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UNITED STATES
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, 1998
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 26, 1999..................$321,653,346
Number of shares of common stock outstanding as of
February 26, 1999............................................33,364,567
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,
1999.
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<PAGE>
SNYDER OIL CORPORATION
Annual Report on Form 10-K
December 31, 1998
PART I
ITEMS 1 AND 2. BUSINESS AND PROPERTIES
GENERAl
Snyder Oil Corporation is an independent oil and gas company with
principal operations in domestic natural gas exploration and production. The
Company's primary properties are located in the Rocky Mountain region, the Gulf
of Mexico and northern Louisiana.
The Company develops reserves which it has acquired or discovered
through its exploration program, and sells the oil and gas which it produces.
The Company has concentrated its exploration and development efforts over the
past year to emphasize natural gas reserve growth. During 1998, 90 percent of
the Company's reserve additions were natural gas. This has increased the
percentage of natural gas reserves to 82 percent, versus 78 percent in 1997.
During 1998, the Company generated revenues of $141.1 million and cash
flows from operations of $75.2 million. Average daily production during 1998 was
83 percent gas or 154.0 million cubic feet of gas and 5,231 barrels of oil per
day. At December 31, 1998, the Company had proved reserves of 100.3 million
barrels of oil equivalent with a pretax present value of $365.6 million,
assuming a ten percent discount rate with constant pricing and costs. Year end
reserves were 82 percent natural gas and 18 percent oil.
In addition to its domestic operations, the Company also owns common
stock in two international exploration and production companies, Cairn Energy
plc and SOCO International plc. Both companies' shares are listed on the London
Stock Exchange. Cairn shares trade under the symbol "CNE" and SOCO International
trades under the symbol "SIA." The Company owns about six percent of the
outstanding shares of Cairn and about 16 percent of the outstanding shares of
SOCO International. The market value of these two securities was $24.0 million
at year end 1998 and $143.1 million at year end 1997.
In October 1997, the Company sold its 74 percent equity interest in
Patina Oil and Gas Corporation. This transaction generated $127 million in
cash while removing approximately $170 million of Patina debt from the Company's
consolidated balance sheet.
On January 13, 1999, the Company and Santa Fe Energy Resources, Inc.
signed an agreement to merge the Company into Santa Fe Energy Resources to form
a single company to be named "Santa Fe Snyder Corporation." The merger is
subject to shareholder approval at a special meeting expected to be held during
the second quarter of 1999. If the Company's shareholders approve the merger and
all other conditions to the merger are met, each share of the Company's common
stock would be converted into 2.05 shares of Santa Fe Energy Resources stock.
Concurrently with signing the merger agreement, the Company amended its
shareholder rights agreement to exempt the merger from the scope of the
agreement. As a result, shareholders of the Company will have no rights under
the shareholder rights agreement relating to the merger. In particular, the
rights will not be distributed or become exercisable.
OPERATIONS
Overview
The Company's operations are focused in three core areas - the Rocky
Mountains, the Gulf of Mexico and northern Louisiana. The Company has been
active in the Rockies for more than 20 years and has developed several large gas
<PAGE>
development projects, which has allowed the Company to add reserves and
production at low development costs. The Rocky Mountain reserves represent 78
percent of the Company's year end reserves and 63 percent of the reserves'
pretax present value assuming a ten percent discount rate with constant pricing
and costs ("Pretax PV10 Value").
The Company began its activities in the Gulf of Mexico in 1994. During
1995 and 1996, the Company sold portions of its gas development projects and
most of its properties outside of its core areas in order to reinvest in its
Gulf projects. This repositioning process allowed the Company to balance its
reserves and production between the Rocky Mountains and the Gulf of Mexico. The
Company's Gulf of Mexico reserves comprise 19 percent of the Company's year end
quantities and 33 percent of the reserves' Pretax PV10 Value. During 1998, the
Company's production was almost equal from the Rockies and Gulf of Mexico core
areas.
The third core area is in northern Louisiana, where the Company is
currently focused on a highly prospective exploration effort targeting potential
Troy Lime reef production. This exploration play represents the first step in a
long-term program in northern Louisiana to exploit the Company's extensive
mineral position based on exclusive 3-D seismic data.
During 1998, the Company increased its reserves by 30 percent,
replacing 382 percent of its 1998 production. Finding and development costs from
all sources, including revisions, were $4.44 per barrel of oil equivalent.
Production from core areas increased 26 percent in 1998 from 1997.
Summary information at December 31, 1998 regarding the Company's
projects is set forth in the following table. (Abbreviated terms in the captions
are explained on page eight.)
<TABLE>
<CAPTION>
Proved Reserve Quantities
Gross Net ------------------------------------ Pretax PV10 Value
Producing Undeveloped Crude Natural Oil --------------------
Wells Acres Oil Gas Equivalent Amount Percent
--------- ----------- --------- ------- ---------- --------- ---------
(MBbl) (MMcf) (MBOE) (000)
<S> <C> <C> <C> <C> <C> <C> <C>
Rocky Mountains:
Washakie (WY) 225 92,808 1,898 183,816 32,533 $ 115,254 31
Wind River (WY) 98 61,182(a) 2,006 125,355 22,898 78,799 22
Northern Wyoming 898 - 13,121 634 13,227 11,115 3
Piceance (CO) (b) 92 46,432 208 49,409 8,443 22,947 6
Uinta (UT) 97 68,947 168 3,769 796 2,475 1
Big Horn (WY) 1 82,239 18 520 105 481 -
Deep Green River (WY) - 54,258 - - - - -
-------- --------- ------- ------- ------- --------- ------
Rocky Mountain Region 1,411 405,866 17,419 363,503 78,002 231,071 63
-------- --------- ------- ------- ------- --------- ------
Gulf of Mexico:
Main Pass Area 21 10,111 765 96,968 16,927 112,967 31
Other 18 22,255 242 14,216 2,611 6,602 2
-------- --------- ------- ------- ------- --------- ------
Total Gulf of Mexico 39 32,366 1,007 111,184 19,538 119,569 33
North Louisiana 14(c) 373,873(d) 67 13,295 2,283 12,956 3
Other 84 1,373 49 2,771 511 2,024 1
-------- --------- ------- ------- ------- --------- ------
Southern Region 137 407,612 1,123 127,250 22,332 134,549 37
-------- --------- ------- ------- ------- --------- ------
Total Company 1,548 813,478 18,542 490,753 100,334 $ 365,620 100
======== ========= ======= ======= ======= ========= ======
<FN>
(a) Excludes 16,500 net acres under option.
(b) Interests were sold subsequent to year end.
(c) Excludes royalty interests in 101 wells.
(d) Excludes 128,000 net acres under option.
</FN>
</TABLE>
ROCKY MOUNTAINS
The Rocky Mountain region represents 78 percent of the Company's total
year end reserves and 64 percent of Pretax PV10 Value. At year end, Rocky
Mountain proved reserves totaled 363.5 billion cubic feet of gas and 17.4
million barrels of oil, a 38 percent increase from 1997. The Company has an
interest in 1,411 total wells, 417 of which are operated. Rocky Mountain
3
<PAGE>
production represented 49 percent of the Company's total 1998 production.
Production from this region increased 15 percent in 1998 to an average of 66.0
million cubic feet of gas and 4.0 thousand barrels of oil per day.
The Company drilled 74 Rocky Mountain wells in 1998, of which 71 were
development and three were exploratory, continuing the long-term growth of the
region. The 1998 capital program in the Rocky Mountains primarily was directed
to the Company's gas development projects in the Washakie and Wind River Basins.
Washakie Basin
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, have been one of the Company's most significant
assets since the mid-1980s. Production from this prolific basin during 1998
averaged 35.0 million cubic feet of gas and 400 barrels of oil per day, or 20
percent of the Company's 1998 production.
The Company currently operates 184 wells in the Washakie Basin and
holds hundreds of potential drilling locations. The Company holds interests in
147,573 gross and 129,655 net acres in this area of which only 28 percent has
been developed. In the currently producing wells, the Company has an average
working interest of 71 percent and an average net revenue interest of 58
percent.
During 1998, the Company continued to develop Mesaverde sands in the
Washakie Basin; 43 wells were put on sales in 1998, seven of which were drilled
in late 1997. These wells were completed at depths ranging from 8,000 to 11,500
feet. Three wells were in progress at year end. Significant portions of the
Washakie area are restricted by a currently pending Environmental Impact Study
("EIS"). Therefore, the 1998 development program was focused on locations
outside the EIS restricted area. The Record of Decision covering the EIS is
expected to be issued in the second half of 1999. The Company expects to drill
25 to 35 wells in this area in 1999.
Wind River Basin
The Company owns an interest in four contiguous areas in the Wind River
Basin: the Riverton Dome Field, the Beaver Creek Unit, a 33,000-acre option on
Tribal lands, and a 64,000-acre undeveloped lease block. The Company has a 50
percent working interest in the option lands and in the lease block.
Total production at year end from the Wind River Basin was 19.6 million
cubic feet of gas and 460 barrels of oil per day, or 12 percent of the Company's
year end production.
The Riverton Dome Field primarily produces natural gas from the
Frontier, Muddy and Phosphoria formations and oil from the Tensleep formation.
The Company operates all 34 wells in this field and has an average working
interest of 88 percent and net revenue interest of 76 percent. Sweet gas is
processed at a Company-owned plant in the field, and sour gas is processed at
the Company's Beaver Creek plant, which is located immediately south of the
field.
The Company drilled four Muddy wells in the Riverton Dome Field in
1998. The Muddy formation is found at depths between 10,000 to 11,000 feet.
Initial production rates from the Muddy generally average three million cubic
feet of gas per day. The Company expects to drill five additional wells in the
Muddy in 1999. If the results are consistent with the Company's 3-D imaging of
the Muddy, the number of wells drilled could increase.
The Beaver Creek Unit is contiguous with the southern border of the
Riverton Dome Field. In May, 1998, the Company acquired 75 percent of Amoco
Production Company's ("Amoco") interest in the Beaver Creek Unit and two
associated gas plants. This transaction included an exchange for the Company's
interest in the Jonah Field, which was part of the Company's properties in the
Deep Green River Basin project. The Company owns an average working interest of
67 percent in the two gas processing facilities and 64 producing wells with an
average net revenue interest of 58 percent. This field produces gas from the
Frontier/Dakota, Phosphoria and Cody formations while oil production is from the
4
<PAGE>
Tensleep and Madison formations. Three wells were spud in 1998. One well was put
on sales and two wells were in progress at year end 1998. The Company also began
a recompletion and deepening program in the Frontier/Dakota and a horizontal
drilling program in the Tensleep during 1998.
The Company spud the North Alkali Butte 10-32 well in August 1998. This
exploratory well is the first test on the Tribal option acreage block and should
be completed in February 1999. Three zones tested productive and should be put
on sales in the first quarter of 1999.
Deep Green River Basin
In May, the Company exchanged its interest in the Jonah Field, which
represented a significant portion of its Deep Green River Basin assets for 75
percent of Amoco's assets in the Beaver Creek Unit. Under the terms of the
agreement, the Company also received Amoco's interest in the Deep Green River
Basin acreage outside the Jonah Field. The Company holds interests in 63,222
gross and 54,258 net undeveloped acres in this project. The Company also
retained the deep rights below the currently producing horizon in the Jonah
Field. These deep rights covering 23,568 gross and 10,625 net acres are not
included in the undeveloped acreage amounts.
During the early part of the year, the Company continued development of
the fluvial Lance sands in the deep portion of the Jonah Field. The Company
participated in eight wells during 1998, two of which were drilled in the last
half of the year on acreage remaining after the trade. The first well, a
six-mile step-out to the south of the Jonah Field, was drilled in July to test a
2-D seismic velocity anomaly in the Ericson formation. The Company decided not
to complete the well and turned operations over to a partner. The second well
was drilled in November to test a seismic defined fault block and a low-velocity
anomaly to the west of the main Jonah Field. The well is temporarily abandoned
and will be plugged in 1999.
Piceance Basin
The Company operated the Hunter Mesa, Grass Mesa and the Divide Creek
Units in the southeast portion of the Piceance Basin through January 1999, when
the Company finalized the sale of its interest in the Piceance project. The
$28.8 million sale included the Company's remaining 55 percent interest and all
gathering and transportation facilities located within the area. Total
production at year end from the Piceance Basin was eight million cubic feet of
gas and 61 barrels of oil per day.
During 1998, the Company participated in eleven new wells to develop
and further delineate the fields; 13 wells, including two in progress at the
beginning of 1998 were put on sales. At year end 1998, there were 92 producing
wells, 87 of which were operated by the Company.
Big Horn Basin
The Company has assembled a 158,964 gross and 82,239 net acre
undeveloped lease block which is prospective for Frontier, Muddy, and
Lance/Mesaverde formations. Two Frontier wells are planned in 1999.
Uinta Basin
In the Uinta Basin, the Company holds interests in 105,991 gross and
77,358 net acres. During 1998, the Company participated in drilling one operated
well in the Horseshoe Bend area. The well, drilled to test the Green River zone,
was unproductive. During the last half of 1996, local oil prices, which
historically had been at a premium to West Texas Intermediate ("WTI") posted
prices, deteriorated and Uinta Basin production currently sells at a discount to
WTI prices. With little improvement expected in the near term, additional
development drilling was curtailed until oil prices in the area improve. At year
end, the Company had interests in 97 producing wells, 47 of which were operated
by the Company.
5
<PAGE>
Northern Wyoming
The Company holds interests in two large, mature oil fields in northern
Wyoming - the Hamilton Dome and Salt Creek Fields. 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. These two fields comprise 71
percent of the Company's oil reserves at year end 1998 and 58 percent of the
Company's oil production in 1998. At year end, the oil price received at
Hamilton Dome was $1.20 less than the WTI reference price and the oil price at
Salt Creek was $1.44 more than the WTI reference price.
GULF OF MEXICO
At year end, total proved reserves in the Gulf of Mexico were 111.2
billion cubic feet of gas and 1.0 million barrels of oil, representing
approximately 19 percent of total year end reserves and 33 percent of Pretax
PV10 Value. The Company has an interest in 39 wells, 36 of which are operated.
Production in 1998 increased 40 percent over 1997 to an average of 82.8 million
cubic feet of gas and 1,140 barrels of oil per day. The Gulf of Mexico
production represented 48 percent of the Company's 1998 total production, of
which 89 percent was concentrated in the Main Pass area.
During 1998, the Company drilled 14 wells in the Gulf of Mexico and
achieved a 50 percent exploratory success rate and a 75 percent development
success rate. Two hurricanes and two tropical storms substantially impacted
operations in the Gulf during September and October, including a direct hit by
Hurricane Georges to the Main Pass area. Although the Company's platforms
suffered no structural harm, repairs to damaged engines and compressors and
pipeline disruptions continued into the fourth quarter.
During 1998, two objectives of the capital program in the Gulf of
Mexico were to develop internal exploration and development prospects and to
expand operations beyond the continental shelf into deeper water. To accomplish
the first objective, the Company invested $8.7 million acquiring 25,000 line
miles of 2-D and 2,000 square miles of 3-D seismic coverage over 203 blocks in
the Gulf. The Company also leased three blocks at Federal lease sales during the
year. Currently, the Company is working on six leads and has 12 prospects in
inventory.
The Company had mixed results in its effort to expand operations into
deeper waters. The Company participated in drilling seven deepwater wells
during the year and found hydrocarbons in economic quantities at three locations
in its Specter and Leo prospects. At East Breaks 208, Garden Banks 269 and 625,
and Green Canyon 179, the Company reported four dry holes at a cost of $26.8
million. Although the costs of these four wells were only 14 percent of the
Company's 1998 capital program, the dry hole expense accounted for 70 percent of
the Company's reported loss for 1998.
In 1999, the Company will continue focusing acquisition efforts in
the Gulf and evaluating existing properties for additional exploratory or
development potential.
Busch and Pabst Fields, Main Pass 255/259
The Busch (Main Pass 255) and Pabst (Main Pass 259) Fields are located
in the Main Pass/Viosca Knoll area offshore Louisiana and Alabama. Production
during 1998 averaged 56.7 million cubic feet per day of gas and 460 barrels of
oil per day, representing 32 percent of the Company's 1998 production. In 1998,
the Company continued development and exploration work around this key area by
drilling one successful development well and one exploratory well. The discovery
well in Main Pass 260 tested 26 million cubic feet of gas and 2,745 barrels of
oil per day from a mid-Miocene Tex W sand series. The well is expected to be
subsea completed and tied back to the Pabst platform in 1999.
The Company's interest in the Busch and Pabst leases was subject to a
reversionary interest upon payout of the original drilling program expenditures.
As a result of program payout in 1998, the Company's interest in these fields
was reduced from a 61.8 percent working interest to a 52.4 percent working
interest, and the net revenue interest was reduced from 43.3 percent to 36.8
percent.
6
<PAGE>
Ingrid Field, Main Pass 261
The Company has a 50 percent working interest and a 37 percent net
revenue interest in the Ingrid Field, where proved reserves were discovered in
1996 in several Tex W sands at approximately 11,000 to 13,000 feet.
Most of the Company's development program in the first quarter of 1998
focused on setting the platform at the Ingrid Field and bringing the two
discovery wells on production. In the second quarter, one exploratory well was
successfully drilled and completed in a shallower horizon. Two additional
development wells were drilled and brought on production, although the reserves
from one well depleted rapidly.
Initial production from the Main Pass 261 platform began after
production facilities were completed in March, with initial volumes transported
on the Viosca Knoll Gathering System. In August, the connection of the 24-inch
Transcontinental Gas Pipeline ("Transco") to the Main Pass 259 and 261 platforms
gave the Company additional transportation capacity and access to additional
markets for its gas. Average Main Pass natural gas price realizations
increased an estimated 25 to 30 cents per Mcf in the fourth quarter because of
the improved markets provided by the Transco pipeline. The Company expects
that the price realizations in the future will be four to five cents more
favorable on Transco than Viosca Knoll.
The Ingrid Field accounted for 15 percent of the Company's total
production during the third quarter. Production subsequently declined
significantly and the Company concluded that the lower reservoirs in two of the
wells were smaller than originally estimated. The Company plans to produce these
lower reservoirs until they are depleted and then recomplete to the larger,
primary reservoirs uphole. It is anticipated that the recompletions may not take
place until 2000. At year end, the reserves associated with these lower
secondary reservoirs represent less than one percent of the Company's total
reserves but will limit future production rates until the upper primary
reservoirs are recompleted.
Specter Prospect, Viosca Knoll 779/780/823/824
The Company participated with a 12 percent working interest,ten
percent net revenue interest, in the Specter Prospect, operated by Shell
Offshore, Inc. The first well, Viosca Knoll 780 #4 was drilled to a measured
depth of 15,170 feet and discovered hydrocarbons in a middle Miocene age
reservoir. The well was sidetracked, as planned, to a separate middle Miocene
age target in Viosca Knoll block 824. The Viosca Knoll 824 #1 was drilled to a
measured depth of 14,200 feet and also discovered hydrocarbon bearing sands. Two
development wells are scheduled in 1999 to be redrilled from Shell's Spirit
platform in block 780.
Leo Prospect, Mississippi Canyon 502/503/546/547
The Company participated in the Leo prospect in block 546 with a 12.5
percent working interest, 10.4 percent net revenue interest, operated by
British-Borneo Exploration, Inc. The initial well in 2,500 feet of water
penetrated multiple Miocene age hydrocarbon sands at depths between 11,500 and
17,500 feet with approximately 200 feet of net pay. Additional seismic analysis
in 1999 and appraisal drilling in 2000 will determine the ultimate scope of the
development.
