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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
-----------------------
Form 10-K
(Mark one)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1997
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
Preferred Stock Purchase Rights 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 February 27, 1998.................................$571,824,508
Number of shares of common stock outstanding as of February 27, 1998..33,392,696
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,
1998.
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SNYDER OIL CORPORATION
Annual Report on Form 10-K
December 31, 1997
PART I
ITEMS 1 AND 2. BUSINESS AND PROPERTIES
General
Snyder Oil Corporation (the "Company") is an independent energy company
engaged in the production, development, acquisition and exploration of domestic
oil and gas properties, primarily in the Gulf of Mexico, the Rocky Mountains and
northern Louisiana. During 1997, the Company's revenues were $255.7 million and
cash flow provided by operations was $122.0 million. At December 31, 1997, the
Company's proved reserves totaled 77.3 million barrels of oil equivalent
("BOE"), having a pretax present value, discounted at 10% based on constant
prices and costs ("Pretax PW 10% Value") of $375.3 million. Approximately 78% of
these reserves are natural gas.
During 1997, the Company undertook efforts to simplify its corporate
structure. The simplification and repositioning resulted in the bulk of the
Company's asset value being concentrated in properties the Company owns and
operates directly. Three primary initiatives were completed in 1997 towards
reaching this goal.
Patina Oil & Gas Corporation. In October 1997, the Company
sold its entire 74% stake, or 14 million shares of the common stock, of
Patina Oil & Gas Corporation ("Patina"). The Company sold 10.9 million
shares of Patina stock in a secondary offering, with the remainder
repurchased by Patina. This transaction generated $127 million in cash
while removing approximately $170 million of Patina debt from the
Company's consolidated balance sheet.
SOCO International, Inc. In May 1997, SOCO International, Inc.
("SOCO International") transferred its 90% interest in SOCO
International Operations, Inc. ("Operations"), which held the Company's
investments in Mongolia, Russia and Thailand, to SOCO International plc
("SOCI plc"), a recently formed United Kingdom company, in exchange for
shares of SOCI plc stock. SOCI plc also acquired the interests of a
number of minority investors in Operations' ventures and assets in
Yemen, Tunisia and onshore England from Cairn Energy plc ("Cairn"). At
the time of the acquisitions, SOCI plc, which is listed on the London
Stock Exchange, completed a public offering of its common shares that
raised approximately $75 million of new equity capital to fund its
continuing exploration and development expenditures. The 7.8 million
shares of SOCI plc acquired by the Company represent approximately
15.9% of SOCI plc and had a market value of $45.1 million at February
27, 1998. Under London Stock Exchange rules, the Company will not be
permitted to sell these shares prior to May 1999. Edward T. Story, a
director and former Vice President - International of the Company, is
the chief executive officer of SOCI plc.
Capital Structure. The Company completed a series of
transactions in 1997 to simplify its capital structure and eliminate
the potential dilution to common shareholders. At January 1, 1997, the
Company had 42.0 million common shares on a fully diluted basis. By
December 31, 1997, the Company had 33.3 million common shares
outstanding with no convertible securities outstanding. These
transactions consisted of the following:
* In first quarter 1997, the Company sold 4.5 million
shares, or 28% of its holdings in Cairn. Net proceeds from
the sales were $39.2 million resulting in a $13.0 million
gain. The Company continues to hold 11.7 million shares of
Cairn with a market value of $80.1 million at February 27,
1998. The Company may maintain its investment, sell all or
part of it, either in one transaction or gradually, or
pursue other courses of action. Any decision, when made,
will be made in light of strategic, financial and other
factors deemed appropriate by management.
* The Company redeployed the cash from the Cairn
transactions into its securities repurchase program,
underscoring management's belief that the Company's common
stock has been undervalued in the market. During the year,
the Company repurchased 2.6 million common shares for
$45.6 million or an average of $17.24 per share.
* In June 1997, the Company issued $175 million of 8.75%
senior subordinated notes due 2007. Following the
issuance, the Company redeemed its convertible
subordinated notes due 2001. The notes were redeemed for a
price of 103.51% of principal plus accrued interest. These
transactions extended the maturity of the indebtedness by
six years and eliminated the potential issuance of 3.6
million shares of common stock on conversion of the old
notes.
* In October 1997, the Company issued 300,000 shares of its
common stock in exchange for warrants held by Union
Pacific Resources to purchase 2.1 million of the Company's
common shares.
* In the fourth quarter 1997, the Company called all of the
depositary shares representing interests in the Company's
$6.00 Convertible Exchangeable Preferred Stock. The calls
resulted in the Company converting a portion of the
preferred shares into approximately 3.6 million shares of
common stock. The Company redeemed the remaining preferred
shares for $30.1 million in cash. The calls of the
preferred shares eliminated 1.4 million common shares of
potential dilution and over $6 million a year in dividend
payments.
As a result of the capital restructuring, all of the Company's growth
potential will benefit its common shareholders. Redeployment of the cash and
marketable securities held by the Company into an acquisition or series of
acquisitions is a strategic objective of the Company.
Operations
The Company's operations are focused on three core areas, each with the
potential to contribute significantly to future growth:
* Offshore. The Company had proved reserves in the Gulf of Mexico of 19.3
million BOE with a Pretax PW 10% Value of $170.5 million at December 31,
1997. These reserves are concentrated in the Pabst, Busch and Ingrid Fields
of the Main Pass area offshore Louisiana and Alabama. Through the end of
1997, production from the Pabst and Busch Fields had often been
restricted to 100 MMcf (42 MMcf net) of gas per day but increased to more
than 150 MMcf (63 MMcf net) per day following the expansion of pipeline
capacity serving these fields in January 1998. The Company intends to
complete installation of a platform and production facilities with total
initial capacity of 150 MMcf per day on its 50%-owned Ingrid Field, with
production commencing by April 1998. The Company plans to expand its
activities in the Gulf of Mexico significantly and has budgeted up to $50
million for development and exploration in this area in 1998.
* North Louisiana. The Company owns over 330,000 net mineral acres, with
leases and lease options covering more than 150,000 additional net
acres, in North Louisiana. The Company has identified a number of
exploration prospects as a result of two 3-D seismic surveys covering
approximately 166 square miles. Two partners earned a one-third interest
each in these prospects by paying all of the costs of these seismic
surveys. Based on these surveys, the Company expects to begin drilling
activities in North Louisiana in the first half of 1998. The Company
expects its expenditures in North Louisiana to total approximately $15
million in 1998.
* Rocky Mountains. The Company had proved reserves in Wyoming, western
Colorado and Utah of 56.5 million BOE with a Pretax PW 10% Value of $193.3
million at December 31, 1997. These reserves are concentrated in gas
development programs in the Washakie, Green River and Piceance Basins, and
in two large, mature non-operated oil fields in northern Wyoming. The
Company has also initiated gas projects in the Wind River and Big Horn
Basins in Wyoming and an oil project in Utah. The Company formed a gas
marketing joint venture with Coastal Corporation, one of the largest gas
marketers in North America, effective January 1, 1997. The Company has
budgeted up to $70 million for continued development and exploration in the
western Rocky Mountains during 1998.
2
Summary information at December 31, 1997 regarding the Company's projects is set
forth in the following table.
Proved Reserve Quantities
Gross Net --------------------------------------- Pretax PW 10% Value
Producing Undeveloped Crude Oil Natural Oil -------------------------
Wells Acres & Liquids Gas Equivalent Amount Percent
--------- ----------- ---------- ------- ---------- ---------- -----------
(MBbl) (MMcf) (MBOE) (000)
Offshore
Main Pass Area 18 9,167 1,094 96,433 17,167 $ 161,783 43%
Other 23 - 285 10,994 2,117 8,734 2
------- --------- -------- --------- -------- ---------- ------
Total Offshore 41 9,167 1,379 107,427 19,284 170,517 45
North Louisiana 14(a) 346,773(b) 57 2,041 397 3,313 1
Other 86 1,533 104 6,099 1,120 8,177 2
-------- --------- -------- --------- -------- ---------- ------
Southern Region 141 357,473 1,540 115,567 20,801 182,007 48
-------- --------- -------- --------- -------- ---------- ------
Washakie (WY) 174 75,174 1,341 139,307 24,559 95,766 26
Piceance (CO) 87 42,641 150 33,669 5,761 21,597 6
Deep Green River (WY) 30 41,555 373 48,661 8,483 32,619 9
Wind River (WY) 26 38,626 447 20,999 3,947 13,726 4
Big Horn (WY) - 77,955 - - - - -
Northern Wyoming 902 - 12,313 566 12,407 24,655 6
Uinta (UT) 126 71,244 596 4,399 1,330 4,904 1
-------- --------- -------- --------- -------- ---------- ------
Rocky Mountain Region 1,345 347,195 15,220 247,601 56,487 193,267 52
-------- --------- -------- --------- -------- ---------- ------
Total Company 1,486 704,668 16,760 363,168 77,288 $ 375,274 100%
======== ========= ======== ========= ======== ========== ======
<FN>
(a) Excludes royalty interests in 101 wells.
(b) Excludes 130,000 net acres under option as of February 27, 1998.
</FN>
Offshore - Gulf of Mexico
The Company believes many areas in the Gulf of Mexico are
under-exploited and, while having greater risks, the potential benefits and
exposure to additional markets complement the Company's onshore activities. The
Company began developing an asset base in the offshore Gulf of Mexico in 1994,
and currently operates 10 platforms accounting for substantially all of the
production from this core area. During 1997, the Company spudded 9 wells, a 28%
increase over the 7 wells drilled in 1996. Since inception, the Company has
recorded a 60% success ratio in its exploratory program (3 out of 5 wells) and a
success ratio of 94% in its development program (17 out of 18 wells).
At year end, total offshore proved reserves were 19.3 million BOE (1.4
million barrels of oil and 107.4 Bcf of gas), up from 17.4 million BOE (2.4
million barrels of oil and 90.0 Bcf of gas) at year end 1996. This represents
approximately 25% of year end reserve quantities, but 45% of Pretax PW 10%
Value. The Company has interests in 41 (17.5 net) wells, 38 (17.2 net) of which
are operated, and 83,000 gross (47,000 net) acres. Production in 1997 was 3.9
million BOE compared to 1.6 million BOE in 1996. Fourth quarter 1997 production
totaled 960 thousand BOE.
In the fourth quarter of 1997, the Company made a major purchase of
seismic data covering approximately 250 offshore blocks, or 2,250 square miles,
in the Main Pass/Viosca Knoll area. The offshore staff of exploration
professionals has doubled in the last six months to facilitate new exploration
and exploitation of existing fields.
The Gulf of Mexico will continue to be a major focus area for the
Company. Estimated 1998 capital expenditures are expected to total $50 million,
including $12 million to install or upgrade platforms and related facilities and
to complete three development wells. The remainder is for the purchase of
additional seismic data and to drill up to twelve exploratory wells. The Company
will continue its acquisition efforts in the area and the evaluation of existing
properties for additional exploratory or development potential.
3
Pabst/Busch Fields. The Pabst (Main Pass 259) and Busch (Main Pass 255)
Fields are located in the Main Pass/Viosca Knoll area offshore Louisiana and
Alabama. The Company continued development and exploration on and around the
Pabst and Busch fields during 1997. Three development wells were drilled at the
Busch field to the 7,900 foot Miocene sand bringing the total to six wells
producing from this field. Two development wells were drilled from the Pabst
platform and one recompletion and one workover were also conducted during the
year. The 12 wells at the Pabst field produce from a series of Miocene zones
ranging from 7,700 to 11,500 feet. The Company drilled a dry hole in Main Pass
248 during 1997 which is northwest of the Pabst platform.
The Company had firm transportation on Viosca Knoll Gathering System
for 100 MMcf per day gross (41 MMcf per day net) covering both platforms during
1997. The Pabst platform facilities are capable of production rates of 110 MMcf
per day and the Busch platform facilities were capable of 60 MMcf per day before
the upgrade in 1998. As of year end, the 12 wells producing from the Pabst
platform had a combined gross well deliverability of 175 MMcf per day and the
six wells producing from the Busch platform had a combined gross well
deliverability of 120 MMcf per day. During 1997, the Company's production from
the two platforms was limited by both the take away capacity and platform
facilities constraints.
During 1997, the Company generally produced the wells at Main Pass 259
in favor of the wells at Main Pass 255 due to the greater condensate yield at
Main Pass 259, except when additional interruptible space was available on the
Viosca Knoll system. Net production from the two fields averaged 56.2 MMcfe per
day in 1997 compared to 19.7 MMcfe per day in 1996. The increase in net
production was primarily the result of including prior year acquisitions of
additional interests for the full year.
The pipeline take away constraints were improved for existing
deliverability when Viosca Knoll system looped its 20 inch line in December
1997. Effective January 1998, the Company's take away capacity increased to 175
MMcf per day gross (72 MMcf per day net) for the two platforms. In addition, the
Main Pass 255 facilities were upgraded by the installation of compression
increasing the platform production capabilities from 55 MMcf per day to 90 MMcf
per day.
At the end of 1997, proved reserves totaled 62.0 Bcf of gas and 297,000
barrels of oil or 10.6 million BOE, as compared to 52.1 Bcf of gas and 932,000
barrels of oil, or 9.6 million BOE at year end 1996. The Pretax PW 10% Value at
December 31, 1997 was $109.4 million. This increase in reserves is primarily
attributable to better than expected performance and extensions of the fields
resulting from further development work. Two exploratory wells are scheduled to
be drilled during 1998.
Ingrid Field. The Ingrid Field (Main Pass 261) was discovered in 1996,
with a second confirmation well also drilled in the same year. The Company has a
50% working interest and a 37% net revenue interest. Proved reserves from both
wells were discovered in the Tex W sands series at approximately 11,000 to
13,000 feet. During 1997, the Company focused on the installation of a platform
for production operations and arranging for transportation and marketing. The
Main Pass 261 platform facilities are under construction with 150 MMcf per day
capacity. The platform jacket was installed in August 1997 and the deck in
February 1998. Tie in of the facilities is underway and production from the
first two wells is expected to commence in April 1998. Initial transportation
has been arranged on Viosca Knoll system at 75 MMcf per day gross to the
Company's working interest (56 MMcf per day net) until a second pipeline is
available in the second half of 1998. The new pipeline system will connect
onshore Alabama directly to the Main Pass 261 platform. An extension of the line
will then connect the Main Pass 261 platform to the Main Pass 259 platform at
the Pabst field. The Company has firm transport in the new system to cover
projected production volumes from the Main Pass area and will retain 60 MMcf per
day gross of firm transport to the Company's working interest (41 MMcf per day
net) on the Viosca Knoll system.
In the fourth quarter of 1997, two additional wells were spudded and in
progress at year end. Pipe was set on both wells and the Company expects to
complete and further test the wells after initial production begins from the
Ingrid platform. Two additional wells are planned for 1998 at Main Pass 261.
Total proved reserves in the field for the Company's interest were 6.5 million
BOE (34.4 Bcf of gas and 798,000 barrels of oil) at year end, with a Pretax PW
10% Value of $52 million.
