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, 1997 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
- ------------------- -------------------
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]
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]
As of February 27, 1998, 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 27, 1998 was approximately $114 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 May 18, 1998 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.
TABLE OF CONTENTS
DESCRIPTION
Item Page
PART I
1. BUSINESS.......................................................... 3
2. PROPERTIES........................................................ 26
3. LEGAL PROCEEDINGS................................................. 26
4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS............... 26
PART II
5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED
STOCKHOLDER MATTERS........................................... 27
6. SELECTED FINANCIAL DATA........................................... 28
7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS........................... 31
8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA....................... 36
9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE........................... 36
PART III
10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT................ 36
11. EXECUTIVE COMPENSATION............................................ 36
12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT................................................... 37
13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.................... 37
PART IV
14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS
ON FORM 8-K.................................................. 38
2
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. In
recent years, the Company has successfully implemented a new business strategy
adopted in 1991, emphasizing growth in reserves and production volumes through
acquisitions and subsequent development and exploitation of acquired properties.
Since its change in strategic direction, the Company's total proved reserves
have grown to 49.7 MMBOE (approximately 60% of which were oil and NGLs) at
December 31, 1997 from 24.3 MMBOE at December 31, 1991, and its annual net
production has grown to 4.9 MMBOE in 1997 from 2.3 MMBOE in 1991. The Company's
primary operations, representing approximately 51% of its proved reserves at
December 31, 1997, are located in the Permian Basin in West Texas and Southeast
New Mexico. Wiser has additional operations in Alberta, Canada, the Appalachian
Basin in Kentucky, Tennessee and West Virginia, 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 successfully 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 successful enhanced oil
recovery projects on properties acquired from 1992 to 1995 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
1997, the Company completed 163 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 2,921 BOE in 1997
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 1,458 BOE in 1997 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 1997, the
Company completed 42 net wells on these properties. As a result, the Company's
average daily net Canadian production increased to 3,232 BOE in 1997 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.
3
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, 1997.
Proved Reserves
-------------------------------------------
1997
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)
--------- --------- ------ -------- --------- ----------
Permian Basin
Maljamar.................................. 231 13,739 5,424 14,643 30% 2,921
Wellman................................... 18 6,696 2,367 7,091 14% 1,458
Dimmitt/Slash Ranch....................... 83 2,265 7,694 3,546 7% 901
----- ------ ------- ------- ----- ------
Total................................... 332 22,700 15,485 25,280 51% 5,280
Appalachian Basin........................... 466 807 35,233 6,679 13% 1,273
San Juan Basin.............................. 2,200 46 20,571 3,474 7% 1,066
Other....................................... 476 1,764 25,659 6,042 12% 2,281
----- ------ ------- ------- ----- ------
Total United States......................... 3,474 25,317 96,948 41,475 83% 9,900
Canada...................................... 322 4,404 23,146 8,262 17% 3,232
----- ------ ------- ------- ----- ------
Total Company............................... 3,796 29,721 120,094 49,737 100% 13,132
===== ====== ======= ======= ===== ======
Permian Basin
Maljamar. The Company's Maljamar properties are situated in Southeast New
Mexico. At December 31, 1997, the Maljamar properties contained 14.6 MMBOE of
proved reserves, which represented 30% of the Company's total proved reserves
and 24% 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 1995: 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 12,800 gross leasehold acres.
Exploitation efforts at the project include recompletions of existing wells
and the drilling of infill development wells on 20-acre spacing to create a
five-spot water injection pattern of 40 acres. From June 1, 1993 through
December 31, 1997, the Company made capital expenditures of $75.5 million and
completed 163 producing wells at the project. At December 31, 1997, the project
included 231 producing wells and 175 water injection wells, all of which were
operated by the Company. During 1997, Wiser placed a total of 50 wells on
production, and had 12 additional wells in various stages of drilling or
completion at year end. At December 31, 1997, a total of 3 wells remain to be
drilled at the project, all of which are expected to be drilled in 1999 as part
of a total capital expenditure thereon of $1.3 million.