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 percent to 100 percent.
During 1999, the Company will continue to evaluate these blocks for additional
exploratory or development potential using its 3-D seismic data.
7
<PAGE>
NORTH LOUISIANA AND OTHER
At year end, proved reserves in North Louisiana and other areas in the
Southern Region totaled 16.1 billion cubic feet of gas and 116 thousand barrels
of oil. The Company has working interests in 98 total wells and royalty
interests in 101 wells. The Company has interests in 602,353 gross acres and
394,209 net acres with options to lease an additional 128,000 net acres.
Included in the total acreage amounts are 488,132 gross and 331,267 net acres in
northern Louisiana and southern Arkansas where the Company owns mineral
interests which are not subject to lease expirations. Production in 1998
averaged 5.2 million cubic feet of gas and 80 barrels of oil per day, or three
percent of the Company's 1998 production. During 1998, the Company drilled eight
wells in North Louisiana and four wells in Webb County Texas.
The North Louisiana core area is highly prospective and represents a
principal exploration play for the Company. The Company has spent the last five
years acquiring and leasing acreage and developing an exploration program to
identify and test reefs in the Jurassic Troy Lime formation. This exploration
play appears to share similar characteristics with the East Texas Cotton Valley
reef play. The Company also initiated a redevelopment program in the Hosston
formation in the Cotton Plant Field and a Gray Sand play in northwest Louisiana
during 1998. The North Louisiana area will continue to be a focus area for the
Company in 1999.
Troy Lime Reef Play
The Company's primary objective in 1998 was to begin testing the 40
different reef anomalies identified from its proprietary 166-square-mile, 3-D
seismic program conducted in 1996 and 1997. The Company formed a joint venture
with two companies in 1996 to evaluate a portion of its mineral and acreage
positions in northern Louisiana which was prospective for reef anomalies. The
two companies agreed to pay for 100 percent of the seismic costs in order to
earn two-thirds of the Company's rights within each seismic area. Where the
Company owns mineral interests within the seismic area, the two companies have
the right to lease two-thirds of the minerals for a fixed-price-per-acre lease
bonus, with the Company retaining a royalty interest.
The Company drilled its first Troy Lime reef test in 1998. The Bozeman
#1 found an apparently gas-saturated reef buildup with measurable porosity and
permeability from logs and core analysis. Mechanical problems during completion
operations prevented a production test of the 800-foot interval of interest. The
well was subsequently sidetracked and successfully drilled back to the objective
and is currently undergoing testing operations. The Bozeman has provided
indications from well logs, core samples and gas shows of a potential gas
discovery. However, extensive testing will be required to prove or disprove the
productivity of this complex rock formation. Testing has just begun and actual
results may not be known for several months.
A second reef test, the Frazier #1, was spud in December and is
currently drilling to a projected total depth of 16,500 feet. The Company holds
a 100 percent working interest in the Bozeman sidetrack and a 33.3 percent
working interest in the Frazier well.
The Blake #1 well was drilled in 1998 as a development well updip of a
Troy Lime, non-pinnacle reef producer. The test well found a tight reservoir and
is being plugged and abandoned. The Company had a 33.3 percent working interest
in this well.
CERTAIN DEFINITIONS
As used in the tables below, these terms have the following meanings:
"Bbl" means barrel.
"MBbl" means thousand barrels.
"MMBbl" means million barrels.
"Mcf" means thousand cubic feet.
"MMcf" means million cubic feet.
8
<PAGE>
"Bcf" means billion cubic feet.
"MMBtu" means million British thermal units.
"BOE" means barrel of oil equivalent.
"MBOE" means thousand barrels of oil equivalent.
Natural gas volumes are converted to barrels of oil equivalent using
the ratio of six Mcf of natural gas to one barrel of crude oil.
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, 1998 for the
Company, and for the Company, excluding Patina, as of December 31, 1996. Patina
was sold in October 1997 and is not included in the 1998 and 1997 balances.
<TABLE>
<CAPTION>
Consolidated Excluding Patina
December 31, December 31,
----------------------------------- ----------------------
1998 1997 1996 1996
-------- --------- -------- --------
<S> <C> <C> <C> <C>
Crude oil and liquids (MBbl)
Developed 17,383 16,101 31,869 16,070
Undeveloped 1,159 659 8,628 1,952
-------- -------- -------- --------
Total 18,542 16,760 40,497 18,022
======== ======== ========= ========
Natural gas (MMcf)
Developed 391,951 297,490 443,441 200,664
Undeveloped 98,802 65,678 162,195 108,313
-------- -------- -------- --------
Total 490,753 363,168 605,636 308,977
======== ======== ======== ========
Total MBOE 100,334 77,288 141,436 69,518
======== ======== ======== ========
</TABLE>
The following table sets forth the estimated pretax future net revenues
from the production of proved reserves and the Pretax PV10 Value of such
revenues.
<TABLE>
<CAPTION>
December 31, 1998
-----------------------------------------------------
Developed Undeveloped (a) Total
----------- --------------- -----------
(In thousands)
<S> <C> <C> <C>
1999 $ 81,436 $ (14,007) $ 67,429
2000 68,156 (1,036) 67,120
2001 53,115 5,380 58,495
Remainder 366,460 103,983 470,443
----------- ----------- -----------
Total $ 569,167 $ 94,320 $ 663,487
=========== =========== ===========
Pretax PV10 Value (b) $ 334,064 $ 31,556 $ 365,620
=========== =========== ===========
<FN>
(a) Net of estimated capital costs of $57.2 million, including estimated costs of $24.5 million during 1999.
(b) The after tax PV10 Value of proved reserves totaled $322.2 million at year end 1998.
</FN>
</TABLE>
The quantities and values shown in the preceding tables are based on
realized prices in effect at December 31, 1998, averaging $9.56 per barrel of
oil and $1.94 per Mcf of gas. Reference prices as of December 31, 1998 were Koch
WTI oil of $9.50 per barrel, Henry Hub gas of $2.10 per Mcf and CIG index gas of
$1.96 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.
9
<PAGE>
Proved developed reserves are proved reserves that are expected to be
recovered from existing wells with existing equipment and operating methods.
Proved undeveloped reserves are proved reserves that are expected to be
recovered from new wells drilled to known reservoirs on undrilled acreage for
which the existence and recoverability of such reserves can be estimated with
reasonable certainty, or from existing wells where a relatively major
expenditure is required to establish production.
Future prices received for production and future production costs may
vary, perhaps significantly, from the prices and costs assumed for purposes of
these estimates. There can be no assurance that the proved reserves will be
developed within the periods indicated or that prices and costs will remain
constant. With respect to certain properties that historically have experienced
seasonal curtailment, the reserve estimates assume that the seasonal pattern of
such curtailment will continue in the future. There can be no assurance that
actual production will equal the estimated amounts used in the preparation of
reserve projections. See "Risk Factors and Investment Considerations."
Netherland, Sewell & Associates, Inc., independent petroleum
consultants, prepared estimates of the Company's proved reserves which
collectively represent 84 percent of Pretax PV10 Value as of December 31, 1998.
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.
10
<PAGE>
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, 1998 for the Company. Also set forth is 1997 and 1996 data
for the Company, excluding Patina.
<TABLE>
<CAPTION>
Consolidated Excluding Patina
------------------------------------------------------------- ---------------------
1998 1997 1996 1995 1994 1997 1996
------- -------- -------- -------- -------- -------- --------
(Dollars in thousands, except prices and production information)
<S> <C> <C> <C> <C> <C> <C> <C>
Production
Oil (MBbl) 1,909 3,490 3,884 4,278 4,366 2,050 2,196
Gas (MMcf) 56,203 61,638 55,840 53,227 43,809 41,377 31,893
MBOE (a) 11,277 13,763 13,191 13,149 11,668 8,946 7,512
Revenues
Oil $ 21,040 $ 65,886 $ 79,201 $ 72,550 $ 64,625 $ 37,397 $ 44,661
Gas (b) 112,164 141,330 110,126 72,058 73,233 96,454 62,482
-------- -------- -------- -------- -------- -------- --------
Subtotal 133,204 207,216 189,327 144,608 137,858 133,851 107,143
Transportation,
processing
and marketing 4,624 7,004 17,655 38,256 107,247 7,004 17,655
-------- -------- -------- -------- --------- -------- --------
$137,828 $214,220 $206,982 $182,864 $245,105 $140,855 $124,798
-------- -------- -------- -------- --------- -------- --------
Operating expenses
Production $ 38,492 $ 48,523 $ 49,638 $ 52,486 $ 46,267 $ 35,016 $ 35,118
Transportation,
processing
and marketing 3,348 6,692 15,020 29,374 94,177 6,692 15,020
-------- -------- --------- --------- --------- --------- --------
$ 41,840 $ 55,215 $ 64,658 $ 81,860 $ 140,444 $ 41,708 $ 50,138
-------- -------- --------- --------- --------- --------- --------
Direct operating margin $ 95,988 $159,005 $ 142,324 $ 101,004 $ 104,661 $ 99,147 $ 74,660
======== ======== ========= ========= ========= ========= ========
Production data
Average sales price (c)
Oil (Bbl) $ 11.02 $ 18.88 $ 20.39 $ 16.96 $ 14.80 $ 18.24 $ 20.34
Gas (Mcf) (b) 2.00 2.29 1.97 1.35 1.67 2.33 1.96
BOE (a) 11.81 15.06 14.35 11.00 11.82 14.96 14.26
Average production
expense/BOE $ 3.41 $ 3.53 $ 3.76 $ 3.99 $ 3.97 $ 3.91 $ 4.67
Average production
margin/BOE $ 8.40 $ 11.53 $ 10.59 $ 7.01 $ 7.85 $ 11.05 $ 9.59
<FN>
(a) Gas production is converted to oil equivalents at the rate of six 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, 1998 were approximately
$1.94 per Mcf of gas and $9.56 per barrel of oil.
</FN>
</TABLE>
11
<PAGE>
PRODUCING WELLS
The following table sets forth certain information at December 31, 1998
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.
<TABLE>
<CAPTION>
Predominant Gross Net
Product Stream Wells Wells
-------------- ----- -----
<S> <C> <C>
Crude oil 1,003 320
Natural gas 545 295
----- ----
1,548 615
===== ====
</TABLE>
ACREAGE
The following table sets forth certain information at December 31, 1998
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 boundaries. 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.
<TABLE>
<CAPTION>
Developed Undeveloped Total
---------------------- ---------------------- ----------------------
Gross Net Gross Net Gross Net
--------- --------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C> <C>
Rocky Mountain Region
Washakie (WY) 42,695 36,847 104,878 92,808 147,573 129,655
Wind River (WY) (a) 10,508 9,180 96,564 61,182 107,072 70,362
Northern Wyoming 7,958 4,909 - - 7,958 4,909
Piceance (CO) (b) 5,920 3,206 98,333 46,432 104,253 49,638
Uinta (UT) 15,361 8,411 90,630 68,947 105,991 77,358
Big Horn (WY) 320 160 158,964 82,239 159,284 82,399
Deep Green River (WY) (c) 480 369 63,222 54,258 63,702 54,627
--------- --------- --------- -------- --------- ---------
Rocky Mountain Region 83,242 63,082 612,591 405,866 695,833 468,948
--------- --------- --------- -------- --------- ---------
Gulf of Mexico
Main Pass Area 33,185 16,949 14,763 10,111 47,948 27,060
Other 44,813 19,056 66,420 22,255 111,233 41,311
--------- --------- --------- -------- --------- ---------
Total Gulf of Mexico 77,998 36,005 81,183 32,366 159,181 68,371
--------- --------- --------- -------- --------- ---------
North Louisiana
Minerals 21,606 13,399 466,526 317,868 488,132 331,267
Leases (d) 4,495 3,900 95,005 56,005 99,500 59,905
--------- --------- --------- -------- --------- ---------
Total North Louisiana 26,101 17,299 561,531 373,873 587,632 391,172
--------- --------- --------- -------- --------- ---------
Other 8,311 1,664 6,410 1,373 14,721 3,037
--------- --------- --------- -------- --------- ---------
Southern Region 112,410 54,968 649,124 407,612 761,534 462,580
--------- --------- --------- -------- --------- ---------
Total Company 195,652 118,050 1,261,715 813,478 1,457,367 931,528
========= ========= ========= ======== ========= =========
<FN>
(a) The Company also holds 16,500 net undeveloped acres under option.
(b) The Company sold its interest subsequent to year end.
(c) The Company also holds the deep rights, below approximately 12,500 feet, in 10,625 net acres which are not included.
(d) The Company also holds 128,000 net undeveloped acres under option.
</FN>
</TABLE>
12
<PAGE>
DRILLING RESULTS
The following table sets forth information with respect to wells
drilled during the past three years. The information should not be considered
indicative of future performance, nor should it be assumed that there is
necessarily any correlation between the number of productive wells drilled,
quantities of reserves found or economic value. Productive wells are those that
produce commercial quantities of hydrocarbons whether or not they produce a
reasonable rate of return.
<TABLE>
<CAPTION>
1998 1997 1996
---- ---- ----
<S> <C> <C> <C>
Development wells
Productive
Gross 64.0 79.0 79.0
Net 44.0 39.2 44.3
Dry
Gross 3.0 4.0 3.0
Net 1.7 1.5 1.5
Exploratory wells
Productive
Gross - 5.0 5.0
Net - 2.2 1.5
Dry
Gross 8.0 2.0 2.0
Net 4.6 1.7 1.6
</TABLE>
At December 31, 1998, the Company had nine gross (6.8 net) development
wells in progress; one drilling, one awaiting pipeline connection and seven in
the completion phase. Additionally, at year end 1998, nine gross (5.2 net)
exploratory wells were in progress; one drilling, one awaiting pipeline
connection, and seven in the completion phase. Wells in progress at the end of
1997 and 1996 are reflected in the appropriate category in the above table based
upon the well's final outcome.
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 1998, Sonat Marketing Company accounted for approximately
33 percent of revenues and Engage Energy accounted for approximately 32 percent
of revenues. In 1997, Sonat Marketing Company accounted for approximately 17
percent of revenues, Engage Energy accounted for approximately 14 percent, and
Duke Power and Energy, which purchased a significant portion of Patina's gas
production, accounted for approximately 12 percent. In 1996, Duke Power and
Energy accounted for approximately 11 percent 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 areas of its operations. 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
currently extend through March 2000 with an option to extend until March 2001.
13
<PAGE>
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 was owned 73 percent by Coastal Field
Services and 27 percent by the Company. At the end of 1998, the Company and
Coastal Field Services elected to discontinue their participation in Great
Divide and to return the facilities involved to their original owners under the
unwinding provisions of the Great Divide agreements. In January, subsequent to
this unwinding, the Company sold its interest in the pipeline facilities in the
Piceance Basin in conjunction with the sale of its oil and gas properties in
this area. The Company continues to pursue strategic alternatives for its
Wyoming pipeline facilities.
Beginng in August of 1998, the Company commenced transporting
substantially all of its production from the East Main Pass area of the Gulf of
Mexico through Transcontinental Gas Pipe Line Corporation for delivery to
markets accessible through Transco in the Mobile Bay Area of Alabama. From March
through August of 1998, the Company delivered production from the area to
markets in southeast Louisiana accessible through Viosca Knoll Gathering
Company. The Company converted to Transco to alleviate the downstream
constraints experienced in southeast Louisiana and to access additional markets
in which to sell production from the area. The Company amended its prior
arrangement with Viosca Knoll to allow for the transportation of gas on Transco
and to provide for continuing back-up, interruptible transportation rights on
Vioca Knoll. As result, the Company has increased transportation capacity from
the area and expects to realize an increase in value net of all transportation
fees payable to Transco and Viosca Knoll under the arrangement. To fully
capitalze on the higher prices available through Transco, the Company is
maximizing the amount of its Main Pass production marketed through Transco by
arranging for displaced delivery into Transco of production attributable to
Company facilities in the area that are not currently connected to the system.
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.
EMPLOYEES
The Company had 306 employees as of December 31, 1998 with principal
executive offices in Fort Worth, Texas and regional offices in Denver,
Colorado and Houston, Texas. Field offices are also maintained in the areas
where the Company operates properties.
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
14
<PAGE>
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 - The Company's Operations are Subject to Strict 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
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 $350.0 million in the case of onshore
facilities and $75.0 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
15
<PAGE>
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 types 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
The Company's Income and Cash Flows are Largely Dependent Upon Gas Prices
The Company derives its revenue principally from the sale of natural
gas. The Company sells the majority of its gas in the open market at prevailing
market prices, or under market-price contracts. The market price for gas is
dictated by supply and demand, and the Company cannot predict or control the
price it receives for its gas. Moreover, market prices for gas vary
significantly by region. For example, natural gas in the Rocky Mountain region,
where the Company produced approximately 43 percent of its gas in 1998,
historically sells for less than gas in the Midwest and Northeast.
Accordingly, the Company's income and cash flows will be greatly
affected by changes in gas prices and by regional pricing differentials. The
Company will experience reduced cash flows and may experience operating losses
when gas prices are low. Under extreme circumstances, the Company's gas sales
may not generate sufficient revenue to meet the Company's financial obligations
and fund its planned capital expenditures. Moreover, significant price decreases
could negatively effect the Company's reserves by reducing the quantities of
reserves that are recoverable on an economic basis, necessitating write downs to
reflect the realizable value of the reserves in the low price environment.
The Company Must Replace Reserves to Sustain Production
The Company depletes its reserves as it produces oil and gas for sale
into the market. In order to sustain and increase the Company's reserves and
production levels, the Company must replace the reserves it produces on a cost
effective basis through a combination of exploration for undiscovered reserves,
enhanced development of known reserves, and acquisitions of new reserves. The
Company's future production is highly dependent upon its level of success in
finding or acquiring additional reserves. Replacing produced reserves on
economic terms will become more and more difficult in the future as domestic
natural resources are depleted. As a result, new exploration operations
increasingly require use of costly seismic and other geoscience technology while
yielding discoveries that are generally of smaller size than those found in
years past. Likewise, the Company's cost of developing and producing reserves is
generally increasing as it is forced to invest in secondary and tertiary
recovery technology to exploit a shrinking reserve base. The Company may be
unable to make the necessary capital investment to maintain or expand its
reserves if cash flow from operations is reduced and external sources of capital
become limited or unavailable. The Company cannot assure you that its future
development, acquisition and exploration activities will result in additional
proved reserves or that it will be able to drill productive wells at acceptable
costs.
The Company's Drilling Program Involves Complicated Wells
A large number of the wells in the Company's drilling program target
carbonate geological formations which involve special drilling risks. The
Company often targets very deep drilling objectives, frequently exceeding 15,000
feet, involving very high subsurface pressures and extreme heat. Many of these
wells encounter hydrogen sulfide gas or other substances which are corrosive or
otherwise harmful to humans and equipment. These wells create a greater risk for
personal injury or property damage from blowout, cratering, well fire, or
similar catastrophe than risks related to less complicated drilling operations.
16
<PAGE>
The Company's Operations Are Subject to Interruption From Severe Weather and
Other Factors
The Company's operations are conducted principally in the offshore Gulf
Coast area and in the Rocky Mountain region. The weather in both of these areas
can be extreme and can cause an interruption in the Company's exploration and
production operations. The Company's Gulf Coast operations are susceptible to
tropical storms and hurricanes. While the Company's offshore facilities are
engineered to withstand typical hurricane force winds, severe storms
nevertheless result in temporary interruptions due to the evacuation of
personnel for safety and the shut in of production. Moreover, especially severe
weather can result in damage to facilities entailing longer operational
interruptions and significant capital investment. Likewise, the Company's Rocky
Mountain operations are subject to disruption from winter storms and severe cold
which can limit operations involving fluids and impair access to the Company's
facilities.
