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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
_____________
FORM 10-K
ANNUAL REPORT
PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1999 Commission file number 0-5426
THE WISER OIL COMPANY
A DELAWARE CORPORATION
_____________
I.R.S. EMPLOYER IDENTIFICATION NO. 55-0522128
8115 PRESTON ROAD, SUITE 400
DALLAS, TEXAS 75225
TELEPHONE: (214) 265-0080
Securities registered pursuant to Section 12(b) of the Act:
Name of exchange on
Title of each class which registered
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Common Stock-Par Value, $3.00 Per Share New York Stock Exchange
Preferred Stock Purchase Rights New York Stock Exchange
Indicate by check mark whether registrant 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, and has been subject to such filing requirements for the
past 90 days. X.
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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. X.
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As of February 24, 2000, registrant had outstanding 8,951,965 shares of common
stock, $3.00 par value ("Common Stock"), which is registrant's only class of
common stock.
The aggregate market value of registrant's Common Stock held by non-affiliates
based on the closing price on February 24, 2000 was approximately $21.8 million.
DOCUMENTS INCORPORATED BY REFERENCE
(Specific incorporations are identified under the applicable item herein.)
Portions of the registrant's proxy statement furnished to stockholders in
connection with the 2000 Annual Meeting of Stockholders (the "Proxy Statement")
are incorporated by reference in Part III of this Report. The Proxy Statement
will be filed with the Securities and Exchange Commission within 120 days of the
close of the registrant's fiscal year.
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TABLE OF CONTENTS
DESCRIPTION
<TABLE>
<CAPTION>
Item Page
- ---- ----
<S> <C>
PART I
1. BUSINESS.............................................................. 3
2. PROPERTIES............................................................ 25
3. LEGAL PROCEEDINGS..................................................... 25
4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS................... 25
PART II
5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS............................................................. 26
6. SELECTED FINANCIAL DATA............................................... 27
7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS............................................... 29
8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA........................... 38
9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE................................................ 38
PART III
10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.................... 39
11. EXECUTIVE COMPENSATION................................................ 39
12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT.......................................................... 39
13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS........................ 39
PART IV
14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K....... 39
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THE WISER OIL COMPANY
PART I
Item 1. Business
General
Founded in 1905, The Wiser Oil Company (the "Company" or "Wiser") is one of the
oldest public independent oil and gas companies in the United States. The
Company's total proved reserves at December 31, 1999 are 37.1 MMBOE
(approximately 69% of which were oil and NGLs), and its annual net production in
1999 was 3.6 MMBOE. The Company's primary operations, representing approximately
62% of its proved reserves at December 31, 1999, are located in the Permian
Basin in West Texas and Southeast New Mexico. Wiser has additional
operations in Alberta, Canada and the San Juan Basin in New Mexico.
Prior to 1991 the Company focused primarily on the acquisition of non-operated
interests in oil and gas properties. In 1991 the Company moved its headquarters
from Sistersville, West Virginia to Dallas, Texas and began to assemble a team
of experienced management with substantial acquisition, exploitation and
development expertise. After reviewing the Company's existing property portfolio
and refining the new business strategy, the management team began disposing of
the Company's non-strategic assets and acquiring and operating properties in new
core areas with the potential for increased reserves and production volumes.
Pursuant to this strategy, the Company acquired and developed properties in the
Permian Basin and Canada, and added reserves and production through workovers,
recompletions, waterfloods and CO2 gas injections, as well as the drilling of
exploratory, development and infill wells.
A substantial portion of the Company's growth in reserves and production volumes
since 1991 has been the result of (i) two enhanced oil recovery projects on
properties acquired from 1992 to 1996 in the Permian Basin and (ii) the
Company's 1994 acquisition and subsequent exploration on and exploitation of
properties in Alberta, Canada. From June 1993 through December 1999, the Company
completed 168 producing wells on its Maljamar waterflood project in Southeast
New Mexico. As a result, the Company's average daily net production from the
three units in this project increased to 1,781 BOE in 1999 from 580 BOE in
January 1993 (on a pro forma combined basis, assuming the Company had acquired
all three units at January 1, 1993). At its Wellman Unit in West Texas, the
Company used CO2 gas injection to increase average daily net production to 1,078
BOE in 1999 from 650 BOE in December 1993. In June 1994 the Company acquired oil
and gas properties located primarily in Alberta, Canada for $52.0 million. From
the date of their acquisition through December 1999, the Company completed 60
net wells on these properties. As a result, the Company's average daily net
Canadian production increased to 3,184 BOE in 1999 from 1,860 BOE in June 1994.
The Company's principal executive offices are located at 8115 Preston Road,
Suite 400, Dallas, Texas 75225, and its telephone number is (214) 265-0080.
Certain oil and gas industry terms used herein are defined in the "Glossary of
Oil and Gas Terms" appearing at the end of this Item 1.
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Principal Oil and Gas Properties
The following table summarizes certain information with respect to each of the
Company's principal areas of operation at December 31, 1999.
<TABLE>
<CAPTION>
Proved Reserves
---------------------------------------
1999
Total Total Percent Average
Gross Oil Proved of Total Net
Oil and and NGLs Gas Reserves Proved Production
Gas Wells (MBbls) (MMcf) (MBOE) Reserves (BOE/Day)
----------- --------- ------- --------- --------- -----------
<S> <C> <C> <C> <C> <C> <C>
Permian Basin
Maljamar............. 208 10,377 2,937 10,867 29% 1,781
Wellman.............. 14 8,747 735 8,869 24% 1,078
Dimmitt/Slash Ranch.. 82 1,826 9,675 3,439 9% 894
----- ------ ------ ------ --- -----
Total.............. 304 20,950 13,347 23,175 62% 3,753
San Juan Basin......... 2,400 45 18,888 3,193 9% 1,129
Other (1).............. 114 501 13,928 2,822 8% 1,910
----- ------ ------ ------ --- -----
Total United States.... 2,818 21,496 46,163 29,190 79% 6,792
Canada................. 285 3,934 23,830 7,905 21% 3,184
----- ------ ------ ------ --- -----
Total Company.......... 3,103 25,430 69,993 37,095 100% 9,976
===== ====== ====== ====== === =====
</TABLE>
(1) Other 1999 Average Net Production includes production from properties that
were sold in the second quarter of 1999.
Permian Basin
Maljamar. The Company's Maljamar properties are situated in Southeast New
Mexico. At December 31, 1999, the Maljamar properties contained 10.9 MMBOE of
proved reserves, which represented 29% of the Company's total proved reserves
and 27% of the Company's Present Value of total proved reserves.
The Maljamar properties consist primarily of three oil producing units acquired
by the Company in separate transactions between 1992 and 1996: the Maljamar
Grayburg and Caprock Maljamar Units, both of which are in Lea County, New
Mexico, and the Skelly Unit in Eddy County, New Mexico. The Maljamar Grayburg
Unit produces from the Grayburg and San Andres formations at depths ranging from
3,800 to 4,500 feet, and the Caprock Maljamar Unit produces from the same
formations at depths ranging from 4,000 to 5,000 feet. The Skelly Unit is
located approximately five miles west of the two Lea County units and produces
from the Seven Rivers, Grayburg and San Andres formations at depths ranging from
2,100 to 4,000 feet. The Company has a 100% working interest in each of these
units, which, along with some smaller adjacent properties, have been combined
into a single large scale waterflood project encompassing approximately 14,000
[see acreage table on page 15] gross leasehold acres.
Exploitation efforts at the project are essentially complete and included
conversion of existing wells to injection wells and the drilling of infill
development wells on 20-acre spacing to create 40-acre five-spot water injection
patterns. From June 1, 1993 through December 31, 1999, the Company made capital
expenditures of approximately $75 million and completed 168 producing wells at
the project. At December 31, 1999, the project included 208 producing wells and
163 water injection wells, virtually all of which were operated by the Company.
No new wells were placed on production in 1999.
The Company's net production from the Maljamar properties averaged 1,624 Bbls of
oil, 45 Bbls of NGLs and 674 Mcf of natural gas per day in 1999. The Company's
cumulative net production from the Maljamar properties since acquired by the
Company has been 3,764 MBbls of oil and 1.9 Bcf of natural gas through December
31, 1999.
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Wellman Unit. In 1993 the Company acquired a 62% working interest in and became
operator of the Wellman Unit in Terry County, Texas, located in the northwestern
edge of the Horseshoe Atoll. During 1998 and 1999, the Company acquired an
additional 28% and 5% working interest, respectively, in the Wellman Unit which
increased the Company's working interest to 95% as of December 31, 1999. At
December 31, 1999, the Company's Wellman property contained 8.9 MMBOE of proved
reserves, which represented 24% of the Company's total proved reserves and 22%
of the Company's Present Value of total proved reserves.
The Company owns approximately 2,300 gross (2,150 net) leasehold acres in the
Wellman Unit. The Wellman Unit produces oil from the Wolfcamp Reef formation at
depths ranging from 9,100 to 10,000 feet through the injection of water and CO2
into the reservoir. Water injection at the unit began in 1979, and CO2 injection
began in 1983. The unit also includes a gas processing plant, which processes
wellhead gas produced from the unit. Wiser's interest in this plant is
proportionate to its working interest in the Wellman Unit. Processing at the
plant involves subjecting the wellhead gas to high pressure and low temperature
treatments that cause the gas to separate into various products, including NGLs,
residual natural gas and CO2. The NGLs and residual natural gas are sold to
pipeline companies, and the CO2 is reinjected into the unit's reservoir. At
December 31, 1999, the unit included 14 productive wells, two water injection
wells, three CO2 injection wells and three water disposal wells, all of which
were operated by the Company.
The Company's net production from the Wellman Unit averaged 672 Bbls of oil, 378
Bbls of NGLs and 166 Mcf of natural gas per day in 1999. The Company's
cumulative net production from the unit since acquired by the Company has been
2,046 MBbls of oil, 739 MBbls of NGLs and 482 MMcf of natural gas through
December 31, 1999.
In 1994 the Company began reconditioning the gas processing plant at the Wellman
Unit to enhance the extraction of NGLs and residual natural gas from the
wellhead gas. The Company completed the reconditioning project in June 1995 at a
total cost of approximately $6.0 million. For the year ended December 31, 1999,
the gas plant processed an average of 31 MMcf of gross natural gas and CO2 per
day and recovered an average of 452 Bbls of NGLs and 199 Mcf of residual natural
gas per day. The plant currently operates at 89% of its maximum capacity of 35
MMcf of gas per day.
Dimmitt/Slash Ranch Fields. The Company's Dimmitt/Slash Ranch properties are
situated in Loving County, Texas, 80 miles west of Midland, Texas. At December
31, 1999, the Dimmitt/Slash Ranch properties contained 3.4 MMBOE of proved
reserves, which represented 9% of the Company's total proved reserves and 9% of
the Company's Present Value of total proved reserves.
The Company owns approximately 4,650 gross (4,130 net) leasehold acres in the
Dimmitt Field, and has working interests in this acreage ranging from 75% to
100%. The Company acquired its initial interest in and became operator of the
field in 1993. The Dimmitt Field produces oil and gas from the Cherry Canyon and
Bell Canyon formations at depths ranging from 4,700 to 6,700 feet. At December
31, 1999, the field included 78 productive wells.
The Slash Ranch Field is a natural gas field that underlies the Dimmitt Field.
The Company owns approximately 2,850 gross (2,350 net) leasehold acres in the
Slash Ranch Field. The Slash Ranch Field produces from the Atoka, Fusselman and
Ellenburger formations at depths ranging from 15,000 to 20,000 feet. At December
31, 1999, the field included four producing wells, all of which were operated by
the Company. The Company's working interests in these wells range from 34% to
100%.
The Company's net production from the Dimmitt/Slash Ranch properties averaged
391 Bbls of oil and 3,020 Mcf of natural gas per day in 1999. The Company's
cumulative net production from the properties since acquired by the Company has
been 759 MBbls of oil and 6.1 Bcf of natural gas through December 31, 1999.
5
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San Juan Basin
The Company's San Juan Basin properties are located in Rio Arriba County in
northwestern New Mexico. At December 31, 1999, the San Juan Basin properties
contained 3.2 MMBOE of proved reserves, which represented 9% of the Company's
total proved reserves and 6% of the Company's Present Value of total proved
reserves. The Company owns approximately 11,000 gross (6,000 net) [see acreage
table on leasehold acres in the San Juan Basin. The Company's average 48%
working interest in most of the acreage was contributed in connection with a
unitization of the wells in the San Juan Basin fields in the 1950's, resulting
in the ownership by the Company of small non-operated working interests in
several large units. At December 31, 1999, the Company owned working interests
in approximately 2,400 producing gas wells in the San Juan Basin. These working
interests range from 0.26% to 50.0% and average approximately 1.8%. The
Company's San Juan Basin properties produce from multiple formations ranging
from depths of 3,000 feet to 8,000 feet.
The Company's net production from these properties averaged 6,370 Mcf of natural
gas and 67 Bbls of oil per day in 1999. During the year ended December 31, 1999,
approximately 26% of the Company's net production from these properties was from
the Fruitland Coal seams. Such production generates nonconventional fuels income
tax credits for Wiser under Section 29 of the Internal Revenue Code of 1986, as
amended. The Company expects that future development of the properties will
depend on natural gas prices, and that its share of the costs of any such future
development activities will not be significant.
Other U.S. Properties
The Company's other United States properties include properties located in the
West Texas, New Mexico and the Gulf Coast onshore region.
Canada
In June 1994, Wiser established an important new core area with the completion
of a $52.0 million acquisition of Canadian oil and gas properties from Eagle
Resources, Ltd. The purchase included 7.2 MMBOE of proved reserves,
approximately 127,000 net undeveloped acres, seven exploration prospects and an
existing staff of 23 persons. At December 31, 1999, the Company's Canadian
properties contained 7.9 MMBOE of proved reserves, which represented 21% of the
Company's total proved reserves and 28% of the Present Value of the Company's
total proved reserves.
The following table summarizes certain information with respect to each of the
Company's principal Canadian areas of operation at December 31, 1999:
<TABLE>
<CAPTION>
Proved Reserves
----------------------------------------
Percent 1999
Total Total of Total Average
Gross Oil Proved Canadian Net
Oil and and NGLs Gas Reserves Proved Production
Gas Wells (MBbls) (MMcf) (MBOE) Reserves (BOE/Day)
--------------- --------- ------- --------- --------- -----------
<S> <C> <C> <C> <C> <C> <C>
Evi........... 14 1,666 -- 1,666 21% 758
Provost....... 71 805 1,029 977 12% 547
Pine Creek.... 9 219 2,467 630 8% 174
Portage....... 14 -- 3,047 508 6% 411
Elm........... 6 276 1,044 450 6% 98
Other......... 171 968 16,243 3,674 47% 1,196
--- ----- ------ ----- --- -----
Total Canada.. 285 3,934 23,830 7,905 100% 3,184
=== ===== ====== ===== === =====
</TABLE>
6
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Evi. The Company's Evi Field is located approximately 400 miles north of
Calgary. At December 31, 1999, the Evi Field contained 1,666 MBOE of proved
reserves, which represented 21% of the Company's total Canadian proved reserves
and 33% of the Present Value of the Company's total Canadian proved reserves.
The Company owns approximately 6,560 gross (3,400 net) leasehold acres in the
Evi Field, and has an average 42% working interest in this acreage. The Evi
Field produces oil from the Granite Wash formation at depths ranging from 4,900
to 5,000 feet. The Company's net production from the Evi Field averaged 758 Bbls
of oil per day in 1999. At December 31, 1999, the Company owned 14 gross (4.3
net) productive wells and 2 gross (0.7net) water disposal wells in the field, of
which 11 productive wells and both water disposal wells were operated by Wiser.
Provost. The Company's Provost properties are located approximately 210 miles
northeast of Calgary. At December 31, 1999, the Provost properties contained 977
MBOE of proved reserves, which represented 12% of the Company's total Canadian
proved reserves and 17% of the Present Value of the Company's total Canadian
proved reserves.
The Company owns approximately 7,010 gross (5,080 net) leasehold acres in the
Provost properties, and has an average 65% working interest in this acreage. The
Provost properties produce mainly from the Dina formation at depths of 3,070 to
3,170 feet. The Provost Dina `X' and Cummings W3W Pools are the Company's main
producing pools in these properties and water injection in these pools began in
1990 and 1998, respectively. The Company drilled 1 well in the Provost
properties in 1999 and plans to drill 9 additional wells in Provost in 2000.
The Company's net production from the Provost properties averaged 527 Bbls of
oil per day and 118 Mcf of natural gas per day in 1999. At December 31, 1999,
the Company owned 71 gross (48.8 net) productive wells and 5 gross (3.5 net)
water injection wells on the properties, of which 54 gross productive wells and
all five water injection wells were operated by the Company.
7
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Pine Creek. The Company's Pine Creek properties are located approximately 240
miles northwest of Calgary. At December 31, 1999, the Pine Creek properties
contained 630 MBOE of proved reserves, which represented 8% of the Company's
total Canadian proved reserves and 6% of the Present Value of the Company's
total Canadian proved reserves. The Company owns approximately 10,400 gross
(2,860 net) leasehold acres in the Pine Creek properties, and has a 27% working
interest in this acreage. The Pine Creek properties produce gas from the Bluesky
and Gething formations at depths of 8,000 to 8,200 feet. At December 31, 1999,
the Company owned 9 gross (2.3 net) productive wells in the Pine Creek
properties, all of which were operated by a third party. The Company's net
production from the Pine Creek properties averaged 413 Mcf of natural gas per
day and 105 Bbls of NGLs per day in 1999.
Portage. The Company's Portage properties are located approximately 350 miles
northeast of Calgary. At December 31, 1999, the Portage properties contained 508
MBOE of proved reserves, which represented 6% of the Company's total Canadian
proved reserves and 4% of the Present Value of the Company's total Canadian
proved reserves.
The Company owns approximately 19,200 gross (11,490 net) leasehold acres in the
Portage properties, and has an average 60% working interest in this acreage. The
Portage properties produce from the Grand Rapids and Nisku formations at depths
of 850 and 1,400 feet, respectively. At December 31, 1999, the Company owned 14
gross (11.5 net) productive wells, 11 of which were operated by Wiser. The
Portage properties commenced production in March 1998 and net production from
the Portage properties averaged 2,463 Mcf of natural gas per day in 1999.
Elm. The Company's Elm properties are located approximately 500 miles northwest
of Calgary in British Columbia. At December 31, 1999, the Elm properties
contained 450 MBOE of proved reserves, which represented 6% of the Company's
total Canadian proved reserves and 6% of the Present Value of the Company's
total Canadian proved reserves.
The Company owns approximately 13,460 gross (4,660 net) leasehold acres in the
Elm properties, and has an average 50% working interest in this acreage. The Elm
properties produce from the Gething formation at depths of 4,000 to 4,100 feet.
At December 31, 1999, the Company owned 6 gross (3.0 net) productive wells, all
of which were operated by Wiser. The Company's net production from the Elm
properties averaged 51 Bbls of oil per day and 279 Mcf of natural gas per day in
1999.
Other Canadian Properties. The Company owns interests in approximately 30 other
Canadian properties, primarily located in its principal areas of operation. For
the year ended December 31, 1999, these properties individually represented less
than 7%, and in the aggregate represented approximately 47%, of the Company's
total Canadian proved reserves.
Exploration Activities
United States
The objective of Wiser's domestic exploration program is to generate exploration
and exploitation drilling opportunities that have the potential of replacing
produced reserves and providing a vehicle of growth for the Company. In 1999 the
Company's US exploration efforts were significantly reduced from the previous
year, due to depressed oil and gas prices in late 1998 and early 1999. Wiser's
US exploration drilling efforts were initiated mid-year, and focused on low
risk, South Texas Frio gas prospects. All wells drilled were internally
generated and based on proprietary 3-D seismic surveys.
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In 1999, Wiser participated in 8 gross (3.7 net) US exploration wells, compared
with 29 gross (18 net) wells in 1998, spending $1.1 million in 1999 and $10.5
million in 1998 on US exploration. Of the 8 gross wells drilled by the Company
in 1999, 6 were completed as gas wells, and 2 were unsuccessful, which yields a
75% US exploration success rate in 1999. In 2000, Wiser plans to drill
approximately 15 gross wells in the US and the Company has budgeted
approximately $4.0 million for its 2000 US exploration program.
The Company is currently focusing its US exploration activities in the following
geographical areas:
South Texas. At the Roche Ranch prospect in Refugio County, the Company drilled
7 gross wells in 1999 of which 6 were completed as new gas field discoveries.
The Company operates and has a 40% working interest in the Roche Ranch prospect.
The primary objectives are Frio gas sands at a depth of 5,000 to 7,000 feet,
which are defined utilizing proprietary 3-D seismic surveys. The Company plans
to drill six exploration wells in the Roche Ranch prospect in 2000.
Wiser also operates and has a 40% working interest in the Fitzsimmons prospect
in Jim Wells County. Utilizing proprietary 3-D seismic surveys, the Company has
identified several Frio and Yegua gas sand objectives at depths of 5,000 to
8,500 feet, respectively. Although no wells were drilled in this prospect in
1999, the Company plans to drill an exploratory well to approximately 8,200 feet
to test the Yegua gas sand objective in 2000.
The Company has recently acquired a 30% non-operating working interest in the
Menefee prospect in Wharton County. Wiser plans to participate in drilling three
to four wells in the Menefee prospect in 2000 which target high pressured Yegua
gas sands at depths of 7,800 to 8,700 feet. The Yegua objective has been defined
using 3-D seismic surveys. The first Menefee prospect exploration well, the
Kathleen Appling GU #1, was drilled in February 2000 to approximately 8,600 feet
and is currently being completed as a Yegua gas discovery well.
At Welder Ranch in Refugio County, the Company drilled and abandoned one well in
1999. The Company does not anticipate any further exploration activity at Welder
Ranch at this point in time.
West Texas. Wiser has sold a portion of its working interest in both the Indian
Mesa and Panther Bluff prospects in Pecos County and now has a carried interest
in these prospects. The Indian Mesa and Panther Bluff prospects do not meet the
Company's exploration objectives at this time.
Gulf Coast. At the Little Crow prospect in Wilkinson County, Mississippi, the
T.O.Sessions #1 exploration well was drilled to a total depth of 13,834 ft. The
Cretaceous Tuscaloosa "A" sands are currently being production tested. Wiser has
a 50% non-operating working interest in this prospect.
The Company has reprocessed and interpreted the 3-D seismic survey data
acquired at the Castleberry prospect in Conecuh County, Alabama, and is planning
to drill the first exploration well on this prospect in 2000. The primary
objectives are Jurassic, Lower Haynesville sands, which produce nearby in the
Frisco City area. The first exploration well will be drilled to approximately
12,500 feet and is based on a 32 square mile 3-D seismic survey. Wiser operates
and has a 50% working interest in the Castleberry prospect. Several other
prospects have also been defined near the Castleberry prospect.
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Canada
Wiser focuses its Canadian exploration activities in specific regions within the
Western Canadian Sedimentary Basin in close proximity to known producing
horizons where the potential for significant reserves exists. The Company's
technical personnel have considerable experience in this focus area. During
1999, the Company drilled one gross (one net) exploratory well which was a
successful gas well. The Company spent $3.6 million on exploration in Canada in
1999 and has budgeted $2.8 million for its 2000 Canadian exploration program.
The Company is currently focusing its Canadian exploration activities in the
following geographical area:
West Central Alberta. In 1999, the Company successfully completed the
Wiser/Mobil Wild River 6-33 exploratory well at the Wild River prospect which
added 352 MBOE to the Company's total proved reserves. The Wild River 6-33 well
started production in January 2000 at an average rate of 500 Mcf per day. Wiser
operates and has a 50% working interest in the well. The Company completed a 21
square mile 3-D seismic survey in the Wild River prospect in February 2000 and
purchased an additional 1,280 acres of undeveloped leasehold acreage in March
2000. Wiser plans to drill one well in 2000 in the Wild River prospect.
In 1999, the Company utilized 3-D seismic survey data to identify a possible
Granite Wash formation trap in the Evi North prospect located 1 mile north of
the Evi Field. Wiser operates and has a 100% working interest in the Evi North
prospect and plans to drill 1 exploratory well in 2000 in the Evi North prospect
International
The Company did not participate in any international exploration activity in
1999 and currently has no plans to participate in future international
exploration activities.
Marketing of Production
The Company markets its production of oil, natural gas and NGLs to a variety of
purchasers, including large refiners and resellers, pipeline affiliate
marketers, independent marketers, utilities and industrial end-users. To help
manage the impact of potential price declines, Wiser has developed a portfolio
of long- and short-term contracts with prices that are either fixed or related
to market conditions in varying degrees. Most of the Company's production is
sold pursuant to contracts that provide for market-related pricing for the areas
in which the production is located.
During the year ended December 31, 1999, revenues from the sale of production to
Highland Energy Company, CXY Energy Marketing and EOTT Energy Operating Ltd.
represented approximately 41%, 11% and 10%, respectively, of the Company's total
oil and gas revenues. The Company believes it would be able to locate alternate
purchasers in the event of the loss of any one or more of these purchasers, and
that any such loss would not have a material adverse effect on the Company's
financial condition or results of operations.
Crude Oil. The Company sells its crude oil and condensate to various refiners
and resellers in the United States and Canada at posting-related and spot-
related prices that also depend on factors such as well location, production
volume and product quality. The Company typically sells its crude oil and
condensate production at or near the well site, although in some cases it is
gathered by the Company or others and delivered to a central point of sale. The
Company's crude oil and condensate production is transported by truck or by
pipeline and is typically committed to arrangements having a term of one year or
less. The Company has not engaged in crude oil trading activities. Revenue from
the sale of crude oil and condensate totaled $25.6 million for the year ended
December 31, 1999 and represented 54% of the Company's total oil and gas
revenues for 1999.