The Company's net production from the Maljamar properties averaged 2,586 Bbls
of oil, 107 Bbls of NGLs and 1,367 Mcf of natural gas per day in 1997. The
Company's cumulative net production from the Maljamar properties since acquired
by the Company has been 2,304 MBbls of oil and 1.2 Bcf of natural gas through
December 31, 1997.
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. At December 31, 1997, the
4
Company's Wellman property contained 7.1 MMBOE of proved reserves, which
represented 14% of the Company's total proved reserves and 4% of the Company's
Present Value of total proved reserves.
The Company owns approximately 2,300 gross (1,400 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, 1997, the unit included 18 productive wells, 3 water injection
wells, 3 CO2 injection wells and 3 water disposal wells, all of which were
operated by the Company.
The Company's net production from the Wellman Unit averaged 946 Bbls of oil,
432 Bbls of NGLs and 480 Mcf of natural gas per day in 1997. The Company's
cumulative net production from the unit since acquired by the Company has been
1,526 MBbls of oil, 436 MBbls of NGLs and 311 MMcf of natural gas through
December 31, 1997.
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, 1997,
the gas plant processed an average of 34 MMcf of gross natural gas and CO2 per
day and recovered an average of 784 Bbls of NGLs and 808 Mcf of residual natural
gas per day. The plant currently operates at 96% 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, 1997, the Dimmitt/Slash Ranch properties contained 3.5 MMBOE of proved
reserves, which represented 7% of the Company's total proved reserves and 8% of
the Company's Present Value of total proved reserves.
The Company owns approximately 5,320 gross (5,290 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, 1997, the field included 80 productive wells. The Company completed 1 well
in the Cherry Canyon formation and performed 9 recompletions on producing wells
in the Bell Canyon formation in 1997. The Company plans to recomplete 18
additional Bell Canyon wells during the next six years for an estimated total
capital expenditure of approximately $1.25 million. The Company's net production
from the Dimmitt Field averaged 411 Bbls of oil and 1,377 Mcf of natural gas per
day in 1997.
The Slash Ranch Field is a natural gas field that underlies the Dimmitt Field.
The Company owns approximately 4,160 gross (3,390 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, 1997, the field included 3 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 Slash Ranch Field averaged 1,564 Mcf
of natural gas per day in 1997. The Company has identified several exploratory
prospects in this field and intends to further define these prospects with 3-D
seismic in 1997. See "-Exploration Activities-United States-West Texas."
The Company's net production from the Dimmitt/Slash Ranch properties averaged
411 Bbls of oil and 2,941 Mcf of natural gas per day in 1997. The Company's
cumulative net production from the properties since acquired by the Company has
been 455 MBbls of oil and 4.1 Bcf of natural gas through December 31, 1997.
5
Appalachian Basin
The Company's Appalachian Basin properties are situated in Kentucky, Tennessee
and West Virginia. At December 31, 1997, these properties contained 6.7 MMBOE of
proved reserves, which represented 13% of the Company's total proved reserves
and 15% of the Company's Present Value of total proved reserves. The Appalachian
Basin reserves are long-lived reserves (generally, over 40 years) characterized
by gradual decline rates.
The Company has operated in Kentucky and Tennessee since 1917 and owns
approximately 123,000 gross (108,000 net) leasehold acres in 22 shallow natural
gas fields in southeastern Kentucky and northeastern Tennessee. The Company's
working interests in this acreage range from 33% to 100%. The Company has a 100%
working interest in approximately 90% of the total acreage. The primary
producing formations in these fields are the Maxon, Big Lime and Corniferous at
a maximum depth of less than 3,000 feet. At December 31, 1997, the Company owned
368 gross (309 net) productive wells in these fields, of which approximately 98%
were operated by the Company. Although daily production from individual wells in
the fields is low (on average, 30 Mcf per day), the production generally
receives a higher sales price than the Company's other natural gas production
because of the proximity of the fields to the northeastern United States gas
markets. The Company completed 4 development wells in Kentucky and Tennessee in
1997. The Company expects to spend approximately $0.3 million on development
drilling activities in Kentucky and Tennessee in 1998. The Company's net
production from its Kentucky and Tennessee properties averaged 5,070 Mcf of
natural gas, 84 Bbls of oil and 143 Bbls of NGLs per day in 1997.