In addition to weather, other factors such as mechanical break-downs,
workover operations and gathering and transportation problems can result in
production interruptions. The Company's exposure to production interruptions is
greatest in the Gulf, where the Company's production is very concentrated.
Almost 90 percent of the Company's 1998 production in the Gulf came from three
platforms located in close proximity in the East Main Pass area. This level of
concentration creates a risk of production interruption from weather or other
local factors. An extended interruption in the Company's operations could have a
material adverse effect on the Company's income and cash flows in the period in
which the interruption occurs.
The Company Invests Heavily in Exploration
The Company has historically invested a significant portion of its
capital budget in drilling exploratory wells in search of unproved oil and gas
reserves. The Company cannot be certain that the exploratory wells it drills
will be productive or that it will recover all or any portion of its
investments. In order to increase the chances for exploratory success, the
Company often invests in seismic or other geoscience data to assist it in
identifying potential drilling objectives. Additionally, the cost of drilling,
completing and testing exploratory wells is often uncertain at the time of the
Company's initial investment. Depending on complications encountered while
drilling, the final cost of the well may significantly exceed that which the
Company originally estimated. The Company expenses all direct costs of drilling
an unsuccessful exploratory well in the period in which the well is determined
not to be producible in commercial quantities.
Acquisitions Could Alter the Company's Geographic Focus and Financial Risk
Profile
The Company continually evaluates acquisition opportunities and
frequently engages in bidding and negotiating for acquisitions, many of which
are substantial. Although the Company generally concentrates on acquiring
producing properties with development and exploration potential located in its
current areas of operation, the Company occasionally considers acquisitions in
other geographic regions. To finance a large acquisition, the Company may alter
or increase substantially its capitalization through the issuance of additional
debt or equity securities, the sale of production payments or other financing
structures. A large acquisition outside the Company's core operational areas or
involving a significant issuance of debt or equity could significantly alter its
financial risk profile and the nature of its operations depending upon the
character of the acquired properties and the structure of the financing.
The Company's Operations Are Subject to Strict Environmental and Other
Governmental Regulation
The Company must conduct its exploration and production operations in
compliance with a wide variety of federal, state and local laws, including those
relating to the discharge of materials into the environment or otherwise
relating to protection of the environment. Because many of the Company's Gulf of
Mexico and Rocky Mountain operations are located in environmentally sensitive or
other protected areas, these operations are subject to special regulations and
permitting requirements. The Company and its personnel could incur material
fines and penalties, and in some cases, be subject to criminal prosecution if it
fails to comply with such regulations.
17
<PAGE>
The Company's compliance with increasingly strict environmental and
other regulations adds materially to the cost of the Company's operations and
can result in substantial delays in new projects. The Company expends
significant managerial and financial resources complying with governmental
regulations and anticipates these costs will increase in response to trends
toward greater environmental protection and stricter governmental oversight.
Likewise, the Company's compliance with environmental impact assessment
regulations on federal leases in the Company's Rocky Mountain region can
significantly delay the commencement of operations in the area and can limit the
extent to which the leases may be developed. For example, delays in the
environmental impact assessment process for the Company's expanded drilling
program in the northern Washakie Basin have resulted in the Company postponing
commencement of a 30-well drilling program in the area.
The Company's Reserve Estimates and Future Net Revenues Are Based on Assumptions
This annual report contains estimates of reserves and estimated future
net revenues from such reserves. These estimates are based on reports of the
Company's independent petroleum engineers. These estimates fluctuate greatly
depending on the underlying assumptions about factors such as: 1) historical
production from analogous areas, 2) taxes and other governmental regulation, 3)
commodity prices and operating costs, 4) future development activity and
investment, and 5) the applicable discount rate. Actual future production, oil
and gas prices, revenues, taxes, development expenditures, operating expenses
and quantities of recoverable oil and gas reserves most likely will vary from
those estimated. Any significant variance could materially affect the estimated
quantities and present value of reserves set forth in this annual report. In
addition, the Company may adjust estimates of proved reserves to reflect
production history, results of exploration and development, prevailing oil and
gas prices and other factors, many of which are beyond its control. For these
reasons, estimates of reserves and future net cash flows should be used for
comparative purposes only and should not be viewed as a measure of actual
production or revenues from the Company's reserves.
The Company Faces Competition for Labor and Services
Oil and gas exploration and production operations are largely regional
in nature. Depending on economic conditions, seasonal drilling activity, and
other factors beyond the Company's control, the Company frequently faces strong
competition in procuring services in the geographic regions in which it operates
from a limited pool of laborers, drilling services contractors and equipment
vendors. Moreover, many of the Company's competitors have substantially greater
financial and other resources than the Company. Competition for labor, services
and equipment is especially intense during warm weather months when the level of
drilling operations traditionally are at their peak. This competition sometimes
results in increased labor and drilling services costs or in operational delays.
Depending on the magnitude of any resulting cost increases or operational
delays, the effects of this competition for labor, services and equipment could
materially impact the Company's income and cash flows.
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
percent. The complaint alleges, among other things, that the defendants have
failed to pay proper royalties under the lease, have unlawfully commingled
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
$175.0 million. The Company and the other interest owners have filed an answer
denying the claims and intend to contest the suit vigorously. Activity in the
case has been stayed pending resolution of a variety of administrative motions
in the matter.
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.
18
<PAGE>
On January 15, 1999, a stockholder of the Company filed a putative
class action complaint in the Delaware Court of Chancery, No. 16900-NC, seeking
to enjoin the merger of the Company into Santa Fe Energy Resources, Inc. ("Santa
Fe") on the proposed terms and seeking damages. Defendants named in the
complaint are the Company, each of its directors and Santa Fe. The plaintiff
alleges numerous breaches of the duties of care and loyalty owed by the Company
and its directors to the purported class in connection with entering into the
merger agreement with Santa Fe. The plaintiff further alleges that Santa Fe
aided and abetted the Company and its directors in their alleged breaches of
fiduciary duty. The defendants believe the complaint is without merit and intend
to vigorously defend the action.
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 1998.
19
<PAGE>
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED
SECURITY HOLDER MATTERS
The Company's stock is listed on the New York Stock Exchange and trades
under the symbol "SNY." The following table sets forth, for 1998 and 1997, 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.
<TABLE>
<CAPTION>
1998 1997
---------------------- ----------------------
High Low High Low
--------- --------- --------- ---------
<S> <C> <C> <C> <C>
First Quarter $ 21-7/16 $ 15 $ 19-1/8 $ 14-5/8
Second Quarter 22-1/2 17-3/8 19 15-1/4
Third Quarter 21-1/4 14-9/16 23-5/8 18-3/16
Fourth Quarter 17-5/16 11-1/4 24-7/8 16-3/4
</TABLE>
On February 26, 1999, the closing price of the common stock was $10
7/16. Quarterly dividends were paid at the rate of $.065 per share during 1998
and 1997. For federal income tax purposes, the common dividends paid during 1998
were a non-taxable return of capital. Shares of common stock receive dividends
as, if and when declared by the Board of Directors. The amount of future
dividends will depend on debt service requirements, capital expenditures and
other factors. On December 31, 1998, there were approximately 2,100 holders of
record of the common stock and 33.4 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,
1998. Share and per share amounts refer to common shares. The following
information includes the results of Patina Oil and Gas Corporation ("Patina")
through the third quarter of 1997 when the Company sold its interest in Patina
and should be read in conjunction with the consolidated financial statements
presented elsewhere herein.
<TABLE>
<CAPTION>
(In thousands, except per share data) As of or for the Year Ended December 31,
---------------------------------------------------------
1998 1997 1996 1995 1994
--------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C>
Income Statement
Revenues $ 141,095 $ 255,728 $ 285,111 $ 197,301 $ 262,328
Income (loss) before extraordinary items (24,733) 35,465 62,950 (39,831) 12,372
Per share (.74) .96 1.81 (1.53) .07
Net income (loss) (24,733) 32,617 62,950 (39,831) 12,372
Per share (.74) .87 1.81 (1.53) .07
Dividends per share .26 .26 .26 .26 .25
Weighted average shares outstanding 33,416 30,588 31,308 30,186 23,704
Cash Flow
Net cash provided by operations $ 75,159 $ 122,041 $ 101,730 $ 69,121 $ 86,397
Net cash realized (used) by investing (188,267) 31,808 (62,356) 32,421 (245,503)
Net cash realized (used) by financing 29,836 (92,328) (38,715) (96,012) 169,926
Balance Sheet
Working capital $ (37,713) $ 56,326 $ 9,168 $ 5,842 $ 708
Oil and gas properties, net 352,983 274,304 635,387 435,217 472,239
Total assets 433,937 546,088 879,459 555,493 673,259
Senior debt 39,001 1 188,231(a) 150,001 234,857
Subordinated notes 173,787 173,635 183,842(b) 84,058 83,650
Stockholders' equity 128,454 263,756 294,668 235,368 274,086
<FN>
(a) Includes $93.7 million of Snyder senior debt and $94.5 million of Patina senior debt.
(b) Includes $80.7 million of Snyder convertible subordinated notes and $103.1 million of Patina subordinated notes.
</FN>
</TABLE>
20
<PAGE>
The following tables set forth unaudited summary financial results on a
quarterly basis for the two most recent years:
<TABLE>
<CAPTION>
(In thousands, except per share data) 1998
------------------------------------------------
First Second Third Fourth
--------- --------- --------- ---------
<S> <C> <C> <C> <C>
Oil and gas sales $ 32,822 $ 34,581 $ 32,636 $ 33,165
Production margin 24,374 25,241 22,050 23,047
Depletion, depreciation, amortization, and property impairments 11,762 13,925 13,987 19,773
Exploration expense 3,213 7,305 24,674 13,111
Income (loss) before extraordinary items 1,838 (777) (13,312) (12,482)
Per share .06 (.02) (.40) (.37)
Net income (loss) 1,838 (777) (13,312) (12,482)
Per share .06 (.02) (.40) (.37)
</TABLE>
<TABLE>
<CAPTION>
(In thousands, except per share data) 1997
------------------------------------------------
First Second Third Fourth
--------- --------- --------- ---------
<S> <C> <C> <C> <C>
Oil and gas sales $ 67,848 $ 48,988 $ 52,156 $ 38,224
Production margin 53,827 36,485 39,029 29,352
Depletion, depreciation, amortization, and property impairments 23,208 23,389 26,802 13,738
Exploration expense 1,700 3,690 7,212 4,444
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
</TABLE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
OVERVIEW
Snyder Oil Corporation (the "Company") is an independent oil and gas
company with principal operations in domestic natural gas exploration and
production. The Company's primary properties are located in the Rocky Mountain
region, Gulf of Mexico and northern Louisiana.
The Company has concentrated its exploration and development efforts
over the past years to emphasize natural gas reserve growth. During 1998, 90
percent of the Company's reserve additions were natural gas. This has increased
the percentage of natural gas reserves to 82 percent, versus 78 percent in 1997.
At December 31, 1998, the Company had proved reserves of 100.3 million barrels
of oil equivalent with a pretax present value of $365.6 million, assuming a ten
percent discount rate with constant pricing and costs.
Exploration expense in 1998 of $48.3 million significantly impacted
the Company's financial results from eight dry holes and significant
acquisitions of 3-D seismic. Even with the high exploration expense, the
Company's capital program replaced 382 percent of 1998 production with a finding
and development cost from all sources, including revisions, of $4.44 per barrel
of oil equivalent, an improvement of 23 percent compared to 1997.
In October 1997, the Company sold its 74 percent 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. Excluding Patina,
production increased 26 percent in 1998 compared to 1997; however, a 21 percent
decrease in prices caused oil and gas revenues to remain constant. Production
grew in all three core operating areas reflecting our strategy of balanced
growth.
The Company also has investments in two international exploration and
production companies, Cairn Energy plc ("Cairn") and SOCO International plc
("SOCI plc") , both listed on the London Stock Exchange. In 1998, the Company
experienced a decline of $119.1 million in the value of its investments in Cairn
and SOCI plc. The unrealized loss reflected in equity was $75.4 million, net of
tax. The book and market value at December 31, 1998 was $24.0 million. The Cairn
shares can be sold at the discretion of the Company. Since the Company
contributed assets to form SOCI plc in 1997, under London Stock Exchange rules,
the Company is not permitted to sell the SOCI plc shares prior to May 1999.
21
<PAGE>
On January 13, 1999, the Company announced its agreement to merge with
Santa Fe Energy Resources, Inc. ("Santa Fe") creating Santa Fe Snyder
Corporation. The Board of Directors of each company has unanimously approved the
transaction and committed to vote his or her shares in favor of the merger.
Snyder shareholders will receive 2.05 shares of Santa Fe common stock for each
share of Snyder resulting in Snyder shareholders owning approximately 40 percent
of the outstanding shares after the merger. It is expected that the transaction
will be accounted for as a purchase. John C. Snyder will be the Chairman of
Santa Fe Snyder Corporation and James L. Payne, currently the Chairman and CEO
of Santa Fe, will be the CEO of the new company. The eleven person board will be
composed of five members from Snyder's current directors and six from Santa Fe.
The Form S-4 has been filed with the SEC and, pending shareholder and other
required approvals, the merger is expected to be completed in the second quarter
of 1999.
In January 1999, the Company sold its interest in the Piceance Basin
and the associated gathering facility for $28.8 million cash, resulting in an
estimated gain of approximately $500,000.
FINANCIAL PERFORMANCE
The Company reported a net loss in 1998 of $24.7 million or ($.74) per
share compared to net income, excluding Patina, for 1997 of $28.2 million or
$.73 per share. Excluding gains on sales of properties, 1998 resulted in a net
loss of $26.9 million compared to a net loss applicable to common of $4.1
million in 1997, excluding Patina, gains on sales of equity interests in
investees, gains on sales of properties, gain on sale of subsidiary interest,
extraordinary item and minority interest. Higher exploration expense and lower
oil and natural gas prices offset the 36 percent increase in gas production from
1997, excluding Patina.
Net cash provided by operating activities decreased to $75.2 million
during 1998, compared to $122.0 million during 1997. This decrease is attributed
to the sale of Patina, which accounted for $48.7 million of last year's cash
flow. Excluding Patina, the Company increased its net cash provided by operating
activities in spite of the decline in oil and natural gas prices between years.
FORWARD-LOOKING INFORMATION
Certain statements 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), other than statements of
historical fact, are forward-looking statements within the meaning of the
Private Securities Litigation Reform Act of 1995. Forward-looking statements may
relate to a variety of matters not currently ascertainable, such as future
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" in this Annual Report on Form 10-K,
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.
22
<PAGE>
RESULTS OF OPERATIONS
COMPARISON OF 1998 RESULTS TO 1997
Oil and Gas Sales
The following table reflects activities for the Company's oil and gas
properties for 1998 and 1997. Two columns are provided for 1997 to show the
effect of the October 1997 disposition of Patina. The discussion following the
-----------------------------
tables will concentrate on differences between 1998 and 1997, excluding Patina.
- -------------------------------------------------------------------------------
<TABLE>
<CAPTION>
Twelve Months Ended December 31,
-------------------------------------------------------
Excluding
Patina
(Unaudited)
1998 1997 1997
------------- -------------- --------------
(In thousands, except production, average
price and cost per BOE data)
<S> <C> <C> <C>
Oil and gas sales $ 133,204 $ 133,851 $ 207,216
Direct operating costs (38,492) (35,016) (48,523)
------------- ------------- -------------
Production margin $ 94,712 $ 98,835 $ 158,693
============= ============= =============
Average daily production:
Oil (Bbls) 5,231 5,617 9,561
Gas (Mcf) 153,982 113,361 168,873
Average oil price (per Bbl) $ 11.02 $ 18.24 $ 18.88
Average gas price (per Mcf) 2.00 2.33 2.29
Direct operating costs (per BOE)
Lease operating $ 2.61 $ 2.74 $ 2.41
Production taxes .66 .89 .94
Workovers .14 .28 .18
------------- ------------- -------------
Total direct operating costs $ 3.41 $ 3.91 $ 3.53
============= ============= =============
Depletion, depreciation and amortization $ 4.78 $ 4.87 $ 5.80
============= ============= =============
</TABLE>
In 1998, the increase in gas production of 36 percent was offset by a
40 percent decrease in the average oil price and a 14 percent decrease in the
average price of natural gas. The increase in gas production reflected growth in
all three core operating areas. Gas production in the Gulf of Mexico increased
50 percent with the commencement of production from the new Main Pass 261
platform in March 1998, along with development drilling and an additional
pipeline connection in the third quarter of 1998. Increased gas production in
the Rocky Mountain Region was driven by the acquisition of interests in the
Washakie and Beaver Creek areas coupled with the region's ongoing development
drilling program. The decrease in oil production reflects the delay of workovers
and drilling where feasible on oil projects due to the low oil price
environment.
The gas price received at the wellhead during 1998 was $1.87 per Mcf,
with downstream activities adding $.13 per Mcf to the reported price. In 1997,
the wellhead gas price, excluding Patina, was $2.28, with downstream activities
adding $.05 to the reported price. The oil price was $11.02 per barrel for 1998
with no downstream activities. This compares to $17.84 at the wellhead in 1997
with $.40 added from downstream activities.
23
<PAGE>
Direct Operating Costs
Direct operating expenses decreased $.50 per barrel of oil equivalent
from 1997, excluding Patina, due to the more equal balance in production between
the Rockies and the Gulf of Mexico along with ongoing cost cutting efforts,
lower workover costs and the absence of production taxes on the growing
production in the Gulf of Mexico.
Depletion, Depreciation and Amortization
DD&A expense for the year increased by $10.4 million due to a 26
percent increase in production. DD&A per barrel of oil equivalent decreased $.09
reflecting the shift in the production mix to properties with lower costs.
Non-Recurring Gains and Losses
Non-recurring gains and losses added $39.7 million to income before
taxes, minority interest and extraordinary item in 1997 while they reduced the
1998 loss by $2.2 million. Gains on sales of equity interests in investees
during 1997 included a $13.0 million gain on the sale of Cairn stock and a $19.8
million gain related to the initial public offering of SOCI plc. Gains on sales
of properties of $3.3 million in 1998 and $8.7 million in 1997 were the result
of the Company's ongoing plan to divest non-strategic assets. The most
significant items in 1998 were a $3.1 million gain on the exchange of
non-strategic South Texas properties for the expansion of a core area in the
Rocky Mountains and a $5.5 million impairment of two Gulf of Mexico properties.
In 1997, the most significant items were the sales of two non-core properties in
the Gulf of Mexico for a $5.1 million gain and impairments of $7.3 million.
Exploration Expense
Exploration expense of $48.3 million in 1998 represents an increase
from $16.9 million in the prior year as 1998 includes $28.4 million for five dry
holes in the Gulf of Mexico and increased expenditures for the purchase and
evaluation of 3-D seismic of $17.8 million to support our exploration and
development efforts in the Gulf of Mexico, northern Louisiana and the Rocky
Mountains. In 1998, with our continuing low risk development program in the
Rockies, we elected to take a higher risk profile in the Gulf attempting to
capture the longer reserve life and higher production rates found in the
transition zone between the continental shelf and the ultra-deep projects.