Other Gulf of Mexico. The Company has interests and operates in several
other areas in the Gulf of Mexico, with working interests ranging from 14% to
100%. During 1998, the Company will continue to evaluate these blocks for
4
additional exploratory or development potential using 3-D seismic data. The
Company plans to drill up to four exploratory wells to test these prospects
during 1998 and 1999. The Company also intends to subsea complete the South
Timbalier 231 #1 well and tie it back to an adjacent platform. Production is
expected to begin in third quarter of 1998.
North Louisiana
The Company's focus in North Louisiana in 1998 is to drill and test
several different reef settings that were identified with the 3-D seismic
program. During 1996 and 1997, the Company and its partners conducted two 3-D
seismic surveys covering 166 square miles in three acreage blocks out of the
Company's over 560,000 acres controlled in the area. Merging and interpreting
the two data sets was completed in 1997. The Company is preparing to drill four
exploratory wells targeting different types of reef anomalies at depths between
15,000 and 17,000 feet. The first well is scheduled for second quarter 1998, and
a second rig is expected to begin drilling shortly thereafter. These wells
require approximately 90 to 100 days to drill and an additional 30 to 60 days to
complete and test. Results from the first two wells are expected in late third
or early fourth quarter 1998. If successful, the Company has mapped sufficient
reef anomalies to support a multi-rig drilling program beginning in 1999. The
Company retains a 33% working interest in the current prospects within the area
of the seismic surveys and is the operator of drilling and production
activities.
The Company has over 6,000 miles of 2-D seismic data over its mineral
holdings in North Louisiana and has mapped numerous reef anomalies as well as
untested salt domes and associated drilling prospects in the Cotton Valley
Sands, Hosston Sands and Cretaceous Limes. Additional 3-D surveys to extend the
play are expected to commence late in 1998 pending drilling results. In
addition, the Company retains the option to increase its working interest from
33% to 50% in subsequent 3-D surveys and associated prospects.
Rocky Mountains
The Company's Rocky Mountain Region continues to focus on several
growth areas in the western Rockies. The Company increased its drilling activity
in 1997 by 65%, drilling a total of 71 wells and positioning itself for
continued future growth. The Company's core development projects are in the
Washakie, Green River, and Piceance Basins. These projects continue as the main
thrust of the Region's activity; however, drilling success in the Wind River and
Big Horn Basins in 1997 and additional drilling in 1998 provides the potential
for these areas to add significant future growth in production and reserves.
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 1997, the Company continued to develop Mesaverde sands in the Washakie
Basin near its existing properties. Nineteen wells were put on sales in 1997 at
depths ranging from 8,000 to 11,500 feet. Five wells were in progress at year
end. Net production of gas, which accounts for approximately 95% of the
reserves, during the year averaged 29.5 MMcf per day, as compared to average
1996 production of 25.4 MMcf per day. Proved reserves at year end totaled 1.3
million barrels of oil and 139.3 Bcf of gas, or 24.6 million BOE, as compared to
1.1 million barrels and 133.1 Bcf, or 23.3 million BOE, at the end of 1996. This
increase in reserves is primarily attributable to better than expected
performance and extensions of the field. The Company expects to accelerate its
activity in this area in 1998, with plans to drill 32 to 36 wells at net costs
expected to range from $500,000 to $775,000 per well. Significant portions of
this area are the subject of a currently pending environmental impact statement.
Pending approval of the statement, which is not expected until 1999, drilling in
the affected areas will be limited.
The Company currently operates 146 wells in the Washakie Basin and
holds hundreds of potential drilling locations, 40 of which were classified as
proved undeveloped at year end 1997. The Company holds interests in
approximately 95,000 gross (75,000 net) undeveloped acres in this area.
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 19 wells during 1997, with five wells in progress at
year end. Year end proved reserves totaled 373,000 barrels of oil and 48.7 Bcf
of gas, or 8.5 million BOE, as compared to 175,000 barrels of oil and 21.7 Bcf
of gas, or 3.8 million BOE, at year end 1996. This increase in reserves is
5
primarily attributable to better than expected performance and extensions of the
field. With 30 wells, 19 of which are operated by the Company, on sales at year
end, net production averaged 1,733 BOE per day during 1997. This more than
doubled 1996's average production of 829 BOE per day, despite the Company's sale
of 50% of its interest in the project to an industry partner in July 1996. The
Company holds interests in approximately 92,000 gross (42,000 net) undeveloped
acres in this project. At the end of 1997, proved undeveloped reserves were
assigned to 20 locations. The Company expects to participate in drilling 25 to
30 wells in 1998. Further expansion of drilling in this area is awaiting
approval of an environmental impact statement, which if approved as expected in
April 1998, will allow the Company to participate in drilling 30 to 40 wells per
year after 1998.
Piceance Basin. The Company operates the 53,000 acre Hunter Mesa Unit,
the 9,000 acre Grass Mesa Unit and the 26,000 acre Divide Creek Unit in the
southeast portion of the Piceance Basin. At year end, the Company owned
approximately 97,000 gross (43,000 net) undeveloped acres in this area. During
1997, the Company participated in 23 new wells to develop and further delineate
the fields. Twenty-two wells (including one in progress at the beginning of
1997) were put on sales, and two were in progress at year end. Net gas
production averaged 8.8 MMcf per day in 1997. This is down slightly from 9.5
MMcf per day in 1996 reflecting the Company's sale of 45% of its interest in
this project in May 1996. At year end 1997, there were 87 producing wells, 72 of
which are operated by the Company. Proved reserves at year end were 33.7 Bcf of
gas and 150,000 barrels of oil, or 5.8 million BOE, as compared with 32.2 Bcf
and 118,000 barrels, or 5.5 million BOE, at year end 1996. Proved undeveloped
reserves were assigned to 11 locations at year end 1997. During 1998, the
Company plans to drill 30 to 33 wells to further develop the Company's acreage
positions and evaluate the fields. The primary objective of drilling is the
fluvial sands of the Mesaverde formation at depths of 4,500 to 8,500 feet.
Wind River Basin. The Company owns the Riverton Dome field, a 33,000
acre option on Tribal lands north and east of the field, and a 64,000 acre
primarily undeveloped lease block east of the option lands. The Company acquired
a 3-D seismic survey over the option lands in 1997 and plans to acquire one over
the Riverton Dome field and another on the option lands in 1998. The Company has
a 50% working interest in the option lands and in the eastern lease block. In
late 1997, a new Frontier well was completed on the Tribal block with initial
production over 2,000 Mcf per day. The Company plans to drill four 50% owned
Frontier wells in 1998.
The Riverton Dome field produces approximately 5,000 Mcf per day from
the Frontier and Phosphoria formations and 160 BOE per day from the Tensleep
formation. The Company owns 100% working interest in the 26 wells in this field.
Year end reserves total 447,000 barrels of oil and 21.0 Bcf or 3.9 million BOE.
There is one proved, undeveloped location in the field. Sweet gas is processed
at a Company owned plant; sour gas is processed at a third party plant. In late
1997, a new Tensleep well was completed at an initial rate of 100 barrels of oil
per day. The Company plans to drill 3 Frontier wells and one Tensleep well in
1998. The Tensleep/Phosphoria well is on a portion of the lease lands in which
the Company has a 100% interest. The Frontier is located at 8,000 to 10,500 feet
and the Tensleep around 12,000 feet. Frontier wells cost approximately $1.2
million and Tensleep wells cost approximately $1.5 million each.
Big Horn Basin. The Company has assembled a 156,000 gross (78,000 net)
acre undeveloped lease block which is prospective for Frontier, Muddy, and
Lance/Mesaverde formations. The initial well, completed at the beginning of
1998, tested at 550 Mcf per day and 20 barrels of oil per day from the Frontier,
a rate at which the Company believes can be improved with different frac
techniques. In January 1998, casing was set on the second well located 2.5 miles
northeast of the initial well and testing should commence in the first quarter
1998. Two additional wells are planned for 1998 at net costs of approximately
$1.2 million each.
Uinta Basin. In the Uinta Basin, the Company holds interests in
approximately 94,000 gross (71,000 net) acres. During 1997, the Company
participated in drilling one operated and two non-operated wells in the basin. A
pilot waterflood in the Leland Bench field commenced during the third quarter of
1996. The initial response was observed in 1997 and production continues to
improve. Depending on the level of oil prices, development may begin in the
second half of 1998. A second pilot project, in the Horseshoe Bend Field,
received all necessary regulatory approvals, and injection commenced in December
1997. The response of the pilot projects and the ability to select locations and
enhance waterflood efforts through the use of 3-D seismic data will influence
the ultimate success of these projects. The projects are also sensitive to oil
prices. During the last half of 1996, local oil prices, which had historically
been at a premium to West Texas Intermediate prices, deteriorated and now trade
at a significant discount to such prices. Throughout 1997, black wax crude oil
6
prices remained relatively low with little improvement expected in the near
term. As a result, additional development drilling will likely be curtailed
until oil prices in the area improve.
During 1997, net production from the Uinta Basin averaged 267 barrels
of oil and approximately 1,401 Mcf of gas per day, as compared to 291 barrels
and 1,255 Mcf per day during 1996. At year end, the Company had interests in 126
producing wells, 74 of which were operated by the Company. Proved reserves at
year end were 596,000 barrels of oil and 4.4 Bcf of gas, or 1.3 million BOE, as
compared to 1.2 million barrels and 3.9 Bcf, or 1.8 million BOE, at the end of
1996. The decrease in oil reserves is primarily due to normal field production
decline coupled with significantly lower year end oil prices. Gas reserves
increased primarily due to improved performance following work programs to
increase production during 1997.
Northern Wyoming. The Company holds significant interests in two large,
mature oil fields undergoing waterflood in Northern Wyoming, the Hamilton Dome
and Salt Creek fields. The Company's 1997 production from these fields averaged
3,183 BOE per day. At year end, net proved reserves at these fields totaled 12.4
million BOE, including 12.3 million barrels of oil and 566 MMcf of gas, compared
to 12.2 million BOE (12.1 million barrels of oil and 531 MMcf of gas) at the end
of 1996. In Hamilton Dome, the operator has reduced the production decline in
the field through an accelerated workover program throughout 1997. This work has
replaced the production in 1997 and kept the reserves virtually unchanged.
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.
7
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, 1997 for the
Company and the Company, excluding Patina, as of December 31, 1997 and 1996.
Consolidated Excluding Patina
December 31, December 31,
----------------------------------- ---------------------
1997 1996 1995 1997 1996
-------- -------- -------- -------- --------
Crude oil and liquids (MBbl)
Developed 16,101 31,869 21,637 16,101 16,070
Undeveloped 659 8,628 2,610 659 1,952
-------- -------- -------- -------- --------
Total 16,760 40,497 24,247 16,760 18,022
======== ======== ======== ======== ========
Natural gas (MMcf)
Developed 297,490 443,441 330,524 297,490 200,664
Undeveloped 65,678 162,195 65,194 65,678 108,313
-------- -------- -------- -------- --------
Total 363,168 605,636 395,718 363,168 308,977
======== ======== ======== ======== ========
Total MBOE 77,288 141,436 90,200 77,288 69,518
======== ======== ======== ======== ========
The following table sets forth the estimated pretax future net revenues
from the production of proved reserves and the Pretax PW 10% Value of such
revenues.
December 31, 1997
--------------------------------------------------------
Developed Undeveloped (a) Total
--------- --------------- ---------
(In thousands)
1998 $ 98,710 $ (6,143) $ 92,567
1999 76,583 1,472 78,055
2000 56,211 5,967 62,178
Remainder 319,208 61,204 380,412
--------- --------- ---------
Total $ 550,712 $ 62,500 $ 613,212
========= ========= =========
Pretax PW 10% Value (b) $ 351,955 $ 23,318 $ 375,273
========= ========= =========
<FN>
(a) Net of estimated capital costs, including estimated costs of $11.8 million during 1998.
(b) The after tax PW 10% value of proved reserves totaled $291.8 million at year end 1997.
</FN>
The quantities and values shown in the preceding tables are based on
realized prices in effect at December 31, 1997, averaging $14.42 per barrel of
oil and $2.12 per Mcf of gas. References prices as of December 31, 1997 were
NYMEX oil of $15.50 per barrel, Henry Hub gas of $2.55 per Mcf and CIG index gas
of $1.94 per Mcf. 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 or increase in
prices of oil or gas could have a material 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.
8
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. See "Risk Factors and Investment Considerations."
Netherland, Sewell & Associates, Inc. ("NSAI"), independent petroleum
consultants, prepared estimates of the Company's proved reserves which
collectively represent 87% of Pretax PW 10% Value as of December 31, 1997. 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.
9
Production, Revenue and Price History
The following table sets forth information regarding net production of
crude oil, 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, 1997 for the Company. Also set forth is 1997 and 1996 data
for the Company, excluding Patina.
Consolidated Excluding Patina
-------------------------------------------------------------- -----------------------
1997 1996 1995 1994 1993 1997 1996
--------- --------- --------- ---------- --------- --------- ---------
(Dollars in thousands, except prices and per barrel equivalent information)
Production
Oil (MBbl) 3,490 3,884 4,278 4,366 3,451 2,050 2,196
Gas (MMcf) 61,638 55,840 53,227 43,809 35,080 41,377 31,893
MBOE (a) 13,763 13,191 13,149 11,668 9,297 8,946 7,512
Revenues
Oil $ 65,886 $ 79,201 $ 72,550 $ 64,625 $ 53,174 $ 37,397 $ 44,661
Gas (b) 141,330 110,126 72,058 73,233 71,467 96,454 62,482
--------- --------- --------- --------- --------- -------- ---------
Subtotal 207,216 189,327 144,608 137,858 124,641 133,851 107,143
Transportation, processing
and marketing 7,004 17,655 38,256 107,247 94,839 7,004 17,655
--------- --------- --------- --------- --------- -------- ---------
Total $ 214,220 $ 206,982 $ 182,864 $ 245,105 $ 219,480 $140,855 $ 124,798
--------- --------- --------- --------- --------- -------- ---------
Operating expenses
Production $ 48,523 $ 49,638 $ 52,486 $ 46,267 $ 41,401 $ 35,016 $ 35,118
Transportation, processing
and marketing 6,692 15,020 29,374 94,177 85,640 6,692 15,020
--------- --------- --------- --------- --------- -------- ---------
$ 55,215 $ 64,658 $ 81,860 $ 140,444 $ 127,041 $ 41,708 $ 50,138
--------- --------- --------- --------- --------- -------- ---------
Direct operating margin $ 159,005 $ 142,324 $ 101,004 $ 104,661 $ 92,439 $ 99,147 $ 74,660
========= ========= ========= ========= ========= ======== =========
Production data
Average sales price (c)
Oil (Bbl) $ 18.88 $ 20.39 $ 16.96 $ 14.80 $ 15.41 $ 18.24 $ 20.34
Gas (Mcf) (b) 2.29 1.97 1.35 1.67 1.94 2.33 1.96
BOE (a) 15.06 14.35 11.00 11.82 13.41 14.96 14.26
Avg. production expense/BOE $ 3.53 $ 3.76 $ 3.99 $ 3.97 $ 4.45 $ 3.91 $ 4.67
Avg. production margin/BOE $ 11.53 $ 10.59 $ 7.01 $ 7.85 $ 8.96 $ 11.05 $ 9.59
<FN>
(a) Gas production is converted to oil equivalents at the rate of 6 Mcf per barrel.
