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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
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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, 1996
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
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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 X 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 10, 1997................................$482,325,221
Number of shares of common stock outstanding as of March 10, 1997....31,268,557
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,
1997.
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<PAGE>
SNYDER OIL CORPORATION
ANNUAL REPORT ON FORM 10-K
DECEMBER 31, 1996
PART I
ITEMS 1 AND 2. BUSINESS AND PROPERTIES
GENERAL
Snyder Oil Corporation (the "Company") is engaged in the development,
acquisition and exploration of oil and gas properties primarily in the Rocky
Mountain region of the United States and the Gulf of Mexico. The Company is also
engaged in international exploration and production, primarily through
affiliates. During 1996, consolidated revenues were $292.4 million and cash flow
provided by operations approximated $101.7 million. At December 31, 1996, the
Company's net proved reserves totaled 141.4 million barrels of oil equivalent
("BOE"), having a pretax present value at 10% based on constant prices ("Pretax
PW 10% Value") of $1.2 billion. Approximately 71% of the reserves are natural
gas.
During 1996, the Company completed the repositioning begun in 1995 in
response to dramatic deterioration of Rocky Mountain gas markets. During the
year, the Company has concentrated investment in its growing core areas,
primarily in the Gulf of Mexico, added industry partners in major gas
development projects in the Rockies, disposed of nearly all remaining non-core
properties and consolidated its Wattenberg properties with those of another
major producer in the area to create Patina Oil & Gas Corporation ("Patina"), a
separately-managed New York Stock Exchange listed company. The Company's
investment in Patina should allow the Company to benefit from efficiencies
arising out of the combination of the two largest producers in this field, while
affording the Company a range of financial options in the future. The Company
also made significant progress in strengthening its organization and
administrative systems to ensure that it can deal with its expected growth in a
more efficient and timely manner.
As a result, the Company's domestic operations, excluding its
investment in Patina, are focused on three areas, all of which have the
potential to contribute significantly to future growth. These areas include:
o The Gulf of Mexico, where 1997 efforts will be concentrated on further
development in the Main Pass area, including construction of facilities
for a major discovery and exploring the potential of other operated
fields through drilling based on 3-D seismic.
o The Rocky Mountain region in Wyoming, Colorado and Utah, where the
Company expects to expand development of its three major gas projects
in the Washakie, Deep Green River and Piceance Basins, begin
exploratory drilling on two potentially significant gas projects in the
Wind River and Big Horn Basins and further test the development
potential of its oil projects in the Uinta Basin.
o North Louisiana, where the 3-D seismic program to survey a portion of
the Company's position of approximately 600,000 gross acres will be
expanded. The Company expects to commence exploratory drilling in late
1997.
The Company expects to increase its development and exploratory
expenditures to $112 million for 1997, up from $51 million, excluding
acquisitions, during 1996. Approximately $85 million is expected to be spent for
development drilling programs, $19 million for expanded exploratory activity and
$8 million for gas facilities and other activities. In total, the Company
expects to drill 124 wells domestically, up from 85 wells in 1996. Approximately
$48 million is targeted for continued development in the Gulf of Mexico, $38
million for expanded development of its major Rocky Mountain projects, and $2
million for additional leasing and seismic costs in North Louisiana.
Internationally, the Company tendered its interest in its Australian
affiliate for 16.2 million shares (approximately 9.6% of the outstanding shares)
of Cairn Energy plc ("Cairn"), realizing a pretax gain of $65.5 million and
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retaining a significant investment in a company positioned to become a major gas
provider to the developing Indian Subcontinent. In Mongolia, where an affiliate
holds over 10 million acres, two wells were drilled, one of which resulted in a
second discovery. Ten wells were drilled in Russia, resulting in that venture
increasing production to over 3,500 barrels per day. Near year end, the Company
entered into an agreement with an international oil company that will fund the
initial well on a prospective block offshore Thailand, while permitting the
Company to retain a significant interest in the block. As the pace of
international activity is accelerating, the Company is pursuing plans for an
offering of its primary operating international subsidiary on a major
international stock exchange to enhance the value of these investments to the
Company's shareholders by establishing an independent valuation in an
appropriate market.
DOMESTIC OPERATIONS
GENERAL. During 1996 the Company greatly increased the focus and
balance of its domestic operations by investing capital primarily in its core
operating areas and selling its remaining non-core assets. In Wattenberg, which
represents over 50% of the Company's consolidated reserves, the Company formed
Patina to combine the Company's properties with those of Gerrity Oil & Gas
Corporation. Patina is a separately managed, New York Stock Exchange traded
company that is 74% owned by the Company. Nearly all non-core properties were
sold by the end of the year, with the Company's remaining domestic properties
now concentrated in three operating divisions:
o The Offshore Division holds interests in producing fields and
prospective blocks in the Gulf of Mexico. As the result of three major
acquisitions and a significant discovery near year end, this Division
increased its proved reserves to 17.4 million BOE at year end (up from
3.6 million BOE at year end 1995), representing 12% of consolidated
year end reserves.
o The Rocky Mountain Division, which consists of two operating groups.
The Major Gas Properties Group includes three major gas development
programs, one mature gas field and two potentially large gas
development projects on which initial drilling is expected to begin
this year. The Rockies Group's properties include two large, mature
non-operated oil fields in northern Wyoming and a potentially large oil
development project in the Uinta Basin. This Division's properties,
located in Wyoming, western Colorado and Utah, had proved reserves of
50.3 million BOE at year end (essentially unchanged from year end
1995), representing 36% of consolidated year end reserves.
o The Southern Division, whose most significant remaining holding is over
300,000 gross mineral acres, with leases and lease options covering an
equivalent position, in North Louisiana. A number of prospects have
been identified through 2-D seismic and as a result of a 3-D seismic
program during 1996, and it is likely that at least one well will be
commenced by the end of 1997. The majority of the producing properties
of the Southern Division, including its properties in the Austin Chalk
Trend in Texas, were sold during 1996.
Summary information at December 31, 1996 regarding the Company's major domestic
projects is set forth in the following table.
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<TABLE>
<CAPTION>
PROVED RESERVE QUANTITIES
NET ------------------------------------- PRETAX PW 10% VALUE
PRODUCING UNDEVELOPED CRUDE OIL NATURAL OIL ----------------------
WELLS ACRES & LIQUIDS GAS EQUIVALENT AMOUNT PERCENT
--------- ----------- --------- -------- ---------- ---------- -------
(MBbl) (MMcf) (MBOE) (000)
<S> <C> <C> <C> <C> <C> <C> <C>
Offshore Division
Main Pass Area 15 8,553 1,570 86,238 15,943 $ 236,349 19%
Other 26 0 851 3,717 1,470 8,488 1
Major Gas Properties
Washakie (WY) 154 75,726 1,144 133,101 23,327 147,880 12
Piceance (CO) 70 44,355 118 32,170 5,479 39,045 3
Deep Green River (WY) 10 43,309 175 21,717 3,794 27,973 2
Wind River Basin (WY) 27 65,577 235 21,151 3,760 15,376 1
Big Horn Basin (WY) 0 80,550 0 0 0 0 0
Rockies Properties
Northern Wyoming (WY) 932 787 12,083 531 12,172 76,938 6
Uinta Basin (UT) 127 79,899 1,152 3,861 1,795 9,042 1
Southern Division
North Louisiana (LA) 96 (a) 318,090 (b) 40 2,715 492 6,615 1
----- ------- ------ ------- ------- ---------- ----
Total Major Projects 1,457 716,846 17,368 305,201 68,232 567,706 46
Other 117 78,587 654 3,776 1,286 10,501 1
----- ------- ------ ------- ------- ---------- ----
Total SOCO 1,574 795,433 18,022 308,977 69,518 578,207 47
Patina (CO) 3,602 (c) 141,713 22,475 296,659 71,918 648,797 53
----- ------- ------ ------- ------- ---------- ----
Company consolidated 5,176 937,146 40,497 605,636 141,436 $1,227,004 100%
===== ======= ====== ======= ======= ========== ====
<FN>
(a) Includes royalty interests in 82 wells.
(b) Does not include 225,000 net acres under option.
(c) Includes royalty interests in 195 wells.
</FN>
</TABLE>
SOCO OFFSHORE
During 1996, the Company acquired the remaining stock interest in
DelMar Petroleum, Inc., now named SOCO Offshore, Inc. With three large
acquisitions of interests in its major properties and a major discovery, the
Company has accomplished its goal of creating a significant presence in the Gulf
of Mexico. The Offshore Division contributes a significant portion of the
Company's reserves and production, with the potential to rapidly increase its
contribution in the future as the major discovery comes on production and
pipeline constraints are eliminated. The Company believes that many properties
in the Gulf of Mexico have, and will continue to be, under-exploited and that,
while offshore operations have greater risks than the Company's Rocky Mountain
operations, the potential benefits and exposure to Gulf Coast markets will
compliment the Company's Rocky Mountain activities and result in significant
benefits to the Company.
By year end, the Offshore Division had proved reserves of 2.4 million
barrels of oil and 90 Bcf of gas (17.4 million BOE), up from 748,000 barrels of
oil and 16.3 Bcf (3.5 million BOE) at year end 1995. Acquisitions accounted for
7.8 million BOE of this increase, and the discovery of the Ingrid Field in Main
Pass Block 261 accounted for 6.3 million BOE. At year end the Offshore Division
had interests in 41 (15.2 net) wells, 35 (14.1 net) of which were operated by
the Company, and held interests in 103,000 (43,600 net) acres. December 1996 net
production averaged 7,250 BOE per day, up from 1,100 BOE per day in December
1995. As the result of an acquisition at the end of the year, the Division's net
daily production has reached 10,000 BOE per day.
During 1997, the Gulf of Mexico will continue to be a major focus for
the Company. Capital expenditures are expected to total $45 to $50 million,
including $20.7 million to install platforms and related facilities, $8.9
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million to drill three development wells and $16.2 million to drill eight
exploratory wells, primarily on existing projects. In addition, the Company will
continue its acquisition efforts in the area, including acquisitions of
additional interest in its existing properties, and will continue to evaluate
its existing properties for additional development or exploratory potential.
The largest project, comprising the Pabst and Busch Fields in Main Pass
Blocks 255 and 259, is in the Main Pass/Viosca Knoll area offshore Mississippi.
The Offshore Division owns interests in 10 lease blocks in the project area and
operates two platforms there. During 1996, additional interests in these Fields
were acquired from three joint venture partners, increasing the Company's
ownership from 12% to 60%. Four wells were successfully completed, and three
successful workovers were completed. One dry hole was drilled. By year end,
SOCO's proved reserves in these Fields totaled 52.1 Bcf of gas and 932,000
barrels of oil (9.6 million BOE), representing 55% of SOCO Offshore's total
proved reserves. In 1997, the Offshore Division will continue to evaluate 3-D
seismic data to evaluate these blocks for additional exploratory or development
potential, with plans to commence two development wells during the year.
During the year, the Offshore Division successfully generated and
drilled two exploratory wells, resulting in the discovery of the Ingrid Field,
on farm-in acreage in Main Pass Block 261, just west of the Pabst and Busch
Fields. Initial proved reserves assigned to the Company's 50% interest in the
Field were 34.1 Bcf of gas and 638,000 barrels of oil (6.3 million BOE) at year
end. During 1997, the Company will begin installation of a platform and
production facilities, with production initially expected to total 100 MMcf per
day (37 MMcf per day net to the Company's interest) and to commence in early
1998. Full development of the Field, including four productive reservoirs
already discovered, as well as additional prospects, is expected to require at
least four additional wells. Two additional exploratory wells are expected to
commence during 1997.
Limited pipeline capacity has constrained production in the Main
Pass/Viosca Knoll area. The Pabst and Busch Fields are capable of producing over
160 MMcf per day, but are currently producing approximately 100 MMcf per day due
to pipeline constraints. The Company is negotiating with several pipelines to
alleviate these constraints and to provide additional capacity to transport
production from the Ingrid Field. Based on the proposals received, management
expects to be able to secure arrangements that will increase capacity
sufficiently to transport its production by late 1997 or early 1998.
The Offshore Division also has interests in several other operated
field areas in the Gulf of Mexico, with the Company's interest often exceeding
40%. During 1997, the Company will continue to evaluate these blocks for
additional development or exploratory potential using recently acquired 3-D
seismic data. Up to four exploratory wells could be drilled in 1997 to test
these prospects, including one well that commenced drilling in February at High
Island 208 offshore Texas. The Company also signed a farm-in agreement in late
1996 that will allow the Company to acquire a 50% interest in two suspended
wells and a significant exploratory prospect in South Timbalier 231. A platform
will be installed during the year to produce the suspended wells, and the
initial exploratory well should commence in early 1998.
MAJOR GAS PROJECTS
During 1996, the Company, while maintaining a modest drilling schedule
in view of low prices prevailing during the first ten months of the year, made
significant strides in positioning its Rocky Mountain properties for long term
growth. Significant interests were sold to industry partners in two major gas
projects. The sales will allow expanded development of these Company-operated
projects, while limiting the Company's capital requirements. In January 1997,
the Company sold a one-half interest in two additional potentially large-scale
gas projects on which initial drilling is scheduled for 1997. The Company also
entered into an alliance with subsidiaries of Coastal Corporation ("Coastal")
whereby the Company's gas production throughout most of the region will be
pooled with that of other producers and marketed by Coastal Gas Marketing
Company ("CGM") affording greater efficiency and the opportunity to share in the
value associated with downstream sales of gas. As part of the venture, most of
the Company's gas facilities were placed under common management with those of
Coastal Field Services Company through the formation
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of Great Divide Gas Services, LLC ("Great Divide"), allowing more efficient
management and greater direction of future expansion.
WASHAKIE BASIN. Since the mid-1980's, the Company's properties in the
Barrel Springs Unit, the Blue Gap Field and the North Standard Draw area of the
Washakie Basin in southern Wyoming, together with its gas gathering and
transportation facilities there, have been one of its most significant assets.
During 1996, the Company continued to develop Mesaverde sands in the Washakie
Basin near its existing properties. Twelve wells were put on sales in 1996 at
depths ranging from 8,000 to 11,500 feet, developing net proved reserves of 1.4
million BOE. Three wells were in progress at year end. Net production of gas,
which accounts for approximately 95% of the reserves, during the year averaged
25.5 MMcf per day, as compared to average 1995 production of 22.9 MMcf per day.
Proved reserves at year end totaled 1.1 million barrels of oil and 133.1 Bcf of
gas, or 23.3 million BOE, as compared to 1.1 million barrels and 105 Bcf, or
18.6 million BOE, at the end of 1995. This increase in reserves is primarily
attributable to increased gas prices at year end 1996 and extensions of the
field. The Company expects to accelerate its activity in this area in 1997, with
plans to drill 25 wells at costs ranging from $500,000 to $600,000 per well.
The Company currently operates 128 wells in this area and holds
hundreds of potential drilling locations, 66 of which were classified as proved
undeveloped at year end 1996. The Company holds interests in approximately
97,000 gross (76,000 net) undeveloped acres in the Washakie Basin.
DEEP GREEN RIVER. Through the year, the Company continued development
of the fluvial Lance sands in the deep portion of the Green River Basin. The
Company participated in eight wells during 1996, with two wells in progress at
year end. Despite the sale of a 50% interest in the project to Amoco Production
Company in the middle of the year, year end proved reserves totaled 175,000
barrels of oil and 21.7 Bcf of gas, or 3.8 million BOE, as compared to 107,000
barrels of oil and 15.9 Bcf of gas, or 2.8 million BOE, at year end 1995. This
increase in reserves is primarily attributable to extensions of the field and
increased gas prices at year end 1996. With 10 wells, six of which are operated
by the Company, on sales at year end, net production averaged 832 BOE per day
during 1996. The Company holds interests in approximately 95,000 gross (43,000
net) undeveloped acres in this project. At the end of 1996, proved undeveloped
reserves were assigned to 17 locations. During 1996, the Company participated in
a 51 square mile 3-D seismic survey that should allow high-grading of future
drilling locations. The Company expects to participate in drilling up to 21
wells in 1997. Further expansion of drilling in this area is awaiting regulatory
approval after preparation of an environmental impact statement, which is
expected to be approved by mid-1997. Assuming the approval is granted, the
Company expects to participate in drilling 25 to 30 wells per year after 1997.
The primary objective of drilling is the stacked, fluvial sands of the Lance
formation.
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. During the year, a 45% interest in this
project was sold to Destec Energy Inc. At year end, the Company owned
approximately 99,000 gross (44,000 net) undeveloped acres in this area. During
1996, the Company participated in 21 new wells to develop and further delineate
the fields. Twenty-two wells (including two in progress at the beginning of the
year) were put on sales, and one was in progress at year end. Net production
averaged 9.7 MMcf per day in 1996, down from 1995 average production of 11.9
MMcf per day as a result of the sale of a 45% interest in the project. At year
end 1996, there were 70 producing wells, 55 of which are operated by the
Company. Proved reserves at year end were 32.2 Bcf of gas and 118,000 barrels of
oil, or 5.5 million BOE, as compared with 42.6 Bcf and 145,300 barrels, or 7.2
million BOE, at year end 1995. The decrease in reserves is primarily the result
of the sale to Destec, partially offset by extensions of the field and increased
gas prices at year end 1996. Proved undeveloped reserves were assigned to 37
locations at year end 1996.
During 1997, the Company plans to drill 23 wells to further develop the
Company's acreage positions and evaluate the fields. An expanded development
effort might be warranted if additional transportation arrangements can be made
and gas prices stabilize at acceptable levels. The primary objective of drilling
is the stacked, fluvial sands of the Mesaverde formation at depths of 4,500 to
8,500 feet.
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WIND RIVER AND BIG HORN BASINS. 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 1996, proved reserves,
nearly all gas, totaled 3.8 million BOE. The Company operates 27 wells having
net production of approximately 1,000 BOE per day. Production from this field is
processed at a Company-owned plant.
The Company has assembled approximately 65,000 (63,000 net) undeveloped
acres in an area east of the 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 toward the east and north of
the Riverton Dome Field. In January 1997, the Company sold a 50% interest in a
portion of this project, which targets various Cretaceous sands at depths of
8,500 to 12,500 feet, to Belco Oil & Gas. The Company expects to drill two wells
during 1997, with the first well expected to commence in the second quarter.
In the Big Horn Basin, northwest of the Worland Field, the Company has
assembled approximately 120,000 gross (81,000 net) undeveloped acres. Belco also
agreed to participate in this project, which also targets Cretaceous sands at
depths of 9,500 to 12,000 feet. The first well was commenced in January 1997.
GREAT DIVIDE. The Company owns over 225 miles of pipeline systems which
transport gas from the Company's properties in the Washakie Basin and Piceance
Basin. Effective January 1, 1997 the Company and Coastal Field Services Company,
a subsidiary of Coastal, formed Great Divide to combine the operations of
approximately 200 miles of pipelines owned by the Company with over 400 miles of
Coastal systems in the Uinta, Washakie and Wind River Basins. Great Divide,
which is 27% owned by the Company and will be jointly managed by its two
shareholders, has combined assets of more than 600 miles of nonjurisdictional
pipelines, connecting 650 natural gas wells producing approximately 165 MMcf per
day. Great Divide will oversee the future expansion of gas pipelines and related
facilities within six areas of mutual interest in Wyoming, Colorado and Utah.
Also effective January 1, 1997, the Company entered into a gas sales
agreement and gas marketing agreement with CGM, another subsidiary of Coastal,
to pool the Company's and and other producers' gas supplies in the Rocky
Mountain region. The initial supply pool is expected to exceed 100 MMcf per day,
with over half the supply provided by the Company. The Company will sell its gas
to CGM based on agreed market index prices and will share in the margin earned
by CGM on downstream sales of the gas, based in part on the portion of the pool
represented by Company gas. CGM and the Company will also evaluate commitments
for firm transportation or longer term contracts, with commitments requiring
joint agreement.
The Company expects the joint venture to result in efficiencies in
operating and managing their pipeline facilities, as well as creating greater
focus for future expansion in the region. In addition, the Company hopes that
the pooling of gas supplies and the expertise of Coastal, one of North America's
largest gas marketers, will result in greater downstream marketing
opportunities. Both the Company and Coastal intend to encourage other Rocky
Mountain producers to join the joint venture, which would further increase the
venture's potential to become a significant developer of facilities and marketer
in the Rocky Mountain region.
OTHER ROCKIES PROJECTS
UINTA BASIN. In the Uinta Basin, the Company holds interests in
approximately 115,000 gross (80,000 net) acres. During 1996, the Company
participated in drilling only one non-operated well in the Basin as efforts were
focused on acquiring and analyzing 3-D seismic data and implementing two pilot
waterflood projects in its Green River oil projects. A pilot waterflood in the
Leland Bench Field was commenced during the third quarter, with initial response
expected to occur early in the second half of 1997. Depending on the response,
development should begin in the second half of 1997. A second pilot project, in
the Horseshoe Bend Field, is awaiting regulatory approval and should commence in
mid-1997. The ultimate success of these projects will be influenced by the
response of the pilot projects and the ability to select locations and enhance
waterflood efforts through the use of 3-D seismic data. The projects are also
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sensitive to oil prices. During the last half of 1996, oil prices, which had had
historically been at a premium to West Texas Intermediate prices, deteriorated
and now trade at a significant discount to such prices. As a result, 1997
activities have been reduced, with plans to drill only five wells during 1997.
During 1996, net production from the Basin averaged 290 barrels of oil
and approximately 1,255 Mcf of gas per day, as compared to 325 barrels and 1,377
Mcf per day during 1995. At year end, the Company had interests in 127 producing
wells, 76 of which were operated by the Company. Proved reserves at year end
were 1.2 million barrels of oil and 3.9 Bcf of gas, or 1.8 million BOE, as
compared to 1.6 million barrels and 3.8 Bcf, or 2.2 million BOE, at the end of
1995. The decreases are primarily the result of production and sales during the
year, as there was no significant development activity. Gas reserves increased
primarily as the result of revisions resulting from higher prices prevailing at
year end.
NORTHERN WYOMING. The Company holds significant interests in two large,
mature oil fields in Northern Wyoming, the Hamilton Dome and Salt Creek Fields.
In late 1996, the Company unitized the Hamilton Dome Field to achieve common
ownership of all producing horizons across the Field. Unitization resulted in an
immediate net production increase to the Company of 140 barrels of oil per day
and is expected to allow the current operator to decrease operating costs due to
efficiencies and to proceed with an expansion of the existing waterflood and
accelerate recompletions. At year end, proved reserves at these Fields totaled
12.2 million BOE, including 12.1 million barrels of oil and 531 MMcf of gas, up
from 10.9 million BOE (10.8 million barrels and 455 MMcf) at the end of 1995.
This increase was the result of upward revisions, primarily caused by higher
product prices as well as increases resulting from the unitization of Hamilton
Dome. Hamilton Dome produces sour crude oil primarily from the Tensleep, Madison
and Phosphoria formations at depths of 2,500 to 5,500 feet. Salt Creek produces
sweet crude oil from the Wall Creek formation at depths of 2,000 to 2,900 feet.
NORTH LOUISIANA
The Company owns over 300,000 gross mineral acres, with leases and
lease option agreements covering an equivalent position, in north Louisiana and
also owns overriding royalty interests in approximately 95 producing wells. The
Company also has access to a database of more than 5,000 miles of 2-D seismic
data and in 1996 joined with two partners to shoot a 48 square mile 3-D seismic
survey covering a portion of its acreage. The results of this survey, which
targeted potential significant reef structures in the Cotton Valley formation,
were encouraging, and the partners have commenced a 110 square mile survey to
the west of the previous survey. The Company has identified a number of reef
prospects that will be imaged by the survey, which should be completed during
the second half of 1997. These surveys are being shot at no cost to the Company,
which will retain a 25% to 50% interest in the prospect areas. One well is
expected to be commenced by the end of 1997.