Although the five dry holes in the Gulf of Mexico were only 15 percent of our
1998 capital program the expense constituted 75 percent of our reported loss for
1998. In 1997, the Company invested $8.9 million in 3-D seismic and incurred
$8.0 million for two exploratory dry holes in the Gulf of Mexico.
General and Administrative Expenses
General and administrative expenses, net of reimbursements, of $16.4
million in 1998 were relatively consistent with the $16.6 million in 1997,
excluding Patina.
Financing Costs
Interest expense, net of interest income, was $13.4 million compared to
$10.6 million in 1997. The increase is due to the higher principal balance
outstanding throughout 1998 and the higher effective interest rate on the
subordinated notes issued in June 1997. Interest income was $2.4 million for
both 1998 and 1997.
Minority Interest in Subsidiaries
Minority interest recognized during 1997 related to the ten percent of
SOCO International, Inc. which was owned by a Director of the Company and the
minority share of Patina. In July 1997, SOCO International, Inc. acquired the
Director's ten percent ownership for shares of common stock of the Company. The
Company's investment in Patina was sold in the fourth quarter of 1997.
24
<PAGE>
Extraordinary Item
The extraordinary item recorded in 1997 of $2.8 million, net of tax,
related to the early extinguishment of the Company's convertible subordinated
notes.
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, for stock in Cairn.
The following table sets forth certain operating information of the
Company for the periods presented. The discussion following the tables includes
consolidated results except as noted.
<TABLE>
<CAPTION>
Excluding Patina Increase Consolidated Increase
----------------------- ----------------------
1997 1996 (Decrease) 1997 1996 (Decrease)
-------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C>
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%)
</TABLE>
Oil and gas sales, excluding Patina, increased 25 percent 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 non-strategic properties during 1996.
Production margin (oil and gas sales less direct operating expenses)
for 1997, excluding Patina, increased 37 percent compared to 1996 as direct
operating expenses decreased in spite of the significant increase in production.
This is primarily due to the sale of non-core properties which had high
operating costs, increased production in the Gulf of Mexico which has much lower
operating costs per barrel of oil equivalent produced, and an increased emphasis
on operating efficiencies. Operating costs per barrel of oil equivalent ,
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 non-strategic
assets. The most significant items in 1997, after the sale of Patina, were the
sales of two non-core 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 percent interest in the Deep 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
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 percent decrease in the fourth quarter of 1997 attributable to
the disposition of Patina.
25
<PAGE>
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
barrel of oil equivalent, 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.
CAPITAL EXPENDITURES
Exploration and Development Activities
During 1998, the Company incurred $167.4 million on exploration and
development activities while placing 78 wells on production with 18 wells in
progress at year end. In the Gulf of Mexico, $33.9 million of development
activity included a production platform at Main Pass 261, three development
wells, one recompletion and one development well in progress at year end.
Exploration activities included $19.1 million for four exploration
discoveries and $28.4 million for five unsuccessful tests. Additionally, $8.7
million was invested in 3-D seismic acquisition and evaluation.
The Company continued its successful drilling program in the Rockies.
Expenditures for 1998, totaled $52.8 million to place 65 development wells on
production with seven wells in progress at year end. One exploration well was
successful totaling $552,000 and two unsuccessful tests totaled $1.0 million.
Additional exploration expense of $2.3 million was incurred for 3-D seismic
acquisition and evaluation.
The Company spent $12.8 million primarily in North Louisiana to place
five development wells on production with one development well and four
exploratory wells in progress at year end. One exploration well was unsuccessful
totaling $1.0 million. An additional $6.8 million of exploration expense was
incurred for the acquisition and evaluation of 3-D seismic in the area.
Acquisitions
During 1998, the Company spent $16.2 million to acquire producing
properties and $7.5 million on acreage purchases in and around the Company's
operating hubs. Of the producing property acquisitions, $5.4 million was
incurred to purchase an incremental interest in the Main Pass properties
operated by the Company in the Gulf of Mexico. The Company also spent $2.6
million in North Louisiana to purchase producing properties and a gas processing
facility and $7.2 million to purchase incremental interests in properties in the
Washakie Basin of southern Wyoming.
The Company also completed a non-cash acquisition in the second quarter
of 1998. The Company acquired 75 percent of Amoco Production Company's ("Amoco")
interest in the Beaver Creek Unit and two associated gas plants in the Wind
River Basin in Wyoming in exchange for the Jonah Field portion of the Company's
properties in the Deep Green River Basin project in Wyoming. Under terms of the
agreement, the Company also received Amoco's interest in the Deep Green River
Basin acreage outside the Jonah Field area and retained the deep rights in Jonah
beneath the Mesaverde horizon at about 12,250 feet.
26
<PAGE>
During the third quarter of 1998, the Company exchanged its interest in
the Cage Ranch Field in South Texas for CIG Exploration's interest in certain
producing and non-producing properties in the Washakie Basin of Wyoming. The
Company received approximately $1.5 million in cash as part of the exchange.
Proved acquisitions during 1996 included $218.4 million related to the
formation of Patina including the acquisition of Gerrity Oil & Gas Corporation.
In October 1997, the Company sold its interest in Patina. Net proceeds from the
sale were approximately $127.0 million.
Capital Commitments
As of December 31, 1998, commitments for capital expenditures totaled
approximately $27.0 million. The Company anticipates that 1999 expenditures for
exploration and development could be up to $75.0 million subject to total cash
flow for the year, which is dependent on commodity prices. 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.
CAPITAL RESOURCES AND LIQUIDITY
Capital Resources
The Company's primary needs for cash are for exploration, development
and acquisition of oil and gas properties, payment of interest on outstanding
indebtedness and working capital obligations. The Company's primary capital
resources are net cash provided by operating activities, existing credit
facilities and proceeds from sales of marketable securities and non-strategic
assets. The Company expects that these resources will be sufficient to fund its
capital commitments in 1999.
At December 31, 1998, the Company had total assets of $433.9 million.
Total capitalization was $341.2 million, of which 51 percent was represented by
subordinated debt, 38 percent by stockholders' equity, and eleven percent by
senior debt.
At December 31, 1998, the Company had marketable securities with a
market value of $24.0 million for its shares of Cairn and SOCI plc. In 1998, the
Company experienced a decline of $119.1 million in the value of its investments
in Cairn and SOCI plc. The unrealized loss reflected in equity was $75.4
million, net of tax.
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.
In the fourth quarter of 1998, the Company increased the borrowing base
under the existing credit facility to $150.0 million from $100.0 million in
order to provide the flexibility to continue to pursue growth opportunities. As
the Company continues to pursue balanced growth through exploitation,
exploration and acquisitions, the Company may utilize alternative financing
sources, including the issuance of fixed rate long-term public debt, convertible
securities or preferred stock. The Company may also issue securities in exchange
for oil and gas properties, stock or other interests in other oil and gas
companies or related assets.
In June 1997, the Company issued $175.0 million of 8.75 percent 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
its credit 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 the Company 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
27
<PAGE>
limitations, more than $70.0 million was available for the payment of dividends
and other restricted payments at December 31, 1998. Upon the occurrence of a
change of control, as defined in the Notes, the Company would be obligated to
make an offer to purchase all outstanding Notes at a price of 101 percent of the
principal amount thereof. In addition, the Company 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 percent of the principal amount thereof. The proposed merger with Santa Fe
does not obligate the Company to make any offer to repurchase the Notes.
The Company seeks to diversify its exploration and development risks by
attracting partners for its significant projects and maintaining a program to
divest of marginal properties and assets which do not fit its long range plans.
The Company received $4.7 million during 1998 and $10.7 million during 1997
in proceeds from sales of properties which were used primarily to fund
development expenditures. None of the sales were individually significant.
Subsequent to year end, the Company sold its interest in the Piceance Basin and
the associated gathering facility for $28.8 million, resulting in an estimated
gain of $500,000.
The Board has authorized, at management's discretion, the repurchase of
up to $70.0 million of the Company's securities. From 1996 through 1998, the
Company repurchased $61.5 million of its securities including 3.6 million common
shares for $57.0 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.
Liquidity
At December 31, 1998, the Company had $6.1 million of cash and cash
equivalents on hand, $17.2 million of unrestricted marketable securities and
$39.0 million of outstanding senior debt compared to $89.4 million of cash and
cash equivalents on hand and $96.1 million of unrestricted marketable securities
at December 31, 1997. The Company's ratio of current assets to current
liabilities was .49 at December 31, 1998, down from 1.98 at December 31, 1997
due to the redeployment of cash for exploration and development projects.
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
1998 and 1997. Average gas prices were increased by $.13 per Mcf in 1998 and
$.05 per Mcf in 1997 by the benefit of the Company's hedging activities. 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 six Mcf per barrel.
28
<PAGE>
<TABLE>
<CAPTION>
Average Prices
----------------------------------------------
Crude Oil
and Natural Equivalent
Liquids Gas Barrels
----------- ---------- ----------
(Per Bbl) (Per Mcf) (Per BOE)
<S> <C> <C> <C>
Annual
------
1998 $ 11.02 $ 2.00 $ 11.81
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
Quarterly
---------
1998
----
First $ 13.07 $ 2.19 $ 13.13
Second 11.10 2.02 11.97
Third 10.31 1.89 11.14
Fourth 9.65 1.92 11.21
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
</TABLE>
At December 31, 1998, the Company was receiving an average of $9.56 per
barrel and $1.94 per Mcf for its production.
While production levels are somewhat controllable by the Company, the
majority of the Company's sales of oil and 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 oil
and gas production are dependent upon numerous factors beyond the control of the
Company. These factors include, but are not limited to, the level of seasonal
demand for oil and gas products, governmental regulations and taxes, the price
and availability of alternative fuels, the level of foreign imports of oil and
gas, and the overall economic environment.
YEAR 2000 MATTERS
Historically, certain computer systems, as well as certain hardware
containing embedded chip technology, such as microcontrollers and
microprocessors, were designed to utilize a two-digit date field and
consequently, they may not be able to properly recognize dates in the Year 2000.
This could result in significant system failures. The Company relies on its
computer-based management information systems, as well as embedded technology,
to operate instruments and equipment in conducting its normal business
activities. Certain of these computer-based programs and embedded technology
may not have been designed to function properly with respect to the application
of dating systems relating to the Year 2000.
In response, the Company has developed a "Year 2000 Plan" and, in 1997,
established an internal group to identify and assess potential areas of risk and
to make any required modifications to its computer systems and equipment used in
oil and gas exploration, production, gathering and gas processing activities.
The Year 2000 Plan is comprised of various phases, including assessment,
remediation, testing and contingency plan development. After the assessment
phase has been completed and evaluated, the remediation, testing and
certification phases will be implemented to ensure that the material facilities
and business activities will continue to operate safely and reliably, and
without interruption after 1999. Based upon the results of these activities
contingency plans will be developed to the extent deemed necessary.
29
<PAGE>
The Company's inventory of computer hardware and software is
substantially Year 2000 compliant except for two software packages. The
programming modifications for these two systems are complete and testing is
scheduled for the first quarter 1999 with implementation and conversion
scheduled for the second quarter of 1999.
The Company has monitor and control equipment with embedded chip
technology which are utilized in production and gas processing operations. The
various systems were reviewed in conjunction with the overall Year 2000 Plan.
Only one major system for gas plant automation is currently being replaced, at
an estimated cost of $500,000, with an expected completion date in the third
quarter of 1999. The phone systems utilized by the Company have or will be
upgraded to ensure Year 2000 compliance at a total cost of $110,000. Other
systems with embedded chip technology are relatively new and should be Year 2000
compliant according to the manufacturers.
The Company has also undertaken to monitor the compliance efforts of
suppliers, contractors and other third parties with whom it does business and
whose computer-based systems and/or embedded technology equipment interface with
those of the Company to ensure that operations will not be adversely affected by
the Year 2000 compliance problems of others. There can be no assurance that
there will not be an adverse effect on the Company if vendors, suppliers,
customers, state and federal governmental authorities and other third parties do
not convert their respective systems in a timely manner and in a way that is
compatible with the Company's information systems and embedded technology
equipment. However, management believes that ongoing communication with and
assessment of the compliance efforts and status of these third parties will
minimize these risks.
The Company believes that it can provide the resources necessary to
ensure Year 2000 compliance and expects to complete its Year 2000 Plan within a
time frame that will enable its computer-based programs and embedded technology
equipment to function without significant disruption in the Year 2000. Through
1998, the Company has incurred third party costs of approximately $1.0 million
for software and equipment costs related to Year 2000 compliance matters and
estimates that the total future third party, software and equipment costs
related to Year 2000 compliance activities, based upon information developed to
date, will be approximately $400,000, which will be expensed as incurred. These
costs have been and will continue to be funded through operating cash flows and
are not deemed to be material to the operations of the Company. The cost of the
remediation activities and the completion dates are based on management's best
estimates and may be updated as additional information becomes available. The
costs incurred to date and those estimated to be incurred in the future with
respect to Year 2000 issues do not include internal costs. The Company does not
presently separately track the internal costs incurred with respect to
implementation of the Year 2000 Plan. Such costs are principally the related
payroll costs for the information systems and field operations personnel,
including senior management, involved in the compliance program and related
travel and other out of pocket expenses.
Although the Company anticipates minimal business disruption will
occur as a result of Year 2000 issues, in the event the computer based programs
and embedded technology equipment of the Company, or that owned and operated by
third parties, should fail to function properly, possible consequences include
but are not limited to, loss of communications links, inability to produce and
process natural gas, loss of electric power, and inability to automatically
process commercial transactions, or engage in similar normal automated or
computerized business activities.
To date, the Company has not finalized its contingency plans for
possible Year 2000 issues. As noted above, in the event the Company, after
completion of the assessment, remediation and testing phases of the Year 2000
Plan and review of the results of monitoring the compliance efforts and status
of third parties, determines that contingency plans are necessary, the Company
will finalize such contingency plans based on its assessment of outside risks.
The Company anticipates that final contingency plans, as necessary, will be in
place by third quarter 1999.
The discussion of the Company's efforts, and management's
expectations, relating to Year 2000 compliance contains forward-looking
statements. Presently, the Company does not anticipate that the Year 2000 issues
will have a material adverse effect on the operations or financial performance
of the Company. However, there can be no assurance that the Year 2000 will not
adversely affect the Company and its business.
30
<PAGE>
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
The Company utilizes various financial instruments which inherently
have some degree of market risk. The primary sources of market risk include the
Company's investments in foreign marketable securities, fluctuations in
commodity prices and interest rate fluctuations.
EQUITY PRICE RISK AND FOREIGN CURRENCY RISK
The Company has investments in two international exploration and
production companies, Cairn Energy plc ("Cairn") and SOCO International plc
("SOCI plc"), which are both listed on the London Stock Exchange. The value of
these investments is subject to the risk of fluctuations in their stock prices
as well as fluctuations in the British pound, the currency in which they trade.
The Company owns 11.7 million shares of Cairn and 7.8 million shares of SOCI plc
and the book and fair market value of the investments was $24.0 million at
December 31, 1998.
PRICE FLUCTUATIONS
The Company's results of operations are highly dependent upon the
prices received for oil and natural gas production. A program to hedge the
impact of fluctuations in oil and gas prices was established by the Board of
Directors and limits hedging activity to non-speculative contracts intended to
manage the risk associated with potential future declines in commodity prices.
At December 31, 1998, the Company had swap contracts outstanding based on the
average final settlement prices for a Henry Hub Natural Gas Futures Contract
traded on the New York Mercantile Exchange ("NYMEX") for 3.6 million MMBtu's
with an average price of $2.22 expiring in October 1999. The Company also had
collar contracts for 3.6 million MMBtu's based on NYMEX with an average cap of
$2.46 and an average floor of $2.14 expiring in March 1999 and swap contracts
based on the business days relevant price for "Colorado Interstate Gas Co.,
Rocky Mountains" Index ("CIG") for 4.2 million MMBtu's at an average price of
$2.22 expiring in March 1999.
In 1994, the Company entered into a long-term gas swap agreement 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, 1998, that volume
represented approximately 30 percent of the Company's Rocky Mountain gas
production. The fair value of the contract based on the market price quoted for
a similar instrument was $576,000 at December 31, 1998.
INTEREST RATE RISK
Total debt at December 31, 1998, included $173.8 million of fixed debt
and $39.0 million of floating-rate debt attributed to bank credit facility
borrowings. As a result, the Company's annual interest cost in 1999 will
fluctuate based on short-term interest rates. The impact on annual cash flow
of a ten percent change in the floating rate (approximately 50 basis points)
would be approximately $200,000.
At December 31, 1998, the Company's fixed rate debt had a book value of
$173.8 million and a fair market value of $171.1 million. The fixed-rate debt
will mature June 15, 2007 and the floating-rate debt will mature December 31,
2000.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTAL DATA
Reference is made to the Index to Consolidated Financial Statements on
page 32 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. CHANGE IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURES
None
31
<PAGE>
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Page
----
Report of Independent Public Accountants......................................33
Consolidated Balance Sheets as of December 31, 1998 and 1997..................34
Consolidated Statements of Operations
for the years ended December 31, 1998, 1997 and 1996.....................35
Consolidated Statements of Changes in Stockholders' Equity
for the years ended December 31, 1998, 1997 and 1996.....................36
Consolidated Statements of Cash Flows
for the years ended December 31, 1998, 1997 and 1996.....................38
Notes to Consolidated Financial Statements....................................39
32
<PAGE>
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
TO THE STOCKHOLDERS OF SNYDER OIL CORPORATION:
We have audited the accompanying consolidated balance sheets of Snyder
Oil Corporation (a Delaware corporation) and subsidiaries as of December 31,
1998 and 1997, 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, 1998. 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, 1998 and 1997, and the results
of their operations and their cash flows for each of the three years in the
period ended December 31, 1998, in conformity with generally accepted accounting
principles.
ARTHUR ANDERSEN LLP
Fort Worth, Texas,
February 10, 1999
33
<PAGE>
<TABLE>
SNYDER OIL CORPORATION
CONSOLIDATED BALANCE SHEETS
(In thousands)
<CAPTION>
December 31,
--------------------------------
1998 1997
---------- -----------
ASSETS
<S> <C> <C>
Current assets
Cash and equivalents $ 6,171 $ 89,443
Accounts receivable 27,572 21,521
Inventory and other 1,812 2,911
---------- -----------
35,555 113,875
---------- -----------
Investments 23,983 143,066
---------- -----------
Oil and gas properties, successful efforts method 542,331 410,973
Accumulated depletion, depreciation and amortization (189,348) (136,669)
----------- -----------
352,983 274,304
---------- -----------
Gas facilities and other 31,624 21,317
Accumulated depreciation and amortization (10,208) (6,474)
----------- -----------
21,416 14,843
---------- -----------
$ 433,937 $ 546,088
========== ===========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities
Accounts payable $ 21,399 $ 23,278
Accrued liabilities 51,869 34,271
---------- -----------
73,268 57,549
---------- -----------
Senior debt 39,001 1
Subordinated notes 173,787 173,635
Deferred taxes payable - 31,649
Other noncurrent liabilities 19,427 19,498
Stockholders' equity
Common stock, $.01 par, 75,000,000 shares authorized,
36,073,375 and 35,696,212 issued 361 357
Capital in excess of par value 238,736 234,118
Retained earnings 10,970 44,390
Common stock held in treasury, 2,708,808 and 2,366,891 shares at cost (46,207) (40,461)
Unrealized gain (loss) on investments (75,406) 25,352
----------- -----------
128,454 263,756
---------- -----------
$ 433,937 $ 546,088
========== ===========
The accompanying notes are an integral part of these statements.