The Company owns approximately 20,000 gross (14,000 net) leasehold acres in
the Blue Creek Field in Clay and Kanawha Counties, West Virginia. The Company
has an average 70% working interest in this acreage, which it acquired in
February 1995. The Blue Creek Field produces from the Rosedale, Injun, Keener
and Weir formations, ranging from depths of 1,200 to 2,800 feet. At December 31,
1997, the Company owned 98 gross (68 net) productive gas wells in this field,
all of which were operated by another company. During 1997, the Company
participated in the drilling of 20 gross (15 net) development wells in the Blue
Creek Field. The Company has identified 30 low-risk exploratory drilling
locations in the field and plans to drill 25 of these locations in 1998 for an
estimated total capital expenditure of $3.6 million. The Company's net
production from its West Virginia properties averaged 1,205 Mcf of natural gas
per day in 1997.
The Company owns and operates an extensive natural gas gathering and
transportation system located in its producing areas of Kentucky and Tennessee.
The system consists of approximately 340 miles of gas gathering pipelines, 6 gas
compressor stations, two gas processing plants and two gas storage reservoirs.
The pipelines have a throughput capacity of approximately 20 MMcf of natural gas
per day. During the year ended December 31, 1997, the pipelines gathered an
average of 10.9 MMcf of natural gas per day. The two processing plants have a
total capacity of 16 MMcf of natural gas per day. During the year ended December
31, 1997, the plants processed an average of 10.5 MMcf of natural gas per day
and recovered an average of 143 Bbls of NGLs per day. See "-Marketing of
Production."
The Company's net production from its Appalachian Basin properties averaged
6,275 Mcf of natural gas, 84 Bbls of oil and 143 Bbls of NGLs per day in 1997.
San Juan Basin
The Company's San Juan Basin properties are located in Rio Arriba County in
northwestern New Mexico. At December 31, 1997, the San Juan Basin properties
contained 3.5 MMBOE of proved reserves, which represented 7% of the Company's
total proved reserves and 8% of the Company's Present Value of total proved
reserves. The Company owns approximately 11,100 gross (5,300 net) leasehold
acres in the San Juan Basin. The Company's average 48% working interest in 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 the wells. At December 31, 1997, the
Company owned working interests in approximately 2,200 producing gas wells in
the San Juan Basin. These working interests range from 0.21% to 4.2% and average
approximately 1.8%. The Company's San Juan Basin properties produce from
multiple formations ranging from depths of 3,500 feet to 8,000 feet. The
Company's net production from these properties averaged 6,277 Mcf of natural gas
and 20 Bbls of
6
oil per day in 1997. During the year ended December 31, 1997, approximately
50% 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. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations-Results of Operations." 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
Anadarko Basin in Texas and Oklahoma and the Gulf Coast onshore region. The
Company intends to develop its Anadarko Basin and Gulf Coast properties as new
core operating areas if certain exploration projects it is currently pursuing
prove successful. See "-Exploration Activities-United States."
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 and 2.8 MMBOE
of probable reserves, approximately 127,000 net undeveloped acres, seven
exploration prospects and an existing staff of 23 persons. At December 31, 1997,
the Company's Canadian properties contained 8.3 MMBOE of proved reserves, which
represented 17% of the Company's total proved reserves and 21% 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, 1997:
Proved Reserves
------------------------------------------
Percent 1997
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)
--------- --------- ------- -------- -------- -----------
Evi......................................... 14 2,047 -- 2,047 25% 520
Provost..................................... 74 870 1,113 1,056 13% 614
Portage..................................... 7 -- 3,902 650 8% --
Pine Creek.................................. 5 133 1,659 410 5% 103
Leahurst.................................... 19 220 300 270 3% 305
Other....................................... 193 1,134 16,172 3,829 46% 1,690
---- ----- ------ ----- ----- -----
Total Canada................................ 312 4,404 23,146 8,262 100% 3,232
==== ===== ====== ===== ==== =====
Evi. The Company's Evi Field is located approximately 400 miles north of
Calgary. At December 31, 1997, the Evi Field contained 2,047 MBOE of proved
reserves, which represented 25% of the Company's total Canadian proved reserves
and 47% of the Present Value of the Company's total Canadian proved reserves.