PATINA OIL & GAS CORPORATION
During 1996 the Company implemented a significant restructuring of its
Wattenberg Field assets by creating Patina. The Company formed Patina to hold
its properties in the Wattenberg Field and to facilitate the acquisition of
Gerrity Oil & Gas Corporation. In May 1996, the consolidation was completed. At
year end, the Company owned 14 million, or 74%, of Patina's common shares. The
Company has thus transformed its working interest in the Field to a controlling
interest in the largest producer in the Field. At December 31, 1996, Patina held
interests in over 3,600 wells in Wattenberg with net proved reserves of
approximately 71.9 million BOE, approximately 70% of which were attributable to
natural gas. Based on unescalated year end oil and gas prices, these reserves
had a pretax PW 10% Value of $648.8 million.
The Wattenberg Field is located approximately 35 miles north of Denver
in the Denver-Julesburg Basin. One of the most attractive features of Wattenberg
is that there are several productive formations. Three of the formations, the
Codell, Niobrara and J-Sand, are "blanket" zones in the area of Patina's
Wattenberg holdings, while others, such as the D-Sand, Dakota and the shallower
Shannon and Sussex, are more localized. Drilling in Wattenberg is low risk
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from the perspective of encountering hydrocarbons with better than 95% of the
wells drilled being completed as producers. Consequently, the Field's economic
attractiveness is primarily dependent on energy prices, the reservoir
characteristics of the specific area of the Field being drilled and the
operator's ability to minimize capital and operating costs.
Over the past five years, Patina and its predecessors have drilled over
1,500 wells in Wattenberg. Given Patina's experience in drilling and completing
wells of this type, combined with an operating base encompassing approximately
3,200 active wells, Patina believes it can drill and operate its oil and gas
properties in the Field at a lower cost than its competitors. Furthermore,
because virtually all of the wells in which it holds an interest lie within a 40
mile radius, Patina believes it has the potential to become one of the most
efficient oil and gas producers in the United States.
As of December 31, 1996, Patina had 728 proved undeveloped locations
and 605 proved behind pipe recompletion opportunities. While this inventory
provides the ability to expand development activities should drilling and
completion technologies improve or the recent recovery in Rocky Mountain natural
gas prices continues, a significant portion of Patina's proved undeveloped
locations are projected to provide rates of return below the level judged
attractive by its management based on projected commodity prices and reserve
recoveries.
During 1996, Patina focused on combining the operations of its
predecessors, reducing costs and identifying attractive projects for further
development. Only $8.5 million was spent on development and acquisitions,
allowing Patina to use the bulk of its cash flow to reduce senior debt (to $94.5
million at year end as compared to $116.3 million at June 30, 1996) and
repurchase securities. In 1997, Patina, at least for the present, expects to
limit its capital expenditures on existing properties to approximately $14
million. As a result, management believes funds generated from operations should
permit a continued paydown of debt, additional security repurchases or the
pursuit of further consolidation or acquisition opportunities.
As with all its investments and properties, the Company evaluates its
position in Patina from time to time and assesses alternatives to increase value
to the Company and its shareholders. A number of alternatives concerning Patina
are available to the Company, including maintaining its investment, selling all
or part of its investment, either in one transaction or gradually, distributing
all or part of its investment to its shareholders or acquiring all of, or an
increased interest in, Patina. Any decision, when made, will be made in light of
strategic, financial and other factors deemed appropriate by management.
INTERNATIONAL ACTIVITIES
The Company's strategy internationally has been 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. SOCO International, in turn, owns 90% of two
subsidiaries, SOCO International Holdings, Inc. ("Holdings"), which owns shares
of Cairn, as discussed below, and SOCO International Operations, Inc.
("Operations"), which holds all other international investments. In December
1996, Edward T. Story, the President of SOCO International and a Vice President
and director of the Company, exercised an option to acquire the remaining 10%
interest in these companies.
As the pace of international activity is accelerating, the Company is
pursuing plans for an offering of Operations on a major international stock
exchange. The offering is intended to enhance the value of Operations'
international projects to the Company's shareholders by establishing an
independent valuation in an appropriate market. If the necessary agreements can
be concluded, the offering could occur as early as the second quarter of 1997.
CAIRN. In the fourth quarter of 1996, Cairn, a Scotland-based
exploration and production company traded on the London Stock Exchange, agreed
to acquire Command Petroleum Limited, an Australian company that was 32.6%
8
<PAGE>
owned by SOCO International, in exchange for Cairn stock. As a result, SOCO
International tendered its shares in Command for 16.2 million shares of Cairn
(approximately 9.6% of the outstanding shares), realizing a pretax gain of $65.5
million. Cairn holds oil and gas interests in several countries, with a primary
focus in the Bay of Bengal offshore Bangladesh, where it recently announced a
major gas discovery. Cairn's position offshore Bangladesh, where it has
identified additional prospects with significant exploratory potential, together
with Command's interest in the Ravva Field offshore India, poise Cairn to make a
major contribution to the development of oil and gas resources in the developing
Indian Subcontinent. Although the potential of Cairn's major exploratory
prospects, and thus the ultimate value of the Company's investment in Cairn,
remains unknown, Cairn's prospects have been well received, resulting in the
value of the Company's investment increasing from $95 million to over $130
million in February 1997. During February and March 1997, the Company sold 4.5
million shares of Cairn at an average price of $8.81 per share, realizing
proceeds of $39.2 million, which was applied to repay SOCO International's debt
to the Company. The remaining 11.7 million shares had a market value exceeding
$100 million on March 6, 1997. The Company presently intends to remain a
significant shareholder in Cairn, although it may elect to liquidate its
holdings as Cairn's future potential is realized and market conditions warrant.
RUSSIA. 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 52 million barrels of oil at year end (8.6 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. Twenty-one wells (10 of which were
drilled in 1996) have been placed on production, and are currently producing
from 3,500 to 4,000 barrels per day, up from a peak of 2,500 in 1995. During
1996, the joint venture produced approximately 776,000 barrels of oil, with all
production (other than oil in transit) being exported and sold on the world
market. Drilling activity has been slower than anticipated due to difficulties
in securing drilling contracts on commercially reasonable terms. During 1997,
the Company expects to drill 11 wells using Russian rigs.
The Company has continued to fund its share of capital costs through
sales of equity in SOCO Perm. In 1996, the Company concluded the sale of 15% of
SOCO Perm's equity for $10 million. This sale decreased the Company's interest
in SOCO Perm to approximately 35%. This sale required SOCO Perm to list its
common shares on a securities exchange no later than 1998 or the investors have
the right to require the Company to purchase their shares at a formula price.
The proposed offering of Operations' shares is expected to satisfy this
requirement. 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-1997.
MONGOLIA. SOCO Tamtsag Mongolia, Inc. ("SOCO Tamtsag"), a 42% owned
affiliate of SOCO International, holds over 10 million acres covering the entire
Tamtsag Basin of northeastern Mongolia. These concessions are located between
the Hailar and Erlian Basins of China. The Company has also acquired 2,700
kilometers of seismic data in the Basin. During 1996, two exploratory wells were
drilled and a second discovery was logged. Although production from the two
discovery wells is not expected to be significant, SOCO Tamtsag's activities
established the existence of productive sands across broad areas of the Basin.
SOCO Tamtsag intends to drill four wells during 1997, including the SOTAMO 21-2,
which began drilling in January.
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.
9
<PAGE>
CNUOC is a joint venture between China National Petroleum Corporation and
SINOCHEM, both state-owned entities. In early 1997, SOCO Tamtsag exported its
first shipment of oil to China, successfully testing the marketing arrangements.
THAILAND. In 1995, SOCO International acquired the 150,000 acre Block
B4/32 concession in the Gulf of Thailand. During 1996, SOCO International was
awarded Block B8/38. In late 1996, SOCO International reached an agreement with
a Malaysian-based international oil company which will fund the drilling of an
exploration well on Block B8/38. SOCO International will retain a 42.5% interest
in Blocks B8/38 and B4/32. The initial well is scheduled to begin in the second
quarter of 1997, and a second well on Block B8/38 may be drilled by the end of
the year.
VIETNAM. In late 1994, SOCO International 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. The Company expects a decision on the award in
mid-1997.
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, 1996. Proved
reserves of 8.6 million BOE with a PW 10% value of $25.8 million assigned to
SOCO International projects in Russia are not included in the table.
<TABLE>
<CAPTION>
DECEMBER 31,
------------------------------------------
1994 1995 1996
-------- -------- --------
<S> <C> <C> <C>
Crude oil and liquids (MBbl)
Developed 26,104 21,637 31,869
Undeveloped 8,873 2,610 8,628
------- ------- ------
Total 34,977 24,247 40,497
======= ======= ======
Natural gas (MMcf)
Developed 353,930 330,524 443,441
Undeveloped 157,321 65,194 162,195
------- -------- -------
Total 511,251 395,718 605,636
======= ======== =======
Total MBOE 120,186 90,200 141,436
======= ======== =======
</TABLE>
The following table sets forth pretax future net revenues from the
production of proved reserves and the Pretax PW 10% Value of such revenues.
<TABLE>
<CAPTION>
DECEMBER 31, 1996
--------------------------------------------------------
(In thousands) DEVELOPED UNDEVELOPED(a) TOTAL
---------- -------------- ----------
<S> <C> <C> <C>
1997 $ 248,683 $ (20,275) $ 228,408
1998 207,527 31,034 238,561
1999 164,789 38,767 203,556
Remainder 1,049,753 409,368 1,459,121
---------- --------- ----------
Total $1,670,752 $458,894 $2,129,646
========== ========= ==========
Pretax PW 10% Value (b) $1,023,125 $203,879 $1,227,004
========== ========= ==========
<FN>
(a) Net of estimated capital costs, including estimated costs of $34.1 million
during 1997.
(b) The after tax PW 10% value of proved reserves totaled $938.6 million at
year end 1996.
</FN>
</TABLE>
10
<PAGE>
The quantities and values shown in the preceding tables are based on
prices in effect at December 31, 1996, averaging $24.47 per barrel of oil and
$3.59 per Mcf of gas. Year end gas prices, although typically higher than prices
prevailing through most of a calendar year, were at or near all time highs and
significantly higher than prices prevailing throughout most of 1996. Prices for
both oil and gas have fallen since year end, partially as the result of
decreased demand associated with warm weather. 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 collectivelyrepresent 99% of
Pretax PW 10% Value as of December 31, 1996. Approximately 85% was estimated
independently by NSAI and 14% 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.
11
<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, 1996.
<TABLE>
<CAPTION>
1992 1993 1994 1995 1996
---------- ---------- ---------- ---------- ---------
(Dollars in thousands, except prices and per barrel equivalent information)
<S> <C> <C> <C> <C> <C>
Production
Oil (MBbl) 1,776 3,451 4,366 4,278 3,884
Gas (MMcf) 23,090 35,080 43,809 53,227 55,840
MBOE (a) 5,989 9,297 11,668 13,149 13,191
Revenues
Oil $ 33,512 $ 53,174 $ 64,625 $ 72,550 $ 79,201
Gas (b) 43,851 71,467 73,233 72,058 110,126
-------- -------- -------- -------- --------
Subtotal 77,363 124,641 137,858 144,608 189,327
Transportation, processing
and marketing 38,611 94,839 107,247 38,256 17,655
Other 2,996 9,372 17,223 19,296 85,432
-------- -------- -------- -------- --------
Total $118,970 $228,852 $262,328 $202,160 $292,414
-------- -------- -------- -------- --------
Operating expenses
Production $ 28,057 $ 41,401 $ 46,267 $ 52,486 $ 49,638
Transportation, processing
and marketing 30,469 85,640 94,177 29,374 15,020
Exploration 1,515 2,960 6,505 8,033 4,232
-------- -------- -------- -------- --------
$ 60,041 $130,001 $146,949 $ 89,893 $ 68,890
-------- -------- -------- -------- --------
Direct operating margin $ 58,929 $ 98,851 $115,379 $112,267 $223,524
======== ======== ======== ======== ========
Production data
Average sales price (c)
Oil (Bbl) $ 18.87 $ 15.41 $ 14.80 $ 16.96 $ 20.39
Gas (Mcf) (a) (b) 1.74 1.94 1.67 1.35 1.97
BOE (a) 12.92 13.41 11.82 11.00 14.35
Average production expense/BOE $ 4.68 $ 4.45 $ 3.97 $ 3.99 $ 3.76
Average production margin/BOE $ 8.24 $ 8.96 $ 7.85 $ 7.01 $ 10.59
<FN>
(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, 1996 were approximately $3.59 per Mcf of gas and $24.47 per barrel of
oil.
</FN>
</TABLE>
12
<PAGE>
PRODUCING WELLS
The following table sets forth certain information at December 31, 1996
relating to the producing wells in which the Company owned a working interest.
The Company also held royalty interests in 277 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 4,132 2,924 71%
Natural gas 1,044 721 69%
----- ------ ---
Total 5,176 3,645 70%
===== ===== ===
</TABLE>
ACREAGE
The following table sets forth certain information at December 31, 1996
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) 359,000 236,000
Undeveloped (b) 1,322,000 937,000
--------- ---------
Total 1,681,000 1,173,000
========= =========
International
Undeveloped
Russia 306,000 53,000
Mongolia 10,796,000 4,534,000
Thailand 2,520,000 1,071,000
---------- ---------
Total 13,622,000 5,658,000
========== =========
<FN>
(a) Developed acreage is acreage assigned to producing wells.
(b) The Company also held 225,000 net undeveloped acres under option in North
Louisiana.
</FN>
</TABLE>
13
<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>
1994 1995 1996
------ ------ -----
<S> <C> <C> <C>
Development wells
Productive
Gross 466.0 223.0 69.0
Net 390.6 133.1 38.9
Dry
Gross 12.0 5.0 2.0
Net 11.1 3.8 .5
Exploratory wells
Productive
Gross - - 3.0
Net - - .5
Dry
Gross 13.0 - 2.0
Net 10.5 - 1.6
</TABLE>
On December 31, 1996, the Company had 17 gross (13.1 net) development
wells and 2 gross (1.0 net) exploratory wells in progress. Between year end and
February 28, 1997, the Company spudded 19 wells. At that date, 18 gross (14.7
net) wells, including wells in progress at year end, had been completed, and 14
gross (9.8 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 1994 and 1995, Amoco Production Company accounted for
approximately 11% and 10% of revenues, respectively. In 1996, Pan Energy, which
purchases a significant portion of Patina's gas production, accounted for
approximately 11% of revenues. 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. During 1996, the volume of the Company's gas production
marketed by the Company averaged approximately 136 MMcf per day. Market
conditions in 1995 and early 1996 highlighted the need to create new market
outlets for Rocky Mountain gas. 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 1996, 61% of the Company's production was sold under
arrangements that are responsive to Rocky Mountain market conditions, and 39%
was sold in the Gulf Coast market. As described on page 6 under "Domestic
Operations - Major Gas Properties - Great Divide," effective January 1, 1997,
the Company's Rocky Mountain gas production (excluding Patina's production) is
being pooled with that of other producers and marketed by a subsidiary of
Coastal. By pooling gas supplies and using Coastal's expertise, this venture is
expected to increase opportunities for downstream marketing of the Company's
Rocky Mountain gas.
14
<PAGE>
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,
the marketing of production, in the hiring of experienced personnel and from
other industries in supplying alternative sources of energy.
Competitors in acquisitions, exploration, development, marketing 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
REGULATION OF DRILLING AND PRODUCTION. 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.
A substantial portion of the Company's oil and gas leases in the Gulf
of Mexico and in the Rocky Mountain area were granted by the U.S. Government and
are administered by two federal agencies, the Bureau of Land Management ("BLM")
and the Minerals Management Service ("MMS"). These leases are issued through
competitive bidding, contain relatively standard terms and require compliance
with detailed BLM and MMS regulations and orders (which are subject to change by
the BLM and MMS). For offshore operations, lessees must obtain MMS approval for
exploration plans and development and production plans before commencement of
operations. In addition to permits required from other agencies (such as the
Coast Guard, the Army Corps of Engineers and the Environmental Protection
Agency), lessees must obtain a permit from the BLM or MMS prior to the
commencement of onshore or offshore drilling.
State regulatory authorities have also 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. Colorado, where all Patina's properties and a portion of the Company's
properties are located, amended its statute concerning oil and gas development
in 1994 to provide the state's Oil and Gas Conservation Commission with
additional authority to regulate oil and gas activities to protect public
health, safety and welfare, as well as the environment. Several rulemakings
pursuant to these statutory changes have, or will be, undertaken by the
Commission to revise the regulation of groundwater protection, soil protection
and site reclamation and financial assurance for industry obligations in these
areas. To date, these rule changes have not adversely affected oil and gas
operations of either the Company or Patina, as the Commission is required to
enact cost-effective and technically feasible regulations. However, there can be
no assurance that, in the aggregate, these regulatory developments, or
developments in other states, will not increase the cost of conducting oil and
gas operations.
15
<PAGE>
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. In recent years, the Federal Energy Regulatory Commission
("FERC") has taken significant steps to increase competition in the sale,
purchase, storage and transportation of natural gas. Under these orders, FERC
has caused pipelines to open up access to transportation, essentially
eliminating pipelines from the role of natural gas merchant and "unbundled"
transportation services so that a buyer can purchase just those services it
needs. FERC's regulatory programs generally allow more accurate and timely price
signals from the consumer to the producer and, on the whole, have helped gas
become more responsive to changing market conditions. To date, the Company
believes it has not experienced any material adverse effect as the result of
these programs. Nonetheless, increased competition in gas markets can and does
add to price volatility and inter-fuel competition, which increases the pressure
on the Company to manage its exposure to changing conditions and position itself
to take advantage of changing market forces.
ENVIRONMENTAL REGULATIONS. The 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 remediation obligations and 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. Drilling and other projects on federal
leases may also require preparation of an environmental assessment or
environmental impact statement, which could delay the commencement of operations
and could limit the extent to which the leases may be developed.
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, and the Company does not expect that, under current regulations,
future expenditures will have a material adverse impact on the Company.
Under the Oil Pollution Act of 1990 ("OPA"), owners and operators of
onshore facilities and pipelines and lessees or permittees of an area in which
an offshore facility is located ("Responsible Parties") are strictly liable on a
joint and several basis for removal costs and damages that result from a
discharge of oil into United States waters. These damages include natural
resource damages, real and personal property damages and economic losses. OPA
limits the strict liability of Responsible Parties for removal costs and damages
that result from a discharge of oil to $350 million in the case of onshore
facilities and $75 million plus removal costs in the case of offshore
facilities, except that no limits apply if the discharge was caused by gross
negligence or wilful misconduct, or by the violation of an applicable federal
safety, construction or operating regulation by the Responsible Party, its agent
or subcontractor.
In addition, OPA requires certain vessels and offshore facilities to
provide evidence of financial responsibility. During 1996, OPA was amended to
reduce the required level of financial responsibility from $150 million to $35
million for offshore facilities and $10 million for facilities located in state
waters. OPA also requires offshore facilities to prepare facility response
plans, which the Company has done, for responding to a "worst case discharge" of
oil. Failure to comply with these requirements or failure to cooperate during a
spill event may subject a Responsible Party to civil or criminal enforcement
actions and penalties.
16
<PAGE>
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 operations. 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.
OFFICERS
Listed below are the officers and a summary of their recent business
experience.
NAME POSITION
John C. Snyder Chairman and Director
Charles A. Brown Senior Vice President-Rocky Mountain Division
Steven M. Burr Vice President-Engineering and Planning
Peter C. Forbes Vice President-Offshore
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 (55), 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 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
also serves as a director of Patina.
CHARLES A. BROWN (50), 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 (40), 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.
From 1978 to 1982, Mr. Burr was employed by Exxon Company, USA in the Production
Department. Mr. Burr received his Bachelor of Science Degree in Civil
Engineering from Tulane University.
PETER C. FORBES (51), Vice President - Gulf of Mexico, who was
appointed to that position in 1996, joined the Company as Executive Vice
President of SOCO Offshore, Inc., the Company's Gulf Coast subsidiary, in July
1995 and has been President of that company since July 1996. 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 and is a Scottish Chartered Accountant.
17
<PAGE>
PETER E. LORENZEN (47), 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.
H. RICHARD PATE (43), Vice President - 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 (43), 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 degree from Brown University and his Master of Science in
Mineral Economics from the Colorado School of Mines.
JAMES H. SHONSEY (45), 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 (53), 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 USA 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. 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, and Seaunion Holdings Limited, an oil and gas
company listed on the Hong Kong Stock Exchange.
RODNEY L. WALLER (47), 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 (44), 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.
FORWARD-LOOKING INFORMATION
Certain information included and incorporated by reference in this
Annual Report, and other materials filed or to be filed by the Company with the
Securities and Exchange Commission (as well as information included in oral
statements or other written statements made or to be made by the Company)
contain or will contain or include, forward-looking statements within the
meaning of Section 27A of the Securities Act of 1933, as amended (the
"Securities Act"), and Section 21E of the Securities Exchange Act of 1934, as
amended. Such forward-looking statements may be or may concern, among other
18
<PAGE>
things, capital expenditures, drilling activity, acquisitions and dispositions,
and conditions and transactions related thereto, development or exploratory
activities, cost savings efforts, production activities and volumes, hydrocarbon
reserves, hydrocarbon prices, hedging activities and the results thereof,
financing plans, liquidity, regulatory matters, competition and the Company's
ability to realize efficiencies related to certain transactions or
organizational changes.
All forward-looking information is based upon management's current
plans, expectations, estimates and assumptions and is subject to a number of
uncertainties and risks that could significantly affect current plans,
anticipated actions, the timing of such actions and the Company's financial
condition and results of operations. The risks and uncertainties associated with
such forward-looking statements include generally the volatility of hydrocarbon
prices and hydrocarbon-based financial derivatives prices; basis risk and
counterparty credit risk in executing hydrocarbon price risk management
activities; economic, political, judicial and regulatory developments;
developments in financial markets, both domestic and foreign; competition in the
industry, as well as competition from other sources of energy; the economics of
producing certain reserves; hydrocarbon demand and supply; the ability to find
or acquire and develop reserves of natural gas and crude oil; and the actions of
customers and competitors. As a consequence, actual results may differ
materially from expectations, estimates or assumptions expressed in any
forward-looking statements made by or on behalf of the Company.
ITEM 3. LEGAL PROCEEDINGS
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. In January 1997, the judge ordered that the class not
be certified. All remaining liability under this suit was assumed by Patina upon
its formation. In January 1996, GOG was also sued in a similar but separate
class action filed in stated court. In both suits, the plaintiffs allege that
unspecified "post-production" costs incurred prior to calculating royalty
payments were deducted in breach of the relevant lease provisions and that this
fact was fraudulently concealed. The plaintiffs seek unspecified compensatory
and punitive damages and a declaratory judgment prohibiting deduction of
post-production costs prior to calculating royalties paid to the class. The
Company believes that calculations of royalties by it and GOG are and have been
proper under the relevant lease provisions, and intends to defend these and any
similar suits vigorously.
In September 1996, the Company and other interest owners in a lease in
southern Texas were sued by the royalty owners in Texas state court in Brooks
County, Texas. The Company's working interest in the lease is approximately 20%.
