the Company's
production, up from 7,408 BOE per day, or 20% of total production,
at year-end 1994. During 1995, the Company disposed of various
non-strategic properties, including its Wattenberg gas transportation
and processing facilities and its properties in west Texas, receiving
proceeds in excess of $100 million. These sales, in addition to allowing
increased focus on significant development projects, enabled the Company
to reduce its senior debt to $150 million by year end.
In view of the low current gas prices in its principal producing
areas, the Company plans to limit its 1996 development expenditures
to approximately $55 million. This level of expenditure is expected
to fund the drilling of up to 75 wells, including 20 in the Washakie
Basin, 8 in the Deep Green River area, 19 in the Piceance Basin and
15 in the Giddings Field. In addition, the Company plans to
implement three pilot waterflood projects to test the secondary
recovery potential of two fields in the Uinta Basin and may drill
three initial wells to test new projects in the Wind River and Big
Horn Basins in northern Wyoming. The Company may continue to
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purchase acreage to establish new development projects and seek to
acquire properties which strengthen its existing asset base or secure
a foothold in new geographic areas. The Company also expects to
continue to pursue various international projects at a limited
capital cost.
Proposed Patina Transaction. In January 1996, the Company and
Gerrity Oil & Gas Corporation ("Gerrity") agreed to combine their
assets and operations in the Wattenberg Field into a new public
company, Patina Oil & Gas Corporation ("Patina"). Patina will have 20
million shares of common stock outstanding. It is expected that the
common stock will be 70% owned by the Company, with the remaining 6
million common shares and warrants to purchase 3 million shares being
owned by Gerrity's stockholders. Depending on the results of the
transaction, Patina will have from $40 to $75 million of outstanding
preferred stock. Patina will assume $75 million of the Company's
bank debt, and will have initial total indebtedness of approximately
$215 million. On a pro forma basis as of December 31, 1995, Patina
held interests in over 3,600 wells in the Wattenberg Field with net
proved reserves of approximately 82.2 million BOE, over 70% of which
is attributable to gas. Based on unescalated year-end prices, these
reserves had a pre-tax present value at 10% of $380 million.
A principal purpose of the consolidation is to eliminate
duplicative overhead costs and to provide the opportunity to combine
the strengths of the two predecessor companies in further developing
the Field. This should provide enhanced operating and financial
performance and economies of scale beyond those already achieved.
These economies are particularly significant given the adverse impact
of the current depressed market for Rocky Mountain gas. As of year-
end 1995, Patina had identified in excess of 1,500 undeveloped
locations on its Wattenberg acreage, including 600 locations
classified as proved. In addition, Patina had an inventory of
approximately 850 recompletion opportunities also classified as
proved. Should drilling and completion technologies improve or Rocky
Mountain gas prices recover, a substantial number of the unproved
locations could become economically attractive to drill. Patina's
inventory of undeveloped locations and recompletion opportunities
will provide the ability to substantially expand development
activities if conditions warrant. In the interim, Patina expects to
limit its capital expenditures on existing properties to less than
$15 million per year. Funds generated from operations should permit
a fairly rapid pay down of debt or the aggressive pursuit of
additional consolidation opportunities.
On a pro forma basis, giving effect to the proposed Patina
transaction, the Company's proved reserves at December 31, 1995 would
increase to 41.1 million barrels of oil and 604.3 Bcf of gas or 141.9
million BOE, with a total pre-tax present value at 10%, of $606
million.
Consummation of the Patina transaction is subject to the approval
of Gerrity's common stockholders and certain other conditions.
Therefore, there can be no assurance that the transaction will occur.
Should the transaction be consummated, it is expected to close in the
second quarter of 1996.
Domestic Operations
General. Since 1992, development drilling has been the Company's
primary focus. The Company's existing properties have extensive
development drilling and enhancement potential, primarily in the
Washakie and Green River Basins in southern Wyoming, the Big Horn and
Wind River Basins in northern Wyoming, the Piceance and Uinta Basins
in western Colorado and Utah, the Gulf Coast area and the Wattenberg
Field in Colorado. The Company designs its major drilling programs to
reduce risk, create synergies with its gas management operations and
exploit the potential for continuous cost improvement. Owing to the
low current gas prices, the Company expects to drill up to only 75
wells in 1996. Assuming no material changes in energy prices, the
Company plans to spend approximately $55 million on development
activities in 1996, of which $46 million is targeted for drilling.
In its large scale development projects, the Company attempts to
acquire and maintain a sizeable inventory of potential drilling
locations, many of which may not be economic at current cost and
price levels. However, these locations may prove attractive if
reservoir assumptions are validated and well economics improve
through cost reductions, improved completion techniques or price increases.
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Wattenberg Field
During the last five years, the Company has drilled over 1,000
wells in the Wattenberg Field, including 25 drilled in 1995. At
December 31, 1995, the Company had interests in more than 1,800
producing wells, of which it operated approximately 1,500. Owing
primarily to depressed gas prices, drilling activity decreased
significantly in late 1994 and 1995. If Rocky Mountain gas prices
recover, the Company would expect to increase its drilling in
Wattenberg.
At year-end 1995, the net proved reserves attributed to the
Company's properties in Wattenberg were 30.6 million BOE, including
7.4 million barrels of oil and 138.9 Bcf of gas. Proved quantities
were significantly reduced by low year-end gas prices (approximately
$1.60 per Mcf) prevailing in Wattenberg. Year-end 1995 reserves were
attributable to 1,850 producing wells, 45 proved undeveloped
locations and approximately 90 proved behind pipe zones. The number
of proved undeveloped locations is sensitive to the prevailing level
of gas prices, and could increase if prices return to historical
levels. Future drilling activity should result in the assignment of
proved reserves to additional locations offsetting new productive
wells.
The Codell formation has traditionally been the primary objective
for development drilling. This formation is a blanket siltstone
formation that exists under much of the Wattenberg acreage at depths
of 6,700 to 7,500 feet. Codell reserves generally have a high degree
of predictability due to uniform deposition and gradual transition
from high to low gas/oil ratio areas. The Company frequently dually
completes the Niobrara chalk formation, which lies immediately above
the Codell, to enhance drilling economics. The Codell/Niobrara wells
produce most prolifically in the first six to twelve months, during
which production declines significantly from initial rates. More
than half of a typical well's reserves are recovered in the first
three years of production. As a result, each well contributes
significantly more production in its first year than in subsequent
years.
During the last several years, the Company expanded its drilling
targets to include both deeper and shallower formations. The J-sand
lies approximately 500 feet below the Codell. It is a low
permeability sandstone generally found to be productive throughout
the Wattenberg Field. Production performance varies with porosity
and thickness and is more variable in those areas outside the heart
of Wattenberg. The Dakota formation lies approximately 200 feet
below the J-sand. It is a low permeability sand occasionally
naturally fractured with less predictable commercial accumulations of
hydrocarbons and varied performance results. A number of wells have
been completed in the shallower Sussex formation at average depths of
4,500 feet. The Sussex sands were deposited in bars and exhibit
variable reservoir quality with a moderate degree of predictability.
Sussex reserves are primarily behind pipe in existing and future
wells drilled to the Codell and J-sands.
Because the Codell, Niobrara and J-sand formations are continuous
reservoirs over a large portion of the Wattenberg Field, the Company
believes that drilling, at least in the heart of Wattenberg, is
relatively low risk with well economics depending primarily on prices
paid for oil and gas production and control of drilling, completion
and operating costs. Of the 1,062 wells drilled between 1991 and
1995, only 15 were classified as dry holes, and most of these were in
outlying areas of the Field. Dry holes in Wattenberg cost an average
of $75,000 per well. The average cost of a completed well
approximated $202,000 in 1995.
At December 31, 1995, the Company held approximately 72,400 net
developed acres and 53,200 net undeveloped acres in the Wattenberg
Field, exclusive of any acreage not earned at that date covered by
the Company's agreement with Union Pacific Resources Company ("UPRC")
covering UPRC's undeveloped acreage in the Wattenberg Field. During
1995, the Company drilled less than the minimum number of wells
specified in the UPRC agreement. UPRC has asserted that the
Company's right to earn additional acreage under the agreement
terminated on December 31, 1995 and that the Company is required to
pay approximately $4.1 million in penalties to UPRC. Arbitration
proceedings on the matter have been initiated. The Company
established a reserve for these penalties in 1995.
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Gas production from Wattenberg is processed in order to recover
natural gas liquids, primarily propane and butane/gasoline mix. The
liquids are then sold separately from the residue gas. Production
from substantially all the Company's acreage is dedicated for
gathering to Associated Natural Gas Corporation ("ANGC") and for
processing at plants owned by ANGC and Amoco Production Company
("Amoco"). ANGC currently processes approximately 55% of the
production from the Company's wells, with the remainder being
processed by Amoco. Under each of these arrangements Amoco and ANGC
received their fees predominately in the form of percentages of the
liquid products and residue gas so that gathering and processing fees
effectively fluctuate with market prices.
In June 1995, the Company sold its recently constructed West
Plant processing plant on the western end of the Wattenberg area
along with certain related assets for a sales price of $18.5 million.
On September 30, 1995, the Company sold its remaining Wattenberg
transportation and processing facilities to ANGC for approximately
$60.9 million.
In connection with the sale to ANGC, the Company agreed that all
its uncommitted production, which had been transported and processed
by the Company's Gas Management Unit, would be transported and
processed by ANGC. The Company does not expect the sale to ANGC to
materially effect the net price realized by the Company from its
Wattenberg production at current price levels.
If either Amoco or ANGC were unable to process the Company's
production at their plants for any reason, including a plant shut-
down, or if a significant portion of ANGC's pipeline system were to
be curtailed, it would have a short-term adverse impact on the
Company's operations. In addition, the purchaser of the West Plant
has ceased operation of that plant, and the Company believes the
plant may be decommissioned. This has resulted in an increase in line
pressures on ANGC's gathering system in the western end of the
Wattenberg and has suppressed Company production in the area since
September 30, 1995. The Company believes, however, that the
flexibility afforded by ANGC's and other gathering systems in the
area, the number of processing plants in the Field and the Company's
contractual arrangements with ANGC, Amoco and pipeline companies
serving the area, will enable the Company to mitigate the effects of
these developments shortly.
Major Gas Projects
Washakie Basin. Since the mid-1980's, the Company's properties
in the Barrel Springs Unit and the Blue Gap Field of southern
Wyoming, together with its gas gathering and transportation
facilities there, have been one of its most significant assets.
During 1995, the Company continued to develop Mesaverde sands in the
Washakie Basin near its existing properties. Eleven wells were
completed in this area in 1995 at depths ranging from 8,000 to 11,000
feet, developing net proved reserves of 1.3 million BOE. By year end,
net production of gas, which accounts for approximately 94% of the
reserves, had reached 22.9 Mmcf per day, a slight increase over
average 1994 production of 21.4 Mmcf per day. Proved reserves at
year end totalled 1.1 million barrels of oil and 105 Bcf of gas, or
18.6 million BOE, as compared to 1.4 million barrels and 130 Bcf, or
23.2 million BOE, at December 31, 1994. An environmental impact
statement covering the Company's northern area was approved in
December 1995, allowing the drilling of up to 500 locations by the
Company and other producers in the area. The Company expects to
drill 20 wells in the Washakie Basin during 1996.
The Company currently operates 159 wells in this area and holds
over 1,200 potential drilling locations, 74 of which were classified
as proved undeveloped at year-end 1995. The Company holds interests
in approximately 110,000 gross (103,000 net) undeveloped acres in the
Washakie Basin.
The Company owns and operates two pipeline systems which
transport gas from wells in the Barrel Springs and Blue Gap Fields
located in the southern portion of Carbon County, Wyoming. The WYGAP
pipeline system, which transports gas from the wells to Western
Transmission ("Westrans"), is comprised of over 185 miles of pipe,
and throughput on the system averaged 24 MMcf per day in 1995, as
compared to 19 MMcf per day in 1994. Westrans is a Company-owned
interstate pipeline system which operates under FERC jurisdiction.
The system consists of a 26-mile 12" pipeline, and 9.2 miles of other
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non-jurisdictional transportation facilities. The mainline extends
from the southern portion of Carbon County, to connections with
Williams' and CIG's interstate pipelines in Sweetwater County,
Wyoming. Daily throughput averaged 28 MMcf per day in 1995, as
compared to 22 MMcf per day during 1994.
Deep Green River. During 1995, the Company continued development
of the fluvial Lance sands in the deep portion of the Green River
Basin. The Company participated in three wells during 1995, with
encouraging results. Production, which commenced in November 1994,
averaged 2.4 MMcf per day in 1995 and reached 6.2 MMcf by year end.
At year end, proved reserves totalled 107,000 barrels of oil and 15.9
Bcf of gas, or 2.8 million BOE. An eight well program is planned for
1996 in strategic locations to earn acreage and further evaluate
potential recoveries. The Company holds interests in approximately
93,000 gross (78,000 net) undeveloped acres in this project. The
Company believes that there are in excess of 500 potential drilling
locations on this acreage. At the end of 1995, only ten locations
were classified as proved undeveloped.
Piceance Basin. The Company operates the 53,000 acre Hunter Mesa
Unit, the 9,000 acre Grass Mesa Unit and the 26,000 acre Divide Creek
Unit in the southeast portion of the Piceance Basin. At year end,
the Company owned approximately 101,000 gross (80,000 net)
undeveloped acres in this area. During 1995, the Company drilled
four new wells to develop and further delineate the Hunter Mesa Unit.
Net production from the Basin averaged 11.9 MMcf per day in 1995, up
from 1994 average production of 4.9 MMcf per day. At year-end 1995,
there were 54 proved producing wells, 36 of which are operated by the
Company. Proved reserves at year end were 42.6 Bcf of gas and
145,000 barrels of oil, or 7.2 million BOE, as compared with 58.1 Bcf
and 86,700 barrels, or 9.8 million BOE, at December 31, 1994. The
decrease in gas reserves is primarily the result of reductions in
proved undeveloped reserves as the result of reduced gas prices.
Proved undeveloped reserves were assigned to 51 locations at year-end
1995.
During 1996, the Company plans to drill 19 wells to develop
infill locations and to further delineate potential reserves by
drilling step-out locations. The primary objective of drilling is
the Mesaverde fluvial sands occurring at a depth of approximately
7,500 feet.
The Company owns and operates the gathering system which
transports gas from wells in the Hunter Mesa/Grass Mesa Field located
in Garfield County, Colorado. The system is comprised of over 45
miles of pipe ranging in diameter from 3" to 12". The system was
enhanced during the year by the addition of compression. Throughput
on the system averaged 14.5 MMcf per day in 1995, as compared to 4.0
MMcf per day in 1994. Gas can be delivered through Rocky Mountain
Natural Gas to Public Service Company of Colorado, Colorado
Interstate Gas Company, the Questar system and Northwest Pipeline's
system. Although this system affords greater transportation capacity
and flexibility, the extent to which the Company will be able to
continue to develop the Piceance Basin is in part dependent on
arranging additional gathering and transportation at a reasonable
cost. The Company is exploring options for gathering and
transporting future gas production, including the possibility of
constructing additional Company owned facilities.
Proposed Partial Sale. The Company is in discussions regarding
the possible sale of interests in its properties in the Washakie,
Deep Green River and Piceance Basins. There can be no assurance that
any such transactions will occur. Should such transaction occur, it
is expected to close early in the second quarter of 1996.
Remaining Rockies Projects
Uinta Basin. In the Uinta Basin, the Company holds interests in
approximately 93,500 gross (73,500 net) acres. During 1995, the
Company drilled one well in the Monument Butte area, two wells in the
Southman Canyon area and three wells in the Leland Bench Field. The
wells drilled in Monument Butte and Leland Bench were successfully
completed. The two wells drilled in the Southman Canyon area were
unsuccessful and abandoned. Net production from the Basin averaged
325 barrels of oil and approximately 1,377 Mcf of gas per day during
December 1995, as compared to 195 barrels and 2,155 Mcf per day
during December 1994. At December 31, 1995, the Company had
interests in 137 producing wells, 85 of which were operated by the
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Company. Proved reserves at year end were 1.6 million barrels of oil
and 3.8 Bcf of gas, or 2.2 million BOE, as compared to 1.5 million
barrels and 14.7 Bcf, or 3.9 million BOE, at December 31, 1994. The
decrease in gas reserves is primarily the result of reductions in
undeveloped reserves throughout the Basin as the result of lower gas
prices and downward revisions as the result of disappointing drilling
results in Southman Canyon.
The potential of the Leland Bench and Horseshoe Bend Fields
depends on the Company's ability to increase recoverable reserves
through secondary recovery. There have been five successful
waterfloods developed within 15 miles of the Leland Bench Field, and
the Horseshoe Bend Field is located within six miles of two large
fields with successful and mature waterfloods. The Company believes
the Green River formation in these fields to be structurally
equivalent to the nearby units that have been successfully
waterflooded. In 1996, the Company plans to begin testing the
secondary recovery potential of its position by implementing two
pilot waterflood projects in the Leland Bench Field, and a third
pilot project in the Horseshoe Bend Field.
Northern Wyoming. In 1992, the Company acquired four large
producing fields from a major oil company. In late 1995, the Company
traded its interest in one of the fields, the Pitchfork Field, for an
increased interest in the Hamilton Dome Field, which is located in
the Big Horn Basin. At year-end 1995, proved reserves at the
Hamilton Dome and Salt Creek Fields totalled 10.9 million BOE,
including 10.8 million barrels of oil and 455 MMcf of gas, up from
9.4 million BOE (9.2 million barrels and 956 MMcf ) at December 31,
1994. This increase was primarily the result of a 1.6 million BOE
addition of proved reserves in Hamilton Dome that resulted from a
property swap. The Hamilton Dome Field produces sour crude oil
primarily from the Tensleep, Madison and Phosphoria formations at
depths of 2,500 to 2,900 feet. The Salt Creek Field produces sweet
crude oil from the Wall Creek formation at depths of 2,000 to 2,900
feet. The Company operates 165 wells, having average net production
during 1995 of 1,500 BOE per day, in the Hamilton Dome Field.
The Riverton Dome Field, located in the Wind River Basin,
produces gas primarily from the Frontier and Dakota tight sands at
depths of 8,000 to 10,000 feet, with some sour crude oil production
from the Tensleep and Phosphoria formations. At year-end 1995,
proved reserves, nearly all gas, totalled 4.3 million BOE. The
Company operates 28 wells having net production of approximately
1,200 BOE per day. Production from this field is processed at a
Company-owned plant.
The Company initiated two new exploitation projects in northern
Wyoming during 1995. In the Wind River Basin, the Company has
assembled approximately 81,000 net undeveloped acres in an area
adjacent to the Company's Riverton Dome Field. In addition, the
Company has obtained an option agreement to exploit oil and gas
resources on approximately 33,000 net acres on Shoshone/Arapaho
tribal lands. In the Big Horn Basin northeast of the Worland Field,
the Company has assembled approximately 112,000 net undeveloped
acres. In both projects, the primary focus is on various Cretaceous
sands ranging from 9,500 to 14,000 feet. Initial drilling on both
projects may begin as early as the fourth quarter of 1996.
Gulf Coast Area
Austin Chalk Trend. In the Giddings Field in southeast Texas,
the Company continued its horizontal drilling program. Horizontal
drilling entails risks in that the technology is still relatively new
and evolving, costs are relatively high, and high initial production,
while leading to high rates of return on successful wells, makes
ultimate recoveries difficult to predict. During 1995, the Company
placed 24 wells on production in the Giddings Field with two wells in
progress at year end. Daily net production averaged 3,600 BOE during
December 1995, approximately equal to December 1994 levels. Proved
reserves are 24% oil and 76% gas and exceeded 3.5 million BOE at year
end. Activity during 1995 focused on development of acreage
targeting the Austin Chalk, Buda and Georgetown formations. Results
in 1995 were disappointing due to poorer than expected production
from the Buda formation and to mechanical difficulties which resulted
in higher costs than expected. However, recent production results
from the Georgetown formation have exceeded expectations, and changes
in drilling procedures have reduced costs substantially. As a
result, the Company expects to focus on continued development of its
Georgetown reserves. The Company plans to drill or recomplete up to
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15 wells during 1996. The Company has 28 locations classified as
proved undeveloped on approximately 99,000 net undeveloped acres in
the Austin Chalk Trend. The total number of potential drillable
locations will depend on the results of the Company's 1996 activities
as well as the results of third-party drilling on adjacent acreage.
The Company plans to exploit its large undeveloped acreage position
by obtaining partners to share the risk of drilling in certain newer
areas of interest.
During 1995, the Company announced that it was considering the
sale of its properties in this area. Due to market conditions, the
Company determined to discontinue its sales efforts in early 1996.
However, the Company will continue to review indications of interest
and may sell some or all of its properties in this area if the
Company believes the prices offered represent the underlying value of
the properties.
In 1995, the Company constructed a new gas gathering system in
Grimes County, Texas as part of its horizontal development program in
the Austin Chalk Trend. The Company is the operator and 50% owner of
the facilities. The pipeline system is comprised of over 31 miles of
pipe ranging in diameter from 3" to 12". Throughput for the system
averaged 14.5 MMcf per day in the fourth quarter of 1995. The
Company has recently received a preliminary offer to purchase the
system for a price substantially in excess of its cost and is
conducting discussions with a view toward the sale of the system
during 1996.
Northern Louisiana. The Company owns over 300,000 net mineral
acres, with lease option agreements covering an equivalent position
in north Louisiana and also owns overriding royalty interests in
approximately 250 producing wells there. The Company also has access
to a database of more than 5,000 miles of seismic data, which the
Company is currently reviewing to develop exploitation and
exploration prospects to drill or to promote to industry partners.
The Company has developed over 12 prospect areas targeting the Cotton
Valley, Hosston and Sligo formations. The Company has reached an
agreement with an independent energy company and the subsidiary of a
seismic company establishing a joint venture under which the other
companies will shoot a 48 square mile 3-D survey in 1996 targeting
several potential Cotton Valley reef structures and other prospective
formations within a 1.7 million acre area of mutual interest. Upon
completion of the first survey, the companies will have the right to
conduct subsequent surveys in the area of mutual interest. The
Company will have the right to participate on favorable terms in
prospects developed by the venture.
Gulf of Mexico. In late 1995, the Company increased its
interest in DelMar Petroleum, Inc., a closely-held company
headquartered in Houston, Texas, to approximately 65%. DelMar
operates 16 platforms in the Gulf of Mexico, including a major
development program covering 11 lease blocks in the Main Pass area,
and manages investment programs for institutional partners. During
1995, DelMar and its partners successfully drilled and completed five
additional wells in the Main Pass area, increasing gross
deliverability to approximately 115 MMcf of gas and 537 barrels of
oil or 19,704 BOE per day at year end, as compared with 65 MMcf and
no oil or 10,833 BOE per day at year-end 1994. DelMar plans to
complete an additional five wells in the Main Pass area during 1996.
In April 1995, DelMar increased its interest in the Main Pass area to
approximately 4% through a property exchange. In late 1995, the
Company acquired the interests of one of DelMar's institutional
partners, including an interest of approximately 8% in the Main Pass
area, in exchange for one million shares of its common stock. The
Company intends to continue to increase its activities in the Gulf of
Mexico, either directly or through DelMar, in 1996 through
acquisition, development and, to a lesser extent, exploration.
International Activities
The Company's strategy internationally is to develop a portfolio
of projects that have the potential to make a major contribution to
its production and reserves while limiting its financial exposure and
mitigating political risk by seeking industry partners and investors
to fund the majority of the required capital. A wholly-owned
subsidiary of the Company, SOCO International, Inc. ("SOCO
International"), is the holding company for all international
operations. The President of SOCO International holds an option,
exercisable through April 1998, to purchase 10% of the currently
outstanding shares of SOCO International.
<PAGE> 8
<PAGE>
Russian Joint Venture. Permtex is a joint drilling venture
formed in 1993 between Permneft, a Russian oil and gas company, and
SOCO Perm Russia, Inc. ("SOCO Perm"), a subsidiary of SOCO
International. The joint venture was formed to develop proven oil
fields located in the Volga-Urals Basin of the Perm Region of Russia,
approximately 800 miles east of Moscow. Permtex holds exploration
and development rights to over 300,000 acres in the Volga-Urals Basin
in a contract area containing four major and four minor fields, as
well as other potential prospects. The Company estimates that the
four major fields contained proved reserves of approximately 38
million barrels of oil at year end (7.8 million barrels net to the
Company), with significant additional reserves expected to be
ultimately recovered if waterflood projects are successfully
implemented. The joint venture utilizes primarily Russian personnel
and equipment and Western technology under joint Russian/American
management.
The major fields were delineated prior to the formation of the
joint venture through 45 previously drilled wells. Six of these
wells and four newly drilled wells have been placed on production and
are currently producing approximately 2,000 barrels per day.
Drilling activity has been slower than anticipated due to
difficulties in securing drilling contracts on commercially
reasonable terms. An 18-mile pipeline was completed in early 1995
which links the Logovskoye Field to Perm where, through a swap
arrangement with LUKoil, the oil enters the export pipeline system.
Through the end of 1995, the joint venture had produced approximately
630,000 barrels of oil, with all production (other than oil in
transit) being exported and sold on the world market.
During 1995, the joint venture paid an average of $3.50 per
barrel in export tariffs. Tentative governmental approval has been
given to lower the export tariff to $1.61 per barrel (based on year-
end currency exchange rates) for 1996, although the decree has not
been signed to date. Permtex has also applied for exemption from the
tariff and has received preliminary indications that an exemption
will be granted.
The slower than expected pace of drilling permitted Permtex's
operating cash flow to fund 80% of its capital expenditures.
The remaining capital expenditures and working capital requirements
were funded by the final $2.75 million payment of SOCO Perm's initial
equity sale. The commitment from the Overseas Private Investment
Company, an agency of the United States Government, to provide up to
$40 million in financing has been extended to mid-1996. In March 1996,
SOCO Perm sold 15% of its shares to two institutional investors for
$10 million. Pursuant to the private placement agreement, the purchasers
would, under certain circumstances, have the right to require SOCO
International to repurchase their shares in mid-1998 based on a formula
price. The Company's interest in SOCO Perm became 34.9% upon the closing
of this transaction.