The Company owns approximately 5,440 gross (2,330 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 520 Bbls
of oil per day in 1997. At December 31, 1997, the Company owned 14 gross (5.1
net) productive wells and two gross (0.4 net) water disposal wells in the field,
of which 11 productive wells and both water disposal wells were operated by
Wiser.
7
In December 1997, the Company exchanged all of its interest in the Grand
Prairie Field located northwest of Calgary and paid $4.3 million in cash to
purchase additional working interests in the Evi Field. This acquisition
increased the Company's average working interests in the Evi Field from 34% to
42%.
Provost. The Company's Provost properties are located approximately 210 miles
northeast of Calgary. At December 31, 1997, the Provost properties contained
1,056 MBOE of proved reserves, which represented 13% of the Company's total
Canadian proved reserves and 13% of the Present Value of the Company's total
Canadian proved reserves.
The Company owns approximately 10,853 gross (7,055 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' Pool is the Company's main producing pool in
these properties and water injection in this pool began in 1990. The Company
drilled 27 wells in the Provost properties in 1997 and plans to drill 4
additional wells in Provost in 1998.
The Company's net production from the Provost properties averaged 614 Bbls of
oil per day in 1997. At December 31, 1997, the Company owned 74 gross (50.8 net)
productive wells and 2 gross (2 net) water injection wells on the properties, of
which 54 gross productive wells and both water injection wells were operated by
the Company.
Portage. The Company's Portage properties are located approximately 350 miles
northeast of Calgary. At December 31, 1997, the Portage properties contained 650
MBOE of proved reserves, which represented 8% of the Company's total Canadian
proved reserves and 3% of the Present Value of the Company's total Canadian
proved reserves.
The Company owns approximately 16,000 gross (11,648 net) leasehold acres in
the Portage properties, and has an average 73% working interest in this acreage.
The Portage properties produce from the Grand Rapids formation at depths of
1,050 to 1,100 feet. At December 31, 1997, the Company owned 7 gross (6.5 net)
productive wells, all of which were operated by Wiser. All of the wells are
temporarily shut-in, and the Company expects to commence production in April
1998. There was no production from the Portage properties during 1997.
Pine Creek. The Company's Pine Creek Field is located approximately 240 miles
northwest of Calgary. At December 31, 1997, the Pine Creek Field contained 410
MBOE of proved reserves, which represented 5% 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 8,000 gross (2,100 net)
leasehold acres in the Pine Creek Field, and has a 26% working interest in this
acreage. The Pine Creek Field produces gas from the Bluesky and Gething
formations at depths of 8,000 to 8,200 feet. At December 31, 1997, the Company
owned 5 gross (1.3 net) productive wells in the Pine Creek Field, all of which
were operated by a third party. The Company's net production from the Pine Creek
Field averaged 620 Mcf of natural gas per day in 1997.
Leahurst. The Company's Leahurst properties are located approximately 180
miles northeast of Calgary. At December 31, 1997, the Leahurst properties
contained 270 MBOE of proved reserves, which represented 3% 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 880 gross (560 net) leasehold acres in the
Leahurst properties, and has an average 63% working interest in this acreage.
The Leahurst properties produce from the Glauconite formation at depths of 4,150
to 4,250 feet. At December 31, 1997, the Company owned 19 gross (3.0 net)
productive wells and 3 gross (0.5 net) water injection wells on the Leahurst
properties. All of the wells in the properties have been unitized in the
Leahurst Glauconite 'B' Unit, in which the Company has a 16% working interest.
The unit is operated by a third party. Water injection in the unit began in 1994
to enhance oil recovery. The Company's net production from the Leahurst
properties averaged 278 Bbls of oil, 117 Mcf of natural gas and 8 Bbls of NGLs
per day in 1997.