The complaint alleges, among other things, that the defendants have failed to
pay proper royalties under the lease and have breached their duties to
reasonably develop the lease. The plaintiffs also claim damages for fraud and
trespass, and demand actual and punitive damages. Although the complaint does
not specify the amount of damages claimed, an earlier letter from plaintiffs
claimed damages in excess of $50 million. The Company and the other interest
owners have filed an answer denying the claims and intend to contest the suit
vigorously.
At this time, the Company is unable to estimate the range of potential
loss, if any, from the foregoing uncertainties. However, the Company believes
their resolution 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.
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 1996.
19
<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 1995 and 1996, 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>
1995 1996
----------------------- -----------------------
HIGH LOW HIGH LOW
------- ------- ------- -------
<S> <C> <C> <C> <C>
First Quarter $15-1/4 $13-1/2 $12-1/8 $ 7-1/4
Second Quarter 15-3/8 11-7/8 10-1/4 7-5/8
Third Quarter 14 10-3/4 12 9-3/8
Fourth Quarter 12-3/4 10 17-3/4 11-3/4
</TABLE>
On March 10, 1997, the closing price of the common stock was $17-3/8.
Quarterly dividends have been paid at the rate of $.065 per share during 1995
and 1996. For federal income tax purposes, 100% of common dividends paid during
1995 and 1996 were a non-taxable return of capital. The Company currently
expects that dividend payments in 1997 will be taxable for federal income tax
purposes. 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, 1996, there were approximately
2,600 holders of record of the common stock and 31.2 million shares outstanding.
20
<PAGE>
ITEM 6. SELECTED FINANCIAL DATA
The following table presents selected financial and operating
information for each of the years in the five year period ended December 31,
1996. Share and per share amounts refer to common shares. The following
information should be read in conjunction with the consolidated financial
statements presented elsewhere herein.
<TABLE>
<CAPTION>
(In thousands, except per share data) As of or for the Year Ended December 31,
------------------------------------------------------------
1992 1993 1994 1995 1996
--------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C>
INCOME STATEMENT
Revenues $ 118,970 $ 228,852 $ 262,328 $ 202,160 $ 292,414
Income (loss) before extraordinary items 14,597 22,538 12,372 (39,831) 62,950
Per share .43 .58 .07 (1.53) 1.81
Net income (loss) 14,597 19,545 12,372 (39,831) 62,950
Per share .43 .45 .07 (1.53) 1.81
Dividends per share .25 (a) .22 .25 .26 .26
Average shares outstanding 22,722 23,096 23,704 30,186 31,308
CASH FLOW
Net cash provided by operations $ 48,339 $ 68,728 $ 86,397 $ 69,121 $ 101,730
Net cash realized (used) by investing (73,645) (207,933) (245,503) 32,421 (62,356)
Net cash realized (used) by financing 21,079 129,633 169,926 (96,012) (38,715)
BALANCE SHEET
Working capital $ 7,619 $ 491 $ 708 $ 5,842 $ 9,168
Oil and gas properties, net 241,804 316,406 472,239 435,217 635,387
Total assets 331,638 453,301 673,259 555,493 879,459
Senior debt 96,568 114,952 234,857 150,001 188,231 (b)
Subordinated notes 18,750 - 83,650 84,058 183,842 (c)
Stockholders' equity 168,866 274,734 274,086 235,368 294,668
<FN>
(a) Due to revised timing, five payments were made at a quarterly rate of $.05
in 1992.
(b) Includes $93.7 million of SOCO senior debt and $94.5 million of Patina
senior debt.
(c) Includes $80.7 million of SOCO convertible subordinated notes and $103.1
million of Patina subordinated notes.
</FN>
</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) 1995
----------------------------------------------
FIRST SECOND THIRD FOURTH
------- ------- -------- --------
<S> <C> <C> <C> <C>
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)
(In thousands, except per share data) 1996
----------------------------------------------
FIRST SECOND THIRD FOURTH
------- ------- ------- ---------
Revenues $41,719 $56,768 $62,475 $131,452
Depletion, depreciation and amortization and property impairments 16,771 22,745 24,673 23,111
Gross profit 9,979 2,217 18,746 89,801
Net income (loss) 1,777 (9,983) 5,560 65,596
Per share .01 (.37) .13 2.06
<FN>
(a) Includes $24.1 million of property impairments.
</FN>
</TABLE>
21
<PAGE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
RESULTS OF OPERATIONS
COMPARISON OF 1996 RESULTS TO 1995. Total revenues for 1996 were $292.4
million, a $90.3 million increase from 1995. The increase is in large part due
to a $67.2 million increase in gains on sales of investments which is primarily
due to a $65.5 million gain recognized in the fourth quarter related to an
exchange of the Company's stock held in Command Petroleum Limited ("Command"),
an Australian affiliate, for stock in Cairn Energy plc ("Cairn"), a United
Kingdom based company. An increase in oil and gas sales of $44.7 million was
also experienced in 1996 as a result of a 31% rise in the price received per
barrel of oil equivalent ("BOE") while production remained relatively stable
compared to 1995. Natural gas prices rebounded in 1996 to $1.97 per Mcf from
$1.35 per Mcf in 1995, a 46% increase. Oil prices improved 20% to average $20.39
per barrel during 1996. Partially offsetting these increases was a decrease in
gas transportation, processing and marketing revenues of $20.6 million primarily
as a result of the sale of the Company's Wattenberg gas facilities in 1995.
Net income for 1996 was $63.0 million, compared to a net loss in 1995
of $39.8 million. The 1996 income was boosted by the net effect of the Command
transaction ($57.2 million after minority interest expense and deferred tax
expense). However, the Company also recorded a noncash charge of $15.5 million
in the second quarter related to the contribution of the Company's Wattenberg
oil and gas properties to a newly formed public company, Patina Oil and Gas
Corporation ("Patina"), in return for a 70% stake in Patina. The 1995 loss was
primarily due to $27.4 million in noncash property impairment charges and almost
$11 million in combined losses resulting from a litigation settlement, losses on
marketable securities, as well as severance and restructuring costs. Absent
these special non-recurring items, there was an increase in net income from 1995
to 1996 of approximately $23 million. This increase can be attributed primarily
to the 31% increase in average price received per BOE which increased revenues
$44.7 million offset partially by a decrease in gas management margin of $6.2
million and an increase in depreciation, depletion and amortization expense of
$8.2 million.
Revenues from production operations, less direct operating expenses,
for 1996 were $139.7 million, an increase of 52% from 1995 net revenue. Average
daily production during 1996 was 36,040 BOE, almost exactly what it was in 1995
(36,024 BOE). However, the average product price received increased by 31% to
$14.35 per BOE. Production remaining relatively constant from 1995 to 1996 can
be attributed to additional interests acquired in four Gulf of Mexico
acquisitions in late 1995 and during 1996 and the properties acquired in the
Patina transaction offset by decreased production related to numerous sales of
noncore properties which have occurred over the past two years and the reduction
of development drilling. The Company focused the last two years on divesting of
marginal assets and acquiring strategic assets that allow for future growth of
the Company. This process is substantially complete and the Company is now in
position for growth. The Company expects to increase its development schedule in
1997 which, along with two acquisitions in the Gulf of Mexico in the fourth
quarter 1996, should result in an increase in production during 1997. Total
operating expenses for 1996 decreased by $2.8 million in line with the Company's
efforts of divesting of marginal properties with high operating costs and
acquiring incremental interests in offshore properties which have historically
had lower operating costs per BOE. Operating costs per BOE were $3.76 compared
to $3.99 in 1995.
Direct operating margin from gas transportation, processing and
marketing for 1996 was $2.6 million compared to $8.9 million in 1995. The
decrease resulted primarily from a reduction in processing margins due to the
sale of the Company's Wattenberg gas processing facilities which was completed
in the third quarter of 1995. The Company realized almost $80 million in sales
proceeds during 1995 on these facilities and recognized a total of $8.7 million
in gains.
Gains on sales of investments were $69.3 million in 1996, compared to
$2.2 million in 1995. The $65.5 million gain on the Command exchange accounted
for the bulk of the increase. The remaining gains are primarily due to sales of
a portion of the Company's interests in the Permtex venture in Russia and the
Tamtsag venture in Mongolia. In January 1997, the Company's interest in the
Tamtsag venture was further reduced.
22
<PAGE>
Gains on sales of properties were $8.8 million in 1996, compared to
$12.3 million in 1995. The most significant gain during 1996 was a $7.4 million
gain on the sale of a 50% interest in the Green River Basin holdings for $16.9
million. The most significant gain during 1995 was the $8.7 million gain
recognized as part of the sale of the Company's Wattenberg gas processing
facilities for almost $80 million.
Other income increased 50% or $2.4 million from 1995. The increase can
be primarily attributed to equity in earnings of Command increasing $1.9 million
from the equity in losses recorded in 1995.
Exploration expenses for 1996 were $4.2 million, down $3.8 million from
1995. The decrease was due primarily to a writeoff of $4.1 million of acreage
costs in 1995 that was not incurred in 1996. Included in the 1996 expenditures
of $4.2 million was a $1.2 million dry hole drilled in the Gulf of Mexico in the
third quarter on an unexplored block adjacent to one of the Company's current
producing blocks.
General and administrative expenses, net of reimbursements, for 1996
were $17.1 million as compared to $17.7 million in 1995. The slight decrease is
the result of ongoing expense reduction efforts and reductions in personnel due
to the property divestitures that have taken place over the past two years
offset somewhat by increased expenses related to the acquisition of Gerrity Oil
& Gas Corporation ("GOG").
Interest and other expense was $28.9 million compared to $27.0 million
in 1995. The majority of the increase is the result of a higher average interest
rate primarily due to Patina's subordinated notes which have an effective
interest rate of 11.1%.
Depletion, depreciation and amortization expense in 1996 increased to
$84.5 million from $76.4 million in 1995. The increase reflects an increase in
the overall depletion, depreciation and amortization rate per equivalent barrel
from $5.80 to $6.41. This increase can be attributed to downward revisions in
reserve quantities at year end 1995 primarily in proved undeveloped reserves
which became uneconomic at year end 1995 prices and the growing impact of the
Gulf of Mexico operations which are typically more capital intensive thus having
a higher depletion rate.
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
Company's Wattenberg gas facilities in 1995. Oil and gas sales, on the other
hand, rose by 5% to $144.6 million as a result of a 13% growth in production of
barrels of oil equivalent. The production increase was partially offset by a 7%
decrease in the average price received per BOE. Natural gas prices dropped
sharply by 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 during 1995.
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 noncash
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 the 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 an impairment is recognized to the extent that net capitalized costs exceed
discounted expected future cash flows. The decline from the 1994 net income also
resulted from the decrease in 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,
for 1995 were $92.1 million, slightly greater than the 1994 net revenue. 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
23
<PAGE>
production late in 1994 and during 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. Additionally, late in 1995, the Company sold
its minor interest in a south Texas field where 70 nonoperated 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. 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. During 1995, the
Company realized almost $80 million in sales proceeds and recorded $8.7 million
in gains. In conjunction with the sales, the Company completed an agreement with
the primary purchaser, which, at current gas prices, is not expected to have a
material adverse effect on the wellhead net prices compared to the Company's
processing arrangements prior to the sale. Gas transportation and gathering
margins from facilities retained by the Company climbed 47% during 1995 to $3.4
million, associated with rising production and system expansions in southern
Wyoming and western Colorado. Gas marketing net revenues declined by $797,000
between years, after the suspension of third party marketing activities in late
1994.
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 were part of the
Company's ongoing program to dispose of nonstrategic assets at favorable prices.
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 portion of the Company's interest in the Permtex venture in Russia 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,
which was applied to further reduce the outstanding debt.
Exploration expenses for 1995 were $8.0 million, up $1.5 million from
1994. The increase resulted primarily from the writeoff of $4.1 million of
certain acreage costs.
General and administrative expenses, net of reimbursements, were $17.7
million as compared to $12.9 million in 1994. The increase consists of $2.3
million associated with an increase of activities related to the Company's newer
development projects, $1.5 million in severance and restructuring costs
primarily related to the Wattenberg Area activities and $1.0 million related 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 the west Texas 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 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.
DEVELOPMENT, ACQUISITION AND EXPLORATION
During 1996, the Company incurred $349.0 million in capital
expenditures, including $297.7 million for property acquisitions, $43.1 million
for development, $4.6 million for exploration, $2.0 million for field and office
equipment and $1.6 million for gas facility expansion.
24
<PAGE>
The Company expended $297.7 million relating to property acquisitions
during 1996. Of this amount, $273.1 million was for producing properties and
$24.6 million was for unevaluated properties. Of the $273.1 million expended for
producing properties, $218.4 million related to the formation of Patina and the
subsequent May 1996 acquisition (the "Acquisition") of GOG. In 1996, the Company
acquired, via three acquisitions, incremental interests in certain properties
located in the Gulf of Mexico for a net purchase price of $72.1 million ($22.4
million was classified as unevaluated properties).
Of the total development expenditures, $12.8 million was concentrated
in the Gulf of Mexico where four wells were placed on sales with three in
progress at year end. The Company expended $8.6 million in the Piceance Basin of
western Colorado to place 22 wells on sales with one in progress at year end.
The Company expended $5.7 million in the East Washakie Basin of southern Wyoming
to place twelve wells on sales with three in progress at year end. In the Green
River Basin of southern Wyoming, $2.9 million was incurred to place five wells
on sales with two in progress at year end.
Exploration costs in 1996 were $4.6 million primarily for seismic work
performed in and around the Company's major drilling projects and a dry hole
drilled in the Gulf of Mexico. In Russia, ten additional wells were drilled and
completed resulting in that venture increasing production to over 3,500 barrels
per day. Drilling activity has been slower than anticipated due to difficulties
in securing drilling contracts on commercially reasonable terms. During 1997,
the Company expects to drill 11 wells. In Mongolia, the Mongolian Parliament
ratified the grant of two additional concessions in the area to SOCO Tamtsag
Mongolia, Inc. bringing the total acreage position to approximately 10 million
acres. During 1996, two exploratory wells were drilled, one of which resulted in
a second discovery. SOCO Tamtsag Mongolia, Inc. intends to drill four wells
during 1997. In Thailand, the Company was awarded Block B8/38 in the Gulf of
Thailand. The Company has entered into an agreement with an international oil
company which will fund the drilling of an exploration well in this block.
Drilling is expected to begin in the second quarter, with a second well possibly
being drilled by year end.
FINANCIAL CONDITION AND CAPITAL RESOURCES
At December 31, 1996, the Company had total assets of $879.5 million.
Total capitalization was $675.8 million, of which 44% was represented by
stockholder's equity, 28% by senior debt, 27% by subordinated debt and 1% by
deferred taxes payable. During 1996, net cash provided by operations was $101.7
million, an increase of 47% compared to 1995. As of December 31, 1996,
commitments for capital expenditures totaled $7.3 million. The Company
anticipates that 1997 expenditures for development drilling will approximate
$112 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
and existing credit facilities. The Company is also considering a public
offering for a subsidiary which holds certain of the Company's international
investments. The Company expects the offering to be completed in 1997 with the
securities being listed on a major international stock exchange. In addition,
joint ventures or future public offerings of debt or equity securities may
be utilized.
As a result of the Acquisition, the Company has realized increased net
cash provided by operations. For the foreseeable future, cash generated by
Patina will, however, be retained by Patina to fund its development program,
reduce debt and pursue acquisitions in the DJ Basin or elsewhere. Moreover,
Patina's credit facilities currently prohibit the payment of dividends on its
common stock. Accordingly, Patina's cash flow is intended to be used to reduce
debt levels, fund a limited development program and any future acquisitions
which may be consummated and may not be available to fund the Company's other
operations or to pay dividends to its stockholders.
SOCO maintains a $500 million revolving credit facility (the "SOCO
Facility"). The SOCO Facility is divided into a $100 million short-term portion
and a $400 million long-term portion that expires on December 31, 2000.
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, 1996 was
$140 million. 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
25
<PAGE>
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 $60 million was available for the payment of dividends
and other restricted payments as of December 31, 1996.
Simultaneously with the Acquisition, Patina entered into a bank credit
agreement. The agreement consists of (i) a facility provided to Patina and SOCO
Wattenberg (the "Patina Facility") and (ii) a facility provided to GOG (the "GOG
Facility").
The Patina Facility is a revolving credit facility in an aggregate
amount up to $102 million. The amount available for borrowing under the
revolving credit facility will be limited to a semiannually adjusted borrowing
base that equaled $85 million at December 31, 1996. At December 31, 1996, $67.5
million was outstanding under the revolving credit facility. Subsequent to the
Acquisition, Patina has utilized primarily cash flow from operations to reduce
the balance outstanding under the Patina Facility by more than $14 million.
The GOG Facility is a revolving credit facility in an aggregate amount
up to $51 million. The amount available for borrowing under the GOG Facility
will be limited to a fluctuating borrowing base that equaled $35 million at
December 31, 1996. At December 31, 1996, $27.0 million was outstanding under the
GOG Facility. The GOG Facility was used primarily to refinance GOG's previous
bank credit facility and pay for costs associated with the Acquisition.
Subsequent to the Acquisition, Patina has utilized primarily cash flow from
operations to reduce the balance outstanding under the GOG Facility by more than
$7 million.
Patina's bank credit agreement contains certain financial covenants
including, but not limited to, a maximum total debt to capitalization ratio, a
maximum total debt to EBITDA ratio and a minimum current ratio. The bank credit
agreement also contains certain negative covenants, including but not limited to
restrictions on indebtedness; certain liens; guarantees, speculative derivatives
and other similar obligations; asset dispositions; dividends, loans and
advances; creation of subsidiaries; investments; leases; acquisitions; mergers;
changes in fiscal year; transactions with affiliates; changes in business
conducted; sale and leaseback and operating lease transactions; sale of
receivables; prepayment of other indebtedness; amendments to principal
documents; negative pledge clauses; issuance of securities; and non-speculative
commodity hedging.
The Company from time to time enters into arrangements to monetize its
Section 29 tax credits. These arrangements result in revenue increases of
approximately $.40 per Mcf on production volumes from qualified Section 29
properties. As a result of such arrangements, the Company recognized additional
gas sales of $2.5 million in both years ended December 31, 1995 and 1996. These
arrangements are expected to increase revenues through 2002.
The Company seeks to diversify its exploration and development risks by
seeking partners for its significant development projects and maintains a
program to divest marginal properties and assets which do not fit its long range
plans. During 1996, the Company received $73.6 million in proceeds from the sale
of oil and gas properties which were used to reduce debt and finance additional
acquisitions in the Gulf of Mexico. The most significant sales arose from the
addition of partners in two of the Company's major development projects. The
largest sale was the sale of a 45% interest in its Piceance Basin holdings for a
sale price of $22.4 million. The Company recognized a net gain of $2.4 million
as a result of this transaction. In addition, the Company sold a 50% interest in
its Green River Basin gas project for $16.9 million. The Company recognized a
net gain of $7.4 million as a result of this transaction. Proceeds from the sale
of nonstrategic properties totaled $34.3 million. The largest of these sales was
the sale in December 1996 of the Company's interests in the Giddings Field of
southeast Texas for $11.8 million. The Company recognized a net loss of $3.3
million as a result of this transaction.
In November 1996, the Company accepted an offer from Cairn for its
interest in Command. The Company received 16.2 million shares of freely
marketable Cairn common stock, and recorded a gain of $65.5 million, with no
associated current tax liability. However, a deferred tax provision of $4.0
million was recorded related to this transaction. Immediately prior to the
acceptance of Cairn's offer, the Company accrued for a transaction in which a
director of the Company exchanged his option to purchase 10% of the outstanding
common stock of SOCO International, Inc. (through which the investment in
Command was held) and issued promissory notes to the Company totaling $591,000
for 10% of the outstanding common stock of two SOCO International, Inc.
26
<PAGE>
subsidiaries, SOCO International Holdings, Inc. and SOCO International
Operations, Inc. As a result of this transaction, the Company recorded a
$260,000 loss on the exchange. Additionally, minority interest expense of $4.3
million was recorded related to the director's 10% ownership as a result of the
Command gain. The actual exchange occurred in December 1996 and the promissory
notes remained outstanding at year end. Subsequent to year end, the Company sold
4.5 million Cairn shares at an average of $8.81 per share realizing $39.2
million in proceeds which will be used primarily to reduce senior debt. These
transactions are anticipated to result in a pretax gain of $11.7 million (after
minority interest expense of $1.3 million) in the first quarter of 1997.
During the second quarter of 1996, the Board authorized the repurchase
of up to $10 million of the Company's securities and in the third quarter of
1996, authorized an additional $10 million for this purpose. During the last
three quarters of 1996, the Company repurchased 725,000 common shares for $7.0
million, 6,000 preferred depository shares for $142,000 and $3.8 million face
value convertible subordinated notes for $3.5 million. Additional repurchases
have and may continue to be made at such times and at such prices as the Company
deems appropriate.
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.
27
<PAGE>
INFLATION AND CHANGES IN PRICES
While certain of its costs are affected by the general level of
inflation, factors unique to the petroleum industry result in independent price
fluctuations. Over the past five years, significant fluctuations have occurred
in oil and gas prices. Although it is difficult to estimate future prices of oil
and gas, price fluctuations have had, and will continue to have, a material
effect on the Company.
The following table indicates the average oil and gas prices received
over the last five years and highlights the price fluctuations by quarter for
1995 and 1996. Average gas prices for 1995 and 1996 were increased by $.06 and
$.08 per Mcf, respectively, by the benefit of the Company's hedging activities.
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
AND NATURAL EQUIVALENT
LIQUIDS GAS BARRELS
--------- --------- ----------
(PER BBL) (PER MCF) (PER BOE)
<S> <C> <C> <C>
ANNUAL
------
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
1996 20.39 1.97 14.35
QUARTERLY
---------
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
1996
----
First $ 17.95 $ 1.78 $ 12.80
Second 20.52 1.62 12.90
Third 20.25 1.78 13.60
Fourth 22.26 2.64 17.69
</TABLE>
In December 1996, the Company received an average of $22.19 per barrel
and $3.68 per Mcf for its production.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTAL DATA
Reference is made to the Index to Consolidated Financial Statements on
page 29 for the Company's consolidated financial statements and notes thereto.
Quarterly financial data for the Company is presented on page 21 of this Form
10-K. Supplementary schedules for the Company, other than Schedule I, have been
omitted as not required or not applicable because the information required to be
presented is included in the financial statements and related notes.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURES.
None.
28
<PAGE>
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
PAGE
Report of Independent Public Accountants....................................30
Consolidated Balance Sheets as of December 31, 1995 and 1996................31
Consolidated Statements of Operations
for the years ended December 31, 1994, 1995 and 1996...................32
Consolidated Statements of Changes in Stockholders' Equity
for the years ended December 31, 1994, 1995 and 1996...................33
Consolidated Statements of Cash Flows
for the years ended December 31, 1994, 1995 and 1996...................34
Notes to Consolidated Financial Statements..................................35
Schedules:
Schedule I-Condensed Financial Information of Snyder Oil Corporation ..54
29
<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,
1995 and 1996, 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, 1996. 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, 1995 and 1996, and the results
of their operations and their cash flows for each of the three years in the
period ended December 31, 1996, in conformity with generally accepted accounting
principles.
As explained in Note 2 to the financial statements, 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", in
1995.
Our audits were made for the purpose of forming an opinion on the basic
financial statements taken as a whole. The supplementary schedules listed in the
index to the consolidated financial statements are presented for purposes of
complying with the Securities and Exchange Commission's rules and are not a
required part of the basic financial statements. These schedules have been
subjected to the auditing procedures applied in our audits of the basic
financial statements and, in our opinion, fairly state in all material respects
the financial data required to be set forth therein in relation to the basic
financial statements taken as a whole.