(b) Sales of natural gas liquids are included in gas revenues.
(c) The Company estimates that its composite net wellhead prices at December 31, 1997 were approximately $2.12 per Mcf of
gas and $14.42 per barrel of oil.
</FN>
10
Producing Wells
The following table sets forth certain information at December 31, 1997
relating to the producing wells in which the Company owned a working interest.
The Company also held royalty interests in 101 producing wells. Wells are
classified as oil or gas wells according to their predominant production stream.
Predominant Gross Net
Product Stream Wells Wells
-------------- ----- -----
Crude oil and liquids 1,023 334
Natural gas 463 223
----- -----
1,486 557
===== =====
Acreage
The following table sets forth certain information at December 31, 1997
relating to domestic acreage held by the Company. Developed acreage is acreage
assigned to producing wells. For offshore blocks, in the Gulf of Mexico, the
entire block is classified as developed if a producing well has been drilled
within its boundries. Such blocks could contain up to 5,000 gross acres. In most
instances, the Company does not consider such blocks to be fully developed.
Undeveloped acreage is acreage held under lease, permit, contract or option that
is not in a spacing unit for a producing well, including leasehold interests
identified for development or exploratory drilling.
Gross Net
--------- ---------
Developed 176,190 106,015
Undeveloped (a) 1,131,657 704,668
--------- ---------
1,307,847 810,683
========= =========
<FN>
(a) The Company also holds 130,000 net undeveloped acres under option in
North Louisiana as of February 27, 1998.
</FN>
Drilling Results
The following table sets forth information with respect to wells
drilled during the past three years. The information should not be considered
indicative of future performance, nor should it be assumed that there is
necessarily any correlation between the number of productive wells drilled,
quantities of reserves found or economic value. Productive wells are those that
produce commercial quantities of hydrocarbons whether or not they produce a
reasonable rate of return.
1997 1996 1995
------ ------ ------
Development wells
Productive
Gross 66.0 69.0 223.0
Net 33.3 38.9 133.1
Dry
Gross 3.0 2.0 5.0
Net 1.3 .5 3.8
Exploratory wells
Productive
Gross 2.0 3.0 -
Net .7 .5 -
Dry
Gross 2.0 2.0 -
Net 1.7 1.6 -
At December 31, 1997, the Company had 15 gross (7.1 net) development
wells and 3 gross (1.5 net) exploratory wells in progress.
11
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 1997, Sonat Marketing Company accounted for approximately
17% of revenues, Engage Energy accounted for approximately 14%, and Duke Power
and Energy, which purchases a significant portion of Patina's gas production,
accounted for approximately 12%. In 1996, Duke Power and Energy accounted for
approximately 11% of revenues. In 1995, Amoco Production Company accounted for
approximately 10% 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 strategy focuses on aligning the Company
with substantial marketers that are active in key ares of operation. The Company
also continues to participate in the midstream gas facilities business through
ownership of pipelines and alliances with other companies.
In the Rocky Mountain region, essentially all of the Company's gas is
marketed through contracts with Engage Energy (a partnership between the Coastal
Corporation and Westcoast Energy, Inc.). Under the arrangements, the Company
receives market value for its gas as it is delivered into mainline pipeline
receipt points. The Company also participates in downstream marketing margins
realized by Engage, after recovery of costs, for a broad spectrum of Engage's
marketing activities in Wyoming, Colorado and Utah. The agreements with Engage
extend through March 1999.
Beginning in 1997, the Company pooled its gas transportation facilities
in Wyoming and Colorado with facilities owned by Coastal Field Services to form
Great Divide Gas Services. Great Divide is owned 73% by Coastal Field Services
and 27% by the Company, and encompases over 600 miles of pipeline connected to
more than 650 wells. In addition to expanding existing pipelines in the Uinta,
Piceance and Washakie Basins, Great Divide is working to develop new Rocky
Mountain pipeline and processing opportunities. In 1997, Great Divide was
responsible for the development of a new 16 mile pipeline linking the Company's
gas production in the Piceance Basin directly to Colorado Interstate Gas.
In the Gulf of Mexico, the Company has entered into a new contract with
Williams Energy Services Company ("WESCO") to increase the market access for gas
in this area. In conjunction with the WESCO contract, Transcontinental Gas
Pipeline Corporation ("Transco") and Williams Field Services ("WFS") will be
extending new pipelines into the Main Pass area, with construction expected to
be completed by mid-1998.
As described in "Operations - Offshore - Gulf of Mexico," during 1997
the Company also upgraded its facilities and made arrangements with the major
gathering system in the Main Pass/Viosca Knoll area to remove historical
restraints on production in that area. Since the beginning of 1998, capacity
constraints have increased on pipelines downstream of the gathering system in
southeastern Louisiana. Although the Company cannot predict the extent or
duration of these constraints, it is possible the constraints will depress
realized prices, reduce production, or both. At the present time, the Company
believes that the completion of the new Transco and WFS facilities will allow
the Company's Main Pass gas production to be delivered to markets in the Mobile
Bay area of Alabama, avoiding the pipeline capacity constraints that have
recently developed in southeastern Louisiana.
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 limited
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.
12
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 the Company'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.
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. See "Risk
Factors and Investment Considerations - Environmental and Other Government
Regulation."
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
13
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 material 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 willful misconduct, or by the violation of an applicable federal
safety, construction or operating regulation by the Responsible Party, its agent
or subcontractor.
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.
Risk Factors and Investment Considerations
Price Fluctuations and Markets. The Company's results of operations are
highly dependent upon the prices received for the Company's oil and natural gas
production. The majority of the Company's sales of oil and natural gas are made
in the spot market, or pursuant to contracts based on spot market prices, and
not pursuant to long-term, fixed-price contracts. Accordingly, the prices
received by the Company for its oil and natural gas production are dependent
upon numerous factors beyond the control of the Company. These factors include,
but are not limited to, the level of consumer product demand, governmental
regulations and taxes, the price and availability of alternative fuels, the
level of foreign imports of oil and natural gas, and the overall economic
environment. Significant declines in prices for oil and natural gas could have a
material adverse effect on the Company's financial condition, results of
operations and quantities of reserves recoverable on an economic basis. Should
the industry experience significant price declines from current levels or other
adverse market conditions, the Company may not be able to generate sufficient
cash flow from operations to meet its obligations and make planned capital
expenditures.
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. Prices in effect at December 31, 1997 averaged $14.42 per
barrel of oil and $2.12 per Mcf of gas. Reference prices as of December 31, 1997
were NYMEX oil of $15.50 per barrel, Henry Hub gas of $2.55 per Mcf and CIG
index gas of $1.94 per Mcf. 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.
The availability of a ready market for the Company's oil and natural
gas production also depends on a number of factors, including the demand for and
supply of oil and natural gas and the proximity of reserves to, and the capacity
of, oil and gas gathering systems, pipelines or trucking and terminal
facilities. Wells may be shut-in or constrained for lack of a market or due to
inadequacy or unavailability of pipeline or gathering system capacity. See
"Customers and Marketing."
Replacement of Reserves. In general, the volume of production from oil
and natural gas properties declines as reserves are depleted. Except to the
extent the Company acquires properties containing proved reserves or conducts
successful development and exploration activities, or both, the proved reserves
of the Company will decline as reserves are produced. The Company's future oil
and gas production is, therefore, highly dependent upon its level of success in
finding or acquiring additional reserves at attractive rates of return. In order
to increase reserves and production, the Company must continue its development
drilling and recompletion programs, pursue its exploration drilling programs or
undertake other replacement activities. The Company's current strategy includes
increasing its reserve base by continuing to exploit its existing properties, by
pursuing exploration opportunities and acquiring producing properties. There can
be no assurance, however, that the Company's planned development and exploration
14
projects and acquisition activities will result in significant additional
reserves or that the Company will have continuing success drilling productive
wells at favorable finding costs.
Substantial Capital Requirements. The Company makes, and will continue
to make, substantial capital expenditures for the acquisition, development,
exploration, production and abandonment of oil and natural gas reserves. The
Company intends to finance such capital expenditures primarily with funds
provided by operations and borrowings under its bank credit facility. During
1997, the Company's capital expenditures totaled $116.0 million, including
$106.7 million for development, exploration and gas transportation facilities
and $9.3 million for acquisitions. During 1998, the Company expects to increase
its capital expenditures, excluding acquisitions, to $130 to $140 million.
The Company believes that, after debt service, it will have sufficient
cash provided by operating activities and capital resources to fund planned
capital expenditures for exploration and development activities for the
foreseeable future. However, if revenues decrease as a result of lower oil or
gas prices or otherwise or if the Company incurs substantial additional
indebtedness to finance acquisitions or for other purposes, the Company may have
limited ability to expend the capital necessary to replace its reserves or to
maintain production at current levels, resulting in a decrease in production
over time. If the Company's cash flow from operations is not sufficient to
satisfy its capital expenditure requirements, there can be no assurance that
additional debt or equity financing will be available to meet these
requirements. See "Management's Discussion and Analysis of Financial Condition
and Results of Operations - Financial Condition and Capital Resources."
Acquisition Risks. The Company continually evaluates acquisition
opportunities and frequently engages in bidding and negotiation for
acquisitions, many of which are substantial. If successful in this process, the
Company may be required to alter or increase substantially its capitalization to
finance these acquisitions through the issuance of additional debt or equity
securities, the sale of production payments or otherwise (although the Company's
credit facility and the Indenture for its subordinated notes include covenants
that limit the Company's ability to incur additional indebtedness). Changes in
capitalization may significantly affect the risk profile of the Company.
Significant acquisitions can change the nature of the operations and business of
the Company depending upon the character of the acquired properties, which may
be substantially different in operating or geologic characteristics or
geographic location from existing properties. While the Company intends to
concentrate on acquiring producing properties with development and exploration
potential located in its current areas of operation, the Company may decide to
pursue acquisitions of properties located in other geographic regions. There can
be no assurance that the Company will be successful in the acquisition of any
material property interests.
Drilling Risks. Drilling activities are subject to many risks,
including the risk that no commercially productive reservoirs will be
encountered. There can be no assurance that new wells drilled by the Company
will be productive or that the Company will recover all or any portion of its
investment. Drilling for oil and natural gas may involve unprofitable efforts,
not only from dry wells, but from wells that are productive but that do not
produce sufficient net revenues to return a profit after drilling, operating and
other costs. The cost of drilling, completing and operating wells is often
uncertain. The Company's drilling operations may be curtailed, delayed or
canceled as a result of numerous factors, many of which are beyond the Company's
control, including title problems, weather conditions, compliance with
environmental and other governmental requirements and shortages or delays in the
delivery of equipment and services.
Operating Hazards and Uninsured Risks. The Company's operations are
subject to hazards and risks inherent in drilling for, producing and
transporting oil and natural gas, such as fires, natural disasters, explosions,
formations with abnormal pressures, blowouts, cratering, pipeline ruptures and
spills, any of which can result in loss of hydrocarbons, environmental
pollution, personal injury claims and other damage to properties of the Company
and others. As protection against operating hazards, the Company maintains
insurance coverage against some, but not all, potential losses. The Company's
coverages include, but are not limited to, operator's extra expense, physical
damage on certain assets, comprehensive general liability, automobile and
workers' compensation insurance. The Company believes that its insurance is
adequate and customary for companies of a similar size engaged in operations
similar to those of the Company, but losses could occur for uninsurable or
uninsured risks or in amounts in excess of existing insurance coverage. The
occurrence of an event that is not fully covered by insurance could have a
material and adverse impact on the Company's financial condition and results of
operations.
15
Uncertainty of Estimates of Reserves and Future Net Revenues. There are
numerous uncertainties inherent in estimating quantities of proved reserves,
including many factors beyond the control of the Company. The reserve
information included in this annual report represents estimates based on reports
prepared by the Company's independent petroleum engineers. Petroleum engineering
is not an exact science. Estimates of economically recoverable oil and natural
gas reserves and of future net cash flows necessarily depend upon a number of
variable factors and assumptions, such as historical production from the area
compared with production from other producing areas, the assumed effects of
regulation by governmental agencies and assumptions concerning future oil and
natural gas prices, future operating costs, severance and excise taxes, capital
expenditures and workover and remedial costs, all of which may in fact vary
considerably from actual results. For these reasons, estimates of
classifications of such reserves based on risk of recovery and estimates of
expected future net cash flows prepared by different engineers or by the same
engineers at different times may vary substantially. Actual production, revenues
and expenditures with respect to the Company's reserves will likely vary from
estimates, and the variances may be material.
The present values of future net cash flows referred to in this annual
report should not be construed as either the current market value of the
estimated oil and gas reserves attributable to the Company's properties or a
prediction of the future net cash flows from those properties. In accordance
with applicable requirements of the Securities and Exchange Commission (the
"Commission"), the discounted future net cash flows from proved reserves are
determined in accordance with certain rules designed to facilitate uniform
presentation by different companies. The present values and future cash flows
are generally based on prices and costs as of the date of the estimate, whereas
actual future prices and costs may be materially higher or lower. Future net
cash flows also will be affected by factors such as the amount and timing of
actual production and expenses, supply and demand for oil and gas, curtailments
or increases in consumption by gas purchasers and changes in governmental
regulations or taxation. In addition, the 10% discount factor, which is required
by the Commission to be used to calculate discounted future net cash flows for
reporting purposes, is not necessarily the most appropriate discount factor
based on interest rates in effect from time to time and risks associated with
the Company or the oil and gas industry in general.
Environmental and Other Governmental Regulation. The Company's
operations are affected by extensive regulation pursuant to various federal,
state and local laws and regulations relating to the exploration for, and the
development, production, transportation and marketing of, oil and natural gas
and the release of materials into the environment or otherwise relating to
protection of the environment. In particular, the Company's oil and natural gas
exploration, development and production, and its activities in connection with
the storage and transportation of liquid hydrocarbons, are subject to stringent
environmental regulations by governmental authorities. Such regulations have
increased the costs of planning, designing, drilling, installing, operating and
abandoning oil and natural gas wells and other related facilities.
The Company is required to expend significant resources, both financial
and managerial, to comply with environmental regulations and permitting
requirements. Although the Company believes that its operations are in general
compliance with all such laws and regulations, risks of substantial costs and
liabilities are inherent in oil and natural gas operations, and there can be no
assurance that significant costs and liabilities will not be incurred in the
future. Moreover, it is possible that other developments, such as increasingly
strict environmental laws and regulations and enforcement policies thereunder,
and claims for damages to property, employees, other persons and the environment
resulting from the Company's operations, could result in substantial costs and
liabilities in the future.