Permtex plans to drill seven wells in 1996. One rig is currently
drilling and another is rigging up in the Logovskoye Field. Permtex
is also negotiating with other contractors for additional drilling
services. Gross production for the year is expected to be in excess
of one million barrels of oil.
Command Petroleum Limited. In 1993, the Company purchased nearly
43% of the outstanding shares of Command Petroleum Limited
("Command") for approximately $18.2 million. Due to shares
subsequently issued by Command in a series of transactions, the
Company's current interest in Command is 30%. Command is an
exploration and production company based in Sydney, Australia and
listed on the Australian Stock Exchange. At year-end 1995, Command
had a market capitalization of approximately $100 million, working
capital of $11 million and no debt. Command currently holds
interests in more than 14 exploration permits and production licenses
primarily in the Southwestern Pacific Rim including Australia and
Papua New Guinea, Tunisia, Yemen and India. Command also holds an
18.75% interest in SOCO Perm, the Company's Russian venture.
During 1995, Command and its industry partners began the
development of the Ravva Field in the Bay of Bengal in India.
Command owns 22.5% of the venture and is operator of the project,
which is currently producing approximately 3,000 barrels of oil per
day. Completion of the single point mooring system later in 1996 is
expected to permit Ravva production to increase to 35,000 barrels per
day. During the year, Command participated in two exploratory wells,
two re-entries and one appraisal well in the TOTAL-operated East
Shabwa contract area in Yemen, in which Command holds a 14.285%
interest. TOTAL is finalizing development plans for the area, and
<PAGE> 9
<PAGE>
initial production is expected by early 1997. Also in 1995, Command
drilled an exploration well in the Fejaj permit in Tunisia,
participated in two wells in the offshore Zarat permit in Tunisia and
elected to convert its 10% ownership in SOCO Tamtsag Mongolia into a
0.5% override in Blocks XIX and XXI and, if granted to SOCO Tamtsag
Mongolia, Block XXII.
Mongolia. In 1993, SOCO Tamtsag Mongolia, Inc. ("SOCO
Tamtsag"), a subsidiary of SOCO International, entered into a
production sharing agreement with Mongol Petroleum Company, the
national oil company of Mongolia, covering a block of 11,400 square
kilometers (approximately 2.8 million gross acres) in the Tamtsag
Basin of northeastern Mongolia. An adjacent block was acquired in
late 1994, increasing the Company's acreage to 5.3 million acres, in
exchange for a 1.25% overriding royalty interest in both blocks.
These concessions are located between the Hailar and Erlian Basins of
China. SOCO Tamtsag also has applications for production sharing
contracts pending as a co-applicant with the Mongolian government for
an additional five million acres on two blocks adjacent to the
venture's current blocks. If these concessions are awarded, SOCO
Tamtsag's acreage would cover the entire Tamtsag Basin in Mongolia.
The Company's interest in the venture was 42% at year-end 1995.
Although the prospective potential of the previously unexplored
Tamtsag Basin has long been recognized, the lack of an outlet for
production has prevented exploration there. In early 1995, SOCO
Tamtsag entered into an agreement with China National United Oil
Corporation ("CNUOC") under which CNUOC agreed to purchase crude oil
produced by the venture at a mutually-agreed Mongolian/Chinese border
point at world market prices, less $2 per barrel. CNUOC is a joint
venture between China National Petroleum Corporation and SINOCHEM,
both state-owned entities.
During 1995, SOCO Tamtsag continued its seismic acquisition
program and drilled two exploration wells. To date, the venture has
acquired 1,715 kilometers of new seismic data in the Tamtsag basin.
An additional 1,000 kilometers of seismic data will be acquired in
1996. The first well, drilled to a depth of 9,840 feet, encountered
indications of hydrocarbons, but was abandoned. The second well, the
SOTAMO #19-2, reached total depth in October, encountering
hydrocarbons over a 55 foot interval with a possible 144 feet of
additional pay, and will undergo extensive testing when weather
conditions permit the mobilization of proper equipment. Depending on
the results of the testing program, which is expected to begin in
April, an offset well to the SOTAMO #19-2 well may be drilled this
year. Another wildcat well is also planned to begin by mid-year.
Thailand. In 1995, ownership of the 150,000 acre Block B4/32
concession in the Gulf of Thailand was formally transferred to SOCO
Thaitex, Inc. which is owned 95% by SOCO International. The assignor
company retained a 25% reversionary interest in the block. The
Company is currently seeking partners to join in a wildcat well
expected to be drilled later in 1996.
Vietnam. In late 1994, the Company signed a Memorandum of
Understanding with Petrovietnam Exploration and Production regarding
a joint exploration and development program on a certain concession
offshore Vietnam. Since that time, negotiations regarding a joint
venture structure have progressed considerably and have resulted in
a formal bid being submitted for the offshore concession.
Petrovietnam has indicated that the bids closed on February 28, 1996.
The Company expects the bid evaluation and award process to be
completed by mid-1996.
<PAGE> 10
<PAGE>
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 each of the years in the five year period ended
December 31, 1995.
<TABLE>
<CAPTION> December 31,
-----------------------------------------------------------------------------------
1991 1992 1993 1994 1995
-------- -------- -------- -------- --------
(Dollars in thousands, except prices and per barrel equivalent information)
<S> <C> <C> <C> <C> <C>
Production
Oil (MBbl) 1,487 1,776 3,451 4,366 4,278
Gas (MMcf) 18,382 23,090 35,080 43,809 53,227
MBOE (a) 4,937 5,989 9,297 11,668 13,149
Revenues
Oil $ 30,667 $ 33,512 $ 53,174 $ 64,625 $ 72,550
Gas (b) 34,677 43,851 71,467 73,233 72,058
--------- -------- --------- --------- ---------
Subtotal 65,344 77,363 124,641 137,858 144,608
--------- -------- --------- --------- ---------
Transportation, processing
and marketing 21,459 38,611 94,839 107,247 38,256
Other (163) 2,996 9,372 17,223 19,296
---------- --------- --------- --------- ---------
Total $ 86,640 $ 118,970 $ 228,852 $ 262,328 $ 202,160
========== ========= ========= ========= =========
Operating expenses
Production $ 24,882 $ 28,057 $ 41,401 $ 46,267 $ 52,486
Transportation, processing
and marketing 14,202 30,469 85,640 94,177 29,374
Exploration 2,294 1,515 2,960 6,505 8,033
---------- --------- ---------- --------- ---------
$ 41,378 $ 60,041 $ 130,001 $ 146,949 $ 89,893
========== ========= ========= ========= =========
Direct operating margin $ 45,262 $ 58,929 $ 98,851 $ 115,379 $ 112,267
========== ========= ========= ========= =========
Production data
Average sales price (c)
Oil (Bbl) $ 20.62 $ 18.87 $ 15.41 $ 14.80 $ 16.96
Gas (Mcf) (a) (b) 1.68 1.74 1.94 1.67 1.35
BOE (a) 13.24 12.92 13.41 11.82 11.00
Average production expense/BOE $ 5.04 $ 4.68 $ 4.45 $ 3.97 $ 3.99
Average production margin/BOE $ 8.20 $ 8.24 $ 8.96 $ 7.85 $ 7.01
<f/n>
- -------------------------
(a) Gas production is converted to oil equivalents at the rate of 6
Mcf per barrel. Prior to 1993 certain high priced gas was
converted based on price equivalency. Average gas prices
exclude this high priced gas production.
(b) Sales of natural gas liquids are included in gas revenues.
(c) The Company estimates that its composite net wellhead prices at
December 31, 1995 were approximately $1.52 per Mcf of gas and
$18.08 per barrel of oil.
</TABLE>
<PAGE> 11
<PAGE>
Drilling Results
The following table sets forth information with respect to
domestic 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>
1993 1994 1995
---- ---- ------
<S> <C> <C> <C>
Development wells
Productive
Gross 382.0 466.0 223.0
Net 316.0 390.6 133.1
Dry
Gross 10.0 12.0 5.0
Net 5.5 11.1 3.8
Exploratory wells
Productive
Gross 2.0 - -
Net 2.0 - -
Dry
Gross 6.0 13.0(a) -
Net 3.3 10.5 -
<f/n>
(a) Ten (8.75 net) of the dry holes were drilled to test shallow
formations in North Louisiana at an approximate cost of $60,000 per
well. See "Domestic Operations - Gulf Coast Area."
</TABLE>
On December 31, 1995, the Company had 9 gross (8.2 net)
development wells and 1 gross (0.3 net) exploratory well in progress.
Between year end and February 29, 1996, the Company spudded 8 wells.
At that date, 8 gross (7.5 net) wells, including wells in progress at
year end, had been completed, and 10 gross (6.8 net) development
wells were in progress.
Customers and Marketing
The Company's oil and gas production is principally sold to end
users, marketers and other purchasers having access to pipeline
facilities near its properties. Where there is no access to
pipelines, crude oil is trucked to storage facilities. In 1993, 1994
and 1995, Amoco Production Company accounted for approximately 12%,
11% and 10% of revenues, respectively. The marketing of oil and gas
by the Company can be affected by a number of factors that are beyond
its control and whose future effect cannot be accurately predicted.
The Company does not believe, however, that the loss of any of its
customers would have a material adverse effect on its operations.
The Company's gas marketing effort is currently exclusively
focused on the sale of production from its properties. Third party
gas marketing was discontinued in 1994. The total volume of gas
production marketed from properties operated by the Company is
currently in excess of 150 MMcf per day. Market conditions in 1995
highlighted the need to create new market outlets for Rocky Mountain
gas. The Company is continuing to develop an overall strategy to
manage the risk associated with volatile prices in markets for its
products. As part of a program to diversify the markets for its gas
production, the Company has pursued transactions that effectively
transfer the price that it receives for a portion of its Rocky
Mountain gas to the Gulf Coast market. See Note 2 to the
Consolidated Financial Statements of the Company. As of year-end
<PAGE> 12
<PAGE>
1995, 59% of the Company's production is sold under arrangements that
are responsive to Rocky Mountain market conditions, and 41% is sold
in the Gulf Coast market. In addition, prices for Wattenberg Field
gas have recently been significantly higher than broader index-based
prices for Rocky Mountain gas, and there are indications that the
disparity may continue. The Company is considering alternative
marketing and pricing arrangements to take advantage of this
potential additional value for its Wattenberg Field production.
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.
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 title 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 SOCO'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
<PAGE> 13
<PAGE>
administered by the Federal Energy Regulatory Commission ("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
SOCO, 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
SOCO is unable to predict the impact on its natural gas production
and marketing operations of judicial review of these orders.
In April 1992, FERC issued Order 636, a rule designed to
restructure the interstate natural gas transportation and marketing
system to remove various barriers and practices that have
historically limited non-pipeline gas sellers, including producers,
from effectively competing with pipelines. The restructuring process
required the "unbundling" of pipeline services (e.g., transportation,
sales and storage) so that producers, marketers and end users of
natural gas contract only for those services which they need and may
obtain each service from the most economical source. The 1993-1994
winter heating season was the first period during which FERC Order
636 procedures were operatives. To date, management of SOCO believes
the Order 636 procedures have not had any significant effect on SOCO.
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. Many states also have statutes and
regulations governing a number of environmental and conservation
matters.
In Colorado, surface owner groups have been active at both the
state and local levels, and there have been a number of city and
county governments who have either enacted new regulations or are
considering doing so. The incident of such local regulation
increased following a decision of the Colorado Supreme Court which
held that local governments could not prohibit the conduct of
drilling activities which were the subject of permits issued by the
Colorado Oil and Gas Conservation Commission ("COGCC"), but that they
could limit those activities under their land use authority. Under
this decision, local municipalities and counties may take the
position that they have the authority to impose restrictions or
conditions on the conduct of such operations which could materially
increase the cost of such operations or even render them entirely
uneconomic. The Company is not able to predict which jurisdictions
may adopt such regulations, what form they may take, or the ultimate
effects of such enactments on its operations. In general, however,
these ordinances are aimed at increasing the involvement of local
governments in the permitting of oil and gas operations, requiring
additional restrictions or conditions on the conduct of operations,
to reduce the impact on the surrounding community and increasing
financial assurance requirements. Accordingly, the ordinances have
the potential to delay and increase the cost, or in some cases, to
prohibit entirely the conduct of drilling operations.
In response to the concerns of surface owners, during 1993 the
COGCC adopted regulations for the Wattenberg area 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.
<PAGE> 14
<PAGE>
During 1995, the COGCC coordinated four task forces to study and
promulgate rules regarding protection of water quality, reclamation,
administrative procedures, safety, plugging and abandonment. In
1996, a fifth task force will be selected to address financial
security matters. These task forces arose out of a 1994 statute
which gave the COGCC authority to consider health, safety and welfare
of the public, as well as the promotion of oil and gas development,
in its decision making process. Participants in the task forces
include representatives of the oil and gas industry, environmental
groups, the agricultural industry, local governments and other
interested groups. While the oil and gas industry is an active
participant in the task forces, it is possible that the
recommendations to the COGCC will result in additional restrictions
that could increase the cost of oil and gas operations in Colorado.
Environmental Regulations. Operations of the Company are subject
to numerous laws and regulations governing the discharge of materials
into the environment or otherwise relating to environmental
protection. These laws and regulations may require the acquisition
of a permit before drilling commences, prohibit drilling activities
on certain lands lying within wilderness and other protected areas
and impose substantial liabilities for pollution resulting from
drilling operations. Such laws and regulations also restrict air or
other pollution and disposal of wastes resulting from the operation
of gas processing plants, pipeline systems and other facilities owned
directly or indirectly by the Company.
The Company currently owns or leases numerous properties that
have been used for many years for natural gas and crude oil
production. Although the Company believes that it and other previous
owners have utilized operating and disposal practices that were
standard in the industry at the time, hydrocarbons or other wastes
may have been disposed of or released on or under the properties
owned or leased 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 they are divested or 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 Resources
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 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 recently promulgated rules
to implement Senate Bill 89-181 which designated the COGCC as an
implementing agency for the Colorado Water Quality Control
Commission's groundwater standards. The revised rules include
production pit/buried vessel testing, spill and release reporting and
facility remediation. In response to these rules, the Company has
registered some 950 partially buried vessels that will require
integrity testing prior to July 1, 1997. The Company will replace or
repair vessels as necessary. In addition, the Jicarilla Apache
Tribe, recently promulgated regulations prohibiting future use of
unlined surface impoundments and outlined closure guidelines for
existing unlined impoundments. The Company has submitted a site
assessment plan outlining closure activities for some 30 impoundment
locations. These closure activities commenced in August 1995 and
will continue through December 1998. Management believes that
compliance with current applicable laws and regulations will not have
a material adverse impact on the Company.
<PAGE> 15
<PAGE>
During 1996, the COGCC has scheduled rulemaking proceedings to
consider, among other things, public safety and facility reclamation
activities. It is possible that the COGCC will require annual
integrity testing of production flowlines, and could require
additional wildlife impact studies prior to approving drilling
permits. In addition, various landowner, general public, and local
governmental notices are being considered. The Company is unable to
predict when and if the rules will be adopted and, if adopted, the
number of facilities that will be affected or the procedures
involved.
Currently the COGCC is conducting rule making proceedings
regarding Colorado Statewide Reclamation Rules. These proposed rules
address all aspects of reclamation of land and soil affected by oil
and gas operations including well permitting, surface owner
notification and consultation, site preparation and interim and final
reclamation. In addition, flowline and gathering line construction
and annual pressure testing requirements are included. The Company
is unable to predict when and if the rules will be adopted and, if
adopted the number of facilities that will be affected or the
procedures involved.
States in which the Company operates have also adopted
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 the
Company's facilities that require permits, which could increase the
Company's cost of operations and restrict its activities in certain
areas.
Federal Leases. The Company conducts operations under federal
oil and gas leases. These operations must be conducted in accordance
with permits issued by the Bureau of Land Management ("BLM") and are
subject to a number of other regulatory restrictions. Multi-well
drilling projects on federal leases may require preparation of an
environmental assessment or environmental impact statement before
drilling may commence. Moreover, on certain federal leases, prior
approval of drill site locations must be obtained from the
Environmental Protection Agency.
Officers
Listed below are the officers and a summary of their recent
business experience.
Name Position
John C. Snyder Chairman and Director
Thomas J. Edelman President and Director
Charles A. Brown Senior Vice President - Rocky Mountain Division
Steven M. Burr Vice President - Engineering and Planning
Ronald E.Dashner Vice President - Rockies
Peter C. Forbes Vice President - Gulf of Mexico
Peter E. Lorenzen Vice President - General Counsel
H. Richard Pate Vice President - Major Gas Projects
David M. Posner Vice President - Gas Management
James H. Shonsey Vice President - Finance
Edward T. Story Vice President - International and Director
Rodney L. Waller Vice President - Special Projects
Richard A. Wollin Vice President - Southern Division and
Acquisitions
John C. Snyder (54), a director and Chairman, founded a
predecessor of the Company 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
<PAGE> 16
<PAGE>
president of Canadian-American Resources Fund, Inc., which he founded
in 1969. From 1964 to 1966, Mr. Snyder was employed by Humble Oil
and Refining Company (currently Exxon Co., USA) as a petroleum
engineer. Mr. Snyder received his Bachelor of Science Degree in
Petroleum Engineering from the University of Oklahoma and his Masters
Degree in Business Administration from the Harvard University
Graduate School of Business Administration. Mr. Snyder is a director
of the Community Enrichment Center, Inc., Fort Worth.
Thomas J. Edelman (45), a director and President, founded a
predecessor of the Company in 1981. Prior to 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
will serve as Chairman of the Board, President and Chief Executive
Officer of Patina Oil and Gas Corporation, a company being formed to
consoldate the Company's Wattenberg assets with Gerrity Oil & Gas
Corporation, and is a director of Command Petroleum Limited and
Chairman of Amerac Energy Corporation, affiliates of the Company. In
addition, Mr. Edelman serves as a director of Petroleum Heat & Power
Co., Inc., a Connecticut based fuel oil distributor, and its
affiliate Star Gas Corporation. Mr. Edelman is also Chairman of
Lomak Petroleum, Inc.
Charles A. Brown (49), Senior Vice President - Rocky Mountain
Division, 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 Kansas Nebraska Natural Gas Company 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 (39), Vice President - Engineering and Planning,
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.
Ronald E. Dashner (43), Vice President - Rockies, has served in
that position since late 1995. Prior to that he was Operations
Manager of the Company's DJ Basin/Greater Green River Unit since
joining the Company in 1994. From 1991 to 1994, Mr. Dashner was
Onshore Gulf Coast Operations Manager for Enron Oil & Gas Company.
From 1980 through 1990, Mr. Dashner held various positions with TXO
Production Corp., including Drilling & Production Manager - Rocky
Mountain District and Assistant District Manager - East Texas
District. From 1978 to 1980, he was employed by Davis Oil Company in
Engineering and Operations. From 1975 to 1978, he was employed by
Chevron in the Drilling, Production and Construction Department. Mr.
Dashner received his Bachelor of Science Degree in Civil Engineering
from Colorado State University.
Peter C. Forbes (50), Vice President - Gulf of Mexico, who was
appointed to that position in 1996, has been Executive Vice President
of DelMar Petroleum, Inc., the Company's Gulf Coast subsidiary, since
July 1995. From 1994 to 1995, he was President and Chief Executive
Officer of SD Resources, Inc., the general partner of Sand Dollar
Resources L.P., a partnership with Enron Gas Services Corp., a
subsidiary of Enron Corp. From 1992 to 1993, Mr. Forbes was Vice
President in charge of the oil and gas property acquisition unit of
Enron Gas Services Corp. From 1988 to 1992, he was President and a
director of American Exploration Company. Prior thereto, Mr. Forbes
was Vice President, Finance of Browning-Ferris Industries, Inc.
during 1988 and Senior Vice President and Chief Financial Officer of
Zapata Corporation from 1985 to 1987. He served in several
positions, including Vice President and Treasurer, at Texas Eastern
Transmission Corporation from 1975 to 1985. Mr. Forbes received his
Bachelor of Arts Degree from Edinburgh University.
Peter E. Lorenzen (46), Vice President - General Counsel and
Secretary, joined the Company in 1991. From 1983 through 1991, he
was a shareholder in the Dallas law firm of Johnson & Gibbs, P.C.
Prior to that, Mr. Lorenzen was an associate with Cravath, Swaine &
Moore. Mr. Lorenzen received his law degree from New York University
School of Law and his Bachelor of Arts Degree from The Johns Hopkins
University.
<PAGE> 17
<PAGE>
H. Richard Pate (42), Vice President - Major Gas Projects,
joined the Company in 1988. From 1981 to 1988, Mr. Pate held various
positions with Mitchell Energy Corporation, including Region Engineer
and Production Manager. He was employed by Champlin Petroleum
Company from 1979 to 1981 and Atlantic Richfield Corporation from
1975 to 1979. Mr. Pate received his Bachelor of Science Degree in
Chemical Engineering from the University of Wyoming.
David M. Posner (42), Vice President - Gas Management Group,
joined the Company in 1991. From 1980 to 1991 he held various
positions with Ladd Petroleum Corporation (a subsidiary of the
General Electric Company) including Vice President of Gas Gathering,
Processing and Marketing. Mr. Posner received his Bachelor of Arts
from Brown University and his Master of Science in Mineral Economics
from the Colorado School of Mines.
James H. Shonsey (44), Vice President - Finance, joined the
Company in 1991. From 1987 to 1991, Mr. Shonsey served in various
capacities including Director of Operations Accounting for Apache
Corporation. From 1976 to 1987 he held various positions with
Deloitte & Touche, Quantum Resources Corporation, Flare Energy
Corporation and Mizel Petro Resources, Inc. Mr. Shonsey received his
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 (52), a director and Vice President -
International of the Company and President of SOCO International,
Inc., joined the Company in 1991. Mr. Story became a director of the
Company in February 1996. From 1990 to 1991, Mr. Story was Chairman
of the Board of a jointly-owned Thai/US company, Thaitex Petroleum
Company. Mr. Story was co-founder, Vice Chairman of the Board and
Chief Financial Officer of Conquest Exploration Company from 1981 to
1990. He served as Vice President Finance and Chief Financial
Officer of Superior Oil Company from 1979 to 1981. Mr. Story held
the positions of Exploration and Production Controller and Refining
Controller with Exxon U.S.A. from 1975 to 1979. He held various
positions in Esso Standard's international companies from 1966 to
1975. Mr. Story received a Bachelor of Science Degree in Accounting
from Trinity University, San Antonio, Texas and a Masters of Business
Administration from The University of Texas in Austin, Texas. Mr.
Story is a director of Command Petroleum Limited, an affiliate of the
Company. In addition, Mr. Story serves as a director of First
BanksAmerica, Inc., a bank holding company, Hi/Lo Automotive, Inc.,
a distributor of automobile parts, Hallwood Realty Corporation, the
general partner of Hallwood Realty Partners, L.P., an American Stock
Exchange-listed real estate limited partnership, New Concept
Technologies International Limited, an Alberta-listed real estate and
energy company, and Territorial Resources, Inc., a publicly traded
oil and gas company.
Rodney L. Waller (46), 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.
Richard A. Wollin (43), Vice President - Southern Division and
Acquisitions, joined the Company in 1990. From 1983 to 1989, Mr.
Wollin served in various management capacities including Executive
Vice President of Quinoco Petroleum, Inc. with primary responsibility
for acquisition, divestiture and corporate finance activities. From
1976 to 1983, he was employed in various capacities for The St. Paul
Companies, Inc., including Senior Vice President of St. Paul Oil &
Gas Corp. Mr. Wollin received his Bachelor of Science Degree from
St. Olaf College and his law degree from the University of Minnesota
Law School. Mr. Wollin is a member of the Minnesota Bar Association.
<PAGE> 18
<PAGE>
ITEM 2. PROPERTIES
General
The Company's reserves are concentrated in several major
producing areas. These include the Wattenberg Field of Colorado,
Washakie and Green River Basins in southern Wyoming, the Hamilton
Dome, Riverton Dome, Big Horn and Wind River Basins in northern
Wyoming, the Piceance and Uinta Basins in western Colorado and Utah
and the Gulf Coast area.
At December 31, 1995, the Company had interests in 4,294 gross
(2,105 net) producing oil and gas wells located in 11 states and in
the Gulf of Mexico. As of December 31, 1995, estimated proved
reserves totalled 90.2 million BOE, including 24.2 million barrels of
oil and 395.7 Bcf of gas.
Proved Reserves
The following table sets forth estimated year-end proved reserves
for each of the years in the three year period ended
December 31, 1995. On a pro forma basis giving effect to the
proposed Patina transaction, proved reserves at December 31, 1995
would increase to 41.1 million barrels of oil and 604.3 Bcf of gas or
141.9 million BOE.
<TABLE>
<CAPTION>
December 31,
----------------------------------------------
1993 1994 1995
---------- ---------- ----------
<S> <C> <C> <C>
Crude oil and liquids (MBbl)
Developed 18,032 26,104 21,637
Undeveloped 13,898 8,873 2,610
------- ------- -------
Total 31,930 34,977 24,247
======= ======= =======
Natural gas (MMcf)
Developed 268,349 353,930 330,524
Undeveloped 161,740 157,321 65,194
------- ------- -------
Total 430,089 511,251 395,718
======= ======= =======
Total MBOE 103,612 120,186 90,200
======= ======= =======
</TABLE>
The following table sets forth pretax future net revenues from
the production of proved reserves and the Pretax PW10% Value of such
revenues. The pretax present value at 10% of the Company's reserves
at December 31, 1995 on a pro forma basis giving effect to the
proposed Patina transaction would increase to $606 million.