ARTHUR ANDERSEN LLP
Fort Worth, Texas,
February 17, 1997
30
<PAGE>
<TABLE>
SNYDER OIL CORPORATION
CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS)
<CAPTION>
DECEMBER 31,
--------------------------------
1995 1996
------------- -------------
ASSETS
<S> <C> <C>
Current assets
Cash and equivalents $ 27,263 $ 27,922
Accounts receivable 29,259 58,944
Inventory and other 11,769 11,212
----------- -----------
68,291 98,078
----------- -----------
Investments 33,220 129,681
----------- -----------
Oil and gas properties, successful efforts method 675,961 887,721
Accumulated depletion, depreciation and amortization (240,744) (252,334)
----------- -----------
435,217 635,387
----------- -----------
Gas facilities and other 30,506 28,111
Accumulated depreciation and amortization (11,741) (11,798)
----------- -----------
18,765 16,313
----------- -----------
$ 555,493 $ 879,459
=========== ===========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities
Accounts payable $ 36,353 $ 51,867
Accrued liabilities 26,096 37,043
----------- -----------
62,449 88,910
----------- -----------
Senior debt 150,001 188,231
Subordinated notes - 103,094
Convertible subordinated notes 84,058 80,748
Deferred taxes payable - 9,034
Other noncurrent liabilities 20,016 28,064
Minority interest 3,601 86,710
Commitments and contingencies
Stockholders' equity
Preferred stock, $.01 par, 10,000,000 shares authorized,
6% Convertible preferred stock, 1,035,000 and 1,033,500
shares issued and outstanding 10 10
Common stock, $.01 par, 75,000,000 shares authorized,
31,430,227 and 31,456,027 issued 314 315
Capital in excess of par value 265,911 260,221
Retained earnings (deficit) (29,001) 25,711
Common stock held in treasury, 134,191 and 250,000 shares at cost (2,457) (3,510)
Unrealized foreign currency translation gain 380 -
Unrealized gain on investments 211 11,921
----------- -----------
235,368 294,668
----------- -----------
$ 555,493 $ 879,459
=========== ===========
The accompanying notes are an integral part of these statements.
</TABLE>
31
<PAGE>
<TABLE>
SNYDER OIL CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
(IN THOUSANDS EXCEPT PER SHARE DATA)
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------------------------
1994 1995 1996
----------- ----------- -----------
<S> <C> <C> <C>
Revenues
Oil and gas sales $ 137,858 $ 144,608 $ 189,327
Gas transportation, processing and marketing 107,247 38,256 17,655
Gains on sales of equity interests in investees 9,747 2,183 69,343
Gains on sales of properties 1,969 12,254 8,786
Other 5,507 4,859 7,303
--------- --------- ---------
262,328 202,160 292,414
--------- --------- ---------
Expenses
Direct operating 46,267 52,486 49,638
Cost of gas and transportation 94,177 29,374 15,020
Exploration 6,505 8,033 4,232
General and administrative 12,853 17,680 17,143
Interest and other 12,463 27,001 28,899
Litigation settlement - 4,400 -
Loss on sale of subsidiary interest - - 15,481
Depletion, depreciation and amortization 70,770 76,378 84,547
Property impairments 5,783 27,412 2,753
--------- --------- ---------
Income (loss) before taxes and minority interest 13,510 (40,604) 74,701
--------- --------- ---------
Provision (benefit) for income taxes
Current - 25 33
Deferred 967 (1,370) 4,313
--------- --------- ---------
967 (1,345) 4,346
--------- --------- ---------
Minority interest (171) (572) (7,405)
--------- --------- ---------
Net income (loss) $ 12,372 $ (39,831) $ 62,950
========= ========= =========
Net income (loss) per common share $ .07 $ (1.53) $ 1.81
========= ========= =========
Weighted average shares outstanding 23,704 30,186 31,308
========= ========= =========
The accompanying notes are an integral part of these statements.
</TABLE>
32
<PAGE>
<TABLE>
SNYDER OIL CORPORATION
CONSOLIDATED STATEMENTS OF CHANGES IN
STOCKHOLDERS' EQUITY
(IN THOUSANDS)
<CAPTION>
PREFERRED STOCK COMMON STOCK CAPITAL IN RETAINED
--------------- ---------------- EXCESS OF EARNINGS TREASURY
SHARES AMOUNT SHARES AMOUNT PAR VALUE (DEFICIT) STOCK
------ ------ ------ ------ --------- --------- --------
<S> <C> <C> <C> <C> <C> <C> <C>
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 - (2,288)
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 (2,288)
Common stock grants and
exercise of options - - 138 1 856 - (169)
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) (2,457)
Common stock grants and
exercise of options - - 267 3 3,179 - (258)
Issuance of common - - 399 4 3,689 - -
Repurchase of common - - (640) (6) (6,243) - (795)
Repurchase of preferred (1) - - - (142) - -
Dividends - - - - (6,173) (8,238) -
Net income - - - - - 62,950 -
------- ------ -------- ------ --------- -------- --------
Balance, December 31, 1996 1,034 $ 10 31,456 $ 315 $ 260,221 $ 25,711 $ (3,510)
======= ====== ======== ====== ========= ======== ========
The accompanying notes are an integral part of these statements.
</TABLE>
33
<PAGE>
<TABLE>
SNYDER OIL CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------------------------
1994 1995 1996
------------ ------------ -----------
<S> <C> <C> <C>
Operating activities
Net income (loss) $ 12,372 $ (39,831) $ 62,950
Adjustments to reconcile net income (loss) to net
cash provided by operations
Amortization of deferred credits (2,986) (2,511) (1,052)
Gains on sales of investments (9,747) (809) (68,343)
Gains on sales of properties (1,969) (12,254) (8,786)
Equity in (earnings) losses of unconsolidated subsidiaries (1,355) 1,319 (421)
Exploration expense 6,505 8,033 4,232
Loss on sale of subsidiary interest - - 15,481
Depletion, depreciation and amortization 70,770 76,378 84,547
Property impairments 5,783 27,412 2,753
Deferred taxes 967 (1,370) 4,313
Minority interest 171 572 7,405
Changes in current and other assets and liabilities
Decrease (increase) in
Accounts receivable 11,024 7,142 (15,869)
Inventory and other (9,241) 3,617 5,175
Increase (decrease) in
Accounts payable 1,901 (8,521) 2,771
Accrued liabilities 1,841 5,165 (316)
Other liabilities 361 4,779 6,890
------------ ------------ -----------
Net cash provided by operations 86,397 69,121 101,730
------------ ------------ -----------
Investing activities
Acquisition, development and exploration (237,879) (92,353) (128,598)
Purchase of controlling interest in subsidiary (6,645) - -
Proceeds from investments 5,019 14,786 1,635
Outlays for investments (8,804) - (9,013)
Proceeds from sales of properties 2,806 109,988 73,620
------------ ------------ -----------
Net cash realized (used) by investing (245,503) 32,421 (62,356)
------------ ------------ -----------
Financing activities
Issuance of common 1,157 688 1,523
Increase (decrease) in indebtedness 187,138 (86,193) (13,289)
Debt issuance costs (2,855) - -
Dividends (16,721) (14,056) (14,411)
Deferred credits 2,356 3,549 (120)
Repurchase of stock (1,149) - (7,186)
Repurchase of subordinated notes - - (5,232)
------------ ------------ -----------
Net cash realized (used) by financing 169,926 (96,012) (38,715)
------------ ------------ -----------
Increase in cash 10,820 5,530 659
Cash and equivalents, beginning of year 10,913 21,733 27,263
------------ ------------ -----------
Cash and equivalents, end of year $ 21,733 $ 27,263 $ 27,922
============ ============ ===========
Noncash investing and financing activities
Gas plant capital lease $ 21,000 - -
Acquisition of properties and stock via stock issuances - $ 13,032 $ 3,693
Acquisition of properties recorded as senior debt - - $ 31,730
Acquisition via subsidiary stock issuance - - $ 115,067
The accompanying notes are an integral part of these statements.
</TABLE>
34
<PAGE>
SNYDER OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) ORGANIZATION AND NATURE OF BUSINESS
Snyder Oil Corporation (the "Company") is primarily engaged in the
acquisition, exploration and development of oil and gas properties principally
in the Rocky Mountain and Gulf Coast regions of the United States. To a minor
extent, the Company gathers, transports and markets natural gas generally in
proximity to its principal producing properties. The Company is also engaged in
international acquisition, exploration and development, primarily through
affiliates. The Company, a Delaware corporation, is the successor to a company
formed in 1978.
(2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation
The consolidated financial statements include the accounts of Snyder
Oil Corporation ("SOCO") and its subsidiaries (collectively, the "Company").
Affiliates in which the Company owns more than 50% but less than 100% are fully
consolidated, with the related minority interest being deducted from subsidiary
earnings and stockholders' equity. Affiliates being accounted for in this manner
include Patina Oil & Gas Corporation ("Patina"), SOCO International Holdings,
Inc. ("Holdings") and SOCO International Operations, Inc. ("Operations"). DelMar
Petroleum, Inc., whose name was subsequently changed to SOCO Offshore, Inc.
("SOCO Offshore"), was accounted for in this manner until all remaining minority
interests were acquired in June 1996. Affiliates in which the Company owns
between 20% and 50% are accounted for under the equity method. Affiliates being
accounted for in this manner include SOCO Perm Russia, Inc. ("SOCO Perm"), a
Russian affiliate, and SOCO Tamtsag Mongolia, Inc. ("SOCO Tamtsag"), a Mongolian
affiliate. Command Petroleum Limited ("Command"), an Australian affiliate, was
accounted for in this manner until the Company disposed of this investment in
November 1996. Affiliates in which the Company owns less than 20% are accounted
for under the cost method. Affiliates being accounted for in this manner include
Cairn Energy plc ("Cairn"). The Company accounts for its interest in joint
ventures and partnerships using the proportionate consolidation method, whereby
its share of assets, liabilities, revenues and expenses are consolidated.
Producing Activities
The Company utilizes the successful efforts method of accounting for
its oil and gas properties. Consequently, leasehold costs are capitalized when
incurred. Unproved properties are assessed periodically within specific
geographic areas and impairments in value are charged to expense. During the
year ended December 31, 1996, the Company provided unproved property impairments
of $2.8 million. Exploratory expenses, including geological and geophysical
expenses and delay rentals, are charged to expense as incurred. Exploratory
drilling costs are initially capitalized, but charged to expense if and when the
well is determined to be unsuccessful. Costs of productive wells, unsuccessful
developmental wells 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 abandonment costs
(net of salvage values) are accrued at unit-of-production rates and taken into
account in determining depletion, depreciation and amortization.
Prior to 1995, the Company provided impairments for significant proved
oil and gas property groups to the extent that net capitalized costs exceeded
the undiscounted future cash flows. During 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 it is recognized to the extent that net capitalized costs exceed discounted
expected future cash flows. Accordingly, in 1995 the Company provided for $27.4
million of such impairments. During the year ended December 31, 1996, the
Company did not provide for any such impairments.
35
<PAGE>
Unrealized Foreign Currency Translation Gain
The company follows SFAS 52, "Foreign Currency Translation", which
requires that business transactions and foreign operations recorded in a foreign
currency must be restated in U.S. dollars. Gains or losses resulting from the
translation process increases or decreases the book value of investments and
must be accumulated in a separate component of stockholders' equity. Command's
functional currency is the Australian dollar. The foreign currency translation
gain reported in the balance sheet as of December 31, 1995 was the result of the
translation of the Australian dollar balance sheet into United States dollars at
then current exchange rates.
Section 29 Tax Credits
The Company from time to time enters into arrangements to monetize its
Section 29 tax credits. These arrangements result in revenue increases of
approximately $.40 per Mcf on production volumes from qualified Section 29
properties. As a result of such arrangements, the Company recognized additional
gas revenues of $2.5 million in both 1995 and 1996. These arrangements are
expected to continue through 2002.
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
proportionate share of gas produced. Gas imbalances at year end 1995 and 1996
were insignificant.
Financial Instruments
The following table sets forth the book value and estimated fair
values of financial instruments (in thousands):
<TABLE>
<CAPTION>
DECEMBER 31, DECEMBER 31,
1995 1996
---------------------- ----------------------
BOOK FAIR BOOK FAIR
VALUE VALUE VALUE VALUE
--------- --------- --------- ---------
<S> <C> <C> <C> <C>
Cash and equivalents $ 27,263 $ 27,263 $ 27,922 $ 27,922
Investments 33,220 52,203 129,681 163,477
Senior debt (150,001) (150,001) (188,231) (188,231)
Subordinated notes - - (103,094) (105,650)
Convertible subordinated notes (84,058) (79,997) (80,748) (82,866)
Long-term commodity contracts - 11,623 - 5,040
Interest rate swap - 107 - (19)
</TABLE>
The book value of cash and equivalents approximates fair value because
of the short maturity of those instruments. See Note (3) for a discussion of the
Company's investments. The fair value of senior debt is presented at face value
given its floating rate structure. The fair value of the subordinated notes and
convertible subordinated notes are estimated based on their December 31, 1996
closing prices on the New York Stock Exchange.
From time to time, the Company enters into commodity contracts to
hedge the price risk of a portion of its production. Gains and losses on such
contracts are deferred and recognized in income as an adjustment to oil and gas
sales revenue in the period to which the contracts relate. In 1994, the Company
entered into a long-term gas swap arrangement in order to lock in the price
differential between the Rocky Mountain and Henry Hub prices on a portion of its
Rocky Mountain gas production. The contract covers 20,000 MMBtu per day through
2004. In December 1996, that volume represented approximately 43% of SOCO's
Rocky Mountain gas production and 17% of the Company's consolidated Rocky
Mountain gas production. The fair value of the contract was based on the market
price quoted for a similar instrument.
36
<PAGE>
In September 1995, the Company entered into an interest rate swap
covering $50 million of its bank debt. The agreement requires payment to a
counterparty based on a fixed rate of 5.585% and requires the counterparty to
pay the Company interest at the then current 30 day LIBOR rate. Accounts
receivable or payable under this agreement are recorded as adjustments to
interest expense and are settled on a monthly basis. The agreement matures in
September 1997, with the counterparty having the option to extend it for two
years. At December 31, 1996, the fair value of the agreement was estimated at
the net present value discounted at 10%.
Risks and Uncertainties
Historically, the market for oil and gas has experienced significant
price fluctuations. Prices for gas in the Rocky Mountain region, where the
Company currently produces over 70% of its natural gas, have traditionally been
particularly volatile. Prices are significantly impacted by the local weather,
production in the area, seasonal variations in local demand and limited
transportation capacity to other regions of the country. Until recently, mild
weather and increased production in the region contributed to depressed prices.
At December 31, 1996, prices in the region had rebounded sharply, although it is
uncertain if this trend will continue. Increases or decreases in prices
received, particularly in the Rocky Mountains, could have a significant impact
on the Company's future results of operations.
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. Such projects are subject to a number of political and economic
uncertainties, in addition to the typical risks and volatility associated with
the oil and gas industry. There is no assurance that the Company's international
operations will reach a level reasonably required to fully exploit the projects,
nor is there any assurance of economic success should such a level be reached.
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.
Other
All liquid investments with an original maturity of three months or
less are considered to be cash equivalents. Certain amounts in prior years
consolidated financial statements have been reclassified to conform with current
classification.
(3) INVESTMENTS
The Company has investments in foreign and domestic energy companies
and long-term notes receivable. The following table sets forth the book values
and estimated fair values of these investments:
<TABLE>
<CAPTION>
DECEMBER 31, 1995 DECEMBER 31, 1996
----------------------- ------------------------
(IN THOUSANDS)
BOOK FAIR BOOK FAIR
VALUE VALUE VALUE VALUE
--------- --------- --------- ---------
<S> <C> <C> <C> <C>
Equity method investments $ 30,901 $ 49,884 $ 8,789 $ 42,585
Marketable securities 652 652 115,558 115,558
Long-term notes receivable 1,667 1,667 5,334 5,334
--------- --------- --------- ---------
$ 33,220 $ 52,203 $ 129,681 $ 163,477
========= ========= ========= =========
</TABLE>
The Company follows SFAS 115, "Accounting for Certain Investments in
Debt and Equity Securities", which requires that investments in marketable
37
<PAGE>
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.
Command Petroleum Limited
From May 1993 to November 1996, the Company had an investment in
Command, an Australian oil company, accounted for by the equity method. Command
was listed on the Australian Stock Exchange. In 1995, the Company acquired an
additional 4.7 million shares of Command common stock in exchange for an
interest in the Fejaj Permit in Tunisia. As a result, the Company's ownership in
Command increased to 30.0% and a $1.4 million gain was recognized during 1995.
In June 1996, the Company purchased 8.5 million shares of Command common stock
for $3.6 million, increasing its ownership to 32.6%. In October 1996, Command
announced that it had completed merger negotiations with Cairn, an international
independent oil company based in Edinburgh, Scotland with shares listed on the
London Stock Exchange. In November 1996, the Company accepted Cairn's offer for
its interest in Command. The Company received 16.2 million shares of freely
marketable Cairn common stock, and recorded a gain of $65.5 million in the
fourth quarter of 1996. The Company's investment in Cairn is accounted for under
the cost method and is reflected as marketable securities in the table above.
Immediately prior to the acceptance of Cairn's offer, the Company accrued for a
transaction in which a director of the Company exchanged his option to purchase
10% of the outstanding common stock of SOCO International, Inc. (through which
the investment in Command was held) and issued promissory notes to the Company
totaling $591,000 for 10% of the outstanding common stock of two SOCO
International, Inc. subsidiaries, Holdings and Operations. As a result of this
transaction, the Company recorded a $260,000 loss on the exchange.
Additionally, minority interest expense of $4.3 million was recorded related to
the director's 10% ownership as a result of the Command gain. The actual
exchange occurred in December 1996 and the promissory notes remained
outstanding at year end.
SOCO Perm Russia, Inc.
In 1993, SOCO Perm was organized by the Company and a U.S. industry
participant. SOCO Perm and a Russian partner formed the Permtex joint venture to
develop proven oil fields in the Volga-Urals Basin of Russia. To finance a
portion of its planned development expenditures, SOCO Perm closed a private
placement of its equity securities with three industry participants in 1994. As
a result, the Company's investment was reduced from 75% to 41.25% and a $3.5
million net gain was recorded. In 1995, the three industry participants paid the
final installments of their contributions to SOCO Perm and as a result, the
Company recognized an additional gain of $1.1 million. In April 1996, SOCO Perm
closed a private placement which reduced the Company's interest to 34.91% and
indicated a market value of $22.7 million for the Company's remaining position.
The Company recognized a gain in the second quarter of $2.6 million as a result
of this transaction. The private placement agreement requires SOCO Perm to list
its common shares on a securities exchange no later than 1998. If such listing
does not occur, the new shareholders have the right to require the Company to
purchase their share at a formula price. The Company's investment in SOCO Perm
is held through Operations. The Company is currently considering the possibility
of listing Operations on a major international Stock Exchange. If such listing
was to occur, it is expected to meet the requirement to list SOCO Perm. The
Company's investment in SOCO Perm had a carrying cost at December 31, 1996 of
$7.0 million.
SOCO Tamtsag Mongolia, Inc.
In 1994, the Company formed a consortium to explore the Tamtsag Basin
of eastern Mongolia, then sold a portion of its interest to three industry
participants. One participant 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 consortium. Accordingly, the Company's
investment in SOCO Tamtsag was reduced from 100% to 49% and a $1.5 million gain
was recognized. In 1996, the Company completed the exchange of a portion of its
interest to an industry participant for consulting services valued at $1.5
million. As a result of this transaction, the Company's ownership was reduced to
42% and an $832,000 gain was recognized. In August 1996, the Mongolian
Parliament ratified the grant of two additional concessions in the area to SOCO
Tamtsag, bringing the total acreage position to approximately 10 million acres.
The Company's investment in SOCO Tamtsag had a carrying cost of $1.8 million at
December 31, 1996 in addition to $4.7 million in stockholder loans, which are
required on a pro rata basis by all stockholders, to SOCO Tamtsag which are
included in notes receivable in the table above. In January 1997, SOCO Tamtsag
completed an equity sale which reduced the Company's investment to 40.3% and
38
<PAGE>
indicated a market value of $19.9 million for the Company's remaining position.
The Company's investment in SOCO Tamtsag is held through Operations.
Marketable Securities
The Company had investments in equity securities of publicly traded
domestic energy companies accounted for on the cost method, with a total cost at
December 31, 1995 of $328,000. The market value of these securities at December
31, 1995 approximated $652,000. In 1996, the Company sold all of these
securities for $968,000 and recognized a corresponding gain of $640,000. 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
had investments in equity securities of one publicly traded foreign energy
company, Cairn, accounted for on the cost method at December 31, 1996. Cairn has
a major development project off the coast of Bangladesh as well as major
producing interests in the United Kingdom and the Dutch North Sea, and
exploration interests in several countries including Thailand, Vietnam and
China. The Company's total cost basis in the Cairn shares was $95.2 million at
December 31, 1996. The market value of the Cairn shares approximated $115.6
million at December 31, 1996. In accordance with SFAS 115, at December 31, 1996,
investments were increased by a $20.4 million gross unrealized holding gain,
stockholders' equity was increased by $11.9 million, minority interest liability
was increased by $1.3 million and deferred taxes payable were increased by $7.2
million. Subsequent to year end, the Company sold 4.5 million Cairn shares at an
average of $8.81 per share realizing $39.2 million in proceeds which will be
used primarily to reduce senior debt. These transactions are anticipated to
result in a pretax gain of $11.7 million (after minority interest expense of
$1.3 million) in the first quarter of 1997.
Notes Receivable
The Company holds long-term notes receivable due from SOCO Tamtsag,
other privately held corporations and a director, with a book value of $1.7
million and $5.3 million at December 31, 1995 and 1996. SOCO Tamtsag shareholder
loans, which bear interest at the three month LIBOR rate plus two percent, are
to be repaid from the gross receipts of SOCO Tamtsag under certain circumstances
(i.e., excess cash reserves). Any remaining balances mature December 31, 2009.
The notes from other privately held corporations are secured by certain assets,
including stock and oil and gas properties. The notes from a director, which
originated in connection with an option to purchase 10% of the Company's
international affiliates, are unsecured and are due April 10, 1998. The Company
believes that, based on existing market conditions, the December 31, 1996
balances will be recovered in the long term. At December 31, 1995 and 1996, 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.
(4) OIL AND GAS PROPERTIES AND GAS FACILITIES
The cost of oil and gas properties at December 31, 1995 and 1996
includes $24.2 million and $32.7 million, respectively, of unevaluated
leasehold. Such properties are held for exploration, development or resale and
are excluded from amortization. The following table sets forth costs incurred
related to oil and gas properties and gas processing and transportation
facilities:
<TABLE>
<CAPTION>
1994 1995 1996
---------- ---------- ----------
(IN THOUSANDS)
<S> <C> <C> <C>
Proved acquisitions $ 44,684 $ 13,675 $ 273,088
Acreage acquisitions 25,571 7,388 24,589
Development 156,912 62,578 43,075
Gas processing, transportation and other 46,607 7,886 3,612
Exploration 5,514 8,214 4,588
---------- ---------- ----------
$ 279,288 $ 99,741 $ 348,952
========== ========== ==========
</TABLE>
During 1996, the Company incurred $273.1 million for domestic proved
acquisitions. Of the total acquisition expenditures, $218.4 million related to
the formation of Patina and the subsequent May 1996 acquisition (the
"Acquisition") of Gerrity Oil & Gas Corporation ("GOG"). As a result, the
Company initially retained 70% of the common stock of Patina and the former GOG
39
<PAGE>
shareholders received 30% of the common stock. The Company currently owns 74% of
Patina, and it is consolidated into the Company's financial statements. The
Company recognized a net loss of $15.5 million in the second quarter of 1996 as
a result of this transaction. In 1996, the Company acquired, via three
acquisitions, incremental interests in certain properties located in the Gulf of
Mexico for a net purchase price of $72.1 million ($22.4 million of which was
classified as acreage acquisitions).