</TABLE>
34
<PAGE>
<TABLE>
SNYDER OIL CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands except per share data)
<CAPTION>
Year Ended December 31,
--------------------------------------------
1998 1997 1996
----------- ----------- -----------
<S> <C> <C> <C>
Revenues
Oil and gas sales $ 133,204 $ 207,216 $ 189,327
Gas transportation, processing and marketing 4,624 7,004 17,655
Gains on sales of equity interests in investees - 32,800 69,343
Gains on sales of properties 3,267 8,708 8,786
---------- ----------- -----------
141,095 255,728 285,111
---------- ----------- -----------
Expenses
Direct operating 38,492 48,523 49,638
Cost of gas and transportation 3,348 6,692 15,020
Exploration 48,303 17,046 4,232
General and administrative 16,440 20,363 17,143
Financing costs, net 13,350 23,029 22,923
Other expense (income) (235) 935 (1,327)
(Gain) loss on sale of subsidiary interest - (5,437) 15,481
Depletion, depreciation and amortization 53,950 79,862 84,547
Property impairments 5,497 7,275 2,753
---------- ----------- -----------
Income (loss) before income taxes, minority interest
and extraordinary item (38,050) 57,440 74,701
---------- ----------- -----------
Provision (benefit) for income taxes
Current - 975 33
Deferred (13,317) 16,881 4,313
----------- ----------- -----------
(13,317) 17,856 4,346
----------- ----------- -----------
Minority interest in subsidiaries - 4,119 7,405
---------- ----------- -----------
Income (loss) before extraordinary item (24,733) 35,465 62,950
Extraordinary item - loss on early extinguishment of debt,
net of income tax benefit of $1,533 - 2,848 -
---------- ----------- -----------
Net income (loss) (24,733) 32,617 62,950
----------- ----------- -----------
Preferred dividends - 5,978 6,210
---------- ----------- -----------
Income (loss) applicable to common $ (24,733) $ 26,639 $ 56,740
=========== =========== ===========
Income (loss) per common share before extraordinary item $ (.74) $ .96 $ 1.81
========== =========== ===========
Net income (loss) per common share $ (.74) $ .87 $ 1.81
========== =========== ===========
Income (loss) per common share before extraordinary
item - assuming dilution $ (.74) $ .95 $ 1.72
========== =========== ===========
Net income (loss) per common share - assuming dilution $ (.74) $ .86 $ 1.72
========== =========== ===========
Weighted average shares outstanding 33,416 30,588 31,308
========== =========== ===========
The accompanying notes are an integral part of these statements.
</TABLE>
35
<PAGE>
<TABLE>
SNYDER OIL CORPORATION
CONSOLIDATED STATEMENTS OF CHANGES IN
STOCKHOLDERS' EQUITY
(In thousands)
Total Unrealized Common Capital in
Stockholders' Gains (Losses) Stock Held Retained Excess of Common Preferred
Equity on Investments in Treasury Earnings Par Value Stock Stock
------------ -------------- ----------- -------- --------- ------ ---------
<S> <C> <C> <C> <C> <C> <C> <C>
Balance, December 31, 1995 $235,368 $ 591 $ (2,457) $ (29,001) $ 265,911 $ 314 $ 10
Net income 62,950 - - 62,950 - - -
Other comprehensive income,
net of tax
Unrealized gain on investments 11,330 11,330 - - - - -
--------
Comprehensive income (1) 74,280
--------
Issuance of 267,000 shares for
common stock grants and
exercise of stock options 2,924 - (258) - 3,179 3 -
Issuance of 399,000 shares
of common 3,693 - - - 3,689 4 -
Repurchase of 640,000 shares
of common (7,044) - (795) - (6,243) (6) -
Repurchase of 1,000 shares
of preferred (142) - - - (142) - -
Dividends (14,411) - - (8,238) (6,173) - -
-------- -------- --------- --------- ----------- ------ ------
Balance, December 31, 1996 294,668 11,921 (3,510) 25,711 260,221 315 10
Net income 32,617 - - 32,617 - - -
Other comprehensive income,
net of tax
Unrealized gain on investments 13,431 13,431 - - - - -
---------
Comprehensive income (1) 46,048
---------
Issuance of 607,000 shares for
common stock grants and
exercise of stock options 2,957 - - - 2,951 6 -
Conversion of subordinated
notes into common shares 25 - - - 25 - -
Issuance of 530,000 shares held
in treasury 8,655 - 8,655 - - - -
Repurchase of 2,647,000 shares
of common (45,606) - (45,606) - - - -
Repurchase of 291,000 shares
of preferred (30,102) - - (1,049) (29,050) - (3)
Conversion of 743,000 shares of
preferred to 3,632,000 shares
of common - - - - (29) 36 (7)
Dividends (12,889) - - (12,889) - - -
-------- --------- --------- --------- --------- ------ ------
Balance, December 31, 1997 263,756 25,352 (40,461) 44,390 234,118 357 -
(Continued)
The accompanying notes are an integral part of these statements.
</TABLE>
36
<PAGE>
(Continued)
<TABLE>
<CAPTION>
SNYDER OIL CORPORATION
CONSOLIDATED STATEMENTS OF CHANGES IN
STOCKHOLDERS' EQUITY (CONTINUED)
(In thousands)
Total Unrealized Common Capital in
Stockholders' Gains (Losses) Stock Held Retained Excess of Common Preferred
Equity on Investments in Treasury Earnings Par Value Stock Stock
------------ -------------- ----------- -------- --------- ------ ---------
<S> <C> <C> <C> <C> <C> <C> <C>
Balance, December 31, 1997 263,756 25,352 (40,461) 44,390 234,118 357 -
Net loss (24,733) - - (24,733) - - -
Other comprehensive loss,
net of tax
Unrealized loss on investments (77,405) (77,405) - - - - -
Deferred tax valuation allowance (23,353) (23,353) - - - - -
--------
Comprehensive loss (1) (125,491)
--------
Issuance of 377,162 shares for
common stock grants and
exercise of stock options 4,622 - - - 4,618 4 -
Repurchase of 341,917 shares
of common (5,746) - (5,746) - - - -
Dividends (8,687) - - (8,687) - - -
-------- --------- --------- --------- --------- ------ -------
Balance, December 31, 1998 $128,454 $ (75,406) $ (46,207) $ 10,970 $ 238,736 $ 361 $ -
======== ========= ========= ========= ========= ====== =======
<FN>
(1) Represents total accumulated other comprehensive income or loss.
</FN>
The accompanying notes are an integral part of these statements.
</TABLE>
37
<PAGE>
<TABLE>
SNYDER OIL CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
<CAPTION>
(In thousands) Year Ended December 31,
----------------------------------------------
1998 1997 1996
------------ ----------- -----------
<S> <C> <C> <C>
Operating activities
Net income (loss) $ (24,733) $ 32,617 $ 62,950
Adjustments to reconcile net income (loss) to net
cash provided by operations
Amortization of deferred credits - - (1,052)
Gains on sales of investments - (32,800) (68,343)
Gains on sales of properties (3,267) (8,708) (8,786)
Exploration expense 48,303 17,046 4,232
Equity in (earnings) losses of unconsolidated subsidiaries - (760) (421)
(Gain) loss on sale of subsidiary interest - (5,437) 15,481
Depletion, depreciation and amortization 53,950 79,862 84,547
Property impairments 5,497 7,275 2,753
Amortization of discount 144 - -
Deferred taxes (13,318) 15,348 4,313
Minority interest - 4,119 7,405
Loss on early extinguishment of debt - 4,381 -
Changes in current and other assets and liabilities
Decrease (increase) in
Accounts receivable (4,598) 24,612 (15,869)
Inventory and other 452 426 5,175
Increase (decrease) in
Accounts payable (1,879) (8,688) 2,771
Accrued liabilities 16,386 (9,497) (316)
Other liabilities (1,778) 2,245 6,890
------------ ----------- ----------
Net cash provided by operations 75,159 122,041 101,730
----------- ----------- ----------
Investing activities
Acquisition, development and exploration (192,995) (135,901) (128,598)
Proceeds from sales of investments - 156,969 1,635
Outlays for investments - - (9,013)
Proceeds from sales of properties 4,728 10,740 73,620
----------- ----------- ----------
Net cash realized (used) by investing (188,267) 31,808 (62,356)
------------ ----------- ----------
Financing activities
Issuance of common 4,622 2,982 1,523
Issuance of subordinated notes - 168,261 -
Increase (decrease) in senior indebtedness 39,000 (89,775) (13,289)
Early extinguishment of convertible subordinated notes - (85,199) -
Dividends (8,687) (12,889) (14,411)
Deferred credits - - (120)
Redemption of preferred (5,099) (30,102) -
Repurchase of stock - (45,606) (7,186)
Repurchase of subordinated notes - - (5,232)
----------- ----------- ----------
Net cash realized (used) by financing 29,836 (92,328) (38,715)
----------- ----------- ----------
Increase (decrease) in cash (83,272) 61,521 659
Cash and equivalents, beginning of year 89,443 27,922 27,263
----------- ----------- ----------
Cash and equivalents, end of year $ 6,171 $ 89,443 $ 27,922
=========== =========== ==========
Noncash investing and financing activities
Acquisition via subsidiary stock issuance $ - $ - $ 115,067
Acquisition of properties recorded as senior debt - - 31,730
Exchange of subsidiary stock for stock of investee - 30,923 -
Acquisition of properties and stock via stock issuances - 8,655 3,693
Exchange of common stock to retire notes receivable 647 - -
The accompanying notes are an integral part of these statements.
</TABLE>
38
<PAGE>
SNYDER OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) ORGANIZATION AND NATURE OF BUSINESS
Snyder Oil Corporation ("Snyder") 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, Cairn Energy plc
("Cairn") and SOCO International plc ("SOCI plc"). The Company, a Delaware
corporation, is the successor to a company formed in 1978.
In October 1997, the Company sold its 74 percent 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.
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.
<TABLE>
<CAPTION>
Excluding Patina
(In thousands, except per share and production data) For the Year Ended December 31,
---------------------------------------------------
1998 1997 1996
------------ ----------- -----------
Unaudited Unaudited
<S> <C> <C> <C>
Revenues
Oil and gas sales $ 133,204 $ 133,851 $ 107,143
Other 7,891 48,512 95,784
----------- ----------- -----------
141,095 182,363 202,927
Expenses
Direct operating 38,492 35,016 35,118
Exploration 48,303 16,926 4,008
General and administrative 16,440 16,566 10,993
Financing costs, net 13,350 10,556 8,619
Depletion, depreciation and amortization 59,447 43,599 39,725
Other 3,113 10,143 32,930
----------- ----------- -----------
Income (loss) before taxes, minority interest and (38,050) 49,557 71,534
extraordinary item
Provision (benefit) for income taxes (13,317) 17,856 4,740
Minority interest - 616 4,866
Extraordinary item, net of tax - 2,848 -
----------- ----------- -----------
Net income (loss) $ (24,733) $ 28,237 $ 61,928
=========== =========== ===========
Net income (loss) per common share $ (.74) $ .73 $ 1.78
============ ============ ===========
Weighted average shares outstanding 33,416 30,588 31,308
=========== =========== ===========
Daily Production
Oil (Bbls) 5,231 5,617 6,000
Gas (Mcf) 153,982 113,361 87,139
</TABLE>
39
<PAGE>
(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 percent but less than
100 percent are fully consolidated, with the related minority interest being
deducted from subsidiary earnings and stockholders' equity. Affiliates in which
the Company owns between 20 percent and 50 percent are accounted for using the
equity method. Affiliates in which the Company owns less than 20 percent are
accounted for using the cost method. At December 31, 1998, affiliates accounted
for under the cost 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 1998,
the Company did not provide for any such impairments. 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 six Mcf to one 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
in 1998 and 1997, the Company provided for $5.5 million and $6.6 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 $933,000 during 1998, $2.4 million during 1997 and $2.5 million
during 1996. Of these amounts, $1.3 million in 1997 and $1.5 million in 1996
were recognized by Patina. These arrangements, without Patina, are expected to
continue through 2002.
40
<PAGE>
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, 1998 and
1997 were not significant.
Financial Instruments
The following table sets forth the book value and estimated fair values
of financial instruments:
<TABLE>
<CAPTION>
December 31, December 31,
1998 1997
---------------------- ----------------------
Book Fair Book Fair
Value Value Value Value
--------- --------- --------- --------
(In thousands)
<S> <C> <C> <C> <C>
Cash and equivalents $ 6,171 $ 6,171 $ 89,443 $ 89,443
Investments 23,983 23,983 143,066 143,066
Senior debt (39,001) (39,001) (1) (1)
Subordinated notes (173,787) (171,063) (173,635) (178,063)
Long-term commodity contracts - 576 - 7,318
</TABLE>
The book value of cash and equivalents approximates fair value because
of the short maturity of those instruments. See Note (3) for a discussion of the
Company's investments. The fair value of senior debt is presented at face value
given its floating rate structure. The fair value of the subordinated notes are
estimated based on their December 31, 1998 and 1997 closing market prices.
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, 1998, that volume
represented approximately 30 percent 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.
Comprehensive Income
Effective January 1, 1998, the Company adopted Statement of Financial
Accounting Standards No. 130 ("SFAS 130"), "Reporting Comprehensive Income,"
which establishes standards for reporting and display of comprehensive income
and its components in a full set of general purpose financial statements.
Comprehensive income includes net income and other comprehensive income, which
includes, but is not limited to, unrealized gains for marketable securities and
future contracts, foreign currency translation adjustments and minimum pension
liability adjustments. The accompanying consolidated financial statements for
the Company reflect other comprehensive income consisting of unrealized gains or
losses for marketable securities. SFAS 130 did not have any effect on the
Company's financial condition or operations.
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.
41
<PAGE>
(3) INVESTMENTS
The Company holds marketable securities of two foreign energy companies
accounted for using the cost method. The Company follows Statement of Financial
Accounting Standards No. 115 ("SFAS 115"), "Accounting for Certain Investments
in Debt and Equity Securities," which requires that such investments be adjusted
to their fair value with a corresponding increase or decrease to stockholders'
equity. The following table sets forth the book/fair values and carrying costs
of these investments (in thousands):
<TABLE>
<CAPTION>
December 31, 1998 December 31, 1997
---------------------------- ----------------------------
Book/Fair Carrying Book/Fair Carrying
Value Cost Value Cost
----------- ----------- ----------- -----------
<S> <C> <C> <C> <C>
Cairn $ 17,231 $ 73,140 $ 96,062 $ 73,140
SOCI plc 6,752 30,923 47,004 30,923
----------- ----------- ----------- -----------
$ 23,983 $ 104,063 $ 143,066 $ 104,063
=========== =========== =========== ===========
</TABLE>
Cairn
In November 1996, the Company exchanged its interest in Command
Petroleum Ltd. 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. In the first quarter of
1997, the Company sold 4.5 million shares at an average price of $8.81 per share
realizing $39.2 million in proceeds and resulting in a gain of $13.0 million. In
accordance with SFAS 115, at December 31, 1998, investments were decreased by
$55.9 million in gross unrealized holding losses, stockholders' equity was
decreased by $36.3 million and deferred taxes payable was decreased by $19.6
million. At December 31, 1997, investments were increased by $22.9 million in
gross unrealized holding gains, stockholders' equity was increased by $14.9
million and deferred taxes payable was increased by $8.0 million.
SOCI plc
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 projects in Russia, Mongolia and
Thailand, for 7.8 million shares (15.9 percent of the total) of SOCI plc. The
offering raised approximately $75.0 million of new equity capital for SOCI plc
to fund its ongoing projects. The Company recognized a gain of $19.8 million as
a result of this exchange and is restricted from selling its shares until May
1999. In accordance with SFAS 115, at December 31, 1998, investments were
decreased by $24.2 million in gross unrealized holding losses, stockholders'
equity was decreased by $15.7 million and deferred taxes payable was decreased
by $8.5 million. At December 31, 1997, investments were increased by $16.1
million in gross unrealized holding gains, stockholders' equity was increased by
$10.5 million and deferred taxes payable was increased by $5.6 million.
During 1999, the Company will continue to evaluate whether the decline
in market value of such investments is other than temporary.
Notes Receivable
The Company held notes receivable of $647,000 due from a director at
December 31, 1997, which originated in connection with an option to purchase ten
percent of the Company's international affiliates due April 10, 1998. In March
1998, the director tendered 31,000 shares of Company common stock with a market
value of $647,000 to retire such notes.
4) OIL AND GAS PROPERTIES AND GAS FACILITIES
The cost of oil and gas properties at December 31, 1998 and 1997
includes $17.2 million and $21.3 million, respectively, 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:
42
<PAGE>
<TABLE>
<CAPTION>
Consolidated
---------------------------------------------------
1998 1997 1996
----------- ------------ ------------
(In thousands)
<S> <C> <C> <C>
Proved acquisitions $ 16,186 $ 3,676 $ 273,088
Acreage acquisitions 7,481 5,609 24,589
Development 119,130 85,998 43,075
Exploration 48,303 17,338 4,588
Gas processing, transportation and other 10,653 3,425 3,612
----------- ------------ -----------
$ 201,753 $ 116,046 $ 348,952
=========== ============ ===========
</TABLE>
<TABLE>
<CAPTION>
Excluding Patina
---------------------------------
1997 1996
------------ ------------
(In thousands)
<S> <C> <C>
Proved acquisitions $ 3,338 $ 54,708
Acreage acquisitions 5,609 24,589
Development 74,676 34,774
Exploration 17,217 4,364
Gas processing, transportation and other 3,096 3,612
------------ -----------
$ 103,936 $ 122,047
============ ===========
</TABLE>
During 1998, the Company incurred $167.4 million on exploration and
development activities while placing 78 wells on production with 18 wells in
progress at year end. In the Gulf of Mexico, development activity included $33.9
million to complete the installation of a production platform at Main Pass 261,
three development wells, one recompletion and one development well in progress
at year end. Exploration activities included $19.1 million for four exploration
discoveries and $28.4 million for five unsuccessful tests. Additionally, $8.7
million was invested in 3-D seismic acquisition and evaluation.
The Company continued its successful drilling program in the Rockies.
Expenditures for 1998, totaled $52.8 million to place 65 development wells on
production with seven wells in progress at year end. One exploration well was
successful totaling $552,000 and two unsuccessful tests totaled $1.0 million.
Additional exploration expense of $2.3 million was incurred for 3-D seismic
acquisition and evaluation.
The Company spent $12.8 million in North Louisiana to place five
development wells on production with one development well and four exploratory
wells in progress at year end. One exploration well was unsuccessful totaling
$1.0 million. An additional $6.8 million of exploration expense was incurred for
the acquisition and evaluation of 3-D seismic in the area.
Acquisitions
During 1998, the Company spent $16.2 million to acquire producing
properties and $7.5 million on acreage purchases in and around the Company's
operating hubs. Of the producing property acquisitions, $5.4 million was
incurred to purchase an incremental interest in the Main Pass properties
operated by the Company in the Gulf of Mexico. The Company also spent $2.6
million in North Louisiana to purchase producing properties and a gas processing
facility and $8.0 million to purchase incremental interests in properties in the
Piceance Basin of western Colorado and the Washakie Basin of southern Wyoming.