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, 1997, these properties
8
individually represented less than 5%, and in the aggregate represented
approximately 46%, of the Company's total Canadian proved reserves.
EXPLORATION ACTIVITIES
United States
Wiser's domestic exploration program seeks to maintain a balanced portfolio of
drilling opportunities that range from lower risk field extension wells to
higher risk, high reserve potential prospects. The Company focuses primarily on
exploration opportunities that can benefit from advanced technologies, including
3-D seismic, designed to reduce risks and increase success rates. Prospects are
developed in-house and through strategic alliances with exploration companies
that have expertise in specific target areas. In addition, the Company evaluates
some externally generated prospects and participates in farm-ins to enhance its
portfolio. In 1997, Wiser participated in 18 gross (10 net) domestic exploration
wells, compared with 3 gross (2 net) wells in 1996, spending $8.9 million in
1997 and $0.9 million in 1996 on domestic exploration. The Company has budgeted
$19.0 million for its 1998 domestic exploration program.
The Company is currently focusing its domestic exploration activities in the
following geographical areas:
South Texas. In the second half of 1997, the Company generated the Frio Project
by initially acquiring interests in the Welder Ranch prospect, which included 29
producing wells and approximately 30 undeveloped drilling locations, and also
acquiring interests in the nearby Terrell Ranch, Roche Ranch, Fitzsimmons and
Blanco Creek prospects . During 1997, the Company utilized 3-D seismic to
identify shallow (3,000 to 6,000 feet) natural gas objectives on the Frio
Project, and during the second half of 1997 the Company drilled 9 successful
wells and 4 dry holes on the project. The Company considers this project as
having relatively low risk and plans to drill 76 wells in the project in
1998. The Company's working interests in the project range from 30% to 80%.
West Texas. The Company has identified deep exploratory prospects in both the
Slash Ranch Field in Loving County and the Wellman Field in Terry County where
they are currently producing at shallower depths. The Company intends to define
the Slash Ranch prospect further with 3-D seismic and plans to drill 1 well at
Slash Ranch and 1 well at Wellman in 1998. In Pecos County, Wiser has a 25%
working interest in both the Indian Mesa and Panther Bluff prospects. The
Company has completed 3-D seismic on the Indian Mesa prospect and an
unsuccessful exploratory well was drilled on this prospect in 1997 at no cost to
the Company. The Company has identified several single-well gas prospects at
Indian Mesa and plans to drill 2 wells in 1998. The Company has identified
unproven drilling potential in the Panther Bluff prospect to be defined further
with 3-D seismic data. Approximately 26 square miles of 3-D seismic will be
processed in 1998. One well is planned for Panther Bluff in 1998. Late in 1997,
the Company acquired a 33% working interest in the Coyanosa prospect, and a well
is currently drilling to test the Cherry Canyon formation.
Gulf Coast. During 1997, the Company participated in the drilling of a dry
hole at the South Lakeside prospect in Cameron Parish, Louisiana. Wiser does
not plan to drill any additional wells at this prospect. The Company has a 20%
working interest in the Bison Ridge prospect in Layfayette Parish, Louisiana
where a 62 square mile 3-D seismic survey was underway at year-end 1997. Two
wells are planned to be drilled on the prospect in 1998 to a depth of 13,000 to
17,000 feet. In Conecuh County, Alabama, the Company has a 50% working interest
in the Castleberry prospect. During 1997, a 31 square mile 3-D seismic survey
was completed and Wiser expects to drill 2 wells at the Castleberry prospect in
1998.
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
9
Company's technical personnel have considerable experience in this focus area.
During 1997, the Company drilled 4 gross (3 net) exploratory wells of which 3
gross (2 net) were successful. The Company spent $3.5 million on exploration in
Canada in 1997 and has budgeted $1.9 million for its 1998 Canadian exploration
program.
The Company is currently focusing its Canadian exploration activities in the
following geographical areas:
Northeast British Columbia. During 1997, the Company continued expanding,
delineating and developing its 1996 oil discovery at the Elm prospect. Currently
3 wells are producing and 6 additional wells are planned for 1998. The Company's
working interests in the Elm prospect range from 50% to 100%.