Of the total development expenditures, $12.8 million was concentrated
in the Gulf of Mexico where four wells were placed on sales with three in
progress at year end. The Company expended $8.6 million in the Piceance Basin of
western Colorado to place 22 wells on sales with one in progress at year end.
The Company expended $5.7 million in the East Washakie Basin of southern Wyoming
to place twelve wells on sales with three in progress at year end. In the Green
River Basin of southern Wyoming, $2.9 million was incurred to place five wells
on sales with two in progress at year end.
In May 1996, the Company sold a 45% interest in its Piceance Basin
holdings for $22.4 million. The Company recognized a net gain of $2.4 million as
a result of this transaction. In July 1996, the Company sold a 50% interest in
its Green River Basin gas project for $16.9 million. The Company recognized a
net gain of $7.4 million as a result of this transaction. In December 1996, the
Company sold its interests in the Giddings Field of southeast Texas for $11.8
million. The Company recognized a net loss of $3.3 million as a result of this
transaction.
The following table summarizes the unaudited pro forma effects on the
Company's financial statements assuming significant acquisitions and
divestitures consummated during 1996 had been consummated on January 1, 1995 and
1996. 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>
1995 1996
----------- ----------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
<S> <C> <C>
Oil and gas sales $ 189,734 $ 221,368
Total revenues $ 250,986 $ 324,127
Production direct operating margin $ 131,310 $ 170,612
Net income (loss) $ (43,638) $ 71,125
Net income (loss) per common share $ (1.65) $ 2.07
Weighted average shares outstanding 30,186 31,308
</TABLE>
(5) INDEBTEDNESS
The following indebtedness was outstanding on the respective dates:
<TABLE>
<CAPTION>
DECEMBER 31,
-------------------------------
1995 1996
----------- -----------
(IN THOUSANDS)
<S> <C> <C>
SOCO bank facility $ 150,001 $ 93,731
Patina bank facilities - 94,500
Less current portion - -
----------- -----------
Senior debt $ 150,001 $ 188,231
=========== ===========
Patina subordinated notes $ - $ 103,094
=========== ===========
SOCO convertible subordinated notes $ 84,058 $ 80,748
=========== ===========
</TABLE>
40
<PAGE>
SOCO maintains a $500 million revolving credit facility ("SOCO
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
was $140 million at December 31, 1996. 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
consolidated tangible net worth as defined. During 1996, the average interest
rate under the revolver was 6.4%. The Company pays certain fees based on the
unused portion of the borrowing base. Among other requirements, covenants
require maintenance of a current working capital ratio of 1 to 1 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 $60
million was available for the payment of dividends and other restricted payments
at December 31, 1996.
Simultaneously with the Acquisition, Patina entered into a bank credit
agreement. The agreement consists of (a) a facility provided to Patina and SOCO
Wattenberg (the "Patina Facility") and (b) a facility provided to GOG (the "GOG
Facility").
The Patina Facility is a revolving credit facility in an aggregate
amount up to $102 million. The amount available for borrowing under the Patina
Facility will be limited to a semiannually adjusted borrowing base that equaled
$85 million at December 31, 1996. At December 31, 1996, $67.5 million was
outstanding under the Patina Facility.
The GOG Facility is a revolving credit facility in an aggregate amount
up to $51 million. The amount available for borrowing under the GOG Facility
will be limited to a fluctuating borrowing base that equaled $35 million at
December 31, 1996. At December 31, 1996, $27.0 million was outstanding under the
GOG Facility. The GOG Facility was used primarily to refinance GOG's previous
bank credit facility and pay for costs associated with the Acquisition.
The borrowers may elect that all or a portion of the credit facilities
bear interest at a rate per annum equal to: (i) the higher of (a) prime rate
plus a margin equal to .25% with respect to the GOG Facility and the Patina
Facility (the "Applicable Margin") and (b) the Federal Funds Effective Rate plus
.5% plus the Applicable Margin, or (ii) the rate at which Eurodollar deposits
for one, two, three or six months (as selected by the applicable borrower) are
offered in the interbank Eurodollar market in the approximated amount of the
requested borrowing (the "Eurodollar Rate") plus 1.25%, with respect to the GOG
Facility and the Patina Facility (the "Eurodollar Margin"). During the period
subsequent to the Acquisition through December 31, 1996, the average interest
rate under the facilities was 6.9%.
Patina's bank credit agreement contains certain financial covenants,
including but not limited to a maximum total debt to capitalization ratio, a
maximum total debt to EBITDA ratio and a minimum current ratio. The bank credit
agreement also contains certain negative covenants, including but not limited to
restrictions on indebtedness; certain liens; guaranties, speculative derivatives
and other similar obligations; asset dispositions; dividends, loans and
advances; creation of subsidiaries; investments; leases; acquisitions; mergers;
changes in fiscal year; transactions with affiliates; changes in business
conducted; sale and leaseback and operating lease transactions; sale of
receivables; prepayment of other indebtedness; amendments to principal
documents; negative pledge clauses; issuance of securities; and non-speculative
commodity hedging.
41
<PAGE>
Simultaneously with the Acquisition, Patina recorded $100 million of
11.75% Subordinated Notes due July 15, 2004 issued by GOG on July 1, 1994. In
connection with the Acquisition, Patina also repurchased $1.2 million of the
notes. As part of the purchase accounting, the remaining notes were reflected in
the accompanying financial statements at a market value of $104.6 million or
105.875% of their principal amount. Subsequent to the Acquisition, an additional
$1.5 million of the notes were repurchased by the Company and retired. Interest
is payable each January 15 and July 15. The Notes are redeemable at the option
of GOG, in whole or in part, at any time on or after July 15, 1999, initially at
105.875% of their principal amount, declining to 100% on or after July 15, 2001.
Upon the occurrence of a change of control, as defined in the Notes, GOG would
be obligated to make an offer to purchase all outstanding Notes at a price of
101% of the principal amount thereof. In addition, GOG would be obligated,
subject to certain conditions, to make offers to purchase Notes with the net
cash proceeds of certain asset sales or other dispositions of assets at a price
of 101% of the principal amount thereof. The Notes are unsecured general
obligations of GOG and are subordinated to all senior indebtedness of GOG and to
any existing and future indebtedness of GOG's subsidiaries.
The Notes contain covenants that, among other things, limit the
ability of GOG to incur additional indebtedness, pay dividends, engage in
transactions with shareholders and affiliates, create liens, sell assets, engage
in mergers and consolidations and make investments in unrestricted subsidiaries.
Specifically, the Notes restrict GOG from incurring indebtedness (exclusive of
the Notes) in excess of approximately $51 million, if after giving effect to the
incurrence of such additional indebtedness and the receipt and application of
the proceeds therefrom, GOG's interest coverage ratio is less than 2.5:1 or
adjusted consolidated net tangible assets are less than 150% of the aggregate
indebtedness of GOG.
In 1994, SOCO 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 $22.57 per share. Given the terms of the notes,
common stock dividends not paid out of retained earnings reduce the conversion
price when paid. The notes 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. During 1996, the Company repurchased $3.8 million of
these notes in accordance with a repurchase program.
Scheduled maturities of indebtedness for the next five years are zero
for 1997 and 1998, $94.5 million in 1999, $93.7 million in 2000 and $82.5
million in 2001. The long-term portions of the Patina Facilities and SOCO
Facility are scheduled to expire in 1999 and 2000. However, it is management's
policy to renew both the short-term and long-term facilities and extend their
maturities on a regular basis.
Consolidated cash payments for interest were $9.9 million, $22.1
million and $21.9 million, respectively, for 1994, 1995 and 1996.
(6) STOCKHOLDERS' EQUITY
A total of 75 million common shares, $.01 par value, are authorized of
which 31.5 million were issued at December 31, 1996. The Company also has 2.1
million warrants outstanding. The warrants are exercisable at a price of $21.04
per share. Under the terms of the warrants, common stock dividends not paid out
of retained earnings reduce the exercise price when paid and increase the number
of warrants outstanding. Half of the warrants expire in each of February 1998
and February 1999. In 1995, the Company issued 1.2 million shares of common
stock, with 1.1 million shares issued in exchange for acquired property
interests and 138,000 shares issued primarily for the exercise of stock options.
In 1996, the Company issued 666,000 shares of common stock, with 399,000 shares
issued in exchange for the remaining outstanding stock of SOCO Offshore and
267,000 shares issued primarily for the exercise of stock options. In 1996, the
Company repurchased 725,000 shares of common stock for $7.0 million. Quarterly
dividends of $.065 per share were paid in 1995 and 1996. For book purposes, for
the period between June 1995 and September 1996, the common stock dividends were
in excess of retained earnings and as such were treated as distributions of
capital.
42
<PAGE>
A total of 10 million preferred shares, $.01 par value, are
authorized. In 1993, 4.1 million depositary shares (each representing a quarter
interest in a 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 $20.46 per share. Under the terms of the stock,
common stock dividends not paid out of retained earnings reduce the conversion
price when paid. The stock is exchangeable at the option of the Company for 6%
convertible subordinated debentures on any dividend payment date. The 6%
convertible preferred stock is currently redeemable at the option of the
Company. The liquidation preference is $25.00 per depositary share, plus accrued
and unpaid dividends. At December 31, 1996, the redemption price was $26.05 per
depository share. The redemption price declines $.15 per year to $25.00 per
depository share in 2003. During 1996, the Company repurchased 6,000 depository
shares for $142,000. The Company paid $6.2 million ($1.50 per 6% convertible
depositary share per annum) in preferred dividends during both 1995 and 1996.
Earnings per share are computed by dividing net income, less dividends
on preferred stock, by weighted average common shares outstanding. Net income
available (loss applicable) to common for the years ended December 31, 1994,
1995 and 1996, was $1.6 million, ($46.0) million and $56.7 million,
respectively. Differences between primary and fully diluted earnings per share
were insignificant for all periods presented.
The Company maintains a stock option plan for certain 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 determined by a
committee of independent members of the Board. A stock grant and option plan is
also maintained by the Company whereby each nonemployee Director receives 500
common shares quarterly in payment of their annual retainer. It also provides
for 2,500 options to be granted annually to each nonemployee Director. The
majority of currently outstanding options vest over a three year period (30%,
60%, 100%) and expire five years from the date of grant.
At December 31, 1996, the Company has two fixed stock option
compensation plans, which are described above. The Company applies APB Opinion
No. 25, "Accounting for Stock Issued to Employees", and related Interpretations
in accounting for the plans. Accordingly, no compensation cost has been
recognized for these fixed stock option plans. Had compensation cost for the
Company's fixed stock option compensation plans been determined consistent with
SFAS 123, "Accounting for Stock-Based Compensation", the Company's net income
(in thousands) and earnings per share would have been reduced to the pro forma
amounts indicated below:
<TABLE>
<CAPTION>
1995 1996
--------- ---------
<S> <C> <C>
Net income (loss) As Reported $ (39,831) $ 62,950
Pro forma $ (40,567) $ 61,936
Income (loss) per share As Reported $ (1.53) $ 1.81
Pro forma $ (1.55) $ 1.78
</TABLE>
The fair value of each option grant is estimated on the date of grant
using the Black-Sholes option-pricing model with the following weighted-average
assumptions used for grants in 1995 and 1996, respectively: dividend yield of
1.9% and 2.8%; expected volatility of 46% and 44%; risk-free interest rates of
7.2% and 5.7%; and an expected life of 4.5 years.
43
<PAGE>
A summary of the status of the Company's two fixed stock option plans
as of December 31, 1994, 1995 and 1996 and changes during the years ended on
those dates is presented below (shares are in thousands):
<TABLE>
<CAPTION>
1994 1995 1996
--------------------- --------------------- ---------------------
WEIGHTED- WEIGHTED- WEIGHTED-
AVERAGE AVERAGE AVERAGE
EXERCISE EXERCISE EXERCISE
SHARES PRICE SHARES PRICE SHARES PRICE
------ --------- ------ --------- ------ ---------
<S> <C> <C> <C> <C> <C> <C>
Outstanding at beginning
of year 1,383 $5.66 1,484 $12.96 1,711 $13.21
Granted 510 18.38 610 14.06 519 9.50
Exercised (407) 5.35 (124) 7.34 (255) 6.69
Forfeited (2) 16.14 (259) 16.62 (301) 14.71
------ ------ ------
Outstanding at end of year 1,484 12.96 1,711 13.21 1,674 12.72
====== ====== ======
Options exercisable at
year end 533 743 772
Weighted-average fair
value of options
granted during
the year N/A $5.78 $3.27
</TABLE>
The following table summarizes information about fixed stock options
outstanding at December 31, 1996:
<TABLE>
<CAPTION>
OPTIONS OUTSTANDING OPTIONS EXERCISABLE
------------------------------------------------------ -------------------------------
NUMBER WEIGHTED- NUMBER
RANGE OUTSTANDING AT AVERAGE WEIGHTED- EXERCISABLE AT WEIGHTED-
OF DECEMBER 31, REMAINING AVERAGE DECEMBER 31, AVERAGE
EXERCISE PRICES 1996 CONTRACTUAL LIFE EXERCISE PRICE 1996 EXERCISE PRICE
(In years)
- ------------------- -------------- ---------------- -------------- -------------- --------------
<C> <C> <C> <C> <C> <C>
$ 6.00 to 8.88 163,000 0.9 $ 6.09 163,000 $ 6.09
9.38 to 13.75 771,000 3.3 10.85 260,000 13.02
14.13 to 20.13 740,000 2.6 16.14 349,000 16.98
--------- -------
$ 6.00 to 20.13 1,674,000 2.7 12.72 772,000 13.35
========= =======
</TABLE>
(7) FEDERAL INCOME TAXES
At December 31, 1996, 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 for the years ended December 31, 1994, 1995 and 1996
follows:
<TABLE>
<CAPTION>
1994 1995 1996
-------- -------- --------
<S> <C> <C> <C>
Federal statutory rate 35% (35%) 35%
Loss in excess of net deferred tax liability - 32% -
Net change in valuation allowance (27%) - (29%)
Alternative minimum taxes (1%) - -
------- ------- -------
Effective income tax rate 7% (3%) 6%
======= ======= =======
</TABLE>
44
<PAGE>
For book purposes, the components of the net deferred tax asset and
liability at December 31, 1995 and 1996, respectively, were:
<TABLE>
<CAPTION>
1995 1996
----------- -----------
<S> <C> <C>
Deferred tax assets
NOL and capital loss carryforwards $ 53,010 $ 65,126
AMT credit carryforwards 1,293 644
Production payment receivables - 32,654
Reserves and other 1,977 5,613
----------- -----------
56,280 104,037
----------- -----------
Deferred tax liabilities
Depreciable and depletable property (24,018) (59,865)
Investments and other (2,171) (42,252)
Unrealized investments gains (317) (7,131)
----------- -----------
(26,506) (109,248)
----------- -----------
Deferred asset (liability) 29,774 (5,211)
Valuation allowance (29,774) (3,823)
----------- -----------
Net deferred tax liability $ - $ (9,034)
=========== ===========
</TABLE>
For tax purposes, Patina is not included in the Company's consolidated
United States federal income tax return. The Company, excluding Patina, had
regular net operating loss carryforwards of $112 million and alternative minimum
tax loss carryforwards of $28.9 million at December 31, 1996. These
carryforwards expire between 1997 and 2010. At December 31, 1996, the Company,
excluding Patina, had long-term capital loss carryforwards of $3.9 million which
will expire in 2000. At December 31, 1996, the Company, excluding Patina, also
had alternative minimum tax credit carryforwards of $644,000 which are available
indefinitely. Patina had regular net operating loss carryforwards of $70.2
million and alternative minimum tax loss carryforwards of $35.1 million at
December 31, 1996. Utilization of $31.9 million regular net operating loss
carryforwards and $31.6 million alternative minimum tax loss carryforwards will
be limited to $5.2 million per year as a result of the Acquisition. These
carryforwards expire from 2006 through 2011. At December 31, 1996, Patina had
alternative minimum tax credit carryforwards of $478,000 which are available
indefinitely. Current income taxes shown in the financial statements reflect
estimates of alternative minimum taxes.
(8) MAJOR CUSTOMERS
In 1994 and 1995, Amoco Production Company accounted for approximately
11% and 10%, respectively, of revenues. In 1996, Pan Energy accounted for
approximately 11% of revenues. Management believes that the loss of any
individual purchaser would not have a material adverse impact on the financial
position or results of operations of the Company.
(9) COMMITMENTS AND CONTINGENCIES
The Company rents offices at various locations under noncancelable
operating leases. Minimum future payments under such leases approximate $2.5
million for 1997, $2.4 million for 1998, $2.6 million for 1999, $2.6 million for
2000 and $1.6 million for 2001.
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. In January 1997, the judge ordered that the class not
be certified. All remaining liability under this suit was assumed by Patina upon
its formation. In January 1996, GOG was also sued in a similar but separate
class action filed in stated court. In both suits, the plaintiffs allege that
unspecified "post-production" costs incurred prior to calculating royalty
payments were deducted in breach of the relevant lease provisions and that this
45
<PAGE>
fact was fraudulently concealed. The plaintiffs seek unspecified compensatory
and punitive damages and a declaratory judgment prohibiting deduction of
post-production costs prior to calculating royalties paid to the class. The
Company believes that calculations of royalties by it and GOG are and have been
proper under the relevant lease provisions, and intends to defend these and any
similar suits vigorously.
In September 1996, the Company and other interest owners in a lease in
southern Texas were sued by the royalty owners in Texas state court in Brooks
County, Texas. The Company's working interest in the lease is approximately 20%.
The complaint alleges, among other things, that the defendants have failed to
pay proper royalties under the lease and have breached their duties to
reasonably develop the lease. The plaintiffs also claim damages for fraud and
trespass, and demand actual and punitive damages. Although the complaint does
not specify the amount of damages claimed, an earlier letter from plaintiffs
claimed damages in excess of $50 million. The Company and the other interest
owners have filed an answer denying the claims and intend to contest the suit
vigorously.
At this time, the Company is unable to estimate the range of potential
loss, if any, from the foregoing uncertainties. However, the Company believes
their resolution 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 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 of 1995 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 has brought suit against 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 second quarter of 1996, the Company received $1.5 million in
proceeds which was reflected in other income related to a judgment involving a
pipeline dispute.
The Company's operations are affected by political developments and
federal and state laws and regulations. Oil and gas industry legislation and
administrative regulations are periodically changed for a variety of political,
economic and other reasons. Numerous departments and agencies, federal, state,
local and Indian, issue rules and regulations binding on the oil and gas
industry, some of which carry substantial penalties for failure to comply. The
regulatory burden on the oil and gas industry increases the Company's cost of
doing business, decreases flexibility in the timing of operations and may
adversely affect the economics of capital projects.
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.
(10) UNAUDITED SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION
Independent petroleum consultants directly evaluated 58%, 81%, and 99%
of proved reserves at December 31, 1994, 1995 and 1996, respectively, and
performed a detailed review of properties which comprised in excess of 80% of
proved reserve value in 1994. All reserve estimates are based on economic and
operating conditions at that time. Future net cash flows as of each year end
were computed by applying then current prices to estimated future production
less estimated future expenditures (based on current costs) to be incurred in
producing and developing the reserves.
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
46
<PAGE>
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, 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
Revisions 4,127 41,385
Extensions, discoveries and additions 1,039 61,821
Production (3,884) (55,840)
Purchases 16,725 225,335
Sales (1,757) (62,783)
-------- --------
Balance, December 31, 1996 40,497 605,636
======== ========
</TABLE>
The table above includes reserves attributable to minority interests
of 18.6 million BOE at December 31, 1996.
The Company's interest in the Russian joint venture (Permtex) is
accounted for under the equity method. At December 31, 1994, 1995 and 1996, the
Company's equity in Permtex proved reserves was 8.0 million BOE, 7.8 million BOE
and 8.6 million BOE, respectively. These amounts are not included in the
quantities above.
47
<PAGE>
<TABLE>
<CAPTION>
PROVED DEVELOPED RESERVES - CRUDE NATURAL
OIL GAS
--------- ---------
(MBBL) (MMCF)
<S> <C> <C>
December 31, 1993 18,032 268,349
========= =========
December 31, 1994 26,104 353,930
========= =========
December 31, 1995 21,637 330,524
========= =========
December 31, 1996 31,869 443,441
========= =========
</TABLE>
<TABLE>
<CAPTION>
STANDARDIZED MEASURE - DECEMBER 31,
----------------------------
1995 1996
----------- -----------
(IN THOUSANDS)
<S> <C> <C>
Future cash inflows $ 1,037,363 $ 3,144,813
Future costs:
Production (374,516) (781,550)
Development (57,959) (233,617)
----------- -----------
Future net cash flows 604,888 2,129,646
Undiscounted income taxes (63,248) (540,520)
----------- -----------
After tax net cash flows 541,640 1,589,126
10% discount factor (210,534) (650,534)
----------- -----------
Standardized measure $ 331,106 $ 938,592
=========== ===========
</TABLE>
The table above includes standardized measure attributable to minority
interests of $129.5 million at December 31, 1996.
At December 31, 1995 and 1996, the Company's equity in the net
present value of Permtex proved reserves was $10.6 million and $25.8 million.
These amounts are not included in the standardized measure above.
48
<PAGE>
<TABLE>
<CAPTION>
CHANGES IN STANDARDIZED MEASURE -
YEAR ENDED DECEMBER 31,
------------------------------------------------
1994 1995 1996
----------- ----------- -----------
(IN THOUSANDS)
<S> <C> <C> <C>
Standardized measure, beginning of year $ 340,518 $ 361,682 $ 331,106
Revisions:
Prices and costs (73,330) 18,975 528,525
Quantities (42,260) (30,495) 10,915
Development costs (12,995) (2,806) (13,027)
Accretion of discount 34,052 36,168 46,045 (a)
Income taxes 2,195 16,249 (242,536)
Production rates and other (9,506) (29,991) 11,052
----------- ----------- -----------
Net revisions (101,844) 8,100 340,974
Extensions, discoveries and additions 68,002 18,171 111,797
Production (97,330) (96,232) (146,257)
Future development costs incurred 99,175 43,551 18,400
Purchases 55,072 31,142 330,225 (a)
Sales (1,911) (35,308) (47,653)
----------- ----------- -----------
Standardized measure, end of year $ 361,682 $ 331,106 $ 938,592
=========== =========== ===========
<FN>
(a) In 1996, $12.9 million in "Purchases" were included in "Accretion of
Discount" due to the significance of the accretion related to the
reserves purchased in the Acquisition.
</FN>
</TABLE>
49
<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 28.
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 from Exhibit 4.1.5 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 from
Exhibit 10.1.1 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 from Exhibit 10.2.1 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 from
Exhibit 10.3 to Registrant's Annual Report on Form 10-K for the
year ended December 31, 1994 (File No. 1-10509)
10.4 - Registrant's Profit Sharing & Savings Plan and Trust as amended
and restated effective October 1, 1993 -- incorporated by
reference from Exhibit 10.12 to the Registrant's Quarterly Report
on Form 10-Q for the quarter-ended September 30, 1993 (File No.