From time to time, the Company enters into crude oil and natural gas price
hedges to reduce its exposure to commodity price fluctuation. See Item 7A -
"Quantitative and Qualitative Disclosures about Market Risk -
10
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Commodity Price Risk" and Note 1 to the Company's Consolidated Financial
Statements included elsewhere in this Report.
Natural Gas. The Company sells its produced natural gas and gathered gas to
utilities, marketers, processor/resellers and industrial end-users primarily
under market-sensitive, long-term contracts or daily, monthly or multi-month
spot agreements. An insignificant amount of the Company's natural gas is
committed to long-term, fixed-price sales agreements. To accomplish the delivery
and sale of certain of its natural gas, the Company has entered into long-term
agreements with various natural gas gatherers that deliver its gas to points of
sale on major transmission pipelines.
The Company believes that it has sufficient production from its properties, and
from those of others tied to its gathering and transportation system, to meet
the Company's delivery obligations under its existing natural gas sales
contracts.
NGLs. From its natural gas processing plants in West Texas, the Company sells
NGLs to independent marketers for resale. A direct pipeline connection to the
Texas Gulf Coast market area facilitates the sale of NGLs from the Company's
Wellman Unit, and enables the Company to receive prices that are representative
of the daily market value of NGLs on the Texas Gulf Coast, less transportation
and fractionation costs. The Company's average price in 1999 for NGLs sold from
Company-operated plants or under processing agreements with others was $13.01
per Bbl. Prices for NGLs attributable to natural gas sold to plants operated by
others are generally included in the prices reported by the Company for the sale
of its natural gas.
Price Considerations. Crude oil prices are established in a highly liquid,
international market, with average crude oil prices received by the Company
generally fluctuating with changes in the futures price established on the
NYMEX for West Texas Intermediate Crude Oil ("NYMEX-WTI"). The average crude oil
price per Bbl received by the Company in 1999 was $15.18. The average NYMEX-WTI
closing price per Bbl for 1999 was $19.24.
Natural gas prices in each of the geographical areas in which the Company
operates are closely tied to established price indices which are heavily
influenced by national and regional supply and demand factors and the futures
price per MMBtu for natural gas delivered at Henry Hub, Louisiana established on
the NYMEX ("NYMEX-Henry Hub"). At times, these indices correlate closely with
the NYMEX-Henry Hub price, but often there are significant variances between the
NYMEX-Henry Hub price and the indices used to price the Company's natural gas.
Average natural gas prices received by Wiser in each of its operating areas
generally fluctuate with changes in these established indices. The average
natural gas price per Mcf received by the Company in 1999 was $1.83. The average
NYMEX-Henry Hub price per MMBtu for 1999 was $2.27, computed by averaging the
closing price on the last three trading days of each month of the forward prompt
month NYMEX natural gas futures contract price applicable to each month in 1999.
The average natural gas price received by the Company in 1999 was lower than
such 1999 NYMEX-Henry Hub price as a result of pricing differentials determined
by the location of the Company's natural gas production relative to the Henry
Hub trading point and lower natural gas prices generally applicable to Canadian
natural gas production relative to U.S. production.
11
<PAGE>
Oil and Gas Reserves
The following table sets forth the proved developed and undeveloped reserves of
the Company at December 31, 1999:
<TABLE>
<CAPTION>
Oil and NGLs (MBbls) Gas (Mmcf) Total Reserves (MBOE)
------------------------------ ------------------------------ ------------------------------
Developed Undeveloped Total Developed Undeveloped Total Developed Undeveloped Total
--------- ----------- ----- --------- ----------- ----- --------- ----------- -----
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Permian Basin
Maljamar................. 9,444 933 10,377 2,849 88 2,937 9,919 948 10,867
Wellman.................. 8,747 -- 8,747 735 -- 735 8,869 -- 8,869
Dimmitt/Slash Ranch...... 1,600 226 1,826 9,226 449 9,675 3,138 301 3,439
------ ----- ------ ------ ----- ------ ------ ----- ------
Total.................. 19,791 1,159 20,950 12,810 537 13,347 21,926 1,249 23,175
San Juan Basin............. 37 8 45 17,375 1,513 18,888 2,933 260 3,193
Other...................... 499 2 501 13,586 342 13,928 2,763 59 2,822
------ ----- ------ ------ ----- ------ ------ ----- ------
Total United States........ 20,327 1,169 21,496 43,771 2,392 46,163 27,622 1,568 29,190
Canada..................... 3,719 215 3,934 22,813 1,017 23,830 7,521 384 7,905
------ ----- ------ ------ ----- ------ ------ ----- ------
Total Company.............. 24,046 1,384 25,430 66,584 3,409 69,993 35,143 1,952 37,095
====== ===== ====== ====== ===== ====== ====== ===== ======
</TABLE>
The following table summarizes the Company's proved reserves, the estimated
future net revenues from such proved reserves and the Present Value and
Standardized Measure of Discounted Future Net Cash Flows attributable thereto at
December 31, 1999, 1998 and 1997:
<TABLE>
<CAPTION>
At December 31,
-----------------------------------------
1999 1998 1997
-------- -------- --------
(000's except weighted average sales prices)
<S> <C> <C> <C>
Proved reserves:
Oil and NGLs (Bbl).................................... 25,430 27,988 29,721
Gas (Mcf)............................................. 69,993 119,981 120,094
BOE.................................................. 37,095 47,985 49,737
Estimated future net revenues before income taxes..... $419,668 $218,969 $359,293
Present Value......................................... $222,539 $123,831 $210,087
Standardized Measure(1)............................... $176,916 $113,232 $174,489
Proved developed reserves:
Oil and NGLs (Bbl).................................... 24,046 26,954 28,202
Gas (Mcf)............................................. 66,584 110,346 109,459
BOE.................................................. 35,143 45,345 46,444
Estimated future net revenues before income taxes..... $395,749 $207,884 $335,338
Present Value......................................... $212,263 $122,502 $200,647
Weighted average sales prices:
Oil (per Bbl)......................................... $ 23.76 $ 10.39 $ 15.92
Gas (per Mcf)......................................... 1.99 1.98 2.35
NGLs (per Bbl)........................................ 19.11 8.44 11.40
</TABLE>
(1) The Standardized Measure of Discounted Future Net Cash Flows prepared by the
Company represents the present value (using an annual discount rate of 10%)
of estimated future net revenues from the production of proved reserves,
after giving effect to income taxes. See the Supplemental Financial
Information attached to the Consolidated Financial Statements of the Company
included elsewhere in this Report for additional information regarding the
disclosure of the Standardized Measure information in accordance with the
provisions of Statement of Financial Accounting Standards ("SFAS") No. 69,
"Disclosures about Oil and Gas Producing Activities."
12
<PAGE>
All information set forth in this Report relating to the Company's proved
reserves, estimated future net revenues and Present Values is taken from reports
prepared by DeGolyer and MacNaughton (with respect to the Company's United
States properties) and Gilbert Lausten Jung Associates Ltd. (with respect to the
Company's Canadian properties), each of which is a firm of independent petroleum
engineers. The estimates of these engineers were based upon review of production
histories and other geological, economic, ownership and engineering data
provided by the Company. No reports on the Company's reserves have been filed
with any federal agency. In accordance with guidelines of the Securities and
Exchange Commission ("SEC"), the Company's estimates of proved reserves and the
future net revenues from which Present Values are derived are made using year
end oil and gas sales prices held constant throughout the life of the properties
(except to the extent a contract specifically provides otherwise). A decline in
prices relative to year end 1999 could cause a significant decline in the
Present Value attributable to the Company's proved reserves at December 31,
1999. Operating costs, development costs and certain production-related taxes
were deducted in arriving at estimated future net revenues, but such costs do
not include debt service, general and administrative expenses and income taxes.
There are numerous uncertainties inherent in estimating oil and gas reserves and
their values, including many factors beyond the Company's control. The reserve
data set forth in this Report represents estimates only. Reservoir engineering
is a subjective process of estimating the sizes of underground accumulations of
oil and gas that cannot be measured in an exact manner. The accuracy of any
reserve estimate is a function of the quality of available data, engineering and
geological interpretation, and judgment. As a result, estimates of different
engineers, including those used by the Company, may vary. In addition, estimates
of reserves are subject to revision based upon actual production, results of
future development, exploitation and exploration activities, prevailing oil and
gas prices, operating costs and other factors, which revisions may be material.
Accordingly, reserve estimates are often different from the quantities of oil
and gas that are ultimately recovered and are highly dependent upon the accuracy
of the assumptions upon which they are based. There can be no assurance that
these estimates are accurate predictions of the Company's oil and gas reserves
or their values. Estimates with respect to proved reserves that may be developed
and produced in the future are often based upon volumetric calculations and upon
analogy to similar types of reserves rather than actual production history.
Estimates based on these methods are generally less reliable than those based on
actual production history. Subsequent evaluation of the same reserves based upon
production history will result in variations, which may be substantial, in the
estimated reserves.
13
<PAGE>
Net Production, Sales Prices and Costs
The following table presents certain information with respect to oil and gas
production, prices and costs attributable to all oil and gas property interests
owned by the Company for the three-year period ended December 31, 1999.
<TABLE>
<CAPTION>
Year Ended December 31,
-----------------------------
1999 1998 1997
---- ---- ----
<S> <C> <C> <C>
Production volumes:
Oil (MBbl)
United States............................ 1,085 1,577 1,769
Canada................................... 599 816 672
------- ------- -------
Total Company.......................... 1,684 2,393 2,441
Gas (MMcf)
United States (1)........................ 7,333 11,143 10,095
Canada................................... 2,915 3,221 2,734
------- ------- -------
Total Company (1)...................... 10,248 14,364 12,829
NGLs (MBbl)
United States............................ 172 260 267
Canada................................... 77 62 52
------- ------- -------
Total Company.......................... 249 322 319
Weighted average sales prices (2):
Oil (per Bbl)
United States............................ $ 14.56 $ 12.68 $ 18.30
Canada................................... 16.29 12.04 17.28
Total Company.......................... 15.18 12.46 18.02
Gas (per Mcf)
United States (1)........................ $ 1.95 $ 2.05 $ 2.46
Canada................................... 1.54 1.12 1.26
Total Company.......................... 1.83 1.84 2.21
NGLs (per Bbl)
United States............................ $ 13.54 $ 9.41 $ 13.34
Canada................................... 11.84 8.56 16.64
Total Company.......................... 13.01 9.25 13.87
Selected expenses per BOE (3):
Lease operating
United States............................ $ 5.82 $ 5.01 $ 5.03
Canada................................... 3.48 3.05 3.50
Total Company.......................... 5.07 4.45 4.65
Production taxes (4)
United States............................ $ 0.77 $ 0.84 $ 1.02
Depreciation, depletion and amortization
United States............................ $ 4.34 $ 4.48 $ 3.88
Canada................................... 6.03 6.54 7.58
Total Company.......................... 4.88 5.15 4.79
General and administrative
United States............................ $ 2.23 $ 2.11 $ 2.17
Canada................................... 1.15 1.41 1.54
Total Company.......................... 1.88 1.96 2.02
</TABLE>
__________________
(1) Calculated by including volumes of natural gas purchased for resale as
follows: 1999 - 148 MMcf, 1998 - 608 MMcf and 1997 - 629 MMcf.
(2) Reflects results of hedging activities. See Item 7A - "Quantitative and
Qualitative Disclosures about Market Risk."
(3) Calculated without including volumes of natural gas purchased for resale.
14
<PAGE>
(4) Canada does not assess production taxes on revenue derived from oil and gas
production from Crown lands. However, in Canada, royalties are payable to
the provincial governments on production from Crown lands, subject to
certain programs that provide for royalty rate reductions, royalty holidays
and tax credits for the purpose of encouraging oil and gas exploration and
development. See "-Governmental Regulation-Canada."
Productive Wells and Acreage
Productive Wells
The following table sets forth the Company's domestic and Canadian productive
wells at December 31, 1999:
<TABLE>
<CAPTION>
Productive Wells
----------------------------------------------------
Oil Gas Total
-------------- --------------- ---------------
Gross Net Gross Net Gross Net
----- --- ----- --- ----- ---
<S> <C> <C> <C> <C> <C> <C>
United States............ 369 299 2,449 (1) 69 2,818 368
Canada................... 201 72 84 37 285 109
--- --- ----- --- ----- ---
Total.................. 570 371 2,533 106 3,103 477
=== === ===== === ===== ===
</TABLE>
(1) 2,400 of the Company's gross natural gas wells are located in the San Juan
Basin. The Company has non-operated working interests in these wells ranging
from 0.26% to 50.0% and average approximately 1.8%.
Acreage
The following table sets forth the Company's undeveloped and developed gross and
net leasehold acreage at December 31, 1999. Undeveloped acreage includes leased
acres on which wells have not been drilled or completed to a point that would
permit the production of commercial quantities of oil and gas, regardless of
whether or not such acreage contains proved reserves.
<TABLE>
<CAPTION>
Undeveloped Developed Total
--------------- ------------------ ----------------
Gross Net Gross Net Gross Net
----- --- ----- --- ----- ---
<S> <C> <C> <C> <C> <C> <C>
Permian Basin
Maljamar............... 480 421 13,932 13,793 14,412 14,214
Wellman................ -- -- 2,280 2,165 2,280 2,165
Dimmitt/Slash Ranch.... 1,469 1,257 6,035 5,229 7,504 6,486
------- ------ ------- ------ ------- -------
Total................ 1,949 1,678 22,247 21,187 24,196 22,865
San Juan Basin......... -- -- 10,880 6,239 10,880 6,239
Other.................. 41,247 18,811 13,321 6,384 54,568 25,195
------- ------ ------- ------ ------- -------
Total United States.. 43,196 20,489 46,448 33,810 89,644 54,299
Canada................. 139,661 67,987 56,942 25,059 196,603 93,046
------- ------ ------- ------ ------- -------
Total.................. 182,857 88,476 103,390 58,869 286,247 147,345
======= ====== ======= ====== ======= =======
</TABLE>
(1) Excluded is acreage in which the Company's interest is limited to a mineral
or royalty interest. At December 31, 1999, the Company held mineral or
royalty interests in 2,815 gross (759 net) developed acres and 30,056 gross
(3,584 net) undeveloped acres.
All the leases for the undeveloped acreage summarized in the preceding table
will expire at the end of their respective primary terms unless prior to that
date the existing leases are renewed or production has been obtained from the
acreage subject to the lease, in which event the lease will remain in effect
until the cessation of production. The following table sets forth the minimum
remaining lease terms for the gross and net undeveloped acreage:
15
<PAGE>
<TABLE>
<CAPTION>
Acres Expiring
------------------
Gross Net
------- ------
<S> <C> <C>
Twelve Months Ending:
December 31, 2000............... 30,296 14,218
December 31, 2001............... 61,677 26,487
Thereafter...................... 90,884 47,771
------- ------
Total......................... 182,857 88,476
======= ======
</TABLE>
As is customary in the industry, the Company generally acquires oil and gas
acreage without any warranty of title except as to claims made by, through or
under the transferor. Although the Company has title to developed acreage
examined prior to acquisition in those cases in which the economic significance
of the acreage justifies the cost, there can be no assurance that losses will
not result from title defects or from defects in the assignment of leasehold
rights. In many instances, title opinions may not be obtained if in the
Company's judgment it would be uneconomical or impractical to do so.
Drilling Activity
The following table sets forth for the three-year period ended December 31, 1999
the number of exploratory and development wells drilled by or on behalf of the
Company.
<TABLE>
<CAPTION>
1999 1998 1997
-------------- -------------- ---------------
Gross Net Gross Net Gross Net
----- --- ----- --- ----- ---
<S> <C> <C> <C> <C> <C> <C>
Exploratory Wells:
- -----------------
United States
Producing....... 6 2 16 11 10 6
Dry............. 2 1 14 7 8 4
Canada
Producing....... 1 1 3 2 3 2
Dry............. -- -- 3 1 1 1
Development Wells:
- -----------------
United States
Producing....... 1 -- 58 44 80 71
Dry............. -- -- 2 1 2 1
Canada
Producing....... 20 4 19 12 39 18
Dry............. 2 1 7 4 6 4
Total Wells:
- -----------
Producing....... 28 7 96 69 132 97
Dry............. 4 2 26 13 17 10
---- -- --- -- --- ---
Total......... 32 9 122 82 149 107
==== == === == === ===
</TABLE>
Operations
The Company generally seeks to be named as operator for wells in which it has
acquired a significant interest, although, as is common in the industry, this
typically occurs only when the Company owns the major portion of the working
interest in a particular well or field. At December 31, 1999, the Company
operated 100% of its properties in the Permian Basin, comprising approximately
62% of the Company's total proved reserves, including Maljamar (208 gross
wells), Wellman (14 gross wells) and Dimmitt/Slash Ranch (82 gross wells). At
December 31, 1999, the Company also operated 114 (out of a total of 285) gross
wells on its Canadian properties.
16
<PAGE>
As operator, the Company is able to exercise substantial influence over the
development and enhancement of a well and to supervise operation and maintenance
activities on a daily basis. The Company does not conduct the actual drilling
of wells on properties for which it acts as operator, but engages independent
contractors who are supervised by the Company. The Company employs petroleum
engineers, geologists and other operations and production specialists who strive
to improve production rates, increase reserves and/or lower the cost of
operating its oil and gas properties.
Oil and gas properties are customarily operated under the terms of a joint
operating agreement, which provides for reimbursement of the operator's direct
expenses and monthly per-well supervision fees. Per-well supervision fees vary
widely depending on the geographic location and producing formation of the well,
whether the well produces oil or gas and other factors. Such fees received by
the Company in 1999 ranged from $95 to $870 per well per month.
Competition
The oil and gas industry is highly competitive. The Company encounters
competition from other oil and gas companies in all areas of its operations,
including the acquisition of producing properties. The Company's competitors
include major integrated oil and gas companies and numerous independent oil and
gas companies, individuals and drilling and income programs. Many of its
competitors are large, well established companies with substantially larger
operating staffs and greater capital resources than the Company. Such companies
may be able to pay more for productive oil and gas properties and exploratory
prospects and to define, evaluate, bid for and purchase a greater number of
properties and prospects than the Company's financial or human resources permit.
The Company's ability to acquire additional properties and to discover reserves
in the future will depend upon its ability to evaluate and select suitable
properties and to consummate transactions in a highly competitive environment.
Drilling and Operating Risks
Drilling activities are subject to many risks, including the risk that no
commercially productive oil or gas reservoirs will be encountered. There can be
no assurance that new wells drilled by the Company will be productive or that
the Company will recover all or any portion of its investment. Drilling for oil
and gas may involve unprofitable efforts, not only from dry wells, but from
wells that are productive but do not produce sufficient net revenues to return a
profit after drilling, operating and other costs. The cost of drilling,
completing and operating wells is often uncertain. The Company's drilling
operations may be curtailed, delayed or canceled as a result of a variety of
factors, many of which are beyond its control, including economic conditions,
mechanical problems, pressure or irregularities in formations, title problems,
weather conditions, compliance with governmental requirements and shortages in
or delays in the delivery of equipment and services. Such equipment shortages
and delays sometimes involve drilling rigs, especially in Canada, where weather
conditions result in a short drilling season, causing a high demand for rigs by
a large number of companies during a relatively short period of time. The
Company's future drilling activities may not be successful. Lack of drilling
success could have a material adverse effect on the Company's financial
condition and results of operations.
In addition, the Company's use of 3-D seismic requires greater pre-drilling
expenditures than traditional drilling strategies. Although the Company believes
that its use of 3-D seismic will increase the probability of success of its
exploratory wells and should reduce average finding costs through the
elimination of prospects that might otherwise be drilled solely on the basis of
2-D seismic and other traditional methods, unsuccessful wells are likely to
occur.
The Company's operations are subject to all the hazards and risks normally
incident to the development, exploitation, production and transportation of, and
the exploration for, oil and gas, including unusual or unexpected geologic
formations, pressures, down-hole fires, mechanical failures, blowouts,
cratering, explosions, uncontrollable flows of oil, gas or well fluids and
pollution and other environmental risks. These hazards could result in
substantial losses to the Company due to injury and loss of life, severe damage
to and destruction of property and equipment, pollution and other environmental
damage and suspension of operations. The Company maintains comprehensive
17
<PAGE>
insurance coverage, including a $1.0 million general liability insurance policy
and a $30.0 million excess liability policy. The Company believes that its
insurance is adequate and customary for companies of a similar size engaged in
comparable operations, but losses could occur for uninsurable or uninsured risks
or in amounts in excess of existing insurance coverage.
Title to Properties
The Company's land department and contract land professionals have reviewed
title records or other title review materials relating to substantially all of
its producing properties. The title investigation performed by the Company
prior to acquiring undeveloped properties is thorough, but less rigorous than
that conducted prior to drilling, consistent with industry standards. The
Company believes it has satisfactory title to all its producing properties in
accordance with standards generally accepted in the oil and gas industry. The
Company's properties are subject to customary royalty interests, liens incident
to operating agreements, liens for current taxes and other inchoate burdens
which the Company believes do not materially interfere with the use of or affect
the value of such properties. At December 31, 1999, the Company's leaseholds for
approximately 40% of its net acreage were being kept in force by virtue of
production on that acreage in paying quantities. The remaining net acreage was
held by lease rentals and similar provisions and requires production in paying
quantities prior to expiration of various time periods to avoid lease
termination.
The Company expects to make acquisitions of oil and gas properties from time to
time. In making an acquisition, the Company generally focuses most of its title
and valuation efforts on the more significant properties. It is generally not
feasible for the Company to review in-depth every property it purchases and all
records with respect to such properties. However, even an in-depth review of
properties and records may not necessarily reveal existing or potential
problems, nor will it permit the Company to become familiar enough with the
properties to assess fully their deficiencies and capabilities. Evaluation of
future recoverable reserves of oil and gas, which is an integral part of the
property selection process, is a process that depends upon evaluation of
existing geological, engineering and production data, some or all of which may
prove to be unreliable or not indicative of future performance. To the extent
the seller does not operate the properties, obtaining access to properties and
records may be more difficult. Even when problems are identified, the seller may
not be willing or financially able to give contractual protection against such
problems, and the Company may decide to assume environmental and other
liabilities in connection with acquired properties.
18
<PAGE>
Governmental Regulation
The Company's operations are affected from time to time in varying degrees by
political developments and federal, state, provincial and local laws and
regulations. In particular, oil and gas production and related operations are or
have been subject to price controls, taxes and other laws and regulations
relating to the oil and gas industry. Failure to comply with such laws and
regulations can result in substantial penalties. The regulatory burden on the
oil and gas industry increases the Company's cost of doing business and affects
its profitability. Although the Company believes it is in substantial compliance
with all applicable laws and regulations, because such laws and regulations are
frequently amended or reinterpreted, the Company is unable to predict the future
cost or impact of complying with such laws and regulations.
United States. Sales of natural gas by the Company are not regulated and are
generally made at market prices. However, the Federal Energy Regulatory
Commission ("FERC") regulates interstate natural gas transportation rates and
service conditions, which affect the marketing of natural gas produced by the
Company, as well as the revenues received by the Company for sales of such
production. Sales of the Company's natural gas currently are made at
uncontrolled market prices, subject to applicable contract provisions and price
fluctuations which normally attend sales of commodity products. The FERC's
jurisdiction over natural gas transportation was unaffected by the Decontrol
Act. While sales by producers of natural gas, and all sales of crude oil,
condensate and NGLs, can currently be made at uncontrolled market prices,
Congress could re-enact prices controls in the future.
Since the mid-1980's, the FERC has issued a series of orders that have
significantly altered the marketing and transportation of natural gas. Such
orders have mandated a fundamental restructuring of interstate pipeline sales
and transportation service, including the unbundling by interstate pipelines of
the sale, transportation, storage and other components of the city-gate sales
services such pipelines previously performed. Further, they have eliminated or
substantially reduced the interstate pipelines' traditional role as wholesalers
of natural gas, and have substantially increased competition and volatility in
natural gas markets. While the Company cannot predict what action the FERC will
take on these or related matters in the future, the Company does not believe
that it will be treated materially differently than other natural gas producers
and marketers with which it competes.
The Company's gathering operations are subject to safety and operational
regulations relating to the design, installation, testing, construction,
operation, replacement and management of facilities. Pipeline safety issues have
recently been the subject of increasing focus in various political and
administrative arenas at both the state and federal levels. The Company believes
its operations, to the extent they may be subject to current gas pipeline safety
requirements, comply in all material respects with such requirements. The
Company cannot predict what effect, if any, the adoption of this or other
additional pipeline safety legislation might have on its operations, but the
industry could be required to incur additional capital expenditures and
increased costs depending upon future legislative and regulatory changes.
19
<PAGE>
The State of Texas and many other states require permits for drilling
operations, drilling bonds and reports concerning operations and impose other
requirements relating to the exploration for and production of oil and gas. Such
states also have statutes or regulations addressing conservation matters,
including provisions for the unitization or pooling of oil and gas properties,
the establishment of maximum rates of production from wells and the regulation
of spacing, plugging and abandonment of such wells. The statutes and regulations
of certain states limit the rate at which oil and gas can be produced from the
Company's properties. However, the Company does not believe it will be affected
materially differently by these statutes and regulations than any other
similarly situated oil and gas company.