West Central Alberta. In March 1997, the Company successfully completed an
exploratory well at the Sunchild prospect and identified a second prospect to
the south of Sunchild at the Ferrier prospect. A follow-up well is planned for
1998 at Sunchild, and an exploratory well is also planned for Ferrier in 1998.
The Company's working interests in the Sunchild and Ferrier prospects range from
25% to 50%.
The Company has a 50% working interest in the Windfall prospect. A natural
gas target has been confirmed, and Wiser plans to drill an exploratory well at
Windfall in 1998.
During 1997, the Company completed a 2-D seismic survey at Wild River and is
currently acquiring acreage in this prospect. A deep well test is planned for
1998 in which the Company will have a 50% working interest.
Southest Alberta. At Provost, the Company discovered the Provost W3W pool in
May 1997, and 24 follow-up oil wells were successfully completed during 1997.
The Company plans to initiate a waterflood at Provost during 1998 and another
exploratory well is planned for 1998 in which the Company will have a 50%
working interest. Wiser's average working interest is 65% in the Provost
properties.
International
Peru. The Company has a 12.5% working interest in Block 81 which is a high risk
and high potential exploration prospect operated by Quintana Minerals Peru that
comprises 2.5 million acres. The Company has budgeted approximately $1.3 million
for drilling a 13,200-foot exploratory well which is expected to start drilling
in April 1998.
Brazil. Wiser is currently participating in a group operated by Santa Fe Energy
Resources, Inc. that has applied for development and exploration concessions
from PETROBRAS, the Brazilian oil company.
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, 1997, revenues from the sale of production
to Highland Energy Company, Koch Oil Co. Ltd. and Enron Oil Trading and
Transportation represented approximately 37%, 15% and 12%, respectively, of the
Company's total oil and gas revenues. The sales to Koch Oil Co. Ltd. accounted
for approximately 75% of the Company's revenues from sales of its Canadian
production in 1997. 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
10
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 $44.0 million for the year ended
December 31, 1997 and represented 57% of the Company's total oil and gas
revenues for that year.
From time to time, the Company enters into crude oil price hedges to reduce
its exposure to commodity price fluctuation. At December 31, 1997, the Company
did not have any hedging agreements in place. See "Management's Discussion and
Analysis of Financial Condition and Results of Operations-Other Matters" 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.
In Kentucky and Tennessee, the Company owns and operates an extensive natural
gas gathering and transportation system consisting of approximately 340 miles of
pipeline, 16 gas compressor stations, two gas processing plants and two gas
storage reservoirs. The Company utilizes this system to procure, aggregate and
deliver natural gas produced from over 260 wells that are owned and operated by
the Company, comprising most of its Appalachian Basin natural gas production,
together with natural gas produced from wells owned and operated by others, in
meeting its delivery obligations under a sales contract with a local utility.
This sales contract, which expires on October 31, 1999, provides for market-
related pricing plus payment of a stated standby demand charge based on an
established peak-day delivery obligation. The maximum daily volume of natural
gas that the utility may demand is subject to annual adjustment (never to exceed
12,000 Mcf per day) and currently is fixed at 9,900 Mcf per day and will decline
to 8,910 Mcf per day effective November 1, 1998. For the year ended December 31,
1997, approximately 9% of the Company's total natural gas production was sold
under this sales contract. The Company also utilizes its Kentucky/Tennessee
gathering and transportation system to transport natural gas on behalf of third
parties and natural gas purchased from third parties for resale.
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. Although the Company has not entered into financial transactions to
hedge the price of its estimated future natural gas production for 1997 or
beyond, it may consider various hedging arrangements in the future.
NGLs. From its natural gas processing plants in West Texas and Kentucky, 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 market for NGLs in Kentucky is less
competitive, with higher transportation costs in that region due to the absence
of product pipelines. The Company's average price in 1997 for NGLs sold from
Company-operated plants or under processing agreements with others was $13.87
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 1997 was $18.02, compared to an average price
per Bbl of $18.99 that would have been received before the effects of the
Company's hedging activities. The average NYMEX-WTI closing price per Bbl for
1997 was $20.61.