<TABLE>
<CAPTION>
(In thousands) December 31, 1995
---------------------------------------------------------------
Developed Undeveloped(a) Total
--------- -------------- --------
<S> <C> <C> <C>
1996 $ 89,280 $ (8,743) $ 80,537
1997 71,033 (2,843) 68,190
1998 58,188 8,971 67,159
Remainder 329,938 59,064 389,002
-------- -------- --------
Total $548,439 $ 56,449 $604,888
======== ======== ========
Pretax PW10% Value (b) $349,563 $ 23,248 $372,811
======== ======== ========
<f/n>
(a) Net of estimated capital costs, including estimated costs of
$16.8 million during 1996.
(b) The after tax PW10% value of proved reserves totalled $331.1
million at year-end 1995.
</TABLE>
<PAGE> 19
<PAGE>
The quantities and values shown in the preceding tables are based
on prices in effect at December 31, 1995, averaging $18.08 per Bbl of
oil and $1.52 per Mcf of gas. Price reductions decrease reserve
values by lowering the future net revenues attributable to the
reserves and also by reducing the quantities of reserves that are
recoverable on an economic basis. Price increases have the opposite
effect. Any significant decline in prices of oil or gas could have a
material adverse effect on the Company's financial condition and
results of operations.
Proved developed reserves are proved reserves that are expected
to be recovered from existing wells with existing equipment and
operating methods. Proved undeveloped reserves are proved reserves
that are expected to be recovered from new wells drilled to known
reservoirs on undrilled acreage for which the existence and
recoverability of such reserves can be estimated with reasonable
certainty, or from existing wells where a relatively major
expenditure is required to establish production.
Future prices received for production and future production costs
may vary, perhaps significantly, from the prices and costs assumed
for purposes of these estimates. There can be no assurance that the
proved reserves will be developed within the periods indicated or
that prices and costs will remain constant. With respect to certain
properties that historically have experienced seasonal curtailment,
the reserve estimates assume that the seasonal pattern of such
curtailment will continue in the future. There can be no assurance
that actual production will equal the estimated amounts used in the
preparation of reserve projections.
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") and Ryder Scott
Company Petroleum Engineers ("Ryder Scott"), independent petroleum
consultants, prepared estimates of the Company's proved reserves
which collectively represent more than 80% of Pretax PW10% Value as
of December 31, 1995. Approximately 73% was estimated independently
by NSAI and 8% by Ryder Scott. 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, 1995 relating to the producing wells in which the Company owned
a working interest. The Company also held royalty interests in 517
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 2,571 1,413 55%
Natural gas 1,206 692 57%
----- -----
Total 3,777 2,105 56%
===== =====
</TABLE>
<PAGE> 20
<PAGE>
Acreage
The following table sets forth certain information at December
31, 1995 relating to acreage held by the Company. Undeveloped
acreage is acreage held under lease, permit, contract, or option that
is not in a spacing unit for a producing well, including leasehold
interests identified for development or exploratory drilling.
<TABLE>
<CAPTION>
Gross Net
---------- -----------
<S> <C> <C>
Domestic
Developed (a) 300,000 225,000
Undeveloped 1,318,000 1,081,000
--------- ---------
Total 1,618,000 1,306,000
========= =========
International (b)
Undeveloped
Russia 306,000 63,000
Mongolia 5,300,000 2,226,000
Thailand 150,000 150,000
--------- ---------
Total 5,756,000 2,439,000
========= =========
<f/n>
(a) Developed acreage is acreage assigned to producing wells.
(b) International acreage excludes 9.7 million gross (2.4 million
net) acres held by Command, primarily in Australia, Papua New
Guinea,Tunisia, Yemen and India.
</TABLE>
Significant Properties
Emphasis has been placed on establishing hubs in certain
producing areas. Interests in six producing areas accounted for
approximately 84% of Pretax PW10% Value at December 31, 1995. This
concentration of assets permits economic efficiencies in the
management of assets and permits identification of complementary
acquisition candidates. Summary information regarding reserve
concentrations of the six most significant properties are set forth
below. More detailed information is set forth under "Business -
Domestic Operations."
<TABLE>
<CAPTION>
Proved Reserve Quantities
------------------------------------------------- Pretax PW 10% Value
Producing Crude Oil Natural Oil ----------------------
Wells & Liquids Gas Equivalent Amount Percent
---------- ---------- ---------- ----------- -------- --------
(MBbl) (MMcf) (MBOE) (000)
<S> <C> <C> <C> <C> <C> <C>
Wattenberg (CO) 1,635 7,421 138,857 30,564 $146,855 39.4%
Northern Wyoming(WY) 1,206 11,072 24,788 15,204 57,176 15.3
Washakie(WY) 173 1,067 105,067 18,578 45,417 12.2
Gulf of Mexico 44 748 16,309 3,466 28,982 7.8
Giddings Field (TX) 110 845 16,366 3,573 21,945 5.9
Piceance (CO) 51 145 42,557 7,238 14,509 3.9
----- ------ ------- ------ -------- ------
Subtotal 3,219 21,298 343,944 78,623 314,884 84.5
Other 558 2,949 51,774 11,577 57,927 15.5
----- ------ ------- ------ -------- ------
Total 3,777 24,247 395,718 90,200 $372,811 100.0%
===== ====== ======= ====== ======== ======
</TABLE>
<PAGE> 21
<PAGE>
ITEM 3. LEGAL PROCEEDINGS
In August 1994, five landowners in Weld County, Colorado sued
Union Pacific Resources Company ("UPRC"), the Company and other
defendants in Weld County District Court, State of Colorado,
challenging UPRC's reservation of minerals in deeds occurring in the
first decade of this century. In September 1994, the case was
removed to the U. S. District Court of the District of Colorado. The
defendants have filed a motion for summary judgment asking the
District Court to rule as a matter of law that UPRC owns the oil and
gas that are part of the severed mineral estate. Similar claims were
made under identical reservations by Utah and Wyoming surface owners
in cases litigated in the federal courts of those states between 1979
and 1987. In those cases, the Federal courts held as a matter of law
that, under the laws of Utah and Wyoming, these mineral reservations
unambiguously severed the mineral estate from the surface estate and
reserved to Union Pacific Railroad Company and its successors all
subsurface substances, including oil and gas. These holdings were
affirmed by the United States Court of Appeals for the Tenth Circuit.
While the Company believes that the rule of law applied by the
federal courts in Utah and Wyoming should also be applied under
Colorado law, there are Colorado court decisions that could provide
a basis for an alternative interpretation. The present value of the
disputed reserves on the Company's properties leased from UPRC
subject to the lawsuit is estimated to be approximately $500,000 as
of year-end 1995. The Company holds approximately 13,000 net acres
of other lands in the Wattenberg Field that are subject to
substantially the same mineral reservations at issue in the present
suit. An adverse interpretation of the reservations at issue is
likely to implicate UPRC's, and thus the Company's, title in these
other lands as well.
In August 1995, the Company was sued in the United States
District Court of Colorado by seven plaintiffs purporting to
represent all persons who, at any time since January 1, 1960, have
had agreements providing for royalties from gas production in
Colorado to be paid by the Company under a number of various lease
provisions. The plaintiffs allege that the Company improperly
deducted unspecified "post-production" costs incurred by the Company
prior to calculating royalty payments in breach of the relevant lease
provisions, and that the Company fraudulently concealed that fact
from plaintiffs. The plaintiffs have recently amended the complaint
to allege that the Company has also underpaid royalties on oil
production. The plaintiffs seek unspecified compensatory and punitive
damages and a declaratory judgment that the Company is not permitted
to deduct post-production costs prior to calculating royalties paid
to the class. The Company believes that its calculations of
royalties are and have been proper under the relevant lease
provisions, and intends to defend this and any similar suits
vigorously.
The Company and its subsidiaries and affiliates are named
defendants in lawsuits and involved from time to time in governmental
proceedings, all arising in the ordinary course of business.
Although the outcome of these lawsuits and proceedings cannot be
predicted with certainty, management does not expect these matters to
have a material adverse effect on the financial position of the
Company.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted for a vote of security holders during
the fourth quarter of 1995.
<PAGE> 22
<PAGE>
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED
SECURITY HOLDER MATTERS
The Company's stock is listed on the New York Stock Exchange and
trade under the symbol "SNY". The following table sets forth, for
1994 and 1995, the high and low sales prices for the Company's
securities for New York Stock Exchange composite transactions, as
reported by The Wall Street Journal.
<TABLE>
<CAPTION>
1994 1995
----------------------------------- ------------------------------
High Low High Low
--------------- ------------- ------------- -----------
<S> <C> <C> <C> <C>
First Quarter $21-3/8 $17-1/2 $15-1/4 $13-1/2
Second Quarter 20-1/2 17-1/2 15-3/8 11-7/8
Third Quarter 19-3/4 17-1/8 14 10-3/4
Fourth Quarter 17-7/8 13-5/8 12-3/4 10
</TABLE>
On March 20, 1996, the closing price of the common stock was $7-
7/8. Dividends were paid at the rate of $.06 per share in the first
and second quarters of 1994. In the third quarter of 1994, the
quarterly dividend was increased to $.065 per share. For federal
income tax purposes, 61% of common dividends paid during 1994 and
100% of common dividends paid during 1995 were a non-taxable return
of capital. The Company currently estimates that all or a
significant portion of common dividends paid during 1996 will
constitute a return of capital. Shares of common stock receive
dividends as, if and when declared by the Board of Directors. The
amount of future dividends will depend on debt service requirements,
dividend requirements on preferred stock, capital expenditures and
other factors. On December 31, 1995, there were approximately 2,900
holders of record of the common stock and 31.4 million shares
outstanding.
<PAGE> 23
<PAGE>
ITEM 6. SELECTED FINANCIAL DATA
The following table presents selected financial and operating
information for each of the five years ended December 31, 1995.
Share and per share amounts refer to common shares. The following
information should be read in conjunction with the financial
statements presented elsewhere herein.
<TABLE>
<CAPTION>
(In thousands, except per share data) As of or for the Year Ended December 31,
------------------------------------------------------------------------
1991 1992 1993 1994 1995
---------- ---------- ---------- ----------- ----------
<S> <C> <C> <C> <C> <C>
Income Statement
Revenues $ 86,640 $118,970 $228,852 $262,328 $202,160
Income (loss) before extraordinary
items 3,663 14,597 22,538 12,372 (39,831)
Per share .14 .43 .58 .07 (1.53)
Net income (loss) 3,663 14,597 19,545 12,372 (39,831)
Per share .14 .43 .45 .07 (1.53)
Dividends per share .20 .25(a) .22 .25 .26
Average shares outstanding 22,839 22,722 23,096 23,704 30,186
Cash Flow
Net cash provided by operations $ 37,738 $ 48,339 $ 68,728 $ 86,461 $ 68,720
Net cash realized (used) by investing (41,120) (73,645) (207,933) (245,332) 32,993
Net cash realized (used) by financing 11,268 21,079 129,633 169,691 (96,183)
Balance Sheet
Working capital $ 17,259 $ 7,619 $ 491 $ 708 $ 5,842
Oil and gas properties, net 160,979 241,804 316,406 472,239 435,217
Total assets 238,992 331,638 453,301 673,259 555,493
Senior debt 17,108 96,568(b) 114,952 234,857 150,001
Subordinated notes, net 25,000 18,750 - 83,650 84,058
Stockholders' equity 165,210 168,866 274,734 274,086 235,368
<f/n>
(a) Due to revised timing, five payments were made at a quarterly
rate of $.05 in 1992.
(b) Includes $49.8 million paid in February 1993 for properties
acquired in December 1992.
</TABLE>
The following table sets forth unaudited summary financial
results on a quarterly basis for the two most recent years.
<TABLE>
<CAPTION>
(In thousands, except per share data) 1994
---------------------------------------------------------------
First Second Third Fourth
-------- --------- -------- --------
<S> <C> <C> <C> <C>
Revenues $ 63,456 $ 64,578 $ 71,051 $ 63,243
Depletion, depreciation and amortization and
property impairments 19,391 18,164 18,742 20,256
Gross profit 8,855 9,365 9,886 10,720
Net income (loss) 4,578 3,663 2,261 1,870
Per share .08 .04 (.02) (.03)
1995
-------------------------------------------------------------
First Second Third Fourth
------ --------- -------- --------
Revenues $ 53,017 $ 57,142 $ 50,839 $ 41,162
Depletion, depreciation and amortization and
property impairments 19,986 20,675 22,540 40,589(a)
Gross profit (deficit) 8,901 12,564 1,672 (14,660)
Net income (loss) (5,981) 525 (9,606) (24,769)
Per share (.25) (.03) (.37) (.88)
<f/n>
(a) Includes $24.1 million of property impairments.
</TABLE>
<PAGE> 24
<PAGE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
Results of Operations
Comparison of 1995 results to 1994. Total revenues for 1995
were $202.2 million, a $60.2 million decline from 1994. The revenue
decrease included $56 million as a result of the suspension of low
margin third party gas marketing activities late in 1994 and a $13
million decrease due to the sale of the Wattenberg gas facilities
in 1995. Oil and gas sales rose 5% to $144.6 million as a
result of a 13% growth in production of barrels of oil equivalent
("BOE"). The production increase was partially offset by a 7%
decrease in the average price received per BOE. Natural gas prices
dropped 19% in 1995 to an average of $1.35 per Mcf, the lowest
average price received in the Company's history. Oil prices
improved 15% to average $16.96 per barrel.
The net loss for 1995 was $39.8 million, compared to net income
in 1994 of $12.4 million. The 1995 loss was primarily due to $27.4
million in non-cash property impairment charges and almost $11
million in losses as a result of a litigation settlement, losses on
marketable securities, as well as severance and restructuring costs.
The property impairment charges resulted from the fourth quarter
adoption of Statement of Financial Accounting Standards No. 121
("SFAS 121"), "Accounting for the Impairment of Long-Lived Assets and
for Long-Lived Assets to Be Disposed Of". Prior to the fourth
quarter of 1995, the Company provided impairments for significant
proved and unproved oil and gas property groups to the extent that
net capitalized costs exceeded aggregate undiscounted future cash
flows. SFAS 121 requires the Company to assess the need for an
impairment of capitalized costs of oil and gas properties on a
property-by-property basis. If an impairment is indicated based
on undiscounted expected future cash flows, then a loss is
recognized sufficient to bring net capitalized costs down to
discounted expected future cash flows. The decline in net income
also resulted from falling natural gas prices and sharply
increased financing costs incurred prior to the reduction in
outstanding debt accomplished during the latter half of 1995.
Revenues from production operations less direct operating
expenses in 1995 were $92.1 million, slightly above the 1994
level. Average daily production during 1995 was 36,024 BOE, up
13% from 1994 levels, although the average product price received
decreased by 7% to $11.00 per BOE. The production increase resulted
primarily from newly drilled wells placed on production in late 1994
and early 1995. In 1995, the Company placed 223 wells on sales,
including 88 in the DJ Basin of Colorado, 24 in the Austin Chalk
area of Texas, 16 in the Green River Basin of Wyoming and six in the
Piceance basin of western Colorado. Late in 1995, the Company sold
its minor interest in a south Texas field where 70 non-operated wells
had been completed earlier in the year. In the DJ Basin, the Company
completed 360 wells in 1994, but reduced its drilling in 1995 in
response to the dramatic decrease in natural gas prices in the
region. The Company expects to maintain a reduced development
schedule in 1996 which, together with the effects of property sales
during 1995, is likely to result in a decline in production during
1996. Total operating expenses for 1995 increased by 13%, in line
with the production growth. Operating costs per BOE were $3.99,
essentially even with those of the prior year.
Revenues from gas processing, transportation, and marketing,
less direct expenses, for 1995 were $8.9 million, compared to $13.1
million in 1994. The decrease resulted primarily from a reduction in
processing margins due to the sale of the Company's Wattenberg
processing facilities. The Company realized almost $80
million in sales proceeds on the facilities and recorded $8.7 million
in gains. In conjunction with the sales, the Company entered into
a gathering and processing agreement, which, at current gas prices,
is not expected to have a material effect on the wellhead net prices.
Gas transportation and gathering margins from facilities retained by
the Company climbed 47% during 1995 to $3.4 million, associated with
<PAGE> 25
<PAGE>
rising production and system expansions in southern Wyoming and
western Colorado. Gas marketing net revenues declined $797,000
between years, due primarily to the suspension of third party
marketing activities.
Gains on sales of properties were $12.3 million in 1995,
compared to $2.0 million in 1994. The $8.7 million gain from the DJ
Basin facility sales accounted for the bulk of the increase. The
remaining gains resulted from the ongoing program to dispose of
non-strategic assets.
Other income in 1995 was $7.0 million, which was reduced from
$15.3 million in 1994, as the prior year included $6.6 million in
gains on the sale of a partial interest in the Permtex venture
and the sale of equity securities by the Company's Australian
affiliate. The remaining decrease was primarily due to losses on
the sale of marketable securities in 1995. The Company realized
$13.1 million in proceeds from the securities sales, during the
year.
Exploration expenses for 1995 totalled $8.0 million, up $1.5
million from 1994. The increase resulted primarily from the
writeoff of $4.1 million of acreage costs.
General and administrative expenses, net of reimbursements, were
$17.7 million as compared to $12.9 million in 1994. The increase
consisted of $2.3 million associated with newer development projects,
$1.5 million in severance and restructuring costs primarily relating
to the Wattenberg area and $1.0 million relating to the expanding offshore
operations.
Interest and other expense was $27.0 million in 1995, up from
$12.5 million in 1994. The majority of the increase was due to
higher outstanding debt levels at higher average interest rates, and
to a lesser extent, the writedown of certain notes receivable to
their realizable value. Senior debt was significantly reduced during
the last half of the year with the proceeds from the sale of the
Wattenberg facilities and miscellaneous oil and gas properties.
Depletion, depreciation and amortization expense increased 8%
during 1995. The increase resulted from the 13% growth in oil and
gas production, offset somewhat by a reduction in the average
depletion, depreciation and amortization rate per BOE to $5.00 in
1995 from $5.37 in 1994. The average depletion rate is expected to
increase to approximately $5.70 per BOE in 1996 based on the recent
decrease in reserves.
The effective income tax rate for 1995 was a benefit of three
percent. This benefit was limited to the extent of the net deferred
tax liability at December 31, 1994 of $591,000 and the realization of
a $779,000 deferred tax asset that was previously recorded to
stockholders' equity as required by SFAS No. 115.
Comparison of 1994 results to 1993. Total revenues in 1994 rose
15% to $262.3 million, primarily as a result of a 26% growth in
oil and gas production and greater gas processing and transportation
throughput. The revenue rise was limited by a 12% decline in the
average price per BOE. Net income for 1994 was $12.4 million,
compared to $19.5 million in 1993. In addition to the price decline,
the decrease resulted from increased expenses for exploration,
interest and depletion. Net income per common share was $.07 in
1994, compared to $.45 in 1993, as higher preferred dividends
compounded the effect of declining earnings. With the conversion of
the 8% preferred stock at year end 1994, preferred dividends decreased
in 1995.
Revenues from production, less direct operating expenses, in
1994 increased 10% to $91.6 million, due to the rise in oil and gas
production. The average price received for oil decreased 4% in 1994
to $14.80 per barrel while gas prices dropped 14% to $1.67 per Mcf.
Total operating expenses increased 12% during 1994. However,
operating costs per BOE decreased to $3.97 from $4.45 in 1993,
primarily due to expense reductions in Wattenberg, where operating
costs averaged $2.80 per BOE. In 1994, the Company drilled and
completed 466 wells. Of the wells placed on production, 360 were
in the DJ Basin of eastern Colorado, 34 in the Green River Basin of
southern Wyoming, 23 in the Giddings Field of southeast Texas and 20
in the Piceance Basin of western Colorado. In the DJ Basin, an
additional 90 wells were recompleted to enhance production. The
<PAGE> 26
<PAGE>
Company completed $44.7 million in producing property acquisitions,
the majority of which were for incremental interests in wells in or
around current hubs.
Revenues from gas processing, transportation and marketing
activities less direct expenses increased 42% to $13.1 million
in 1994 from $9.2 million in 1993. The increase was primarily
attributable to a 45% ($3.7 million) rise in processing and
transportation margins as a result of the DJ Basin facilities
expansion and increased throughput in the Green River Basin as a
result of development drilling in the area. The gas marketing gross
margin increased 16% to $1.1 million in 1994. However, late in
1994 margins narrowed due to the decrease in price differentials
available with the precipitous decline in spot market gas prices.
The Company suspended third party marketing at year end 1994
until the markets recover.
Other income for 1994 was $15.3 million, up $4.8 million from
1993. The increase resulted from a $3.5 million gain from the sale
of a portion of the Permtex joint venture and a $3.1 million gain
from the sale of equity securities by the Company's Australian
affiliate. After these transactions, the Company's interests in
Command and Permtex were reduced to 29% and 21%, respectively.
General and administrative expenses, net of reimbursements, were
4.9% of revenues in 1994, compared to 4.5% of revenues in 1993.
Interest and other expense was $12.5 million in 1994 compared to $7.3
million in 1993. The increase was the result of a rise in outstanding
debt levels due to capital project expenditures, as well as
increasing interest rates.
Depletion, depreciation and amortization expense for 1994
increased 30% from the prior year. The increase was directly related
to the 26% rise in oil and gas production.
The Company adopted SFAS No. 109, "Accounting for
Income Taxes", effective January 1, 1992. In 1993, the income tax
provision was reduced from the statutory rate of 35% to zero due to
the elimination of deferred taxes upon realization of tax basis in
excess of financial basis. In 1994, the income tax provision was
reduced from the statutory rate by $3.8 million from the realization
of the remaining excess tax basis.
Development, Acquisition and Exploration
During 1995, the Company incurred $99.7 million in capital
expenditures, including $62.6 million for oil and gas development
(of which more than $21 million carryover costs for development
activities initiated in 1994 and recorded in the financial statements in
early 1995), $21.1 million for acquisitions, $5.5 million for gas facility
expansion, $8.2 million for exploration and $2.3 million for field
and office equipment.
Of the total development expenditures, $12.1 million was
concentrated in the DJ Basin of Colorado. A total of 88 wells were
placed on production there in 1995 with no dry holes drilled and one
well in progress at year end. As a result of continued declines in
gas prices in 1995, the Company significantly reduced its DJ Basin
drilling plans. The Company expended $13.0 million on development in
the Green River Basin of southern Wyoming, with 16 wells placed on
sales and four in progress at year end. In the horizontal drilling
program in the Giddings Field of southeast Texas, 24 wells were
placed on sales, with two in progress at year end. The Uinta Basin
development program in northeast Utah had 11 wells placed on sales
and three wells abandoned with none in progress at year end. In the
Piceance Basin of western Colorado, six wells were placed on sales,
with two in progress at year end. In the Sonora field of south
Texas, 70 non-operated wells (4.3 wells net) were placed on sales;
however, the Company's interest in the field was sold late in the year.
The Company expended $21.1 million for domestic acquisitions, of
which $13.7 million was for producing properties and $7.4 million was
for acreage purchases in or around the Company's operating hubs. Of
the producing property acquisitions, $11.0 million was for offshore
property interests in the Gulf of Mexico which were acquired through
the issuance of Company stock.
<PAGE> 27
<PAGE>
The Company's gas gathering and processing operations incurred
$5.5 million of capital expenditures in 1995. The work was
concentrated primarily in Wattenberg, the Piceance Basin,
the Washakie Basin and the Giddings Field. In June 1995, the
Company sold its recently constructed gas processing plant in the
west end of Wattenberg along with certain related assets for
a sales price of $18.5 million. A net gain of $715,000 was recognized
on the transaction. In September 1995, the Company sold substantially
all of its remaining Wattenberg gas facilities for $60.9 million,
recognizing a net gain of $8.0 million.
Exploration costs in 1995 were $8.2 million, primarily for
geological and other studies on the newly acquired domestic
undeveloped acreage and the writeoff of certain acreage costs. In
Russia, production in 1995 averaged 1,500 barrels per day, with a
peak rate of 2,500 barrels per day. Total production should exceed
1.0 million barrels in 1996, based on planned drilling activity. An
18 mile pipeline to connect the Logovskoye (southernmost) field to
the Perm refining center has been completed. An additional pipeline
of almost twice that length, which is required to connect the two
northern fields, should be constructed by 1998. In Tunisia, an
agreement was reached in 1995 to sell the project to Command for
stock producing a gain of $1.4 million. The Company will receive
additional proceeds if commercial reserves are assigned to the
initial well drilled by Command. In Mongolia, the Company's
interest was reduced to 42% as the venture sold a portion of its
equity in 1995 for a combination of cash and property rights with
a gain to the Company of $456,000. As part of the sale, one
partner committed to drill two test wells in Mongolia. One well was
drilled in 1995 but proved noncommercial. The second well was
spudded in the third quarter, but testing was suspended until Spring
1996 due to the winter.
Financial Condition and Capital Resources
At December 31, 1995, the Company had assets of $555.5 million.
Total capitalization was $469.4 million, of which 50% was represented
by stockholder's equity, 32% by senior debt and 18% by subordinated
debt. During 1995, net cash provided by operations was $68.7 million,
a decrease of 21% from 1994. As of December 31, 1995, commitments
for capital expenditures totalled $4.1 million. The Company anticipates
that 1996 expenditures for development drilling will approximate $55
million. The level of these and other future expenditures is largely
discretionary, and the amount of funds devoted to any particular
activity may increase or decrease significantly, depending on available
opportunities and market conditions. The Company plans to finance its
ongoing development, acquisition and exploration expenditures using
internally generated cash flow, asset sales proceeds and existing
credit facilities. In addition, joint ventures or future public and
private offerings of debt or equity securities may be utilized. Should
the proposed Patina transaction be consummated, the Company expects the
transaction to result in increased consolidated net cash provided by
operations, although cash generated by Patina will be retained by
Patina and will not be available to fund the Company's other operations
or to pay dividends to its stockholders.
The Company maintains a $500 million revolving credit facility.
The facility is divided into a $100 million short-term portion and a
$400 million long-term portion that expires on December 31, 1998.
Management's policy is to renew the facility on a regular basis.