The Company expects to maintain customary insurance coverage for its
operations, including coverage for sudden environmental damages, but does not
believe that insurance coverage that explicitly covers environmental damages
that occur over time will be available at a reasonable cost. The Company does
not believe that insurance coverage against the full potential liability that
could be caused by environmental damages is currently available at a reasonable
cost. Accordingly, the Company might be subject to uninsured or only partially
insured liability because of the prohibitive premium costs of insuring against
certain hazards.
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. Environmental impact statements are currently
pending in two significant areas of the Company's operations, the Deep Green
River Basin and the northern part of the Washakie Basin. Approval of new
drilling in these areas is limited until the statements receive final approval.
While the timing of final approval, and terms of conditions placed on
development in the affected areas, is uncertain, the Company currently does not
16
expect the statements to significantly impact plans to develop these two areas.
However, delays in approving the statements or the inclusion of unexpected
conditions, could limit or delay development plans in these areas in 1998, and
possibly beyond.
Competition. The oil and gas industry is highly competitive. The
Company will compete in the acquisition, development, production and marketing
of oil and natural gas with major oil companies, other independent oil and
natural gas concerns and individual producers and operators. There is also
competition in the hiring of experienced personnel. Many of the Company's
competitors have substantially greater financial and other resources than the
Company. Furthermore, the oil and natural gas industry competes with other
industries in supplying the energy and fuel needs of industrial, commercial and
other consumers.
Forward-looking Information
All statements other than statements of historical fact contained in
this Annual Report on Form 10-K 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 the Private Securities Litigation Reform Act of 1995. Such
forward-looking statements may be or may concern, among other things, capital
expenditures, drilling activity, acquisitions and dispositions, 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.
Forward-looking statements generally are accompanied by words such as
"anticipate," "believe," "estimate," "expect," "intend," "plan," "project,"
"potential" or similar statements. Although the Company believes that the
expectations reflected in such forward-looking statements are reasonable, no
assurance can be given that such expectations will prove correct. Factors that
could cause the Company's results to differ materially from the results
discussed in such forward-looking statements include the risks described under
"Risk Factors and Investment Considerations," such as the fluctuations of the
prices received or demand for the Company's oil and gas, the ability to replace
depleting reserves, potential additional indebtedness, the requirements for
capital, drilling risks, operating hazards, the cost and availability of
drilling rigs, acquisition risks, the uncertainty of reserve estimates,
competition and the effects of governmental and environmental regulation. All
forward-looking statements are expressly qualified in their entirety by the
cautionary statements in this section.
Officers
Listed below are the officers of the Company and a summary of their
business experience.
Name Position
- ------------------------ -------------------------------------------------
John C. Snyder Chairman
William G. Hargett President and Chief Operating Officer
Charles A. Brown Senior Vice President - Rocky Mountain Region
Mark A. Jackson Senior Vice President and Chief Financial Officer
Jay H. Smith Senior Vice President - Southern Region
Steven M. Burr Vice President - Engineering and Planning
Peter E. Lorenzen Vice President - General Counsel
H. Richard Pate Vice President - Rocky Mountain Region, Operations and Engineering
David M. Posner Vice President - Gas Management
Roger B. Rice Vice President - Human Resources
Rodney L. Waller Vice President - Treasurer
John C. Snyder (55), Chairman and a director, 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. From
1969 to 1971, Mr. Snyder was with Canadian-American Resources Fund, Inc., which
he founded. From 1964 to 1966, Mr. Snyder was employed by Humble Oil and
17
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. In 1995, Mr.
Snyder was named Wildcatter of the Year by the Independent Petroleum Association
of Mountain States. He currently serves as a director of SOCI plc and is a
member of the National Petroleum Council.
William G. Hargett (48), President, Chief Operating Officer and a
director, has been with the Company since April 1997. Prior to joining the
Company, Mr. Hargett served as President of Greenhill Petroleum Corporation from
1994 to 1997, Amax Oil & Gas, Inc. from 1993 to 1994 and North Central Oil
Corporation from 1988 to 1993 and in various exploration capacities at Tenneco
Oil Company from 1974 to 1988 and Amoco Production Company from 1973 to 1974.
Mr. Hargett earned Bachelor of Science and Master of Science degrees from the
University of Alabama.
Charles A. Brown (50), Senior Vice President - Rocky Mountain Region,
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.
Mark A. Jackson (42), Senior Vice President and Chief Financial
Officer, joined the Company in August, 1997. Prior to joining the Company, Mr.
Jackson served in various executive capacities at Apache Corporation including
Vice President and Controller from 1988, Vice President, Finance from 1994 and
Chief Financial Officer from 1996. From 1984 until 1988, Mr. Jackson served as
Assistant Controller of Diamond Shamrock and Maxus Energy Company. Mr. Jackson
began his career with the certified public accounting firm of Ernst & Ernst,
specializing in the oil and gas industry. Mr. Jackson received his Bachelor of
Science degree in Accounting from Oklahoma Christian University.
Jay H. Smith (51), Senior Vice President - Southern Region, joined
the Company in February 1998. From 1993 until he joined the Company, Mr. Smith
served as Executive Vice President of Sonat Exploration Company. From 1983 until
1993, Mr. Smith served in a variety of positions with BP Exploration and Sohio
Petroleum Company, most recently as Chief of Staff, Western Hemisphere North.
From 1981 to 1983, Mr. Smith was Vice President - Operations of Spectrum Oil and
Gas Company. Mr. Smith began his career with Shell Oil Company in 1968. Mr.
Smith received his Bachelor of Science degree from Syracuse University.
Steven M. Burr (41), 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 and attended the Program for Management
Development at the Harvard University School of Business Administration.
Peter E. Lorenzen (48), 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 (44), Vice President - Rocky Mountain Region,
Operations and Engineering, joined the Company in 1988. From 1981 to 1988, Mr.
Pate held various positions with Mitchell Energy Corporation, including Region
Engineer and Production Manager. He was employed by Champlin Petroleum Company
from 1979 to 1981 and Atlantic Richfield Corporation from 1975 to 1979. Mr. Pate
received his Bachelor of Science degree in Chemical Engineering from the
University of Wyoming.
David M. Posner (44), Vice President - Gas Management, joined the
Company in 1991. From 1980 to 1991 he held various positions with Ladd Petroleum
Corporation (a subsidiary of the General Electric Company) including Vice
President of Gas Gathering, Processing and Marketing. Mr. Posner received his
Bachelor of Arts degree from Brown University and his Master of Science in
Mineral Economics from the Colorado School of Mines.
Roger B. Rice (53), Vice President - Human Resources, joined the
Company in 1997. From 1992 to 1997, Mr. Rice was Vice President Human Resources
18
and Administration with Apache Corporation. From 1989 to 1992, he was Managing
Consultant with Barton Raben, Inc., an executive search and consulting firm
specializing in the energy industry. Previously, Mr. Rice was Vice President
Administration for The Superior Oil Company and held various management
positions with Shell Oil Company. He earned his Bachelor of Arts degree and
Masters Degree in Business Administration from Texas Technological University.
Rodney L. Waller (48), Vice President - Treasurer, joined the Company
in 1977 as an officer. Since that time, Mr. Waller has performed various
corporate, operational and finance functions. Previously, Mr. Waller was
employed by Arthur Andersen & Co. Mr. Waller received his Bachelor of Arts
degree from Harding University.
ITEM 3. LEGAL PROCEEDINGS
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, have unlawfully comingled production with
production from other leases and have breached their duties to reasonably
develop the lease. The plaintiffs also claim damages for fraud, trespass and
similar matters, and demand actual and punitive damages. Although the complaint
does not specify the amount of damages claimed, plaintiffs have submitted
calculations showing total damages against all owners in excess of $100 million.
The Company and the other interest owners have filed an answer denying the
claims and intend to contest the suit vigorously. The suit is currently in
discovery.
At this time, the Company is unable to estimate the range of potential
loss, if any, from the foregoing uncertainty. However, the Company believes that
resolution should not have a material adverse effect on 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 VOTE OF SECURITY HOLDERS
No matters were submitted for a vote of security holders during the
fourth quarter of 1997.
19
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 trades
under the symbol "SNY." The following table sets forth, for 1997 and 1996, the
high and low closing prices for the Company's securities for New York Stock
Exchange composite transactions, as reported by The Wall Street Journal.
-----------------------
1997 1996
--------------------- ---------------------
High Low High Low
------- ------- ------- -------
First Quarter $19-1/8 $14-5/8 $12-1/8 $ 7-1/4
Second Quarter 19 15-1/4 10-1/4 7-5/8
Third Quarter 23-5/8 18-3/16 12 9-3/8
Fourth Quarter 24-7/8 16-3/4 17-3/4 11-3/4
On February 27, 1998, the closing price of the common stock was
$18-5/8. Quarterly dividends were paid at the rate of $.065 per share during
1997 and 1996. For federal income tax purposes, 100% of common dividends paid
during 1996 were a non-taxable return of capital. The Company's dividend
payments in 1997 were 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, capital
expenditures and other factors. On December 31, 1997, there were approximately
2,300 holders of record of the common stock and 33.3 million shares outstanding.
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,
1997. 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.
(In thousands, except per share data) As of or for the Year Ended December 31,
-----------------------------------------------------------------
1997 1996 1995 1994 1993
---------- ---------- ---------- ---------- ----------
Income Statement
Revenues $ 255,728 $ 285,111 $ 197,301 $ 262,328 $ 228,852
Income (loss) before extraordinary items 35,465 62,950 (39,831) 12,372 22,538
Per share .96 1.81 (1.53) .07 .58
Net income (loss) 32,617 62,950 (39,831) 12,372 19,545
Per share .87 1.81 (1.53) .07 .45
Dividends per share .26 .26 .26 .25 .22
Weighted average shares outstanding 30,588 31,308 30,186 23,704 23,096
Cash Flow
Net cash provided by operations $ 122,041 $ 101,730 $ 69,121 $ 86,397 $ 68,728
Net cash realized (used) by investing 31,808 (62,356) 32,421 (245,503) (207,933)
Net cash realized (used) by financing (92,328) (38,715) (96,012) 169,926 129,633
Balance Sheet
Working capital $ 56,326 $ 9,168 $ 5,842 $ 708 $ 491
Oil and gas properties, net 274,304 635,387 435,217 472,239 316,406
Total assets 546,088 879,459 555,493 673,259 453,301
Senior debt 1 188,231(a) 150,001 234,857 114,952
Subordinated notes 173,635 183,842(b) 84,058 83,650 -
Stockholders' equity 263,756 294,668 235,368 274,086 274,734
<FN>
(a) Includes $93.7 million of SOCO senior debt and $94.5 million of Patina senior debt.
(b) Includes $80.7 million of SOCO convertible subordinated notes and $103.1 million of Patina subordinated notes.
</FN>
20
The following table sets forth unaudited summary financial results on a
quarterly basis for the two most recent years.
(In thousands, except per share data) 1997
-----------------------------------------------
First Second Third Fourth
-------- --------- --------- --------
Revenues $ 87,664 $ 73,187 $ 56,299 $ 38,578
Depletion, depreciation and amortization and property impairments 23,208 23,389 26,802 13,738
Gross profit 30,637 13,960 16,791 17,755
Income before extraordinary items 19,926 5,992 3,633 5,914
Per share .59 .15 .07 .14
Net income 19,926 3,144 3,633 5,914
Per share .59 .05 .07 .14
(In thousands, except per share data) 1996
-----------------------------------------------
First Second Third Fourth
-------- --------- -------- --------
Revenues $ 40,960 $ 54,604 $ 59,960 $129,587
Depletion, depreciation and amortization and property impairments 16,771 22,745 24,673 23,111
Gross profit 9,376 11,099 10,835 26,467
Income (loss) before extraordinary items 1,777 (9,983) 5,560 65,596
Per share .01 (.37) .13 2.06
Net income (loss) 1,777 (9,983) 5,560 65,596
Per share .01 (.37) .13 2.06
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
Overview
Snyder Oil Corporation (the "Company") is engaged in the production,
development, acquisition and exploration of domestic oil and gas properties,
primarily in the Gulf of Mexico, the Rocky Mountains and northern Louisiana. The
Company also has investments in two international exploration and production
companies, SOCO International plc ("SOCI plc") and Cairn Energy plc ("Cairn"),
both listed on the London Stock Exchange.
During 1997, the Company consummated several transactions to simplify
its operating and capital structure.
* The Company exchanged its international operational holdings for stock
in SOCI plc, which simultaneously completed an initial public offering
of its stock on the London Stock Exchange to raise capital to fund its
ongoing exploration and development efforts. This transaction
effectively replaced the Company's equity investments in various
international ventures with one marketable security.
* The Company issued $175 million in ten-year, 8.75% subordinated debt
and used the proceeds to redeem the outstanding 7% convertible
subordinated debt and to pay down its revolving credit facility. These
transactions provided the capacity for the Company to enter into a
large acquisition from existing credit sources, extended the maturity
of subordinated debt at an attractive rate for the next ten years and
eliminated the potential dilution of common shareholders from the
convertible subordinated debt.
* The Company sold its 74% interest in Patina Oil and Gas Corporation
("Patina") for approximately $127 million in cash and the elimination
of approximately $170 million in debt. This transaction provided cash
and additional acquisition capacity while simplifying the capital
structure of the Company. Patina was restricted by its debt covenants
from paying dividends to its shareholders; thus the Company did not
directly benefit from the cash flow of Patina.
* The Company issued 300,000 common shares in exchange for 2.1 million
outstanding warrants, which also reduced the potential dilution of the
common shareholders of the Company.
* The Company called its preferred stock for redemption with 72%
converting to common (3.6 million shares issued) and the remainder
being redeemed for $30.1 million of cash. This transaction eliminated
1.4 million shares of additional potential dilution to the common
shareholders of the Company and over $6 million per year in dividend
payments.
21
The aforementioned transactions simplified the Company's capital
structure and, together with the sale of nonstrategic assets during 1995 and
1996, positioned the Company to focus on its core growth areas with all future
increases in value going to the common shareholders of the Company.
Unless indicated otherwise, amounts in this discussion reflect the
consolidated results of the Company, including Patina. References to the Company
"excluding Patina" refer to the Company on a consolidated basis but after
excluding amounts attributable to Patina.
Results of Operations
Comparison of 1997 results to 1996. Net income for 1997 was $32.6
million as compared to $63.0 million in 1996. During 1997, the Company
recognized a $13.0 million gain on the sale of 4.5 million shares of Cairn stock
and a $19.8 million gain on the formation of SOCI plc. Net income in 1996
benefited from a $65.5 million gain on the exchange of the Company's stock held
in Command Petroleum Limited ("Command"), for stock in Cairn, a United Kingdom
based company.
The following table sets forth certain operating information of the
Company for the periods presented.