Canada. In Canada producers of oil negotiate sales contracts directly with oil
purchasers, with the result that sales of oil are generally made at market
prices. The price of oil received by the Company depends in part on oil quality,
prices of competing fuels, distance to market, the value of refined products and
the supply/demand balance. Oil exports may be made pursuant to export contracts
with terms not exceeding one year in the case of light crude, and not exceeding
two years in the case of heavy crude, provided that an order approving any such
export has been obtained from the National Energy Board ("NEB"). Any oil export
to be made pursuant to a contract of a longer duration requires an exporter to
obtain an export license from the NEB and the issue of such license requires the
approval of the Governor General in Council.
In Canada the price of natural gas sold is determined by negotiation between
buyers and sellers. Natural gas exported from Canada is subject to regulation by
the NEB and the government of Canada. Exporters are free to negotiate prices and
other terms with purchasers, provided that export contracts in excess of two
years must continue to meet certain criteria prescribed by the NEB and the
government of Canada. As is the case with oil, natural gas exports for a term of
less than two years must be made pursuant to an NEB order, or, in the case of
exports for a longer duration, pursuant to an NEB license and Governor General
in Council approval. The government of Alberta also regulates the volume of
natural gas that may be removed from Alberta for consumption elsewhere based on
such factors as reserve availability, transportation arrangements and marketing
considerations.
In addition to Canadian federal regulation, Alberta and certain other provinces
have legislation and regulations that govern royalties payable on production
from Crown lands. The royalty regime that is in place at a particular time or
location is a significant factor in the profitability of oil and gas production.
Royalties payable on production from lands other than Crown lands are determined
by negotiations between the mineral owner and the lessee. Crown royalties are
determined by governmental regulation and are generally calculated as a
percentage of the value of the gross production. The rate of royalties payable
generally depends in part on prescribed reference prices, well productivity,
geographical location, field discovery date and the type and quality of the
petroleum product produced.
From time to time the government of Alberta has established incentive programs
that have included royalty rate reductions, royalty holidays and tax credits for
the purpose of encouraging oil and gas exploration or enhanced production
projects. For example, a producer of oil or gas is entitled to a credit against
the royalties payable to the Crown by virtue of the Alberta Royalty Tax Credit
("ARTC") program. The ARTC program provides a rebate on Crown royalties paid in
respect of eligible producing properties. The ARTC program is based on a price-
sensitive formula, and the ARTC rate currently varies between 25% and 75% of the
royalty otherwise payable on production. The ARTC rate is currently applied to a
maximum of $2.0 million of Alberta Crown royalties otherwise payable by each
producer or associated group of producers in each tax year. The rate is
established quarterly based on average "par price," as determined by the Alberta
Department of Energy for the previous quarterly period. Producing properties
acquired from corporations claiming maximum entitlement to ARTC will generally
not be eligible for ARTC.
20
<PAGE>
Environmental Matters
The Company's operations and properties are subject to extensive and changing
federal, state, provincial and local laws and regulations relating to
environmental protection, including the generation, storage, handling and
transportation of oil and gas and the discharge of materials into the
environment, and relating to safety and health. The recent trend in
environmental legislation and regulation generally is toward stricter standards,
and this trend will likely continue. These laws and regulations may require the
acquisition of a permit or other authorization before construction or drilling
commences and for certain other activities; limit or prohibit construction,
drilling and other activities on certain lands lying within wilderness and other
protected areas; and impose substantial liabilities for pollution resulting from
the Company's operations. The permits required for various of the Company's
operations are subject to revocation, modification and renewal by issuing
authorities. Governmental authorities have the power to enforce compliance with
their regulations, and violations are subject to fines, penalties or
injunctions. In the opinion of management, the Company is in substantial
compliance with current applicable environmental laws and regulations, and the
Company has no material commitments for capital expenditures to comply with
existing environmental requirements. Nevertheless, changes in existing
environmental laws and regulations or in interpretations thereof could have a
significant impact on the Company. The impact of such changes, however, would
not likely be any more burdensome to the Company than to any other similarly
situated oil and gas company.
The Comprehensive Environmental Response, Compensation, and Liability Act
("CERCLA"), also known as the "Superfund" law, and similar state laws impose
liability, without regard to fault or the legality of the original conduct, on
certain classes of persons that are considered to have contributed to the
release of a "hazardous substance" into the environment. These persons include
the owner or operator of the disposal site or sites where the release occurred
and companies that disposed or arranged for the disposal of the hazardous
substances found at the site. Persons who are or were responsible for releases
of hazardous substances under CERCLA may be subject to joint and several
liability for the costs of cleaning up the hazardous substances that have been
released into the environment and for damages to natural resources. Furthermore,
neighboring landowners and other third parties may file claims for personal
injury and property damage allegedly caused by the hazardous substances released
into the environment.
The Company generates typical oil and gas field wastes, including hazardous
wastes, that are subject to the federal Resources Conservation and Recovery Act
and comparable state statutes. The United States Environmental Protection Agency
and various state agencies have limited the approved methods of disposal for
certain hazardous and nonhazardous wastes. Furthermore, certain wastes generated
by the Company's oil and gas operations that are currently exempt from
regulation as "hazardous wastes" may in the future be designated as "hazardous
wastes," and therefore be subject to more rigorous and costly operating and
disposal requirements.
The Oil Pollution Act ("OPA") imposes a variety of requirements on responsible
parties for onshore and offshore oil and gas facilities and vessels related to
the prevention of oil spills and liability for damages resulting from such
spills in waters of the United States. The "responsible party" includes the
owner or operator of an onshore facility or vessel or the lessee or permittee
of, or the holder of a right of use and easement for, the area where an onshore
facility is located. OPA assigns liability to each responsible party for oil
spill removal costs and a variety of public and private damages from oil spills.
Few defenses exist to the liability for oil spills imposed by OPA. OPA also
imposes financial responsibility requirements. Failure to comply with ongoing
requirements or inadequate cooperation in a spill event may subject a
responsible party to civil or criminal enforcement actions.
The Company's Canadian operations are also subject to environmental regulation
pursuant to local, provincial and federal legislation. Canadian environmental
legislation provides for restrictions and prohibitions on releases or emissions
of various substances produced in association with certain oil and gas industry
operations and can affect the location of wells and facilities and the extent to
which exploration and development is permitted. In addition, legislation
requires that well and facilities sites be abandoned and reclaimed to the
satisfaction of provincial authorities. In most cases, an environmental
assessment and review is required prior to initiating exploration or development
projects or undertaking significant changes to existing projects. A breach of
such legislation may result in the imposition of fines and issuance of clean-up
orders. Environmental legislation in Alberta has recently undergone a major
revision and has been consolidated in the Environmental Protection and
Enhancement Act.
21
<PAGE>
Under the new Act, environmental standards and compliance for releases, clean-up
and reporting are stricter. Also, the range of enforcement actions available and
the severity of penalties have been significantly increased. These changes will
have an incremental effect on the cost of conducting operations in Alberta.
The Company owns, leases or operates numerous properties that for many years
have produced or processed oil and gas. The Company also owns and operates
natural gas gathering, transportation and processing systems. It is not uncommon
for such properties to be contaminated with hydrocarbons or polychlorinated
biphenyls. Although the Company or previous owners of these interests may have
used operating and disposal practices that were standard in the industry at the
time, hydrocarbons, polychlorinated biphenyls or other wastes may have been
disposed of or released on or under the properties or on or under other
locations where such wastes have been taken for disposal. These properties may
be subject to federal or state requirements that could require the Company to
remove any such wastes or to remediate the resulting contamination. In addition,
some of the Company's properties are operated by third parties over whom the
Company has no control. Notwithstanding the Company's lack of control over
properties operated by others, the failure of the previous owners or operators
to comply with applicable environmental regulations may, in certain
circumstances, adversely impact the Company.
Abandonment Costs
The Company is responsible for payment of plugging and abandonment costs on its
oil and gas properties pro rata to its working interest. Based on its
experience, the Company anticipates that the ultimate aggregate salvage value of
lease and well equipment located on its properties will exceed the costs of
abandoning such properties. There can be no assurance, however, that the Company
will be successful in avoiding additional expenses in connection with the
abandonment of any of its properties. In addition, abandonment costs and their
timing may change due to many factors, including actual production results,
inflation rates and changes in environmental laws and regulations.
Employees
At February 24, 2000, the Company employed 67 full-time employees, of whom five
were executive officers, 13 were technical personnel, 28 were field personnel
and 21 were administrative personnel. Of the total employees, 53 were located in
the United States and 14 were located in Canada. At February 24, 2000, none of
the Company's employees were represented by a labor union. The Company considers
its relations with its employees to be good.
Facilities
The Company's principal executive and administrative offices are located at 8115
Preston Road, Suite 400, Dallas, Texas. The offices contain approximately 21,000
square feet of space and are leased through December 31, 2001. Rental payments
are approximately $37,000 per month. The office of the Company's Canadian
subsidiary, The Wiser Oil Company of Canada, is located at 645 7th Avenue, S.W.,
Suite 2550, Calgary, Alberta. This office contains approximately 14,000 square
feet of space and is leased through December 20, 2003. Rental payments are
approximately $20,000 per month.
Glossary of Oil and Gas Terms
The following are abbreviations and definitions of terms commonly used in the
oil and gas industry that are used in this Report.
"Bbl" means a barrel of 42 U.S. gallons.
"Bcf" means billion cubic feet.
"BOE" means barrels of oil equivalent, converting volumes of natural gas to oil
equivalent volumes using a ratio of six Mcf of natural gas to one Bbl of oil.
22
<PAGE>
"completion" means the installation of permanent equipment for the production of
oil or gas.
"development well" means a well drilled within the proved area of an oil or gas
reservoir to the depth of a stratigraphic horizon known to be productive.
"dry hole" or "dry well" means a well found to be incapable of producing
hydrocarbons in sufficient quantities such that proceeds from the sale of such
production exceed production expenses and taxes.
"exploratory well" means a well drilled to find and produce oil or gas reserves
not classified as proved, to find a new production reservoir in a field
previously found to be productive of oil or gas in another reservoir or to
extend a known reservoir.
"farm-in" means an agreement pursuant to which the owner of a working interest
in an oil and gas lease assigns the working interest or a portion thereof to
another party who desires to drill on the leased acreage. Generally, the
assignee is required to drill one or more wells in order to earn its interest in
the acreage. The assignor usually retains a royalty or reversionary interest in
the lease. The interest received by an assignee is a "farm-in."
"gas" means natural gas.
"gross" when used with respect to acres or wells, refers to the total acres or
wells in which the Company has a working interest.
"infill drilling" means drilling of an additional well or wells provided for by
an existing spacing order to more adequately drain a reservoir.
"MBbl" means thousand Bbls.
"MBOE" means thousand BOE.
"Mcf" means thousand cubic feet.
"MMBOE" means million BOE.
"MMBtu" means one million British Thermal Units. British Thermal Unit means the
quantity of heat required to raise the temperature of one pound of water by one
degree Fahrenheit.
"MMcf" means million cubic feet.
"net" when used with respect to acres or wells, refers to gross acres or wells
multiplied, in each case, by the percentage working interest owned by the
Company.
"net production" means production that is owned by the Company less royalties
and production due others.
"NGL" means natural gas liquid.
"operator" means the individual or company responsible for the exploration,
development and production of an oil or gas well or lease.
"Present Value" when used with respect to oil and gas reserves, means the
estimated future gross revenues to be generated from the production of proved
reserves calculated in accordance with the guidelines of the SEC, net of
estimated production and future development costs, using prices and costs as of
the date of estimation without future escalation (except to the extent a
contract specifically provides otherwise), without giving effect to non-property
related expenses such as general and administrative expenses, debt service,
future income tax expense and depreciation, depletion and amortization, and
discounted using an annual discount rate of 10%.
23
<PAGE>
"productive wells" or "producing wells" consist of producing wells and wells
capable of production, including wells waiting on pipeline connections.
"proved developed reserves" means reserves that can be expected to be recovered
through existing wells with existing equipment and operating methods. Additional
oil and gas expected to be obtained through the application of fluid injection
or other improved recovery techniques for supplementing the natural forces and
mechanisms of primary recovery will be included as "proved developed reserves"
only after testing by a pilot project or after the operation of an installed
program has confirmed through production response that increased recovery will
be achieved.
"proved reserves" means the estimated quantities of crude oil, natural gas and
NGLs which upon analysis of geological and engineering data appear with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions, i.e., prices and costs as of
the date the estimate is made. Prices include consideration of changes in
existing prices provided only by contractual arrangements, but not on
escalations based upon future conditions.
(i) Reservoirs are considered proved if economic producibility is supported
by either actual production or conclusive formation tests. The area of
a reservoir considered proved includes (A) that portion delineated by
drilling and defined by gas-oil and/or oil-water contacts, if any; and
(B) the immediately adjoining portions not yet drilled, but which can
be reasonably judged as economically productive on the basis of
available geological and engineering data. In the absence of
information on fluid contacts, the lowest known structural occurrence
of hydrocarbons controls the lower proved limit of the reservoir.
(ii) Reserves which can be produced economically through application of
improved recovery techniques (such as fluid injection) are included in
the "proved" classification when successful testing by a pilot project,
or the operation of an installed program in the reservoir, provides
support for the engineering analysis on which the project or program
was based.
(iii) Estimates of proved reserves do not include the following: (A) oil that
may become available from known reservoirs but is classified separately
as "indicated additional reserves"; (B) crude oil, natural gas and
NGLs, the recovery of which is subject to reasonable doubt because of
uncertainty as to geology, reservoir characteristics or economic
factors; (C) crude oil, natural gas, and NGLs, that may occur in
undrilled prospects; and (D) crude oil, natural gas and NGLs that may
be recovered from oil shales, coal, gilsonite and other such resources.
"proved undeveloped reserves" means reserves that are expected to be recovered
from new wells on undrilled acreage, or from existing wells where a relatively
major expenditure is required for completion. Reserves on undrilled acreage
shall be limited to those drilling units offsetting productive units that are
reasonably certain of production when drilled. Proved reserves for other
undrilled units can be claimed only where it can be demonstrated with certainty
that there is continuity of production from the existing productive formation.
Under no circumstances should estimates for proved undeveloped reserves be
attributable to any acreage for which an application of fluid injection or other
improved recovery technique is contemplated, unless such techniques have been
proved effective by actual tests in the area and in the same reservoir.
"recompletion" means the completion for production of an existing well bore in
another formation from that in which the well has been previously completed.
"reserves" means proved reserves.
"reservoir" means a porous and permeable underground formation containing a
natural accumulation of producible oil and/or gas that is confined by
impermeable rock or water barriers and is individual and separate from other
reservoirs.
24
<PAGE>
"royalty" means an interest in an oil and gas lease that gives the owner of the
interest the right to receive a portion of the production from the leased
acreage (or of the proceeds of the sale thereof), but generally does not require
the owner to pay any portion of the costs of drilling or operating the wells on
the leased acreage. Royalties may be either landowner's royalties, which are
reserved by the owner of the leased acreage at the time the lease is granted, or
overriding royalties, which are usually reserved by an owner of the leasehold in
connection with a transfer to a subsequent owner.
"2-D seismic" means an advanced technology method by which a cross-section of
the earth's subsurface is created through the interpretation of reflecting
seismic data collected along a single source profile.
"3-D seismic" means an advanced technology method by which a three dimensional
image of the earth's subsurface is created through the interpretation of
reflection seismic data collected over surface grid. 3-D seismic surveys allow
for a more detailed understanding of the subsurface than do conventional surveys
and contribute significantly to field appraisal, development and production.
"working interest" means an interest in an oil and gas lease that gives the
owner of the interest the right to drill for and produce oil and gas on the
leased acreage and requires the owner to pay a share of the costs of drilling
and production operations. The share of production to which a working interest
owner is entitled will always be smaller than the share of costs that the
working interest owner is required to bear, with the balance of the production
accruing to the owners of royalties.
"workover" means operations on a producing well to restore or increase
production.
Item 2. Properties
The information required by this Item is contained in Item 1. Business, and is
incorporated herein by reference.
Item 3. Legal Proceedings
The Company and its subsidiaries and affiliates are named defendants in lawsuits
and are involved in governmental proceedings from time to time, all arising in
the ordinary course of business. Although the outcome of these lawsuits and
proceedings cannot be predicted with certainty, management does not expect these
matters to have a material adverse effect on the financial position of the
Company.
Item 4. Submission of Matters to a Vote of Security Holders
No matters were submitted to security holders during the fourth quarter of the
year ended December 31, 1998.
25
<PAGE>
PART II
Item 5. Market for Registrant's Common Equity and Related Stockholder Matters
The Common Stock is traded on the New York Stock Exchange under the symbol WZR.
The quarterly high and low sales prices and dividends per share of Common Stock
during the three years ended December 31, 1999, were as follows:
<TABLE>
<CAPTION>
High Low Dividends
------ ------ ---------
<S> <C> <C> <C>
1999
First Quarter......................... $ 3.13 $ 1.44 $0.00
Second Quarter........................ 4.88 2.00 0.00
Third Quarter......................... 4.81 2.88 0.00
Fourth Quarter........................ 4.13 2.25 0.00
1998
First Quarter......................... $14.25 $11.75 $0.03
Second Quarter........................ 13.25 8.75 0.03
Third Quarter......................... 12.50 5.00 0.03
Fourth Quarter........................ 5.75 1.63 0.03
1997
First Quarter......................... $22.38 $17.63 $0.03
Second Quarter........................ 18.88 15.13 0.03
Third Quarter......................... 18.75 14.06 0.03
Fourth Quarter........................ 18.75 13.06 0.03
</TABLE>
At February 24, 20000, there were 8,951,965 shares of Common Stock outstanding
held by approximately 800 shareholders of record and approximately 3,700
beneficial owners.
Each share of Common Stock also represents one preferred stock purchase right
which entitles the holder thereof to purchase from the Company one-one
thousandth of a share (a "Unit") of Series B Preferred Stock of the Company at
an exercise price of $72.00 per Unit.
On December 10, 1998, the Board of Directors approved a cost reduction plan
which included suspending payments of cash dividends on the Company's common
stock. In addition, under the terms of the BankOne Revover (see Note 4 to the
Company's Consolidated Financial Statements) the payment of dividends is
prohibited.
26
<PAGE>
Item 6. Selected Financial Data
The following selected consolidated financial data of the Company are derived
from information contained in the Company's consolidated financial statements.
The selected consolidated financial and operating data presented below should be
read in conjunction with "Management's Discussion and Analysis of Financial
Condition and Results of Operations" and the Company's Consolidated Financial
Statements and notes thereto included elsewhere in this Report.
<TABLE>
<CAPTION>
Year Ended December 31,
---------------------------------------------------
1999 1998 1997 1996 1995
-------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C>
Income Statement Data (000's except per share amounts):
Revenues:
Oil and gas sales...................................... $ 47,602 $ 59,197 $ 76,729 $ 72,012 $ 54,400
Dividends and interest................................. 739 269 1,113 683 1,241
Marketable security sales gains........................ -- -- 7,495 12,977 13,101
Other.................................................. 4,453 1,942 2,478 1,017 2,939
-------- -------- -------- -------- --------
Total revenues....................................... 52,794 61,408 87,815 86,689 71,681
-------- -------- -------- -------- --------
Costs and expenses:
Production and operating............................... 21,111 26,529 27,183 23,970 20,690
Purchased natural gas.................................. 336 1,440 1,622 1,462 727
Depreciation, depletion and amortization ("DD&A")...... 17,663 25,811 22,977 19,653 19,778
Property impairments................................... 2,214 3,838 3,289 12,112 4,893
Exploration............................................ 7,059 15,328 9,655 4,176 5,801
General and administrative............................. 6,816 10,571 9,661 9,364 8,193
Interest expense....................................... 13,310 13,097 9,845 5,452 5,618
-------- -------- -------- -------- --------
Total costs and expenses............................. 68,509 96,614 84,232 76,189 65,700
-------- -------- -------- -------- --------
Earnings (loss) before income taxes...................... (15,715) (35,206) 3,583 10,500 5,981
Income tax expense (benefit)............................. (859) (10,740) 264 4,072 3,788
-------- -------- -------- -------- --------
Net income (loss)........................................ $(14,856) $(24,466) $ 3,319 $ 6,428 $ 2,193
======== ======== ======== ======== ========
Average outstanding shares (000's) (1)................... 8,952 8,952 8,949 8,939 8,939
Basic earnings (loss) per share.......................... $ (1.66) $ (2.73) $ 0.37 $ 0.72 $ 0.25
Cash dividends per share................................. $ 0.00 $ 0.12 $ 0.12 $ 0.12 $ 0.40
Other Financial Data (000's):
EBITDA (2)............................................... $ 23,792 $ 22,599 $ 40,741 $ 38,233 $ 27,729
Operating cash flows..................................... 6,478 (3,316) 26,372 33,228 19,239
Capital expenditures..................................... 8,327 29,980 70,209 46,056 28,851
Balance Sheet Data - end of period (000's):
Cash and cash equivalents................................ $ 21,447 $ 2,779 $ 13,255 $ 5,870 $ 1,397
Working capital (3)...................................... 17,875 (19,911) 7,809 3,493 1,034
Marketable securities.................................... -- -- -- 7,176 19,592
Net property and equipment............................... 159,973 213,295 220,708 179,718 169,089
Total assets............................................. 196,726 231,810 254,556 208,617 203,407
Long-term debt........................................... 124,526 124,452 124,304 78,654 74,171
Stockholders' equity..................................... 57,141 72,091 97,424 99,262 101,132
</TABLE>
27
<PAGE>
<TABLE>
<CAPTION>
Year Ended December 31,
----------------------------------------------------
1999 1998 1997 1996 1995
-------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C>
Reserve and Operating Data:
Production and volumes:
Oil and NGLs (MBbl)............................................ 1,933 2,715 2,760 2,776 2,332
Gas (MMcf) (4)................................................. 10,248 14,364 12,829 12,288 12,171
BOE (000's) (4).............................................. 3,641 5,109 4,898 4,824 4,361
Weighted average sales prices (5):
Oil (per Bbl).................................................. $ 15.18 $ 12.46 $ 18.02 $ 18.81 $ 16.91
Gas (per Mcf).................................................. 1.83 1.84 2.21 1.77 1.37
NGLs (per Bbl)................................................. 13.01 9.25 13.87 13.36 10.11
BOE (per Bbl)................................................ 11.59 11.59 15.66 14.93 12.47
Selected expenses per BOE (6):
Lease operating................................................ $ 5.07 $ 4.45 $ 4.65 $ 4.14 $ 4.06
Production taxes............................................... 0.77 0.84 1.02 0.93 0.78
DD&A........................................................... 4.88 5.15 4.79 4.16 4.62
General and administrative..................................... 1.88 1.96 2.02 1.98 1.92
Proved reserves (end of year) (7):
Oil and NGLs (MBbls)........................................... 25,430 27,988 29,721 31,612 32,208
Gas (MMcf)..................................................... 69,993 119,981 120,094 113,377 109,915
BOE (MBbls).................................................. 37,095 47,985 49,737 50,508 50,527
Estimated future net revenues before income taxes (000's)...... $419,668 $218,969 $359,293 $705,723 $401,037
Present Value.................................................. 222,539 123,831 210,087 414,314 235,416
Standardized Measure (000's) (8)............................... 176,916 113,232 174,489 317,180 194,602
Weighted average sales prices (end of year) (7)(9):
Oil (per Bbl).................................................. $ 23.76 $ 10.39 $ 15.92 $ 24.63 $ 18.19
Gas (per Mcf).................................................. 1.99 1.98 2.35 3.45 1.84
NGLs (per Bbl)................................................. 19.11 8.44 11.40 19.79 12.87
</TABLE>
(1) Basic earnings per share is calculated without including dilutive effect of
common stock equivalents consisting of stock options. See Note 12 to the
Company's Consolidated Financial Statements.
(2) EBITDA is not a generally accepted accounting measure, but is presented as a
supplemental financial indicator of the Company's ability to service or
incur debt. EBITDA is calculated by adding interest expense, income tax
expense, depreciation, depletion and amortization, property impairment costs
and exploration costs to net income (excluding marketable security sales
gains and dividends and interest). EBITDA should not be considered in
isolation or as a substitute for net income, operating cash flows or any
other measure of financial performance prepared in accordance with generally
accepted accounting principles or as a measure of the Company's
profitability or liquidity.
(3) Working capital represents the difference between current assets and current
liabilities.
(4) Calculated by including volumes of natural gas purchased for resale as
follows: 1999 - 148 MMcf, 1998 - 608 MMcf, 1997 - 629 MMcf, 1996 - 605 MMcf
and 1995 - 500 MMcf.
(5) Reflects results of hedging activities. See Item 7A - "Quantitative and
Qualitative Disclosures about Market Risk."
(6) Calculated without including volumes of natural gas purchased for resale.
(7) Estimates of proved reserves and future net revenues from which Present
Values are derived are based on year end prices of oil and gas held constant
(except to the extent a contract specifically provides otherwise) in
accordance with SEC regulations.
(8) The Standardized Measure of Discounted Future Net Cash Flows prepared by the
Company represents the present value (using an annual discount rate of 10%)
of estimated future net revenues from the production of proved reserves,
after giving effect to income taxes. See the Supplemental Financial
Information attached to the Company's Consolidated Financial Statements
included elsewhere in this Report for additional information regarding the
disclosure of the Standardized Measure of Discounted Future Net Cash Flows.
(9) Year end prices used to estimate proved reserves and future net revenues
from which Present Values are derived. See footnotes 7 and 8 above.
28
<PAGE>
Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations
The following discussion is intended to assist in an understanding of the
Company's historical financial position and results of operations for each year
in the three-year period ended December 31, 1999. The Company's Consolidated
Financial Statements and notes thereto included elsewhere in this Report contain
detailed information that should be referred to in conjunction with the
following discussion.
General
The Company's future results of operations and growth are substantially
dependent upon (i) its ability to acquire or find and successfully develop
additional oil and gas reserves and (ii) the prevailing prices for oil and gas.