Credit availability is adjusted semiannually to reflect changes in
reserves and asset values. The borrowing base available under the
facility at December 31, 1995 was $225 million. The majority of the
borrowings under the facility currently bear interest at LIBOR plus
.75% with the remainder at prime. The Company also has the option to
select CD plus .75%. The margin on LIBOR or CD loans increases to 1%
when the Company's consolidated senior debt becomes greater than 80%
of its tangible net worth. Financial covenants limit debt, require
maintenance of $1.0 million in minimum working capital as defined and
restrict certain payments, including stock repurchases, dividends and
contributions or advances to unrestricted subsidiaries. Such
restricted payments are limited by a formula that includes
underwriting proceeds, cash flow and other items. Based on such
limitations, more than $100 million was available for the payment of
dividends and other restricted payments as of December 31, 1995.
Should the proposed Patina transaction be consummated, the Company
anticipates various changes to the facility, the most significant
being the reduction of the borrowing base by approximately $100
million.
<PAGE> 28
<PAGE>
In 1994, the Company executed an agreement with Union Pacific
Resources Corporation ("UPRC") whereby the Company gained the right
to drill wells on UPRC's previously uncommitted acreage in the
Wattenberg area. UPRC retained a royalty and the right to
participate as a 50% working interest owner in each well, and
received warrants to purchase two million shares of Company stock.
On February 8, 1995, the exercise prices were reset to $21.60 per
share and their expiration extended one year. One million of the
warrants expire in February 1998 and the other million expire in
February 1999. In early 1995, the Company paid UPRC $400,000 for an
extension of the time period to drill the commitment wells and
released a portion of the outlying acreage committed to the venture.
During 1995, the Company drilled less than the required number of
wells on the UPRC acreage. UPRC has asserted that the Company's
right to earn additional acreage under the agreement terminated
on December 31, 1995 and that the Company is required to pay
approximately $4.1 million in penalties to UPRC. Arbitration
proceedings on the matter have been initiated. The Company
established a reserve for these penalties in 1995.
In 1992, the Company formed a partnership to monetize Section 29
tax credits to be realized from the Company's properties, mainly in
the DJ Basin. Contributions of $8.8 million were received through
1994. In early 1995, a second investor was added and the limited
partners committed to contribute an additional $5.0 million, of which
$2.0 million was received in January 1995 and $2.0 million in August
1995. As a result, this transaction is anticipated to increase cash
flow and net income through early 1996. A revenue increase of more
than $.40 per Mcf is realized on production generated from qualified
Section 29 properties in this arrangement. The Company recognized
$3.0 million and $2.5 million, respectively, of this revenue during
1994 and 1995.
The Company is currently negotiating an agreement to replace the
existing partnership to monetize Section 29 tax credits. The new
agreement will provide for the Company to receive proceeds for the
sale of an interest in certain oil and gas properties as well as
future Section 29 tax credits. The sale will enable the purchaser to
earn tax credits associated with future natural gas production from
the properties. The Company will retain a variable production
payment from the properties.
The Company maintains a program to divest marginal properties
and assets which do not fit its long range plans. During 1994, the
Company received $2.8 million in proceeds from sales of oil and gas
properties. In 1995, the Company received almost $80 million in
proceeds from the sale of its Wattenberg gas processing facilities
and $30 million from the sale of oil and gas properties. The
proceeds were applied to reduce the Company's outstanding senior
debt.
The Company believes that its capital resources are adequate to
meet the requirements of its business. However, future cash flows
are subject to a number of variables including the level of
production and oil and gas prices, and there can be no assurance that
operations and other capital resources will provide cash in
sufficient amounts to maintain planned levels of capital expenditures
or that increased capital expenditures will not be undertaken.
<PAGE> 29
Inflation and Changes in Prices
While certain of its costs are affected by the general level of
inflation, factors unique to the petroleum industry tend to determine
the Company's cost levels. 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 average oil and gas prices
received over the last five years and highlights the price
fluctuations by quarter for 1994 and 1995. Average gas prices prior
to 1994 exclude Mississippi gas production sold under a high price
contract. In 1993, the Company renegotiated the gas contract and
received a substantial payment. Average gas prices for 1995 were
increased by $.06 per Mcf through hedging. 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.
<TABLE>
<CAPTION>
Average Prices
-----------------------------------
Crude Oil Per
and Natural Equivalent
Liquids Gas Barrel
--------- --------- ----------
(Per Bbl) (Per Mcf)
<S> <C> <C> <C>
Annual
------
1991 $ 20.62 $ 1.68 $ 14.36
1992 18.87 1.74 13.76
1993 15.41 1.94 13.41
1994 14.80 1.67 11.82
1995 16.96 1.35 11.00
Quarterly
---------
1994
First $ 12.02 $ 1.98 $ 11.93
Second 15.55 1.65 12.20
Third 16.21 1.53 11.83
Fourth 15.30 1.56 11.39
1995
First $ 16.40 $ 1.31 $ 10.66
Second 17.52 1.29 10.95
Third 17.05 1.30 10.81
Fourth 16.84 1.55 11.69
</TABLE>
In December 1995, the Company received an average of $17.30 per
barrel and $1.62 per Mcf for its production.
<PAGE> 30
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTAL DATA
Reference is made to the Index to Financial Statements on page
32 for the Company's financial statements and notes thereto.
Quarterly financial data for the Company is presented on page 24 of
this Form 10-K. Supplementary schedules for the Company have been
omitted as not required or not applicable because the information
required to be presented is included in the financial statements and
related notes.
The following financial statements of Gerrity Oil & Gas
Corporation are hereby incorporated by reference from the Amendment
No. 1 to the Registration Statement on Form S-4 of Patina Oil
& Gas Corporation (Registration No. 333-572):
(i) Report of Independent Public Accountants
(ii) Report of Independent Accountants
(iii) Consolidated Balance Sheets as of December 31, 1994 and
1995
(iv) Consolidated Statements of Operations for the Years
Ended December 31, 1993, 1994 and 1995
(v) Consolidated Statements of Stockholders' Equity for the
Years Ended December 31, 1993, 1994 and 1995
(vi) Consolidated Statements of Cash Flows the Years Ended
December 31, 1993, 1994 and 1995.
(vii) Notes to Consolidated Financial Statements
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURES.
None.
<PAGE> 31
<PAGE>
INDEX TO FINANCIAL STATEMENTS
Page
----
Report of Independent Public Accountants. . . . . . . . . . . . . .33
Consolidated Balance Sheets as of December 31, 1994 and 1995. . . .34
Consolidated Statements of Operations for the years ended
December 31, 1993, 1994 and 1995 . . . . . . . . . . . . . . .35
Consolidated Statements of Changes in Stockholders' Equity
for the years ended December 31, 1993, 1994 and 1995 . . . . .36
Consolidated Statements of Cash Flows
for the years ended December 31, 1993, 1994 and 1995 . . . . .37
Notes to Consolidated Financial Statements. . . . . . . . . . . . .38
<PAGE> 32
<PAGE>
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Stockholders of Snyder Oil Corporation:
We have audited the accompanying consolidated balance sheets of
Snyder Oil Corporation (a Delaware corporation) and subsidiaries as
of December 31, 1994 and 1995, and the related consolidated
statements of operations, changes in stockholders' equity, and cash
flows for each of the three years in the period ended December 31,
1995. These financial statements are the responsibility of the
Company's management. Our responsibility is to express an opinion on
these financial statements based on our audits.
We conducted our audits in accordance with generally accepted
auditing standards. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the financial statements referred to above
present fairly, in all material respects, the financial position of
Snyder Oil Corporation and subsidiaries as of December 31, 1994 and
1995, and the results of their operations and their cash flows for
each of the three years in the period ended December 31, 1995, in
conformity with generally accepted accounting principles.
As explained in Note 2 to the financial statements, in 1995, the
Company adopted Statement of Financial Accounting Standards No. 121,
"Accounting for the Impairment of Long-Lived Assets and for Long-
Lived Assets to Be Disposed Of".
ARTHUR ANDERSEN LLP
Fort Worth, Texas,
February 20, 1996
<PAGE> 33<PAGE>
<TABLE>
SNYDER OIL CORPORATION
CONSOLIDATED BALANCE SHEETS (Notes 1 and 2)
(In thousands)
<CAPTION>
December 31,
-------------------------
1994 1995
---------- ------------
<S> <C> <C>
ASSETS
Current assets
Cash and equivalents $ 21,733 $ 27,263
Accounts receivable 37,055 29,259
Inventory and other 13,651 11,769
---------- ----------
72,439 68,291
---------- ----------
Investments (Note 4) 43,301 33,220
---------- ----------
Oil and gas properties, successful efforts method (Note 5) 680,215 675,961
Accumulated depletion, depreciation and amortization (207,976) (240,744)
---------- ----------
472,239 435,217
---------- ----------
Gas facilities and other (Note 5) 106,622 30,506
Accumulated depreciation (21,342) (11,741)
---------- ----------
85,280 18,765
---------- ----------
$ 673,259 $ 555,493
========== ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities
Accounts payable $ 44,874 $ 36,353
Accrued liabilities 25,112 26,096
Current portion of long-term debt (Note 3) 1,745 -
---------- ----------
71,731 62,449
---------- ----------
Senior debt, net (Note 3) 234,857 150,001
Convertible subordinated notes (Note 3) 83,650 84,058
Other noncurrent liabilities (Notes 7 and 9) 3,211 20,016
Minority interest 5,724 3,601
Commitments and contingencies (Note 10)
Stockholders' equity (Note 6)
Preferred stock, $.01 par, 10,000,000 shares authorized,
6% Convertible preferred stock, 1,035,000
shares issued and outstanding 10 10
Common stock, $.01 par, 75,000,000 shares authorized,
30,209,197 and 31,430,227 issued 302 314
Capital in excess of par value 255,961 265,911
Retained earnings (deficit) 20,959 (29,001)
Common stock held in treasury, 122,018 shares and
134,191 shares at cost (2,288) (2,457)
Foreign currency translation adjustment 1,222 380
Unrealized gain (loss) on investments (Note 4) (2,080) 211
---------- ----------
274,086 235,368
---------- ----------
$ 673,259 $ 555,493
========== ==========
<f/n> The accompanying notes are an integral part of these statements.
</TABLE>
<PAGE> 34
<PAGE>
<TABLE>
SNYDER OIL CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS (Notes 1 and 2)
(In thousands except per share data)
<CAPTION>
Year Ended December 31,
----------------------------------
1993 1994 1995
--------- --------- ----------
<S> <C> <C> <C>
Revenues (Note 8)
Oil and gas sales $124,641 $137,858 $144,608
Gas processing, transportation and marketing 94,839 107,247 38,256
Gain (loss) on sales of properties (Note 5) (1,033) 1,969 12,254
Other 10,405 15,254 7,042
--------- --------- ---------
228,852 262,328 202,160
Expenses
Direct operating 41,401 46,267 52,486
Cost of gas and transportation 85,640 94,177 29,374
Exploration 2,960 6,505 8,033
General and administrative 10,280 12,853 17,680
Interest and other 7,271 12,463 27,001
Litigation settlement (Note 10) - - 4,400
Depletion, depreciation and amortization 54,393 70,770 76,378
Property impairments 4,369 5,783 27,412
--------- --------- ---------
Income (loss) before taxes, minority interest
and extraordinary item 22,538 13,510 (40,604)
--------- --------- ----------
Provision (benefit) for income taxes (Note 7)
Current - - 25
Deferred - 967 (1,370)
--------- --------- ----------
- 967 (1,345)
--------- --------- -----------
Minority interest - (171) (572)
--------- --------- ----------
Income (loss) before extraordinary item 22,538 12,372 (39,831)
Extraordinary item - early extinguishment
of debt (Note 3) (2,993) - -
--------- --------- ----------
Net income (loss) $ 19,545 $ 12,372 $ (39,831)
========= ========= ==========
Net income (loss) per common share (Note 6)
Before extraordinary item $ .58 $ .07 $ (1.53)
Extraordinary item (.13) - -
--------- --------- ----------
Total $ .45 $ .07 $ (1.53)
========= ========= ==========
Weighted average shares outstanding (Note 6) 23,096 23,704 30,186
========= ========= =========
<f/n> The accompanying notes are an integral part of these statements.
</TABLE>
<PAGE> 35
<PAGE>
<TABLE>
SNYDER OIL CORPORATION
CONSOLIDATED STATEMENTS OF CHANGES IN
STOCKHOLDERS' EQUITY (Notes 1, 2 and 6)
(In thousands)
<CAPTION>
Preferred Stock Common Stock Capital in
---------------- --------------- Excess of Retained
Shares Amount Shares Amount Par Value Earnings
------- ------ ------- ------ ----------- ----------
<S> <C> <C> <C> <C> <C> <C>
Balance, December 31, 1992 1,200 $ 12 22,874 $ 229 $ 148,670 $ 19,955
Issuance of preferred 1,035 10 - - 99,315 -
Common stock grants and
exercise of options - - 309 3 1,729 -
Conversion of preferred
to common (14) - 77 1 (1) -
Dividends - - - - - (14,192)
Net income - - - - - 19,545
--------- -------- -------- ------ --------- ------------
Balance, December 31, 1993 2,221 22 23,260 233 249,713 25,308
Common stock grants and
exercise of options - - 414 4 2,851 -
Conversion of preferred
to common (1,186) (12) 6,535 65 (53) -
Issuance of warrants - - - - 3,450 -
Dividends - - - - - (16,721)
Net income - - - - - 12,372
------- ------- ------- ------- ---------- ------------
Balance, December 31, 1994 1,035 10 30,209 302 255,961 20,959
Common stock grants and
exercise of options - - 138 1 856 -
Issuance of common - - 1,083 11 13,021 -
Dividends - - - - (3,927) (10,129)
Net loss - - - - - (39,831)
------- ------- -------- ------ --------- ------------
Balance, December 31, 1995 1,035 $ 10 31,430 $ 314 $ 265,911 $ (29,001)
======= ======= ======== ====== ========= ============
<f/n> The accompanying notes are an integral part of these statements.
</TABLE>
<PAGE> 36
<PAGE>
<TABLE>
SNYDER OIL CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS (Notes 1 and 2)
(In thousands)
<CAPTION>
Year Ended December 31,
--------------------------------
1993 1994 1995
--------- --------- ---------
<S> <C> <C> <C>
Operating activities
Net income (loss) $ 19,545 $ 12,372 $ (39,831)
Adjustments to reconcile net income (loss) to net
cash provided by operations
(Gain) loss on sales of properties 1,033 (1,969) (12,254)
Exploration expense 2,960 6,505 8,033
Depletion, depreciation and amortization 54,393 70,770 76,378
Property impairments 4,369 5,783 27,412
Deferred taxes - 967 (1,370)
Extraordinary item - early extinguishment of debt 2,993 - -
Gain on sales of investments (2,283) (9,747) (809)
Equity in (earnings) losses of
unconsolidated subsidiaries (189) (1,355) 1,319
Amortization of deferred credits (3,846) (2,986) (2,511)
Changes in operating assets and liabilities
Decrease (increase) in
Accounts receivable (22,397) 11,024 7,142
Inventory and other (3,354) (9,241) 3,617
Increase (decrease) in
Accounts payable 12,753 1,901 (8,521)
Accrued liabilities 2,227 1,841 5,165
Other liabilities 319 361 4,779
Other 205 235 171
--------- --------- ---------
Net cash provided by operations 68,728 86,461 68,720
--------- --------- ---------
Investing activities
Acquisition, development and exploration (194,264) (237,708) (91,781)
Purchase of controlling interest in subsidiary - (6,645) -
Proceeds from investments 8,378 5,019 14,786
Outlays for investments (27,594) (8,804) -
Proceeds from sales of properties 5,547 2,806 109,988
--------- --------- ---------
Net cash realized (used) by investing (207,933) (245,332) 32,993
--------- --------- ---------
Financing activities
Issuance of common 1,528 922 517
Issuance of preferred 99,325 - -
Increase (decrease) in indebtedness 43,159 187,138 (86,193)
Debt issuance costs - (2,855) -
Premium on debt extinguishment (2,983) - -
Dividends (14,192) (16,721) (14,056)
Deferred credits 2,796 2,356 3,549
Repurchase of common - (1,149) -
--------- --------- ---------
Net cash realized (used) by financing 129,633 169,691 (96,183)
--------- --------- ---------
Increase (decrease) in cash (9,572) 10,820 5,530
Cash and equivalents, beginning of year 20,485 10,913 21,733
--------- --------- ---------
Cash and equivalents, end of year $ 10,913 $ 21,733 $ 27,263
========= ========= =========
Noncash investing and financing activities
Gas plant capital lease - $ 21,000 -
Acquisition of properties and stock - - $ 13,032
<f/n> The accompanying notes are an integral part of these statements.
</TABLE>
<PAGE> 37
SNYDER OIL CORPORATION
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) ORGANIZATION AND NATURE OF BUSINESS
Snyder Oil Corporation (the "Company") is primarily engaged in the
acquisition, exploration, development and production of oil and gas
properties principally in the Rocky Mountain and Gulf Coast regions
of the United States. To a lesser extent, the Company also gathers,
transports and markets natural gas generally in proximity to its
principal producing properties. The Company is engaged to a modest
but growing extent in international acquisition, exploration and
development. The Company, a Delaware corporation, is the successor
to a company formed in 1978.
Historically, the market for oil and gas has had significant price
fluctuations. Prices for Rocky Mountain gas production, where the
Company currently produces approximately three-fourths of its natural
gas, have traditionally been more volatile than prices in other
markets and have been depressed since late 1994. In large part, the
decreased prices are the result of increased production in the region
and limited transportation capacity to other regions of the country.
As a result, prices are particularly sensitive to local demand, which
has been depressed primarily due to unusually mild weather in the
region in late 1994 and early 1995. Future increases or decreases in
prices received could have a significant impact on the Company's
future results of operations.
(2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Risks and Uncertainties
The preparation of financial statements in conformity with
generally accepted accounting principles requires management to make
estimates and assumptions that affect the reported amounts of assets
and liabilities and disclosure of contingent assets and liabilities
at the date of the financial statements and the reported amounts of
revenues and expenses during the reporting period. Actual results
could differ from those estimates.
Principles of Consolidation
The consolidated financial statements include the accounts of
Snyder Oil Corporation and its subsidiaries (collectively, the
Company). Affiliates in which the Company owns more than 50% are
fully consolidated, with the related minority interest being deducted
from subsidiary earnings and stockholders' equity. Affiliates in
which the Company owns 50% or less are accounted for under the equity
method.
Cash and Equivalents
All liquid investments with a maturity of three months or less
are considered to be cash equivalents.
Oil and Gas Producing Activities
The Company utilizes the successful efforts method of accounting
for its oil and gas properties. Under successful efforts, oil and
gas leasehold costs are capitalized when incurred. Unproved
properties are assessed periodically on a prospect-by-prospect basis
and impairments in value are charged to expense. Exploratory
expenses, including geological and geophysical expenses and delay
rentals, are charged to expense as incurred. Exploratory drilling
costs, including stratigraphic test wells, are initially capitalized,
but charged to expense if and when the well is determined to be
unsuccessful. Costs of productive wells, developmental dry holes and
productive leases are capitalized and amortized on a unit-of-
production basis over the life of the remaining proved or proved
developed reserves, as applicable. Gas is converted to equivalent
barrels at the rate of 6 Mcf to 1 barrel. Amortization of
capitalized costs is generally provided on a property-by-property
basis. Estimated future dismantlement, restoration and abandonment
costs, net of estimated salvage values, are accrued over the
properties' operating lives. Such costs are calculated at unit-of-
production rates based upon estimated proved recoverable reserves and
<PAGE> 38
<PAGE>
are taken into account in determining depletion, depreciation and
amortization.
Prior to the fourth quarter of 1995, the Company provided
impairments for significant proved and unproved oil and gas property
groups to the extent that net capitalized costs exceeded aggregate
undiscounted future cash flows. During 1993 and 1994, the Company
provided impairments of $4.4 million and $5.8 million, respectively.
During the fourth quarter of 1995, the Company adopted Statement of
Financial Accounting Standards No. 121 ("SFAS 121"), "Accounting for
the Impairment of Long-Lived Assets and for Long-Lived Assets to Be
Disposed Of". SFAS 121 requires the Company to assess the need for
an impairment of capitalized costs of oil and gas properties on a
property-by-property basis. If an impairment is indicated based on
undiscounted expected future cash flows, then a loss is recognized
sufficient to bring net capitalized costs down to discounted
expected future cash flows. During 1995, the Company provided
impairments of $27.4 million. The impairments were primarily the
result of less than anticipated development drilling results and
decreased Rocky Mountain gas prices that resulted in lower than
anticipated reserves in certain fields.
Foreign Currency Translation Adjustment
The Company's investment in its Australian affiliate is
accounted for using the equity method, whereby the cash basis
investment is increased for equity in earnings and decreased for
dividends, if any were received. The affiliate's functional currency
is the Australian dollar. The foreign currency translation
adjustments reported in the balance sheet are the result of the
translation of the Australian dollar balance sheet into United States
dollars at the balance sheet dates and changes in the exchange rate
subsequent to purchase.
Gas Imbalances
The Company uses the sales method to account for gas imbalances.
Under this method, revenue is recognized based on the cash received
rather than the Company's proportionate share of gas produced. The
gas imbalances at December 31, 1994 and 1995 were not significant.
Financial Instruments
The following table sets forth the carrying value and estimated
fair values of the Company's financial instruments:
<TABLE>
<CAPTION>
December 31,
--------------------------------------------------
1994 1995
------------------------ -----------------------
(In thousands)
Carrying Fair Carrying Fair
Amount Value Amount Value
----------- ---------- ---------- ----------
<S> <C> <C> <C> <C>
Cash and equivalents $ 21,733 $ 21,733 $ 27,263 $ 27,263
Investments 43,301 48,151 33,220 52,203
Senior debt (236,602) (236,602) (150,001) (150,001)
Convertible subordinated notes (83,650) (75,900) (84,058) (79,997)
Commodities contracts - 4,925 - 11,623
Interest rate swap - - - 107
</TABLE>
The carrying amount of cash and equivalents approximates fair
value because of the short maturity of those instruments. See Note
(4) for a discussion of the Company's investments. The fair value of
senior debt is presented at the current floating rate. The fair
value of the convertible subordinated notes was estimated based on
their December 30, 1994 and December 29, 1995 closing prices on the
New York Stock Exchange.
To a limited extent, the Company enters into commodities
contracts to hedge the price risk of a portion of its production.
Gains and losses on commodities contracts are deferred and recognized
in income as an adjustment to oil and gas sales revenue when the related
<PAGE> 39
<PAGE>
transaction being hedged is finalized (generally on a monthly basis).
In 1994, the Company entered into a gas swap arrangement in order to
lock in the price differential between the Rocky Mountain and the
NYMEX Henry Hub prices on a limited portion of its gas production to
reduce exposure to the Rocky Mountain spot prices. The Company
believed that the Rocky Mountain spot prices might be exposed to the
potential for a widening price differential when compared to Henry
Hub prices due to increasing supplies and limited pipeline capacity
out of the Rocky Mountain region. At December 31, 1995, the long-
term contract in effect covered 20,000 MMBtu per day through 2004.
In December 1995, that volume represented approximately 20% of the
Company's current Rocky Mountain gas production. The fair value of
the contract was estimated as the net present value at 10% of the
quoted market price of a similar instrument of the same duration.
In September 1995, the Company entered into an interest rate
swap agreement for a principal amount of $50 million to reduce the
impact of changes in interest rates on its revolving credit facility.
The agreement requires that the Company pay the counterparty interest
at a fixed rate of 5.585%, and requires the counterparty to pay the
Company interest at LIBOR. Accounts receivable or payable under this
agreement are recorded as adjustments to interest expense and are
generally settled on a monthly basis. The agreement matures on
September 26, 1997, with the counterparty having the option to extend
it for another two years. At December 31, 1995, the fair value of
the agreement was estimated as the net present value discounted at
10% of cash flows based on the interest rate differential.
Other
Certain amounts in prior years consolidated financial statements
have been reclassified to conform with current classification.
(3) INDEBTEDNESS
The following indebtedness was outstanding on the respective
dates:
<TABLE>
<CAPTION>
December 31,
---------------------------
1994 1995
---------- ----------
(In thousands)
<S> <C> <C>
Revolving credit facility $ 216,001 $ 150,001
Capital lease 20,551 -
Other 50 -
--------- ---------
236,602 150,001
Less current portion (1,745) -
--------- ---------
Senior debt, net $ 234,857 $ 150,001
========= =========
Convertible subordinated notes, net $ 83,650 $ 84,058
========= =========
</TABLE>
The Company maintains a $500 million revolving credit facility.
The facility is divided into a $400 million long-term portion and a
$100 million short-term portion. The borrowing base available under
the facility at December 31, 1995 was $225 million. The majority of
the borrowings under the facility currently bear interest at LIBOR
plus .75% with the remainder at prime, with an option to select CD
plus .75%. The margin on LIBOR or CD increases to 1% when the
Company's consolidated senior debt becomes greater than 80% of its
tangible net worth. During 1995, the average interest rate under the
revolver was 7.1%. The Company pays certain fees based on the unused
portion of the borrowing base. Among other requirements, covenants
require maintenance of $1.0 million in minimum working capital as
defined, limit the incurrence of debt and restrict dividends, stock
repurchases, certain investments, other indebtedness and unrelated
business activities. Such restricted payments are limited by a
formula that includes underwriting proceeds, cash flow and other
items. Based on such limitations, more than $100 million was
available for the payment of dividends and other restricted payments
as of December 31, 1995.
<PAGE> 40
<PAGE>
In May 1994, the Company issued $86.3 million of 7% convertible
subordinated notes due May 15, 2001. The net proceeds were $83.4
million. The notes are convertible into common stock at $23.16 per
share, and are redeemable at the option of the Company on or after
May 15, 1997, initially at 103.51% of principal, and at prices
declining to 100% at May 15, 2000, plus accrued interest.