Excluding Patina Consolidated
----------------------- Increase ----------------------- Increase
1997 1996 (Decrease) 1997 1996 (Decrease)
-------- -------- ---------- --------- -------- ----------
Oil and gas sales (in thousands) $133,851 $107,143 25% $207,216 $189,327 9%
Production margin (in thousands) $ 98,835 $ 72,025 37% $158,693 $139,689 14%
Daily production:
Oil (Bbls) 5,617 6,000 (6%) 9,561 10,611 (10%)
Gas (Mcf) 113,361 87,139 30% 168,873 152,570 11%
Equivalent barrels (BOE) 24,510 20,525 19% 37,707 36,040 5%
Average Prices:
Oil ($/Bbl) $ 18.24 $ 20.34 (10%) $ 18.88 $ 20.39 (7%)
Gas ($/Mcf) $ 2.33 $ 1.96 19% $ 2.29 $ 1.97 16%
Equivalent barrel ($/BOE) $ 14.96 $ 14.26 5% $ 15.06 $ 14.35 5%
DD&A per BOE $ 4.87 $ 5.29 (10%) $ 5.80 $ 6.41 (10%)
Oil and gas sales, excluding Patina, increased 25% due to a significant
increase in gas production along with higher gas prices. Production in the Gulf
of Mexico more than doubled due to two fourth quarter 1996 acquisitions and the
Company's drilling efforts beginning to come on stream. The Rocky Mountain
Region also increased production due to successful development drilling
primarily in the second and third quarters of 1997, but the increase was
partially offset by sales of nonstrategic properties during 1996. The Company
expects increasing production from exploratory and development drilling during
1997 and 1998 to largely replace Patina's 1997 production contribution by the
end of 1998. The largest contributor to increased production in 1998 is expected
to be the commencement of production from the Ingrid Field in the Gulf of Mexico
by April 1998.
Production margin (oil and gas sales less direct operating expenses)
for 1997, excluding Patina, increased 37% compared to 1996 as direct operating
expenses decreased in spite of the significant increase in production. This is
primarily due to the sale of noncore properties which had high operating costs,
increased production in the Gulf of Mexico which has much lower operating costs
per BOE produced, and an increased emphasis on operating efficiencies. Operating
costs per BOE, excluding Patina, were $3.91 compared to $4.67 in 1996.
Gains on sales of properties of $8.7 million in 1997 and $8.8 million
in 1996 were a result of the Company's ongoing plan to divest of nonstrategic
assets. The most significant items in 1997 were the sales of two noncore
properties in the Gulf of Mexico for a $5.1 million gain. The most significant
item during 1996 was a $7.4 million gain on the sale of a 50% interest in the
Green River Basin holdings.
General and administrative expenses, net of reimbursements, for 1997
were $20.4 million, a $3.2 million increase compared to 1996 as several of the
22
properties sold during 1996, while having high operating costs and depletion,
depreciation and amortization rates, provided significant general and
administrative expense reimbursements. Net general and administrative costs have
declined three to six percent each quarter since the fourth quarter of 1996.
There was a 16% decrease in the fourth quarter of 1997 attributable to the
disposition of Patina.
Interest expense, net of interest income, was $23.0 million in 1997,
$12.5 million of which was incurred by Patina. In 1996, interest expense, net of
interest income, was $22.9 million, $14.3 million of which was incurred by
Patina. The majority of the increase was the result of higher average interest
rates, as subordinated notes represented a higher percentage of total debt.
Interest income in 1997 was $2.4 million compared to $664,000 in 1996 as the
Company had a higher average cash balance, particularly in the fourth quarter of
1997, due to the proceeds from the disposition of Patina.
Depletion, depreciation and amortization expense for 1997 decreased
$4.7 million to $79.9 million in spite of higher production levels. The decrease
is primarily due to higher 1996 amortization costs on a noncompete agreement at
Patina, but was also the result of lower production depletion, depreciation and
amortization rates. Production depletion, depreciation and amortization per BOE,
excluding Patina, was $4.44 in 1997 compared to $4.70 in 1996. The lower rates
were the result of upward revisions in reserve quantities at year end 1996
primarily in proved undeveloped reserves which became economic at year end 1996
prices.
Property impairments in 1997 included a $4.5 million impairment
recorded on the Uinta Field. At the end of 1996, Uinta prices benefited from a
tight local oil supply and very high Rocky Mountain area oil prices. Since then,
new supplies have depressed the oil market and prices in the area have returned
to more normal levels. Additionally, a $2.2 million impairment was recorded on a
Gulf of Mexico oil well after it did not respond to workover attempts.
Comparison of 1996 results to 1995. Total revenues for 1996 were $285.1
million, a $87.8 million increase from 1995. The increase was in large part due
to a $67.2 million increase in gains on sales of investments which was 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 for stock in Cairn. 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 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, 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 remained relatively constant from 1995 to 1996 which
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 in 1995 and 1996 and the reduction of development drilling.
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.
23
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 Russia and Mongolia. In January 1997,
the Company's interest in Mongolia was further reduced.
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, net of other expense, increased $1.8 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 Patina transaction.
Net financing costs were $22.9 million compared to $21.7 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.
Acquisition, Exploration and Development
During 1997, the Company, excluding Patina incurred $103.9 million in
capital expenditures, including $74.7 million for development, $17.2 million for
exploration, $8.9 million for property acquisitions, $2.2 million for field and
office equipment and $900,000 for gas facility expansion.
Of the total development expenditures, $36.4 million was concentrated
in the Gulf of Mexico where five wells were placed on sales with two in progress
at year end. The Company expended $13.0 million in the East Washakie Basin of
southern Wyoming to place 19 wells on sales with five in progress at year end.
In the Green River Basin of southern Wyoming, $10.1 million was incurred to
place 16 wells on sales with five in progress at year end. The Company expended
$6.2 million in the Piceance Basin of western Colorado to place 22 wells on
sales with two in progress at year end.
Exploration expenditures for 1997 totaled $17.2 million, including $8.0
million for two exploratory dry holes drilled in the Gulf of Mexico. The Company
has been successful on two of four exploratory wells in the Gulf of Mexico. The
balance is primarily the cost of 3-D seismic in the Gulf of Mexico ($4.5
million), in northern Louisiana ($2.3 million) and in the Rocky Mountain region
($2.2 million).
24
The Company, excluding Patina, expended $8.9 million relating to
property acquisitions during 1997. Of this amount, $3.3 million was for
producing properties and $5.6 million was for unevaluated properties.
Financial Condition and Capital Resources
During 1997, net cash provided by operations was $122.0 million, an
increase of 20% compared to 1996. As of December 31, 1997, commitments for
capital expenditures totaled $10.3 million. The Company anticipates that 1998
expenditures for exploration and development will approximate $130 to $140
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,
available cash, marketable securities and existing credit facilities.
At December 31, 1997, the Company had total assets of $546.1 million.
Total capitalization was $437.4 million, of which 60% was represented by
stockholders' equity and 40% by subordinated debt. At December 31, 1997, the
Company had $89.4 million in cash, and marketable securities with a market value
of $143.1 million for its shares of Cairn and SOCI plc. The Patina disposition
generated cash proceeds of approximately $127 million, of which $30.1 million
was used in the fourth quarter to redeem the preferred stock.
The Company 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, 1997 was
$120 million. During 1997, the average interest rate under the facility was
6.5%. At December 31, 1997, the Company had $1,000 outstanding under the
facility. Covenants, in addition to other requirements, require maintenance of a
current working capital ratio of 1 to 1 as defined, limit the incurrence of
additional debt and restrict dividends, stock repurchases, certain investments,
other indebtedness and unrelated business activities. Such restricted payments
are limited by a formula that includes proceeds from certain securities, cash
flow and other items. Based on such limitations, more than $120 million was
available for the payment of dividends and other restricted payments at December
31, 1997.
In June 1997, SOCO issued $175.0 million of 8.75% Senior Subordinated
Notes ("Notes") due June 15, 2007. The net proceeds of the offering were $168.3
million which were used to redeem the Company's convertible subordinated notes
due May 15, 2001, and reduce the balance outstanding under the SOCO Facility.
Through the issuance of the new Notes and the redemption of the old notes, the
Company has effectively extended its debt maturity by over six years. The Notes
contain covenants that, among other things, limit the ability of SOCO 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 unrestricred subsidiaries. Such restricted payments are
limited by a formula that includes proceeds from certain securities, cash flow
and other items. Based on such limitations, more than $100 million was available
for the payment of dividends and other restricted payments at December 31, 1997.
The Company seeks to diversify its exploration and development risks by
attracting partners for its significant development projects and maintaining a
program to divest of marginal properties and assets which do not fit its long
range plans. During 1997, the Company received $10.7 million in proceeds from
sales of properties which were used primarily to fund development expenditures.
None of the sales were individually significant.
The Board has authorized, at management's discretion, the repurchase of
up to $70 million of the Company's securities. During 1996 and 1997, the Company
repurchased 3.4 million common shares for $52.6 million under this plan. During
1997, the Company redeemed its preferred depositary shares by issuing 3.6
million shares of common stock and paying $30.1 million in cash. As a result, a
$1.0 million redemption premium is included in preferred dividends in the 1997
consolidated statement of operations.
The Company has developed a plan to ensure its systems are compliant
with the requirements to process transactions in the year 2000 and beyond. The
25
majority of the Company's systems are already compliant, with a detailed plan
for the remaining systems scheduled to be modified or replaced within one year.
The costs associated with final compliance are not considered material.
The Company believes that its capital resources are adequate to meet
the requirements of its business. However, future cash flows are subject to a
number of variables including the level of production and oil and gas prices,
and there can be no assurance that operations and other capital resources will
provide cash in sufficient amounts to maintain planned levels of capital
expenditures or that increased capital expenditures will not be undertaken.
Inflation and Changes in Prices
While certain of the Company's 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. In addition, changing prices often cause costs
of equipment and supplies to vary as industry activity levels increase and
decrease to reflect perceptions of future price levels. 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
1997 and 1996. Average gas prices for 1997 and 1996 were increased by $.05 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.
Average Prices
--------------------------------------------
Crude Oil
and Natural Equivalent
Liquids Gas Barrels
--------- --------- ---------
(Per Bbl) (Per Mcf) (Per BOE)
Annual
------
1997 $ 18.88 $ 2.29 $ 15.06
1996 20.39 1.97 14.35
1995 16.96 1.35 11.00
1994 14.80 1.67 11.82
1993 15.41 1.94 13.41
Quarterly
---------
1997
----
First $ 21.18 $ 2.83 $ 18.10
Second 18.33 1.85 13.09
Third 18.09 1.97 13.38
Fourth 16.86 2.65 16.09
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
In December 1997, the Company received an average of $15.37 per barrel
and $2.43 per Mcf for its production.
26
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTAL DATA
Reference is made to the Index to Consolidated Financial Statements on
page 28 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 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
27
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Page
----
Report of Independent Public Accountants......................................29
Consolidated Balance Sheets as of December 31, 1997 and 1996..................30
Consolidated Statements of Operations
for the years ended December 31, 1997, 1996 and 1995.....................31
Consolidated Statements of Changes in Stockholders' Equity
for the years ended December 31, 1997, 1996 and 1995.....................32
Consolidated Statements of Cash Flows
for the years ended December 31, 1997, 1996 and 1995.....................33
Notes to Consolidated Financial Statements....................................34
28
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,
1997 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, 1997. 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, 1997 and 1996, and the results
of their operations and their cash flows for each of the three years in the
period ended December 31, 1997, 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.
ARTHUR ANDERSEN LLP
Fort Worth, Texas,
February 10, 1998
29
SNYDER OIL CORPORATION
CONSOLIDATED BALANCE SHEETS
(In thousands)
December 31,
--------------------------------
1997 1996
---------- -----------
ASSETS
Current assets
Cash and equivalents $ 89,443 $ 27,922
Accounts receivable 21,521 58,944
Inventory and other 2,911 11,212
---------- -----------
113,875 98,078
---------- -----------
Investments 143,066 129,681
---------- -----------
Oil and gas properties, successful efforts method 410,973 887,721
Accumulated depletion, depreciation and amortization (136,669) (252,334)
---------- -----------
274,304 635,387
---------- -----------
Gas facilities and other 21,317 28,111
Accumulated depreciation and amortization (6,474) (11,798)
---------- -----------
14,843 16,313
---------- -----------
$ 546,088 $ 879,459
========== ===========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities
Accounts payable $ 23,278 $ 51,867
Accrued liabilities 34,271 37,043
---------- -----------
57,549 88,910
---------- -----------
Senior debt 1 188,231
Subordinated notes 173,635 103,094
Convertible subordinated notes - 80,748
Deferred taxes payable 31,649 9,034
Other noncurrent liabilities 19,498 28,064
Minority interest - 86,710
Commitments and contingencies
Stockholders' equity
Preferred stock, $.01 par, 10,000,000 shares authorized,
6% Convertible preferred stock, zero and 1,033,500
shares issued and outstanding - 10
Common stock, $.01 par, 75,000,000 shares authorized,
35,696,213 and 31,456,027 issued 357 315
Capital in excess of par value 234,118 260,221
Retained earnings 44,390 25,711
Common stock held in treasury, 2,366,891 and 250,000 shares at cost (40,461) (3,510)
Unrealized gain on investments 25,352 11,921
---------- -----------
263,756 294,668
---------- -----------
$ 546,088 $ 879,459
========== ===========
The accompanying notes are an integral part of these statements.
30
SNYDER OIL CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands except per share data)
Year Ended December 31,
--------------------------------------------
1997 1996 1995
----------- ----------- -----------
Revenues
Oil and gas sales $ 207,216 $ 189,327 $ 144,608
Gas transportation, processing and marketing 7,004 17,655 38,256
Gains on sales of equity interests in investees 32,800 69,343 2,183
Gains on sales of properties 8,708 8,786 12,254
---------- ----------- -----------
255,728 285,111 197,301
---------- ----------- -----------
Expenses
Direct operating 48,523 49,638 52,486
Cost of gas and transportation 6,692 15,020 29,374
Exploration 17,046 4,232 8,033
General and administrative 20,363 17,143 17,680
Financing costs, net 23,029 22,923 21,679
Other expense (income) 935 (1,327) 463
Litigation settlement - - 4,400
(Gain) loss on sale of subsidiary interest (5,437) 15,481 -
Depletion, depreciation and amortization 79,862 84,547 76,378
Property impairments 7,275 2,753 27,412
---------- ----------- -----------
Income (loss) before income taxes, minority interest
and extraordinary item 57,440 74,701 (40,604)
---------- ----------- -----------
Provision (benefit) for income taxes
Current 975 33 25
Deferred 16,881 4,313 (1,370)
---------- ----------- -----------
17,856 4,346 (1,345)
---------- ----------- -----------
Minority interest in subsidiaries 4,119 7,405 572
---------- ----------- -----------
Income (loss) before extraordinary item 35,465 62,950 (39,831)
Extraordinary item - loss on early extinguishment of debt,
net of income tax benefit of $1,533 2,848 - -
---------- ----------- -----------
Net income (loss) 32,617 62,950 (39,831)
---------- ----------- -----------
Preferred dividends 5,978 6,210 6,210
---------- ----------- -----------
Income (loss) applicable to common $ 26,639 $ 56,740 $ (46,041)
========== =========== ===========
Income (loss) per common share before extraordinary item $ .96 $ 1.81 $ (1.53)
========== =========== ===========
Net income (loss) per common share $ .87 $ 1.81 $ (1.53)
========== =========== ===========
Income (loss) per common share before extraordinary
item - assuming dilution $ .95 $ 1.72 $ (1.53)
========== =========== ===========
Net income (loss) per common share - assuming dilution $ .86 $ 1.72 $ (1.53)
========== =========== ===========
Weighted average shares outstanding 30,588 31,308 30,186
========== =========== ===========
The accompanying notes are an integral part of these statements.