At December 31, 1999, the Company's proved reserves were comprised of
approximately 95% proved developed reserves, and the Company does not have a
large inventory of development drilling locations or enhanced recovery projects
to pursue after 1999. If the Company is unable to economically acquire or find
significant new reserves for development and exploitation, the Company's oil and
gas production, and thus its revenues, would likely decline gradually as its
reserves are produced. In addition, oil and gas prices are dependent upon
numerous factors beyond the Company's control, such as economic, political and
regulatory developments and competition from other sources of energy. The oil
and gas markets have historically been very volatile. In particular, oil prices
during 1998 were at their lowest levels since 1986. As a result, the Company's
results of operations were adversely affected. During the last half of 1999 and
early 2000, oil prices increased significantly from 1998. Any significant and
extended decline in the price of oil or gas would have a material adverse effect
on the Company's financial condition and results of operations, and could result
in a reduction in the carrying value of the Company's proved reserves and
adversely affect its access to capital.
The Company completed the liquidation of its marketable securities portfolio in
1997 and used the proceeds from the sale of its marketable securities to fund a
portion of the Company's capital and exploration expenditures in 1997. The
Company recognized pretax gains from the sale of marketable securities of $7.5
million in 1997. In the absence of such gains, the Company would have reported
net losses in 1997.
SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-
Lived Assets to Be Disposed Of," requires the Company to assess the need for an
impairment of capitalized costs of proved oil and gas properties and the costs
of wells and related equipment and facilities on a property-by-property basis.
Applying SFAS No. 121, the Company recognized non-cash property impairment
charges of $2.2 million in 1999, $3.8 million in 1998 and $3.3 million in 1997.
Subsequent Event
As described in Note 13 to the Company's Consolidated Financial Statements, the
Company and Wiser Investment Company, LLC ("WIC") have entered into an Amended
and Restated Stock Purchase Agreement and an Amended and Restated Warrant
Purchase Agreement providing for, among other things, the issuance and sale by
the Company to WIC of up to 1,000,000 Preferred Shares at a purchase price of
$25.00 per share and the issuance of Warrants to purchase up to that number of
shares of Common Stock representing approximately 5% of the outstanding shares
of Common Stock at any given time.
Results of Operations
Production information presented below includes volumes of natural gas purchased
for resale; however, per unit of production information with respect to
production and operating expenses, depreciation, depletion and amortization and
general and administrative costs is calculated without including such volumes.
Such volumes were 148 MMcf in 1999, 608 MMcf in 1998 and 629 MMcf in 1997.
29
<PAGE>
Comparison of 1999 to 1998
In April and May 1999, the Company entered into three separate agreements to
sell its oil and gas properties in the Appalachia area, certain oil and gas
properties in Texas and New Mexico and virtually all of its oil and gas royalty
interests in the United States ("Second Quarter Property Sales"). The Second
Quarter Property Sales were closed in April and May 1999 for an aggregate sales
price of $42.3 million before fees and adjustments, and represented
approximately 19% of the Company's proved reserves as of December 31, 1998. The
Company recognized a net gain of $3.4 million in 1999 from the Second Quarter
Property Sales and the revenues and expenses associated with the sold properties
are included in the Company's consolidated statements of income through the
various closing dates.
The following table sets forth the production, oil and gas revenues, production
and operating expenses and purchased gas related to the Second Quarter Property
Sales for the years ended December 31,1999 and 1998 (000's):
<TABLE>
<CAPTION>
1999 1998
------ -------
<S> <C> <C>
Oil production (Bbls)................. 56 224
Gas production (Mcf).................. 1,215 4,189
NGL production (Bbls)................. 16 69
BOE production (Bbls)................. 275 991
Oil and gas revenues.................. $3,162 $12,969
Production and operating expenses..... 1,142 4,625
Purchased gas......................... 336 1,440
</TABLE>
Revenues
Oil and gas sales decreased $11.6 million or 20% to $47.6 million in 1999 from
$59.2 million in 1998, due to the Second Quarter Property Sales, which accounted
for $9.8 million of the decrease and also due to lower oil and gas production
which was partially offset by higher oil and NGL prices. Oil production in 1999
was 709 MBbls lower than 1998 oil production, with 89% of the decrease
attributed to lower oil production from the Maljamar field in New Mexico of 249
MBbls, lower oil production in Canada of 217 MBbls, primarily attributable to
the Evi and Provost fields, and a reduction of 168 MBbls related to the Second
Quarter Property Sales . The average oil price received in 1999 increased 22% to
$15.18 per Bbl from $12.46 per Bbl in 1998. Gas production during 1999 decreased
29% to 10.2 Bcf from 14.4 Bcf in 1998. Approximately 21% of the decrease in gas
production was attributable to the Second Quarter Property Sales and
approximately 3% of the decrease in gas production was due to lower gas
production in South Texas, which was 499 MMcf lower than 1998. The average gas
price received in 1999 was $1.83 per Mcf or $0.01 less than 1998. As a result
of hedging activities, oil and gas sales were decreased by $3.6 million in 1999
and increased by $0.2 million in 1998. On an equivalent unit basis, total
production decreased 29% to 3,641 MBOE in 1999 from 5,109 MBOE in 1998.
Dividends and interest increased 133% to $0.7 million in 1999 compared to $0.3
million in 1998 as a result of higher interest income earned on the net proceeds
from the Second Quarter Property Sales which were invested in short-term
investments.
Pension plan curtailment gain of $0.8 million in 1998 was recognized as a
result of amendments to the Company's pension plan in December 1998 which
curtailed certain pension benefits. There were no such amendments in 1999.
Gain on sales of properties were $3.6 million in 1999 compared to $0.6 million
in 1998 due to the Second Quarter Property Sales as discussed above. Property
sales in 1998 consisted of several non-strategic oil and gas properties.
30
<PAGE>
Costs and Expenses
Production and operating expense decreased 20% to $21.1 million in 1999 from
$26.5 million in 1998 primarily due to the Second Quarter Property Sales, which
reduced production and operating expenses by $3.5 million in 1999, and also due
to cost cutting measures implemented at the Maljamar field which reduced
production and operating expenses in 1999 by $1.5 million compared to 1998. On a
BOE basis, production and operating expense increased 10% to $5.84 per BOE in
1999 from $5.29 per BOE in 1998 primarily as a result of higher production and
operating expenses per BOE at the Maljamar and Wellman fields and the Second
Quarter Property Sales which included properties with a lower than average
production and operating expense per BOE.
Purchase natural gas decreased 79% to $0.3 million in 1999 from $1.4 million in
1998 due to the Second Quarter Property Sales.
DD&A decreased $8.1 million or 31% to $17.7 million in 1999 from $25.8 million
in 1998 and DD&A per BOE decreased 5% to $4.88 per BOE in 1999 from $5.15 per
BOE in 1998. U.S. DD&A decreased $5.9 million, due primarily to the Second
Quarter Property Sales, and Canadian DD&A decreased $2.2 million.
Impairment expense decreased 42% to $2.2 million in 1999 from $3.8 million in
1998. Impairment expense in 1999 was resulted from lower than expected reserve
estimates for certain properties and impairment expense in 1998 was due
primarily to unusually low oil prices used to value reserves at year-end 1998.
Exploration expense decreased 54% to $7.1 million in 1999 from $15.3 million in
1998 as the Company significantly curtailed its exploration activities in 1999
due to low oil prices experienced in 1998 and the first quarter of 1999. Dry
hole expense decreased 79% to $1.3 million in 1999 from $6.1 million in 1998.
Geological and geophysical expenses in 1999 were $0.8 million, down 76% from
$3.4 million in 1998.
General and administrative expense ("G&A") decreased 36% to $6.8 million in 1999
from $10.6 million in 1998 and G&A per BOE decreased 4% to $1.88 per BOE in 1999
from $1.96 per BOE in 1998. The decrease in G&A was attributable in part to an
informal cost reduction program that was implemented by the Company in December
1998 that involved reducing its workforce by approximately 36% and reducing
other discretionary administrative expenses. In connection with this cost
reduction program, the Company recognized approximately $545,000 of employee
severance expense in 1998.
Income tax benefit decreased $9.8 million to a tax benefit of $0.9 million in
1999 from a tax benefit of $10.7 million in 1998. The Company had a net
operating loss carryforward of approximately $16 million at December 31, 1999
and since full realization of the future tax benefits of the net operating loss
carryforward was determined by the Company to not be "more likely than not" at
December 31, 1999, only $0.9 million of income tax benefit was recognized in
1999.
Net loss decreased $9.6 million to a net loss of $14.9 million in 1999 from a
net loss of $24.5 million in 1998 as total costs and expenses and income taxes
for 1999 were $18.2 million lower than 1998 and total revenues for 1999 were
only $8.6 million lower than 1998.
Comparison of 1998 to 1997
Revenues
31
<PAGE>
Oil and gas sales decreased $17.5 million or 23% to $59.2 million in 1998 from
$76.7 million in 1997, as lower oil and gas prices decreased oil and gas sales
by $19.8 million which was offset by $2.3 million attributed to higher gas and
NGL production. The average oil price received in 1998 decreased 31% to $12.46
per Bbl from $18.02 per Bbl in 1997 and the average gas price received in 1998
decreased 17% to $1.84 per Mcf from $2.21 per Mcf in 1997. Gas production
during 1998 increased 12% to 14.4 Bcf from 12.8 Bcf in 1997. The increase in
gas production was primarily attributable to the Welder Ranch field in South
Texas which produced 2.3 Bcf of gas during 1998 compared to 0.8 Bcf of gas in
1997. The Welder Ranch field was acquired in June 1997. Oil production in 1998
decreased 2% to 2,393 MBbls from 2,441 MBbls in 1997. As a result of
development activity in 1997 and 1998, oil production in 1998 from the Evi and
Provost fields in Canada was 88 MBbls and 150 MBbls higher than 1997,
respectively. Oil production from the Maljamar and Wellman fields in 1998 was
102 MBbls and 70 MBbls lower than 1997, respectively, as development activities
at these fields was substantially complete in 1997. As a result of hedging
activities, oil and gas sales were increased by $0.2 million in 1998 and reduced
by $2.4 million during 1997. On an equivalent unit basis, total production
increased 4% to 5,109 MBOE in 1998 from 4,898 MBOE in 1997.
Dividends and interest decreased 76% to $0.3 million in 1998 compared to $1.1
million in 1997 as the Company completed the liquidation of its remaining
marketable securities in 1997.
Marketable security sales gains were $7.5 million in 1997 as the Company
completed the liquidation of its remaining marketable securities in 1997.
Pension plan curtailment gain of $0.8 million in 1998 was recognized as a
result of amendments to the Company's pension plan in December 1998 which
curtailed certain pension benefits. There were no such amendments in 1997.
Costs and Expenses
Production and operating expense decreased 2% to $26.5 million in 1998 from
$27.2 million in 1997 primarily due to a decrease of $0.7 million in production
taxes associated with lower oil and gas sales in 1998. On a BOE basis,
production and operating expense decreased 7% to $5.29 per BOE in 1998 from
$5.67 per BOE in 1997 as a result of higher BOE production and lower production
taxes in 1998.
DD&A increased 12% to $25.8 million in 1998 from $23.0 million in 1997 and
increased 8% to $5.15 per BOE in 1998 from $4.79 per BOE in 1997. The increases
were primarily attributable to additional wells drilled at the Maljamar field
combined with increased depletion from the Welder field in South Texas.
Impairment expense increased 17% to $3.8 million in 1998 from $3.3 million in
1997. Impairment expense in 1998 and 1997 was due primarily to low oil prices
used to value reserves at year-end 1998 and year-end 1997.
Exploration expense increased 59% to $15.3 million in 1998 from $9.7 million in
1997 as the Company increased its exploration activities during 1998. Dry hole
expense increased 49% to $6.1 million in 1998 from $4.1 million in 1997 and
included dry hole expense of $1.6 million in Peru and $2.0 million in South
Texas during 1998. Surrendered and abandoned lease expense in 1998 increased
227% to $4.9 million from $1.5 million in 1997 primarily as a result of
increased lease abandonment expense associated with unsuccessful exploration
drilling in 1998 and the curtailment of exploration activities due to low oil
prices.
G&A increased 9% to $10.6 million in 1998 from $9.7 million in 1997 and
increased 4% to $2.11 per BOE in 1998 from $2.02 per BOE in 1997. The increase
in G&A was attributable primarily to an informal cost reduction program that was
implemented by the Company in December 1998 that involved reducing its workforce
by approximately 36% and reducing other discretionary administrative expenses.
In connection with this cost reduction program, the Company recognized $545,000
of employee severance expense in 1998.
32
<PAGE>
Interest expense increased 33% to $13.1 million in 1998 from $9.8 million in
1997 due primarily to incurring a full year of interest expense in 1998 under
the 9 1/2% Senior Subordinated Notes ("2007 Notes"), which were issued in May
1997, and increased long-term debt in 1998 compared to 1997.
Income tax expense decreased $11.0 million to a benefit of $10.7 million in 1998
from tax expense of $0.3 million in 1997 primarily as a result of a decrease in
earnings before income taxes of $38.8 million.
Net income decreased $27.8 million to a net loss of $24.5 million in 1998 from
net income of $3.3 million in 1997 primarily as a result of lower oil and gas
prices and higher DD&A, exploration and interest expense in 1998.
Liquidity and Capital Resources
Cash flows
Cash flows from operating activities increased $9.8 million to $6.5 million in
1999 from a deficit of $3.3 million in 1998. The major factors contributing to
the increase in cash flows during 1999 were lower costs and expenses of $16.9
million offset by lower revenues of $11.6 million and changes in working capital
of $4.5 million from 1998 to 1999 that provided operating cash flows. The net
proceeds from the Second Quarter Property Sales of $41.0 million provided most
of the $32.7 million of cash flows from investing activities. Capital
expenditures were $8.3 million in 1999, a decrease of $21.7 million from $30.0
million in 1998. Capital expenditures were curtailed in 1999 as a result of low
oil prices in 1998 and the first quarter of 1999. The major components of
capital expenditures for 1999 were $5.4 million for development activities and
$2.7 million for exploration activities. Cash flows from financing activities in
1999 consisted of repaying $21 million of borrowings under the Credit Agreement,
formerly with NationsBank of Texas, N.A., and borrowing $0.5 million under the
Restated Credit Agreement with Bank One Texas, NA.
Financial Position
Cash and cash equivalents increased $18.7 million from $2.8 million at December
31, 1998 to $21.5 million at December 31, 1999. The increase was attributable
primarily to $41.0 million of sales proceeds from the Second Quarter Property
Sales less $20.5 million of repayments of long-term debt. Working capital of
$18.4 million at December 31, 1999 was $38.3 million higher than the working
capital deficit of $19.9 million at December 31, 1998 due primarily to increased
cash and cash equivalents of $18.7 million and the repayment of $21.0 million of
current portion of long-term debt. Net property and equipment decreased $53.3
million, of which $36.5 million is attributable to the Second Quarter Property
Sales. Total assets decreased $35.1 million during 1999 to $196.7 million at
December 31, 1999, and stockholders' equity decreased $15.0 million during 1999
to $57.1 million at December 31, 1999.
At December 31, 1999, capitalization totaled $182.1 million and consisted of
$125.0 million of long-term debt (69%) and $57.1 million of stockholders' equity
(31%).
Capital Sources
Funding for the Company's business activities has been provided by cash flow
from operations, borrowings and sales of marketable securities. The Company
completed the liquidation of its marketable securities in 1997 and, accordingly,
this source of funds is no longer available.
While the Company regularly engages in discussions relating to potential
acquisitions of oil and gas properties, the Company has no current agreement or
commitment with respect to any such acquisitions which would be material to the
Company. Any future acquisitions may require additional financing and will be
dependent upon financing arrangements available at the time.
33
<PAGE>
The Company entered into a Credit Agreement with a group of banks which provides
for the issuance of letters of credit and for revolving credit loans to the
Company (the "Credit Agreement"). On March 23, 1999, a financial institution
("New Lender") purchased all of the rights and obligations of the Credit
Agreement from Nations Bank of Texas, N.A. and the Bank of Montreal and became
the new Agent under the Credit Agreement.
In April 1999, the Company used $10 million of proceeds from the sale of oil and
gas properties to reduce the outstanding balance under the Credit Agreement to
$11 million. On May 10, 1999, the Company entered into a Restated Credit
Agreement with Bank One, Texas, N.A. (the "BankOne Revolver"). The Company
borrowed $11 million under the BankOne Revolver and repaid in full the
outstanding principal balance of $11 million under the Credit Agreement and the
Credit Agreement was terminated. Also in May 1999, the Company used $10.5
million of proceeds from the sale of oil and gas properties to reduce the
BankOne Revolver balance to $0.5 million.
The BankOne Revolver provides the Company with up to a $25 million line of
credit through April 30, 2001. The amounts available for borrowing are based on
the Company's oil and gas reserves and the Company's Borrowing Base at December
31, 1999 was $8 million. Available loan and interest options are (i) Prime Rate
Loans, at the bank's prime interest rate and (ii) Eurodollar Loans, at LIBOR
plus 2.5%, 2.75% or 3% depending on the percentage of the Borrowing Base
actually borrowed by the Company. The commitment fee on the unused Borrowing
Base is 0.5%. The BankOne Revolver imposes certain restrictions on sales of
assets, payment of dividends and incurrence of indebtedness and requires the
Company to, among other things, maintain certain financial ratios and make
monthly escrow deposits of $1.0 million to fund the semi-annual interest
payments on the 9 1/2% Senior Subordinated Notes. The Company is currently
negotiating certain amendments to the BankOne Revolver and, subject to the
completion of the negotiations, the Company has classified the entire $500,000
balance outstanding at December 31, 1999 as a current liability in the
Consolidated Balance Sheets.
On April 13, 1999, the Company entered into a Purchase and Sale Agreement with
Prince Minerals, Ltd. to sell certain producing and non-producing mineral
interests ("Mineral Properties") for $10 million effective April 1, 1999. The
sale closed on April 21, 1999. The producing portion of the oil and gas
properties comprising the Mineral Properties represented approximately 2% of the
Company's total proved oil and gas reserves at December 31, 1998. The sales
proceeds were used to reduce the outstanding balance under the Credit Agreement
to approximately $11 million.
On April 12, 1999, the Company entered into a Purchase and Sale Agreement with
Columbia Natural Resources to sell all of the Company's oil and gas properties
in Kentucky, Tennessee and West Virginia ("Appalachia Properties") for $28
million effective April 1, 1999. The sale closed on May 12, 1999. The oil and
gas properties comprising the Appalachia Properties represented approximately
15% of the Company's total proved oil and gas reserves at December 31, 1998. The
sales proceeds were used to reduce the outstanding balance under the Credit
Agreement to approximately $11 million, and for general corporate purposes.
In addition, the Company sold a number of smaller, non-strategic oil and gas
properties in Texas and New Mexico for an aggregate sales price of $4.3 million.
This sale closed on May 25, 1999. The sales proceeds from these properties were
used for general corporate purposes.
The Company believes that cash flows from operations and borrowings under the
BankOne Revolver will be sufficient to meet anticipated capital and exploration
expenditure requirements (excluding any material property acquisitions) in 2000.
If the Company's cash flows from operations and borrowings under the BankOne
Revolver are not sufficient to satisfy its capital and exploration expenditure
requirements, there is no assurance that additional equity or debt financing
will be available to meet such requirements.
34
<PAGE>
Capital and Exploration Expenditures
The Company requires capital primarily for the acquisition, development and
exploitation of, and the exploration for, oil and gas properties, the repayment
of indebtedness and general working capital needs. During 2000, subject to
market conditions and drilling and operating results, the Company expects to
spend approximately $15.0 million on acquisition, development, exploitation and
exploration activities.
Other Matters
Environmental and Other Regulatory Matters
The Company's business is subject to certain federal, state, provincial and
local laws and regulations relating to the development, exploitation, production
and gathering of, and the exploration for, oil and gas, including those relating
to the protection of the environment. Many of these laws and regulations have
become more stringent in recent years, often imposing greater liability on a
larger number of potentially responsible parties. Although the Company believes
it is in substantial compliance with all applicable laws and regulations, the
requirements imposed by laws and regulations are frequently changed and subject
to interpretation, and the Company is unable to predict the ultimate cost of
compliance with these requirements or their effect on its operations. Although
significant expenditures may be required to comply with governmental laws and
regulations applicable to the Company, compliance has not had a material adverse
effect on the earnings or competitive position of the Company.
Year 2000 Issue
Although the transition to the year 2000 did not have any significant impact on
the Company or its reporting systems and operations, the Company will continue
to assess the impact of the "Year 2000" ("Y2K") issue on its reporting systems
and those of its primary business partners, suppliers and vendors during the
Year 2000. The Y2K issue exists because many computer systems and applications
used two-digit date fields to designate a year, which meant that two-digit date
systems would recognize the year 2000 as 1900 or not at all. This inability to
recognize or properly treat the year 2000 may cause systems to process critical
financial and operational information incorrectly.
In 1998 and the first quarter of 1999, the Company's U.S. and Canadian
computerized accounting systems were upgraded to versions which are Y2K
compliant. These upgrades were completed at a nominal cost to the Company. In
addition, the Company's personal computer systems were analyzed for Y2K
compliance during 1998 and certain components were upgraded at a nominal cost to
the Company. Virtually all of the Company's personal computer systems are
currently Y2K compliant.
35
<PAGE>
New Accounting Standards
The Company adopted the following pronouncements in 1998:
SFAS No. 130, "Reporting Comprehensive Income" requires that all items that
are to be recognized under accounting standards as components of
comprehensive income be reported in a financial statement that is displayed
with the same prominence as other financial statements, and
SFAS No. 131, "Disclosures about Segments of an Enterprise and Related
Information" requires reporting of financial and descriptive information
about a company's reportable operating segments. The Company has identified
only one operating segment, which is the exploration for and production of
oil and gas.
In June 1998, the Financial Accounting Standards Board issued SFAS 133
"Accounting for Derivative Instruments and Hedging Activities" which is
effective for all fiscal years beginning after June 15, 2000 (January 1, 2001
for the Company). SFAS No. 133 requires that derivatives be reported on the
balance sheet at fair value and, if the derivative is not designated as a
hedging instrument, changes in fair value must be recognized in earnings in the
period of change. If the derivative is designated as a hedge and to the extent
such hedge is determined to be effective, changes in fair value are either
offset by the change in fair value of the hedged asset or liability (if
applicable) or reported as a component of other comprehensive income in the
period of change, and subsequently recognized in earnings when the offsetting
hedged transaction occurs. The definition of derivatives has also been expanded
to include contracts that require physical delivery of oil and gas if the
contract allows for net cash settlement. The Company currently uses derivatives
to hedge oil and gas price risk and gains or losses on such derivatives are
recorded as adjustments to oil and gas sales. Accordingly, adoption of SFAS No.
133 should not have a significant impact on reported earnings, but could have a
material impact on comprehensive income and the reported financial position of
the Company.
Disclosure Regarding Forward-Looking Statements
This Report includes "forward-looking statements" within the meaning of Section
27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act
of 1934. All statements other than statements of historical facts included in
this Report, including without limitation statements in this "Management's
Discussion and Analysis of Financial Condition and Results of Operations" and
under "Business" and "Properties" regarding proved reserves,
estimated future net revenues, Present Values, planned capital expenditures
(including the amount and nature thereof), increases in oil and gas production,
the number of wells anticipated to be drilled and the Company's financial
position, business strategy and other plans and objectives for future
operations, are forward-looking statements. Although the Company believes that
the expectations reflected in such forward-looking statements are reasonable,
there can be no assurance that the actual results or developments anticipated by
the Company will be realized or, even if substantially realized, that they will
have the expected consequences to or effects on its business or operations.
Among the factors that could cause actual results to differ materially from the
Company's expectations are the volatility of oil and gas prices, the ability to
acquire or find and successfully develop additional oil and gas reserves, the
uncertainty of estimates of reserves and future net revenues, risks relating to
acquisitions of producing properties, drilling and operating risks, general
economic conditions, competition, domestic and foreign government regulations
and other factors which are beyond the Company's control. All subsequent written
and oral forward-looking statements attributable to the Company or persons
acting on its behalf are expressly qualified in their entirety by such factors.
The Company assumes no obligation to update any such forward-looking statements.
36
<PAGE>
Item 7A. Quantitative and Qualitative Disclosures about Market Risk
The Company only uses derivative financial instruments such as commodity futures
agreements to hedge against fluctuations in oil and gas prices. Gains and losses
on these derivative instruments are recorded as adjustments to oil and gas
sales. The Board of Directors of the Company have adopted a policy governing the
use of derivative instruments which requires that all derivatives used by the
Company relate to an anticipated transaction and prohibits the use of
speculative or leveraged derivatives.
Interest Rate Risk
Total debt at December 31, 1999 included $124.5 million of fixed-rate debt and
$0.5 million of floating-rate debt attributed to borrowings under the BankOne
Revolver. As a result, the Company's annual interest cost will fluctuate based
on changes in short-term interest rates. The impact on annual cash flow of a 10%
change in the short-term interest rate (approximately 85 basis points) would be
less than $0.01 million.
At December 31, 1999, the estimated fair value of the Company's fixed-rate debt
of $125.0 million was $98.8 million. The fixed-rate debt will mature in May 2007
and the floating-rate debt will mature in May 2001.
Commodity Price Risk
The Company has in the past entered into and may in the future enter into
hedging arrangements with respect to portions of its oil, natural gas and NGL
production to reduce its sensitivity to volatile commodity prices. The Company
believes that hedging, although not free of risk, allows the Company to achieve
a more predictable cash flow and to reduce exposure to price fluctuations.