The Company also completed a non-cash acquisition in the second quarter
of 1998. The Company acquired 75 percent of Amoco Production Company's ("Amoco")
interest in the Beaver Creek Unit and two associated gas plants in the Wind
River Basin in Wyoming in exchange for the Jonah Field portion of the Company's
properties in the Deep Green River Basin project in Wyoming. Under terms of the
agreement, Snyder also received Amoco's interest in the Deep Green River Basin
project outside the Jonah Field area and retained the deep rights in Jonah
beneath the Mesaverde horizon at about 12,250 feet.
43
<PAGE>
During the third quarter of 1998, the Company exchanged its interest in
the Cage Ranch Field in South Texas for CIG Exploration's interest in certain
producing and non-producing properties in the Washakie Basin of Wyoming. The
Company received approximately $1.5 million in cash as part of the exchange.
Proved acquisitions during 1996 included $218.4 million related to the
formation of Patina including the acquisition of Gerrity Oil & Gas Corporation.
In October 1997, the Company sold its interest in Patina for approximately
$127 million in cash and the elimination of approximately $170 million in
debt.
(5) INDEBTEDNESS
The following indebtedness was outstanding on the respective dates:
<TABLE>
<CAPTION>
December 31, December 31,
1998 1997
------------- ------------
(In thousands)
<S> <C> <C>
Subordinated notes $ 173,787 $ 173,635
Bank facility 39,001 1
----------- -----------
$ 212,788 $ 173,636
=========== ===========
</TABLE>
Snyder maintains a revolving credit facility ("Snyder Facility") under
which credit availability is adjusted semiannually to reflect changes in
reserves and asset values. The borrowing base available under the facility was
$150.0 million at December 31, 1998. Borrowings under the facility generally
bear interest at prime, with an option to select LIBOR plus .75 percent or CD
plus .75 percent. The margin on LIBOR or CD increases to one percent when the
Company's consolidated senior debt becomes greater than 80 percent of its
consolidated tangible net worth, as defined. During 1998, the average interest
rate under the facility was 6.1 percent. 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 one to
one as defined and adjusted for unused portions of the Snyder Facility, 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
$175.0 million was available for the payment of dividends and other restricted
payments at December 31, 1998.
In June 1997, Snyder issued $175.0 million of 8.75 percent Senior
Subordinated Notes ("Notes") due June 15, 2007. The Notes were sold at a
discount resulting in an 8.875 percent 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 percent of principal, and at prices declining to
100 percent of principal on or after June 15, 2005. Upon the occurrence of a
change of control, as defined in the Notes, Snyder would be obligated to make an
offer to purchase all outstanding Notes at a price of 101 percent of the
principal amount thereof. In addition, Snyder 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 percent of the principal amount thereof. The proposed merger with Santa Fe
Energy Resources, Inc. described in Note (11) does not obligate the Company to
make any offer to repurchase the Notes. The Notes are unsecured general
obligations of Snyder and are subordinated to the Snyder Facility and to any
existing and future indebtedness of Snyder's subsidiaries. The Notes contain
covenants that, among other things, limit the ability of Snyder 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 $70.0 million was
available for the payment of dividends and other restricted payments at December
31, 1998. The Company's international subsidiaries are considered unrestricted
subsidiaries. As such, their activities and the proceeds realized from any
disposition of these interests are not restricted by the Note covenants.
44
<PAGE>
In 1994, Snyder issued $86.3 million of seven percent convertible
subordinated notes due May 15, 2001. The notes were redeemed by the Company in
June 1997 at 103.51 percent 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.
Maturities of indebtedness for the next five years are $39.0 million in
2000, with no amounts due in 1999, 2001, 2002 or 2003. The long-term portion of
the Snyder Facility is scheduled to expire December 31, 2000. However,
management has the ability and intent to renew both the short-term and long-term
facilities and extend their maturities on a regular basis.
Consolidated cash payments for interest were $15.5 million, $28.6
million and $21.9 million, respectively, for 1998, 1997 and 1996.
(6) FEDERAL INCOME TAXES
At December 31, 1998, 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 1998, 1997 and 1996 follows:
<TABLE>
<CAPTION>
1998 1997 1996
--------- --------- ---------
<S> <C> <C> <C>
Federal statutory rate 35% 35% 35%
Net change in valuation allowance - (3%) (29%)
Tax effect of cumulative earnings of subsidiary - 1% -
--------- --------- --------
Effective income tax rate 35% 33% 6%
========= ========= ========
</TABLE>
For book purposes, the components of the net deferred tax asset and
liability at December 31, 1998 and 1997, respectively, were:
<TABLE>
<CAPTION>
1998 1997
----------- -----------
(In thousands)
<S> <C> <C>
Deferred tax assets
NOL and capital loss carryforwards $ 35,769 $ 27,307
AMT credit carryforwards 1,181 1,401
Production payment receivables 3,950 5,557
Reserves and other 6,733 6,031
Unrealized investment losses 654 -
----------- -----------
48,287 40,296
----------- -----------
Deferred tax liabilities
Depreciable and depletable property (24,934) (30,964)
Investments and other - (25,884)
Unrealized investment gains (losses) - (15,097)
----------- -----------
(24,934) (71,945)
----------- -----------
Deferred tax asset (liability) 23,353 (31,649)
Valuation allowance (23,353) -
----------- -----------
Net deferred tax liability $ - $ (31,649)
=========== ===========
</TABLE>
The Company had regular net operating loss carryforwards of $102.0
million at December 31, 1998. The majority of these carryforwards expire between
2007 and 2010 with a minimal amount expiring between 2000 and 2005. At December
31, 1998, the Company also had alternative minimum tax credit carryforwards of
$1.2 million which are available indefinitely. Cash payments for income taxes
were $500,000 in 1998 and 1997. No cash payments were made for income taxes in
1996.
The valuation allowance noted above relates to the tax effect of the
unrealized loss on marketable securities included in stockholder's equity.
45
<PAGE>
(7) STOCKHOLDERS' EQUITY
A total of 75 million common shares, $.01 par value, are authorized of
which 36.1 million were issued and 33.4 million were outstanding at December 31,
1998. In 1998, the Company issued 377,162 shares primarily for the exercise of
stock options and repurchased 341,917 shares of common stock for $5.7 million.
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 ten percent 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 1998 and 1997. 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.
A total of 10 million preferred shares, $.01 par value, have been
authorized none of which are oustanding at December 31, 1998. In 1993, 4.1
million depositary shares (each representing a quarter interest in a share of
$100 liquidation value stock) of six percent 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
percent 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 six percent 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 tables illustrate the calculation of earnings per share for
income from continuing operations.
46
<PAGE>
<TABLE>
<CAPTION>
(In thousands except per share data)
Income Shares Per-Share
----------- ----------- ----------
For the Year Ended December 31, 1998
------------------------------------
<S> <C> <C> <C>
Loss applicable to common shareholders $ (24,733) 33,416 $ (.74)
=========== =========== ==========
For the Year Ended December 31, 1997
------------------------------------
Income before extraordinary item $ 35,465
Preferred dividends (5,978)
-----------
Income before extraordinary item
available to common shareholders $ 29,487 30,588 $ .96
EFFECT OF DILUTIVE SECURITIES
Stock options 513
-----------
Income before extraordinary item
applicable to common-assuming dilution $ 29,487 31,101 $ .95
=========== =========== ===========
For the Year Ended December 31, 1996
------------------------------------
Income before extraordinary item $ 62,950
Preferred dividends (6,210)
------------
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 $ 62,950 36,513 $ 1.72
=========== =========== ===========
</TABLE>
As of December 31, 1998, the only potentially dilutive securities
outstanding were stock options that have yet to be exercised. The dilutive
effect of outstanding stock options would have been to increase the shares
outstanding by 213,000.
The Company maintains a stock option plan for certain employees
providing for the issuance of options at prices not less than fair market value.
Options to acquire up to three million shares of common stock may be outstanding
at any given time. The specific terms of grant and exercise are determined by a
committee of independent members of the Board. A stock grant and option plan is
also maintained by the Company whereby each nonemployee Director receives 500
common shares quarterly in payment of their annual retainer. It also provides
for 2,500 options to be granted annually to each nonemployee Director. The
majority of currently outstanding options vest over a three year period (30
percent, 60 percent, 100 percent) and expire five years from the date of grant.
At December 31, 1998, 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:
47
<PAGE>
<TABLE>
<CAPTION>
1998 1997 1996
--------- -------- ---------
<S> <C> <C> <C>
Net income (loss) As Reported $ (24,733) $ 32,617 $ 62,950
Pro forma $ (27,874) $ 29,260 $ 61,936
Net income (loss) per common As Reported $ (.74) $ .87 $ 1.81
share Pro forma $ (.83) $ .76 $ 1.78
</TABLE>
The fair value of each option grant is estimated on the date of grant
using the Black-Sholes option-pricing model with the following weighted-average
assumptions used for grants in 1998, 1997 and 1996, respectively: dividend yield
of 1.5 percent, 1.6 percent and 2.8 percent; expected volatility of 43 percent,
41 percent and 44 percent; risk-free interest rates of 5.4 percent, 6.1 percent
and 5.7 percent; 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, 1998, 1997 and 1996 and changes during the years ended on
those dates is presented below (shares are in thousands):
<TABLE>
<CAPTION>
1998 1997 1996
-------------------- ------------------- ---------------------
Weighted- Weighted- Weighted-
Average Average Average
Exercise Exercise Exercise
Shares Price Shares Price Shares Price
------ -------- ------ -------- ------ --------
<S> <C> <C> <C> <C> <C> <C>
Outstanding at beginning of year 2,327 $14.64 1,674 $12.72 1,711 $13.21
Granted 881 17.72 1,013 16.82 519 9.50
Exercised (363) 18.71 (295) 11.27 (255) 6.69
Forfeited (261) 15.74 (65) 14.88 (301) 14.71
------ ------ ------
Outstanding at end of year 2,584 15.86 2,327 14.64 1,674 12.72
====== ====== ======
Options exercisable at
year end 1,181 1,105 772
Weighted-average fair
value of options
granted during
the year $6.40 $5.96 $3.27
</TABLE>
The following table summarizes information about fixed stock options
outstanding at December 31, 1998:
<TABLE>
<CAPTION>
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 1998 (in years) Exercise Price 1998 Exercise Price
------------------- -------------- ---------------- -------------- --------------- --------------
<S> <C> <C> <C> <C> <C>
$ 6.00 to 9.75 317,000 2.4 $ 8.94 225,000 $ 8.75
10.63 to 14.25 428,000 2.1 13.73 374,000 13.85
16.06 to 17.31 802,000 3.4 16.25 290,000 16.16
17.69 to 18.40 705,000 3.1 17.81 230,000 18.07
18.63 to 23.81 332,000 3.9 20.13 62,000 19.99
-------------- ---------------
$ 6.00 to 23.81 2,584,000 3.0 $ 15.86 1,181,000 $ 14.59
------------- -------------
</TABLE>
48
<PAGE>
(8) DISCLOSURE OF SEGMENT FINANCIAL INFORMATION
Effective December 31, 1998, the Company adopted Statement of Financial
Accounting Standards No. 131, "Disclosures about Segments of an Enterprise and
Related Information," which requires disclosure of certain information about
operating segments and geographic areas of operation.
The Company operates in three geographic areas: the Gulf of Mexico, the
Rocky Mountains and northern Louisiana. All three areas are engaged in the
production, development, acquisition and exploration of oil and gas properties.
The accounting policies of the divisions are the same as those described in the
summary of significant accounting policies. The Company evaluates the
performance of its geographic segments based on profit or loss from operations
before income taxes and does not allocate financing costs. The Company's
divisions are managed separately because of the different strategies used in
developing and producing oil and gas properties in different geographic regions.
Revenues from one customer of the Rocky Mountain Division accounted for
32 percent of the Company's consolidated revenues, and revenues from one
customer of the Gulf of Mexico Division accounted for 33 percent of the
Company's consolidated revenues.
<TABLE>
<CAPTION>
December 31, 1998 Segment Disclosure
-----------------------------------------------------------
Gulf of Rocky Northern Total
Mexico Mountains Louisiana Segments
---------- ----------- ----------- -----------
<S> <C> <C> <C> <C>
Oil and gas revenues $ 63,421 $ 58,794 $ 4,657 $ 126,872
Other revenues 953 5,129 3,185 9,267
Depletion, depreciation and amortization 33,576 14,892 2,438 50,906
Property impairments 5,497 - - 5,497
Exploration expense 37,150 3,353 7,800 48,303
Segment profit/(loss) (23,023) 17,210 (3,059) (8,872)
Oil & gas properties and gas facilities, net 135,057 198,477 30,027 363,561
Capital expenditures 60,370 68,420 18,266 147,056
</TABLE>
<TABLE>
<CAPTION>
December 31, 1997 Segment Disclosure
-----------------------------------------------------------------
Gulf of Rocky Northern Total
Mexico Mountains Louisiana Patina Segments
---------- --------- --------- ---------- ----------
<S> <C> <C> <C> <C> <C>
Oil and gas revenues $ 62,080 $ 66,300 $ 4,588 $ 73,365 $ 206,333
Other revenues 5,265 9,555 3,624 679 19,123
Depletion, depreciation and amortization 24,377 15,426 1,664 36,263 77,730
Property impairments 2,150 5,125 - - 7,275
Exploration expense 12,470 2,191 2,264 121 17,046
Net financing costs - - - 12,473 12,473
Segment profit 17,679 20,759 1,651 7,883 47,972
Oil & gas properties and gas facilities, net 113,832 149,679 17,805 - 281,316
Capital expenditures 40,568 39,092 4,866 11,989 96,515
</TABLE>
49
<PAGE>
The following tables reconcile segment information to consolidated
totals:
<TABLE>
<CAPTION>
December 31,
--------------------------------
1998 1997
---------- -----------
<S> <C> <C>
Revenues
Total revenues for reportable segments $ 126,872 $ 206,333
Revenue from marketing agreements,
hedging and other 6,332 883
---------- -----------
Total consolidated revenues $ 133,204 $ 207,216
========== ===========
Profit or (loss)
Total segment profit/(loss) $ (8,872) $ 47,972
Other revenues 6,332 883
General and administrative expense (17,987) (15,716)
Net financing costs (13,350) (10,556)
Depletion, depreciation and amortization (3,044) (2,133)
Gains on sales of investments - 32,800
Gain on sale of subsidiary interest - 5,437
Other corporate expenses (1,129) (1,247)
---------- -----------
Income/(loss) before income taxes, minority
interest and extraordinary item $ (38,050) $ 57,440
========== ===========
Assets
Total assets for reportable segments $ 363,561 $ 281,316
Current assets 35,555 113,875
Investments 23,983 143,066
Other assets 10,838 7,831
---------- -----------
Total assets $ 433,937 $ 546,088
========== ===========
Capital expenditures
Total segment capital expenditures $ 147,056 $ 96,515
Corporate capital expenditures 6,394 2,193
---------- -----------
Total consolidated capital expenditures $ 153,450 $ 98,708
========== ===========
</TABLE>
(9) RECENTLY ISSUED STATEMENTS OF FINANCIAL ACCOUNTING STANDARDS
In June 1998, Statement of Financial Accounting Standards No. 133
("SFAS 133"), "Accounting for Derivative Instruments and Hedging Activities,"
was released. The statement establishes accounting and reporting standards for
derivative instruments and hedging activities. It requires that derivatives be
recognized as assets or liabilities and measured at their fair value. SFAS 133
will be adopted in 2000 and is not expected to have a material effect on the
Company's financial condition or operations.
(10) 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 percent of their compensation. The Board of Directors elected to
contribute an amount equal to at least seven percent of each employee's pretax
salary for the years ended December 31, 1998, 1997 and 1996 resulting in total
Company contributions of $942,000, $766,000 and $1.2 million, respectively.
50
<PAGE>
(11) SUBSEQUENT EVENTS
On January 13, 1999, the Company announced its agreement to merge with
Santa Fe Energy Resources, Inc. ("Santa Fe") creating Santa Fe Snyder
Corporation. The Board of Directors of each company has unanimously approved the
transaction and committed to vote his or her shares in favor of the merger.
Snyder shareholders will receive 2.05 shares of Santa Fe common stock for each
share of Snyder resulting in Snyder shareholders owning approximately 40 percent
of the outstanding shares after the merger. It is expected that the transaction
will be accounted for as a purchase. John C. Snyder will be the Chairman of
Santa Fe Snyder Corporation and James L. Payne, currently the Chairman and CEO
of Santa Fe, will be the CEO of the new company. The eleven person board will be
composed of five members from Snyder's current directors and six from Santa Fe.
The Form S-4 has been filed with the SEC and, pending shareholder and other
required approvals, the merger is expected to be completed in the second quarter
of 1999.
In January 1999 the Company sold its interest in the Piceance Basin and
the associated gathering facility for $28.8 million cash, resulting in an
estimated gain of approximately $500,000.
(12) GUARANTOR CONDENSED CONSOLIDATING FINANCIAL INFORMATION
Pursuant to the Notes, all of the Company's subsidiaries except SOCO
International, Inc. (the "Unrestricted Subsidiary") would be guarantors of the
Notes (the "Restricted Group"). The condensed consolidating financial
information below shows the impact of the guarantors and the Unrestricted
Subsidiary to the Company's consolidated position as of and for the year ended
December 31, 1998. In the aggregate, the Unrestricted Subsidiary holds less than
ten percent of the total assets and revenues included in the consolidated
totals.
<TABLE>
<CAPTION>
CONDENSED CONSOLIDATING BALANCE SHEETS
December 31, 1998
(In thousands)
Restricted Unrestricted
Group Subsidiary Consolidated
----------- ------------ ------------
<S> <C> <C> <C>
Current assets $ 31,183 $ 4,372 $ 35,555
Investments 1 23,982 23,983
Oil and gas properties, net 352,983 - 352,983
Gas facilities and other, net 21,416 - 21,416
----------- ----------- -----------
Total assets $ 405,583 $ 28,354 $ 433,937
=========== =========== ===========
Current liabilities $ 73,268 $ - $ 73,268
Senior debt 39,001 - 39,001
Subordinated notes 173,787 - 173,787
Deferred taxes payable (5,802) 5,802 -
Other noncurrent liabilities 19,427 - 19,427
Total stockholders' equity 105,902 22,552 128,454
----------- ----------- -----------
Liabilities and stockholders'
equity $ 405,583 $ 28,354 $ 433,937
=========== =========== ===========
</TABLE>
51
<PAGE>
<TABLE>
<CAPTION>
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
Year Ended December 31, 1998
(In thousands)
Restricted Unrestricted
Group Subsidiary Consolidated
---------- ------------ ------------
<S> <C> <C> <C>
Revenues $ 141,082 $ 13 $ 141,095
Expenses 179,143 2 179,145
---------- ---------- -----------
Income (loss) before taxes, minority interest
and extraordinary item (38,061) 11 (38,050)
Income taxes 13,317 - 13,317
----------- ----------- -----------
Net income (loss) $ (24,744) $ 11 $ (24,733)
=========== =========== ===========
</TABLE>
(13) COMMITMENTS AND CONTINGENCIES
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
percent. The complaint alleges, among other things, that the defendants have
failed to pay proper royalties under the lease, have unlawfully commingled
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
$175.0 million. The Company and the other interest owners have filed an answer
denying the claims and intend to contest the suit vigorously. Activity in the
case has been stayed pending resolution of a variety of administrative motions
in the matter.
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.