31
SNYDER OIL CORPORATION
CONSOLIDATED STATEMENTS OF CHANGES IN
STOCKHOLDERS' EQUITY
(In thousands)
Preferred Stock Common Stock Capital in Retained
------------------ ------------------- Excess of Earnings Treasury
Shares Amount Shares Amount Par Value (Deficit) Stock
------ ------ ------ -------- --------- --------- --------
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)
Common stock grants and
exercise of options - - 607 6 2,951 - -
Issuance of treasury - - - - - - 8,655
Conversion of subordinated
notes into common - - 1 - 25 - -
Repurchase of common - - - - - - (45,606)
Redemption of preferred (291) (3) - - (29,050) (1,049) -
Conversion of preferred (743) (7) 3,632 36 (29) - -
Dividends - - - - - (12,889) -
Net income - - - - - 32,617 -
------- -------- ------- -------- --------- --------- ---------
Balance, December 31, 1997 - - 35,696 $ 357 $ 234,118 $ 44,390 $ (40,461)
======= ======== ======= ======== ========= ========= =========
The accompanying notes are an integral part of these statements.
32
SNYDER OIL CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
Year Ended December 31,
---------------------------------------------
1997 1996 1995
------------ ----------- ----------
Operating activities
Net income (loss) $ 32,617 $ 62,950 $ (39,831)
Adjustments to reconcile net income (loss) to net
cash provided by operations
Amortization of deferred credits - (1,052) (2,511)
Gains on sales of investments (32,800) (68,343) (809)
Gains on sales of properties (8,708) (8,786) (12,254)
Exploration expense 17,046 4,232 8,033
Equity in (earnings) losses of unconsolidated subsidiaries (760) (421) 1,319
(Gain) loss on sale of subsidiary interest (5,437) 15,481 -
Depletion, depreciation and amortization 79,862 84,547 76,378
Property impairments 7,275 2,753 27,412
Deferred taxes 15,348 4,313 (1,370)
Minority interest 4,119 7,405 572
Loss on early extinguishment of debt 4,381 - -
Changes in current and other assets and liabilities
Decrease (increase) in
Accounts receivable 24,612 (15,869) 7,142
Inventory and other 426 5,175 3,617
Increase (decrease) in
Accounts payable (8,688) 2,771 (8,521)
Accrued liabilities (9,497) (316) 5,165
Other liabilities 2,245 6,890 4,779
----------- ----------- ----------
Net cash provided by operations 122,041 101,730 69,121
----------- ----------- ----------
Investing activities
Acquisition, development and exploration (135,901) (128,598) (92,353)
Proceeds from sales of investments 156,969 1,635 14,786
Outlays for investments - (9,013) -
Proceeds from sales of properties 10,740 73,620 109,988
----------- ----------- ----------
Net cash realized (used) by investing 31,808 (62,356) 32,421
----------- ----------- ----------
Financing activities
Issuance of common 2,982 1,523 688
Issuance of subordinated notes 168,261 - -
Increase (decrease) in senior indebtedness (89,775) (13,289) (86,193)
Early extinguishment of convertible subordinated notes (85,199) - -
Dividends (12,889) (14,411) (14,056)
Deferred credits - (120) 3,549
Redemption of preferred (30,102) - -
Repurchase of stock (45,606) (7,186) -
Repurchase of subordinated notes - (5,232) -
----------- ----------- ----------
Net cash used by financing (92,328) (38,715) (96,012)
----------- ----------- ----------
Increase in cash 61,521 659 5,530
Cash and equivalents, beginning of year 27,922 27,263 21,733
----------- ----------- ----------
Cash and equivalents, end of year $ 89,443 $ 27,922 $ 27,263
=========== =========== ==========
Noncash investing and financing activities
Acquisition of properties and stock via stock issuances $ 8,655 $ 3,693 $ 13,032
Acquisition of properties recorded as senior debt - 31,730 -
Acquisition via subsidiary stock issuance - 115,067 -
Exchange of subsidiary stock for stock of investee 30,923 - -
The accompanying notes are an integral part of these statements.
33
SNYDER OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) ORGANIZATION AND NATURE OF BUSINESS
Snyder Oil Corporation ("SOCO") and its subsidiaries (collectively, the
"Company") are engaged in the production, development, acquisition and
exploration of domestic oil and gas properties, primarily in the Gulf of Mexico,
the Rocky Mountains and northern Louisiana. The Company also has investments in
two international exploration and production companies, SOCO International plc
("SOCI plc") and Cairn Energy plc ("Cairn"). The Company, a Delaware
corporation, is the successor to a company formed in 1978.
In October 1997, the Company sold its 74% interest in Patina Oil and
Gas Corporation ("Patina"). Net proceeds from the sale were approximately $127
million resulting in a $2.8 million gain, net of tax. The following table
represents the Company's condensed statements of operations, excluding Patina.
Had the disposition of Patina been consummated on January 1, 1997 and 1996,
financing costs, net of tax, would have been reduced by $3.3 million in 1997,
and $4.5 million in 1996, from the amounts shown in the following schedule.
Future results may differ substantially from these condensed statements or pro
forma results due to changes in oil and gas prices, production declines and
other factors. Therefore, such statements cannot be considered indicative of
future operations.
(In thousands, except per share and production data) For the Year Ended December 31,
-----------------------------------
1997 1996
----------- -----------
Unaudited
Revenues
Oil and gas sales $ 133,851 $ 107,143
Other 48,512 95,784
----------- -----------
182,363 202,927
Expenses
Direct operating 35,016 35,118
Exploration 16,926 4,008
General and administrative 16,566 10,993
Financing costs, net 10,556 8,619
Depletion, depreciation and amortization 43,599 39,725
Other 10,143 32,930
----------- -----------
Income before taxes, minority interest and extraordinary item 49,557 71,534
Provision for income taxes 17,856 4,740
Minority interest 616 4,866
Extraordinary item, net of tax 2,848 -
----------- -----------
Net income $ 28,237 $ 61,928
=========== ===========
Net income per common share $ .73 $ 1.78
=========== ===========
Weighted average shares outstanding 30,588 31,308
=========== ===========
Daily Production
Oil (Bbls) 5,617 6,000
Gas (Mcf) 113,361 87,139
34
(2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation
The consolidated financial statements include the accounts of 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 in which the Company
owns between 20% and 50% are accounted for using the equity method. Affiliates
in which the Company owns less than 20% are accounted for using the cost method.
At December 31, 1997, affiliates accounted for under this method included Cairn
and SOCI plc. The Company accounts for its interest in joint ventures and
partnerships using the proportionate consolidation method, whereby its
proportionate share of assets, liabilities, revenues and expenses are
consolidated.
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 produces a substantial portion of its natural gas, have traditionally
been particularly volatile. Prices are significantly impacted by the local
weather, supply in the area, seasonal variations in local demand and limited
transportation capacity to other regions of the country. 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 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.
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 1997
and 1996, the Company provided unproved property impairments of $700,000 and
$2.8 million, respectively. 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.
The Company follows 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 and
other assets. Oil and gas properties are generally assessed on a
property-by-property basis. If an impairment is indicated based on undiscounted
expected future net cash flows, then it is recognized to the extent that net
capitalized costs exceed discounted expected future net cash flows. Accordingly,
during 1997 and 1995, the Company provided for $6.6 million and $27.4 million,
respectively, for such impairments. During 1996, the Company did not provide for
any such impairments.
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 $2.4 million during 1997 and $2.5 million during each of 1996
and 1995. Of these amounts, $1.3 million in 1997 and $1.5 million in 1996 were
35
recognized by Patina. These arrangements, excluding Patina, 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 December 31, 1997 and
1996 were not significant.
Financial Instruments
The following table sets forth the book value and estimated fair values
of financial instruments:
December 31, December 31,
1997 1996
---------------------- ----------------------
Book Fair Book Fair
Value Value Value Value
--------- --------- --------- ---------
(In thousands)
SOCO
Cash and equivalents $ 89,443 $ 89,443 $ 21,769 $ 21,769
Investments 143,066 143,066 129,681 163,477
Senior debt (1) (1) (93,731) (93,731)
Subordinated notes (173,635) (178,063) - -
Convertible subordinated notes - - (80,748) (82,866)
Long-term commodity contracts - 7,318 - 5,040
Interest rate swap - - - (19)
Patina
Cash and equivalents - - 6,153 6,153
Senior debt - - (94,500) (94,500)
Subordinated notes - - (103,094) (105,650)
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, 1997
and 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 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's per day through 2004. At December 31, 1997, that volume
represented approximately 30% of the Company's Rocky Mountain gas production.
The fair value of the contract was based on the market price quoted for a
similar instrument.
At December 31, 1997, the Company had entered into various swap sales
contracts with a weighted average price (NYMEX based) of $2.62 for contract
volumes of 4,205,000 MMBtu's of natural gas for January 1998 through May 1998.
Also, the Company had entered into various swap sales contracts with a weighted
average price (CIG-Inside FERC based) of $2.14 for contract volumes of 2,250,000
MMBtu's of natural gas for January 1998 through March 1998. The unrecognized
gain on these contracts totaled $2.4 million based on December 31, 1997 market
values.
Subsequent to December 31, 1997, the Company has entered into
additional swap sales contracts with a weighted average price (NYMEX based) of
$2.30 for contract volumes of 17,120,000 MMBtu's of natural gas for April 1998
36
through October 1998. Also, the Company has entered into additional swap sales
contracts with a weighted average price (CIG-Inside FERC based) of $1.71 for
contract volumes of 3,638,000 MMBtu's of natural gas for April 1998 through
October 1998.
In September 1995, the Company entered into an interest rate swap
covering $50 million of its bank debt. The agreement required payment to a
counterparty based on a fixed rate of 5.585% and required the counterparty to
pay the Company interest at the then current 30 day LIBOR rate. Accounts
receivable or payable under this agreement were recorded as adjustments to
financing costs and settled on a monthly basis. The agreement matured in
September 1997. At December 31, 1996, the fair value of the agreement was
estimated at the net present value discounted at 10%.
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 energy companies and long-term
notes receivable. The following table sets forth the book values and estimated
fair values of these investments:
December 31, 1997 December 31, 1996
-------------------------- --------------------------
Book Fair Book Fair
Value Value Value Value
----------- ----------- ----------- -----------
(In thousands)
Marketable securities $ 143,066 $ 143,066 $ 115,558 $ 115,558
Equity method investments - - 8,789 42,585
Long-term notes receivable - - 5,334 5,334
----------- ----------- ----------- -----------
$ 143,066 $ 143,066 $ 129,681 $ 163,477
=========== =========== =========== ===========
The Company follows SFAS 115, "Accounting for Certain Investments in
Debt and Equity Securities," which requires that investments in marketable
securities accounted for using the cost method and long-term notes receivable be
adjusted to their market value with a corresponding increase or decrease to
stockholders' equity. The pronouncement does not apply to investments accounted
for using the equity method.
Cairn
From May 1993 to November 1996, the Company had an investment in
Command Petroleum Limited ("Command"), an Australian oil company, which was
accounted for using the equity method. In November 1996, the Company exchanged
its interest in Command for 16.2 million shares of freely marketable common
stock of Cairn, an international independent oil company based in Edinburgh,
Scotland whose shares are listed on the London Stock Exchange. The Company
recognized a gain of $65.5 million in 1996 as a result of this exchange.
SOCI plc
In 1993, SOCO Perm Russia, Inc. ("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. A private placement in April 1996 reduced the Company's interest to
34.91%. The Company recognized a gain of $2.6 million as a result of this
transaction.
In 1994, the Company formed a consortium to explore the Tamtsag Basin
of eastern Mongolia, SOCO Tamtsag Mongolia, Inc. ("SOCO Tamtsag"). 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.
37
In May 1997, a newly formed entity, SOCI plc, completed an initial
public offering of its shares on the London Stock Exchange. Simultaneously with
the offering, the Company exchanged its shares of SOCO International Operations,
Inc., which included the Company's interests in SOCO Perm, SOCO Tamtsag and
certain Thailand properties, for shares of SOCI plc. Certain minority interest
owners in these ventures also contributed their interests. As part of the
listing, SOCI plc acquired Cairn's UK onshore company as well as certain assets
in Yemen and Tunisia that were formerly owned by Command. The offering raised
approximately $75 million of new equity capital for SOCI plc. The Company
received 7.8 million shares (15.9% of the total) of SOCI plc, which it has
agreed not to sell for the two-year period following the listing. The Company
recognized a gain of $19.8 million as a result of this exchange.
Marketable Securities
As a result of the transactions described above, the Company has
investments in equity securities of two publicly traded foreign energy
companies, Cairn and SOCI plc. Both investments are accounted for using the cost
method. In the first quarter of 1997, the Company sold 4.5 million Cairn shares
at an average price of $8.81 per share realizing $39.2 million in proceeds
resulting in a gain of $13.0 million. The Company's carrying cost in the Cairn
and SOCI plc shares was $73.1 million and $30.9 million, respectively, at
December 31, 1997. The market value of the Cairn and SOCI plc shares
approximated $96.1 million and $47.0 million, respectively, at December 31,
1997. In accordance with SFAS 115, at December 31, 1997 and 1996, respectively,
investments were increased by $39.0 million and $20.4 million in gross
unrealized holding gains, stockholders' equity was increased by $25.3 million
and $11.9 million and deferred taxes payable were increased by $13.7 million and
$7.2 million. In addition, minority interest liability was increased by $1.3
million at December 31, 1996.
Notes Receivable
The Company held notes receivable due from a director at December 31,
1997 and 1996. At December 31, 1996, the Company also held a long-term note
receivable due from SOCO Tamtsag, a Mongolian affiliate, with a book value of
$4.7 million which was contributed to SOCI plc along with the Company's interest
in SOCO Tamtsag in May 1997. The notes from a director, which originated in
connection with an option to purchase 10% of the Company's international
affiliates are due April 10, 1998, and are secured by shares of the Company
which are owned by the director. At December 31, 1997, the notes were classified
as current assets in the accompanying financial statements and had a book value
of $647,000. At December 31, 1997 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.