However, hedging arrangements limit the benefit to the Company of increases in
the prices of the hedged commodity. Moreover, the Company's hedging arrangements
apply only to a portion of its production and provide only partial price
protection against declines in prices. Such arrangements may expose the Company
to risk of financial loss in certain circumstances. The Company expects that the
amount of production it hedges will vary from time to time. During 1999, 1998
and 1997, the Company entered into various natural gas and crude oil forward
sale agreements, natural gas price swaps and oil price collar agreements to
hedge against price fluctuations. Oil and gas sales are adjusted for the effects
of hedging transactions as the underlying hedged production is sold. Adjustments
to oil and gas sales from the Company's hedging activities resulted in a
decrease in revenues of $3.6 million in 1999, an increase in revenues of $0.2
million in 1998 and a decrease in revenues of $2.4 million in 1997. Based on
December 31, 1999 NYMEX futures prices, the fair value of the Company's hedging
arrangements at December 31, 1999 was a loss of $1.2 million. A 10% increase in
both the oil price and the gas price would increase this loss by $3.0 million
and a 10% decrease in both the oil price and the gas price would decrease this
loss by $3.0 million.
37
<PAGE>
As of February 24, 2000 the Company's hedging arrangements were as follows:
<TABLE>
<CAPTION>
Period Daily Volume Price (Floor / Ceiling)
- ------ ------------ -----------------------
<S> <C> <C>
Crude Oil:
----------
January 1, 2000 to March 31, 2000 1,000 Bbls (1) $18.50 / 26.60 per Bbl
January 1, 2000 to March 31, 2000 2,700 Bbls $24.00 per Bbl
April 1, 2000 to June 30, 2000 3,500 Bbls $22.30 per Bbl
July 1, 2000 to September 30, 2000 3,400 Bbls $21.07 per Bbl
October 1, 2000 to December 31, 2000 3,300 Bbls $19.78 per Bbl
Natural Gas:
------------
February 1, 2000 to September 30, 2000 5,261 MMBTU (2) $2.29 per MMBTU (2)
February 1, 2000 to September 30, 2000 5,226 MMBTU (2)(3) $2.01 (Put) per MMBTU (2)
March 1, 2000 to September 30, 2000 5,174 MMBTU (2)(3) $2.20 (Put) per MMBTU (2)
</TABLE>
(1) The 1,000 Bbls per day crude oil hedge is a "collar" hedge whereby the
Company will receive the actual market price if the actual market price
is between the floor price of $18.50 per Bbl and the ceiling price of
$26.60 per Bbl. If the actual market price is below or above the floor or
ceiling prices, the price received by the Company will be limited to the
floor price or ceiling price, respectively.
(2) Average for period.
(3) The 5,226 MMBTU per day the and 5,174 MMBTU per day natural gas hedges
are "Put" agreements whereby the Company will receive the actual market
price if the actual market price is above the put prices of $2.01 and
$2.20 per MMBTU, respectively. If the actual market price is below the
put price, the price received by the Company will be limited to the put
price.
The Company continuously reevaluates its hedging program in light of market
conditions, commodity price forecasts, capital spending and debt service
requirements. Also see Note 1 to the Company's Consolidated Financial Statements
included elsewhere in this Report.
Foreign Currency Exchange Risk
The Company receives a substantial portion of its revenue in Canadian dollars
(29% in 1999). As a result, fluctuations in the exchange rates of the Canadian
dollar with respect to the U.S. dollar could have an adverse effect on the
Company's financial condition and results of operations. Historically however,
exchange rate fluctuations have not been material to the Company.
Item 8. Financial Statements and Supplementary Data
The Report of Independent Accountants, Consolidated Financial Statements and
supplementary financial data required by this Item are set forth on pages F-1
through F-20 of this Report and are incorporated herein by reference.
Item 9. Changes in and Disagreements With Accountants on Accounting and
Financial Disclosure
Not applicable.
38
<PAGE>
PART III
Item 10. Directors and Executive Officers of the Registrant
The information required by this Item will be contained in the Proxy Statement
under the headings "Election of Directors" and "Executive Officers" and is
incorporated herein by reference.
Item 11. Executive Compensation
The information required by this Item will be contained in the Proxy Statement
under the heading "Executive Compensation" and is incorporated herein by
reference.
Item 12. Security Ownership of Certain Beneficial Owners and Management
The information required by this Item will be contained in the Proxy Statement
under the heading "Beneficial Ownership of Common Stock" and is incorporated
herein by reference.
Item 13. Certain Relationships and Related Transactions
The information required by this Item, if any, will be contained in the Proxy
Statement under the heading "Executive Compensation" and is incorporated herein
by reference.
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K
A. Financial Statements
The following documents are filed as part of this Report:
1. Report of Independent Accountants
Consolidated Statements of Income
Consolidated Balance Sheets
Consolidated Statements of Changes in Stockholders' Equity
Consolidated Statements of Cash Flows
Notes to Consolidated Financial Statements
2. Schedules are omitted because of the absence of conditions under which
they are required or because the required information is given in the
financial statements or notes thereto.
B. Reports on Form 8-K.
The Company filed a report on Form 8-K on December 23, 1999 disclosing
under Item 5. thereof that the Company entered into a Stock Purchase
Agreement and Warrant Purchase Agreement, each dated as of December 13, 1999,
with Wiser Investment Company, LLC.
39
<PAGE>
C. Exhibits
Exhibits not incorporated herein by reference to a prior filing are designated
by an asterisk (*) and are filed herewith; all exhibits not so designated are
incorporated herein by reference as indicated.
Exhibit
Numbers
- -------
(3.1) Certificate of Incorporation of the Company, as amended, incorporated by
reference to Exhibit 4.2 to the Company's report on Form 8-K (Commission
File No. 0-5426), dated November 9, 1993 (Date of Event: October 25,
1993).
(3.2) Bylaws of the Company, as amended, incorporated by reference to Exhibit
4.3 to the Company's report on Form 8-K (Commission File No. 0-5426),
dated November 9, 1993 (Date of Event: October 25, 1993).
(4) Rights Agreement dated as of October 25, 1993 by and between the Company
and The Chase Manhattan Bank (as successor to Chemical Bank), as Rights
Agent, which includes as Exhibit 2 thereto the Form of Rights
Certificate, incorporated by reference to Exhibit 4.1 to the Company's
report on Form 8-K (Commission File No. 0-5426), dated November 9, 1993
(Date of Event: October 25, 1993).
(4a) First Amendment to Rights Agreement dated as of October 25, 1993 by and
between the Company and ChaseMellon Shareholder Services, L.L.C. (as
successor to Chemical Bank), as Rights Agent, incorporated by reference
to Exhibit 4.1 to the Company's report on Form 8 -K (Commission File No.
0-5426), dated December 23, 1999 (Date of Event: December 13, 1999).
(4.1) Indenture dated May 21, 1997, among the Company, certain subsidiaries of
the Company and Texas Commerce Bank National Association, as Trustee,
incorporated by reference to Exhibit 4.1 to the Company's Registration
Statement on Form S-4 (Commission File No. 333-29211), filed on June 13,
1997.
(4.2) Form of 9 1/2% Senior Subordinated Notes due 2007 (included in the
indenture filed as Exhibit 4.1), incorporated by reference to Exhibit 4.2
to the Company's Registration Statement on Form S-4 (Commission File No.
333-29211), filed on June 13, 1997.
(4.3) Registration Agreement dated May 21, 1997, among the Company, certain
subsidiaries of the Company and Salomon Brothers Inc., NationsBanc
Capital Markets, Inc. and Nesbitt Burns Securities Inc., as the Initial
Purchasers, incorporated by reference to Exhibit 4.3 to the Company's
Registration Statement on Form S-4 (Commission File No. 333-29211), filed
on June 13, 1997.
(4.4) Credit Agreement dated June 23, 1994 among The Wiser Oil Company and The
Wiser Oil Company of Canada, as Borrowers, and NationsBank of Texas, N.A.
(NationsBank), as Agent, and Certain Financial Institutions Listed on the
Signature Pages Thereto, as Banks, incorporated by reference to the
Exhibit 10.1 to the Company's report on Form 8-K (Commission File No.
0-5426), dated July 11, 1994 (Date of Event: July 11, 1994), as amended
on Form 8-K/A filed on August 17, 1994.
(4.5) First Amendment to Credit Agreement dated November 29, 1995 among The
Wiser Oil Company and The Wiser Oil Company of Canada, as Borrowers, and
NationsBank, as Agent, and Certain Financial Institutions Listed on the
Signature Pages Thereto, as Banks, incorporated by reference to Exhibit
4.5 to the Company's Registration Statement on Form S-4 (Commission File
No. 333-29211), filed on June 13, 1997.
40
<PAGE>
(4.6) Second Amendment to Credit Agreement dated May 20, 1997 among The Wiser
Oil Company and The Wiser Oil Company of Canada, Inc., as Borrowers, and
NationsBank, as Agent, and Certain Financial Institutions Listed on the
Signature Pages thereto, as Banks, incorporated by reference to Exhibit
4.6 to the Company's Registration Statement on Form S-4 (Commission File
No. 333-29211), filed on June 13, 1997.
(4.7) Guaranty Agreement dated May 20, 1997, by Wiser Oil Delaware, Inc., in
favor of NationsBank and PNC Bank, National Association ("PNC"),
incorporated by reference to Exhibit 4.7 to the Company's Registration
Statement on Form S-4 (Commission File No. 333-29211), filed on June 13,
1997.
(4.8) Guaranty Agreement dated May 20, 1997, by Wiser Delaware LLC, in favor
of NationsBank and PNC, incorporated by reference to Exhibit 4.8 to the
Company's Registration Statement on Form S-4 (Commission File No. 333-
29211), filed on June 13, 1997.
(4.9) Guaranty Agreement dated May 20, 1997, by The Wiser Marketing Company,
in favor of NationsBank and PNC, incorporated by reference to Exhibit
4.9 to the Company's Registration Statement on Form S-4 (Commission File
No. 333-29211), filed on June 13, 1997.
(4.10) Guaranty Agreement dated May 20, 1997, by The Wiser Oil Company of
Canada, in favor of NationsBank and PNC, incorporated by reference to
Exhibit 4.10 to the Company's Registration Statement on Form S-4
(Commission File No. 333-29211), filed on June 13, 1997.
(4.11) Guaranty Agreement dated May 20, 1997, by T.W.O.C., Inc., in favor of
NationsBank and PNC, incorporated by reference to Exhibit 4.11 to the
Company's Registration Statement on Form S-4 (Commission File No. 333-
29211), filed on June 13, 1997.
(4.13) Credit Agreement dated December 23, 1997 among The Wiser Oil Company, as
borrowers, and NationsBank of Texas, N.A., as agent, and The Financial
Institutions Listed on the Signature Pages thereto, as Banks,
incorporated by reference to Exhibit 4.13 to the Company's Annual Report
on Form 10-K for the year ended December 31, 1997.
(4.13a) First Amendment to Credit Agreement dated September 30, 1998 among The
Wiser Oil Company, as borrowers, and NationsBank of Texas, N.A., as
agent, and The Financial Institutions Listed on the Signature Pages
thereto, as Banks, incorporated by reference to Exhibit 4.13a to the
Company's Quarterly Report on Form 10-Q for the quarter ended September
30, 1998.
(4.13b) Second Amendment to Credit Agreement dated January 11, 1999 among The
Wiser Oil Company, as borrowers, and NationsBank of Texas, N.A., as
agent, and The Financial Institutions Listed on the Signature Pages
thereto, as Banks, incorporated by reference to Exhibit 4.13b to the
Company's Annual Report on Form 10-K for the year ended December 31,
1998.
(4.15) Restated Credit Agreement dated May 10, 1999 among The Wiser Oil
Company, as borrower, and Bank One Texas, N.A., as agent, and the
Institutions as listed on the signature pages thereto, as Banks,
incorporated by reference to Exhibit 4.15 to the Company's Quarterly
Report on Form 10-Q for the quarter ended June 30, 1999.
(10.3) Purchase and Sale Agreements made as of May 31, 1994 among Eagle
Resources Ltd., Caneagle Resources Corporation, The Erin Mills
Investment Corporation and The Wiser Oil Company, incorporated by
reference to Exhibit 10 to the Company's report on Form 8-K dated July
11, 1994 (Date of Event: July 11, 1994), as amended by Form 8-K/A filed
on August 17, 1994.
41
<PAGE>
(10.3a) Purchase and Sale Agreement dated April 12, 1999 between Columbia
Natural Resources, Inc. and The Wiser Oil Company, incorporated by
reference to Exhibit 10.3a to the Company's Annual Report on Form 10-
K for the year ended December 31, 1998.
(10.4) + Employment Agreement dated August 1, 1994 between the Company and
Allan J. Simus, incorporated by reference to Exhibit 10(d) to the
Company's Annual Report on Form 10-K for the year ended December 31,
1994.
(10.4a) + Amendment to Employment Agreement dated August 1, 1994 between the
Company and Alan J. Simus dated March 22, 1996, incorporated by
reference to Exhibit 10.4a to the Company's Annual Report on Form 10-
K for the year ended December 31, 1998.
(10.4b) + Second Amendment to Employment Agreement dated August 1, 1994 between
the Company and Alan J. Simus dated May 20, 1997, incorporated by
reference to Exhibit 10.4a to the Company's Annual Report on Form 10-
K for the year ended December 31, 1997.
(10.4c) + Third Amendment to Employment Agreement dated August 1, 1994 between
the Company and Alan J. Simus dated January 1, 1999, incorporated by
reference to Exhibit 10.4c to the Company's Annual Report on Form 10-
K for the year ended December 31, 1998.
(10.4d) + Fourth Amendment to Employment Agreement dated August 4, 1994 between
the Company and Alan J. Simus dated June 1, 1999, incorporated by
reference to Exhibit 10.4d to the Company's Quarterly Report on Form
10-Q for the quarter ended September 30, 1999.
(10.5) + Employment Agreement dated July 1, 1991 between the Company and
Andrew J. Shoup, Jr., incorporated by reference to Exhibit 10(a) to
the Company's Annual Report on Form 10-K for the year ended December
31, 1993.
(10.5a) + Amendment to Employment Agreement dated July 1, 1991 between the
Company and Andrew J. Shoup, Jr. dated June 1, 1994, incorporated by
reference to Exhibit 10.5a to the Company's Form 10-K for the year
ended December 31, 1998.
(10.5b) + Second Amendment to Employment Agreement dated July 1, 1991 between
the Company and Andrew J. Shoup, Jr. dated May 20, 1997, incorporated
by reference to Exhibit 10.5a to the Company's Annual Report on Form
10-K for the year ended December 31, 1997.
(10.5c) + Third Amendment to Employment Agreement dated July 1, 1991 between
the Company and Andrew J. Shoup, Jr. dated January 1, 1999,
incorporated by reference to Exhibit 10.5c to the Company's Annual
Report on Form 10-K for the year ended December 31, 1998.
(10.5d) + Fourth Amendment to Employment Agreement dated July 1, 1991 between
the Company and Andrew J. Shoup Jr. dated June 1, 1999, incorporated
by reference to Exhibit 10.5d to the Company's Quarterly Report on
Form 10-Q for the quarter ended September 30, 1999.
(10.6) + The Wiser Oil Company 1991 Stock Incentive Plan, as amended,
incorporated by reference to Exhibit 4.1 to the Company's
Registration Statement on Form S-8 (Commission File No. 33-62441),
filed on September 8, 1995.
(10.6a) + Amendment to The Wiser Oil Company 1991 Stock Incentive Plan,
incorporated by reference to the Company's Registration Statement on
Form S-8 (Commission File No. 333-29973), filed on June 25, 1997.
42
<PAGE>
(10.7) + The Wiser Oil Company 1991 Non-Employee Directors' Stock Option Plan,
as amended, incorporated by reference to Exhibit 99.1 to the
Company's Registration Statement on Form S-8 (Commission File No.
333-22525), filed on February 28, 1997.
(10.8) + Employment Agreement dated November 1, 1993 between the Company and
Lawrence J. Finn, incorporated by reference to Exhibit 10(b) to the
Company's Annual Report on Form 10-K for the year ended December 31,
1993.
(10.8a) + Amendment to Employment Agreement dated November 1, 1993 between the
Company and Lawrence J. Finn dated March 22, 1996, incorporated by
reference to Exhibit 10.8a to the Company's Annual Report on Form
10-K for the year ended December 31, 1998.
(10.8b) + Second Amendment to Employment Agreement dated November 1, 1993
between the Company and Lawrence J. Finn dated May 20, 1997,
incorporated by reference to Exhibit 10.8a to the Company's Annual
Report on Form 10-K for the year ended December 31, 1997.
(10.8c) + Third Amendment to Employment Agreement dated November 1, 1993
between the Company and Lawrence J. Finn dated January 1, 1999,
incorporated by reference to Exhibit 10.8c to the Company's Annual
Report on Form 10-K for the year ended December 31, 1998.
(10.8d) + Fourth Amendment to Employment Agreement dated November 1, 1991
between the Company and Lawrence J. Finn dated June 1, 1999,
incorporated by reference to Exhibit 10.8d to the Company's Quarterly
Report on Form 10-Q for the quarter ended September 30, 1999.
(10.9) + Employment Agreement dated January 24, 1994 between the Company and
A. Wayne Ritter, incorporated by reference to Exhibit 10(c) to the
Company's Annual Report on Form 10-K for the year ended December 31,
1993.
(10.9a) + Amendment to Employment Agreement dated January 24, 1994 between the
Company and A. Wayne Ritter dated March 22, 1996, incorporated by
reference to Exhibit 10.9a to the Company's Annual Report on Form
10-K for the year ended December 31, 1998.
(10.9b) + Second Amendment to Employment Agreement dated January 24, 1994
between the Company and A. Wayne Ritter dated May 20, 1997,
incorporated by reference to Exhibit 10.9a to the Company's Annual
Report on Form 10-K for the year ended December 31, 1997.
(10.9c) + Third Amendment to Employment Agreement dated January 24, 1994
between the Company and A. Wayne Ritter dated January 1, 1999,
incorporated by reference to Exhibit 10.9c to the Company's Annual
Report on Form 10-K for the year ended December 31, 1998.
(10.9d) + Fourth Amendment to Employment Agreement dated January 24, 1994
between the Company and A. Wayne Ritter dated June 1, 1999,
incorporated by reference to Exhibit 10.9d to the Company's Quarterly
Report on Form 10-Q for the quarter ended September 30, 1999.
(10.10) + Employment Agreement dated September 30, 1996 between the Company and
Kent E. Johnson, incorporated by reference to Exhibit 10.10 to the
Company's Annual Report on Form 10-K for the year ended December 31,
1996.
(10.10a)+ Amendment to Employment Agreement dated September 30, 1996 between
the Company and Kent E. Johnson dated May 20, 1997, incorporated by
reference to Exhibit 10.2 of the Company's Quarterly Report on Form
10-Q for the quarter ended June 30, 1997.
43
<PAGE>
(10.10b)+ Second Amendment to Employment Agreement dated September 30, 1996
between the Company and Kent E. Johnson dated January 1, 1999,
incorporated by reference to Exhibit 10.10b to the Company's Annual
Report on Form 10-K for the year ended December 31, 1998.
(10.11) + The Wiser Oil Company Equity Compensation Plan For Non-Employee
Directors, incorporated by reference to Exhibit 10.11 to the
Company's Annual Report on Form 10-K for the year ended December 31,
1996.
(10.12) The Wiser Oil Company Savings Restoration Plan dated February 24,
1998, incorporated by reference to Exhibit 10.12 to the Company's
Annual Report on Form 10-K for the year ended December 31, 1997.
(10.13) Retirement Restoration Plan dated March 23, 1995, incorporated by
reference to Exhibit 10.13 to the Company's Quarterly Report on Form
10-Q for the quarter ended June 30, 1998.
(10.14) +* The Wiser Oil Company 1997 Share Appreciation Rights Plan dated as of
August 19, 1997.
(10.14a)+* Amendment to the Wiser Oil Company 1997 Share Appreciation Rights
Plan dated May 18, 1999.
(10.15) Amended and Restated Stock Purchase Agreement dated as of December
13, 1999 between the Company and Wiser Investment Company, LLC,
incorporated by reference to Exhibit 10.1 to the Company's report on
Form 8-K (Commission File No. 0-5426), dated March 20, 2000 (Date of
Event: March 10, 2000).
(10.15) Amended and Restated Warrant Purchase Agreement dated as of December
13, 1999 between the Company and Wiser Investment Company, LLC,
incorporated by reference to Exhibit 10.2 to the Company's report on
Form 8-K (Commission File No. 0-5426), dated March 20, 2000 (Date of
Event: March 10, 2000).
(21) * Subsidiaries of registrant.
(23.1) * Consent of Independent Public Accountants.
(23.2) * Consent of DeGolyer and MacNaugton, Independent Petroleum Engineers.
(23.3) * Consent of Gilbert Laustsen Jung Associates Ltd., Independent
Petroleum Engineers.
(27) * Financial Data Schedule.
______________
+ Represent management compensatory plans or agreements.
* Filed herewith.
44
<PAGE>
SIGNATURES
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, on the 12th day of April
2000.
The Wiser Oil Company
By: /s/ Andrew J. Shoup, Jr.
-----------------------------------
Andrew J. Shoup, Jr.
President and Chief
Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons on behalf of the Registrant and
in the capacities and on the dates indicated.
<TABLE>
<CAPTION>
Signature Title Date
--------- ----- ----
<S> <C> <C>
/s/ ANDREW J. SHOUP, JR. President, Chief Executive April 12, 2000
- -------------------------------- Officer and Director
ANDREW J. SHOUP, JR. (Principal Executive
Officer)
/s/ C. FRAYER KIMBALL Director April 12, 2000
- --------------------------------
C. FRAYER KIMBALL
/s/ HOWARD G. HAMILTON Director April 12, 2000
- --------------------------------
HOWARD G. HAMILTON
/s/ A. W. SCHENCK, III Director April 12, 2000
- --------------------------------
A. W. SCHENCK, III
/s/ JOHN W. CUSHING, III Director April 12, 2000
- --------------------------------
JOHN W. CUSHING, III
/s/ JON L. MOSLE, JR. Director April 12, 2000
- --------------------------------
JON L. MOSLE, JR.
/s/ LORNE H. LARSON Director April 12, 2000
- --------------------------------
LORNE H. LARSON
/s/ LAWRENCE J. FINN Vice President and Chief April 12, 2000
- -------------------------------- Financial Officer
LAWRENCE J. FINN (Principal Financial and
Accounting Officer)
</TABLE>
45
<PAGE>
THE WISER OIL COMPANY
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
Page
----
<S> <C>
Report of Independent Public Accountants........................ F-2
Consolidated Statements of Income............................... F-3
Consolidated Balance Sheets..................................... F-4
Consolidated Statements of Changes in Stockholders' Equity...... F-5
Consolidated Statements of Cash Flows........................... F-6
Notes to Consolidated Financial Statements...................... F-7
</TABLE>
F-1
<PAGE>
Report of Independent Public Accountants
To the Shareholders of The Wiser Oil Company:
We have audited the accompanying consolidated balance sheets of The Wiser Oil
Company (a Delaware corporation) and subsidiaries as of December 31, 1999 and
1998, and the related consolidated statements of income, changes in
stockholders' equity, and cash flows for the years ended December 31, 1999, 1998
and 1997. These financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States. 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 consolidated financial position of The Wiser Oil
Company and subsidiaries as of December 31, 1999 and 1998, and the results of
their operations and their cash flows for the years ended December 31, 1999,
1998 and 1997, in conformity with accounting principles generally accepted in
the United States.