1-10509).
50
<PAGE>
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 from
Exhibit 10.1.2 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 - Formation and Capitalization Agreement dated as of December 30,
1996 among Registrant, SOCO International, Inc., SOCO
International Holdings, Inc., SOCO International Operations, Inc.
and Edward T. Story.*
10.9.1 - Promissory Note dated December 30, 1996 from Edward T. Story
payable to the order of SOCO International Holdings, Inc.*
10.9.2 - Promissory Note dated December 30, 1996 from Edward T. Story
payable to the order of SOCO International Operations, Inc.*
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 from Exhibit 10.11.1 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 from Exhibit
10.12.2 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 -- incorporated by reference from Exhibit
10.11.3 to Registrant's Annual Report on Form 10-K of the year
ended December 31, 1995 (File No. 1-10509).
10.11.4 - Fourth Amendment dated as of April 4, 1996 to Fifth Restated
Credit Agreement -- incorporated by reference to Registrant's
Quarterly Report on Form 10-Q for the quarter-ended March 31,
1996 (File No. 1-10509).
10.11.5 - Fifth Amendment dated as of November 1, 1996 to Fifth Restated
Credit Agreement.*
10.12 - Severance Agreement and Release dated November 14, 1995 between
Registrant and John A. Fanning -- incorporated by reference from
Exhibit 10.12 to Registrant's Annual Report on Form 10-K of the
year ended December 31, 1995 (File No. 1-10509).
51
<PAGE>
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 from 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.*
22.1 - Subsidiaries of the Registrant.*
23.1 - Consent of Arthur Andersen LLP.*
23.2 - Consent of Netherland, Sewell & Associates, Inc.*
23.3 - Consent of Ryder Scott Company Petroleum Engineers.*
27 - Financial Data Schedule.*
99.1 - Reserve letter from Netherland, Sewell & Associates, Inc. dated
February 5, 1997 to the Snyder Oil Corporation interest as of
December 31, 1996*
99.2 - Reserve letter from Netherland, Sewell & Associates, Inc. dated
February 5, 1997 to the Patina Oil & Gas Corporation interest as
of December 31, 1996*
99.3 - Reserve letter from Ryder Scott Company Petroleum Engineers dated
February 5, 1997 to the SOCO Offshore, Inc. interest as of
December 31, 1996*
(b) No reports on Form 8-K in the fourth quarter of 1996.
* Filed herewith.
52
<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 Director and Chairman of the Board March 10, 1997
- ------------------------ (Principal Executive Officer)
John C. Snyder
/S/ ROGER W. BRITTAIN Director March 10, 1997
- ------------------------
Roger W. Brittain
/S/ JOHN A. HILL Director March 10, 1997
- ------------------------
John A. Hill
/S/ WILLIAM J. JOHNSON Director March 10, 1997
- ------------------------
William J. Johnson
/S/ B. J. KELLENBERGER Director March 10, 1997
- ------------------------
B. J. Kellenberger
/S/ JAMES E. MCCORMICK Director March 10, 1997
- ------------------------
James E. McCormick
/S/ ALFRED M. MICALLEF Director March 10, 1997
- ------------------------
Alfred M. Micallef
/S/ EDWARD T. STORY Director and March 10, 1997
- ------------------------ Vice President - International
Edward T. Story
/S/ JAMES H. SHONSEY Vice President - Finance March 10, 1997
- ------------------------ (Principal Financial and
James H. Shonsey Accounting Officer)
53
<PAGE>
<TABLE>
SCHEDULE I
SNYDER OIL CORPORATION (PARENT COMPANY)
CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS)
<CAPTION>
DECEMBER 31,
-------------------------------
1995 1996
------------ ------------
ASSETS
<S> <C> <C>
Current assets
Cash and equivalents $ 27,263 $ 21,769
Accounts receivable 29,259 38,968
Inventory and other 11,769 9,755
------------ ------------
68,291 70,492
------------ ------------
Investments 33,220 245,610
------------ ------------
Oil and gas properties, successful efforts method 675,961 328,649
Accumulated depletion, depreciation and amortization (240,744) (91,902)
------------ ------------
435,217 236,747
------------ ------------
Gas facilities and other 30,506 16,558
Accumulated depreciation and amortization (11,741) (4,251)
------------ ------------
18,765 12,307
------------ -------------
$ 555,493 $ 565,156
============ ============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities
Accounts payable $ 36,353 $ 36,804
Accrued liabilities 26,096 25,534
------------ ------------
62,449 62,338
------------ ------------
Senior debt 150,001 93,731
Convertible subordinated notes 84,058 80,748
Deferred taxes payable - 9,034
Other noncurrent liabilities 20,016 18,233
Minority interest 3,601 6,404
Commitments and contingencies
Stockholders' equity
Preferred stock, $.01 par, 10,000,000 shares authorized,
6% Convertible preferred stock, 1,035,000 and 1,033,500
shares issued and outstanding 10 10
Common stock, $.01 par, 75,000,000 shares authorized,
31,430,227 and 31,456,027 issued 314 315
Capital in excess of par value 265,911 260,221
Retained earnings (deficit) (29,001) 25,711
Common stock held in treasury, 134,191 and 250,000 shares at cost (2,457) (3,510)
Unrealized foreign currency translation gain 380 -
Unrealized gain on investments 211 11,921
------------ ------------
235,368 294,668
------------ ------------
$ 555,493 $ 565,156
============ ============
See "Notes to Consolidated Financial Statements" of the
Snyder Oil Corporation Consolidated Financial Statements included in this report.
</TABLE>
54
<PAGE>
<TABLE>
SCHEDULE I
SNYDER OIL CORPORATION (PARENT COMPANY)
CONSOLIDATED STATEMENTS OF OPERATIONS
(IN THOUSANDS EXCEPT PER SHARE DATA)
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------------------
1994 1995 1996
---------- ---------- ----------
<S> <C> <C> <C>
Revenues
Oil and gas sales $ 137,858 $ 144,608 $ 121,967
Gas transportation, processing and marketing 107,247 38,256 17,655
Gains on sales of equity interests in investees 9,747 2,183 69,343
Gains on sales of properties 1,969 12,254 8,786
Equity in earnings of Patina - - 1,554
Other 5,507 4,859 6,320
--------- --------- ---------
262,328 202,160 225,625
--------- --------- ---------
Expenses
Direct operating 46,267 52,486 37,736
Cost of gas and transportation 94,177 29,374 15,020
Exploration 6,505 8,033 4,094
General and administrative 12,853 17,680 13,129
Interest and other 12,463 27,001 16,218
Litigation settlement - 4,400 -
Loss on sale of subsidiary interest - - 15,481
Depletion, depreciation and amortization 70,770 76,378 49,032
Property impairments 5,783 27,412 2,753
--------- --------- ---------
Income (loss) before taxes and minority interest 13,510 (40,604) 72,162
--------- --------- ---------
Provision (benefit) for income taxes
Current - 25 33
Deferred 967 (1,370) 4,313
--------- --------- ---------
967 (1,345) 4,346
--------- --------- ---------
Minority interest (171) (572) (4,866)
--------- --------- ---------
Net income (loss) $ 12,372 $ (39,831) $ 62,950
========= ========= =========
Net income (loss) per common share $ .07 $ (1.53) $ 1.81
========= ========= =========
Weighted average shares outstanding 23,704 30,186 31,308
========= ========= =========
See "Notes to Consolidated Financial Statements" of the
Snyder Oil Corporation Consolidated Financial Statements included in this report.
</TABLE>
55
<PAGE>
<TABLE>
SCHEDULE I
SNYDER OIL CORPORATION (PARENT COMPANY)
CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------------------------
1994 1995 1996
----------- ----------- -----------
<S> <C> <C> <C>
Operating activities
Net income (loss) $ 12,372 $ (39,831) $ 62,950
Adjustments to reconcile net income (loss) to net
cash provided by operations
Amortization of deferred credits (2,986) (2,511) (966)
Gains on sales of investments (9,747) (809) (68,343)
Gains on sales of properties (1,969) (12,254) (8,786)
Equity in (earnings) losses of unconsolidated subsidiaries (1,355) 1,319 (1,975)
Exploration expense 6,505 8,033 4,094
Loss on sale of subsidiary interest - - 15,481
Depletion, depreciation and amortization 70,770 76,378 49,032
Property impairments 5,783 27,412 2,753
Deferred taxes 967 (1,370) 4,313
Minority interest 171 572 4,866
Changes in current and other assets and liabilities
Decrease (increase) in
Accounts receivable 11,024 7,142 (12,025)
Inventory and other (9,241) 3,617 3,583
Increase (decrease) in
Accounts payable 1,901 (8,521) 4,502
Accrued liabilities 1,841 5,165 (69)
Other liabilities 361 4,779 (346)
----------- ----------- -----------
Net cash provided by operations 86,397 69,121 59,064
----------- ----------- -----------
Investing activities
Acquisition, development and exploration (237,879) (92,353) (93,368)
Purchase of controlling interest in subsidiary (6,645) - -
Proceeds from investments 5,019 14,786 1,635
Outlays for investments (8,804) - (9,013)
Proceeds from sales of properties 2,806 109,988 72,510
----------- ----------- -----------
Net cash realized (used) by investing (245,503) 32,421 (28,236)
----------- ----------- -----------
Financing activities
Issuance of common 1,157 688 1,523
Increase (decrease) in indebtedness 187,138 (86,193) (12,814)
Debt issuance costs (2,855) - -
Dividends (16,721) (14,056) (14,411)
Deferred credits 2,356 3,549 62
Repurchase of stock (1,149) - (7,186)
Repurchase of subordinated notes - - (3,496)
----------- ----------- -----------
Net cash realized (used) by financing 169,926 (96,012) (36,322)
----------- ----------- -----------
Increase in cash 10,820 5,530 (5,494)
Cash and equivalents, beginning of year 10,913 21,733 27,263
----------- ----------- -----------
Cash and equivalents, end of year $ 21,733 $ 27,263 $ 21,769
=========== =========== ===========
Noncash investing and financing activities
Gas plant capital lease $ 21,000 - -
Acquisition of properties and stock via stock issuances - $ 13,032 $ 3,693
Acquisition of properties recorded as senior debt - - $ 31,730
Acquisition via subsidiary stock issuance - - $ 115,067
See "Notes to Consolidated Financial Statements" of the
Snyder Oil Corporation Consolidated Financial Statements included in this report.
</TABLE>
56
EXHIBIT 10.9
FORMATION AND CAPITALIZATION AGREEMENT
This Formation and Capitalization Agreement (this "Agreement") is
entered into as of the 30th day of December, 1996 by and between Snyder Oil
Corporation, a Delaware corporation ("Snyder"), SOCO International, Inc., a
Delaware corporation ("SOCO International"), SOCO International Holdings, Inc.,
a Delaware corporation ("Holdings"), SOCO International Operations, Inc., a
Delaware corporation ("Operations") and Edward T. Story, Jr., a resident of the
State of Texas ("Story").
WHEREAS, SOCO International is a wholly owned subsidiary of Snyder;
WHEREAS, SOCO International has recently incorporated and organized
Operations and Holdings as wholly-owned subsidiaries of SOCO International;
WHEREAS, SOCO International owns beneficially and of record one share of
the common stock of Operations ("Operations Common Stock") and one share of the
common stock of Holdings ("Holdings Common Stock");
WHEREAS, pursuant to that certain agreement by and between Snyder and
Story dated as of April 30, 1993 (the "1993 Agreement"), Story holds a
non-compensatory option (the "Option") to acquire 100 shares of common stock
(10% of the then outstanding shares) of SOCO International, which Option was
received in exchange for common stock of SOCO International then held by Story;
WHEREAS, Story and International desire to capitalize Operations and
Holdings by contributing the assets described herein to such corporations in the
manner set forth herein, subject to the assumption of the liabilities described
herein;
NOW THEREFORE, in consideration of the premises set forth above, the
mutual covenants set forth herein and other good and valuable consideration, the
receipt and sufficiency of which are hereby acknowledged, the parties hereto
agree as follows:
1. DEFINITIONS.
(a) "EFFECTIVE TIME" shall mean 9:00 a.m. (Houston time) on
the date first set forth above.
(b) "CAIRN SHARES" shall mean the shares of capital stock of
Cairn Energy Plc owned beneficially or of record by SOCO International
immediately prior to the Effective Time.
(c) "HOLDINGS ASSETS" shall mean SOCO International's right,
title and interest in any rights, privileges, powers, franchises,
properties or assets related to the Cairn Shares, (including any
dividends and distributions with respect thereto) immediately prior to
the Effective Time.
(d) "OPERATIONS ASSETS" shall mean SOCO International's
right, title and interest in any rights, privileges, powers,
franchises, properties or assets immediately prior to the Effective
Time, but specifically excluding the Holdings Assets.
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<PAGE>
(e) "LIABILITIES" shall mean all losses, claims, taxes,
fines, penalties, damages, costs (including costs of investigation)
expenses (including reasonable legal fees and expenses) and other
liabilities, whether joint or several.
(f) "INTERCOMPANY DEBT" shall mean the intercompany
indebtedness owed by SOCO International to Snyder as of the Effective
Time, which had a balance of $34,504,390 as of November 30, 1996.
(g) "HOLDINGS LIABILITIES" shall mean SOCO International's
Liabilities related to the Holdings Assets and (ii) the Intercompany
Debt.
(h) "OPERATIONS LIABILITIES" shall mean SOCO International's
Liabilities relating to the Operations Assets, but specifically
excluding the Holdings Liabilities.
(i) "SOCO INTERNATIONAL INDEMNIFIED PARTIES" shall mean SOCO
International and its subsidiaries (other than Operations, Holdings
and their respective subsidiaries) and any officer, director,
employee, agent or other representative thereof (individually, a "SOCO
International Indemnified Party").
(j) "OPERATIONS INDEMNIFIED PARTIES" shall mean Operations
and its subsidiaries and any officer, director, employee, agent or
other representative thereof (individually, an "Operations Indemnified
Party").
(k) "HOLDINGS INDEMNIFIED PARTIES" shall mean Holdings and
its subsidiaries and any officer, director, employee, agent or other
representative thereof (individually, an "Holdings Indemnified
Party").
2. CAPITALIZATION OF OPERATIONS. (a) Effective as of the Effective Time,
SOCO International and Story hereby contribute to Operations the assets
described in paragraphs (b) and (c) hereof, respectively. In consideration for
such contributions, Operations hereby issues shares of Operations Common Stock
to SOCO International and Story in the respective amounts set forth below:
<TABLE>
<CAPTION>
TOTAL SHARES
OF OPERATIONS
SHARES OF OPERATIONS SHARES OF OPERATIONS COMMON STOCK OWNED
COMMON STOCK COMMON STOCK TO BE IMMEDIATELY FOLLOWING
SHAREHOLDER CURRENTLY OWNED ISSUED AT EFFECTIVE TIME EFFECTIVE TIME
- ----------- --------------- ------------------------ ---------------------
<S> <C> <C> <C>
SOCO 1 899 900
International
Story 0 100 100
- --- -----
Total 1 999 1,000
= === =====
</TABLE>
(b) Effective as of the Effective Time, (i) SOCO International hereby
transfers, sells, assigns, bargains and conveys to Operations all of SOCO
International's right, title and interest in the Operations Assets, and (ii)
Operations hereby assumes all of the Operations Liabilities.
(c) Effective as of the Effective Time, Story hereby (i) transfers,
sells, assigns, bargains and conveys to Operations such portion of Story's
right, title and interest in the Option as it relates
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<PAGE>
to the right to purchase 45.65 shares of the common stock of SOCO International
(together with 45.65% of Story's remaining rights under the 1993 Agreement), and
(ii) delivers to Operations a recourse promissory note from Story in the
principal amount of $269,563.25 and substantially in the form attached hereto as
Exhibit A (the "Operations Note").
(d) Effective as of the Effective Time, Operations hereby delivers to
International and Story certificates for the shares of Operations Common Stock
issued pursuant to this Section 2.
3. CAPITALIZATION OF HOLDINGS. (a) Effective as of the Effective Time,
SOCO International and Story hereby contribute to Holdings the assets described
in paragraphs (b) and (c) hereof, respectively. In consideration for such
contributions, Holdings hereby issues shares of Holdings Common Stock to SOCO
International and Story in the respective amounts set forth below:
<TABLE>
TOTAL SHARES
OF HOLDINGS
SHARES OF HOLDINGS SHARES OF HOLDINGS COMMON STOCK OWNED
COMMON STOCK COMMON STOCK TO BE IMMEDIATELY FOLLOWING
SHAREHOLDER CURRENTLY OWNED ISSUED AT EFFECTIVE TIME EFFECTIVE TIME
- ----------- --------------- ------------------------ ---------------------
<S> <C> <C> <C>
SOCO
International 1 899 900
Story 0 100 100
- --- -----
Total 1 999 1,000
= === =====
</TABLE>
(b) Effective as of the Effective Time, (i) SOCO International hereby
transfers, sells, assigns, bargains and conveys to Holdings all of SOCO
International's right, title and interest in all of the Holdings Assets, and
(ii) Holdings hereby assumes the Holdings Liabilities.
(c) Effective as of the Effective Time, Story hereby (i) transfers,
sells, assigns, bargains and conveys to Holdings such portion of Story's right,
title and interest in the Option as it relates to the right to purchase 54.35
shares of the common stock of SOCO International (together with 54.35% of
Story's remaining rights under the 1993 Agreement), and (ii) delivers to
Holdings a recourse promissory note from Story in the principal amount of
$320,936.75 and substantially in the form attached hereto as Exhibit A (the
"Holdings Note"). The parties hereto acknowledge that after the transfer of the
Option pursuant to Sections 2(c) and 3(c) hereof, Story shall have no further
rights under the Option or the 1993 Agreement, and all such rights shall be
transferred to Operations and Holdings in the respective amounts set forth
herein. In accordance with paragraph 8 of the 1993 Agreement, Snyder hereby
consents to the assignments of the Option contemplated by this Agreement.
(d) Effective as of the Effective Time, Holdings hereby delivers to
International and Story certificates for the shares of Holdings Common Stock
issued pursuant to this Section 3.
4. INDEMNIFICATION.
(a) Operations shall defend, indemnify and hold harmless the SOCO
International Indemnified Parties and the Holdings Indemnified Parties against
any and all Operations Liabilities, whether or not the result of the sole or
partial negligence or otherwise culpable conduct or fault of one or more of the
SOCO International Indemnified Parties or the Holdings Indemnified Parties.
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<PAGE>
(b) Holdings shall defend, indemnify and hold harmless the SOCO
International Indemnified Parties and the Operations Indemnified Parties against
any and all Holdings Liabilities, whether or not the result of the sole or
partial negligence or otherwise culpable conduct or fault of one or more of the
SOCO International Indemnified Parties or the Operations Indemnified Parties.
5. INDEMNIFICATION PROCEDURE. Each person to be indemnified pursuant to
this Agreement (an "Indemnified Party") agrees to give prompt notice to the
indemnifying party of the assertion of any claim, or the commencement of any
suit, action or proceeding, brought against or sought to be collected from such
Indemnified Party (each a "Third Party Claim"), in respect of which indemnity
may be sought by such Indemnified Party under this Agreement; provided that the
omission so to promptly notify the indemnifying party with respect to a Third
Party Claim brought against or sought to be collected from such Indemnified
Party will not relieve the indemnifying party from any Liability that it may
have to such Indemnified Party under this Agreement except to the extent that
such failure has materially prejudiced such indemnifying party with respect to
the defense of such Third Party Claim. If any Indemnified Party shall seek
indemnity under this Agreement with respect to a Third Party Claim brought
against or sought to be collected from such Indemnified Party, the indemnifying
party shall be entitled to participate therein and, to the extent that it
wishes, to assume and direct the defense and settlement thereof with counsel
satisfactory to such Indemnified Party. After notice from the indemnifying party
to an Indemnified Party of its election to assume and direct the defense and
settlement of a Third Party Claim brought against or sought to be collected from
such Indemnified Party that such indemnifying party is entitled to assume and
direct under the terms hereof, the indemnifying party shall not be liable to
such Indemnified Party under this Agreement for any legal or other expenses
subsequently incurred by such Indemnified Party in connection with the defense
thereof other than reasonable costs of investigation, unless the Indemnifying
Party and the Indemnified Party are both named parties to any such action, claim
or demand and representation of both parties by the same counsel would be
inappropriate due to actual or potential conflicts of interest between them.
Notwithstanding the foregoing provisions of this Section 5, the indemnifying
party shall not (A) without the prior written consent of an Indemnified Party,
effect any settlement of any pending or threatened proceeding in respect of
which such Indemnified Party is, or with reasonable foreseeability, could have
been a party and indemnity could have been sought hereunder by such Indemnified
Party for a Third Party Claim brought against or sought to be collected from
such Indemnified Party, unless such settlement includes an unconditional
release, in form and substance satisfactory to the Indemnified Party, of such
Indemnified Party from all Liability arising out of such proceeding (provided
that, whether or not such a release is required to be obtained, the indemnifying
party shall remain liable to such Indemnified Party in accordance with this
Agreement in the event that a Third Party Claim is subsequently brought against
or sought to be collected from such Indemnified Party) or (B) be liable for any
settlement of any Third Party Claim brought against or sought to be collected
from an Indemnified Party effected without such indemnifying party's written
consent (which shall not be unreasonably withheld), but if settled with such
indemnifying party's written consent, or if there is a final judgment for the
plaintiff in any such Third Party Claim, such indemnifying party agrees (to the
extent stated above) to indemnify the Indemnified Party from and against any
loss, liability, claim, damage or expense by reason or such settlement or
judgment. The indemnification required by this Agreement shall be made by
payments of the amount thereof during the course of the investigation or
defense, as and when bills are received or loss, liability, claim, damage or
expense is incurred.
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<PAGE>
6. REPRESENTATIONS. In order to induce each other party to enter into
this Agreement, each party hereto hereby represents and warrants to each other
party hereto that (a) this Agreement has been duly authorized by such party by
all necessary corporate action (to the extent such party is a corporation), (b)
such party has the legal capacity to enter into this Agreement (to the extent
such party is an individual), (c) the performance by such party of the
obligations contemplated hereby to be performed by such party do not conflict
with the organizational documents (to the extent such party is a corporation) or
any agreement, judgment, order, law, regulation, rule or instrument to which
such party is subject. Without limiting the generality of the foregoing, Snyder
and Story each represent that the 1993 Agreement and the Option granted therein
are in full force and effect, that such party is not in breach thereof and that
such party has not assigned or transferred any rights thereunder, or attempted
to do so, except as expressly contemplated by this Agreement.
7. SECURITIES LAW MATTERS. SOCO International and Story represent to
each other and to Operations and Holdings that they are knowledgeable and
sophisticated investors with respect to the type of business to be conducted by
Operations and Holdings and that they have had access to such information as
they have requested in connection therewith. SOCO International and Story
acknowledge that the shares of Operations Common Stock and Holdings Common Stock
received by them will not be registered under the federal or any state
securities laws, that no party shall have any obligation to register such
shares, and that no sale, transfer or other disposition of such shares may be
made without registration or an exemption therefrom. The certificates for shares
of the Operations Common Stock and Holdings Common Stock shall bear such legends
as the issuer thereof shall deem appropriate with respect to the foregoing.