38
(4) OIL AND GAS PROPERTIES AND GAS FACILITIES
The cost of oil and gas properties at December 31, 1997 and 1996
includes $21.3 million and $32.7 million of unevaluated leasehold. Such
properties are held for exploration, development or resale. The following table
sets forth costs incurred related to oil and gas properties and gas processing
and transportation facilities:
Excluding Patina
--------------------------------------------------
1997 1996 1995
----------- ------------ -----------
(In thousands)
Proved acquisitions $ 3,338 $ 54,708 $ 13,025
Acreage acquisitions 5,609 24,589 7,388
Development 74,676 34,774 50,437
Exploration 17,217 4,364 7,798
Gas processing, transportation and other 3,096 3,612 7,873
----------- ------------ -----------
$ 103,936 $ 122,047 $ 86,521
=========== ============ ===========
Patina
--------------------------------------------------
1997 1996 1995
------------ ------------ -----------
(In thousands)
Proved acquisitions $ 338 $ 218,380 $ 650
Development 11,322 8,301 12,141
Exploration 121 224 416
Gas processing, transportation and other 329 - 13
------------ ------------ -----------
$ 12,110 $ 226,905 $ 13,220
============ ============ ===========
Excluding Patina, the 1997 development expenditures of $74.7 million
were concentrated in the Gulf of Mexico and Rocky Mountains. During 1997, the
Company placed 72 wells on sales with 24 wells in progress at year end. 1997
exploration costs include the costs of two exploratory dry holes in the Gulf of
Mexico and continuing seismic programs in the Gulf of Mexico, northern Louisiana
and the Rocky Mountains.
Proved acquisitions during 1996 included $218.4 million related to the
formation of Patina including the acquisition of Gerrity Oil & Gas Corporation
("GOG"). In October 1997, the Company sold its interest in Patina. Net proceeds
from the sale were approximately $127 million.
(5) INDEBTEDNESS
The following indebtedness was outstanding on the respective dates:
December 31, December 31,
1997 1996
------------ ------------
(In thousands)
SOCO subordinated notes $ 173,635 $ -
SOCO bank facility 1 93,731
SOCO convertible subordinated notes - 80,748
----------- ---------
173,636 174,479
Patina subordinated notes - 103,094
Patina bank facilities - 94,500
----------- ---------
$ 173,636 $ 372,073
=========== =========
SOCO maintains a $500 million revolving credit facility ("SOCO
Facility"). The SOCO Facility is divided into a $400 million long-term portion
and a $100 million short-term portion. Credit availability is adjusted
semiannually to reflect changes in reserves and asset values. The borrowing base
available under the facility was $120 million at December 31, 1997. Borrowings
under the facility generally bear interest at prime, with an option to select
39
LIBOR plus .75% or 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 1997, the average interest
rate under the facility was 6.5%. The Company pays certain fees based on the
unused portion of the borrowing base. Covenants, in addition to other
requirements, require maintenance of a current working capital ratio of 1 to 1
as defined, limit the incurrence of additional debt and restrict dividends,
stock repurchases, certain investments, other indebtedness and unrelated
business activities. Such restricted payments are limited by a formula that
includes proceeds from certain securities, cash flow and other items. Based on
such limitations, more than $120 million was available for the payment of
dividends and other restricted payments at December 31, 1997.
In June 1997, SOCO issued $175.0 million of 8.75% Senior Subordinated
Notes ("Notes") due June 15, 2007. The Notes were sold at a discount resulting
in an 8.875% effective interest rate. The net proceeds of the offering were
$168.3 million which were used to redeem convertible subordinated notes and pay
down the balance outstanding under the credit facility. The Notes are redeemable
at the option of the Company on or after June 15, 2002, initially at 104.375% of
principal, and at prices declining to 100% of principal on or after June 15,
2005. Upon the occurrence of a change of control, as defined in the Notes, SOCO
would be obligated to make an offer to purchase all outstanding Notes at a price
of 101% of the principal amount thereof. In addition, SOCO would be obligated,
subject to certain conditions, to make offers to purchase the Notes with the net
cash proceeds of certain asset sales or other dispositions of assets at a price
of 100% of the principal amount thereof. The Notes are unsecured general
obligations of SOCO and are subordinated to the SOCO Facility and to any
existing and future indebtedness of SOCO's subsidiaries. The Notes contain
covenants that, among other things, limit the ability of SOCO 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. Such restricted payments are
limited by a formula that includes proceeds from certain securities, cash flow
and other items. Based on such limitations, more than $100 million was available
for the payment of dividends and other restricted payments at December 31, 1997.
The Company's international subsidiaries and Patina are considered unrestricted
subsidiaries. As such, their activities and the proceeds realized from any
disposition of these interests are not restricted by the Note convenants.
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 were
convertible into common stock at $22.57 per share. During 1996 and the first six
months of 1997, the Company repurchased $3.8 million and $824,000, respectively,
of these notes in accordance with a repurchase program. The notes were redeemed
by the Company in June 1997 at 103.51% of principal. As a result of the note
redemption, the Company incurred a loss of $4.4 million or $2.8 million net of
tax ($.09 per common share) which has been recorded as an extraordinary item in
the accompanying financial statements.
As a result of the disposition of Patina in October 1997, Patina's
indebtedness is no longer included in the Company's consolidated financial
statements.
Scheduled maturities of indebtedness for the next five years are zero
in 1998 and 1999, $1,000 in 2000 and zero in 2001 and 2002. The long-term
portion of the SOCO Facility is scheduled to expire in 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 $28.6 million, $21.9
million and $22.1 million, respectively, for 1997, 1996 and 1995.
40
(6) FEDERAL INCOME TAXES
At December 31, 1997, 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 1997, 1996 and 1995 follows:
1997 1996 1995
---------- ----------- ----------
Federal statutory rate 35% 35% (35%)
Net change in valuation allowance (3%) (29%) -
Tax effect of cumulative earnings of subsidiary 1% - -
Loss in excess of net deferred tax liability - - 32%
---------- ---------- ---------
Effective income tax rate 33% 6% (3%)
========== ========== =========
For book purposes, the components of the net deferred tax asset and
liability at December 31, 1997 and 1996, respectively, were:
1997 1996
----------- -----------
(In thousands)
Deferred tax assets
NOL and capital loss carryforwards $ 27,307 $ 65,126
AMT credit carryforwards 1,401 644
Production payment receivables 5,557 32,654
Reserves and other 6,031 5,613
----------- -----------
40,296 104,037
----------- -----------
Deferred tax liabilities
Depreciable and depletable property (30,964) (59,865)
Investments and other (25,884) (42,252)
Unrealized investments gains (15,097) (7,131)
------------ -----------
(71,945) (109,248)
----------- -----------
Deferred tax liability (31,649) (5,211)
Valuation allowance - (3,823)
----------- -----------
Net deferred tax liability $ (31,649) $ (9,034)
=========== ===========
The Company had regular net operating loss carryforwards of $78.0
million at December 31, 1997. The majority of these carryforwards expire between
2006 and 2010 with a minimal amount expiring between 1998 and 2005. At December
31, 1997, the Company also had alternative minimum tax credit carryforwards of
$1.4 million which are available indefinitely. Cash payments for income taxes
were $500,000 in 1997 and $245,000 in 1995. No cash payments were made for
income taxes in 1996.
(7) STOCKHOLDERS' EQUITY
A total of 75 million common shares, $.01 par value, are authorized of
which 35.7 million were issued and 33.3 million were outstanding at December 31,
1997. In 1997, the Company issued a total of 4.2 million shares of common stock
as follows: 3.6 million for the conversion of preferred shares, 300,000 in
exchange for 2.1 million of outstanding warrants and 308,000 primarily for the
exercise of stock options. The Company also issued 530,000 shares of treasury
stock in exchange for a director's 10% interest in SOCO International Holdings,
Inc. During 1997, the Company repurchased 2.6 million shares of common stock for
$45.6 million. 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, Inc. (formerly DelMar Operating, Inc.) and 267,000 shares issued
primarily for the exercise of stock options and repurchased 725,000 shares of
common stock for $7.0 million. Quarterly dividends of $.065 per share were paid
in 1997 and 1996. For book purposes, for the period between June 1995 and
September 1996, common stock dividends were in excess of retained earnings and,
as such, were treated as distributions of capital.
41
A total of 10 million preferred shares, $.01 par value, have been
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. During 1996,
the Company repurchased 6,000 shares for $142,000. During 1997, the Company
called the preferred stock for redemption. The preferred stock was convertible
into common stock at $20.46 per share or the liquidation preference was $25.00
per depositary share, plus accrued and unpaid dividends. As a result of the
call, 72% of the preferred shares were converted into 3.6 million shares of
common stock. The remaining preferred shares were redeemed for $29.1 million
before accrued dividends and a redemption premium. The Company paid $5.0 million
and $6.2 million ($1.50 per 6% convertible depositary share per annum) in
preferred dividends during 1997 and 1996, respectively. A $1.0 million
redemption premium for the preferred shares is also included in the 1997
preferred dividend amount in the statement of operations.
Effective December 31, 1997, the Company adopted Statement of Financial
Accounting Standards No. 128 ("SFAS 128"), "Earnings per Share" which prescribes
standards for computing and presenting earnings per share and supersedes APB
Opinion No. 15, "Earnings per Share." In accordance with SFAS 128, income
applicable to common has been calculated based on the weighted average shares
outstanding during the year and income applicable to common-assuming dilution
has been calculated assuming the exercise or conversion of all dilutive
securities as of January 1, 1997 and 1996, or as of the date of issuance if
later. The following table illustrates the calculation of earnings per share for
income from continuing operations.
Income Shares Per-Share
------------ -------- ------------
For the Year Ended December 31, 1997
------------------------------------
Income before extraordinary item $ 35,465
Preferred dividends (5,978)
-----------
Income applicable to common
Income available to common shareholders 29,487 30,588 $ .96
Effect of Dilutive Securities
Stock options 513
----------- -----------
Income applicable to common-assuming dilution
Income available to common shareholders +
assumed conversions $ 29,487 31,101 $ .95
=========== =========== ===========
For the Year Ended December 31, 1996
------------------------------------
Income before extraordinary item $ 62,950
Preferred dividends (6,210)
-----------
Income applicable to common
Income available to common shareholders 56,740 31,308 $ 1.81
Effect of Dilutive Securities
Stock options 153
Convertible preferred stock 6,210 5,052
----------- -----------
Income applicable to common-assuming dilution
Income available to common shareholders +
assumed conversions $ 62,950 36,513 $ 1.72
=========== =========== ===========
As of December 31, 1997, the only potentially dilutive securities
outstanding were stock options that have yet to be exercised.
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
42
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, 1997, 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
the method established by 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:
1997 1996 1995
--------- -------- ---------
Net income (loss) As Reported $ 32,617 $ 62,950 $(39,831)
Pro forma $ 29,260 $ 61,936 $(40,567)
Net income (loss) per common As Reported $ .87 $ 1.81 $(1.53)
share Pro forma $ .76 $ 1.78 $(1.55)
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 1997, 1996 and 1995, respectively: dividend yield
of 1.6%, 2.8% and 1.9%; expected volatility of 41%, 44% and 46%; risk-free
interest rates of 6.1%, 5.7% and 7.2%; and an expected life of 4.5 years.
A summary of the status of the Company's two fixed stock option plans
as of December 31, 1997, 1996 and 1995 and changes during the years ended on
those dates is presented below (shares are in thousands):
1997 1996 1995
-------------------- ------------------- ---------------------
Weighted- Weighted- Weighted-
Average Average Average
Exercise Exercise Exercise
Shares Price Shares Price Shares Price
------ ----------- ------ --------- ------ ---------
Outstanding at beginning
of year 1,674 $12.72 1,711 $13.21 1,484 $12.96
Granted 1,013 16.82 519 9.50 610 14.06
Exercised (295) 11.27 (255) 6.69 (124) 7.34
Forfeited (65) 14.88 (301) 14.71 (259) 16.62
------ ------ -------
Outstanding at end of year 2,327 14.64 1,674 12.72 1,711 13.21
====== ====== =======
Options exercisable at
year end 1,105 772 743
Weighted-average fair
value of options
granted during
the year $5.96 $3.27 $5.78
43
The following table summarizes information about fixed stock options
outstanding at December 31, 1997:
Options Outstanding Options Exercisable
---------------------------------------------------- --------------------------------
Weighted-
Number Average Number
Range Outstanding at Remaining Weighted- Exercisable at Weighted-
of December 31, Contractual Life Average December 31, Average
Exercise Prices 1997 (in years) Exercise Price 1997 Exercise Price
- ----------------- -------------- ---------------- -------------- --------------- --------------
$ 6.00 to 9.75 443,000 3.0 $ 8.64 232,000 $ 7.96
10.63 to 14.13 585,000 2.1 13.58 427,000 13.55
16.13 to 17.50 858,000 4.0 16.24 176,000 16.37
18.13 to 23.81 441,000 2.9 18.93 270,000 18.27
------------- -------------
$ 6.00 to 23.81 2,327,000 3.1 $14.64 1,105,000 $13.97
------------- -------------
(8) MAJOR CUSTOMERS
In 1997, Sonat Marketing Company accounted for approximately 17% of
revenues, Engage Energy accounted for approximately 14%, and Duke Power and
Energy accounted for approximately 12%. In 1996, Duke Power and Energy accounted
for approximately 11% of revenues. In 1995, Amoco Production Company accounted
for approximately 10% 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) EMPLOYEE RETIREMENT PLAN
The Company has a defined contribution plan pursuant to Section 401(k)
of the Internal Revenue Code. Substantially all employees are eligible to
participate after the completion of four months of service and may contribute up
to 15% of their compensation. The Board of Directors elected to contribute an
amount equal to at least 7% of each employee's pretax salary for the years ended
December 31, 1997, 1996 and 1995 resulting in total Company contributions of
$766,000, $1.2 million and $1.0 million, respectively.
(10) GUARANTOR CONDENSED CONSOLIDATING FINANCIAL INFORMATION
Pursuant to the Notes, all of the Company's subsidiaries except Patina
and SOCO International (the "Unrestricted Subsidiaries") would be guarantors of
the Notes (the "Restricted Group"). The condensed consolidating financial
information below shows the impact of the guarantors and the Unrestricted
Subsidiaries to the Company's consolidated position as of and for the year ended
December 31, 1997. "SOCO" includes all subsidiaries other than SOCO Offshore and
the Unrestricted Subsidiaries. In the aggregate, the subsidiaries other than
SOCO Offshore and the Unrestricted Subsidiaries hold less than 10% of the total
assets and revenues included in SOCO.