ARTHUR ANDERSEN LLP
Dallas, Texas,
February 24, 2000
F-2
<PAGE>
THE WISER OIL COMPANY
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31, 1999, 1998 and 1997
<TABLE>
<CAPTION>
1999 1998 1997
-------- -------- --------
(000's except per share data)
<S> <C> <C> <C>
Revenues:
Oil and gas sales......................... $ 47,602 $ 59,197 $76,729
Dividends and interest.................... 739 269 1,113
Marketable security sales................. -- -- 7,495
Gain on sales of properties............... 3,555 615 1,875
Pension plan curtailment gain............. -- 778 --
Other..................................... 898 549 603
-------------------------------
52,794 61,408 87,815
-------------------------------
Costs and Expenses:
Production and operating.................. 21,111 26,529 27,183
Purchased natural gas..................... 336 1,440 1,622
Depreciation, depletion and amortization.. 17,663 25,811 22,977
Property impairments...................... 2,214 3,838 3,289
Exploration............................... 7,059 15,328 9,655
General and administrative................ 6,816 10,571 9,661
Interest expense.......................... 13,310 13,097 9,845
-------------------------------
68,509 96,614 84,232
-------------------------------
Earnings (Loss) Before Income Taxes......... (15,715) (35,206) 3,583
Income Tax Expense (Benefit)................ (859) (10,740) 264
-------------------------------
NET INCOME (LOSS)........................... $(14,856) $(24,466) $ 3,319
===============================
Earnings (Loss) Per Share (Note 12):
Basic..................................... $ (1.66) $ (2.73) $ 0.37
===============================
Diluted................................... $ (1.66) $ (2.73) $ 0.37
===============================
Cash Dividends Per Share.................... $ -- $ 0.12 $ 0.12
===============================
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-3
<PAGE>
THE WISER OIL COMPANY
CONSOLIDATED BALANCE SHEETS
December 31, 1999 and 1998
<TABLE>
<CAPTION>
1999 1998
-------- --------
(000's)
<S> <C> <C>
Assets
Current Assets:
Cash and cash equivalents.................................. $ 21,447 $ 2,779
Restricted cash............................................ 992 --
Accounts receivable........................................ 9,565 9,102
Inventories................................................ 335 669
Income taxes receivable.................................... -- 1,270
Prepaid expenses........................................... 379 472
-----------------------
Total current assets.................................... 32,718 14,292
-----------------------
Property and Equipment, at cost:
Oil and gas properties (successful efforts method)......... 274,760 367,974
Other properties........................................... 3,781 5,523
-----------------------
278,541 373,497
Accumulated depreciation, depletion and amortization....... (118,568) (160,202)
-----------------------
Net property and equipment................................. 159,973 213,295
Other Assets................................................ 4,035 4,223
-----------------------
$ 196,726 $ 231,810
=======================
Liabilities and Stockholders' Equity
Current Liabilities:
Accounts payable........................................... $ 11,694 $ 10,473
Current portion of long-term debt.......................... 500 21,000
Accrued liabilities........................................ 2,649 2,730
-----------------------
Total current liabilities................................ 14,843 34,203
-----------------------
Long-term Debt.............................................. 124,526 124,452
Deferred Benefit Cost....................................... 216 378
Deferred Income Taxes....................................... -- 686
Stockholders' Equity:
Common stock - $3 par value; 20,000,000 shares authorized;
9,128,169 shares issued; 8,951,965 shares outstanding... 27,385 27,385
Paid-in capital............................................ 3,223 3,223
Retained earnings.......................................... 28,234 43,090
Foreign currency translation............................... 1,028 1,122
Treasury stock; 176,204 shares, at cost.................... (2,729) (2,729)
-----------------------
Total stockholders' equity............................... 57,141 72,091
-----------------------
$ 196,726 $ 231,810
=======================
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-4
<PAGE>
THE WISER OIL COMPANY
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY
For the Years Ended December 31, 1999, 1998 and 1997
<TABLE>
<CAPTION>
Marketable
Securities Foreign
Common Paid-in Retained Valuation Currency Treasury
Total Stock Capital Earnings Adjustment Translation Stock
-------- -------- ------- -------- ---------- ----------- --------
(000's)
<S> <C> <C> <C> <C> <C> <C> <C>
December 31, 1996................. $ 99,262 $ 27,347 $3,078 $ 66,385 $ 4,328 $ 853 $(2,729)
Net income...................... 3,319 -- -- 3,319 -- -- --
Other comprehensive income
(loss), net of tax........... (4,266) -- -- -- (4,328) 62 --
--------
Comprehensive income (loss)..... (947)
Stock options exercised......... 183 38 145 -- -- -- --
Dividends paid.................. (1,074) -- -- (1,074) -- -- --
-------- -------- ------- -------- ---------- ----------- --------
December 31, 1997................. 97,424 27,385 3,223 68,630 -- 915 (2,729)
Net income (loss)............... (24,466) -- -- (24,466) -- -- --
Other comprehensive income
(loss), net of tax........... 207 -- -- -- -- 207 --
--------
Comprehensive income (loss)..... (24,259)
Dividends paid.................. (1,074) -- -- (1,074) -- -- --
-------- -------- ------- -------- ---------- ----------- --------
December 31, 1998................. 72,091 27,385 3,223 43,090 -- 1,122 (2,729)
Net income (loss)............... (14,856) -- -- (14,856) -- -- --
Other comprehensive income
(loss), net of tax (94) -- -- -- -- (94) --
--------
Comprehensive income (loss)..... (14,950)
Dividends paid.................. -- -- -- -- -- -- --
-------- -------- ------- -------- ---------- ----------- --------
December 31, 1999................. $ 57,141 $ 27,385 $3,223 $ 28,234 $ -- $1,028 $(2,729)
======== ======== ======= ======== ========== =========== ========
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-5
<PAGE>
THE WISER OIL COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 1999, 1998 and 1997
<TABLE>
<CAPTION>
1999 1998 1997
--------- --------- --------
(000's except per share data)
<S> <C> <C> <C>
Cash Flows from Operating Activities:
Net income (loss) $(14,856) $(24,466) $ 3,319
Adjustments to reconcile to cash flows from
operating activities:
Depreciation, depletion and amortization........ 17,663 25,811 22,977
Deferred income taxes........................... (686) (9,592) 1,530
Marketable securities and property sales gains.. (3,555) (615) (9,370)
Property impairments and abandonments........... 6,824 8,744 4,830
Foreign currency translation.................... (94) 207 62
Amortization of debt issuance costs............. 607 556 282
Other changes:
Restricted cash............................... (992) -- --
Accounts receivable........................... (463) 4,663 326
Inventories................................... 39 338 282
Income taxes receivable....................... 1,270 (545) (725)
Prepaid expenses.............................. 93 (597) 35
Accounts payable.............................. 1,221 (7,923) 3,400
Accrued income taxes.......................... -- -- (1,697)
Accrued liabilities........................... (81) (255) 1,449
Deferred benefit costs........................ (162) (791) (328)
Other......................................... (350) 1,149 --
-------------------------------
Operating Cash Flows........................ 6,478 (3,316) 26,372
-------------------------------
Cash Flows From Investing Activities:
Capital expenditures.............................. (8,327) (29,980) (70,209)
Proceeds from sales of property and equipment..... 41,017 2,894 3,288
Proceeds from sales of marketable securities...... -- -- 8,115
-------------------------------
Investing Cash Flows........................ 32,690 (27,086) (58,806)
-------------------------------
Cash Flows From Financing Activities:
Borrowings of long-term debt...................... 500 21,000 125,000
Repayments of long-term debt...................... (21,000) -- (78,654)
Long-term debt issuance costs and fees............ -- -- (5,636)
Common stock issued............................... -- -- 183
Dividends paid.................................... -- (1,074) (1,074)
-------------------------------
Financing Cash Flows........................ (20,500) 19,926 39,819
-------------------------------
Net Increase (Decrease) in Cash.......................... 18,668 (10,476) 7,385
Cash and Cash Equivalents, beginning of year............. 2,779 13,255 5,870
-------------------------------
Cash and Cash Equivalents, end of year................... $ 21,447 $ 2,779 $ 13,255
===============================
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-6
<PAGE>
THE WISER OIL COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 1999, 1998 and 1997
1. Summary of Significant Accounting Policies
a. Principles of Consolidation - The consolidated financial statements
include the accounts of The Wiser Oil Company (Company), a Delaware
corporation, and its wholly owned subsidiaries: The Wiser Oil Company of
Canada ("Wiser Canada"), The Wiser Marketing Company, and T.W.O.C., Inc.
Wiser Canada was formed in 1994 to conduct the Company's Canadian
activities. Prior to the formation of Wiser Canada, the Company's oil and
gas operations were conducted primarily in the United States. The Wiser
Marketing Company functions as a natural gas marketer and broker. T.W.O.C.,
Inc. is a Delaware holding company responsible for the management of
investment activities. Intercompany accounts and transactions have been
eliminated. Certain reclassifications have been made to conform prior
years' amounts to current presentation.
b. Risks and Uncertainties - The preparation of financial statements in
conformity with accounting principles generally accepted in the U.S.
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.
c. Oil and Gas Properties - The Company is engaged in the exploration and
development of oil and gas in the United States and Canada. The Company
follows the "successful efforts" method of accounting for its oil and gas
properties. Under this method of accounting, all costs of property
acquisitions and exploratory wells are initially capitalized. If a well is
unsuccessful, the capitalized costs of drilling the well, net of any
salvage value, are charged to expense. If a well finds oil and gas reserves
that cannot be classified as proved within a year after discovery, the well
is assumed to be impaired and the capitalized costs of drilling the well,
net of any salvage value, are charged to expense. The capitalized costs of
unproven properties are periodically assessed to determine whether their
value has been impaired below the capitalized cost, and if such impairment
is indicated, a loss is recognized. The Company considers such factors as
exploratory drilling results, future drilling plans and the lease
expiration terms when assessing unproved properties for impairment.
Geological and geophysical costs and the costs of retaining undeveloped
properties are expensed as incurred. Expenditures for maintenance and
repairs are charged to expense, and renewals and betterments are
capitalized. Upon disposal, the asset and related accumulated depreciation,
depletion and amortization are removed from the accounts, and any resulting
gain or loss is reflected currently in income.
Long-lived assets are assessed for possible impairment in accordance with
Statement of Financial Accounting Standards ("SFAS") No. 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 proved oil and gas properties and the
costs of wells and related equipment and facilities on a property-by-
property basis. If an impairment is indicated based on undiscounted
expected future cash flows, then an impairment is recognized to the extent
that net capitalized costs exceed the estimated fair value of the property.
Fair value of the property is estimated by the Company using the present
value of future cash flows discounted at 10%.
F-7
<PAGE>
THE WISER OIL COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
December 31, 1999, 1998 and 1997
The following expected future prices were used to estimate future cash flows
to assess properties for impairment:
Price starting after December 31, 1999, 1998 and 1997, respectively:
<TABLE>
<CAPTION>
1999 1998 1997
------- ------------ ------------
<S> <C> <C> <C>
Oil Price per barrel:
Year 1.............. $25.60 $12.35 $16.75
Year 2.............. 25.60 13.73 17.25
Year 3.............. 25.60 14.57 17.77
Year 4.............. 25.60 15.81 18.30
Thereafter.......... 25.60 Escalated 3% Escalated 3%
Maximum............. 25.60 20.00 21.85
Gas Price per MMBTU:
Year 1.............. $ 2.34 $ 1.96 $ 2.68
Year 2.............. 2.34 2.25 2.68
Year 3.............. 2.34 2.34 2.68
Year 4.............. 2.34 2.55 2.68
Thereafter.......... 2.34 Escalated 3% 2.68
Maximum............. 2.34 3.50 2.68
</TABLE>
Oil and gas expected future price estimates were based on NYMEX future prices
at each year-end. Expected future prices were escalated if such prices were
unusually low at year-end compared to historical averages. These prices were
applied to production profiles developed by the Company's engineers using
proved developed and undeveloped reserves at December 31, 1999, 1998 and
1997, respectively. The Company's price assumptions change based on current
industry conditions and the Company's future plans. During 1999, 1998 and
1997, the Company recognized impairments of $2,214,000, $3,838,000 and
$3,289,000, respectively. The impairments were determined based on the
difference between the carrying value of the assets and the present value of
future cash flows discounted at 10%. It is reasonably possible that a change
in reserve or price estimates could occur in the near term and adversely
impact management's estimate of future cash flows and consequently the
carrying value of properties.
d. Depreciation, Depletion and Amortization ("DD&A") - DD&A of the
capitalized costs of producing oil and gas properties are computed for
individual properties using the units-of-production method based on total
proved reserves. Other properties consist primarily of computer systems,
vehicles and office equipment and depreciation is computed generally using
the straight-line method over the estimated useful lives of these assets
which range from 5 to 10 years.
e. Cash and Cash Equivalents - Cash equivalents consist of short-term
investments maturing in three months or less from the date of acquisition.
These investments of $24,020,000 at December 31, 1999 and $2,675,000 at
December 31, 1998 are recorded at cost plus accrued interest, which
approximates market.
f. Inventories - Natural gas product inventories in pipelines are recorded
at the lower of average cost or market. Materials and supplies are recorded
at the lower of average cost or market.
F-8
<PAGE>
THE WISER OIL COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
December 31, 1999, 1998 and 1997
g. Accrued Liabilities - In December 1998, the Company reduced its workforce
by approximately 36% and accrued liabilities at December 31, 1998 includes
$545,000 for employee severance payments. The employee severance liability of
$545,000 is included in general and administrative expense in the
consolidated statements of income for the year ended December 31, 1998 and
the entire liability was paid in 1999. Accrued liabilities also include
accrued vacation and payroll of $379,000 at December 31, 1999 and $323,000 at
December 31, 1998.
h. Postretirement Benefits - SFAS No. 106, "Employers' Accounting for
Postretirement Benefits Other Than Pensions", has no significant impact on
the Company. The Company has no significant liabilities for postretirement
benefits, other than pensions, and has historically recognized such
liabilities as they are incurred.
i. Gas Imbalances - Gas imbalances are accounted for using the sales method.
The Company's net imbalance position is not material at December 31, 1999 and
1998.
j. Financial Instruments - The following table sets forth the book value and
estimated fair values of financial instruments at December 31, 1999 and 1998,
respectively (000's):
<TABLE>
<CAPTION>
1999 1998
-------------- -------------
Book Fair Book Fair
Value Value Value Value
-------- -------- -------- -------
<S> <C> <C> <C> <C>
Cash and equivalents $ 21,447 $21,447 $ 2,779 $ 2,779
Restricted cash 992 992 -- --
Floating-rate debt 500 500 21,000 21,000
Fixed-rate debt 124,526 98,750 124,452 86,250
</TABLE>
The fair value of the fixed-rate debt was based on quoted market prices of
the Company's fixed-rate debt at December 31, 1999 and 1998, respectively.
During 1999, 1998 and 1997, the Company entered into various natural gas
forward sale agreements and natural gas price swap and oil price collar
agreements to hedge against price fluctuations. Oil and gas sales in the
accompanying Consolidated Statements of Income are adjusted for the effects
of hedging transactions as the underlying hedged production is sold.
Adjustments to oil and gas sales from the Company's hedging activities
resulted in a reduction in revenues of $3,609,000 in 1999, an increase in
revenues of $210,000 in 1998 and a reduction in revenues of $2,372,000 in
1997. As of December 31, 1999 and December 31, 1998, the Company had no
deferred net gains or net losses. As of February 24, 2000 the Company's
hedging arrangements were as follows:
<TABLE>
<CAPTION>
Crude Oil: Daily Volume Price (Floor / Ceiling)
--------- ------------ -----------------------
<S> <C> <C>
January 1, 2000 to March 31, 2000 1,000 Bbls (1) $18.50 / 26.60 per Bbl
January 1, 2000 to March 31, 2000 2,700 Bbls $24.00 per Bbl
April 1, 2000 to June 30, 2000 3,500 Bbls $22.30 per Bbl
July 1, 2000 to September 30, 2000 3,400 Bbls $21.07 per Bbl
October 1, 2000 to December 31, 2000 3,300 Bbls $19.78 per Bbl
Natural Gas:
-----------
February 1, 2000 to September 30, 2000 5,261 MMBTU (2) $2.29 per MMBTU (2)
February 1, 2000 to September 30, 2000 5,226 MMBTU (2)(3) $2.01 (Put) per MMBTU (2)(3)
March 1, 2000 to September 30, 2000 5,174 MMBTU (2)(3) $2.20 (Put) per MMBTU (2)(3)
</TABLE>
F-9
<PAGE>
THE WISER OIL COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
December 31, 1999, 1998 and 1997
(1) The 1,000 Bbls per day crude oil hedge is a "collar" hedge whereby the
Company will receive the actual market price if the actual market price
is between the floor price of $18.50 per Bbl and the ceiling price of
$26.60 per Bbl. If the actual market price is below or above the floor
or ceiling prices, the price received by the Company will be limited to
the floor price or ceiling price, respectively.
(2) Average for period.
(3) The 5,226 MMBTU per day the and 5,174 MMBTU per day natural gas hedges
are "Put" agreements whereby the Company will receive the actual market
price if the actual market price is above the put prices of $2.01 and
$2.20 per MMBTU, respectively. If the actual market price is below the
put price, the price received by the Company will be limited to the put
price.
k. Foreign Currency Translation - The functional currency of Wiser Canada is
the Canadian dollar. In accordance with SFAS No. 52, "Foreign Currency
Translation", Wiser Canada's financial statements have been translated from
Canadian dollars to U.S. dollars with the cumulative translation adjustment
gain of $1,028,000 for 1999 and $1,122,000 for 1998 classified in
Stockholders' Equity.
l. Comprehensive Income - In 1998, the Company adopted Statement of
Financial Accounting Standards No. 130 "Reporting Comprehensive Income"("SFAS
130") 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 impact of
adopting SFAS No. 130 for the three years ended December 31, 1999 was not
material.
m. Recent Accounting Pronouncements - In June 1998, the Financial Accounting
Standards Board issued SFAS 133 "Accounting for Derivative Instruments and
Hedging Activities" which, as amended, is effective for all fiscal years
beginning after June 15, 2000 (January 1, 2001 for the Company). SFAS No. 133
requires that derivatives be reported on the balance sheet at fair value and,
if the derivative is not designated as a hedging instrument, changes in fair
value must be recognized in earnings in the period of change. If the
derivative is designated as a hedge and to the extent such hedge is
determined to be effective, changes in fair value are either offset by the
change in fair value of the hedged asset or liability (if applicable) or
reported as a component of other comprehensive income in the period of
change, and subsequently recognized in earnings when the offsetting hedged
transaction occurs. The definition of derivatives has also been expanded to
include contracts that require physical delivery of oil and gas if the
contract allows for net cash settlement. The Company currently uses
derivatives to hedge oil and gas price risk and gains or losses on such
derivatives are recorded as adjustments to oil and gas sales. Accordingly,
adoption of SFAS No. 133 should not have a significant impact on reported
earnings, but could have a material impact on comprehensive income and the
reported financial position of the Company.
For the year ended December 31, 1998, the Company elected early adoption of
SOP 98-5, "Reporting the Costs of Start-Up Activities", which requires that
costs associated with start-up activities be expensed as incurred. Initial
application of the SOP is required to be reported as the cumulative effect of
a change in accounting principle. The adoption of SOP 98-5 did not have a
material impact on the Company's financial position or the results of its
operations.
F-10
<PAGE>
THE WISER OIL COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
December 31, 1999, 1998 and 1997
2. Divestitures
In April and May 1999, the Company entered into three separate agreements
to sell its oil and gas properties in the Appalachia area, certain
properties in Texas and New Mexico and virtually all of its royalty
interests in the United States (the "Second Quarter Property Sales"). The
Second Quarter Property Sales were closed in April and May 1999 for an
aggregate sales price of $42,300,000, before fees and adjustments, and
represented approximately 19% of the Company's proved reserves as of
December 31, 1998. The Company recognized a net gain of $3,361,000 from the
Second Quarter Property Sales and the revenues and expenses associated with
the sold properties are included in the Company's consolidated statements
of income through the various closing dates.
3. Marketable Securities
The Company follows the accounting procedures as established by SFAS No.
115, "Accounting for Certain Investments in Debt and Equity Securities".
Under SFAS No. 115 marketable securities, such as those owned by the
Company, are classified as available-for-sale securities and are to be
reported at market value, with unrealized gains and losses, net of income
taxes, excluded from earnings and reported as a separate component of
stockholders' equity. All marketable securities were liquidated during
1997.
The Company recognized a pretax gain of $7,495,000 in 1997 from the sale of
its marketable securities.
4. Long-term Debt
a. On May 21, 1997, the Company sold $125 million in principal amount of 9
1/2% Senior Subordinated Notes ("2007 Notes") due May 15, 2007, providing
net proceeds to the Company of $120,898,000. The original issue price was
99.718%. The Company used the net proceeds from the sale of the 2007
Notes to repay all outstanding bank indebtedness and for general
corporate purposes.
The 2007 Notes are redeemable at the option of the Company, in whole or
in part, at any time on or after May 15, 2002 at a redemption price of
104.75%, plus accrued interest to the date of redemption, and declining
at the rate of 1.583% per year to May 15, 2005 and 100% thereafter. Prior
to May 15, 2000, the Company may, at its option, redeem up to 33 1/3% of
the original principal amount at a redemption price of 109.5%, plus
accrued interest to the date of redemption, with the net proceeds from
any future public offering of Company stock.
Under the terms of the 2007 Notes, the Company must meet certain tests
before it is able to pay cash dividends or make other restricted
payments, incur additional indebtedness, engage in transactions with its
affiliates, incur liens and engage in certain sale and leaseback
arrangements. The terms of the 2007 Notes also limit the Company's
ability to undertake a consolidation, merger or transfer of all or
substantially all of its assets. In addition, the Company is, subject to
certain conditions, obligated to offer to repurchase the 2007 Notes at
par value plus accrued interest to the date of repurchase with the net
cash proceeds of certain sales or dispositions of assets. Upon a change
of control, as defined, the Company will be required to make an offer to
purchase the 2007 Notes at 101% of the principal amount thereof, plus
accrued interest to the date of purchase.
F-11
<PAGE>
THE WISER OIL COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
December 31, 1999, 1998 and 1997
b. On May 10, 1999 the Company entered into a $25 million Restated Credit
Agreement ("BankOne Revolver") with Bank One, Texas, NA. The BankOne
Revolver provides the Company with up to a $25 million line of credit
through April 30, 2001. The amounts available for borrowing are based on
the Company's oil and gas reserves and the Company's Borrowing Base at
December 31, 1999 was $8 million. Available loan and interest options are
(i) Prime Rate Loans, at the bank's prime interest rate and (ii) Eurodollar
Loans, at LIBOR plus 2.5%, 2.75% or 3% depending on the percentage of the
Borrowing Base actually borrowed by the Company. The average interest rate
during 1999 under the Credit Agreement was 6.56%. The commitment fee on the
unused Borrowing Base is 0.5%. The BankOne Revolver imposes certain
restrictions on sales of assets, payment of dividends and incurrence of
indebtedness and requires the Company to, among other things, maintain
certain financial ratios and make monthly escrow deposits of $990,000 to
fund the semi-annual interest payments on the 9 1/2% Senior Subordinated
Notes. At December 31, 1999, restricted cash included $992,000 of escrow
deposits which are restricted to fund the May 15, 2000 interest payment on
the 9 1/2% Senior Subordinated Notes. The Company is currently negotiating
certain amendments to the BankOne Revolver and, subject to the completion
of the negotiations, the Company has classified the entire $500,000 balance
outstanding at December 31, 1999 as a current liability in the
Consolidated Balance Sheets.
c. On June 23, 1994, the Company entered into a Credit Agreement with
NationsBank of Texas, N. A. as agent, which provided for a term loan to
Wiser Canada and a revolving credit facility to the Company. On December
23, 1997, the Credit Agreement was renewed under the same basic terms. The
Credit Agreement provided the Company with up to a $150 million line of
credit through March 31, 2002. The amounts available for borrowing were
determined under formulas related to oil and gas reserves and the Company's
borrowing base at December 31, 1998 was $25 million. The indebtedness
outstanding under the Credit Agreement was secured by a guaranty from Wiser
Canada. The average interest rate during 1998 under the Credit Agreement
was 6.15%. The Credit Agreement required the Company to, among other
things, maintain certain financial ratios and imposes certain restrictions
on sales of assets, payment of dividends and the incurrence of
indebtedness. At December 31, 1998 and through March 31, 1999, the Company
was not able to maintain one of the financial ratios required by the Credit
Agreement. After March 31, 1999 and through April 15, 1999, the Company was
not able to maintain two of the financial ratios required by the Credit
Agreement. On May 11, 1999 the Company repaid the outstanding balance under
the Credit Agreement and the Credit Agreement was terminated.
The Company paid $12,993,000, $12,375,000 and $8,120,000 in interest during
1999, 1998 and 1997, respectively.
<TABLE>
<CAPTION>
Long-term debt consists of the following (000's): December 31,
------------------
1999 1998
------ ------
<S> <C> <C>
2007 Notes - 9.5% interest rate at December 31, 1999........ $124,526 $124,452
BankOne Revolver - 8.5% interest rate at December 31, 1999.. 500 --
Credit Agreement............................................ -- 21,000
-------- --------
125,026 145,452
Less current maturities..................................... 500 21,000
-------- --------
$124,526 $124,304
======== ========
</TABLE>
F-12
<PAGE>
THE WISER OIL COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
December 31, 1999, 1998 and 1997
The annual requirements for reduction of principal of long-term debt
outstanding as of December 31, 1999 are estimated as follows (000's):
2000 ........................... $ 500
2001 ........................... --
2002 ........................... --
2003 ........................... --
Thereafter ..................... 124,526
---------
$ 125,026
=========
5. Income Taxes
The Company provides deferred income taxes for differences between the tax
reporting basis and the financial reporting basis of assets and liabilities.
The Company follows the accounting procedures established by SFAS No. 109,
"Accounting for Income Taxes". The Company did not pay any Federal income
taxes in 1999 or 1998 and paid $566,000 in 1997.
Income tax expense (benefit) for the three years ended December 31, 1999 was
as follows (000's):
<TABLE>
<CAPTION>
1999 1998 1997
------- -------- ------
<S> <C> <C> <C>
Current:
Federal.......................................... $ (173) $ (1,248) $ 375
State............................................ -- 100 200
------ -------- ------
(173) (1,148) 575
------ -------- ------
Deferred:
Federal....................................... (686) (9,592) (311)
------ -------- ------
Total income tax expense (benefit)................ $ (859) $(10,740) $ 264
====== ======== ======
</TABLE>
A reconciliation of the statutory federal income tax rate to the Company's
effective tax rate follows:
<TABLE>
<CAPTION>
1999 1998 1997
------ ------ ------
<S> <C> <C> <C>
Statutory federal income tax rate.................................. 34.0% 34.0% 34.0%
Statutory depletion in excess of cost basis........................ -- -- (5.4)
State taxes, net of federal income taxes........................... -- -- 5.8
Dividends received credit.......................................... -- -- (1.3)
Non-conventional fuels credit...................................... -- -- (7.3)
Net operating loss................................................. (28.5) (3.5) --
Reversal of valuation allowance................................... -- -- (15.3)
Adjustment of accrued tax position................................. -- -- (3.1)
------ ------ ------
Effective tax rate................................................. 5.5% 30.5% 7.4%
====== ====== ======
</TABLE>
F-13
<PAGE>
THE WISER OIL COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
December 31, 1999, 1998 and 1997
The deferred tax liabilities and assets at December 31, 1999 and 1998 were as
follows (000's):
<TABLE>
<CAPTION>
1999 1998
-------- --------
<S> <C> <C>
Deferred tax assets:
Net operating loss carryforwards..................... $ 5,530 $ 6,013
Alternative minimum tax credit carryforwards......... 3,040 3,040
Other................................................ 265 349
------- --------
Total gross deferred tax assets.................... 8,835 9,053
Less valuation allowance........................... (3,069) --
------- --------
Net deferred tax assets............................ 5,766 9,402
Deferred tax liabilities:
Property and equipment, principally due to
differences in depreciation and the expensing of
intangible drilling costs for tax purposes......... (5,766) (10,088)
------- --------
Net deferred tax liability........................... $ -- $ (686)
======= ========
</TABLE>
In 1998, the Company had a net operating loss (NOL) for Federal income tax
purposes of $20,736,000. In 1999, the Company received a Federal income tax
refund of $1,442,000 as a result of carrying back $8,335,000 of the 1998 NOL.