In November 1994, the Company entered into an agreement with a
bank whereby the bank purchased the recently constructed West
Wattenberg Gas Plant from the Company for $21 million and leased it
back. The lease had a term of seven years and included an option to
repurchase the plant at the end of the lease. As a capital lease,
the asset and related debt were recorded on the balance sheet of the
Company. In June 1995, the Company sold the plant and certain
related assets and relinquished plant operations to the purchaser.
In conjunction with the sale, the lease remained in effect until
November 1995, when it was fully repaid with additional borrowings
under the revolving credit facility. As a result of the sale, the
Company recorded a gain of $715,000, net of accrued penalties
associated with the early lease termination.
In 1993, the Company retired $25 million of subordinated notes
and the related cumulative participating rights. The portion of the
payment in excess of principal and accrued interest was expensed as
an extraordinary item for $3.0 million.
Scheduled maturities of indebtedness for the next five years are
zero in 1996 and 1997, $150.0 million in 1998 and zero in 1999 and
2000. The long-term portion of the revolving credit facility is
scheduled to expire in 1998; however, it is management's policy to
renew both the short-term and long-term facility and extend the
maturities on a regular basis.
Cash payments for interest were $9.2 million, $9.9 million and
$22.1 million, respectively, for 1993, 1994 and 1995.
(4) INVESTMENTS
The Company has investments in foreign and domestic energy
companies and long-term notes receivable. The following table sets
forth the carrying cost of the Company's investments:
<TABLE>
<CAPTION>
December 31,
-------------------------
1994 1995
-------- --------
(In thousands)
<S> <C> <C>
Equity method investments $ 28,211 $ 30,901
Marketable securities 12,208 652
Long-term notes receivable 2,882 1,667
-------- --------
$ 43,301 $ 33,220
======== ========
</TABLE>
The corresponding fair market values of these investments were
$48.2 million and $52.2 million at December 31, 1994 and 1995,
respectively. In 1994, the Company adopted SFAS 115, "Accounting for
Certain Investments in Debt and Equity Securities." SFAS 115
requires that investments in marketable securities accounted for on
the cost method and long-term notes receivable must be adjusted to
their market value with a corresponding increase or decrease to
stockholders' equity. The pronouncement does not apply to
investments accounted for by the equity method.
The Company has an investment in Command Petroleum Limited
("Command"), an Australian exploration and production company,
accounted for by the equity method. The Sydney based company is
listed on the Australian Stock Exchange, and holds interests in
various international exploration and production permits and
licenses. In 1995, the Company acquired an additional 4.7 million
shares of Command common stock in exchange for the Company's interest
in the Fejaj Permit area in Tunisia. The Company will receive an
additional 4.7 million shares if a commercial discovery is made as
the result of the initial 4,000 meter drilling commitment. As a
<PAGE> 41
<PAGE>
result of this transaction, the Company's ownership in Command was
increased to 30.0% and a $1.4 million gain was recognized. The
market value of the Company's investment in Command based on
Command's closing price at December 31, 1995 was $29.5 million,
compared to a carrying cost of $24.5 million.
In early 1993, the Company formed the Permtex joint venture to
develop proven oil fields in the Volga-Urals Basin of Russia. To
finance its portion of planned development expenditures, the Company
sold a portion of its investment in the project to three industry
participants in 1994. As a result, its equity basis investment was
reduced from 50% to 20.6% and a $3.5 million net gain was recorded.
In 1995, the three industry participants paid the final installments
of their contributions to the venture and as a result, the Company
recognized an additional gain of $1.1 million. The Russian
investment had a carrying cost and stated fair value at December 31,
1995 of $4.6 million. In March 1996, the Company closed a private
foreign market placement which established a market value of
approximately $11 million.
In late 1994, the Company formed a consortium to explore the
Tamtsag Basin of eastern Mongolia. In late 1994 and early 1995, the
venture sold a portion of its equity to three industry participants,
one of which committed to fund the drilling of two wells, the second
purchased its interest for cash and a third participant assigned its
exploration rights in the basin to the venture. Accordingly, the
Company's equity basis investment was reduced from 100% to 42% and
had a carrying cost at December 31, 1995 of $1.8 million. The fair
value of the Company's investment, based on a recent equity sale by
one of the industry participants to another entity, was approximately
$15.8 million at December 31, 1995. The first well was drilled in
the second quarter 1995 and found to be noncommercial. The second
well was spudded in the third quarter and encountered hydrocarbons,
but testing was suspended until Spring 1996 when the proper equipment
can be mobilized.
The Company has investments in equity securities of publicly
traded domestic energy companies accounted for on the cost method,
with a total cost at December 31, 1994 and 1995 of $15.4 million and
$328,000 respectively. The market value of these securities at
December 31, 1994 and 1995 approximated $12.2 million and $652,000
respectively. In 1995, the Company sold the majority of these
securities for $13.1 million and recorded a corresponding net loss of
$2.0 million. In accordance with SFAS 115 at December 31, 1995,
investments were increased by $324,000 of gross unrealized holding
gains, stockholders' equity was increased by $211,000 and deferred
taxes payable were increased by $113,000.
The Company holds long-term notes receivable due from privately
held corporations with a carrying cost of $2.9 million and $1.7
million at December 31, 1994 and 1995. All notes are secured by
certain assets, including stock and oil and gas properties. The
notes include various contractual maturities that in some cases allow
for payment deferral if certain conditions are not met by the
Company. The Company believes based on existing market conditions,
the balances will mature in one to five years. At December 31, 1994
and 1995, the fair value of the notes receivable, based on existing
market conditions and the anticipated future net cash flow related to
the notes, approximated their carrying cost.
<PAGE> 42
<PAGE>
(5) OIL AND GAS PROPERTIES AND GAS FACILITIES
The cost of oil and gas properties at December 31, 1994 and 1995
includes $23.7 million and $24.2 million, respectively, of
unevaluated leasehold. Such properties are held for exploration,
development or resale and are excluded from amortization. The
following table sets forth costs incurred related to oil and gas
properties and gas processing and transportation facilities:
<TABLE>
<CAPTION>
1993 1994 1995
--------- --------- ---------
(In thousands)
<S> <C> <C> <C>
Proved acquisitions $ 43,999 $ 44,684 $ 13,675
Unproved acquisitions 4,163 25,571 7,388
Development 90,617 156,912 62,578
Gas processing, transportation and other 22,595 46,607 7,886
Exploration 5,787 5,514 8,214
--------- --------- ---------
$ 167,161 $ 279,288 $ 99,741
========= ========= =========
</TABLE>
Of the total 1995 development expenditures, $12.1 million was
concentrated in the DJ Basin of Colorado. A total of 88 wells were
placed on production in the DJ Basin in 1995 with no dry holes
drilled and one well in progress at year end. The Company completed
360 wells in the DJ Basin in 1994, but reduced its drilling in 1995
as a result of the significant decline in natural gas prices. The
Company expended $13.0 million on development in the Green River
Basin of southern Wyoming, with 16 wells placed on sales and four in
progress at year end. In the horizontal drilling program in the
Giddings Field of southeast Texas, 24 wells were placed on sales,
with two in progress at year end. The Uinta Basin development
program in northeast Utah had 11 wells placed on sales and three
wells abandoned with none in progress at year end. In the Piceance
Basin of western Colorado, six wells were placed on sales, with two
in progress at year end. In the Sonora field of south Texas, 70 non-
operated wells (4.3 wells net) were placed on sales, however, the
Company's interest in the field was sold late in the year.
The Company expended $21.1 million for domestic acquisitions, of
which $13.7 million was for producing properties and $7.4 million was
for acreage purchases in or around the Company's operating hubs. Of
the producing property acquisitions, $11.0 million was for offshore
property interests in the Gulf of Mexico which were acquired through
the issuance of Company stock. In 1995, the Company sold over 2,000
wells through its divestiture program for proceeds of $30.0 million,
with a net gain of $3.5 million.
The Company's gas gathering and processing operations
incurred $5.5 million of capital expenditures in 1995. The work was
concentrated primarily in Wattenberg, the Piceance Basin, the
Washakie Basin and the Giddings Field. In June 1995, the Company
sold its recently constructed gas processing plant on the west end
of Wattenberg along with certain related assets for a sales price
of $18.5 million. A net gain of $715,000 was recognized on the
transaction. In September 1995, the Company sold substantially all
of its remaining Wattenberg gas facilities for $60.9 million
recognizing a net gain of $8.0 million.
Exploration costs for 1995 were $8.2 million, primarily for
geological and other studies on the newly acquired domestic
undeveloped acreage and the writeoff of certain acreage costs. In
Russia, production in 1995 averaged 1,500 barrels per day, with a
peak rate of 2,500 barrels per day. An 18 mile pipeline to connect
the Logovskoye (southernmost) field to the Perm refining center has
been completed. An additional pipeline of almost twice that length,
which is required to connect the two northern fields, should be
constructed by 1998. In Tunisia, an agreement was reached in 1995
to sell the project to Command for stock with a gain of $1.4
million. The Company will receive additional proceeds if commercial
reserves are assigned to the initial well drilled by Command. In Mongolia,
the Company's interest was reduced to 42% as the venture sold a portion
of its equity in 1995 for a combination of cash and property rights
with a gain to the Company of $456,000. As part of the sale, one
partner committed to drill two test wells in Mongolia. One well was
drilled in 1995 but proved noncommercial. The second well was spudded
in the third quarter, but testing was suspended until Spring 1996
due to the winter.
<PAGE> 43
<PAGE>
In January 1996, the Company entered into an agreement whereby
the Wattenberg operations of the Company will be consolidated (the
"Merger") with Gerrity Oil & Gas Corporation ("Gerrity"). As a
result, the Company will own 70% of the common stock and the former
Gerrity shareholders will own 30% of the common stock of a new public
company which will be known as Patina Oil & Gas Corporation
("Patina"). If consummated, the Merger will be accounted for by
Patina as a purchase of Gerrity and Patina will then be consolidated
into the Company's financial statements. The consummation of the
Merger is subject to certain conditions including approval by
Gerrity's shareholders. There can be no assurance that the Merger
will be consummated.
The following table summarizes the unaudited pro forma effects
on the Company's financial statements assuming significant
acquisitions and divestitures consummated during 1995 (including the
Merger which is not expected to be completed until the second quarter
of 1996) had been consummated on December 31, 1995 (for balance sheet
and reserve data) and January 1, 1995 (for statement of operatons and
production data). Future results may differ substantially from
pro forma results due to changes in oil and gas prices, production
declines and other factors. Therefore, pro forma statements cannot
be considered indicative of future operations.
<TABLE>
<CAPTION>
As of or for the
Year Ended December 31, 1995
-------------------------------------
Historical Pro Forma
---------------- ----------------
(In thousands, except per share data) (unaudited)
<S> <C> <C>
Total assets $555,493 $786,445
Oil and gas sales $144,608 $196,044
Gas processing, transportation and marketing $ 38,256 $ 15,170
Total revenues $202,160 $224,127
Production direct operating margin $ 92,122 $135,943
Net loss $(39,831) $(37,140)
Net loss per common share $ (1.53) $ (1.39)
Weighted average shares outstanding 30,186 31,269
Production volume (MBOE) 13,149 17,787
Total proved reserves (MBOE) 90,200 141,857
Pretax PV10 value $372,811 $606,019
</TABLE>
(6) STOCKHOLDERS' EQUITY
A total of 75 million common shares, $.01 par value, are
authorized of which 31.4 million were issued at December 31, 1995.
In 1994, the Company issued 6,949,000 shares, with 6,535,000 shares
issued on conversion of 1.2 million preferred shares and 414,000
shares issued primarily for the exercise of stock options by
employees (for which 122,000 shares were received as consideration in
lieu of cash and are held in treasury). In addition, the Company
executed an agreement whereby the Company granted warrants to
purchase two million shares of Company stock in exchange for the
right to drill wells on certain acreage in the Wattenberg area. The
exercise price of the warrants is $21.60 per share with one million
expiring in February 1998 and the remaining one million in February 1999.
For financial reporting purposes, the warrants were valued at $3.5
million, which was recorded as an increase to oil and gas properties
and capital in excess of par value. In 1995, the Company issued 1.2
million shares, with 1.1 million shares issued in exchange for
acquired property interests and 138,000 shares issued primarily for
the exercise of stock options by employees (for which 12,000 shares
were received as consideration in lieu of cash and are held in
treasury). In 1994, the Company paid first and second quarter
dividends at the rate of $.06 per share and increased the rate to
$.065 per share in the third and fourth quarters. Quarterly
dividends of $.065 per share were paid in 1995. For book purposes,
subsequent to June, the common stock dividends were in excess of
retained earnings and as such have been and will continue to be
treated as distributions of capital.
<PAGE> 44
<PAGE>
A total of 10 million preferred shares, $.01 par value, are
authorized. In 1991, 1.2 million shares of 8% convertible
exchangeable preferred stock were sold through an underwriting. The
net proceeds were $57.4 million. In 1993, 14,000 of the preferred
shares were converted into 77,000 common shares. Effective December
31, 1994, the remaining 8% convertible preferred shares were
converted into 6,535,000 common shares. In 1993, 4.1 million
depositary shares (each representing a one quarter interest in one
share of $100 liquidation value stock) of 6% preferred stock were
sold through an underwriting. The net proceeds were $99.3 million.
The stock is convertible into common stock at $21.00 per share and is
exchangeable at the option of the Company for 6% convertible
subordinated debentures on any dividend payment date. The 6%
convertible preferred stock is redeemable at the option of the
Company on or after March 31, 1996. The liquidation preference is
$25.00 per depositary share, plus accrued and unpaid dividends. The
Company paid $10.8 million ($4.00 per 8% convertible preferred share
and $1.50 per 6% convertible depositary share) and $6.2 million
($1.50 per 6% convertible depositary share), respectively, in
preferred dividends during 1994 and 1995.
The Company maintains a stock option plan for employees
providing for the issuance of options at prices not less than fair
market value. Options to acquire up to three million shares of
common stock may be outstanding at any given time. The specific
terms of grant and exercise are determinable by a committee of
independent members of the Board of Directors. The majority of
currently outstanding options vest over a three-year period (30%,
60%, 100%) and expire five to seven years from date of grant.
In 1990, the shareholders adopted a stock grant and option plan
(the "Directors' Plan") for non-employee Directors of the Company.
The Directors' Plan provides for each non-employee director to
receive 500 common shares quarterly in payment of their annual
retainer. It also provides for 2,500 options to be granted annually
to each non-employee Director. The options vest over a three-year
period (30%, 60%, 100%) and expire five years from date of grant.
The following is a summary of stock option transactions during
1994 and 1995 (shares in thousands):
<TABLE>
<CAPTION>
1994 1995
--------------------------- ---------------------------
Price Range Price Range
Shares per Share Shares per Share
------- ----------------- ------- -----------------
<S> <C> <C> <C> <C>
Beginning balance 1,383 $ 4.53 - $ 19.25 1,484 $ 4.53 - $ 20.38
Granted 510 $ 18.13 - $ 20.38 610 $ 12.00 - $ 14.13
Exercised (407) $ 4.53 - $ 13.00 (124) $ 4.53 - $ 13.00
Forfeited (2) $ 13.00 - $ 18.13 (259) $ 13.00 - $ 20.38
------ ----------------- ------ -----------------
Ending balance 1,484 $ 4.53 - $ 20.38 1,711 $ 6.00 - $ 20.13
====== ================= ====== =================
Vested 533 $ 4.53 - $ 19.25 743 $ 6.00 - $ 20.13
====== ================= ====== =================
</TABLE>
Earnings per share are computed by dividing net income, less
dividends on preferred stock, by average common shares outstanding.
Net income (loss) available to common for the three years ended
December 31, 1995, was $10.4 million, $1.6 million and ($46.0)
million, respectively. Differences between primary and fully diluted
earnings per share were insignificant for all periods presented.
<PAGE> 45
<PAGE>
(7) FEDERAL INCOME TAXES
At December 31, 1995, the Company had no liability for foreign
taxes. A reconciliation of the United States federal statutory rate
to the Company's effective income tax rate as they apply to the
provision for 1993 and 1994 and the benefit for 1995 follows:
<TABLE>
<CAPTION>
1993 1994 1995
------ ------ ------
<S> <C> <C> <C>
Federal statutory rate 35% 35% (35%)
Utilization of net deferred tax asset (35%) (27%) -
Loss in excess of net deferred tax liability - - 32%
Prior year tax reimbursement - (1%) -
------ ------ ------
Effective income tax rate - 7% (3%)
====== ====== ======
</TABLE>
For book purposes, the components of the net deferred asset and
liability at December 31, 1994 and 1995, respectively, were:
<TABLE>
<CAPTION>
1994 1995
------------ ------------
(In thousands)
<S> <C> <C>
Deferred tax assets
NOL carryforwards $ 56,902 $ 53,010
AMT credit carryforwards 1,350 1,293
Reserves and other 907 1,977
---------- -----------
59,159 56,280
---------- -----------
Deferred tax liabilities
Depreciable and depletable property (55,601) (24,018)
Investments and other (2,308) (2,488)
---------- -----------
(57,909) (26,506)
---------- -----------
Deferred asset 1,250 29,774
Valuation allowance (1,841) (29,774)
---------- -----------
Net deferred tax asset (liability) $ (591) $ -
========== ===========
</TABLE>
For tax purposes, the Company had regular net operating loss
carryforwards of $151.5 million and alternative minimum tax loss
carryforwards of $9.6 million at December 31, 1995. These
carryforwards expire between 1997 and 2010. At December 31, 1995,
the Company had alternative minimum tax credit carryforwards of $1.3
million which are available indefinitely. Current income taxes shown
in the financial statements reflect estimates of alternative minimum
taxes. Cash payments during 1993 and 1994 were $75,000 and $10,000
with a net cash refund of $117,000 received in 1995.
(8) MAJOR CUSTOMERS
In 1993, 1994 and 1995, Amoco Production Company accounted for
approximately 12%, 11% and 10%, respectively, of revenues.
Management believes that the loss of any individual purchaser would
not have a material adverse impact on the financial position or
results of operations of the Company.
<PAGE> 46
<PAGE>
(9) DEFERRED CREDITS
In 1992, the Company formed a partnership to monetize Section 29
tax credits to be realized from the Company's properties, mainly in
the DJ Basin. Contributions of $8.8 million were received through
1994. In early 1995, a second investor was added and the limited
partners committed to contribute an additional $5.0 million of which
$2.0 million was received in January 1995 and an additional $2.0
million in August 1995. As a result, this transaction is
anticipated to increase cash flow and net income through early 1996.
A revenue increase of more than $.40 per Mcf is realized on
production generated from qualified Section 29 properties in this
arrangement. The Company recognized $3.8 million, $3.0 million, and
$2.5 million of this revenue during 1993, 1994 and 1995.
(10) COMMITMENTS AND CONTINGENCIES
The Company rents office space and gas compressors at various
locations under non-cancelable operating leases. Minimum future
payments under such leases approximate $2.0 million for 1996, $2.1
million for 1997, $2.2 million for 1998 and $2.4 million for 1999 and
2000.
In April 1995, the Company settled a lawsuit in Harris County,
Texas filed by certain landowners relating to certain alleged
problems at a Company well site. The Company recorded a charge of
$4.4 million during the first quarter to reflect the cost of the
settlement. A primary insurer honored its commitments in full and
participated in the settlement. The Company's excess carriers have
declined, to date, to honor indemnification for the loss. Based on
the advice of counsel, the Company is pursuing the non-participating
carriers for the great majority of the cost of settlement. However,
given the time period which may be involved in resolving the matter,
the full amount of the settlement was provided for in the financial
statements in the first quarter of 1995.
In August 1995, the Company was sued in the United States
District Court of Colorado by seven plaintiffs purporting to
represent all persons who, at any time since January 1, 1960, have
had agreements providing for royalties from gas production in
Colorado to be paid by the Company under a number of various lease
provisions. The plaintiffs allege that the Company improperly
deducted unspecified "post-production" costs incurred by the Company
prior to calculating royalty payments in breach of the relevant lease
provisions and that the Company fraudulently concealed that fact from
plaintiffs. The plaintiffs have recently amended the complaint to
allege that the Company has also underpaid royalties on oil
production. The plaintiffs seek unspecified compensatory and
punitive damages and a declaratory judgment that the Company is not
permitted to deduct post-production costs prior to calculating
royalties paid to the class. The Company believes that its
calculations of royalties are and have been proper under the relevant
lease provisions, and intends to defend this and any similar suits
vigorously. At this time, the Company is unable to estimate the
range of potential loss, if any, from this uncertainty. However, the
Company believes the resolution of this uncertainty should not have
a material adverse effect upon the Company's financial position,
although an unfavorable outcome in any reporting period could have a
material impact on the Company's results of operations for that
period.
In 1993, the Company was granted a $2.7 million judgment in
litigation involving the allocation of proceeds from a pipeline
dispute. On appeal, the appellate court upheld the verdict but
reduced the judgment to approximately $1.4 million. The judgment has
been appealed to the Oklahoma state supreme court.
The financial statements reflect favorable legal proceedings
only upon receipt of cash, final judicial determination or execution
of a settlement agreement. The Company is a party to various other
lawsuits incidental to its business, none of which are anticipated to
have a material adverse impact on its financial position or results
of operations.
(11) UNAUDITED SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION
Independent petroleum consultants directly evaluated 62%, 58%,
and 81% of proved reserves at December 31, 1993, 1994 and 1995,
respectively, and performed a detailed review of properties which
comprised in excess of 80% of proved reserve value. All reserve
estimates are based on economic and operating conditions at that
time. Future net cash flows as of each year end were computed by
applying then current prices to estimated future production less
<PAGE> 47
<PAGE>
estimated future expenditures (based on current costs) to be incurred
in producing and developing the reserves.
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.
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
tables below 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 below. 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.
All reserves included in the tables below are located onshore in
the United States and in the waters of the Gulf of Mexico.
<TABLE>
<CAPTION>
Quantities of Proved Reserves - Crude Oil Natural Gas
--------- -----------
(MBbl) (MMcf)
<S> <C> <C>
Balance, December 31, 1992 32,202 287,658
Revisions (4,908) 5,140
Extensions, discoveries and additions 4,022 90,166
Production (3,451) (35,080)
Purchases 4,372 85,850
Sales (307) (3,645)
------- --------
Balance, December 31, 1993 31,930 430,089
Revisions (296) (102,871)
Extensions, discoveries and additions 3,981 136,583
Production (4,366) (43,809)
Purchases 3,866 93,334
Sales (138) (2,075)
------- ---------
Balance, December 31, 1994 34,977 511,251
Revisions (3,633) (89,455)
Extensions, discoveries and additions 782 32,835
Production (4,278) (53,227)
Purchases 2,002 13,449
Sales (5,603) (19,135)
------- --------
Balance, December 31, 1995 24,247 395,718
======= ========
</TABLE>
<page 48
<PAGE>
The Company's interests in the Russian joint venture (Permtex)
and its Australian affiliate (Command) are accounted for under the
equity method. At December 31, 1994 and 1995, the Company's equity
in Permtex proved reserves was 8.0 MMBOE and 7.8 MMBOE. At December
31, 1994 and 1995, the Company's equity in Command proved reserves
was 5.9 MMBOE and 10.2 MMBOE. These amounts are not included in the
quantities above.
<TABLE>
<CAPTION>
Proved Developed Reserves - Crude Natural
Oil Gas
------- ---------
(MBbl) (MMcf)
<S> <C> <C>
December 31, 1992 21,116 194,621
====== =======
December 31, 1993 18,032 268,349
====== =======
December 31, 1994 26,104 353,930
====== =======
December 31, 1995 21,637 330,524
====== =======
</TABLE>
<TABLE>
<CAPTION>
Standardized Measure - December 31,
-------------------------
1994 1995
----------- -----------
(In thousands)
<S> <C> <C>
Future cash inflows $ 1,332,705 $ 1,037,363
Future costs:
Production (469,947) (374,516)
Development (150,970) (57,959)
------------ ------------
Future net cash flows 711,788 604,888
Undiscounted income taxes (88,273) (63,248)
------------ ------------
After tax net cash flows 623,515 541,640
10% discount factor (261,833) (210,534)
------------ ------------
Standardized measure $ 361,682 $ 331,106
============ ============
</TABLE>
At December 31, 1994 and 1995, the Company's equity in the net
present value of Permtex proved reserves was $14.2 million and $10.6
million. At December 31, 1994 and 1995, the Company's equity in the
net present value of Command proved reserves was $7.1 million and
$25.6 million. These amounts are not included in the standardized
measure above.
<PAGE> 49
<PAGE>
<TABLE>
<CAPTION>
Changes in Standardized Measure - Year Ended December 31,
-------------------------------------
1993 1994 1995
---------- ---------- ----------
(In thousands)
<S> <C> <C> <C>
Standardized measure, beginning of year $ 283,572 $ 340,518 $ 361,682
Revisions:
Prices and costs (70,433) (73,330) 18,975
Quantities 6,632 (42,260) (30,495)
Development costs 16,379 (12,995) (2,806)
Accretion of discount 28,357 34,052 36,168
Income taxes (7,181) 2,195 16,249
Production rates and other (14,281) (9,506) (29,991)
--------- ---------- ----------
Net revisions (40,527) (101,844) 8,100
Extensions, discoveries and additions 57,782 68,002 18,171
Production (85,700) (97,330) (96,232)
Future development costs incurred 67,959 99,175 43,551
Purchases (a) 60,752 55,072 31,142
Sales (b) (3,320) (1,911) (35,308)
---------- ---------- ----------
Standardized measure, end of year $ 340,518 $ 361,682 $ 331,106
========== ========== ==========
<f/n>
(a) "Purchases" includes the present value at the end of the
period of properties acquired during the year plus the cash
flow received on such properties during the period, rather
than their estimated present value at the time of the
acquisition.
(b) "Sales" represents the present value at the beginning of the
period of properties sold, less the cash flow received on such
properties during the period.
</TABLE>
<PAGE> 50
<PAGE>
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON
FORM 8-K.