11
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 1997 was $2.21. The
NYMEX-Henry Hub price per MMBtu for 1997, as represented by the annual average
of the closing price on the last three trading days for the prompt month NYMEX
natural gas futures contract applicable to each month in 1997, was $2.63. The
average natural gas price received by the Company in 1997 was lower than such
1997 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. The Company did not enter
into any natural gas price hedges during 1997.
12
OIL AND GAS RESERVES
The following table sets forth the proved developed and undeveloped reserves
of the Company at December 31, 1997:
OIL AND NGLS (MBBLS) GAS (MMCF) TOTAL RESERVES (MBOE)
------------------------------ ---------------------------- ---------------------------
DEVELOPED UNDEVELOPED TOTAL DEVELOPED UNDEVELOPED TOTAL DEVELOPED UNDEVELOPED TOTAL
--------- ---------- ----- --------- ----------- ----- --------- ----------- -----
Permian Basin
Maljamar........... 12,502 1,237 13,739 5,169 255 5,424 13,363 1,280 14,643
Wellman............ 6,696 -- 6,696 2,367 -- 2,367 7,091 -- 7,091
Dimmitt/Slash Ranch 2,037 227 2,264 7,236 454 7,690 3,234 312 3,546
------ ----- ------ ------- ------ ------- ------- ----- ------
Total............ 21,235 1,464 22,699 14,772 709 15,481 23,688 1,592 25,280
Appalachian Basin.... 788 -- 788 29,895 5,337 35,232 5,771 908 6,679
San Juan Basin....... 34 11 45 18,654 1,917 20,571 3,143 331 3,474
Other................ 1,741 44 1,785 24,367 1,297 25,664 5,810 232 6,042
------ ----- ------ ------- ------ ------- ------- ----- ------
Total United States.. 23,798 1,519 25,317 87,688 9,260 96,948 38,412 3,063 41,475
Canada............... 4,404 -- 4,404 21,771 1,375 23,146 8,032 230 8,262
------ ----- ------ ------- ------ ------- ------- ----- ------
Total Company........ 28,202 1,519 29,721 109,459 10,635 120,094 46,444 3,293 49,737
====== ===== ====== ======= ====== ======= ====== ===== ======
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, 1997, 1996 and 1995:
AT DECEMBER 31,
----------------------------------------
1997 1996 1995
--------- --------- ---------
(000's except weighted average sales prices)
Proved reserves:
Oil and NGLs (Bbl)....................................... 29,721 31,612 32,208
Gas (Mcf)................................................ 120,094 113,377 109,915
BOE.................................................... 49,737 50,508 50,527
Estimated future net revenues before income taxes........ $ 359,293 $ 705,723 $ 401,037
Present Value............................................ $ 210,087 $ 414,314 $ 235,416
Standardized Measure(1).................................. $ 174,489 $ 317,180 $ 194,602
Proved developed reserves:
Oil and NGLs (Bbl)....................................... 28,202 28,117 21,556
Gas (Mcf)................................................ 109,459 103,129 102,026
BOE.................................................... 46,444 45,305 38,560
Estimated future net revenues before income taxes........ $ 359,293 $ 631,406 $ 310,034
Present Value............................................ $ 311,848 $ 381,169 $ 195,439
Weighted average sales prices:
Oil (per Bbl)............................................ $ 15.92 $ 24.63 $ 18.19
Gas (per Mcf)............................................ 2.35 3.45 1.84
NGLs (per Bbl)........................................... 11.40 19.79 12.87
(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."
13
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 1997 could cause a significant decline in the
Present Value attributable to the Company's proved reserves at December 31,
1997. 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.
14
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, 1997.