8. FURTHER ASSURANCES. (a)If at any time after the date hereof either
Operations or Holdings shall consider or be advised that any deeds, bills of
sale, stock powers, assignments, other documents or assurances or any other acts
or things are necessary, desirable or proper to vest, perfect or confirm, of
record or otherwise, any of the rights, privileges, powers, franchises,
properties or assets purported to be transferred pursuant hereto, SOCO
International or Story, as applicable, shall execute and deliver all such deeds,
bills of sale, stock powers, assignments, other documents and assurances and do
all such other acts and things necessary, desirable or proper to vest, perfect
or confirm the right, title or interest of Operations or Holdings, as the case
may be, in, to or under any of the rights, privileges, powers, franchises,
properties or assets purported to be transferred pursuant hereto.
(b) If at any time after the date hereof SOCO International shall
consider or be advised that assumptions, other documents, assurances or other
acts or other things are necessary, desirable or proper for Operations or
Holdings, as the case may be, to effectively assume any of the obligations or
liabilities purported to be assumed hereby, Operations or Holdings, as the case
may be, shall execute and deliver all such assumptions, other documents and
assurances and do all such other acts and things necessary, desirable or proper
to effectively assume any of the obligations or liabilities purported to be
assumed hereby.
(c) Notwithstanding the foregoing or the terms and conditions of
such additional documents, acts or things, such additional documents, acts or
things shall neither increase nor decrease the scope of the assignment and
assumption contemplated by this Agreement.
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<PAGE>
9. ASSIGNMENT. Except by operation of law or in connection with the sale
of all or substantially all the assets of a party hereto, this Agreement shall
not be assignable, in whole or in part, directly or indirectly, by any party
hereto without the written consent of the other parties, and any attempt to
assign any rights or obligations arising under this Agreement without such
consent shall be void; provided, however, that the provisions of this Agreement
shall be binding upon, inure to the benefit of and be enforceable by the parties
hereto and their respective successors and permitted assigns.
10. PARTIES IN INTEREST. Except as herein otherwise specifically
provided, nothing in this Agreement expressed or implied is intended to confer
any right or benefit upon any person, firm or corporation or other entity other
than the parties hereto, the SOCO International Indemnified Parties, the
Operations Indemnified Parties and the Holdings Indemnified Parties, and their
respective successors and permitted assigns.
11. WAIVERS, ETC. No failure or delay on the part of the parties hereto
in exercising any power or right hereunder shall operate as a waiver thereof,
nor shall any single or partial exercise of any such right or power, or any
abandonment or discontinuance of steps to enforce such a right or power,
preclude any other or further exercise thereof or the exercise of any other
right or power. No modification or waiver of any provision of this Agreement nor
consent to any departure by any parties therefrom shall in any event be
effective unless the same shall be in writing and signed by all such parties,
and then such waiver or consent shall be effective only in the specific instance
and for the purpose for which given and only against those parties who have
executed such writing.
12. SEVERABILITY. If any term, provision, covenant or restriction of
this Agreement is held by a court of competent jurisdiction to be invalid, void
or unenforceable, the remainder of the terms, provisions, covenants and
restrictions set forth herein shall remain in full force and effect and shall in
no way be affected, impaired or invalidated. It is hereby stipulated and
declared to be the intention of the parties that they would have executed the
remaining terms, provisions, covenants and restrictions without including any
thereof which may be hereafter declared invalid, void or unenforceable. In the
event that any such term, provision, covenant or restriction is held to be
invalid, void or unenforceable, the parties hereto shall use their reasonable
efforts to find and employ an alternate means to achieve the same or
substantially the same result as that contemplated by such term, provision,
covenant or restriction.
13. NOTICES. Any notices to be given hereunder shall be in writing and
shall be deemed to be sufficiently given when delivered personally or sent
certified or registered mail, postage prepaid and return receipt requested, or
by telecopy, and if intended for Story addressed to:
Edward T. Story, Jr.
SOCO International, Inc.
1221 Lamar Street, Suite 1200
Houston, Texas 77010
Telecopy No.: (713) 646-6676
6
<PAGE>
or if intended for Snyder, SOCO International, Operations or Holdings,
addressed to:
Snyder Oil Corporation
777 Main Street, Suite 2500
Fort Worth, Texas 76012
Attention: General Counsel
Telecopy No.: (817) 882-5982
Any party hereto may change the address for receiving notice upon notice to the
other parties given in the manner set forth in this Section 13.
14. GOVERNING LAW. This Agreement shall be governed by and construed
in accordance with the laws of the State of Delaware, without giving effect to
the principles of conflicts of law thereof.
15. AMENDMENT. This Agreement may be amended or otherwise modified
only by a writing duly executed by each of the parties hereto or their
respective successors or assigns.
16. HEADINGS. The section headings used in this Agreement are for
convenience only and shall not be considered a part of, or affect the
construction or interpretation of, any provisions of this
Agreement.
17. EXECUTION OF COUNTERPARTS. This Agreement may be executed in
counterparts, and each such counterpart shall be deemed to be an original
instrument, but all such counterparts together for all purposes shall constitute
one agreement.
EXECUTED as of the day and year first written above.
SNYDER OIL CORPORATION
By:/s/Thomas J. Edelman
-----------------------
Name: Thomas J. Edelman
Title: President
SOCO INTERNATIONAL, INC.
By:/s/Edward T. Story, Jr.
--------------------------
Name: Edward T. Story, Jr.
Title: President
7
<PAGE>
SOCO INTERNATIONAL HOLDINGS, INC.
By:/s/Edward T. Story, Jr.
--------------------------
Name: Edward T. Story, Jr.
Title: President
SOCO INTERNATIONAL OPERATIONS, INC.
By:/s/Edward T. Story, Jr.
--------------------------
Name: Edward T. Story, Jr.
Title: President
/s/Edward T. Story, Jr.
-----------------------
EDWARD T. STORY, JR.
8
EXHIBIT 10.9.1
PROMISSORY NOTE
THIS ISSUANCE OF THIS NOTE HAS NOT BEEN REGISTERED OR QUALIFIED UNDER
THE SECURITIES ACT OF 1933 OR THE SECURITIES LAWS OF ANY STATE. THIS NOTE MAY
NOT BE SOLD OR TRANSFERRED IN THE ABSENCE OF REGISTRATION OR QUALIFICATION UNDER
SAID ACT OR ANY APPLICABLE STATE SECURITIES LAWS OR AN EXEMPTION THEREFROM.
$320,936.75 December 30, 1996
- ----------- -----------------
EDWARD T. STORY, a resident of the State of Texas ("Maker"), For Value
Received, promises and agrees to pay to the order of SOCO International
Holdings, Inc. ("Payee"), at Snyder Oil Corporation, 777 Main Street, Suite
2500, Fort Worth, Texas, 76012, Attention: General Counsel, or at such other
address as to which Payee (or any subsequent holder of this Note) shall notify
Maker in writing, in lawful money of the United States of America, the principal
sum of Three Hundred Twenty Thousand Nine Hundred Thirty-Six and 75/100 Dollars
($320,936.75), on or before April 10, 1998 (the "Scheduled Maturity Date"),
payable together with interest on the unpaid balance thereof as provided below.
1. INTEREST. Interest shall accrue from and after the date hereof on
the principal balance hereof from time to time remaining unpaid at One Percent
(1%) per calendar month. Interest shall be payable on or before the Scheduled
Maturity Date.
2. PREPAYMENTS. Principal and interest on this Note may be prepaid at
any time without premium or penalty.
3. ACCELERATION UPON EVENTS OF DEFAULT. Payee, or any subsequent
holder of this Note, may declare all unpaid amounts of principal and interest
hereunder immediately due and payable by giving Maker notice of acceleration
after the occurrence of an Event of Default (as hereinafter defined). An "Event
of Default" shall occur (i) upon the failure by Maker to pay any amounts due
under this Note as and when they become due and payable, but only if such
failure continues for a period of five days after written notice thereof is
dispatched by Payee to Maker, (ii) upon the filing of a petition, consent to
relief or the entry of a decree or order by a court having jurisdiction in the
premises for relief in respect of Maker under Title 11 of the United States
Code, as now constituted or hereafter amended or (iii) upon the breach or
violation by Maker of any representation, warranty, covenant or provision of
that certain Formation and Capitalization Agreement by and among Snyder Oil
Corporation, SOCO International, Inc., SOCO International Operations, Inc.,
Payee and Edward T. Story, dated as of December 30, 1996, but only if such
breach or violation continues for a period of 15 days after written notice
thereof is dispatched by Payee to Maker.
4. ATTORNEY'S FEES. If an Event of Default shall occur and this Note
is placed in the hands of an attorney for collection, or suit is filed hereon,
or bankruptcy proceedings are commenced by or against Maker, or probate,
receivership or other judicial proceedings for the establishment or collection
of any amount called for hereunder are commenced, or any amount payable or to be
payable hereunder is collected through any such proceedings, Maker agrees to pay
to the owner and holder of this Note a reasonable amount as attorney's or
collection fees.
5. WAIVERS. Maker, and all persons liable or who become liable for all
or any part of this Note, expressly waive demand and presentment for payment,
notice of nonpayment, protest, demand,
1
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notice of protest, notice of dishonor, dishonor, bringing of suit, notice of
extension and diligence in taking any action to collect amounts called for
hereunder and in the handling of securities at any time existing in connection
herewith; and are liable for the payment of all sums owing and to be owing
hereon, regardless of and without any notice, diligence, act or omission as or
with respect to the collection of any amount called for hereunder or in
connection with any right, lien, interest or property at any and all times had
or existing as security for any amount called for hereunder.
6. NO RELEASE. The granting to Maker of an extension or extensions of
time for the payment of any sum or sums due under this Note or any other
agreement by the Maker with the Payee or any subsequent holder of this Note, or
the exercise of or failure to exercise any right or power under this Note, or
any agreement by the Maker with the Payee or any subsequent holder of this Note,
shall not in any way release or affect the liability of Maker, any guarantor
hereof, or any other party obligated to pay the indebtedness evidenced by this
Note.
7. SEVERABILITY. If any provision of this Note or the application
thereof to any party or circumstance is held invalid or unenforceable, the
remainder of this Note and the application of such provision to other parties or
circumstances shall not be affected thereby, the provisions of this Note being
severable in any such instance.
8. SUCCESSORS. This Note shall be binding upon and shall inure to the
benefit of Maker and Payee and their respective successors and assigns.
9. GOVERNING LAW. The terms of this Note shall be governed by, and
interpreted in accordance with the provisions of, the laws of the State of
Delaware including without limitation, all matters of construction, validity,
performance and enforcement and without giving effect to the principles of
conflict of laws.
/s/Edward T. Story, Jr.
--------------------------------
EDWARD T. STORY, JR.
2
EXHIBIT 10.9.2
PROMISSORY NOTE
THIS ISSUANCE OF THIS NOTE HAS NOT BEEN REGISTERED OR QUALIFIED UNDER
THE SECURITIES ACT OF 1933 OR THE SECURITIES LAWS OF ANY STATE. THIS NOTE MAY
NOT BE SOLD OR TRANSFERRED IN THE ABSENCE OF REGISTRATION OR QUALIFICATION UNDER
SAID ACT OR ANY APPLICABLE STATE SECURITIES LAWS OR AN EXEMPTION THEREFROM.
$269,563.25 December 30, 1996
- ----------- -----------------
EDWARD T. STORY, a resident of the State of Texas ("Maker"), For Value
Received, promises and agrees to pay to the order of SOCO International
Operations, Inc. ("Payee"), at Snyder Oil Corporation, 777 Main Street, Suite
2500, Fort Worth, Texas, 76012, Attention: General Counsel, or at such other
address as to which Payee (or any subsequent holder of this Note) shall notify
Maker in writing, in lawful money of the United States of America, the principal
sum of Two Hundred Sixty-Nine Thousand Five Hundred Sixty-Three and 25/100
Dollars ($269,563.25), on or before April 10, 1998 (the "Scheduled Maturity
Date"), payable together with interest on the unpaid balance thereof as provided
below.
1. Interest. Interest shall accrue from and after the date hereof on
the principal balance hereof from time to time remaining unpaid at One Percent
(1%) per calendar month. Interest shall be payable on or before the Scheduled
Maturity Date.
2. Prepayments. Principal and interest on this Note may be prepaid at
any time without premium or penalty.
3. Acceleration upon Events of Default. Payee, or any subsequent
holder of this Note, may declare all unpaid amounts of principal and interest
hereunder immediately due and payable by giving Maker notice of acceleration
after the occurrence of an Event of Default (as hereinafter defined). An "Event
of Default" shall occur (i) upon the failure by Maker to pay any amounts due
under this Note as and when they become due and payable, but only if such
failure continues for a period of five days after written notice thereof is
dispatched by Payee to Maker, (ii) upon the filing of a petition, consent to
relief or the entry of a decree or order by a court having jurisdiction in the
premises for relief in respect of Maker under Title 11 of the United States
Code, as now constituted or hereafter amended or (iii) upon the breach or
violation by Maker of any representation, warranty, covenant or provision of
that certain Formation and Capitalization Agreement by and among Snyder Oil
Corporation, SOCO International, Inc., SOCO International Holdings, Inc., Payee
and Edward T. Story, dated as of December 30, 1996, but only if such breach or
violation continues for a period of 15 days after written notice thereof is
dispatched by Payee to Maker.
4. Attorney's Fees. If an Event of Default shall occur and this Note
is placed in the hands of an attorney for collection, or suit is filed hereon,
or bankruptcy proceedings are commenced by or against Maker, or probate,
receivership or other judicial proceedings for the establishment or collection
of any amount called for hereunder are commenced, or any amount payable or to be
payable hereunder is collected through any such proceedings, Maker agrees to pay
to the owner and holder of this Note a reasonable amount as attorney's or
collection fees.
5. Waivers. Maker, and all persons liable or who become liable for all
or any part of this Note, expressly waive demand and presentment for payment,
notice of nonpayment, protest, demand,
1
<PAGE>
notice of protest, notice of dishonor, dishonor, bringing of suit, notice of
extension and diligence in taking any action to collect amounts called for
hereunder and in the handling of securities at any time existing in connection
herewith; and are liable for the payment of all sums owing and to be owing
hereon, regardless of and without any notice, diligence, act or omission as or
with respect to the collection of any amount called for hereunder or in
connection with any right, lien, interest or property at any and all times had
or existing as security for any amount called for hereunder.
6. No Release. The granting to Maker of an extension or extensions of
time for the payment of any sum or sums due under this Note or any other
agreement by the Maker with the Payee or any subsequent holder of this Note, or
the exercise of or failure to exercise any right or power under this Note, or
any agreement by the Maker with the Payee or any subsequent holder of this Note,
shall not in any way release or affect the liability of Maker, any guarantor
hereof, or any other party obligated to pay the indebtedness evidenced by this
Note.
7. Severability. If any provision of this Note or the application
thereof to any party or circumstance is held invalid or unenforceable, the
remainder of this Note and the application of such provision to other parties or
circumstances shall not be affected thereby, the provisions of this Note being
severable in any such instance.
8. Successors. This Note shall be binding upon and shall inure to the
benefit of Maker and Payee and their respective successors and assigns.
9. Governing Law. The terms of this Note shall be governed by, and
interpreted in accordance with the provisions of, the laws of the State of
Delaware including without limitation, all matters of construction, validity,
performance and enforcement and without giving effect to the principles of
conflict of laws.
/s/Edward T. Story
---------------------------------
EDWARD T. STORY, JR.
2
EXHIBIT 10.11.5
FIFTH AMENDMENT TO FIFTH RESTATED CREDIT AGREEMENT
This Fifth Amendment to Fifth Restated Credit Agreement (this "FIFTH
AMENDMENT") is entered into as of the 1st day of November, 1996, by and among
Snyder Oil Corporation ("BORROWER"), NationsBank of Texas, N.A., as Agent
("AGENT"), and NationsBank of Texas, N.A. ("NATIONSBANK"), Bank One, Texas, N.A.
("BANK ONE"), Wells Fargo Bank, N.A. ("WELLS FARGO"), and Texas Commerce Bank
National Association ("TCB") as Banks (the "BANKS").
W I T N E S E T H:
WHEREAS, the Banks, Borrower and Agent are parties to that certain 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, (ii) Second Amendment to Fifth Restated Credit Agreement by and among
Borrower, Agent and the Banks dated as of June 30, 1995, (iii) Third Amendment
to Fifth Restated Credit Agreement by and among Borrower, Agent and the Banks
dated as of November 1, 1995, and (iv) Fourth Amendment to Fifth Restated Credit
Agreement by and among Borrower, Agent and the Banks dated as of April 4, 1996
(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) the Banks waive their right to
make a Special Determination of the Borrowing Base in connection with any sale
or sales of the Sale Properties (as herein defined), (ii) Section 9.2 of the
Credit Agreement be amended in certain respects, (iii) Section 9.11 of the
Credit Agreement be amended in certain respects, (iv) 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 on November 1, 1996 and continuing
until the next succeeding Determination Date be set forth herein, and (v) the
Banks extend the Facility B Termination Date to October 30, 1997; 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 5 hereof and in reliance on the representations,
warranties, covenants and agreements contained in this Fifth Amendment, the
Credit Agreement shall be amended effective November 1, 1996 (the "EFFECTIVE
DATE") in the manner provided in this SECTION 1.
1
<PAGE>
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 Fourth Amendment, the Fifth
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.
1.2. ADDITIONAL DEFINITIONS. Section 1.1 of the Credit Agreement shall
be amended to add the following definition to such Section:
"Fifth Amendment" means that certain Fifth Amendment to Fifth
Restated Credit Agreement dated as of November 1, 1996, by and among
Borrower, Agent and the Banks.
1.3. RESTRICTED PAYMENTS COVENANT. Section 9.2 of the Credit Agreement
shall be amended to read in full as follows:
SECTION 9.2. RESTRICTED PAYMENTS. Neither Borrower nor any
Restricted Subsidiary will declare or make any Restricted Payment;
provided, that, so long as no Default or Event of Default, Borrowing
Base Deficiency or noncompliance with SECTION 10.4 exists (without
giving effect to the cure periods provided by SECTION 4.4 or 10.4), and
provided further that no Default or Event of Default, Borrowing Base
Deficiency or non compliance with SECTION 10.4 would result from such
Restricted Payment (without giving effect to the cure periods provided
by SECTION 4.4 or 10.4), Borrower and Restricted Subsidiaries may (a)
make Restricted Payments in an aggregate amount (measured cumulatively
from January 1, 1996) not to exceed the sum of the following (i)
$75,000,000, plus (ii) the net cash proceeds to Borrower from all equity
offerings completed by Borrower of Borrower's equity securities after
January 1, 1996, plus (iii) all cash Distributions actually received by
Borrower or any Restricted Subsidiary from Unrestricted Subsidiaries
after January 1, 1996, plus (iv) fifty percent (50%) of Borrower's
Consolidated Cash Flow earned on or after January 1, 1996 to the earlier
of (y) the date of determination, or (z) December 31, 1996, (b) declare
and make a Qualified Redemption of the First Issue, (c) declare and make
a Qualified Redemption of the Second Issue, (d) declare and make a
Qualified Redemption of the Third Convertible Debentures, (e) issue the
First Convertible Debentures in exchange for the First Preferred Stock,
and (f) issue the Second Convertible Debentures in exchange for the
Second Preferred Stock. Notwithstanding the foregoing, the aggregate
amount of Distributions consisting of dividends paid on or with respect
to the Common Stock of Borrower shall not exceed $.30 per weighted
average share outstanding during any period of four (4) consecutive
fiscal quarters. Furthermore, provided, that, no Default or Event of
Default, Borrowing Base Deficiency or noncompliance with SECTION 10.4
has occurred which is continuing (without giving effect to the cure
periods provided by SECTION 4.4 or 10.4), on May 1, 1997, (Y) subsection
(a)(iv) of this SECTION 9.2 shall be automatically amended,
2
<PAGE>
without the necessity of any further action by Borrower, Agent or any
Bank, to read in full as follows: "(iv) fifty percent (50%) of
Borrower's Consolidated Cash Flow earned on or after January 1, 1996 to
the date of determination," and, (Z) the sentence immediately preceding
this sentence and beginning with the phrase "Notwithstanding the
foregoing" shall automatically be deleted in its entirety without the
necessity of any further action by Borrower, Agent or any Bank.
1.4. HEDGE TRANSACTIONS COVENANT. Section 9.11 of the Credit Agreement
shall be amended to read in full as follows:
SECTION 9.11. HEDGE TRANSACTIONS. Neither Borrower nor any of its
Restricted Subsidiaries shall enter into Hedge Transactions with the
exception that Borrower and its Restricted Subsidiaries may enter into
Hedge Transactions as long as (a) (i) the aggregate notional volume of
oil which is the subject of oil Hedge Transactions in existence at any
time does not exceed seventy-five percent (75%) of Borrower's and its
Restricted Subsidiaries' anticipated production of oil from proved,
developed producing reserves during the entire term of such existing
Hedge Transactions, and (ii) the notional volume of oil with respect to
which a settlement is required on a particular settlement date under
such oil Hedge Transactions shall not exceed (A) ninety percent (90%) of
Borrower's and its Restricted Subsidiaries anticipated production of oil
from proved, developed producing reserves for the period (a "Settlement
Period") from the immediately preceding settlement date under any oil
Hedge Transaction (or the commencement of such Hedge Transaction in the
event there is no prior settlement date) to such settlement date in the
case of any Settlement Period ending on or prior to April 30, 1997, and
(B) seventy five percent (75%) of Borrower's and its Restricted
Subsidiaries' anticipated production of oil from proved, developed
producing reserves for any Settlement Period thereafter, and (b) (i) the
aggregate notional volume of gas which is the subject of gas Hedge
Transactions in existence at any time does not exceed seventy-five
percent (75%) of Borrower's and its Restricted Subsidiaries' anticipated
production of gas from proved, developed producing reserves during the
entire term of such existing Hedge Transactions, and (ii) the notional
volume of gas with respect to which a settlement is required on a
particular settlement date under such gas Hedge Transactions shall not
exceed (A) ninety percent (90%) of Borrower's and its Restricted
Subsidiaries' anticipated production of gas from proved, developed
producing reserves for the Settlement Period ending on such settlement
date in the case of any Settlement Period ending on or prior to April
30, 1997, and (B) seventy five percent (75%) of Borrower's and its
Restricted Subsidiaries' anticipated production of gas from proved,
developed producing reserves for any Settlement Period thereafter.
SECTION 2. SALE OF SALE PROPERTIES. Borrower has advised the Banks that
Borrower intends to sell the Borrower's interest in some or all of the oil and
gas properties described on EXHIBIT I attached hereto (the "SALE PROPERTIES").
Borrower has further advised the Banks that it intends to complete any such sale
or sales of the Sale Properties pursuant to the exception to Section 9.5 of the
Credit Agreement contained in clause (z) of such Section, and Borrower has
requested that the Banks waive their right to make a Special Determination of
the Borrowing Base in connection with any such specific sale. The Banks hereby
(i) agree with Borrower that any sale or sales of the Sale
3
<PAGE>
Properties (the "APPROVED SALES") will be deemed sales under clause (z) of
Section 9.5 of the Credit Agreement and will not reduce or eliminate exceptions
to Section 9.5 of the Credit Agreement available under any other clause of
Section 9.5, and (ii) waive their right to require a Special Determination of
the Borrowing Base in connection with any such Approved Sales.