(a) 1. Reference is made to Item 8 on page 35.
2. Schedules otherwise required by Item 8 have been
omitted as not required or not applicable.
3. Exhibits.
4.1.1 - Certificate of Incorporation of Registrant -
incorporated by reference from Exhibit 3.1 to the
Registrant's Registration Statement on Form S-4
(Registration No. 33-33455).
4.1.2 - Certificate of Amendment to Certificate of
Incorporation of Registrant filed February 9, 1990 -
incorporated by reference from Exhibit 3.1.1 to the
Registrant's Registration Statement on Form S-4
(Registration No. 33-33455).
4.1.3 - Certificate of Amendment to Certificate of
Incorporation of Registrant filed May 22, 1991 -
incorporated by reference from Exhibit 3.1.2 to the
Registrant's Registration Statement on Form S-1
(Registration No. 33-43106).
4.1.4 - Certificate of Amendment to Certificate of
Incorporation of Registrant filed May 24, 1993 -
incorporated by reference from Exhibit 3.1.5 to the
Registrant's Form 10-Q for the quarter-ended June 30,
1993 (File No. 1-10509).
4.1.5 - Indenture dated as of May 1, 1994 between the
Registrant and Texas Commerce Bank National
Association relating to Registrant's 7% Convertible
Subordinated Notes due 2001 - incorporated by
reference to Registrant's Annual Report on Form 10-K
for the year-ended December 31, 1994 (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 - Registrant's Deferred Compensation Plan for Select
Employees, adopted effective June 1, 1994 -
incorporated by reference to Registrant's Annual
Report on Form 10-K for the year-ended December 31,
1994 (File No. 1-10509).
<PAGE> 51
<PAGE>
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 - incorporated by
reference from Exhibit 10.8 to the Registrant's
Annual Report on Form 10-K for the year-ended
December 31, 1993 (File No. 1-10509).
10.9 - Purchase and Sale Agreement dated December 11, 1992
between Atlantic Richfield Company and Registrant -
incorporated by reference to Report on Form 8-K dated
December 11, 1992 (File No. 1-10509).
10.10 - Warrant dated February 8, 1994 issued by Registrant
to Union Pacific Resources Company - incorporated by
reference from Exhibit 10.10 to the Registrant's
Annual Report on Form 10-K for the year-ended
December 31, 1993 (File No. 1-10509).
10.11 - Fifth Restated Credit Agreement dated as of June 30,
1994 among the Registrant and the banks party thereto
- incorporated by reference from Exhibit 10.11 to the
Registrant's Quarterly Report on Form 10-Q for the
quarter-ended June 30, 1994 (File No. 1-10509).
10.11.1- First Amendment dated as of May 1, 1995 to Fifth
Restated Credit Agreement - incorporated by reference
to Registrant's Quarterly Report on Form 10-Q for the
quarter-ended June 30, 1995 (File No. 1-10509).
10.11.2- Second Amendment dated as of June 30, 1995 to Fifth
Restated Credit Agreement - incorporated by reference
to Registrant's Quarterly Report on Form 10-Q for the
quarter-ended June 30, 1995 (File No. 1-10509).
10.11.3- Third Amendment dated as of November 1, 1995 to
Fifth Restated Credit Agreement.*
10.12 - Severance Agreement and Release dated November 14,
1995 between Registrant and John A. Fanning.*
10.13 - Amended and Restated Agreement and Plan of Merger
dated as of March 20, 1996 among Registrant, Patina
Oil & Gas Corporation, Patina Merger Corporation and
Gerrity Oil & Gas Corporation - incorporated by
reference to Exhibit 2.1 to Amendment No. 1 to the
Registration Statement on Form S-4 of Patina Oil & Gas
Corporation (Registration No.333-572).
11.1 - Computation of Per Share Earnings.*
12 - Computation of Ratio of Earnings to Fixed Charges and
Ratio of Earnings to Combined Fixed Charges and
Preferred Stock Dividends.*
<PAGE> 52
<PAGE>
22.1 - Subsidiaries of the Registrant.*
23.1 - Consent of Arthur Andersen LLP relating to
Registrant.*
23.2 - Consent of Netherland, Sewell & Associates, Inc.
relating to Registrant.*
23.3 - Consent of Ryder Scott Company Petroleum Engineers
relating to Registrant.*
23.4 - Consent of Arthur Andersen LLP relating to Gerrity
Oil & Gas Corporation.*
23.5 - Consent of Coopers & Lybrand L.L.P. relating to
Gerrity Oil & Gas Corporation.*
27 - Financial Data Schedule.*
99 - Reserve letter from Ryder Scott Company Petroleum
Engineers dated January 30, 1996 to the DelMar
Operating, Inc. interest as of December 31, 1995.*
99.1 - Reserve letter from Ryder Scott Company Petroleum
Engineers dated January 31, 1996 to the Snyder Oil
Corporation interest in the Baralonco properties as
of December 31, 1995.*
99.2 - Reserve letter from Netherland, Sewell & Associates,
Inc. dated March 20, 1996 to the Snyder Oil
Corporation interest as of December 31, 1995.*
(b) No reports on Form 8-K in the fourth quarter of 1995.
* Filed herewith.
<PAGE> 53
<PAGE>
<PAGE>
SIGNATURE
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the Registrant has duly caused this
report to be signed on its behalf by the undersigned thereunto duly
authorized.
/s/ John C. Snyder March 20, 1996
- ---------------------
John C. Snyder Director and Chairman of the Board
(Principal Executive Officer)
/s/ Thomas J. Edelman March 20, 1996
- ---------------------
Thomas J. Edelman Director and President
(Principal Financial Officer)
/s/ Roger W. Brittain March 20, 1996
- ---------------------
Roger W. Brittain Director
/s/ John A. Hill March 20, 1996
- ---------------------
John A. Hill Director
/s/ William J. Johnson March 20, 1996
- ---------------------
William J. Johnson Director
/s/ B. J. Kellenberger March 20, 1996
- ----------------------
B. J. Kellenberger Director
/s/ James E. McCormick March 20, 1996
- ----------------------
James E. McCormick Director
/s/ Alfred M. Micallef March 20, 1996
- ----------------------
Alfred M. Micallef Director
/s/Edward T. Story March 20, 1996
- ---------------------
Edward T. Story Director and
Vice President - International
/s/ James H. Shonsey March 20, 1996
- ---------------------
James H. Shonsey Vice President - Finance
(Principal Accounting Officer)
<PAGE> 54
<PAGE>
THIRD AMENDMENT TO FIFTH RESTATED CREDIT AGREEMENT
This Third Amendment to Fifth Restated Credit Agreement
(this"Third Amendment") is entered into as of the 1st day of
November,1995, by and among Snyder Oil Corporation ("Borrower"),
NationsBank of Texas, N.A., as Agent ("Agent"), and NationsBank of
Texas, N.A.,Bank One, Texas, N.A., Wells Fargo Bank, N.A. and Texas
Commerce Bank National Association as Banks (the "Banks").
W I T N E S E T H:
WHEREAS, Borrower, Agent and the Banks are parties to
thatcertain Fifth Restated Credit Agreement dated as of June 30,
1994, as amended by that certain (i) letter agreement by and among
Borrower and the Banks dated as of May 1, 1995, and (ii) Second
Amendment to Fifth Restated Credit Agreement by and among Borrower,
Agent and the Banks dated as of June 30, 1995 (as amended, the
"Credit Agreement") (unless otherwise defined herein, all terms used
herein with their initial letter capitalized shall have the meaning
given such terms in the Credit Agreement); and
WHEREAS, pursuant to the Credit Agreement the Banks have made
certain Loans to Borrower, and Agent has issued certain Letters of
Credit on behalf of Borrower; and
WHEREAS, Borrower has requested that (i) certain provisions of
the Credit Agreement, including, without limitation, Sections 9.5 and
10.4 and related definitions be amended in certain respects, (ii) the
amount of the Total Borrowing Base and the amounts of the Facility A
Borrowing Base and the Facility B Borrowing Base for the period
commencing November 1, 1995 and continuing until the next succeeding
Determination Date be set forth herein, and (iii) the Banks extend
the Facility B Termination Date to October 29, 1996; and
WHEREAS, subject to the terms and conditions herein contained,
the Banks have agreed to Borrower's requests.
NOW THEREFORE, for and in consideration of the mutual covenants
and agreements herein contained and other good and valuable
consideration, the receipt and sufficiency of which are hereby
acknowledged and confessed, Borrower, Agent and each Bank hereby
agree as follows:
Section 1. Amendments. Subject to the satisfaction of each
condition precedent set forth in Section 4 hereof and in reliance on
the representations, warranties, covenants and agreements contained
in this Third Amendment, the Credit Agreement shall be amended
effective November 1, 1995 (the "Effective Date") in the manner
provided in this Section 1.
1.1. Amendment to Definitions. The definition of "Loan Papers"
contained in Section 1.1 of the Credit Agreement shall be amended to
read in full as follows:
"Loan Papers" means this Agreement, the Letter Agreement, the
Second Amendment, the Third Amendment, the Notes, the Mortgages,
the Restricted Subsidiary Guarantees and all other certificates,
documents or instruments delivered in connection with this
Agreement, as the foregoing may be amended from time to time.
<PAGE>
1.2. Additional Definitions. Section 1.1 of the Credit
Agreement shall be amended to add the following definitions to such
Section:
"Giddings Properties" means those certain oil and gas properties
owned by Borrower located in the Austin-Chalk trend of Texas
and Louisiana, and primarily located in Brazos, Burleson,
Fayette, Grimes, Lee, Walker and Washington Counties, Texas,
and including those properties described in the most recent
Reserve Report delivered to the Banks as of November 1, 1995,
as being in the "GID" area.
"Rockies Properties" means those certain oil and gas properties
owned by Borrower located in (a) the Piceance basin in the
State of Colorado, and including those properties described in
the most recent Reserve Report delivered to the Banks as
of November 1, 1995 as being in the "PIC" area, (b) the East
Washakie area of the State of Wyoming, and including those
properties described in the most recent Reserve Report
delivered to the Banks as of November 1, 1995 as being in the
"BSU," "NSD," "BLG," and "BBT" areas, and (c) the Deep Green
River area of the State of Wyoming, and including those
properties described in the most recent Reserve Report
delivered to the Banks as of November 1, 1995 as being in the
"LEF" area.
"Third Amendment" means that certain Third Amendment to Fifth
Restated Credit Agreement dated as of November 1, 1995, by and
among Borrower, Agent and the Banks.
1.3. Asset Dispositions. Section 9.5 of the Credit Agreement
shall be amended to read in full as follows:
SECTION 9.5. Asset Dispositions. Except as herein provided,
neither Borrower, any Restricted Subsidiary nor DJ Partners, L.P.
shall sell, lease, abandon or otherwise transfer any of its assets to
any other Person other than pursuant to an Exempt Transfer.
Borrower, the Restricted Subsidiaries and DJ Partners, L.P. shall be
permitted to sell or otherwise dispose of any asset other than (a)
oil and gas properties, (b) Related Assets, (c) debt and equity
securities issued by any Restricted Subsidiary, and (d) Other
Borrowing Base Property. Borrower, the Restricted Subsidiaries and
DJ Partners, L.P. may sell oil and gas assets, Related Assets and
Other Borrowing Base Property; provided, that the aggregate value of
all oil and gas properties, Related Assets and Other Borrowing Base
Property sold by Borrower, the Restricted Subsidiaries and DJ
Partners, L.P. in transactions which are not Exempt Transfers during
any period between Periodic Determinations commencing with the
period between the Periodic Determinations scheduled to occur on
or around November 1, 1995, and May 1, 1996 shall not exceed the
sum of (i) the greater of (A) $10,000,000, or (B) five percent
(5%) of the Recognized Value of all oil and gas properties and
Related Assets held by Borrower and the Restricted Subsidiaries
as reflected on the most recent Reserve Report and Related Asset
Report delivered to the Banks prior to the commencement of such
period, plus (ii) the Recognized Value of all proved, developed,
producing oil and gas reserves acquired by Borrower and the
Restricted Subsidiaries during such period; provided, further,
that during the period between the Periodic Determination
scheduled to occur on or around November 1, 1995 and the Periodic
Determination scheduled to occur on or around May 1,1996, Borrower,
the Restricted Subsidiaries and DJ Partners, L.P. may sell (in
addition to the assets permitted to be sold pursuant to the preceding
proviso) (i) Borrower's interest in the Giddings Properties, and (ii)
up to twenty five percent (25%) of the interests owned by Borrower in
any or all of the Rockies Properties. The Recognized Value of all
proved, developed, producing reserves acquired by Borrower during any
period between Periodic Determinations shall be determined by
Borrower; provided that such value shall be subject to verification
and adjustment by Required Banks if the value asserted by Borrower
exceeds $5,000,000. For purposes of determining compliance with this
Section 9.5, the value of oil and gas properties, Related Assets and
Other Borrowing Base Property sold for cash shall be the sales price
of the properties sold. The value of oil and gas properties sold for
consideration other than cash shall be the amount which should be
reflected on Borrower's books in accordance with GAAP as "proceeds
from the sale of properties." Farmouts of undeveloped properties
shall not be considered sales or dispositions for purposes of this
Section 9.5 until the farmee earns a right to an assignment of the
underlying property.
<PAGE>
1.4. Adjusted Consolidated Cash Flow Coverage of Borrower.
Section 10.4 of the Credit Agreement shall be amended to read in full
as follows:
SECTION 10.4. Adjusted Consolidated Cash Flow Coverage of
Borrower. If as of March 31, 1995, June 30, 1995, September 30,
1995, December 31, 1995 or March 31, 1996, Borrower's Adjusted
Consolidated Cash Flow for (a) the fiscal quarter then ending,is less
than four percent (4%) of Borrower's Consolidated Total Covered Debt
as of such date exclusive of such portion of Consolidated Total
Covered Debt with respect to which Exempt Subsidiaries are the only
obligors, or (b) any period of four (4) fiscal quarters then ending
is less than nineteen percent (19%) of Borrower's Consolidated Total
Covered Debt as of such date exclusive of such portion of
Consolidated Total Covered Debt with respect to which Exempt
Subsidiaries are the only obligors, then, in either event, Borrower
will, prior to the expiration of the applicable Special Cash Flow
Cure Period, reduce the principal balance of the Loans to an amount
which would cause Borrower's Adjusted Consolidated Cash Flow for such
quarter and period of four (4) fiscal quarters to exceed the
percentages set forth herein of Borrower's Consolidated Total Covered
Debt as so reduced. If, as of the end of any fiscal quarter ending
on or after June 30, 1996, the aggregate Adjusted Consolidated Cash
Flow of Borrower for (y) the fiscal quarter then ended is less than
five percent (5%) of Borrower's Consolidated Total Covered Debt as of
the end of such fiscal quarter exclusive of such portion of
Consolidated Total Covered Debt with respect to which Exempt
Subsidiaries are the only obligors, or (z) the four (4) fiscal
quarters then ended is less than twenty five percent (25%) of
Borrower's Consolidated Total Covered Debt as of the end of such
fiscal quarter exclusive of such portion of Consolidated Total
Covered Debt with respect to which Exempt Subsidiaries are the only
obligors, then, in either event, Borrower will, prior to the
expiration of the applicable Special Cash Flow Cure Period, reduce
the principal balance of the outstanding Loans to an amount which
would cause Borrower's Adjusted Consolidated Cash Flow for such
quarter and period of four (4) fiscal quarters to exceed the
percentages set forth herein of Borrower's Consolidated Total Covered
Debt as so reduced.
SECTION 2. Borrowing Base. In accordance with Section 4.1
and 4.4 of the Credit Agreement, effective November 1, 1995, and
continuing until the earlier of (i) any sale of the Giddings
Properties or the Rockies Properties in accordance with Section 9.5
of the Credit Agreement, as amended by this Third Amendment
("Approved Sales"), or (ii) the next Determination Date, the Total
Borrowing Base shall be $225,000,000, allocated as follows:
$125,000,000 to the Facility A Borrowing Base, and $100,000,000 to
the Facility B Borrowing Base. Upon any Approved Sale of the
Giddings Properties, the Total Borrowing Base shall be reduced by
$12,500,000, which amount shall be fully allocated to the reduction
of the Facility A Borrowing Base. Upon any Approved Sale of the
Rockies Properties, the Total Borrowing Base shall be reduced by
$12,500,000 (assuming a twenty-five percent (25%) interest in each of
the Rockies Properties is sold, or such lesser amount as the Banks
shall approve if less than twenty-five percent (25%) of the interests
owned by Borrower in any or all of the Rockies Properties is sold),
which amount shall be fully allocated to the reduction of the
Facility A Borrowing Base. Upon any such Approved Sale, Borrower
shall immediately make a principal payment on the outstanding Loans
in an amount sufficient to eliminate any Borrowing Base Deficiency
resulting from such reduction in the Borrowing Base, and Borrower
will apply the net cash proceeds received from any Approved Sale to
the prepayment of the outstanding Loans.
SECTION 3. Extension of Facility B Termination Date.
Inaccordance with Section 2.9(b) of the Credit Agreement, Borrower
has requested that the Banks extend the Facility B Termination Date
from April 29, 1996 to October 29, 1996. The Facility B Termination
Date is hereby extended from April 29, 1996 to October 29, 1996. At
Borrower's request, the Banks hereby defer compliance with the
condition contained in Section 2.9(b) of the Credit Agreement that,
in connection with the extension of the Facility B Termination Date,
corresponding amendments be executed to each Mortgage required by
Section 5.1 of the Credit Agreement. In that regard, Borrower
acknowledges and agrees that (a) the Banks have not permanently
waived the mortgage amendment requirements of Section 2.9(b), but
have only agreed to defer compliance with such requirements, and (b)
within fifteen (15) days following request by Required Banks,
Borrower shall execute (and cause DJ Partners and the appropriate
Restricted Subsidiaries [as applicable] to execute) such amendments.
<PAGE>
SECTION 4. Conditions Precedent to Effectiveness of Amendments.
The amendments to the Credit Agreement contained in Section 1 of this
Third Amendment shall be effective only upon the satisfaction of each
of the conditions set forth in this Section 4. If each condition set
forth in this Section 4 has not been satisfied by the Effective
Date,this Third Amendment and all obligations of the Banks and Agent
contained herein shall, at the option of Majority Banks, terminate.
4.1 Corporate Existence and Authority. Borrower shall have
delivered to Agent such resolutions, certificates and other documents
as Agent shall request relative to the authorization, execution and
delivery by Borrower of this Third Amendment.
4.2 Certificate Regarding Representations and Warranties.
Borrower shall have delivered to Agent a certificate of its vice
president of finance, chief financial officer or chief accounting
officer certifying that each representation and warranty contained in
(a) the Credit Agreement, (b) this Third Amendment, and (c) each of
the other Loan Papers is true and correct and will be true and
correct after giving effect to the amendments contained in Section 1
hereof.
SECTION 5. Representations and Warranties of Borrower. To
induce the Banks and Agent to enter into this Third Amendment,
Borrower hereby represents and warrants to Agent as follows:
(a) Each representation and warranty of Borrower contained in
the Credit Agreement and the other Loan Papers is true and correct on
the date hereof and will be true and correct after giving effect to
the amendments set forth in Section 1 hereof.
(b) The execution, delivery and performance by Borrower of this
Third Amendment are within the Borrower's corporate powers, have been
duly authorized by necessary action, require no action by or in
respect of, or filing with, any governmental body, agency or official
and do not violate or constitute a default under any provision of
applicable law or any Material Agreement binding upon Borrower or the
Subsidiaries of Borrower or result in the creation or imposition of
any Lien upon any of the assets of Borrower or the Subsidiaries of
Borrower except Permitted Encumbrances.
(c) This Third Amendment constitutes the valid and binding
obligation of Borrower enforceable in accordance with its terms,
except as (i) the enforceability thereof may be limited by
bankruptcy, insolvency or similar laws affecting creditor's rights
generally, and (ii) the availability of equitable remedies may be
limited by equitable principles of general application.
SECTION 6. Miscellaneous.
6.1 No Defenses. Borrower hereby represents and warrants to
the Banks that there are no defenses to payment, counterclaims or
rights of set-off with respect to the Loans existing on the date
hereof.
6.2 Reaffirmation of Loan Papers; Extension of Liens. Any and
all of the terms and provisions of the Credit Agreement and the Loan
Papers shall, except as amended and modified hereby, remain in full
force and effect. Borrower hereby extends the Liens securing the
Obligations until the Obligations have been paid in full, and agrees
that the amendments and modifications herein contained shall in no
manner affect or impair the Obligations or the Liens securing payment
and performance thereof.
<PAGE>
6.3 Parties in Interest. All of the terms and provisions of
this Third Amendment shall bind and inure to the benefit of the
parties hereto and their respective successors and assigns.
6.4 Legal Expenses. Borrower hereby agrees to pay on demand
all reasonable fees and expenses of counsel to Agent incurred by
Agent, in connection with the preparation, negotiation and execution
of this Third Amendment and all related documents.
6.5 Counterparts. This Third Amendment may be executed in
counterparts, and all parties need not execute the same counterpart;
however, no party shall be bound by this Third Amendment until all
parties have executed a counterpart. Facsimiles shall be effective
as originals.
6.6 Complete Agreement. THIS THIRD AMENDMENT, THE CREDIT
AGREEMENT AND THE OTHER LOAN PAPERS REPRESENT THE FINAL AGREEMENT
BETWEEN THE PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR,
CONTEMPORANEOUS OR ORAL AGREEMENTS OF THE PARTIES. THERE ARE NO
UNWRITTEN ORAL AGREEMENTS BETWEEN THE PARTIES.
6.7 Headings. The headings, captions and arrangements used in
this Third Amendment are, unless specified otherwise, for convenience
only and shall not be deemed to limit, amplify or modify the terms of
this Third Amendment, nor affect the meaning thereof.
IN WITNESS WHEREOF, the parties hereto have caused this Third
Amendment to be duly executed by their respective authorized officers
on the date and year first above written.
BORROWER:
SNYDER OIL CORPORATION,
a Delaware corporation
By:/s/ Peter E. Lorenzen
Its:Vice President
<PAGE>
AGENT:
NATIONSBANK OF TEXAS, N.A.
By:/s/ E. Murphy Markham IV
-------------------------
Its:Senior Vice President
BANKS:
NATIONSBANK OF TEXAS, N.A.
By:/s/ E. Murphy Markham IV
------------------------
Its:Senior Vice President
TEXAS COMMERCE BANK
NATIONAL ASSOCIATION
By:/s/ John Field
------------------------
Its:Vice President
BANK ONE, TEXAS, N.A.
By:\s\ Brad Bartek
------------------------
Its:Vice President
WELLS FARGO BANK, N.A.
By:/s/Chad Kirkham
------------------------
Its:Vice President
SEVERANCE AGREEMENT AND RELEASE
BETWEEN SNYDER OIL CORPORATION AND JOHN A. FANNING
This Separation Agreement and Release ("Agreement") is made
and entered into this 14th day of November, 1995, by and between
Snyder Oil Corporation ("SOCO") and John A. Fanning ("Fanning").
Fanning is currently employed by SOCO as its Chief Operating
Officer. SOCO and Fanning have mutually agreed to end Fanning's
employment with SOCO, at which time SOCO wishes to retain Fanning as
an independent consultant.
Accordingly, the parties agree as follows:
1. Effective November 14, 1995, Fanning will resign as an officer
and director of SOCO and its subsidiaries. Fanning's employment by
SOCO will terminate effective the close of business on December 31,
1995 (the "Effective Date"). Between November 14, 1995 and the
Effective Date, Fanning will continue to perform those services at
such times and in such places as requested by the Chairman, but will
otherwise not be required to be present in the offices of SOCO or to
discharge any other duties of a SOCO employee.
2. Upon the Effective Date, SOCO will pay Fanning's salary for
services rendered as an employee by Fanning through and including the
Effective Date. SOCO also agrees to pay on the Effective Date, as a
severance payment, to Fanning a check in the amount of $65,000 plus
payment for any unused vacation days earned by Fanning as of the
Effective Date, net of required withholding.
3. Upon the Effective Date, Fanning will also be entitled to
receive an allocation of SOCO's 1995 contribution to the 401(k)
plan,in accordance with the terms of such plan. Pursuant to the terms
of SOCO's Deferred Compensation Plan for Select Employees a portion
of the Company's contributions allocated to Fanning's account will
become vested on December 31, 1995, the last day of the 1995 Plan
Year. For purposes of clarification, SOCO agrees that it is the
intent of this Agreement that Fanning will be an employee of SOCO on
December 31, 1995 so that amounts allocated to Fanning's account
under such Plan which would become vested on December 31, 1995 will,
in fact, become vested.
4. Upon the Effective Date, SOCO also agrees to reimburse Fanning
for any expense incurred by him through the Effective Date which is
reimbursable to Fanning in accordance with SOCO policy, provided that
Fanning submits the expenses for reimbursement in accordance with
SOCO policy.
5. Fanning recognizes that, after the Effective Date, he will no
longer be eligible to participate as a SOCO employee in any option,
savings, insurance, or other benefit plan except to the extent any
such plan provides otherwise or except as provided herein.
6. Upon the Effective Date, Fanning will be eligible to apply for
the Group Medical and Dental Plan continuation coverage pursuant to
the Consolidated Omnibus Budget Reconciliation Act ("COBRA"). If
Fanning chooses to continue coverage pursuant to COBRA, SOCO agrees
that Fanning's monthly premium for such coverage will not exceed the
amount Fanning would have paid in respect of comparable coverage
under SOCO's employee health benefit plan if Fanning were an
employee. SOCO will pay this amount only for as long as Fanning
receives COBRA continuation coverage. Fanning will be allowed to
convert his current Company paid life insurance at his own expense.