On January 15, 1999, a stockholder of the Company filed a putative
class action complaint in the Delaware Court of Chancery, No. 16900-NC, seeking
to enjoin the merger of the Company into Santa Fe Energy Resources, Inc. on the
proposed terms and seeking damages. Defendants named in the complaint are the
Company, each of its directors and Santa Fe. The plaintiff alleges numerous
breaches of the duties of care and loyalty owed by the Company and its directors
to the purported class in connection with entering into the merger agreement
with Santa Fe. The plaintiff further alleges that Santa Fe aided and abetted the
Company and its directors in their alleged breaches of fiduciary duty. The
defendants believe the complaint is without merit and intend to vigorously
defend the action.
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.
The Company has firm transportation commitments in the Gulf of Mexico
which may exceed the Company's production capacity in the area over the next
several years. The Company may incur demand charges in the $1.0 million range
for the unused transportation commitments, however, the amount of production
shortfall, if any, is subject to prices, weather, timing of operations and
availablity of equipment and services.
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
52
<PAGE>
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.
(14) UNAUDITED SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION
Independent petroleum consultants directly evaluated 84 percent, 87
percent, and 99 percent of proved reserves at December 31, 1998, 1997 and 1996,
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.
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, and the second set of tables shows
consolidated Company totals. Subsequent to year end the Company sold its
interest in the Piceance Basin which represented 8,443 MBOE of proved reserves
at December 31, 1998.
53
<PAGE>
<TABLE>
<CAPTION>
Excluding Patina
-----------------------------
Quantities of Proved Reserves - Crude Oil Natural Gas
--------- -----------
(MBbl) (MMcf)
<S> <C> <C>
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
--------- -----------
Revisions (211) (5,066)
Extensions, discoveries and additions 3,171 148,378
Production (1,909) (56,186)
Purchases 1,124 90,686
Sales (393) (50,227)
---------- ------------
Balance, December 31, 1998 18,542 490,753
========= ===========
</TABLE>
<TABLE>
<CAPTION>
Proved Developed Reserves - Crude Oil Natural Gas
--------- -----------
(MBbl) (MMcf)
<S> <C> <C>
December 31, 1996 16,070 200,664
========= ===========
December 31, 1997 16,101 297,490
========= ===========
December 31, 1998 17,383 391,951
========= ===========
</TABLE>
<TABLE>
<CAPTION>
Excluding Patina
------------------------------
Changes in Standardized Measure - Year Ended December 31,
-------------------------------
1998 1997
----------- ------------
(In thousands)
<S> <C> <C>
Standardized measure, beginning of year $ 291,818 $ 438,656
Revisions:
Prices and costs (79,926) (284,824)
Quantities 22,173 2,676
Development costs (1,822) (9,241)
Accretion of discount 37,527 43,866
Income taxes 40,006 70,050
Production rates and other (28,541) (31,871)
------------ ------------
Net revisions (10,583) (209,344)
Extensions, discoveries and additions 85,899 142,209
Production (104,767) (104,465)
Future development costs incurred 31,098 21,250
Purchases 65,919 2,374
Sales (37,215) 1,138
------------ ------------
Standardized measure, end of year $ 322,169 $ 291,818
=========== ============
</TABLE>
54
<PAGE>
<TABLE>
<CAPTION>
Consolidated
---------------------------
Quantities of Proved Reserves - Crude Oil Natural Gas
--------- -----------
(MBbl) (MMcf)
<S> <C> <C>
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
Revisions (211) (5,066)
Extensions, discoveries and additions 3,171 148,378
Production (1,909) (56,186)
Purchases 1,124 90,686
Sales (393) (50,227)
------------ ------------
Balance, December 31, 1998 18,542 490,753
=========== ===========
</TABLE>
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.
<TABLE>
<CAPTION>
Consolidated
-----------------------------
Proved Developed Reserves - Crude Oil Natural Gas
----------- -----------
(MBbl) (MMcf)
<S> <C> <C>
December 31, 1995 21,637 330,524
=========== ===========
December 31, 1996 31,869 443,441
=========== ===========
December 31, 1997 16,101 297,490
=========== ===========
December 31, 1998 17,383 391,951
=========== ===========
</TABLE>
55
<PAGE>
<TABLE>
<CAPTION>
Consolidated
------------------------------
Standardized Measure - December 31,
------------------------------
1998 1997
----------- -----------
(In thousands)
<S> <C> <C>
Future cash inflows $ 1,127,778 $ 1,016,597
Future costs:
Production (385,866) (339,147)
Development (78,424) (64,237)
------------ -----------
Future net cash flows 663,488 613,213
Undiscounted income taxes (106,132) (148,049)
------------ -----------
After tax net cash flows 557,356 465,164
10 percent discount factor (235,187) (173,346)
------------ -----------
Standardized measure $ 322,169 $ 291,818
=========== ===========
</TABLE>
<TABLE>
<CAPTION>
Consolidated
--------------------------------------------------
Changes in Standardized Measure - Year Ended December 31,
--------------------------------------------------
1998 1997 1996
------------ ----------- ------------
(In thousands)
<S> <C> <C> <C>
Standardized measure, beginning of year $ 291,818 $ 938,592 $ 331,106
Revisions:
Prices and costs (79,926) (609,467) 528,525
Quantities 22,173 2,676 10,915
Development costs (1,822) (9,241) (13,027)
Accretion of discount 37,527 81,361 (a) 46,045 (b)
Income taxes 40,006 230,075 (242,536)
Production rates and other (28,541) (31,871) 11,052
------------ ----------- -----------
Net revisions (10,583) (336,467) 340,974
Extensions, discoveries and additions 85,899 142,209 111,797
Production (104,767) (164,330) (146,257)
Future development costs incurred 31,098 21,250 18,400
Purchases 65,919 2,374 330,225 (b)
Sales (37,215) (311,810) (a) (47,653)
------------ ----------- -----------
Standardized measure, end of year $ 322,169 $ 291,818 $ 938,592
=========== =========== ===========
<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 Gerrity Oil & Gas Corporation.
</FN>
</TABLE>
56
<PAGE>
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K.
(a) 1. Reference is made to Item 8 on page 31.
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 percent 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
Registrant 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 - Amendment Number 1 to Rights Agreement, dated as of January
13, 1999, between the Registrant and ChaseMellon Shareholder
Services, L.L.C., as Rights Agent. *
57
<PAGE>
4.4 - 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).
10.1 - Agreement and Plan of Merger, dated January 13, 1999, between
Registrant and Santa Fe Energy Resources Inc. -- incorporated
by reference from Exhibit 2.1 to Santa Fe Energy Resources,
Inc.'s Registration Statement on Form S-4 (Registration No.
333-71595).
10.2 - 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).
10.2.1 - 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).
10.3 - Registrant's Amended and Restated 1989 Stock Option Plan.
10.4 - Registrant's Deferred Compensation Plan for Select
Employees, adopted effective June 1, 1994, as amended.
10.5 - 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).
10.6 - 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).
10.7 - 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).
10.8 - 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).
10.9 - 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).
10.10 - 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).
10.10.1 - 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).
10.10.2 - 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).
58
<PAGE>
10.10.3 - Exchange Agreement dated July 10, 1997 between SOCO
International, Inc. and Edward T. Story, Jr.
10.11 - 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).
10.12 - Fifth Restated Credit Agreement dated as of June 30, 1994
among the Registrant and the banks party thereto --
incorporated by reference from Exhibit 10.11 to the
Registrant's Quarterly Report on Form 10-Q for the
quarter-ended June 30, 1994 (File No. 1-10509).
10.12.1 - 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).
10.12.2 - 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).
10.12.3 - 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).
10.12.4 - 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).
10.12.5 - 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).
10.12.6 - 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).
10.12.7 - Seventh Amendment dated as of October 13, 1997 to Fifth
Restated Credit Agreement.
10.12.8 - Eighth Amendment dated as of November 1, 1998 to Fifth
Restated Credit Agreement. *
10.13 - Directors Deferral Plan for Independent Directors of the
Registrant.
10.14 - 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).
10.15 - Employment Agreement effective as of May 2, 1997 between
Registrant 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).
10.16 - Indemnification Agreement dated as of May 2, 1997 between
Registrant 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).
59
<PAGE>
10.17 - Severance Agreement dated as of April 17, 1997 between
Registrant 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).
10.18 - Advisory Agreement entered into effective as of May 1, 1997
between Registrant 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).
12 - Computation of Ratio of Earnings to Fixed Charges and Ratio
of Earnings to Combined Fixed Charges and Preferred Stock
Dividends. *
22.1 - Subsidiaries of the Registrant. *
23.1 - Consent of Arthur Andersen LLP. *
23.2 - Consent of Netherland, Sewell & Associates, Inc.*
27 - Financial Data Schedule.*
99.1 - Reserve letter from Netherland, Sewell & Associates, Inc.
dated February 3, 1999 to the Registrant interest as of
December 31, 1998*
(b) Current reports on Form 8-K filed during the quarter ended December
31, 1998.
* Filed herewith.
60
<PAGE>
SIGNATURE
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed on
its behalf by the undersigned thereunto duly authorized.
/s/ John C. Snyder February 26, 1999
- ------------------------ Director and Chairman of the Board
John C. Snyder (Principal Executive Officer)
/s/ William G. Hargett February 26, 1999
- ------------------------ Director, President and Chief
William G. Hargett Operating Officer
/s/ Roger W. Brittain February 26, 1999
- ------------------------ Director
Roger W. Brittain
/s/ John A. Hill February 26, 1999
- ------------------------ Director
John A. Hill
/s/ William J. Johnson February 26, 1999
- ------------------------ Director
William J. Johnson
/s/ B. J. Kellenberger February 26, 1999
- ------------------------ Director
B. J. Kellenberger
/s/ Harold R. Logan, Jr. February 26, 1999
- ------------------------ Director
Harold R. Logan, Jr.
/s/ James E. McCormick February 26, 1999
- ------------------------ Director
James E. McCormick
/s/ Edward T. Story February 26, 1999
- ------------------------ Director
Edward T. Story
/s/ Mark A. Jackson February 26, 1999
- ------------------------ Senior Vice President and Chief
Mark A. Jackson Financial Officer (Principal Financial
and Accounting Officer)
61
EXHIBIT 4.3
AMENDMENT NO. 1 TO
THE RIGHTS AGREEMENT
This Amendment No. 1 to the Rights Agreement (this "Amendment"), dated
as of January 13, 1999, is an amendment to the Rights Agreement, dated as of May
27, 1997 (the "Rights Agreement"), between Snyder Oil Corporation, a Delaware
corporation (the "Company"), and ChaseMellon Shareholder Services, L.L.C., as
Rights Agent (the "Rights Agent").
WHEREAS, the Company proposes to enter into an Agreement and Plan of
Merger (the "Merger Agreement") dated as of the date hereof with Santa Fe Energy
Resources, Inc., a Delaware corporation ("Santa Fe"), pursuant to which the
Company will merge with and into Santa Fe on the terms set forth therein (the
"Merger"); and
WHEREAS, pursuant to and in compliance with Section 29 of the Rights
Agreement, the Company and the Rights Agent desire to amend the Rights Agreement
as set forth in this Amendment;
NOW THEREFORE, in consideration of the premises and the mutual
agreements herein set forth, the parties hereto agree as follows:
Section 1. AMENDMENTS.
(a) The first sentence of the Rights Agreement is hereby amended by
inserting after "May 27, 1997" the phrase ", as amended as of January 13, 1999."
(b) Section 1 of the Rights Agreement is hereby amended by adding a new
last sentence to the definition of "Acquiring Person" so that the last sentence
of the definition of "Acquiring Person" shall read in its entirety as follows:
"In addition, notwithstanding the foregoing, Santa Fe Energy
Resources, Inc., a Delaware corporation ("Santa Fe"), shall
not be deemed to be an "Acquiring Person" for purposes of
this Agreement."
(c) Section 3(d) of the Rights Agreement is hereby amended by
inserting after "May 27, 1997" in line 4 of the legend set forth therein the
phrase ", as amended as of January 13, 1999."
(d) Section 14 of the Rights Agreement is hereby amended by adding the
following paragraph to the end of Section 14 so that the last paragraph of
Section 14 shall read in its entirety as follows:
"Notwithstanding any other provision of this Agreement,
neither of the following events shall constitute an
occurrence of the events referred to in Section 14(a)(i),
(ii) or (iii) hereof: (A) the announcement, approval,
execution or delivery of the Agreement and Plan of
Merger (the "Merger Agreement") dated as of January 13,
1999, between the Company and Santa Fe, and any amendments
thereto in accordance with its terms, pursuant to which
the Company will merge with and into Santa Fe on the terms
set forth therein (the "Merger") or (B) the consummation
of the Merger."
(e) The Rights Agreement is hereby amended by adding the following
Section 36 after Section 35 such that the last section of the Rights Agreement
shall read in its entirety as follows:
"Section 36. SANTA FE MERGER. Anything in this Agreement
to the contrary notwithstanding, the announcement,
approval, execution or delivery of the Merger Agreement
and the consummation of the transactions contemplated by
the Merger Agreement (including the Merger) shall not cause
Santa Fe or any Affiliates or Associates of Santa Fe to
be deemed an Acquiring Person or to give rise to a
Distribution Date, any event referred to in Section 12
hereof, any of the events referred to in Section 14 (a)(i),
(ii) or (iii) hereof or a Shares Acquisition Date."
(f) The Form of Right Certificate attached to the Rights Agreement as
Exhibit B is hereby amended by inserting after "May 27, 1997" in line 4 thereof
the phrase ", as amended as of January 13, 1999."
Section 2. REMAINDER OF AGREEMENT Not Affected. Except set forth in
Section 1 hereof, this Amendment shall not by implication or otherwise alter,
modify, amend or in any way affect any of the terms, conditions, obligations,
covenants or agreements contained in the Rights Agreement, all of which are
ratified and affirmed in all respects and shall continue in full force and
effect.
Section 3. AUTHORITY. Each party represents that such party has full
power and authority to enter into this Amendment, and that this Amendment
constitutes a legal, valid and binding obligation of such party, enforceable
against such party in accordance with its terms.
Section 4. COUNTERPARTS. This Amendment may be executed in any number
of counterparts and each of such counterparts shall for all purposes be deemed
to be an original, and all such counterparts shall together constitute but one
and the same instrument.
Section 5. GOVERNING LAW. This Amendment shall be governed by and
construed in accordance with the laws of the State of Delaware without regard to
principles of conflicts of laws.
IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be
duly executed and attested, all as of the day and year first above written.
ATTEST: SNYDER OIL CORPORATION
By: __________________________ By: ______________________________
Name: Name:
Title: Title:
ATTEST: CHASEMELLON SHAREHOLDER SERVICES, L.L.C.
As Rights Agent
By: __________________________ By: ______________________________
Name: Name:
Title: Title:
EXHIBIT 10.12.8
EIGHTH AMENDMENT TO FIFTH RESTATED CREDIT AGREEMENT
This Eighth Amendment to Fifth Restated Credit Agreement ("EIGHTH
AGREEMENT") is entered into as of the 1st day of November, 1998, by and among
Snyder Oil Corporation ("BORROWER"), NationsBank, N.A., successor by merger to
NationsBank of Texas, N.A., as Agent ("AGENT"), and NationsBank, N.A., successor
by merger to NationsBank of Texas, N.A. ("NATIONSBANK"), Bank One, Texas, N.A.
("BANK ONE"), Wells Fargo Bank, N.A. ("WELLS FARGO"), Chase Bank of Texas, N.A.,
formerly known as Texas Commerce Bank National Association ("TCB," together with
NationsBank, Bank One and Wells Fargo, collectively referred to herein as
"ORIGINAL BANKS") and Credit Lyonnais New York Branch, as Banks ("BANKS").
WITNESSETH:
WHEREAS, the Banks, Borrower and Agent are parties to that certain
Fifth Restated Credit Agreement dated as of June 30, 1994, as amended by that
certain (i) letter agreement by and among Borrower and the Original Banks dated
as of May 1, 1995, (ii) Second Amendment to Fifth Restated Credit Agreement by
and among Borrower, Agent and the Original Banks dated as of June 30, 1995,
(iii) Third Amendment to Fifth Restated Credit Agreement by and among Borrower,
Agent and the Original Banks dated as of November 1, 1995, (iv) Fourth Amendment
to Fifth Restated Credit Agreement by and among Borrower, Agent and Original
Banks dated as of April 4, 1996, (v) Fifth Amendment to Fifth Restated Agreement
by and among Borrower, Agent and the Original Banks dated as of November 1,
1996, (vi) Sixth Amendment to Fifth Restated Credit Agreement by and among
Borrower, Agent and Banks dated as of May 19, 1997, and (vii) Seventh Amendment
to Fifth Restated Credit Agreement by and among Borrower, Agent and Banks dated
as of October 13, 1997 (as amended, the "CREDIT AGREEMENT") (unless otherwise
defined herein, all terms used herein with their initial letter capitalized
shall have the meaning given such terms in the Credit Agreement); and
WHEREAS, pursuant to the Credit Agreement, the Banks have made certain
Loans to Borrower, and Agent has issued certain Letters of Credit on behalf of
Borrower; and
WHEREAS, Borrower has requested that certain provisions of the Credit
Agreement, including, without limitation, Section 10.3 and related definitions
be amended in certain respects; and
WHEREAS, Borrower has requested that Banks (i) establish a Total
Borrowing Base of $150,000,000 with $90,000,000 allocated to Facility A and
$60,000,000 allocated to Facility B effective November 1, 1998 and continuing
until the next Determination Date, and (ii) extend the Facility B Termination
Date to October 30, 1999; and
WHEREAS, subject to the terms and conditions herein contained, the
Banks have agreed to Borrower's request.
NOW THEREFORE, for and in consideration of the mutual covenants and
agreements herein contained and other good and valuable consideration, the
receipt and sufficiency of which are hereby acknowledged and confessed,
Borrower, Agent and Banks hereby agree as follows:
<PAGE>
SECTION 1 AMENDMENTS. Subject to the satisfaction of each condition
precedent set forth in Section 4 hereof and in reliance on the representations,
warranties, covenants and agreements contained in this Eighth Amendment, the
Credit Agreement shall be amended effective November 1, 1998 (the "EFFECTIVE
DATE") in the manner provided in this Section 1.
1.1 AMENDMENT TO DEFINITIONS. The definitions of "CONSOLIDATED CASH
FLOW" and "LOAN PAPERS" contained in Section 1.1 of the Credit Agreement shall
be amended to read in full as follows:
"Consolidated Cash Flow" means, with respect to Borrower for a
time period, consolidated net income of Borrower for such time period
as set forth in the financial statements delivered pursuant to SECTION
8.1 (a) exclusive of net gain or loss (after provision for Taxes) on
the sale of assets, other than production sold in the ordinary course
of business, during such time period, (b) exclusive of income
attributable to any Subsidiary which is an Exempt Subsidiary as of the
last day of such time period, except to the extent of dividends
actually received by Borrower or a Restricted Subsidiary from such
Exempt Subsidiary during such Period, (c) exclusive of income
attributable to assets which are not owned beneficially and of record
by Borrower or a Restricted Subsidiary as of the last day of such time
period, (d) plus or minus, as appropriate, changes in deferred Taxes
with respect to such time period, (e) plus depreciation, depletion,
amortization of principal and other non-cash charges for such time
period, and (f) plus exploration expenses deducted in determining
consolidated net income.
"Loan Papers" means this Agreement, the Letter Agreement, the
Second Amendment, the Third Amendment, the Fourth Amendment, the Fifth
Amendment, the Sixth Amendment, the Seventh Amendment, the Eighth
Amendment, the Notes, the Mortgages, the Restricted Subsidiary
Guarantees and all other certificates, documents or instruments
delivered in connection with this Agreement, as the foregoing may be
amended from time to time.