The waiver granted by the Banks in this SECTION 2 is expressly limited
as follows: (a) such waiver is limited solely to Section 9.5 of the Credit
Agreement and solely with respect to the Approved Sales, (b) such waiver shall
not be applicable to any provision of any Loan Paper other than Section 9.5 of
the Credit Agreement, and (c) such waiver is a limited, one-time waiver, and
nothing contained herein shall obligate the Banks to grant any additional, or
future waiver of Section 9.5 of the Credit Agreement or any other provision of
any Loan Paper.
SECTION 3. BORROWING BASE. In accordance with Section 4.1 and 4.4 of the
Credit Agreement, effective November 1, 1996, and continuing until the next
Determination Date, the Total Borrowing Base shall be $140,000,000, allocated as
follows: $90,000,000 to the Facility A Borrowing Base, and $50,000,000 to the
Facility B Borrowing Base.
SECTION 4. EXTENSION OF FACILITY B TERMINATION DATE. In accordance with
Section 2.9(b) of the Credit Agreement, Borrower has requested that the Banks
extend the Facility B Termination Date from April 3, 1997 to October 30, 1997.
The Facility B Termination Date is hereby extended from April 3, 1997 to October
30, 1997.
SECTION 5. CONDITIONS PRECEDENT TO EFFECTIVENESS OF AMENDMENTS. The
amendments to the Credit Agreement contained in SECTION 1 of this Fifth
Amendment shall be effective only upon, and are conditioned upon, the delivery
to Agent of such resolutions, certificates and other documents as Agent shall
request relative to the authorization, execution and delivery by Borrower of
this Fifth Amendment. If the foregoing condition has not been satisfied by the
Effective Date, this Fifth Amendment and all obligations of the Banks and Agent
contained herein shall, at the option of Majority Banks, terminate.
SECTION 6. REPRESENTATIONS AND WARRANTIES OF BORROWER. To induce the
Banks and Agent to enter into this Fifth 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 Fifth
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.
4
<PAGE>
(c) This Fifth 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 7. MISCELLANEOUS.
7.1 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.
7.2 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.
7.3 PARTIES IN INTEREST. All of the terms and provisions of this Fifth
Amendment shall bind and inure to the benefit of the parties hereto and their
respective successors and assigns.
7.4 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 Fifth
Amendment and all related documents.
7.5 COUNTERPARTS. This Fifth Amendment may be executed in counterparts,
and all parties need not execute the same counterpart; however, no party shall
be bound by this Fifth Amendment until all parties have executed a counterpart.
Facsimiles shall be effective as originals.
7.6 COMPLETE AGREEMENT. THIS FIFTH 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.
7.7 HEADINGS. The headings, captions and arrangements used in this Fifth
Amendment are, unless specified otherwise, for convenience only and shall not be
deemed to limit, amplify or modify the terms of this Fifth Amendment, nor affect
the meaning thereof.
5
<PAGE>
IN WITNESS WHEREOF, the parties hereto have caused this Fifth 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
AGENT:
NATIONSBANK OF TEXAS, N.A.
By:/s/Scott Fowler
------------------
Its:Vice President
BANKS:
NATIONSBANK OF TEXAS, N.A.
By:/s/Scott Fowler
------------------
Its:Vice President
TEXAS COMMERCE BANK
NATIONAL ASSOCIATION
By:/s/Tim Perry
-------------------------
Its:Senior 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
6
EXHIBIT 11.1
SNYDER OIL CORPORATION
Computation of Net Income (Loss) per Common Share
For The Years Ended December 31, 1994, 1995 and 1996
(In thousands except per share data)
<TABLE>
<CAPTION>
Year Ended December 31,
---------------------------------------------------
1994 1995 1996
------------- ------------- --------------
<S> <C> <C> <C>
Net income (loss) $12,372 ($39,831) $62,950
Dividends on preferred stock (10,806) (6,210) (6,210)
------------- ------------- --------------
Net income (loss) available to common $1,566 ($46,041) $56,740
============= ============= ==============
Weighted average shares outstanding 23,704 30,186 31,308
Assumed exercise of vested common stock options
net of treasury shares repurchased 290(a) 138(c) 179(d)
Assumed conversion of 6% preferred stock 4,881(b) 4,881(b) 5,051(e)
------------- ------------- --------------
Weighted average common stock and equivalents outstanding 28,875 35,205 36,538
============= ============= ==============
PRIMARY NET INCOME (LOSS) PER COMMON SHARE:
Net income (loss) $0.52 ($1.32) $2.01
Dividends on preferred stock (0.45) (0.21) (0.20)
------------- ------------- --------------
Net income (loss) available to common $0.07 ($1.53) $1.81
============= ============= ==============
FULLY DILUTED NET INCOME (LOSS) PER COMMON SHARE:
Net income (loss) $0.43 ($1.13) $1.72
Dividends on preferred stock 0.00 0.00 0.00
------------- ------------- --------------
Net income (loss) available to common $0.43 ($1.13) $1.72
============= ============= ==============
Antidilutive Antidilutive Dilutive
<FN>
(a) Computed as 532,837 shares assumed to be issued upon exercise of
vested options less 242,690 shares assumed to be purchased and held
in treasury ($4,421,814 proceeds divided by $18.22 average closing
price).
(b) 4,100,000 shares X $25.00/$21.00. Should be 4,140,000 shares, but
will leave the same as reported in prior years.
(c) Computed as 743,285 shares assumed to be issued upon exercise of
vested options less 605,327 shares assumed to be purchased and held
in treasury ($7,802,659 proceeds divided by $12.89 average closing
price).
(d) Computed as 772,155 shares assumed to be issued upon exercise of
vested options less 593,111 shares assumed to be purchased and held
in treasury ($10,308,269 proceeds divided by $17.38 ending market
price).
(e) 4,134,000 shares X $25.00/$20.46.
</FN>
</TABLE>
EXHIBIT 12
<TABLE>
SNYDER OIL CORPORATION
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
(UNAUDITED)
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------------------------------------------------
1992 1993 1994 1995 1996
----------- ----------- ----------- ----------- -----------
(DOLLARS IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
Income (loss) before taxes, minority
interest and extraordinary item $15,027 $22,538 $13,510 ($40,604) $75,701
Interest expense 4,997 5,315 10,337 21,679 23,587
----------- ----------- ----------- ----------- -----------
Earnings before taxes, minority
interest, extraordinary item and
fixed charges 20,024 27,853 23,847 (18,925) 99,288
=========== =========== =========== =========== ===========
Fixed Charges:
Interest expense 4,997 5,315 10,337 21,679 23,587
Preferred stock dividends of
majority owned subsidiary - - - - 1,520
----------- ----------- ---------- ----------- -----------
Total fixed charges $4,997 $5,315 $10,337 $21,679 $25,107
=========== =========== =========== =========== ===========
Ratio of earnings to fixed charges 4.01 5.24 2.31 (0.87) 3.95
=========== =========== =========== =========== ===========
</TABLE>
1
<PAGE>
<TABLE>
SNYDER OIL CORPORATION
COMPUTATION OF RATIO OF EARNINGS TO
COMBINED FIXED CHARGES AND PREFERRED DIVIDENDS
(UNAUDITED)
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------------------------------------------------
1992 1993 1994 1995 1996
----------- ----------- ----------- ----------- -----------
(DOLLARS IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
Income (loss) before taxes, minority
interest and extraordinary item $15,027 $22,538 $13,510 ($40,604) $75,701
Interest expense 4,997 5,315 10,337 21,679 23,587
----------- ----------- ----------- ----------- -----------
Earnings before taxes, minority
interest, extraordinary item and
fixed charges 20,024 27,853 23,847 (18,925) 99,288
=========== =========== =========== =========== ===========
Fixed Charges:
Interest expense 4,997 5,315 10,337 21,679 23,587
Preferred stock dividends 4,800 9,100 10,806 6,210 6,210
Preferred stock dividends
majority owned subsidiary - - - - 1,520
----------- ----------- ----------- ----------- -----------
Total fixed charges $9,797 $14,415 $21,143 $27,889 $31,317
=========== =========== =========== =========== ===========
Ratio of earnings
to combined fixed charges
and preferred dividends 2.04 1.93 1.13 (0.68) 3.17
============ ========== =========== =========== ==========
2
</TABLE>
EXHIBIT 22.1
SNYDER OIL CORPORATION
SUBSIDIARIES AS OF MARCH 10, 1997
State of
Name of Subsidiary Organization
------------------ -------------
Patina Oil & Gas Corporation Delaware
SOCO Wattenberg Corporation Delaware
Gerrity Oil & Gas 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 17, 1997 on the financial statements of Snyder Oil
Corporation included in this Form 10-K, into Snyder Oil Corporation's previously
filed Registration Statement File Nos. 33-34446, 33-45213, 33- 54809, 33-64219
and 333-09877.
ARTHUR ANDERSEN LLP
Fort Worth, Texas,
March 10, 1997
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. 33-34446, 33-45213, 33- 54809, 33-64219 and
333-09877.
NETHERLAND, SEWELL & ASSOCIATES, INC.
By:/s/ Frederic D. Sewell
-----------------------------------
Frederic D. Sewell
President
Dallas, Texas
March 11, 1997
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. 33-34446, 33-45213, 33- 54809,
33-64219 and 333-09877.
RYDER SCOTT COMPANY
PETROLEUM ENGINEERS
Houston, Texas
March 10, 1997
WARNING: THE EDGAR SYSTEM ENCOUNTERED ERROR(S) WHILE PROCESSING THIS SCHEDULE.
<TABLE> <S> <C>
<ARTICLE> 5
<MULTIPLIER> 1,000
<CURRENCY> US $
<S> <C>
<PERIOD-TYPE> Year
<FISCAL-YEAR-END> Dec-31-1996
<PERIOD-START> Jan-01-1996
<PERIOD-END> Dec-31-1996
<CASH> 27,922
<SECURITIES> 0
<RECEIVABLES> 58,944
<ALLOWANCES> 0
<INVENTORY> 3,403
<CURRENT-ASSETS> 98,078
<PP&E> 910,700
<DEPRECIATION> 261,502
<TOTAL-ASSETS> 879,459
<CURRENT-LIABILITIES> 88,910
<BONDS> 372,073
0
10
<COMMON> 315
<OTHER-SE> 294,343
<TOTAL-LIABILITY-AND-EQUITY> 879,459
<SALES> 206,982
<TOTAL-REVENUES> 292,414
<CGS> 136,601
<TOTAL-COSTS> 154,081
<OTHER-EXPENSES> 19,713
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 24,179
<INCOME-PRETAX> 74,701
<INCOME-TAX> 4,346
<INCOME-CONTINUING> 62,950
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 62,950
<EPS-PRIMARY> 1.81
<EPS-DILUTED> 1.72
</TABLE>
EXHIBIT 99.1
February 4, 1997
Snyder Oil Corporation
Suite 2500
777 Main Street
Forth Worth, Texas 76102
Gentlemen:
In accordance with your request, we have estimated the proved reserves and
future revenue, as of December 31, 1996, to the Snyder Oil Corporation (SOCO)
interest in certain oil and gas properties located in the United States and in
federal waters offshore Louisiana 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 and
conforms to 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, 1996, to be: Net Reserves Future Net Revenue
<TABLE>
<CAPTION>
Net Reserves Future Net Revenue
------------------------------------- ---------------------------------------
Oil Gas Present Worth
Category (Barrels) (MCF) Total at 10%
- --------------------------- --------------- ---------------- ----------------- ------------------
<S> <C> <C> <C> <C>
Proved Developed
Producing 13,159,701 145,971,065 $ 517,276,200 $ 287,013,000
Non-Producing 603,626 2,096,499 13,474,300 7,602,100
Proved Undeveloped 1,935,000 105,239,714 291,643,300 134,424,700
--------------- ---------------- ----------------- ----------------
Total Proved 15,698,327 253,307,278 $ 822,393,800 $ 429,039,800
</TABLE>
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 project areas behind the appropriate division tab. Included for
each project area are summary projections of reserves and revenue for each
reserve category along with one-line summaries of reserves, economics, and basic
data by lease for each significant property group. For the purposes of this
report, the term "lease" refers to a single economic projection.
The estimated reserves and future revenue shown in this report are for
proved developed producing, proved developed non-producing, and proved
undeveloped reserves. In accordance with SEC guidelines, our estimate do
not include any value for probable or possible reserves which may exit for
<PAGE>
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
consideration of federal income taxes; future net revenue for the offshore
properties is also after deducting abandonment costs. 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. Our
estimates of future revenue do not include any salvage value for the lease and
well equipment nor the cost of abandoning the onshore properties. Future revenue
estimates for offshore properties also do not include any salvage value for the
lease and well equipment, but do include our estimates of the costs to abandon
the wells, platforms, and production facilities. Abandonment costs for offshore
properties are included with other capital investments.
Oil prices used in this report are based on a December 31, 1996 West Texas
Intermediate posted price of $24.25 per barrel, adjusted by significant property
group for regional posted price differentials. Gas prices used in this report
are based on average December 1996 prices by pipeline for each significant
property group. Oil and gas prices are held constant in accordance with SEC
guidelines.
Lease and well operating costs are based on operating expense records of
SOCO. For non-operated properties, these costs include the per-well overhead
expenses allowed under joint operating agreements along with costs estimated to
be incurred at and below the district and field levels. As requested, lease and
well operating costs for the operated properties include only direct lease and
field level costs. Headquarters general and administrative overhead expenses of
SOCO are not included. Lease and well operating costs are held constant in
accordance with SEC guidelines. Capital costs are included as required for
workovers, new development wells, and production equipment.
We have made no investigation of potential gas volume and value imbalances
which may have resulted from 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 uncertainties of supply and demand.
Also, estimates of reserves may increase or decrease as a result of future
operations.
<PAGE>
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
uncertainties 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 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
Netherland Sewell & Associates, Inc.
RKG:AKC
EXHIBIT 99.2
February 5, 1997
Patina Oil & Gas Corporation
Suite 2000
1625 Broadway
Denver, Colorado 80202
Gentlemen:
In accordance with your request, we have estimated the proved reserves
and future revenue, as of December 31, 1996, to the Patina Oil & Gas Corporation
(Patina) interest in certain oil and gas properties located in Colorado. 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 Patina. This report has been prepared using constant prices and costs and
conforms to 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 Patina interest,
as of December 31, 1996, 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 12,971,418 206,872,544 $ 824,044,600 $ 500,440,700
Non-Producing 2,827,690 35,904,440 156,219,400 81,966,600
Proved Undeveloped 6,676,152 53,882,147 188,602,900 66,389,200
--------------- ---------------- ----------------- ------------------
Total Proved 22,475,260 296,659,131 $1,168,866,900 $ 648,796,500
</TABLE>
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, this report includes summary
projections 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
undeveloped reserves. In accordance with SEC guidelines, our estimates do
not include any value for probable or possible reserves which may exist for
<PAGE>
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 Patina 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
consideration of federal income taxes. In accordance with SEC guidelines, the
future net revenue has been discounted at an annual rate of 10 percent to
determine its "present worth." The present worth is shown to indicate the effect
of time on the value of money and should not be construed as being the fair
market value of the properties.
For the purposes of this report, a field inspection of the properties
has not been performed nor has the mechanical operation or condition of the
wells and their related facilities been examined. We have not investigated
possible environmental liability related to the properties; therefore, our
estimates do not include any costs which may be incurred due to such possible
liability. Also, our estimates do not include any salvage value for the lease
and well equipment nor the cost of abandoning the properties.
Oil prices used in this report are based on a December 31, 1996 West
Texas Intermediate posted price of $24.25 per barrel, adjusted by lease for
gravity, transportation fees, and regional posted price differentials. Gas
prices used in this report are the average December 1996 prices for each
pipeline. Oil and gas prices are held constant in accordance with SEC
guidelines.
Lease and well operating costs are based on operating expense records
of Patina. For non-operated properties, these costs include the per-well
overhead expenses allowed under joint operating agreements along with costs
estimated to be incurred at and below the district and field levels. As
requested, lease and well operating costs for the operated properties include
only direct lease and field level costs. Headquarters general and administrative
overhead expenses of Patina 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
Patina 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 Patina 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
uncertainties of supply and demand. Also, estimates of reserves may increase or
decrease as a result of future operations.
In evaluating the information at our disposal concerning this report,
we have excluded from our consideration all matters as to which legal or
accounting, rather than engineering and geological, interpretation may be
controlling. As in all aspects of oil and gas evaluation, there are
uncertainties inherent in the interpretation of engineering and geological data;
therefore, our conclusions necessarily represent only informed professional
judgments.
<PAGE>
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
Patina Oil & Gas Corporation 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
-------------------------------
Netherland Sewell & Associates, Inc.
RKG:HAY
EXHIBIT 99.3
February 5, 1997
SOCO Offshore, Inc.
A subsidiary of Snyder Oil Corporation
1221 Lamar, Suite 1200
Houston, Texas 77010
Gentlemen:
At your request, we have prepared an estimate of the reserves, future
production, and income attributable to certain leasehold and royalty interests
of SOCO Offshore, Inc. (SOCO) as of December 31, 1996. The subject properties
are located in the state of Texas and in the federal waters offshore Louisiana
and Texas. The income data were estimated using the Securities and Exchange
Commission (SEC) guidelines for future price and cost parameters.
The estimated reserves and future income amounts presented in this report
are related to hydrocarbon prices. December 1996 hydrocarbon prices were used in
the preparation of this report as required by SEC guidelines; however, actual
future prices may vary significantly from December 1996 prices. Therefore,
volumes of reserves actually recovered and amounts of income actually received
may differ significantly from the estimated quantities presented in this report.
The results of this study are summarized below.
<TABLE>
SEC PARAMETERS
Estimated Net Reserves and Income Data
Certain Leasehold and Royalty Interests of
SOCO OFFSHORE, INC.
As of December 31, 1996
----------------------------------------------------------------------------------------
<CAPTION>
PROVED
---------------------------------------------------------------------------------------
DEVELOPED TOTAL
---------------------------------------------
PRODUCING NON-PRODUCING UNDEVELOPED PROVED
------------------ --------------------- ------------------ -------------------
<S> <C> <C> <C> <C>
NET REMAINING RESERVES
OIL/CONDENSATE - BARRELS 1,130,123 614,980 35,461 1,780,564
GAS - MMCF 38,952 14,712 1,170 54,834
INCOME DATA
FUTURE GROSS REVENUE $182,774,740 $74,060,517 $5,589,874 $262,452,131
DEDUCTIONS 30,263,094 16,604,502 4,099,373 50,966,969
-------------- ------------ ----------- --------------
FUTURE NET INCOME (FNI) $152,511,646 $57,456,015 $1,490,501 $211,458,162
DISCOUNTED FNI @ 10% $139,086,667 $35,973,701 $ 523,445 $175,583,813
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
PROBABLE
--------------------------------------------------------------------------------------------
DEVELOPED TOTAL
-------------------------------------------
PRODUCING NON-PRODUCING UNDEVELOPED PROBABLE
----------------- -------------------- ------------------ -----------------
<S> <C> <C> <C> <C>
NET REMAINING RESERVES
OIL/CONDENSATE - BARRELS 274,627 40,422 37,763 352,812
GAS - MMCF 5,943 3,903 1,246 11,092
INCOME DATA
FUTURE GROSS REVENUE $30,479,322 $16,291,982 $5,952,614 $52,723,918
DEDUCTIONS 148,298 752,249 3,248 903,795
-------------- -------------- -------------- --------------
FUTURE NET INCOME (FNI) $30,331,024 $15,539,733 $5,949,366 $51,820,123
DISCOUNTED FNI @ 10% $21,772,784 $ 8,181,240 $5,064,732 $35,018,756
</TABLE>
<TABLE>
<CAPTION>
POSSIBLE
----------------------------------------------------------------------------------------------
DEVELOPED TOTAL
---------------------------------------------
PRODUCING NON-PRODUCING UNDEVELOPED POSSIBLE
------------------ --------------------- ------------------- -----------------
<S> <C> <C> <C> <C>
NET REMAINING RESERVES
OIL/CONDENSATE - BARRELS 239,006 94 37,568 276,668
GAS - MMCF 2,915 1,122 1,240 5,277
INCOME DATA
FUTURE GROSS REVENUE $17,440,154 $4,316,005 $5,921,988 $27,678,147
DEDUCTIONS 128,986 128,251 2,050 259,287
-------------- ------------ -------------- --------------
FUTURE NET INCOME (FNI) $17,311,168 $4,187,754 $5,919,938 $27,418,860
DISCOUNTED FNI @ 10% $10,805,217 $2,092,899 $4,990,695 $17,888,811
</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.
The future gross revenue is after the deduction of production taxes. The
deductions are comprised of the normal direct costs of operating the wells, ad
valorem taxes, recompletion costs, development costs, and certain 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. at SOCO's request, gas imbalances for
four fields were included in this report. The fields were Eugene Island 342,
East Cameron 317/318, Eugene Island 324, and Eugene Island 198/199/202. 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.
<PAGE>
<TABLE>
<CAPTION>
DISCOUNTED FUTURE NET INCOME
AS OF DECEMBER 31, 1996
---------------------------------------------------------------------
DISCOUNT RATE TOTAL TOTAL TOTAL
PERCENT PROVED PROBABLE POSSIBLE
---------------------- --------------------- -------------------- ------------------
<S> <C> <C> <C>
5 $192,063,468 $42,306,871 $21,991,600
15 $161,504,807 $29,357,298 $14,751,966
20 $149,392,052 $24,900,590 $12,326,477
25 $138,890,657 $21,347,634 $10,429,946
</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. The definitions of proved,
probable, and possible reserves are included under the tab "Reserve Definitions
and Pricing Assumptions" in this report.
We have included probable and possible reserves and income in this report
at the request of SOCO. These data are for SOCO's information only and should
not be included in reports to the SEC according to the SEC guidelines. 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.
The proved developed non-producing reserves included herein are comprised
of shut-in and behind pipe categories. The probable developed non-producing
reserves included herein are comprised of the behind pipe category. The possible
developed non-producing reserves included herein are comprised of the behind
pipe category. The various reserve status categories are defined under the tab
"Reserve Definitions and Pricing Assumptions" in this report.
ESTIMATES OF RESERVES
Producing reserves included herein were estimated by the performance method
and the volumetric method. The performance method utilized extrapolations of
various historical data. Non- producing and undeveloped reserves included herein
were estimated by the volumetric method. All of the reserves included herein
were based only on primary recovery
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.
<PAGE>
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
SOCO.
We estimated that future gas production rates limited by allowables or
marketing conditions 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.
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
SOCO furnished us with prices in effect at December 31, 1996 and these
prices were held constant. In accordance with Securities and Exchange Commission
guidelines, changes in liquid and gas prices subsequent to December 31, 1996
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 leases and wells in this report were provided by SOCO.
They were accepted without independent verification. SOCO informs us that these
costs are representative of the historical costs directly applicable to the
leases or wells. 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.
Development costs were furnished to us by SOCO and are based on
authorizations for expenditure for the proposed work or actual costs for similar
projects. The estimated net cost of abandonment after salvage was included for
all of the properties. The estimates of the net abandonment costs furnished by
SOCO were accepted without independent verification.
Current costs were held constant throughout the life of the properties.
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
<PAGE>
subject properties. Tables 1 through 212 present our estimated projection of
production and income by years beginning January 1, 1997, by program, 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 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 properties in which SOCO owns an interest; 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. SOCO 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 SOCO were accepted without independent
verification. The estimates presented in this report are based on data available
through December 1996.
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 and sole benefit of SOCO
Offshore, 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
Joseph E. Blankenship, P.E.
Senior Petroleum Engineer
JEB/sw
Approved:
- -------------------------------------
Joseph E. Magoto, P.E.
Group Vice President