The majority of the NOL carryforwards do not expire until 2018 and the
alternative minimum tax credit carryforwards can be carried forward
indefinitely. The tax benefits of carryforwards are recorded as an asset to
the extent that management assesses the future utilization of such
carryforwards as "more likely than not". When the future utilization of some
portion of the carryforwards is determined not to be "more likely than not",
a valuation allowance is provided to reduce the recorded tax benefits from
such assets. At December 31, 1999, a valuation allowance of $3,069,000 was
provided to reduce deferred tax assets to an amount equal to deferred tax
liabilities.
6. Oil and Gas Producing Activities
Set forth below is certain information regarding the aggregate capitalized
costs of oil and gas properties and costs incurred in oil and gas property
acquisitions, exploration and development activities (000's):
<TABLE>
<CAPTION>
U.S. Canada Total
---------- --------- ---------
<S> <C> <C> <C>
December 31, 1999:
------------------
Capitalized Costs:
Proved properties......... $172,428 $ 87,295 $ 259,723
Unproved properties....... 10,480 4,557 15,037
-------- -------- ---------
Total................... 182,908 91,852 274,760
Accumulated DD&A.......... (66,519) (49,369) (115,888)
-------- -------- ---------
Net capitalized cost...... $116,389 $ 42,483 $ 158,872
======== ======== =========
Costs Incurred during 1999:
Property acquisition...... $ 409 $ 227 $ 636
Exploration............... 1,108 3,566 4,674
Development............... 2,524 2,838 5,362
</TABLE>
F-14
<PAGE>
THE WISER OIL COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
December 31, 1999, 1998 and 1997
<TABLE>
<CAPTION>
<S> <C> <C> <C>
December 31, 1998:
------------------
Capitalized Costs:
Proved properties...................................... $ 261,361 $ 83,668 $ 345,029
Unproved properties.................................... 18,007 4,938 22,945
--------- -------- ---------
Total................................................ 279,368 88,606 367,974
Accumulated DD&A....................................... (114,769) (41,825) (156,594)
--------- -------- ---------
Net capitalized cost................................... $ 164,599 $ 46,781 $ 211,380
========= ======== =========
Costs Incurred during 1998:
Property acquisition................................... $ 2,946 $ 1,181 $ 4,127
Exploration (A)........................................ 12,162 2,147 14,309
Development............................................ 10,226 11,397 21,623
(A) U.S. includes $1,615 for exploration in Peru, S.A.
December 31, 1997:
------------------
Capitalized Costs:
Proved properties...................................... $ 247,809 $ 76,325 $ 324,134
Unproved properties.................................... 17,315 5,206 22,521
--------- -------- ---------
Total................................................ 265,124 81,531 346,655
Accumulated DD&A....................................... (95,038) (34,589) (129,627)
--------- -------- ---------
Net capitalized cost................................... $ 170,086 $ 46,942 $ 217,028
========= ======== =========
Costs Incurred during 1997:
Property acquisition................................... $ 22,399 $ 5,377 $ 27,776
Exploration............................................ 8,906 3,461 12,367
Development............................................ 27,380 9,593 36,973
</TABLE>
7. Employee Pension Plan
The Company has a noncontributory defined benefit pension plan, which covers
substantially all full-time employees. Plan participants become fully vested
after five years of continuous service. The retirement benefit formula is
based on the employee's earnings, length of service and age at retirement.
Contributions required to fund plan benefits are determined according to the
Projected Unit Credit Method. The assets of the plan are primarily invested
in equity and debt securities. An amendment to the pension plan, effective
January 1, 1993, reduced the normal retirement age from 65 years to 62 years.
Effective December 11, 1998, the pension plan was further amended to curtail
certain pension benefits.
F-15
<PAGE>
THE WISER OIL COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
December 31, 1999, 1998 and 1997
The net pension expense and principal assumptions utilized in computing net
pension expense were as follows (000's):
<TABLE>
<CAPTION>
1999 1998 1997
-------- -------- ---------
<S> <C> <C> <C>
Service cost..................................................... $ -- $ 375 $ 345
Interest cost.................................................... 676 729 682
Expected return on plan assets................................... (780) (711) (654)
Amortization of prior service cost............................... -- 148 149
Amortization of transition obligation............................ (25) (22) (35)
Recognized gain (loss)........................................... -- -- (6)
Plan curtailment adjustment...................................... -- (778) --
------- ------- -------
Net periodic pension cost (credit)............................... $ (129) $ (259) $ 481
======= ======= =======
Discount rate.................................................... 8.0% 7.0% 8.0%
Rate of return on plan assets.................................... 8.5% 8.5% 8.5%
Rate of increase in compensation levels.......................... 0.0% 0.0% 5.0%
</TABLE>
The following table presents the funded status of the Company's pension plan as
of December 31 (000's):
<TABLE>
<CAPTION>
Change in benefit obligations: 1999 1998 1997
------- ------- -------
<S> <C> <C> <C>
Benefit obligation at beginning of year.......................... $ 9,666 $ 9,269 $ 9,321
Service cost..................................................... -- 375 345
Interest cost.................................................... 676 729 682
Actuarial gain (loss)............................................ (712) 1,333 (480)
Benefits paid.................................................... (623) (602) (599)
Effect of plan curtailment....................................... -- (1,438) --
------- ------- -------
Benefit obligation at end of year................................ 9,007 9,666 9,269
Change in plan assets:
Fair value of plan assets at beginning of year................... 9,477 8,547 8,010
Actual return on plan assets..................................... 1,789 1,032 736
Employer contributions........................................... -- 500 400
Benefits paid.................................................... (623) (602) (599)
------- ------- -------
Fair value of plan assets at end of year......................... 10,643 9,477 8,547
Plan assets over (under) benefits obligations....................... 1,636 (189) (722)
Unrecognized net actuarial loss (gain).............................. (1,740) (16) (1,032)
Unrecognized transition obligation.................................. (43) (65) (87)
Unrecognized prior service cost..................................... -- -- 812
------- ------- -------
Net amount recognized............................................... $ (147) $ (270) $(1,029)
======= ======= =======
</TABLE>
The net amounts recognized in the consolidated balance sheets consist of the
following (000's):
<TABLE>
<CAPTION>
1999 1998 1997
------- ------- -------
<S> <C> <C> <C>
Accrued benefit cost............................................ $ (147) $ (270) $(1,029)
======= ======= =======
</TABLE>
F-16
<PAGE>
THE WISER OIL COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
December 31, 1999, 1998 and 1997
8. Employee Savings Plan
The Company has a qualified Savings Plan available to all employees. An
employee may elect to have up to 15% of the employee's base monthly
compensation, exclusive of other forms of special or extra compensation,
withheld and placed in the Savings Plan account. On a monthly basis, the
Company contributes to this account an amount equal to 50% of the
employee's contribution, limited to 3% of the employee's base compensation.
Company contributions to the Savings Plan were $99,000, $156,000 and
$142,000, in 1999, 1998 and 1997, respectively.
9. Business Segment Information
In 1998, the Company adopted SFAS No. 131, "Disclosures about Segments of
an Enterprise and Related Information" which requires reporting of
financial and descriptive information about a company's reportable
operating segments. The Company has identified only one operating segment,
which is the exploration for and production of oil and gas with sales made
to domestic and Canadian energy customers. Sales to major customers for the
year ended December 31, 1999 were $19,345,000 to Highland Energy Company,
$5,013,000 to CXY Energy Marketing and $4,972,000 to EOTT Energy Operating
Ltd. which represented 41%, 11% and 10%, respectively, of the Company's
total oil and gas revenues. Sales to major customers for the year ended
December 31, 1998 were $20,684,000 to Highland Energy Company and
$7,656,000 to Koch Oil Co. Ltd. which represented 34% and 13%,
respectively, of the Company's total oil and gas revenues. The sales to
Koch Oil Co. Ltd. accounted for approximately 55% of the Company's revenues
from sales of its Canadian production in 1998. Sales to major customers for
the year ended December 31, 1997 were $28,352,000 to Highland Energy
Company, $11,617,000 to Koch Oil Co. Ltd. and $9,474,000 to Enron Oil
Trading and Transportation which represented 37%, 15% and 12%,
respectively, of the Company's total oil and gas revenues. The sales to
Koch Oil Co. Ltd. accounted for approximately 73% of the Company's revenues
from sales of its Canadian production in 1997. However, due to the nature
of the oil and gas industry, the Company is not dependent upon any of these
customers. The loss of any major customer would not have a material adverse
impact on the Company's business.
The following table summarizes the oil and gas activity of the Company by
geographic area for the years ended December 31, 1999, 1998 and 1997.
<TABLE>
<CAPTION>
U.S. Canada Total
--------- -------- ---------
1999:
-----
<S> <C> <C> <C>
Total revenues................................ $ 37,389 $15,405 $ 52,794
Costs and expenses:
Production and operating.................... 17,062 4,049 21,111
Purchased natural gas....................... 336 -- 336
DD&A........................................ 10,655 7,008 17,663
Property impairments........................ 900 1,314 2,214
Exploration................................. 4,760 2,299 7,059
Other operating............................. 18,784 1,342 20,126
-------- ------- --------
Total costs and expenses................. 52,497 16,012 68,509
-------- ------- --------
Earnings (loss) before income taxes........... (15,108) (607) (15,715)
Income tax expense (benefit).................. (859) -- (859)
-------- ------- --------
Net income (loss)............................. $(14,249) $ (607) $(14,856)
======== ======= ========
At year end:
Property and equipment, net of accumulated DD&A.. $117,378 $42,595 $159,973
======== ======= ========
Total assets..................................... $148,773 $47,953 $196,726
======== ======= ========
</TABLE>
F-17
<PAGE>
THE WISER OIL COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
December 31, 1999, 1998 and 1997
<TABLE>
<CAPTION>
1998:
-----
<S> <C> <C> <C>
Total revenues...................................... $ 47,106 $14,302 $ 61,408
Costs and expenses:
Production and operating.......................... 22,217 4,312 26,529
Purchased natural gas............................. 1,440 -- 1,440
DD&A.............................................. 16,548 9,263 25,811
Property impairments.............................. 1,766 2,072 3,838
Exploration....................................... 13,046 2,282 15,328
Other operating................................... 21,669 1,999 23,668
-------- ------- --------
Total costs and expenses....................... 76,686 19,928 96,614
-------- ------- --------
Earnings (loss) before income taxes.................. (29,580) (5,626) (35,206)
Income tax expense (benefit)......................... (10,740) -- (10,740)
-------- ------- --------
Net income (loss).................................... $(18,840) $(5,626) $(24,466)
======== ======= ========
At year end:
Property and equipment, net of accumulated DD&A...... $166,281 $47,014 $213,295
======== ======= ========
Total assets......................................... $181,013 $50,797 $231,810
======== ======= ========
<CAPTION>
1997:
-----
<S> <C> <C> <C>
Total revenues...................................... $ 71,706 $16,109 $ 87,815
Costs and expenses:
Production and operating.......................... 23,058 4,125 27,183
Purchased natural gas............................. 1,622 -- 1,622
DD&A.............................................. 14,032 8,945 22,977
Property impairments.............................. 1,786 1,503 3,289
Exploration....................................... 6,956 2,699 9,655
Other operating................................... 16,407 3,099 19,506
-------- ------- --------
Total costs and expenses....................... 63,861 20,371 84,232
-------- ------- --------
Earnings before income taxes........................ 7,845 (4,262) 3,583
Income tax expense.................................. 264 -- 264
-------- ------- --------
Net income.......................................... $ 7,581 $(4,262) $ 3,319
======== ======= ========
At year end:
Property and equipment, net of accumulated DD&A..... $173,433 $47,275 $220,708
======== ======= ========
Total assets........................................ $202,474 $52,082 $254,556
======== ======= ========
</TABLE>
10. Stock Compensation Plans
Stock Options
SFAS No. 123, "Accounting for Stock-Based Compensation," encourages but does
not require companies to record compensation cost for stock-based employee
compensation plans at fair value. During 1996, the Company adopted the
disclosure provisions of SFAS No. 123. The Company continues to apply the
accounting provisions of APB Opinion 25, "Accounting for Stock Issued to
Employees," and related interpretations to account for stock-based
compensation. Accordingly, compensation cost for stock options is measured
as the excess, if any, of the quoted market price of the Company's stock at
the date of the grant over the amount an employee must pay to acquire the
stock.
F-18
<PAGE>
THE WISER OIL COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
December 31, 1999, 1998 and 1997
The Company has two stock option plans, the 1991 Stock Incentive Plan
("Incentive Plan") and the 1991 Non-Employee Directors' Stock Option Plan
("Directors' Plan"). The Incentive Plan provides for the issuance of ten-
year options with a variable vesting period and a grant price equal to the
fair market value at the issue date. The Directors' Plan, as amended,
provides for the issuance of ten-year options with a six month vesting period
and a grant price equal to the fair market value at the issue date.
A summary of the status of the Company's two stock option plans at December
31, 1999, 1998 and 1997 and changes during the years then ended follows:
<TABLE>
<CAPTION>
1999 1998 1997
----------------------- ------------------------- ------------------------
Exercise Exercise Exercise
Shares Price(1) Shares Price(1) Shares Price(1)
----------- ----------- ----------- ----------- ----------- -----------
<S> <C> <C> <C> <C> <C> <C>
Outstanding at beginning of year.. 1,027,350 $15.61 1,022,475 $15.62 876,500 $15.02
Granted........................... 223,825 4.96 10,500 11.94 164,500 18.87
Exercised......................... -- -- -- -- (15,025) 15.68
Expired and cancelled............. (32,600) 14.71 (5,625) 11.25 (6,500) 15.76
---------- ------ ---------- ------ ---------- ------
Outstanding at end of year........ 1,218,575 $13.68 1,027,350 $15.61 1,022,475 $15.62
========== ====== ========== ====== ========== ======
Exercisable at end of year........ 1,137,450 $13.27 868,850 $15.40 773,975 $15.23
========== ====== ========== ====== ========== ======
Fair value of options granted(1).. $1.02 $3.66 $6.07
===== ===== =====
</TABLE>
(1) Weighted average per option granted.
223,825 of the options outstanding at December 31, 1999 have exercise
prices between $3.50 and $5, with a weighted average exercise price of
$4.96 and a weighted average remaining contractual life of 9.3 years. All
of the $3.50 to $5 options are currently exercisable with a weighted
average exercise price of $4.96. 647,250 of the options outstanding at
December 31, 1999 have exercise prices between $11 and $15, with a weighted
average exercise price of $14.40 and a weighted average remaining
contractual life of 6.7 years. 629,875 of the $11 to $15 options are
currently exercisable with a weighted average exercise price of $14.29.
The remaining 347,500 options have exercise prices between $15 and $20,
with a weighted average exercise price of $17.95 and a weighted average
contractual life of 5.3 years. 283,750 of the $15 to $20 options are
currently exercisable with a weighted average exercise price of $17.56.
The fair value of each option grant is estimated on the date of grant using
the Black-Scholes option pricing model with the following weighted-average
assumptions used for grants for both the Incentive Plan and the Directors'
Plan:
<TABLE>
<CAPTION>
1999 1998 1997
------ ------ ------
<S> <C> <C> <C>
Risk free interest rate............ 5.71% 5.58% 6.29%
Expected dividend yields........... 0.00% 1.01% .64%
Expected lives, in years........... 5.00 5.00 5.06
Expected volatility................ 48.11% 25.99% 23.66%
</TABLE>
F-19
<PAGE>
THE WISER OIL COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
December 31, 1999, 1998 and 1997
Had compensation cost been determined consistent with SFAS No. 123, the
Company's net income and basic earnings per share would have been reduced to
the following pro forma amounts:
<TABLE>
<CAPTION>
1999 1998 1997
---------- ---------- -------
<S> <C> <C> <C>
Net income (loss) - as reported (in thousands)....... $(14,856) $(24,466) $3,319
Net income (loss) - pro forma (in thousands)......... (15,186) (24,685) 2,256
Earnings (loss) per share - as reported.............. $ (1.66) (2.73) 0.37
Earnings (loss) per share - pro forma................ (1.70) (2.76) 0.25
</TABLE>
Because the SFAS No. 123 method of accounting has not been applied to
options granted prior to January 1, 1995, the resulting pro forma
compensation cost may not be representative of compensation cost to be
expected in future years.
Share Appreciation Rights Plan
The Company has a share appreciation rights ("SARs") plan which authorizes
the granting of SARs to employees of the Company. Upon exercise, SARs allow
the holder to receive the difference between the SARs exercise price and the
fair market value of the Company's common stock covered by the SARs on the
exercise date. At December 31, 1999, 47,175 SARs were outstanding with an
exercise price of $5.00 per share and 4,000 SARs were outstanding with an
exercise price of $14.63 per share. The $5.00 SARs fully vested on November
19, 1999 and the $14.63 SARs vest at 25% per year. All SARs expire at the
earlier of 5 years or termination of employment.
11. Preferred Stock
In addition to Common Stock, the Company is authorized to issue 300,000
shares of Preferred Stock with a par value of $10 per share, none of which
has been issued.
12. Earnings Per Share
The Company accounts for earnings per share ("EPS") in accordance with SFAS
No. 128, "Earnings Per Share". Under SFAS No. 128, basic EPS is computed by
dividing net income by the weighted average common shares outstanding
without including any potentially dilutive securities. Diluted EPS is
computed by dividing net income by the weighted average common shares
outstanding plus, when their effect is dilutive, common stock equivalents
consisting of stock options. Previously reported EPS were equivalent to the
diluted EPS calculated under SFAS No. 128. Following are the weighted
average common shares outstanding used in the computation of basic EPS and
diluted EPS for the years ended December 31, 1999, 1998 and 1997 (000's):
<TABLE>
<CAPTION>
1999 1998 1997
----- ----- -----
<S> <C> <C> <C>
Basic EPS shares.... 8,952 8,952 8,949
===== ===== =====
Diluted EPS shares.. 8,952 8,952 8,982
===== ===== =====
</TABLE>
F-20
<PAGE>
THE WISER OIL COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
December 31, 1999, 1998 and 1997
13. Subsequent Event
On December 13, 1999, the Board of Directors approved the sale of not less
than 600,000 shares of convertible preferred stock and not more than
1,000,000 shares of convertible preferred stock through a private placement
to Wiser Investment Company, LLC ("WIC") for $25 million. The convertible
preferred stock will be convertible at the option of the holder into shares
of the Company's common stock at a conversion price of $4.25 per common
share, subject to customary adjustments. The convertible preferred stock
will pay dividends in cash or in shares of the Company's common stock, at
the option of the Company, at an annual rate of 7%. The holders of the
convertible preferred stock will have the same voting rights as the holders
of the Company's common stock with each share of the convertible preferred
stock having one vote for each share of common stock into which it is
convertible. Any shares of convertible preferred stock not previously
converted will convert automatically to common stock three years after the
transaction closing date or whenever the market price of the Company's
common stock exceeds $10.00 per share for a period of 60 consecutive trading
days.
In addition, WIC will acquire, for a nominal sum, seven-year warrants to
purchase that number of the Company's common stock equal to 741,716
multiplied by a fraction, of which the numerator is the total number of
shares of convertible preferred stock purchased at the closing and any
option closing and the denominator is 1,000,000, at a purchase price of
$0.02 per warrant. The strike price of the warrants issued at closing will
be $4.25 per share, subject to adjustment.
The transaction is expected to close in the second quarter of 2000 and is
subject to stockholders approval and receipt of financing by WIC. The Board
of Directors will also be changed to include four of the current directors
and three new directors designated by WIC
14. Summary of Guaranties of 9 1/2% Senior Subordinated Notes
In May 1997, the Company issued $125 million aggregate principal amount of
its 9 1/2% senior Subordinated Notes due 2007 pursuant to an offering exempt
from registration under the Securities Act of 1933. The notes are unsecured
obligations of the Company, subordinated in right of payment to all existing
and any future senior indebtedness of the Company. The notes rank pari passu
with any future senior subordinated indebtedness and senior to any future
junior subordinated indebtedness of the Company. The notes are fully and
unconditionally guaranteed, jointly and severally, on an unsecured, senior
subordinated basis by certain wholly owned subsidiaries of the Company (the
"Subsidiary Guarantors"). At the time of the initial issuance of the notes,
Wiser Oil Delaware, Inc., Wiser Delaware LLC, The Wiser Oil Company of
Canada , (collectively "Wiser Canada"), The Wiser Marketing Company and
T.W.O.C., Inc. and were the Subsidiary Guarantors (the "Initial Subsidiary
Guarantors"). Except for two wholly owned subsidiaries that are
inconsequential to the Company on a consolidated basis, the Initial
Subsidiary Guarantors comprise all of the Company's direct and indirect
subsidiaries.
Following is summarized financial information of the Subsidiary Guarantors.
The Company has not presented separate financial statements and other
disclosures concerning each Subsidiary Guarantor because management has
determined that they are not material to investors. There are no significant
contractual restrictions on distributions from each of the Subsidiary
Guarantors to the Company.
F-21
<PAGE>
THE WISER OIL COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
December 31, 1999, 1998 and 1997
<TABLE>
<CAPTION>
Subsidiary Guarantors
----------------------------------------
The Wiser
Wiser T.W.O.C. Marketing Combined
Canada Inc. Company Total
-------- -------- --------- --------
<S> <C> <C> <C> <C>
Revenues:
For the Year Ended December 31, 1999.. $ 15,405 $ -- $ 523 $ 15,928
For the Year Ended December 31, 1998.. 14,303 1 2,141 16,445
For the Year Ended December 31, 1997.. 16,109 7,687 2,304 26,100
Earnings (Loss) Before Income Taxes:
For the Year Ended December 31, 1999.. $ (607) $ -- $ 68 $ (539)
For the Year Ended December 31, 1998.. (5,626) (14) 243 (5,397)
For the Year Ended December 31, 1997.. (4,262) 7,671 231 3,640
Net Income (Loss):
For the Year Ended December 31, 1999.. $ (577) $ -- $ 65 $ (512)
For the Year Ended December 31, 1998.. (3,882) (10) 168 (3,724)
For the Year Ended December 31, 1997.. (3,947) 7,103 214 3,370
Cash Flows from Operating Activities:
For the Year Ended December 31, 1999.. $ 9,139 $ -- $ 65 $ 9,204
For the Year Ended December 31, 1998.. 6,863 (10) 168 7,021
For the Year Ended December 31, 1997.. 8,833 7,103 214 16,150
Cash Flows from Investing Activities:
For the Year Ended December 31, 1999.. $ (5,361) $ -- $ -- $ (5,361)
For the Year Ended December 31, 1998.. (12,421) -- -- (12,421)
For the Year Ended December 31, 1997.. (17,241) -- -- (17,241)
Cash Flows from Financing Activities:
For the Year Ended December 31, 1999.. $ (2,522) $ -- $ -- $ (2,522)
For the Year Ended December 31, 1998.. 6,227 -- -- 6,227
For the Year Ended December 31, 1997.. 7,543 -- -- 7,543
Net Increase (Decrease) in Cash:
For the Year Ended December 31, 1999.. $ 1,256 $ -- $ 65 $ 1,321
For the Year Ended December 31, 1998.. 669 (10) 168 827
For the Year Ended December 31, 1997.. (865) 7,103 214 6,452
Current Assets:
December 31, 1999..................... $ 5,357 $ 3 $ -- $ 5,360
December 31, 1998..................... 3,782 3 213 3,998
December 31, 1997..................... 4,808 44 165 5,017
Total Assets:
December 31, 1999..................... $ 47,953 $ 3 $ -- $ 47,956
December 31, 1998..................... 50,797 3 526 51,326
December 31, 1997..................... 52,083 44 492 52,619
</TABLE>
F-22
<PAGE>
THE WISER OIL COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
December 31, 1999, 1998 and 1997
<TABLE>
<CAPTION>
Subsidiary Guarantors
---------------------------------------
The Wiser
Wiser T.W.O.C. Marketing Combined
Canada Inc. Company Total
-------- -------- --------- --------
<S> <C> <C> <C> <C>
Current Liabilities:
December 31, 1999.............. $ 5,116 $-- $ -- $ 5,116
December 31, 1998.............. 4,806 -- 361 5,167
December 31, 1997.............. 6,646 -- 250 6,896
Non-current Liabilities:
December 31, 1999.............. $17,851 $-- $ -- $17,851
December 31, 1998.............. 17,846 -- -- 17,846
December 31, 1997.............. 9,474 -- -- 9,474
Stockholders' Equity (Deficit):
December 31, 1999.............. $24,986 $ 3 $ -- $24,989
December 31, 1998.............. 28,145 3 165 28,313
December 31, 1997.............. 35,963 44 242 36,249
</TABLE>
F-23
<PAGE>
THE WISER OIL COMPANY
Supplemental Financial Information
For the years ended December 31, 1999, 1998 and 1997 (Unaudited)
The following pages include unaudited supplemental financial information as
currently required by the Securities and Exchange Commission (SEC) and the
Financial Accounting Standards Board.