<PAGE 1>
7. Amounts credited to Fanning's account under the Deferred
Compensation Plan for Select Employees which are presently vested or
which become vested under the terms of such plan as of the Effective
Date will, notwithstanding the termination of Fanning's employment,
be retained under such Plan and will be paid in annual sums of
$61,000 per year, or such smaller amount as shall represent the full
balance credited to Fanning under such Plan, on January 5 of such
year beginning in 1996 until the full amount credited to Fanning
under such Plan is paid out. Subject to paragraph 3, amounts
forfeitable under such Plan as the result of the termination of
Fanning's employment will be forfeited as of the Effective Date.
8. The parties recognize that Fanning is the holder of 260,000
options granted under the 1989 Employee Stock Option Plan, of which
135,500 will be vested as of the Effective Date. Not withstanding
the terms of the agreements under which such options were granted,
SOCO agrees to permit Fanning to exercise his vested options in
accordance with such Plan until the close of business on the last
business day in December 1998. SOCO further agrees to permit Fanning
to pay all or any part of the exercise price of any such options
exercised by Fanning in the form of previously-owned common stock of
SOCO as provided by the Plan. The remaining options which will not
be vested as of the Effective Date will expire as provided in such
Plan and the agreements under which the options were granted.
9. In consideration of the promises of SOCO in this Agreement,
Fanning, for himself and on behalf of any agents, heirs, assigns,
relatives, spouse (if any), and related persons, hereby releases,
acquits, and forever discharges SOCO and its subsidiaries, directors,
officers, employees, agents, representatives, and related persons or
entities from all rights, demands, actions, damages, and claims,
whether known or unknown, arising from or in any way connected with
Fanning's employment with SOCO and the discontinuation thereof. This
release and waiver of all claims and damages includes, but is not
limited to, any claims to salary, vacation, or benefits, or severance
or other payment (other than as expressly provided for in this
Agreement, the Consulting Agreement referenced in paragraph 13 of
this Agreement or any other written plan under which, by its terms,
Fanning has rights after the Effective Date), any rights to be
reinstated as an employee in the future, any tort or claim of
contractual obligation relating to Fanning's employment or
discontinuation thereof, and any and all rights under federal, state,
or local laws prohibiting race, sex, age, religion, national origin,
handicap, disability, or other forms of discrimination, including but
not limited to Title VII of the Civil Rights Act, as amended, and the
Age Discrimination in Employment Act, as amended.
During the seven day period following execution of this
Agreement, Fanning may revoke this Agreement but only to the extent
that it relates to claims of age discrimination under the Age
Discrimination in Employment Act. Upon such partial revocation,
Fanning will immediately cease to be an employee of SOCO and the
promises of SOCO under paragraphs 3, 6, 7 and 8 of this Agreement and
the Consulting Agreement entered into pursuant to paragraph 13 of
this Agreement will be void; in lieu thereof, SOCO will pay Fanning
the amount provided for in SOCO's policy statement 2-7 and all
remaining parts of this Agreement will continue to be in full force
and effect.
<PAGE 2>
If Fanning breaches his agreement as provided in this
paragraph 9 not to file any charge, complaint, or claim against SOCO,
then Fanning shall be liable to SOCO for all expenses, costs, and
attorney's fees incurred in defending such charge, complaint, or
claim, regardless of the merits of the outcome.
10. It is expressly understood and agreed that this Agreement is
not and shall not be construed as an admission of liability on the
part of SOCO, which expressly denies any such liability. Neither
this Agreement nor any part thereof is admissible in any
administrative orjudicial proceeding other than one to enforce the
terms of this Agreement.
11. Fanning represents that before or on the Effective Date, he
will return all SOCO records and property in Fanning's possession
except as permitted by SOCO. SOCO hereby conveys to Fanning the
office computer equipment (not including any Company owned or
licensed software) currently in Fanning's office as well as the
cellular phone used by Fanning in his automobile.
12. SOCO agrees to assist Fanning in procuring outplacement
services. Such assistance shall be limited to reimbursement for such
services in an amount to be mutually agreed to by Fanning and the
Chairman.
13. Subject to Fanning's compliance with paragraph 9 of this
Agreement, SOCO is concomitantly entering into a consulting agreement
(the"Consulting Agreement") with Fanning in substantially the form
attached as Appendix I.
14. This Agreement shall be governed by the laws of the State of
Texas except to the extent applicable federal or state law mandates
otherwise. Any claim under or relating to this Agreement or relating
to Fanning's employment with SOCO or the discontinuance thereof,
shall be filed only in the courts of Tarrant County, Texas.
15. If any part of this Agreement is found to be invalid or not in
accordance with law, then all other parts shall remain in full force
and effect.
16. Any notices, payments, revocations, or demands under this
Agreement shall be made by hand delivery or certified mail as
follows: If to Fanning, at the address set forth on the signature
page hereto. If to SOCO, at the following address:
Snyder Oil Corporation
777 Main Street, Suite 2500
Fort Worth, Texas 76102
Attention: John C. Snyder
17. Fanning represents and warrants that he has been given
adequate time to consider this Agreement before signing it and,
further, that he was advised in writing to consult with an attorney
before signing it. Further, Fanning warrants that he has carefully
read and fully understands all the provisions and effects of this
Agreement and that he has voluntarily executed in the space provided
below.
<PAGE 3>
18. Fanning agrees that he will not make or issue any statement
concerning SOCO which damages or disparages its reputation. SOCO
likewise agrees not to make or issue any statement concerning Fanning
which damages Fanning's business or professional reputation or
prospects. In addition, when inquiries are made as to reasons for
Fanning's termination of employment, the statement set forth in
Appendix II will be given. This paragraph shall survive the end of
the Consulting Period under the Consulting Agreement referred to in
paragraph 13 of this Agreement.
19. This Agreement shall be binding on Fanning and his heirs and
legal representatives, and on SOCO, and its directors and officers.
SOCO understands and agrees in particular that the restrictions set
forth in paragraph 18 hereof apply to all current and future
directors and officers of SOCO and that any violation by any of said
persons at any time shall be deemed a violation by SOCO of this
Agreement.
SNYDER OIL CORPORATION
/s/ JOHN A. FANNING
- -------------------
JOHN A. FANNING
Date Executed: BY:/s/ John C. Snyder
--------------
John C. Snyder
Chairman of the Board
Address
921 Hillcrest Date Executed:
Fort Worth, Texas 76107
<PAGE 4>
APPENDIX I
to Severance Agreement and Release
Between Snyder Oil Corporation and John A. Fanning
CONSULTING AGREEMENT BETWEEN
SNYDER OIL CORPORATION AND JOHN A. FANNING
This Consulting Agreement is made and entered into this 14 th
day of November, 1995, by and between SNYDER OIL CORPORATION
("SOCO")
and JOHN A. FANNING ("Fanning").
Fanning's employment with SOCO is due to terminate on December
31, 1995. However, SOCO desires to avail itself of the services,
experience, sources of information, advice, and assistance of
Fanning, and Fanning is willing to make such services, experience,
sources of information, advice and assistance available to SOCO.
Accordingly, the parties agree as follows:
1. SOCO agrees to retain Fanning to perform certain consulting
services (the "Consulting Services"). The Consulting Services
shall
include management and organizational advisory services as
requested
by the Chairman, but only to the extent Fanning in his sole
judgment
has time available to render such services. Consulting Services
shall also include litigation assistance on behalf of SOCO.
Notwithstanding any other language in this paragraph, Fanning
agrees
to make himself reasonably available to assist SOCO and its counsel
in connection with any current or future litigation to which SOCO
or
any of its subsidiaries is or may be a party. Such assistance
shall
include but will not be limited to consultation interviews,
preparation for attendance at depositions, and preparation for
presentation of testimony at any trials or hearings. During the
term
of this Agreement, Fanning agrees to provide such services without
further remuneration except as to reasonable out-of-pocket expenses
as specified in paragraph 4. After the term of this Agreement
expires, Fanning also agrees to furnish such litigation assistance
services as reasonably requested by SOCO, provided that SOCO agrees
to pay Fanning a fee for such services. The parties agree to
negotiate a reasonable rate for such a fee.
2. Fanning shall perform the Consulting Services for a period of
time (the "Consulting Period") commencing on January 1, 1996, and
continuing until September 30, 1997.
3. In consideration for the Consulting Services, SOCO agrees to
pay
Fanning during the Consulting Period a fee of FOUR HUNDRED
FIFTY-FIVE
THOUSAND AND NO/100THS DOLLARS ($455,000.00). Such fee shall be
paid
to Fanning in 42 equal semi-monthly installments in an amount of
TEN
THOUSAND EIGHT HUNDRED THIRTY-THREE AND 33/100THS DOLLARS
($10.833.33) per installment. SOCO shall remit each installment to
Fanning on the fifteenth and last day of each month. Each such
payment will be made regardless of Fanning's availability to
perform
Consulting Services. In the event of Fanning's death, each such
payment will be made to Fanning's estate.
4. SOCO will also reimburse Fanning for all reasonable out-of-
pocket expenses incurred by Fanning in the course of providing any
Consulting Services hereunder, provided that Fanning promptly
submits
vouchers to SOCO for any such out-of-pocket expenses and receives
advance approval from the Chairman of expenditures exceeding $500.
<PAGE 5>
5. Fanning acknowledges that while performing any Consulting
Services under this Agreement, he will be acting as an independent
contractor and not as a SOCO employee or as an agent with authority
to bind SOCO in any respect. Fanning further acknowledges and
agrees that, except as provided in this Agreement, he shall be solely
responsible for all expenses, taxes, insurance, and other
obligations incurred by Fanning while performing the Consulting
Services.
6. Fanning acknowledges that he has obtained as an employee and
may obtain as a consultant certain proprietary information relating
to SOCO's operations ("Confidential Information"). Confidential
Information means information relating to SOCO's exploration plans,
acquisition plans, development plans, its future financial plans,
and its technology and associated trade secrets. Fanning agrees he
shall not directly or indirectly disclose any such Confidential
Information to any party or entity except as explicitly permitted by
SOCO in writing. This paragraph shall survive the end of the
Consulting Period.
7. In consideration of both the benefits made to Fanning under
this Agreement and of the Confidential Information imparted to
Fanning, Fanning agrees not to engage in certain business activities
in competition with SOCO (the "Restricted Activities"). Fanning also
agrees not to associate either directly or indirectly as an
employee, contractor, investor, officer, partner, or agent of any
person or entity involved in Restricted Activities. Restricted
Activities in this paragraph shall mean any business activity
relating to the sale, purchase, leasing, exploration, or development
of any oil, gas, or mineral interest located within the area of any
existing or prospective oil, gas, or mineral interest or other
property owned, leased, or otherwise possessed by SOCO or about which
Fanning was provided Confidential Information by SOCO, all as
specifically described in Exhibit A attached hereto and made a part
hereof. The parties understand and agree that from time to time
during the Consulting Period SOCO may propose to add additional
properties, interests or prospects to Exhibit A by delivering to
Fanning a written description of the proposed addition. If within 15
days of receipt of a proposed addition Fanning notifies SOCO in
writing that if said addition were added to Exhibit A he would be in
violation of this paragraph 7, then said proposed addition shall not
become a part of Exhibit A. If within said 15-day period, Fanning
does not notify SOCO that he would be in violation of this paragraph
7 if such addition was added to Exhibit A, then, at the end of said
15-day period said proposed addition shall become a part of Exhibit
A, and the restrictions herein shall thereafter apply to said
addition. The restrictions on Fanning's future business activities as
described in this paragraph will continue until June 30, 1998. The
parties further agree, however, that Fanning may be permitted by SOCO
to engage in such Restricted Activities in the Chairman's sole
discretion provided that Fanning obtains the Chairman's written
authorization before engaging in such Restricted Activities. If
Fanning breaches any obligation under this paragraph, SOCO can seek
injunctive relief and, at SOCO's option, may cancel any remaining
installments due Fanning pursuant to paragraph 3 of this Agreement or
may reduce the amount of such remaining installments to $2,000.00 per
monthly installment. Further, if Fanning breaches any obligation
under this paragraph, then SOCO may, at its election, cancel any
remaining stock options held by Fanning as set forth in paragraph 8
of the Severance Agreement and Release expressly incorporated herein.
Fanning acknowledges that Exhibit A contains Confidential
Information of SOCO and agrees, except as may be authorized in
writing by SOCO, to keep the contents of such Exhibit confidential to
the same extent Fanning is required to maintain the confidentiality
of other Confidential Information imparted to him by SOCO by virtue
of Fanning's having served as an officer of SOCO.
<PAGE 6>
8. During the Consulting Period, Fanning agrees to notify SOCO in
writing promptly of any activities or investments he proposes to make
which he believes may constitute a violation of paragraph 7. Within
10 days after SOCO receives said written notice, SOCO will deliver a
written reply to Fanning indicating whether it believes said proposed
activity or investment would be deemed by SOCO a violation of
paragraph 7 and whether or not SOCO's Chairman is authorizing
Fanning's engagement in such activity or investment as permitted
under paragraph 7 of this Agreement. If SOCO does not deliver such
written reply to Fanning within said 10 days, Fanning shall be free
to undertake such activity or investment, and it shall not be a
violation of paragraph 7.
9. This Agreement and the rights, interests, and benefits of
Fanning hereunder may not be assigned or transferred in any way by
Fanning, without the express written consent of SOCO. Fanning may
not assign or delegate any of the duties hereunder without the
express written consent of SOCO. Any assignment or transfer contrary
to the foregoing provisions shall be void.
10. Any notices, payments, revocations, or demands under this
Agreement shall be made by hand-delivery or certified mail as
follows: If to Fanning, at the address set forth on the signature
page hereunder; if to SOCO, at the following address:
Snyder Oil Corporation
777 Main Street, Suite 2500
Fort Worth, TX 76102
Attention: John C. Snyder
11. This Agreement shall be governed by the laws of the State of
Texas. Any claim under or relating to this Agreement shall be filed
only in the courts of Tarrant County, Texas.
12. This Agreement shall be fairly interpreted according to its
language and without regard to the drafter.
13. If any provision of this Agreement shall be held to be
unenforceable or invalid, then such provision, or the invalidity or
unenforceability thereof, shall in no way affect the validity of any
other provisions hereof. This Agreement contains the entire
agreement of the parties with respect to the subject matter hereof,
and supersedes any prior agreements, written or oral, between the
parties with respect to such subject matter. This Agreement may be
amended only in writing signed by both parties.
SNYDER OIL CORPORATION
/s/ John A. Fanning
- -------------------
JOHN A. FANNING
Date Executed: BY:/s/ John C. Snyder
------------------
John C. Snyder
Chairman of the Board
Address:
921 Hillcrest Date Executed:
Fort Worth, Texas 76107
<PAGE 7>
EXHIBIT A
to Consulting Agreement between
Snyder Oil Corporation and John A. Fanning
Exhibit A consists of this page and seven pages of maps, each of
which has been initialled by the parties for purposes of
identification.
<PAGE 8>
APPENDIX II
to Severance Agreement and Release
Between Snyder Oil Corporation and John A. Fanning
John Fanning left the employment of snyder Oil as part of are
structuring of the Company. Since January 1, 1995, we have sold or
plan to sell a significant number of assets and reduced employment by
35% to 40%. As a result, we have organized into a smaller, more
focused organization and reduced the number of reporting
relationships. Therefore, the position of Chief Operating Officer
has been eliminated and John elected to resign.
<TABLE>
EXHIBIT 11.1
SNYDER OIL CORPORATION
COMPUTATION OF NET INCOME (LOSS) PER SHARE
FOR THE YEARS ENDED DECEMBER 31, 1993, 1994 AND 1995
(In thousands except per share data)
<CAPTION>
Year Ended December 31,
--------------------------------
1993 1994 1995
-------- -------- --------
<S> <C> <C> <C>
Income (loss) before extraordinary item $22,538 $12,372 $(39,831)
Extraordinary item-early extinguishment of debt (2,993) - -
-------- -------- --------
Net income (loss) 19,545 12,372 (39,831)
Dividends on preferred stock (9,100) (10,806) (6,210)
-------- -------- --------
Net income (loss) available to common $10,445 $ 1,566 $(46,041)
======== ======== =========
Weighted average shares outstanding 23,096 23,704 30,186
Add common stock equivalents 10,356 11,706 5,019
-------- -------- ---------
Weighted average common stock
and equivalents outstanding 33,452 35,410 35,205
======== ======== ========
Primary net income (loss) per share:
Income (loss) before extraordinary item $ .97 $ .52 $ (1.32)
Extraordinary item-early extinguishment of debt (.13) - -
-------- -------- --------
Net income (loss) .84 .52 (1.32)
Dividends on preferred stock (.39) (.45) (.21)
-------- -------- --------
Net income (loss) available to common $ .45 $ .07 $ (1.53)
======== ======== ========
Fully diluted net income (loss) per share:
Income (loss) before extraordinary item $ .67 $ .35 $(1.13)
Extraordinary item-early extinguishment of debt (.09) - -
-------- -------- --------
Net income (loss) .58 .35 (1.13)
Dividends on preferred stock - - -
-------- -------- --------
Net income (loss) available to common $ .58 $ .35 $(1.13)
======== ======== ========
</TABLE>
<TABLE>
EXHIBIT 12
SNYDER OIL CORPORATION
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
(Unaudited)
<CAPTION>
Year Ended December 31,
-----------------------------------------------
1991 1992 1993 1994 1995
------- ------- ------- ------- -------
(Dollars in thousands)
<S> <C> <C> <C> <C> <C>
Income (loss) before taxes, minority
interest and extraordinary item $ 3,893 $15,027 $22,538 $13,510 ($40,604)
Interest expense 8,452 4,997 5,315 10,337 21,679
------- ------- ------- ------- -------
Earnings before fixed charges $12,345 $20,024 $27,853 $23,847 ($18,925)
======= ======= ======= ======= =========
Fixed Charges:
Interest expense $ 8,452 $ 4,997 $ 5,315 $10,337 $21,679
------- ------- ------- ------- -------
Total fixed charges $ 8,452 $ 4,997 $ 5,315 $10,337 $21,679
======= ======= ======= ======= =======
Ratio of earnings
to fixed charges 1.46 4.01 5.24 2.31 (0.87)
======= ======= ======= ======= ========
</TABLE>
<PAGE>
<TABLE>
SNYDER OIL CORPORATION
COMPUTATION OF RATIO OF EARNINGS TO
COMBINED FIXED CHARGES AND PREFERRED STOCK DIVIDENDS
(Unaudited)
<CAPTION>
Year Ended December 31,
-----------------------------------------------
1991 1992 1993 1994 1995
------- ------- ------- ------- -------
(Dollars in thousands)
<S> <C> <C> <C> <C> <C>
Income (loss) before taxes, minority
interest and extraordinary item $ 3,893 $15,027 $22,538 $13,510 ($40,604)
Interest expense 8,452 4,997 5,315 10,337 21,679
------- ------- ------- ------- ---------
Earnings before fixed charges $12,345 $20,024 $27,853 $23,847 ($18,925)
======= ======= ======= ======= =========
Fixed Charges:
Interest expense $ 8,452 $ 4,997 $ 5,315 $10,337 $21,679
Preferred stock dividends 453 4,800 9,100 10,806 6,210
------- ------- ------- ------- -------
Total fixed charges $ 8,905 $ 9,797 $14,415 $21,143 $27,889
======= ======= ======= ======= =======
Ratio of earnings
to combined fixed charges
and preferred stock dividends 1.39 2.04 1.93 1.13 (0.68)
======= ======= ======= ======= ========
</TABLE>
EXHIBIT 22.1
SNYDER OIL CORPORATION
SUBSIDIARIES AS OF MARCH 10, 1996
State of
Name of Subsidiary Organization
------------------ -------------
SOCO Wattenberg Corporation Delaware
SOCO International, Inc. Delaware
The names of other subsidiaries are omitted in accordance with
Item 601(b)(22)(ii) of Regulation S-K.
EXHIBIT 23.1
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the
incorporation of our report dated February 20, 1996 on the financial
statements of Snyder Oil Corporation included in this Form 10-K, into
Snyder Oil Corporation's previously filed Registration Statement Nos.
33-54809 and 33-64219.
ARTHUR ANDERSEN LLP
Fort Worth, Texas
March 22, 1996
EXHIBIT 23.2
CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND CONSULTANTS
As independent petroleum consultants, we hereby consent to the incorporation of
our reports included in this Form 10-K into Snyder Oil Corporation's
Registration Statement Nos. 33-54809 and 33-64219.
NETHERLAND, SEWELL & ASSOCIATES, INC.
By:/s/ Frederic D. Sewell
-----------------------------------
Frederic D. Sewell
President
Dallas, Texas
March 21, 1996
EXHIBIT 23.3
CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND CONSULTANTS
As independent petroleum consultants, we hereby consent to the
incorporation of the references to us in this Form 10-K into Snyder
Oil Corporation's Registration Statement Nos. 33-54809 and 33-64219.
RYDER SCOTT COMPANY
PETROLEUM ENGINEERS
Houston, Texas
March 22, 1996
EXHIBIT 23.4
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the
incorporation by reference of our report dated March 19, 1996 on the
financial statements of Gerrity Oil & Gas Corporation for the years
ended December 31, 1994 and 1995 included in the Registration
Statement on Amendment No. 1 to Form S-4 of Patina Oil & Gas
Corporation (Registration Statement No. 333-572) into this Form 10-K,
and into Snyder Oil Corporation's previously filed Registration
Statements Nos. 33-54809 and 33-64219.
ARTHUR ANDERSEN LLP
Denver, Colorado
March 22, 1996
EXHIBIT 23.5
CONSENT OF INDEPENDENT ACCOUNTANTS
We consent to the incorporation by reference in this annual report on
Form 10-K and in Snyder Oil Corporation's previously filed
registration statements (SEC File Nos 33-54809 and 33-64219) of our
report dated March 30, 1994 on our audit of the consolidated financial
statements of Gerrity Oil & Gas Corporation for the year ended
December 31, 1993, appearing in the registration statement on
amendment No. 1 to Form S-4 (SEC File No. 333-572) of Patina Oil &
Gas Corporation filed with the Securities and Exchange Commission
pursuant to the Securities Act of 1933.
COOPERS & LYBRAND L.L.P.
Denver, Colorado
March 22, 1996
<TABLE> <S> <C>
<ARTICLE> 5
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1995
<PERIOD-START> JAN-01-1995
<PERIOD-END> DEC-31-1995
<CASH> 27,263
<SECURITIES> 0
<RECEIVABLES> 29,259
<ALLOWANCES> 0
<INVENTORY> 9,958
<CURRENT-ASSETS> 68,291
<PP&E> 706,467
<DEPRECIATION> 252,485
<TOTAL-ASSETS> 555,493
<CURRENT-LIABILITIES> 62,449
<BONDS> 234,059
0
10
<COMMON> 314
<OTHER-SE> 235,044
<TOTAL-LIABILITY-AND-EQUITY> 555,493
<SALES> 182,864
<TOTAL-REVENUES> 202,160
<CGS> 173,781
<TOTAL-COSTS> 203,330
<OTHER-EXPENSES> 12,433
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 27,001
<INCOME-PRETAX> (40,604)
<INCOME-TAX> (1,345)
<INCOME-CONTINUING> (39,831)
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (39,831)
<EPS-PRIMARY> (1.53)
<EPS-DILUTED> (1.53)
</TABLE>
EXHIBIT 99
January 30, 1996
DelMar Operating, Inc.
1100 Louisiana, Suite 900
Houston, Texas 77002-5218
Gentlemen:
At your request, we have prepared an estimate of the reserves,
future production, and income attributable to certain company
leasehold and royalty interest of DelMar Operating, Inc. (DelMar),
as of December 31, 1995. The subject properties are located in the
states of Louisiana and Texas and in federal waters offshore
Louisiana, and Texas. The income data were estimated using
Securities and Exchange Commission (SEC) guidelines for future cost
and price parameters.
The estimated reserves and future income amounts presented in
this report are related to hydrocarbon prices. December 1995
hydrocarbon prices were used in the preparation of this report as
required by SEC guidelines; however, actual future prices may vary
significantly from December 1995 prices. Therefore, volumes of
reserves actually recovered and amounts of income actually received
may differ significantly from the estimated quantities presented in
this report. A summary of the results of this study is shown
below.
<TABLE>
<CAPTION>
SEC PARAMETERS
Estimated Net Reserves and Income Data
Certain Company Leasehold and Royalty Interest of
DelMar Operating, Inc.
As of December 31, 1995
Proved
--------------------------------------------------------------------------------------
Developed
------------------------------------- Total
Producing Non-Producing Undeveloped Proved
-------------- --------------- ------------- ------------
<S> <C> <C> <C> <C>
Net Remaining Reserves
- ----------------------
Oil/Condensate - Barrels 171,840 164,993 9,371 346,204
Gas - MMCF 3,374 1,922 709 6,005
Income Data
- ----------------------
Future Gross Revenue $10,735,515 $7,524,844 $1,792,863 $20,053,222
Deductions 3,914,186 2,814,763 492,894 7,221,843
----------- ---------- ---------- ----------
Future Net Income (FNI) $ 6,821,329 $4,710,081 $1,299,969 $12,831,379
Discounted FNI @ 10% $6,264,843 $3,328,474 $ 947,031 $10,540,348
/TABLE
<PAGE>
<TABLE>
<CAPTION>
Probable
--------------------------------------------------------------------------------------
Developed
------------------------------------- Total
Producing Non-Producing Undeveloped Probable
-------------- --------------- -------------- -------------
<S> <C> <C> <C> <C>
Net Remaining Reserves
- -------------------------
Oil/Condensate - Barrels 4,873 21,816 2,769 29,458
Gas - MMCF 192 702 220 1,114
Income Data
- -------------------------
Future Gross Revenue $533,342 $2,060,966 $553,597 $3,147,905
Deductions 0 333,099 250,409 583,508
-------- ---------- -------- ----------
Future Net Income (FNI) $533,342 $1,727,867 $303,188 $2,564,397
Discounted FNI @ 10% $446,526 $1,009,594 $229,266 $1,685,386
</TABLE>
<TABLE>
<CAPTION>
Possible
---------------------------------------------------------
Developed
--------------------------------- Total
Producing Non-Producing Possible
---------- -------------- ----------
<S> <C> <C> <C>
Net Remaining Reserves
- -------------------------
Oil/Condensate - Barrels 4,873 2,488 7,361
Gas - MMCF 166 129 295
Income Data
- --------------------------
Future Gross Revenue $468,668 $340,374 $809,042
Deductions 0 14,233 14,233
-------- -------- ---------
Future Net Income (FNI) $468,668 $326,141 $794,809
Discounted FNI @ 10% $398,126 $188,671 $586,797
</TABLE>
Liquid hydrocarbons are expressed in standard 42 gallon
barrels. All gas volumes are sales gas expressed in millions of
cubic feet (MMCF) at the official temperature and pressure bases of
the areas in which the gas reserves are located. We have included
probable and possible reserves and income in this report at the
request of DelMar. These data are for DelMar's information only
and should not be included in reports to the SEC according to the
SEC guidelines.