44
CONDENSED CONSOLIDATING BALANCE SHEETS
December 31, 1997
(In thousands)
Restricted Group
----------------------------
SOCO Unrestricted
SOCO Offshore Subsidiaries Eliminations Consolidated
----------- ----------- ------------ ------------ ------------
Current assets $ 87,843 $ 21,671 $ 4,361 $ - $ 113,875
Investments 141,501 - 143,066 (141,501) 143,066
Oil and gas properties, net 174,160 100,144 - - 274,304
Gas facilities and other, net 14,843 - - - 14,843
----------- ----------- ----------- ----------- -----------
Total assets $ 418,347 $ 121,815 $ 147,427 $ (141,501) $ 546,088
=========== =========== =========== =========== ===========
Current liabilities $ 52,201 $ 5,348 $ - $ - $ 57,549
Senior debt 1 - - - 1
Subordinated notes 173,635 - - - 173,635
Deferred taxes payable (15,832) - 47,481 - 31,649
Other noncurrent liabilities 7,413 12,085 - - 19,498
Total stockholders' equity 200,929 104,382 99,946 (141,501) 263,756
----------- ----------- ----------- ----------- -----------
Liabilities and stockholders'
equity $ 418,347 $ 121,815 $ 147,427 $ (141,501) $ 546,088
=========== =========== =========== =========== ===========
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
Year Ended December 31, 1997
(In thousands)
Restricted Group
-----------------------------
SOCO Unrestricted
SOCO Offshore Subsidiaries Consolidated
----------- ------------ ------------ ------------
Revenues $ 90,015 $ 59,549 $ 106,164 $ 255,728
Expenses 86,029 44,117 68,142 198,288
----------- ------------ ----------- ------------
Income before taxes, minority interest
and extraordinary item 3,986 15,432 38,022 57,440
Income taxes 5,504 - 12,352 17,856
Minority interest - - 4,119 4,119
Extraordinary item 2,848 - - 2,848
----------- ----------- ----------- -----------
Net income $ (4,366) $ 15,432 $ 21,551 $ 32,617
=========== =========== =========== ===========
45
(11) COMMITMENTS AND CONTINGENCIES
The Company rents offices at various locations under noncancelable
operating leases. Minimum future payments under such leases approximate $2.4
million for 1998, $2.6 million for 1999 and 2000, $1.7 million for 2001 and
$153,000 for 2002.
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, have unlawfully comingled production with
production from other leases and have breached their duties to reasonably
develop the lease. The plaintiffs also claim damages for fraud, co-mingling,
trespass and similar matters, and demand actual and punitive damages. Although
the complaint does not specify the amount of damages claimed, plaintiffs have
submitted calculations showing total damages against all owners in excess of
$100 million. The Company and the other interest owners have filed an answer
denying the claims and intend to contest the suit vigorously. The suit is
currently in discovery.
At this time, the Company is unable to estimate the range of potential
loss, if any, from the foregoing uncertainty. However, the Company believes that
resolution should not have a material adverse effect on 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.
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 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.
In the second quarter of 1996, the Company received $1.5 million in
proceeds 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.
(12) UNAUDITED SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION
Independent petroleum consultants directly evaluated 87%, 99%, and 81%
of proved reserves at December 31, 1997, 1996 and 1995, respectively. 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.
46
Future prices received for production and future production costs may
vary, perhaps significantly, from the prices and costs assumed for purposes of
these estimates. There can be no assurance that the proved reserves will be
developed within the periods indicated or that prices and costs will remain
constant. With respect to certain properties that historically have experienced
seasonal curtailment, the reserve estimates assume that the seasonal pattern of
such curtailment will continue in the future. There can be no assurance that
actual production will equal the estimated amounts used in the preparation of
reserve projections.
There are numerous uncertainties inherent in estimating quantities of
proved reserves and in projecting future rates of production and timing of
development expenditures. The data in the tables below represent estimates only.
Oil and gas reserve engineering must be recognized as a 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. The first set of tables
reflects the Company, excluding Patina (including Wattenberg area reserves of
the Company prior to formation of Patina in May 1996), and the second set of
tables shows consolidated Company totals.
47
EXCLUDING PATINA
Quantities of Proved Reserves - Crude Oil Natural Gas
--------- -----------
(MBbl) (MMcf)
Balance, December 31, 1995 16,826 256,861
Revisions 3,407 42,699
Extensions, discoveries and additions 845 60,479
Production (2,196) (31,893)
Purchases 891 41,606
Sales (1,751) (60,775)
--------- ---------
Balance, December 31, 1996 18,022 308,977
Revisions (266) (6,649)
Extensions, discoveries and additions 1,790 100,874
Production (2,049) (41,377)
Purchases 11 1,568
Sales (748) (225)
--------- ---------
Balance, December 31, 1997 16,760 363,168
========= =========
Proved Developed Reserves - Crude Oil Natural Gas
--------- -----------
(MBbl) (MMcf)
December 31, 1995 14,682 197,436
========= ==========
December 31, 1996 16,070 200,664
========= ==========
December 31, 1997 16,101 297,490
========= ==========
48
EXCLUDING PATINA
Standardized Measure - December 31,
--------------------------------
1997 1996
------------ ------------
(In thousands)
Future cash inflows $ 1,016,597 $ 1,476,338
Future costs:
Production (339,147) (442,798)
Development (64,237) (72,761)
------------ ------------
Future net cash flows 613,213 960,779
Undiscounted income taxes (148,049) (246,113)
------------ ------------
After tax net cash flows 465,164 714,666
10% discount factor (173,346) (276,010)
------------ ------------
Standardized measure $ 291,818 $ 438,656
============ ============
Changes in Standardized Measure -
Year Ended December 31,
-------------------------------
1997 1996
----------- ------------
(In thousands)
Standardized measure, beginning of year $ 438,656 $ 203,590
Revisions:
Prices and costs (284,824) 176,801
Quantities 2,676 10,414
Development costs (9,241) (2,003)
Accretion of discount 43,866 18,426
Income taxes 70,050 (112,924)
Production rates and other (31,871) 14,758
----------- ------------
Net revisions (209,344) 105,472
Extensions, discoveries and additions 142,209 108,006
Production (104,465) (78,591)
Future development costs incurred 21,250 10,494
Purchases 2,374 136,227
Sales 1,138 (46,542)
----------- ------------
Standardized measure, end of year $ 291,818 $ 438,656
=========== ============
49
CONSOLIDATED
Quantities of Proved Reserves - Crude Oil Natural Gas
--------- -----------
(MBbl) (MMcf)
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
Revisions (3,829) (34,334)
Extensions, discoveries and additions 1,790 100,874
Production (3,490) (61,638)
Purchases 11 1,568
Sales (18,219) (248,938)
----------- -----------
Balance, December 31, 1997 16,760 363,168
=========== ===========
The quantities of proved reserves above at December 31, 1996 include
5.8 MBbl and 77.1 MMcf related to the minority interest owners of Patina which
was sold in October 1997.
Proved Developed Reserves - Crude Oil Natural Gas
--------- -----------
(MBbl) (MMcf)
December 31, 1994 26,104 353,930
=========== ===========
December 31, 1995 21,637 330,524
=========== ===========
December 31, 1996 31,869 443,441
=========== ===========
December 31, 1997 16,101 297,490
=========== ===========
50
CONSOLIDATED
Standardized Measure - December 31,
------------------------------
1997 1996
------------- -------------
(In thousands)
Future cash inflows $ 1,016,597 $ 3,144,813
Future costs:
Production (339,147) (781,550)
Development (64,237) (233,617)
------------ ------------
Future net cash flows 613,213 2,129,646
Undiscounted income taxes (148,049) (540,520)
------------ ------------
After tax net cash flows 465,164 1,589,126
10% discount factor (173,346) (650,534)
------------ ------------
Standardized measure $ 291,818 $ 938,592
============ ============
The table above includes standardized measure attributable to minority
interests of $129.5 million at December 31, 1996.
Changes in Standardized Measure -
Year Ended December 31,
-------------------------------------------------
1997 1996 1995
------------ ----------- -----------
(In thousands)
Standardized measure, beginning of year $ 938,592 $ 331,106 $ 361,682
Revisions:
Prices and costs (609,467) 528,525 18,975
Quantities 2,676 10,915 (30,495)
Development costs (9,241) (13,027) (2,806)
Accretion of discount 81,361 (a) 46,045 (b) 36,168
Income taxes 230,075 (242,536) 16,249
Production rates and other (31,871) 11,052 (29,991)
----------- ----------- -----------
Net revisions (336,467) 340,974 8,100
Extensions, discoveries and additions 142,209 111,797 18,171
Production (164,330) (146,257) (96,232)
Future development costs incurred 21,250 18,400 43,551
Purchases 2,374 330,225 (b) 31,142
Sales (311,810) (a) (47,653) (35,308)
----------- ----------- -----------
Standardized measure, end of year $ 291,818 $ 938,592 $ 331,106
=========== =========== ===========
<FN>
(a) In 1997, $12.5 million in "Accretion of Discount" was included in "Sales" due to the sale of Patina
in October 1997.
(b) 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 of GOG.
</FN>
51
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K.
(a) 1. Reference is made to Item 8 on page 27.
2. Schedules otherwise required by Item 8 have been omitted as
not required or not applicable.
3. Exhibits.
3.1 - 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).
3.1.1 - 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).
3.1.2 - 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).
3.1.3 - 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 Quarterly Report on
Form 10-Q for the quarter-ended June 30, 1993 (File No.
1-10509).
3.2 - By-laws of the Registrant, as amended.*
4.1 - Indenture dated as of June 10, 1997 between the Registrant
and Texas Commerce Bank National Association relating to
Registrant's 8 3/4% Senior Subordinated Notes due 2007 --
incorporated by reference from Exhibit 4.1 to the
Registrant's Current Report on Form 8-K dated June 10, 1997
(File No. 1-10509).
4.1.1 - First Supplemental Indenture dated as of June 10, 1997 to
Exhibit 4.1.5 -- incorporated by reference from Exhibit 4.2
to the Registrant's Current Report on Form 8-K dated June 10,
1997 (File No. 1-10509).
4.1.2 - Second Supplemental Indenture dated as of June 10, 1997 to
Exhibit 4.1.5 -- incorporated by reference from Exhibit 4.3
to the Registrant's Current Report on Form 8-K dated June 10,
1997 (File No. 1-10509).
4.2 - Rights Agreement, dated as of May 27, 1997, between the
Company and ChaseMellon Shareholder Services, L.L.C., as
Rights Agent, specifying the terms of the Rights, which
includes the form of Certificate of Designation of Junior
Participating Preferred Stock as Exhibit A and the form of
Right Certificate as Exhibit B -- incorporated by reference
from Exhibit 1 to the Registrant's Current Report on Form 8-K
dated June 2, 1997 (File No. 1-10509).
4.3 - Form of Certificate of Designation of Junior Participating
Preferred Stock setting forth the terms of the Junior
Participating Preferred Stock, par value $.01 per share --
incorporated by reference from Exhibit A to Exhibit 1 to the
Registrant's Current Report on Form 8-K dated June 2, 1997
(File No.1-10509).
52
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 Amended and Restated 1989 Stock Option Plan.*
10.3 - Registrant's Deferred Compensation Plan for Select Employees,
adopted effective June 1, 1994, as amended.*
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).
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. -- incorporated by reference from
Exhibit 10.9 to the Registrant's Annual Report on Form 10-K
for the year ended December 31, 1996 (File No. 1-10509).
10.9.1 - Promissory Note dated December 30, 1996 from Edward T.
Story payable to the order of SOCO International Holdings,
Inc. -- incorporated by reference from Exhibit 10.9.1 to the
Registrant's Annual Report on Form 10-K for the year ended
December 31, 1996 (File No. 1-10509).
10.9.2 - Promissory Note dated December 30, 1996 from Edward T.
Story payable to the order of SOCO International Operations,
Inc. -- incorporated by reference from Exhibit 10.9.2 to the
Registrant's Annual Report on Form 10-K for the year ended
December 31, 1996 (File No. 1-10509).
10.9.3 - Exchange Agreement dated July 10, 1997 between SOCO
International, Inc. and Edward T. Story, Jr. *
10.10 - Amended and Restated Stock Repurchase Agreement dated as of
July 31, 1997 and amended and restated as of September 18,
1997 among the Registrant and Patina Oil & Gas Corporation --
incorporated by reference to Exhibit 10.12 to Amendment No. 2
to the Registration Statement on Form S-3 of Patina Oil & Gas
Corporation (Commission File No. 333-32671).
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).
53
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 -- incorporated by reference from
Exhibit 10.11.5 to the Registrant's Annual Report on Form
10-K for the year ended December 31, 1996 (File No. 1-10509).
10.11.6 - Sixth Amendment dated as of May 19, 1997 to Fifth Restated
Credit Agreement -- incorporated by reference from Exhibit
10.11.6 to the Registrant's Quarterly Report on Form 10-Q for
the quarter ended June 30, 1997 (File No. 1-10509).
10.11.7 - Seventh Amendment dated as of October 13, 1997 to Fifth
Restated Credit Agreement. *
10.12 - Directors Deferral Plan for Independent Directors of the
Registrant. *
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).
10.14 - Employment Agreement effective as of May 2, 1997 between
Snyder Oil Corporation and William G. Hargett -- incorporated
by reference from Exhibit 1 to the Registrant's Current
Report on Form 8-K dated April 24, 1997 (File No. 1-10509).
10.15 - Indemnification Agreement dated as of May 2, 1997 between
Snyder Oil Corporation and William G. Hargett -- incorporated
by reference from Exhibit 2 to the Registrant's Current
Report on Form 8-K dated April 24, 1997 (File No. 1-10509).
10.16 - Severance Agreement dated as of April 17, 1997 between
Snyder Oil Corporation and Thomas J. Edelman -- incorporated
by reference from Exhibit 3 to the Registrant's Current
Report on Form 8-K dated April 24, 1997 (File No. 1-10509).
10.17 - Advisory Agreement entered into effective as of May 1, 1997
between Snyder Oil Corporation and Thomas J. Edelman --
incorporated by reference from Exhibit 4 to the Registrant's
Current Report on Form 8-K dated April 24, 1997 (File No.
1-10509).
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.*
54
23.1 - Consent of Arthur Andersen LLP.*
23.2 - Consent of Netherland, Sewell & Associates, Inc.*
27 - Financial Data Schedule.*
99.1 - Reserve letter from Netherland, Sewell & Associates, Inc.
dated February 5, 1998 to the Snyder Oil Corporation interest
as of December 31, 1997.*
(b) The following report on Form 8-K was filed during the quarter
ended December 31, 1997:
October 22, 1997 - Item 2. Acquisition or Disposition of Assets;
Item 5. Other Events; Item 7.
* Filed herewith.
55
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 February 27, 1998
- ---------------------- (Principal Executive Officer)
John C. Snyder
/s/ William G. Hargett Director, President and Chief February 27, 1998
- ---------------------- Operating Officer
William G. Hargett
/s/ Roger W. Brittain Director February 27, 1998
- ----------------------
Roger W. Brittain
/s/ John A. Hill Director February 27, 1998
- ----------------------
John A. Hill
/s/ William J. Johnson Director February 27, 1998
- ----------------------
William J. Johnson
/s/ B. J. Kellenberger Director February 27, 1998
- ----------------------
B. J. Kellenberger
/s/ Harold R.Logan, Jr. Director February 27, 1998
- ----------------------
Harold R. Logan, Jr.
/s/ James E. McCormick Director February 27, 1998
- ----------------------
James E. McCormick
/s/ Edward T. Story Director February 27, 1998
- ----------------------
Edward T. Story
/s/ Mark A. Jackson Senior Vice President and Chief February 27, 1998
- ---------------------- Financial Officer (Principal Financial
Mark A. Jackson and Accounting Officer)
56