15. Estimated Quantities of Oil and Gas Reserves (Unaudited)
Proved reserves are the estimated quantities of crude oil, natural gas and
natural gas liquids, which upon analysis of geological and engineering data
appear with reasonable certainty to be recoverable in future years from
known reservoirs under existing economic and operating conditions. Proved
developed reserves are proved reserves which can be expected to be recovered
through existing wells with existing equipment and under existing operating
conditions.
The estimation of reserves requires substantial judgment on the part of
petroleum engineers and may result in imprecise determinations, particularly
with respect to new discoveries. Accordingly, it is expected that the
estimates of reserves will change as future production and development
information becomes available and that revisions in these estimates could be
significant.
Following is a reconciliation of the Company's estimated net quantities of
proved oil and gas reserves, as estimated by independent petroleum consultants.
<TABLE>
<CAPTION>
Oil (MBbls) Gas (MMcf)
------------------------------- ----------------------------------
U.S. Canada Total U.S. Canada Total
------- ----------- ------- -------- ---------- --------
<S> <C> <C> <C> <C> <C> <C>
Balance December 31, 1996..................... 28,080 3,532 31,612 89,546 23,831 113,377
Revisions of previous estimates............. (2,614) 274 (2,340) 1,208 1,988 3,196
Properties sold and abandoned............... (810) (344) (1,154) (902) (2,606) (3,508)
Reserves purchased in place................. 1,493 1,013 2,506 8,961 -- 8,961
Extensions and discoveries.................. 1,205 653 1,858 7,601 2,667 10,268
Production.................................. (2,037) (724) (2,761) (9,466) (2,734) (12,200)
------- ------- -------- --------- -------- ---------
Balance December 31, 1997..................... 25,317 4,404 29,721 96,948 23,146 120,094
Revisions of previous estimates............. (2,773) 689 (2,084) (4,001) 1,362 (2,639)
Properties sold and abandoned............... (215) (118) (333) (237) (882) (1,119)
Reserves purchased in place................. 2,686 -- 2,686 319 -- 319
Extensions and discoveries.................. 407 306 713 12,971 4,111 17,082
Production.................................. (1,837) (878) (2,715) (10,535) (3,221) (13,756)
------- ------- -------- --------- -------- ---------
Balance December 31, 1998..................... 23,585 4,403 27,988 95,465 24,516 119,981
Revisions of previous estimates............. 358 (164) 194 (3,070) (2,951) (6,021)
Properties sold and abandoned............... (1,928) (20) (1,948) (41,235) (352) (41,587)
Reserves purchased in place................. 461 -- 461 39 -- 39
Extensions and discoveries.................. 277 391 668 2,150 5,532 7,682
Production.................................. (1,257) (676) (1,933) (7,186) (2,915) (10,101)
------- ------- -------- --------- -------- ---------
Balance December 31, 1999..................... 21,496 3,934 25,430 46,163 23,830 69,993
======= ======= ======== ========= ======== =========
Proved Developed Reserves at December 31, (1):
1996........................................ 24,892 3,225 28,117 80,652 22,477 103,129
1997........................................ 23,798 4,404 28,202 87,688 21,771 109,459
1998........................................ 22,701 4,253 26,954 86,610 23,736 110,346
1999........................................ 20,327 3,719 24,046 43,771 22,813 66,584
</TABLE>
(1) Reserve volumes as assigned by third party engineers have been increased
to reflect the effect of the Alberta Royalty Tax Credit refund. Total proved
and proved developed reserves were increased by 364 MBBL and 1,914 MMCF for
1997, 389 MBBL and 2,088 MMCF for 1998 and 136 MBBL and 826 MMCF for 1999.
Standardized Measure of Discounted Future
Net Cash Flows of Proved Oil and Gas Reserves (Unaudited)
The Company has estimated the standardized measure of discounted future net
cash flows and changes therein relating to proved oil and gas reserves in
accordance with the standards established by the Financial Accounting
Standards Board through its Statement No. 69. The estimates of future cash
inflows are based year-end prices.
F-24
<PAGE>
THE WISER OIL COMPANY
Supplemental Financial Information
For the years ended December 31, 1999, 1998 and 1997 (Unaudited)
Estimated future production of proved reserves and estimated future
production and development costs of proved reserves are based on year-end
costs and economic conditions. Estimated future income tax expense is
calculated by applying year-end statutory tax rates (adjusted for permanent
differences and tax credits) to estimated future pretax net cash flows
related to proved oil and gas reserves, less the tax basis of the properties
involved.
This standardized measure of discounted future net cash flows is an attempt
by the Financial Accounting Standards Board to provide the users of financial
statements with information regarding future net cash flows from proved
reserves. However, the users of these financial statements should use
extreme caution in evaluating this information. The assumptions required to
be used in these computations are subjective and arbitrary. Had other
equally valid assumptions been used, significantly different results of
discounted future net cash flows would result. Therefore, these estimates do
not necessarily reflect the current value of the Company's proved reserves or
the current value of discounted future net cash flows for the proved
reserves.
The following are the Company's estimated standardized measure of discounted
future net cash flows from proved reserves (000's):
<TABLE>
<CAPTION>
U.S. Canada Total
---------- ---------- ----------
<S> <C> <C> <C>
December 31, 1999:
------------------
Future cash flows....................................... $ 595,402 $141,011 $ 736,413
Future production and development costs................. (277,756) (38,989) (316,745)
Future income tax expense............................... (76,024) (17,816) (93,840)
--------- -------- ---------
Future net cash flows................................... 241,622 84,206 325,828
10% Annual discount for estimated timing of cash flows.. (114,440) (34,472) (148,912)
--------- -------- ---------
Standardized measure of discounted cash flows............ $ 127,182 $ 49,734 $ 176,916
========= ======== =========
December 31, 1998:
------------------
Future cash flows....................................... $ 440,715 $ 87,869 $ 528,584
Future production and development costs................. (278,468) (31,147) (309,615)
Future income tax expense............................... (15,091) (5,063) (20,154)
--------- -------- ---------
Future net cash flows................................... 147,156 51,659 198,815
10% Annual discount for estimated timing of cash flows.. (67,065) (18,518) (85,583)
--------- -------- ---------
Standardized measure of discounted cash flows.......... $ 80,091 $ 33,141 $ 113,232
========= ======== =========
December 31, 1997:
------------------
Future cash flows....................................... $ 650,810 $ 98,143 $ 748,953
Future production and development costs................. (357,598) (32,062) (389,660)
Future income tax expense............................... (60,477) (6,512) (66,989)
--------- -------- ---------
Future net cash flows................................... 232,735 59,569 292,304
10% Annual discount for estimated timing of cash flows.. (97,116) (20,699) (117,815)
--------- -------- ---------
Standardized measure of discounted cash flows.......... $ 135,619 $ 38,870 $ 174,489
========= ======== =========
</TABLE>
F-25
<PAGE>
THE WISER OIL COMPANY
Supplemental Financial Information
For the years ended December 31, 1999, 1998 and 1997 (Unaudited)
The following are the sources of changes in the standardized measure of
discounted net cash flows (000's):
<TABLE>
<CAPTION>
1999 1998 1997
------ ------ ------
<S> <C> <C> <C>
Standardized measure, beginning of year................. $113,232 $174,489 $ 317,180
Sales, net of production costs.......................... (26,248) (31,445) (47,959)
Net change in price and production costs................ 151,018 (78,321) (204,859)
Reserves purchased in place............................. 2,503 1,817 30,570
Extensions, discoveries and improved recoveries......... 13,208 11,259 11,751
Change in future development costs...................... (355) 9,316 16,339
Revisions of previous quantity estimates and disposals.. (6,576) (4,846) (6,992)
Sales of reserves in place.............................. (27,429) (1,698) (10,756)
Accretion of discount................................... 12,383 21,007 41,431
Changes in timing and other............................. (19,794) (13,327) (33,752)
Net change in income taxes.............................. (35,026) 24,981 61,536
-------- -------- ---------
Standardized measure, end of year....................... $176,916 $113,232 $ 174,489
======== ======== =========
</TABLE>
16. Unaudited Quarterly Financial Data
The supplementary financial data in the table below for each quarterly
period within the years ended December 31, 1999 and 1998 are derived from
the unaudited consolidated financial statements of the Company.
<TABLE>
<CAPTION>
Net Earnings
Income (Loss)
Revenues (Loss) Per Share
--------- --------- ----------
(000's) (000's)
<S> <C> <C> <C>
1999:
First quarter........ $11,871 $(4,358) $(0.49)
Second quarter....... 13,978 (1,055) (0.12)
Third quarter........ 12,710 (5,391) (0.60)
Fourth quarter....... 14,235 (4,052) (0.45)
1998:
First quarter........ $17,415 $(3,556) $(0.40)
Second quarter....... 16,019 (4,675) (0.52)
Third quarter........ 13,833 (8,153) (0.91)
Fourth quarter....... 14,141 (8,082) (0.90)
</TABLE>
F-26
<PAGE>
Exhibit 10.14
THE WISER OIL COMPANY
1997 SHARE APPRECIATION RIGHTS PLAN
PREAMBLE
THIS 1997 SHARE APPRECIATION RIGHTS PLAN (the "Plan"), made and executed at
Dallas, Texas, by THE WISER OIL COMPANY, a Delaware corporation (the "Company"),
is being established to promote the interests of the Company and its
shareholders by more closely aligning the interests of certain key employees of
the Company and its subsidiaries with the interests of the shareholders of the
Company. The Plan is designed to allow eligible employees to share in the
increase in the value of the shares of the Common Stock, $3.00 par value, of the
Company (the "Common Stock") through the grant of stock appreciation rights
("SARs") with respect to Common Stock, and is intended to enable the Company and
its subsidiaries to attract, retain and motivate employees who can make
significant contributions to the success of the Company and its subsidiaries.
ARTICLE I
ADMINISTRATION
Section 1.1 Committee. The Plan shall be administered by a committee (the
---------
"Committee") appointed by the Board of Directors of the Company (the "Board")
and consisting of two or more members of the Board who, at the time of their
appointment to the Committee and at all times during their service as members of
the Committee, are both "non-employee directors" within the meaning of Rule
16b-3 promulgated under the Securities Exchange Act of 1934, as amended (or any
successor rule), and "outside directors" within the meaning of section 162(m) of
the Internal Revenue Code of 1986, as amended (the "Code"). The Committee shall
have discretionary and final authority to interpret and implement the provisions
of the Plan. The Committee shall act by a majority of its members at the time in
office and such action may be taken either by a vote at a meeting or in writing
without a meeting. The Committee may adopt such rules and procedures for the
administration of the Plan as are consistent with the terms hereof and shall
keep adequate records of its proceedings and acts. Every interpretation, choice,
determination or other exercise by the Committee of any power or discretion
given either expressly or by implication to it shall be conclusive and binding
upon all parties having or claiming to have an interest under the Plan or
otherwise directly or indirectly affected by such action, without restriction,
however, on the right of the Committee to reconsider and redetermine such
action. The Company shall indemnify and hold harmless each member of the
Committee against any claim, cost, expense (including reasonable attorneys'
fees), judgment or liability (including any sum paid in settlement of a claim
with the approval of the Board) arising out of any act or omission to act as a
member of the Committee, except in the case of willful misconduct.
1
<PAGE>
ARTICLE II
ELIGIBILITY
Section 2.1 Eligibility. Awards of SARs under the Plan may be made by the
-----------
Committee to those employees of the Company or a parent or subsidiary
corporation of the Company within the meaning of section 424(e) and (f) of the
Code (the Company and each such parent or subsidiary corporation an "Employer"
and together the "Employers") who, in the sole opinion of the Committee, have
made or are in a position to make significant contributions to the success of
the Employers. In determining the eligibility of any employee of an Employer
for an award of SARs, and in determining the terms and conditions of such award,
the Committee shall take into account the position and responsibilities of the
employee being considered, the nature and value of the services being rendered
by such employee, the current and potential contributions of such employee to
the success of the Employers, and such other factors as the Committee in its
discretion may deem relevant. Awards may be made under the Plan to the same
individual on more than one occasion. "Awardee" means an employee who has been
awarded an SAR pursuant to the Plan and who has executed such written agreement
evidencing such award (an "SAR Agreement") as may be prescribed by the Committee
in its discretion.
ARTICLE III
AWARDS
Section 3.1 Nature of SARs. Awards made under the Plan shall be in the
--------------
form of SARs. Each SAR (i) is a fictional deferred compensation unit used
solely for the accounting purposes of this Plan to determine an amount of
compensation to be paid in cash to or with respect to an Awardee pursuant to the
Plan, (ii) shall be deemed to be equivalent in value to one share of Common
Stock, and (iii) shall be evidenced by an SAR Agreement containing such terms
and conditions not inconsistent with the provisions of the Plan as may be
approved by the Committee in its discretion. SARs shall not entitle an Awardee
to any dividend, voting rights or other rights of a holder of shares of Common
Stock.
2
<PAGE>
Section 3.2 Available SARs. Subject to any increasing or decreasing
--------------
adjustment made pursuant to this Section, the total number of SARs that may be
awarded pursuant to the Plan shall not exceed 90,000, and the total number of
SARs that may be awarded to any one person during any calendar year shall not
exceed 10,000. If any SAR awarded under the Plan expires or terminates prior to
its exercise, such SAR shall again be available to be awarded under the Plan.
If the Company effects a split of shares of Common Stock or pays a dividend in
the form of shares of Common Stock, or if the outstanding shares of Common Stock
are combined into a smaller number of shares, the total number of SARs that may
be awarded pursuant to the Plan and the total number of SARs that may be awarded
to any one person during any calendar year shall be increased or decreased to
reflect proportionately the increase or decrease in the number of outstanding
shares of Common Stock resulting from such split, dividend or combination. In
the event of a reclassification of shares of Common Stock not covered by the
foregoing, or in the event of a liquidation, separation or reorganization
(including, without limitation, a merger, consolidation, spinoff or sale of
assets involving the Company), the Committee shall make such adjustments, if
any, to the total number of SARs that may be awarded pursuant to the Plan and
the total number of SARs that may be awarded to any one person during any
calendar year as the Committee in its discretion may deem appropriate.
3.3 Award of SARs. From time to time while the Plan is in effect, the
-------------
Committee may award SARs to employees of an Employer who are deemed by the
Committee in its discretion to satisfy the eligibility requirements of Section
2.1. Each award under the Plan shall specify the number of SARs being awarded,
the award value of each SAR (which shall not be less than the fair market value
of one share of Common Stock on the date of such award), the term during which
such award may be exercised (which term shall not extend for any period beyond
the earlier of (i) the expiration of three months following the date as of which
the Awardee is no longer an employee of any Employer, or (ii) the expiration of
five years following the date of such award), and such other terms and
conditions not inconsistent with the provisions of the Plan as the Committee
shall determine in its discretion. Subject to the limitations specified in the
Plan, the Committee shall have the right and power to amend the terms and
conditions of any outstanding award of SARs; provided, however, that no such
amendment shall adversely affect the rights of an Awardee under any outstanding
award of SARs without the consent of the affected Awardee.
Section 3.4 Exercise of SARs. Each SAR shall become exercisable and shall
----------------
be exercised in accordance with the terms and conditions of the SAR Agreement
awarding such SAR. Upon the exercise of an SAR, the Employer who is or was the
last employer of the Awardee of such SAR shall pay to such Awardee an amount in
cash equal to the excess of the fair market value of one share of Common Stock
on the date of the exercise of such SAR over the award value of such SAR, and
such SAR shall be canceled.
3
<PAGE>
ARTICLE IV
AMENDMENT AND TERMINATION
Section 4.1 Amendment and Termination. The Board shall have the right and
-------------------------
power at any time and from time to time to amend this Plan, in whole or in part,
on behalf of all Employers, and at any time to terminate this Plan or the
participation of any Employer hereunder; provided, however, that no such
amendment or termination shall adversely affect the rights of an Awardee under
any outstanding award of SARs without the consent of the affected Awardee.
ARTICLE V
MISCELLANEOUS PROVISIONS
Section 5.1 Nonassignability. No SAR or right or interest of any Awardee
----------------
under this Plan or an SAR Agreement may be assigned, transferred or alienated,
in whole or in part, except by will or by the laws of descent and distribution.
An SAR awarded under the Plan to an Awardee shall be exercisable during the
lifetime of such Awardee only by him or her.
Section 5.2 Employment Noncontractual. The establishment of this Plan and
-------------------------
the award of SARs hereunder to an Awardee shall not enlarge or otherwise affect
the terms of such Awardee's employment with the Employer which employs such
Awardee, and such Employer may terminate the employment of such Awardee as
freely and with the same effect as if this Plan had not been established.
Section 5.3 Tax Withholding. An Employer making a payment to or with
---------------
respect to an Awardee in connection with the exercise of an SAR shall withhold
from any such payment, and shall remit to the appropriate governmental
authority, any income, employment or other tax such Employer is required by
applicable law to so withhold and remit on behalf of the payee.
4
<PAGE>
Section 5.4 Fair Market Value of Common Stock. For purposes of the Plan,
---------------------------------
the "fair market value" of the Common Stock means the fair market value per
share of Common Stock as determined by the Committee in good faith; provided,
however, that so long as the Common Stock is listed on the New York Stock
Exchange, the fair market value per share of Common Stock shall be the average
of the reported high and low sales prices on the date in question (or if there
was no reported sale on such date, on the last preceding date on which any
reported sale occurred) on the New York Stock Exchange, or if the Common Stock
is listed or admitted to trading on a securities exchange registered under the
Securities Exchange Act of 1934 other than the New York Stock Exchange, the fair
market value per share of Common Stock shall be the average of the reported high
and low sales prices on the date in question (or if there was no reported sale
on such date, on the last preceding date on which any reported sale occurred) on
the principal securities exchange on which the Common Stock is listed or
admitted to trading, or if the Common Stock is not listed or admitted to trading
on any such exchange but is listed as a national market security on the National
Association of Securities Dealers, Inc. Automated Quotations System ("NASDAQ")
or any similar system then in use, the fair market value per share of Common
Stock shall be the average of the reported high and low sales prices on the date
in question (or if there was no reported sale on such date, on the last
preceding date on which any reported sale occurred) on such system, or if the
Common Stock is not listed or admitted to trading on any such exchange and is
not listed as a national market security on NASDAQ but is quoted on NASDAQ or
any similar system then in use, the fair market value per share of Common Stock
shall be the average of the closing high bid and low asked quotations on such
system for such share on the date in question.
Section 5.5 Outstanding SAR Adjustments. If the Company effects a
---------------------------
split of shares of Common Stock or pays a dividend in the form of shares of
Common Stock, or if the outstanding shares of Common Stock are combined into a
smaller number of shares, the number of unexercised SARs subject to an
outstanding award made under the Plan shall be increased or decreased
proportionately and the award value of such SARs shall be decreased or increased
proportionately so that the aggregate award value of such SARs shall remain the
same as immediately prior to such split, dividend or combination. In the event
of a reclassification of shares of Common Stock not covered by the foregoing, or
in the event of a liquidation, separation or reorganization (including, without
limitation, a merger, consolidation, spinoff or sale of assets involving the
Company), the Committee shall make such adjustments, if any, to the number and
award value of unexercised SARs subject to an outstanding award made under the
Plan as the Committee in its discretion may deem appropriate.
IN WITNESS WHEREOF, this Plan has been executed to be effective as of
August 19, 1997.
THE WISER OIL COMPANY
By /s/ Andrew J. Shoup, Jr.
--------------------------------------------
Title: President and Chief Executive Officer
5
<PAGE>
Exhibit 10.14a
AMENDMENT TO THE WISER OIL COMPANY
1997 SHARE APPRECIATION RIGHTS PLAN
Pursuant to the provisions of Section 4.1 of The Wiser Oil Company 1997
Share Appreciation Rights Plan (the "Plan"), the Plan is hereby amended,
effective as of May 18, 1999, to restate the first sentence of Section 3.2 of
the Plan in its entirety to read as follows:
"Subject to any increasing or decreasing adjustment made pursuant to
this Section, the total number of SARs that may be awarded pursuant to the
Plan shall not exceed 90,000, and the total number of SARs that may be
awarded to any one person during any calender year shall not exceed
12,750."
THE WISER OIL COMPANY
By: /s/ Andrew J. Shoup, Jr.
---------------------------------
Name: Andrew J. Shoup, Jr.
Title: President and Chief Executive Officer
Dated as of May 18, 1999
1
<PAGE>
EXHIBIT 21
SUBSIDIARIES OF THE WISER OIL COMPANY
T.W.O.C., Inc.
The Wiser Oil Company of Canada
Wiser Delaware LLC
<PAGE>
Exhibit 23.1
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation by
reference in the Registration Statements on Form S-8 relating to the stock
incentive plans of The Wiser Oil Company (Nos. 33-44171, 33-62441, 33-44172,
333-22525 and 333-15083) of our report dated February 24, 2000 appearing on page
F-2 of this Annual Report on Form 10-K.
/s/ ARTHUR ANDERSEN LLP
Arthur Andersen LLP
Dallas, Texas,
February 24, 2000
<PAGE>
Exhibit 23.2
CONSENT OF PETROLEUM ENGINEERS
April 11, 2000
The Wiser Oil Company
8115 Preston Road, Suite 400
Dallas, Texas 75225
Gentlemen:
We hereby consent to the incorporation by reference in the Registration
Statements on Form S-8 (Nos. 33-44171, 33-62441, 33-44172, 333-22525, and
333-15083) relating to the stock incentive plans of The Wiser Oil Company (the
Company) of our reserves estimates included in the Annual Report on Form 10-K
(the Annual Report) of the Company for the year ended December 31, 1999, and to
the references to our firm included in the Annual Report. Our estimates of the
oil, condensate, natural gas liquids (shown collectively as "Oil and NGL"), and
natural gas reserves of certain properties owned by the Company are contained in
our reports entitled "Appraisal Report as of December 31, 1999 on Certain
Properties owned by the Wiser Oil Company-Proved Reserves". Reserves estimates
from our reports are included in the sections "Principal Oil and Gas
Properties," "Oil and Gas Reserves," and "Supplemental Financial Information for
the years ending December 31, 1999, 1998 and 1997 (unaudited)-Oil and Gas
Reserves." Also included in the third section mentioned above are reserves
estimates from our "Appraisal Report as of December 31, 1999 on Certain
Properties owned by the Wiser Oil Company-Proved Reserves." In the sections
"Summary Reserve and Operating Data" and "Oil and Gas Reserves," estimates of
reserves, revenue, and discounted present worth set forth in our above mentioned
reports have been combined with estimates of reserves, revenue, and discounted
present worth prepared by another petroleum consultant. We are necessarily
unable to verify the accuracy of the reserves, revenue, and present worth values
contained in the Annual Report when our estimates have been combined with those
of another firm.
Very truly yours,
/S/ DEGOLYER AND MACNAUGHTON
DeGOLYER and MacNAUGHTON
<PAGE>
EXHIBIT 23.3
LETTER OF CONSENT
CONSENT OF PETROLEUM ENGINEERS
As independent petroleum engineers, we hereby consent to the incorporation
by reference in the Registration Statements on Form S-8 relating to the stock
incentive plans of The Wiser Oil Company (the "Company"), (Nos. 33-44171, 33-
62441, 33-44172, 333-22525 and 333-15083), of certain data from our report
entitled "The Wiser Oil Company Canada Ltd. Reserve Appraisal and Economic
Evaluation effective January 1, 2000" with respect to the oil and gas reserves
of the Company, the future net revenues therefrom and present values
attributable to these reserves included in this Annual Report on Form 10-K, and
to all references to our firm included in this Annual Report.
Yours very truly,
GILBERT LAUSTSEN JUNG ASSOCIATES LTD.
/s/ Wayne W. Chow, P. Eng.
Vice-President
April 11, 2000
Calgary, Canada
<TABLE> <S> <C>
<PAGE>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM ANNUAL
REPORT ON FORM 10-K AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH
FINANCIAL STATEMENTS.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C> <C>
<PERIOD-TYPE> 3-MOS YEAR
<FISCAL-YEAR-END> DEC-31-1999 DEC-31-1999
<PERIOD-START> OCT-01-1999 JAN-01-1999
<PERIOD-END> DEC-31-1999 DEC-31-1999
<CASH> 22,439 22,439
<SECURITIES> 0 0
<RECEIVABLES> 9,565 9,565
<ALLOWANCES> 0 0
<INVENTORY> 335 335
<CURRENT-ASSETS> 32,718 32,718
<PP&E> 278,541 278,541
<DEPRECIATION> 118,568 118,568
<TOTAL-ASSETS> 119,726 196,726
<CURRENT-LIABILITIES> 14,843 14,843
<BONDS> 124,526 124,526
0 0
0 0
<COMMON> 27,385 27,385
<OTHER-SE> 29,756 29,756
<TOTAL-LIABILITY-AND-EQUITY> 196,726 196,726
<SALES> 12,934 47,602
<TOTAL-REVENUES> 14,235 52,794
<CGS> 6,184 21,447
<TOTAL-COSTS> 18,287 68,509
<OTHER-EXPENSES> 0 0
<LOSS-PROVISION> 0 0
<INTEREST-EXPENSE> 3,148 13,310
<INCOME-PRETAX> (4,052) (15,715)
<INCOME-TAX> 0 (859)
<INCOME-CONTINUING> (4,052) (14,856)
<DISCONTINUED> 0 0
<EXTRAORDINARY> 0 0
<CHANGES> 0 0
<NET-INCOME> (4,052) (14,856)
<EPS-BASIC> (0.45) (1.66)
<EPS-DILUTED> (0.45) (1.66)
</TABLE>