The proved, probable, and possible developed non-producing
reserves included herein are comprised of the behind pipe category.
The various producing status categories are defined under the tab
"Reserve Definitions and Pricing Assumptions" in this report.
The deductions are comprised of the normal direct costs of
operating the wells, recompletion costs, development costs, and
certain "unfunded" abandonment costs net of salvage. The future
net income is before the deduction of state and federal income
taxes and general administrative overhead, and has not been
adjusted for outstanding loans that may exist nor does it include
any adjustment for cash on hand or undistributed income. DelMar
informed us of three gas imbalances which are included in this
report. They are in the Eugene Island 342, East Cameron 317/318,
and Eugene Island 324 fields. Gas reserves account for
approximately 68 percent and Liquid hydrocarbon reserves account
for the remaining 32 percent of total future gross revenue from
proved reserves.
The discounted future net income shown above was calculated
using a discount rate of 10 percent per annum compounded monthly.
Future net income was discounted at four other discount rates which
were also compounded monthly. These results are shown on each
estimated projection of future production and income presented in a
later section of this report and in summary form below.
<TABLE>
<CAPTION>
Discounted Future Net Income
As of December 31, 1995
-------------------------------------------------------------------------
Discount Rate Total Total Total
Percent Proved Probable Possible
------------------ ---------------- --------------- -----------------
<S> <C> <C> <C>
5 $11,591,704 $2,057,722 $678,308
15 $ 9,640,592 $1,406,247 $513,932
20 $ 8,864,025 $1,192,731 $455,147
25 $ 8,188,521 $1,026,141 $407,116
The results shown above are presented for your information and
should not be construed as our estimate of fair market value.
Reserves Included in This Report
The proved reserves included herein conform to the definition
as set forth in the Securities and Exchange Commission's Regulation
S-X Part 210.4-10 (a) as clarified by subsequent Commission Staff
Accounting Bulletins. The probable reserves and possible reserves
included herein conform to definitions of probable and possible
reserves approved by the Society of Petroleum Engineers and the
Society of Petroleum Evaluation Engineers. Our definitions of
proved, probable, and possible reserves are included under the tab
"Reserve Definitions and Pricing Assumptions" in this report.
The probable reserves are less certain to be recovered than the
proved reserves and reserves classified as possible are less
certain to be recovered than those in the probable category. The
reserves and income quantities attributable to the different
reserve classifications that are included herein have not been
adjusted to reflect the varying degrees of risk associated with
them and thus are not comparable.
Estimates of Reserves
In general, the reserves included herein were estimated by
performance methods or the volumetric method; however, other
methods were used in certain cases where characteristics of the
data indicated such other methods were more appropriate in our
opinion. The reserves estimated by the performance method utilized
extrapolations of various historical data in those cases where such
data were definitive in our opinion. Reserves were estimated by
the volumetric method in those cases where there were inadequate
historical performance data to establish a definitive trend or
where the use of production performance data as a basis for the
reserve estimates was considered to be inappropriate.
The reserves included in this report are estimates only and
should not be construed as being exact quantities. They may or may
not be actually recovered, and if recovered, the revenues therefrom
and the actual costs related thereto could be more or less than the
estimated amounts. Moreover, estimates of reserves may increase or
decrease as a result of future operations.
Future Production Rates
Initial production rates are based on the current producing
rates for those wells now on production. Test data and other
related information were used to estimate the anticipated initial
production rates for those wells or locations which are not
currently producing. If no production decline trend has been
established, future production rates were held constant, or
adjusted for the effects of curtailment where appropriate, until a
decline in ability to produce was anticipated. An estimated rate
of decline was then applied to depletion of the reserves. If a
decline trend has been established, this trend was used as the
basis for estimating future production rates. For reserves not yet
on production, sales were estimated to commence at an anticipated
date furnished by DelMar.
In general, we estimate that future gas production rates will
continue to be the same as the average rate for the latest
available 12 months of actual production until such time that the
well or wells are incapable of producing at this rate. The well or
wells were then projected to decline at their decreasing delivery
capacity rate. Our general policy on estimates of future gas
production rates is adjusted when necessary to reflect actual gas
market conditions in specific cases.
The future production rates from wells now on production may be
more or less than estimated because of changes in market demand or
allowables set by regulatory bodies. Wells or locations which are
not currently producing may start producing earlier or later than
anticipated in our estimates of their future production rates.
Hydrocarbon Prices
DelMar furnished us with prices in effect at December 31, 1995
and these prices were held constant. In accordance with Securities
and Exchange Commission guidelines, changes in liquid and gas
prices subsequent to December 31, 1995 were not taken into account
in this report. Future prices used in this report are discussed in
more detail under the tab "Reserve Definitions and Pricing
Assumptions" in this report.
Costs
Operating costs for the leases and wells in this report were
furnished by DelMar. They were accepted without independent
verification. They are based on the operating expense reports of
DelMar and include only those costs directly applicable to the
leases or wells. When applicable, the operating costs include a
portion of general and administrative costs allocated directly to
the leases and wells under terms of operating agreements. They do
not include COPAS costs.
Development costs were furnished to us by DelMar and are based
on authorizations for expenditure for the proposed work or actual
costs for similar projects. The current operating and development
costs were held constant throughout the life of the properties. No
deduction was made for indirect costs such as general
administration and overhead expenses, loan repayments, interest
expenses, and exploration and development prepayments that are not
charged directly to the leases or wells.
Abandonment Costs
For offshore properties, DelMar's estimate of net, "unfunded",
abandonment cost after salvage was included in this report (other
deductions). Please note, that at DelMar's request, only the
unfunded portion was included. In this report, funded means a
letter of credit or money in an escrow account. Unfunded, means
costs still to be collected, either by unit of production,
overriding royalty, or end of life payment. There are "Remarks" on
the first summary of each field that indicate how funding was
handled in that field.
For onshore properties, at the request of DelMar, DelMar's
estimate of zero net abandonment costs after salvage value was used
in this report. Ryder Scott has not performed a detail study of
the abandonment costs nor the salvage value and makes no warranty
for DelMar's estimates.
General
Table A presents a one line summary of proved reserve and
income data for each of the subject properties which are ranked
according to their future net income discounted at 10 percent per
year. Table B presents a one line summary of gross and net
reserves and income data for each of the subject properties. Table
C presents a one line summary of initial basic data for each of the
subject properties. Tables 1 through 239 present our estimated
projection of production and income by years beginning December 31,
1995, by program, state, field, and lease or well.
While it may reasonably be anticipated that the future prices
received for the sale of production and the operating costs and
other costs relating to such production may also increase or
decrease from existing levels, such changes were, in accordance
with rules adopted by the SEC, omitted from consideration in making
this evaluation.
The estimates of reserves presented herein were based upon a
detailed study of the subject properties; however, we have not made
any field examination of the properties. No consideration was
given in this report to potential environmental liabilities which
may exist nor were any costs included for potential liability to
restore and clean up damages, if any, caused by past operating
practices. DelMar has informed us that they have furnished us all
of the accounts, records, geological and engineering data, and
reports and other data required for this investigation. The
ownership interests, prices, and other factual data furnished by
DelMar were accepted without independent verification. The
estimates presented in this report are based on data available
through December 1995.
Neither we nor any of our employees have any interest in the
subject properties and neither the employment to make this study
nor the compensation is contingent on our estimates of reserves and
future income for the subject properties.
This report was prepared for the exclusive use of DelMar
Operating, Inc. The data, work papers, and maps used in this
report are available for examination by authorized parties in our
offices. Please contact us if we can be of further service.
Very truly yours,
RYDER SCOTT COMPANY
PETROLEUM ENGINEERS
/s/Joseph E. Blankenship, P.E.
------------------------------
Joseph E. Blankenship, P.E.
JEB/sw Petroleum Engineer
Approved:
/s/ Joseph E. Magoto, P.E.
- --------------------------
Joseph E. Magoto, P.E.
Group Vice President
<PAGE>
</TABLE>
EXHIBIT 99.1
January 31, 1996
DelMar Operating, Inc.
1100 Louisiana, Suite 900
Houston, Texas 77002-5218
Gentlemen:
At your request, we have prepared an estimate of the reserves,
future production, and income attributable to certain "Baralonco
interest" owned by Snyder Oil Corporation in DelMar Operating, Inc.
Programs as of December 31, 1995. The subject properties are
located in the states of Louisiana and Texas and in federal waters
offshore Louisiana, and Texas. The income data were estimated
using Securities and Exchange Commission (SEC) guidelines for
future cost and price parameters.
The estimated reserves and future income amounts presented in
this report are related to hydrocarbon prices. December 1995
hydrocarbon prices were used in the preparation of this report as
required by SEC guidelines; however, actual future prices may vary
significantly from December 1995 prices. Therefore, volumes of
reserves actually recovered and amounts of income actually received
may differ significantly from the estimated quantities presented in
this report. A summary of the results of this study is shown
below.
<TABLE>
<CAPTION>
SEC PARAMETERS
Estimated Net Reserves and Income Data
Snyder Oil Corporation (Baralonco Interest)
DelMar Operating, Inc. Programs
As of December 31, 1995
Proved
----------------------------------------------------------------------------
Developed
--------------------------------- Total
Producing Non-Producing Undeveloped Proved
---------- ------------- --------------- ------------
<S> <C> <C> <C> <C>
Net Remaining Reserves
- ----------------------
Oil/Condensate-Barrels 119,218 74,240 77,647 271,105
Gas - MMCF 5,050 2,638 2,553 10,241
Income Data
- ----------------------
Future Gross Revenue $13,638,609 $7,426,972 $7,273,369 $28,338,950
Deductions 2,180,714 1,478,727 2,053,474 5,712,915
----------- ---------- ---------- -----------
Future Net Income(FNI) $11,457,895 $5,948,245 $5,219,895 $22,626,035
Discounted FNI @ 10% $10,057,206 $4,182,178 $3,811,756 $18,051,140
/TABLE
<PAGE>
<TABLE>
<CAPTION>
Probable
--------------------------------------------------------------------------------
Developed
----------------------------------- Total
Producing Non-Producing Undeveloped Probable
----------- -------------- ----------- ----------
<S> <C> <C> <C> <C>
Net Remaining Reserves
- --------------------------
Oil/Condensate - Barrels 9,179 13,173 32,401 54,753
Gas - MMCF 330 705 1,159 2,194
Income Data
- --------------------------
Future Gross Revenue $923,033 $1,859,812 $3,278,402 $6,061,247
Deductions 0 296,847 904,336 1,201,183
-------- ---------- ---------- ----------
Future Net Income (FNI) $923,033 $1,562,965 $2,374,066 $4,860,064
Discounted FNI @ 10% $780,317 $ 920,921 $1,807,376 $3,508,614
</TABLE>
<TABLE>
<CAPTION>
Possible
-------------------------------------------------------------------------------
Developed
---------------------------------- Total
Producing Non-Producing Undeveloped Possible
----------- -------------- ----------- ----------
<S> <C> <C> <C> <C>
Net Remaining Reserves
- -------------------------
Oil/Condensate - Barrels 9,179 4,607 9,334 23,120
Gas - MMCF 314 218 440 972
Income Data
- ------------
Future Gross Revenue $882,831 $580,626 $1,199,706 $2,663,163
Deductions 0 15,271 312,432 327,703
-------- -------- ---------- ----------
Future Net Income (FNI) $882,831 $565,355 $ 887,274 $2,335,460
Discounted FNI @ 10% $750,231 $318,515 $ 535,410 $1,604,156
</TABLE>
Liquid hydrocarbons are expressed in standard 42 gallon
barrels. All gas volumes are sales gas expressed in millions of
cubic feet (MMCF) at the official temperature and pressure bases of
the areas in which the gas reserves are located. We have included
probable and possible reserves and income in this report at the
request of DelMar. These data are for DelMar's information only
and should not be included in reports to the SEC according to the
SEC guidelines.
The proved, probable, and possible developed non-producing
reserves included herein are comprised of the behind pipe category.
The various producing status categories are defined under the tab
"Reserve Definitions and Pricing Assumptions" in this report.
The deductions are comprised of the normal direct costs of
operating the wells, "COPAS" costs, recompletion costs, development
costs, and certain "unfunded" abandonment costs net of salvage.
The future net income is before the deduction of state and federal
income taxes and general administrative overhead, and has not been
adjusted for outstanding loans that may exist nor does it include
any adjustment for cash on hand or undistributed income. DelMar
informed us of four gas imbalances which are included in this
report. They are in the Eugene Island 342, East Cameron 317/318,
Eugene Island 324, and Ewing Bank 947 fields. Gas reserves account
for approximately 83 percent and Liquid hydrocarbon reserves
account for the remaining 17 percent of total future gross revenue
from proved reserves.
The discounted future net income shown above was calculated
using a discount rate of 10 percent per annum compounded monthly.
Future net income was discounted at four other discount rates which
were also compounded monthly. These results are shown on each
estimated projection of future production and income presented in a
later section of this report and in summary form below.
<TABLE>
<CAPTION>
Discounted Future Net Income
As of December 31, 1995
----------------------------------------------------------------------
Discount Rate Total Total Total
Percent Proved Probable Possible
------------------ ---------------- --------------- ------------------
<S> <C> <C> <C>
5 $20,138,754 $4,098,918 $1,923,630
15 $16,284,861 $3,040,817 $1,354,067
20 $14,778,870 $2,662,784 $1,156,521
25 $13,485,368 $2,351,943 $ 999,071
</TABLE>
The results shown above are presented for your information and
should not be construed as our estimate of fair market value.
Reserves Included in This Report
The proved reserves included herein conform to the definition
as set forth in the Securities and Exchange Commission's Regulation
S-X Part 210.4-10 (a) as clarified by subsequent Commission Staff
Accounting Bulletins. The probable reserves and possible reserves
included herein conform to definitions of probable and possible
reserves approved by the Society of Petroleum Engineers and the
Society of Petroleum Evaluation Engineers. Our definitions of
proved, probable, and possible reserves are included under the tab
"Reserve Definitions and Pricing Assumptions" in this report.
The probable reserves are less certain to be recovered than the
proved reserves and reserves classified as possible are less
certain to be recovered than those in the probable category. The
reserves and income quantities attributable to the different
reserve classifications that are included herein have not been
adjusted to reflect the varying degrees of risk associated with
them and thus are not comparable.
Estimates of Reserves
In general, the reserves included herein were estimated by
performance methods or the volumetric method; however, other
methods were used in certain cases where characteristics of the
data indicated such other methods were more appropriate in our
opinion. The reserves estimated by the performance method utilized
extrapolations of various historical data in those cases where such
data were definitive in our opinion. Reserves were estimated by
the volumetric method in those cases where there were inadequate
historical performance data to establish a definitive trend or
where the use of production performance data as a basis for the
reserve estimates was considered to be inappropriate.
The reserves included in this report are estimates only and
should not be construed as being exact quantities. They may or may
not be actually recovered, and if recovered, the revenues therefrom
and the actual costs related thereto could be more or less than the
estimated amounts. Moreover, estimates of reserves may increase or
decrease as a result of future operations.
Future Production Rates
Initial production rates are based on the current producing
rates for those wells now on production. Test data and other
related information were used to estimate the anticipated initial
production rates for those wells or locations which are not
currently producing. If no production decline trend has been
established, future production rates were held constant, or
adjusted for the effects of curtailment where appropriate, until a
decline in ability to produce was anticipated. An estimated rate
of decline was then applied to depletion of the reserves. If a
decline trend has been established, this trend was used as the
basis for estimating future production rates. For reserves not yet
on production, sales were estimated to commence at an anticipated
date furnished by DelMar.
In general, we estimate that future gas production rates will
continue to be the same as the average rate for the latest
available 12 months of actual production until such time that the
well or wells are incapable of producing at this rate. The well or
wells were then projected to decline at their decreasing delivery
capacity rate. Our general policy on estimates of future gas
production rates is adjusted when necessary to reflect actual gas
market conditions in specific cases.
The future production rates from wells now on production may be
more or less than estimated because of changes in market demand or
allowables set by regulatory bodies. Wells or locations which are
not currently producing may start producing earlier or later than
anticipated in our estimates of their future production rates.
Hydrocarbon Prices
DelMar furnished us with prices in effect at December 31, 1995
and these prices were held constant. In accordance with Securities
and Exchange Commission guidelines, changes in liquid and gas
prices subsequent to December 31, 1995 were not taken into account
in this report. Future prices used in this report are discussed in
more detail under the tab "Reserve Definitions and Pricing
Assumptions" in this report.
Costs
Operating costs for the leases and wells in this report were
furnished by DelMar. They were accepted without independent
verification. They are based on the operating expense reports of
DelMar and include only those costs directly applicable to the
leases or wells. When applicable, the operating costs include a
portion of general and administrative costs allocated directly to
the leases and wells under terms of operating agreements. They
include COPAS costs.
Development costs were furnished to us by DelMar and are based
on authorizations for expenditure for the proposed work or actual
costs for similar projects. The current operating and development
costs were held constant throughout the life of the properties. No
deduction was made for indirect costs such as general
administration and overhead expenses, loan repayments, interest
expenses, and exploration and development prepayments that are not
charged directly to the leases or wells.
Abandonment Costs
For offshore properties, DelMar's estimate of net, "unfunded",
abandonment cost after salvage was included in this report (other
deductions). Please note, that at DelMar's request, only the
unfunded portion was included. In this report, funded means a
letter of credit or money in
an escrow account. Unfunded, means costs still to be collected,
either by unit of production, overriding royalty, or end of life
payment. There are "Remarks" on the first summary of each field
that indicate how funding was handled in that field.
For onshore properties, at the request of DelMar, DelMar's
estimate of zero net abandonment costs after salvage value was used
in this report. Ryder Scott has not performed a detail study of
the abandonment costs nor the salvage value and makes no warranty
for DelMar's estimates.
General
Table A presents a one line summary of proved reserve and
income data for each of the subject properties which are ranked
according to their future net income discounted at 10 percent per
year. Table B presents a one line summary of gross and net
reserves and income data for each of the subject properties. Table
C presents a one line summary of initial basic data for each of the
subject properties. Tables 1 through 260 present our estimated
projection of production and income by years beginning December 31,
1995, by program, state, field, and lease or well.
While it may reasonably be anticipated that the future prices
received for the sale of production and the operating costs and
other costs relating to such production may also increase or
decrease from existing levels, such changes were, in accordance
with rules adopted by the SEC, omitted from consideration in making
this evaluation.
The estimates of reserves presented herein were based upon a
detailed study of the subject properties; however, we have not made
any field examination of the properties. No consideration was
given in this report to potential environmental liabilities which
may exist nor were any costs included for potential liability to
restore and clean up damages, if any, caused by past operating
practices. DelMar has informed us that they have furnished us all
of the accounts, records, geological and engineering data, and
reports and other data required for this investigation. The
ownership interests, prices, and other factual data furnished by
DelMar were accepted without independent verification. The
estimates presented in this report are based on data available
through December 1995.
Neither we nor any of our employees have any interest in the
subject properties and neither the employment to make this study
nor the compensation is contingent on our estimates of reserves and
future income for the subject properties.
This report was prepared for the exclusive use of DelMar
Operating, Inc. The data, work papers, and maps used in this
report are available for examination by authorized parties in our
offices. Please contact us if we can be of further service.
Very truly yours,
RYDER SCOTT COMPANY
PETROLEUM ENGINEERS
/s/ Joseph E. Blankenship, P.E.
-------------------------------
Joseph E. Blankenship, P.E.
JEB/sw Petroleum Engineer
Approved:
/s/Joseph E. Magoto, P.E.
- -------------------------
Joseph E. Magoto, P.E.
Group Vice President
<PAGE>
EXHIBIT 99.2
March 20, 1996
Snyder Oil Corporation
Suite 2500
777 Main Street
Fort Worth, Texas 76102
Gentlemen:
In accordance with your request, we have estimated the proved
reserves and future revenue, as of December 31, 1995, to the Snyder
Oil Corporation (SOCO) interest in certain oil and gas properties
located in Colorado, Nebraska, Utah, and Wyoming as listed in the
accompanying tabulations. As requested, lease and well operating
costs do not include the per-well overhead expenses allowed under
joint operating agreements for those properties operated by SOCO.
This report has been prepared using constant prices and costs in
accordance with the guidelines of the Securities and Exchange
Commission (SEC).
As presented in the accompanying summary projections, Tables I
through IV, we estimate the net reserves and future net revenue to
the SOCO interest, as of December 31, 1995, to be:
<TABLE>
<CAPTION>
Net Reserves Future Net Revenue
------------------------ ---------------------------
Oil Gas Present Worth
Category (Barrels) (MCF) Total at 10%
- ----------------- ---------- ----------- ----------- --------------
<S> <C> <C> <C> <C>
Proved Developed
Producing 18,308,376 263,674,635 $406,194,100 $253,646,600
Non-Producing 790,450 12,055,007 17,670,000 7,679,000
Proved Undeveloped 1,907,590 42,603,423 32,743,700 9,483,800
Total Proved 21,006,416 318,333,065 $456,607,800 $270,809,400
The oil reserves shown include crude oil and condensate. Oil
volumes are expressed in barrels which are equivalent to 42 United
States gallons. Gas volumes are expressed in thousands of standard
cubic feet (MCF) at the contract temperature and pressure bases.
As shown in the Table of Contents, the properties in this
report have been subdivided into SOCO's significant property groups
behind the appropriate state tab. Included for each significant
property group are summary projec- tions of reserves and revenue for
each reserve category along with one-line summaries of reserves,
economics, and basic data by lease. For the purposes of this report,
the term "lease" refers to a single economic projection.
The estimated reserves and future revenue shown in this report
are for proved developed producing, proved developed non-producing,
and proved unde- veloped reserves. In accordance with SEC
guidelines, our estimates do not include any value for probable or
possible reserves which may exist for these properties. This report
does not include any value which could be attributed to interests in
undeveloped acreage beyond those tracts for which undeveloped
reserves have been estimated.
Future gross revenue to the SOCO interest is prior to
deducting state production taxes and ad valorem taxes. Future net
revenue is after deducting these taxes, future capital costs, and
operating expenses, but before consider- ation of federal income
taxes. In accordance with SEC guidelines, the future net revenue has
been discounted at an annual rate of 10 percent to determine its
"present worth." The present worth is shown to indicate the effect
of time on the value of money and should not be construed as being
the fair market value of the properties.
For the purposes of this report, a field inspection of the
properties has not been performed nor has the mechanical operation or
condition of the wells and their related facilities been examined.
We have not investigated possible environmental liability related to
the properties; therefore, our estimates do not include any costs
which may be incurred due to such possible liability. Also, our
estimates do not include any salvage value for the lease and well
equipment nor the cost of abandoning the properties.
Oil prices used in this report are based on a December 31,
1995 West Texas Intermediate posted price of $18.00 per barrel,
adjusted by lease for regional posted price differentials. Gas
prices used in this report are based on either the most current price
available for each lease, adjusted to a December 1995 regional spot
market price, or the contract price. Oil and gas prices are held
constant in accordance with SEC guidelines.
Lease and well operating costs are based on operating expense
records of SOCO. For non-operated properties, these costs include
the per-well overhead expenses allowed under joint operating
agreements along with costs estimated to be incurred at and below the
district and field levels. As requested, lease and well operating
costs for the operated properties include only direct lease and field
level costs. Headquarters general and administrative overhead ex-
penses of SOCO are not included. Lease and well operating costs are
held constant in accordance with SEC guidelines. Capital costs are
included as required for workovers, new development wells, and
production equipment.
We have made no investigation of potential gas volume and
value imbalances which may have resulted from overdelivery or
underdelivery to the SOCO interest. Therefore, our estimates of
reserves and future revenue do not include adjustments for the
settlement of any such imbalances; our projections are based on SOCO
receiving its net revenue interest share of estimated future gross
gas production.
The reserves included in this report are estimates only and
should not be construed as exact quantities. They may or may not be
recovered; if recovered, the revenues therefrom and the costs related
thereto could be more or less than the estimated amounts. The sales
rates, prices received for the reserves, and costs incurred in
recovering such reserves may vary from assumptions included in this
report due to governmental policies and uncertain- ties of supply and
demand. Also, estimates of reserves may increase or decrease as a
result of future operations.
In evaluating the information at our disposal concerning this
report, we have excluded from our consideration all matters as to
which legal or accounting, rather than engineering and geological,
interpretation may be controlling. As in all aspects of oil and gas
evaluation, there are uncer- tainties inherent in the interpretation
of engineering and geological data; therefore, our conclusions
necessarily represent only informed professional judgments. The
titles to the properties have not been examined by Netherland, Sewell
& Associates, Inc., nor has the actual degree or type of interest
owned been independently confirmed. The data used in our estimates
were obtained from Snyder Oil Corporation, other interest owners,
various operators of the properties, and the nonconfidential files of
Netherland, Sewell & Associates, Inc. and were accepted as accurate.
We are independent petroleum engineers, geologists, and
geophysicists; we do not own an interest in these properties and are
not employed on a contingent basis. Basic geologic and field
performance data together with our engineering work sheets are
maintained on file in our office.
Very truly yours,
/s/ Clarence Netherland
RKG:LCD
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