1.2 ADDITIONAL DEFINITIONS. Section 1.1 of the Credit
Agreement shall be amended to add the following definition to such Section:
"Eighth Amendment" means that certain Eighth Amendment to
Fifth Restated Credit Agreement dated as of November 1, 1998, by and
among Borrower, Agent and the Banks.
1.3 RATIO OF CONSOLIDATED TOTAL DEBT AND CONSOLIDATED SENIOR
DEBT TO CONSOLIDATED TANGIBLE NET WORTH OF BORROWER COVENANT. Section 10.3 of
the Credit Agreement shall be amended to read in full as follows:
<PAGE>
SECTION 10.3 RATIO OF CONSOLIDATED TOTAL DEBT AND
CONSOLIDATED SENIOR DEBT TO CONSOLIDATED TANGIBLE NET WORTH OF
BORROWER. Borrower will not permit its consolidated total Debt as of
the end of any fiscal quarter to exceed two hundred twenty-five percent
(225%) of its Consolidated Tangible Net Worth as of the end of such
fiscal quarter. Borrower will not permit its Consolidated Senior Debt
as of the end of any fiscal quarter to exceed one hundred twenty
percent (120%) of its Consolidated Tangible Net Worth as of the end of
such fiscal quarter.
SECTION 2 DETERMINATION OF BORROWING BASE. In accordance with SECTIONS
4.1 and 4.4 of the Credit Agreement, effective November 1, 1998 and continuing
until the next Determination Date, the Total Borrowing Base shall be
$150,000,000, allocated as follows: $90,000,000 to the Facility A Borrowing Base
and $60,000,000 allocated to the Facility B Borrowing Base.
SECTION 3 EXTENSION OF FACILITY B TERMINATION DATE. In accordance with
SECTION 2.9(b) of the Credit Agreement, the Facility B Termination Date is
hereby extended from April 30, 1999 to October 30, 1999.
SECTION 4 CONDITIONS PRECEDENT TO EFFECTIVENESS OF AMENDMENTS. The
amendments to the Credit Agreement contained in SECTION 1 of this Eighth
Amendment and the redetermination and allocation of the Total Borrowing Base and
extension of the Facility B Termination Date pursuant to Sections 2 and 3 of
this Eighth Amendment shall be effective only upon payment by Borrower to Agent
for the ratable benefit of the Banks of an amendment and borrowing base increase
fee in the amount of $75,000. If this condition has not been satisfied by the
Effective Date, this Eighth Amendment and all obligations of the Banks and Agent
contained herein shall, at the option of Majority Banks, terminate.
SECTION 5 REPRESENTATIONS AND WARRANTIES OF BORROWER. To induce the
Banks and Agent to enter into this Eighth Amendment, Borrower hereby represents
and warrants to Agent as follows:
5.1 REAFFIRMATION OF REPRESENTATIONS AND WARRANTIES. Each
representation and warranty of Borrower and each Restricted Subsidiary contained
in the Credit Agreement and the other Loan Papers is true and correct on the
date hereof and will be true and correct after giving effect to the amendments
set forth in SECTION 1 hereof.
5.2 DUE AUTHORIZATION; NO CONFLICTS. The execution, delivery
and performance by Borrower of this Eighth Amendment are within the Borrower's
corporate powers, have been duly authorized by necessary action, require no
action by or in request of, or filing with, any governmental body, agency or
official and do not violate or constitute a default under any provision of
applicable law or any Material Agreement binding upon Borrower or the
Subsidiaries of Borrower or result in the creation or imposition of any Lien
upon any of the assets of Borrower of the Subsidiaries of Borrower except
Permitted Encumbrances.
5.3 VALIDITY AND ENFORCEABILITY. This Eighth Amendment
constitutes the valid and binding obligation of Borrower enforceable in
accordance with its terms, except as (i) the enforceability thereof may be
limited by bankruptcy, insolvency or similar laws affecting creditor's rights
generally, and (ii) the availability of equitable remedies may be limited by
equitable principles of general application.
<PAGE>
SECTION 6 MISCELLANEOUS.
6.1 NO DEFENSES. Borrower hereby represents and warrants to
the Banks that there are no defenses to payment, counterclaims or rights of
set-off with respect to the Obligations existing on the date hereof.
6.2 REAFFIRMATION OF LOAN PAPERS; EXTENSION OF LIENS. Any and
all of the terms and provisions of the Credit Agreement and the Loan Papers
shall, except as amended and modified hereby, remain in full force and effect.
Borrower hereby extends the Liens securing the Obligations until the Obligations
have been paid in full, and agrees that the amendments and modifications herein
contained shall in no manner affect or impair the Obligations or the Liens
securing payment and performance thereof.
6.3 PARTIES IN INTEREST. All of the terms and provisions of
this Eighth Amendment shall bind and inure to the benefit of the parties hereto
and their respective successors and assigns.
6.4 LEGAL EXPENSES. Borrower hereby agrees to pay on demand
all reasonable fees and expenses of counsel to Agent incurred by Agent, in
connection with the preparation, negotiation and execution of this Eighth
Amendment and all related documents.
6.5 COUNTERPARTS. This Eighth Amendment may be executed in
counterparts, and all parties need not execute the same counterpart; however, no
party shall be bound by this Eighth Amendment until all parties have executed a
counterpart. Facsimiles shall be effective as originals.
6.6 COMPLETE AGREEMENT. THIS EIGHTH AMENDMENT, THE CREDIT
AGREEMENT AND THE OTHER LOAN PAPERS REPRESENT THE FINAL AGREEMENT BETWEEN THE
PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS OR
ORAL AGREEMENTS OF THE PARTIES. THERE ARE NO UNWRITTEN ORAL AGREEMENTS BETWEEN
THE PARTIES.
6.7 HEADINGS. The headings, captions and arrangements used in
this Eighth Amendment are, unless specified otherwise, for convenience only and
shall not be deemed to limit, amplify or modify the terms of this Eighth
Amendment, nor affect the meaning thereof.
<PAGE>
IN WITNESS WHEREOF, the parties hereto have caused this Eighth
Amendment to be duly executed by their respective authorized officers on the
date and year first above written.
BORROWER:
SNYDER OIL CORPORATION,
a Delaware corporation
By:
-------------------------------------
Name:
-----------------------------------
Title:
----------------------------------
AGENT:
NATIONSBANK, N.A.,
successor by merger to
NationsBank of Texas, N.A.
By:
-------------------------------------
J. Scott Fowler,
Vice President
BANKS:
NATIONSBANK, N.A.,
successor by merger to
NationsBank of Texas, N.A.
By:
-------------------------------------
J. Scott Fowler,
Vice President
CHASE BANK OF TEXAS, N.A.
By:
-------------------------------------
Name:
-----------------------------------
Title:
----------------------------------
<PAGE>
BANK ONE, TEXAS, N.A.
By:
-------------------------------------
Name:
-----------------------------------
Title:
----------------------------------
WELLS FARGO BANK, N.A.
By:
-------------------------------------
Name:
-----------------------------------
Title:
----------------------------------
CREDIT LYONNAIS NEW YORK BRANCH
By:
-------------------------------------
Name:
-----------------------------------
Title:
<TABLE>
SNYDER OIL CORPORATION
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
(Unaudited)
<CAPTION>
Year Ended December 31,
-------------------------------------------------------------------------
1998 1997 1996 1995 1994
----------- ------------- ------------ ------------ ------------
(In thousands, except share data)
<S> <C> <C> <C> <C> <C>
Income (loss) before taxes, minority
interest and extraordinary item $ (38,050) $ 57,440 $ 74,701 $ (40,604) $ 13,510
Interest expense 15,796 25,472 23,587 21,679 10,337
----------- ------------- ------------ ------------ ------------
Earnings before taxes, minority
interest, extraordinary item and
interest expense $ (22,254) $ 82,912 $ 98,288 $ (18,925) $ 23,847
=========== ============= ============ ============ ============
Interest expense $ 15,796 $ 25,472 $ 23,587 $ 21,679 $ 10,337
Preferred stock dividends of
majority owned subsidiary - 1,474 1,520 - -
----------- ------------- ------------ ------------ ------------
Total fixed charges $ 15,796 $ 26,946 $ 25,107 $ 21,679 $ 10,337
=========== ============= ============ ============ ============
Ratio of earnings to fixed charges N/A (2) 3.08 3.91 N/A (1) 2.31
=========== ============= ============ ============ ============
<FN>
(1) Earnings were inadequate to cover fixed charges by $40.6 million.
(2) Earnings were inadequate to cover fixed charges by $38.1 million.
</FN>
</TABLE>
<PAGE>
<TABLE>
EXHIBIT 12
SNYDER OIL CORPORATION
COMPUTATION OF RATIO OF EARNINGS TO
COMBINED FIXED CHARGES AND PREFERRED DIVIDENDS
(Unaudited)
<CAPTION>
Year Ended December 31,
-------------------------------------------------------------------------
1998 1997 1996 1995 1994
----------- ------------- ------------ ------------ ------------
(In thousands, except share data)
<S> <C> <C> <C> <C> <C>
Income (loss) before taxes, minority
interest and extraordinary item $ (38,050) $ 57,440 $ 74,701 $ (40,604) $ 13,510
Interest expense 15,796 25,472 23,587 21,679 10,337
----------- ------------- ------------ ------------ ------------
Earnings before taxes, minority
interest, extraordinary item and
interest expense $ (22,254) $ 82,912 $ 98,288 $ (18,925) $ 23,847
=========== ============= ============ ============ ============
Interest expense $ 15,796 $ 25,472 $ 23,587 $ 21,679 $ 10,337
Preferred stock dividends - 4,929 (1) 6,210 6,210 10,806
Adjustment to tax effect preferred
stock dividends - 2,428 429 - -
Preferred stock dividends of
majority owned subsidiary - 1,474 1,520 - -
----------- ------------- ------------ ------------ ------------
Total fixed charges $ 15,796 $ 34,303 $ 31,746 $ 27,889 $ 21,143
=========== ============= ============ ============ ============
Ratio of earnings
to combined fixed charges
and preferred dividends N/A (3) 2.42 3.10 N/A (2) 1.13
=========== ============= ============ ============ ============
<FN>
(1) Excludes redemption premium of $1.0 million.
(2) Earnings were inadequate to cover combined fixed charges and preferred dividends by $46.8 million.
(3) Earnings were inadequate to cover combined fixed charges by $38.1 million.
</FN>
</TABLE>
EXHIBIT 22.1
SNYDER OIL CORPORATION
Subsidaries
Mexican Flats Service Company, Inc.
Snyder Fluid Technologies, Inc.
Snyder Gas Marketing, Inc.
SOCO Gas Systems, Inc.
SOCO International, Inc.
SOCO International Holdings, Inc.
SOCO Louisiana Leasing, Inc.
SOCO Technologies, Inc.
Wyoming Gathering & Production
EXHIBIT 23.1
CONSENT OF INDEPENDENT ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation of our
report dated February 10, 1999 on the financial statements of Snyder Oil
Corporation included in this Form 10-K, into Snyder Oil Corporation's previously
filed Registration Statement File Nos. 33-34446, 33-45213, 33-54809, 33-64219,
333-09877 and 333-71595.
ARTHUR ANDERSEN LLP
Fort Worth, Texas,
February 10, 1999
EXHIBIT 23.2
CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS
As independent petroleum consultants, we hereby consent to the
incorporation of our Reports included in this Form 10-K into Snyder Oil
Corporation's Registration Statements Nos. 33-34446, 33-45213, 33-54809,
33-64219, 333-09877 and 333-71595.
NETHERLAND, SEWELL & ASSOCIATES, INC.
BY /s/ Clarence M. Netherland
---------------------------------
Clarence M. Netherland
President
Dallas, Texas
February 26, 1999
<TABLE> <S> <C>
<ARTICLE> 5
<MULTIPLIER> 1000
<CURRENCY> U.S. Dollars
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-START> JAN-1-1998
<PERIOD-END> DEC-31-1998
<EXCHANGE-RATE> 1
<CASH> 6,171
<SECURITIES> 0
<RECEIVABLES> 27,572
<ALLOWANCES> 0
<INVENTORY> 1,449
<CURRENT-ASSETS> 35,555
<PP&E> 568,642
<DEPRECIATION> 198,734
<TOTAL-ASSETS> 433,937
<CURRENT-LIABILITIES> 73,268
<BONDS> 212,788
0
0
<COMMON> 361
<OTHER-SE> 128,093
<TOTAL-LIABILITY-AND-EQUITY> 433,937
<SALES> 137,828
<TOTAL-REVENUES> 141,095
<CGS> 88,314
<TOTAL-COSTS> 117,727
<OTHER-EXPENSES> 48,068
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 13,350
<INCOME-PRETAX> (38,050)
<INCOME-TAX> (13,317)
<INCOME-CONTINUING> 0
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (24,733)
<EPS-PRIMARY> (.74)
<EPS-DILUTED> (.74)
</TABLE>
EXHIBIT 99.1
NSAll N E T H E R L A N D, S E W E L L CHAIRMAN-CLARENCE M.NETHERLAND
& A S S O C I A T E S. I N C. PRESIDENT- FREDERIC D.SEWELL
International Petroleum Consultants SENIOR VICE PRESIDENTS
Engineering, Geology, Geophysics DANNY D. SIMMONS -HOUSTON
THOMAS J. TELLA II - DALLAS
DAN PAUL SMITH - DALLAS
G. LANCE BINDER - DALLAS
PHILLIP A.LONGACRE - DALLAS
P. SCOTT FROST - DALLAS
C.H.(SCOTT) REES II - DALLAS
February 3, 1999
Snyder Oil Corporation
777 Main-Street, Suite 1400
Fort Worth, Texas 76102
Gentlemen:
In accordance with your request, we have estimated the proved reserves
and future revenue, as of December 31, 1998, to the Snyder Oil Corporation
(SOCO) interest in certain oil and gas properties located in Wyoming and in
state and federal waters offshore Gulf of Mexico as listed in the accompanying
tabulations. This report has been prepared using constant prices and costs and
conforms to the guidelines of the Securities and Exchange Commission (SEC).
As presented in the accompanying summary projections, Tables I through
IV, we estimate the net reserves and future net revenue to the SOCO interest, as
of December 31, 1998, to be:
<TABLE>
<CAPTION>
Net Reserves Future Net Revenue
------------------------------- -------------------------------------
Oil Gas Present Worth
Category (Barrels) (MCF) Total at 10%
- ------------------------ ----------- --------------- --------------- --------------
<S> <C> <C> <C> <C>
Proved Developed
Producing 2,109,898 262,025,911 $36O,693,600 $215,412,500
Non-Producing 1,447,711 43,168,301 70,520,100 44,911,100
Proved Undeveloped 875,798 67,846,732 67,919,400 25,100,100
--------- ------------ -------------- --------------
Total Proved 4,433,407 373,040,944 $499,133,100 $285,423,700
</TABLE>
The oil reserves shown include crude oil and condensate. Oil volumes
are expressed in barrels which are equivalent to 42 United States gallons. Gas
volumes are expressed in thousands of standard cubic feet (MCF) at the contract
temperature and pressure bases.
As shown in the Table of Contents, this report includes summary
projections of reserves and revenue by reserve category for all properties and
for each division. Summary projections of reserves and revenue by reserve
category along with one-line summaries of reserves, economics, and basic data by
lease are also included for each project behind the appropriate division tab.
For the purposes of this report, the term "lease" refers to a single economic
projection.
The estimated reserves and future revenue shown in this report are for
proved developed producing, proved developed non-producing, and proved
undeveloped reserves. In accordance with SEC guidelines, our estimates do not
include any value for probable or possible reserves which may exist for these
properties. This report does not include any value which could be attributed to
interests in undeveloped acreage beyond those tracts for which undeveloped
reserves have been estimated.
<PAGE>
Future gross revenue to the SOCO interest is prior to deducting state
production taxes and ad valorem taxes. Future net revenue is after deducting
these taxes, future capital costs, and operating expenses, but before
consideration of federal income taxes; future net revenue for the offshore
properties is also after deducting abandonment costs. In accordance with SEC
guidelines, the future net revenue has been discounted at an annual rate of 10
percent to determine its "present worth." The present worth is shown to indicate
the effect of time on the value of money and should not be construed as being
the fair market value of the properties.
For the purposes of this report, a field inspection of the properties
has not been performed nor has the mechanical operation or condition of the
wells and their related facilities been examined. We have not investigated
possible environmental liability related to the properties; therefore, our
estimates do not include any costs which may be incurred due to such possible
liability. Our estimates of future revenue do not include any salvage value for
the lease and well equipment nor the cost of abandoning the onshore properties.
Future revenue estimates for offshore properties include SOCO's estimates of the
net costs to abandon the wells, platforms, and production facilities; such net
costs include credit for recoverable salvage. We have reviewed SOCO's estimates
and consider them to be reasonable. Abandonment costs for offshore properties
are included with other capital investments.
Oil prices used in this report are based on a December 31, 1998 West
Texas Intermediate posted price of $9.50 per barrel, adjusted for regional
posted price differentials by zone for the Beaver Creek Project, by significant
property group for the Washakie Project, and by field for the offshore projects.
Gas prices used in this report are based on average December 1998 prices by zone
for the Beaver Creek Project, by pipeline for the Washakie Project, and by field
for the offshore projects. Oil and gas prices are held constant in accordance
with SEC guidelines.
Lease and well operating costs are based on operating expense records
of SOCO. For non-operated properties, these costs include the per-well overhead
expenses allowed under joint operating agreements along with costs estimated to
be incurred at and below the district and field levels. As requested, lease and
well operating costs for the operated properties include only direct lease and
field level costs. Headquarters general and administrative overhead expenses of
SOCO are not included. Lease and well operating costs are held constant in
accordance with SEC guidelines. Capital costs are included as required for
workovers, new development wells, and production equipment.
We have made no investigation of potential gas volume and value
imbalances which may have resulted from overdelivery or underdelivery to the
SOCO interest. Therefore, our estimates of reserves and future revenue do not
include adjustments for the settlement of any such imbalances; our projections
are based on SOCO receiving its net revenue interest share of estimated future
gross gas production.
The reserves included in this report are estimates only and should not
be construed as exact quantities. They may or may not be recovered; if
recovered, the revenues therefrom and the costs related thereto could be more or
less than the estimated amounts. The sales rates, prices received for the
reserves, and costs incurred in recovering such reserves may vary from
<PAGE>
assumptions included in this report due to governmental policies and
uncertainties of supply and demand. Also, estimates of reserves may increase or
decrease as a result of future operations.
In evaluating the information at our disposal concerning this report,
we have excluded from our consideration all matters as to which legal or
accounting, rather than engineering and geological, interpretation may be
controlling. As in all aspects of oil and gas evaluation, there are
uncertainties inherent in the interpretation of engineering and geological data;
therefore, our conclusions necessarily represent only informed professional
judgments.
The titles to the properties have not been examined by Netherland,
Sewell & Associates, Inc., nor has the actual degree or type of interest owned
been independently confirmed. The data used in our estimates were obtained from
Snyder Oil Corporation and the nonconfidential files of Netherland, Sewell &
Associates, Inc. and were accepted as accurate. We are independent petroleum
engineers, geologists, and geophysicists; we do not own an interest in these
properties and are not employed on a contingent basis. Basic geologic and field
performance data together with our engineering work sheets are maintained on
file in our office.
Very truly yours,
/s/ Frederic D. Sewell
RKG:EAD