YEAR ENDED DECEMBER 31,
--------------------------------------
1997 1996 1995
-------- --------- -------
PRODUCTION VOLUMES:
Oil (MBbl)
United States.......................................... 1,769 1,732 1,445
Canada................................................. 672 693 635
------ ------ ------
Total Company........................................ 2,441 2,425 2,104
Gas (MMcf)
United States (1)...................................... 10,095 9,479 9,418
Canada................................................. 2,734 2,809 2,753
------ ------ ------
Total Company (1).................................... 12,829 12,288 12,171
NGLs (MBbl)
United States.......................................... 267 301 212
Canada................................................. 52 50 40
------ ------ ------
Total Company........................................ 319 351 252
WEIGHTED AVERAGE SALES PRICES (2):
Oil (per Bbl)
United States.......................................... $ 18.30 $ 18.91 $ 17.14
Canada................................................. 17.28 18.55 16.38
Total Company........................................ 18.02 18.81 16.91
Gas (per Mcf)
United States (1)...................................... $ 2.46 $ 1.95 $ 1.46
Canada................................................. 1.26 1.16 1.05
Total Company........................................ 2.21 1.77 1.37
NGLs (per Bbl)
United States.......................................... $ 13.34 $ 12.88 $ 9.67
Canada................................................. 16.64 16.21 12.45
Total Company........................................ 13.87 13.36 10.11
SELECTED EXPENSES PER BOE (3):
Lease operating
United States.......................................... $ 5.03 $ 4.53 $ 4.59
Canada................................................. 3.50 3.04 2.58
Total Company........................................ 4.65 4.14 4.06
Production taxes (4)
United States.......................................... $ 1.02 $ 0.93 $ 0.78
Depreciation, depletion and amortization
United States.......................................... $ 3.88 $ 3.36 $ 3.63
Canada................................................. 7.58 6.49 7.37
Total Company........................................ 4.79 4.16 4.62
General and administrative
United States.......................................... $ 2.17 $ 2.11 $ 1.99
Canada................................................. 1.54 1.61 1.70
Total Company........................................ 2.02 1.98 1.92
- ---------------------
(1) Calculated by including volumes of natural gas purchased for resale as
follows: 1997 - 629 MMcf, 1996-605 MMcf and 1995-500 MMcf.
(2) Reflects results of hedging activities. See "Management's Discussion and
Analysis of Financial Condition and Results of Operations-Other Matters."
(3) Calculated without including volumes of natural gas purchased for resale.
15
(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, 1997:
Productive Wells
----------------------------------------------------------------
Oil Gas Total
------------------ ------------- -----------------
Gross Net Gross Net Gross Net
------ ---- -------- --- ----- ----
United States............................... 782 667 2,692 (1) 431 3,474 1,098
Canada...................................... 241 73 81 31 322 104
----- --- ----- --- ----- -----
Total..................................... 1,023 740 2,773 462 3,796 1,202
===== === ===== === ===== =====
(1) 2,200 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 0.21% to 4.2%.
Acreage
The following table sets forth the Company's undeveloped and developed gross
and net leasehold acreage at December 31, 1997. 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.
Undeveloped Developed Total
---------------- -------------- -----------------
Gross Net Gross Net Gross Net
----- ---- ----- --- ----- ----
Permian Basin
Maljamar.................................. -- -- 11,773 11,761 11,773 11,761
Wellman................................... -- -- 2,280 1,432 2,280 1,432
Dimmitt/Slash Ranch....................... 440 418 5,715 5,183 6,155 5,601
---------- --------- --------- --------- --------- ---------
Total................................... 440 418 19,768 18,376 20,208 18,794
Appalachian Basin......................... 15,483 11,608 112,488 95,334 127,971 106,942
San Juan Basin............................ -- -- 11,160 5,831 11,160 5,831
Other..................................... 121,424 50,386 50,567 17,930 171,990 68,316
------- -------- -------- -------- ------- --------
Total United States..................... 137,347 62,412 193,982 137,470 331,329 199,882
Canada.................................... 172,058 80,807 61,132 24,334 233,190 105,141
------- -------- -------- -------- ------- -------
Total..................................... 309,405 143,219 255,114 161,804 564,519 305,023
======= ======= ======= ======= ======= =======
(1) Excluded is acreage in which the Company's interest is limited to a mineral
or royalty interest. At December 31, 1997, the Company held mineral or
royalty interests in 278,536 gross (34,097 net) developed acres and
1,413,944 gross (208,159 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:
16
Acres Expiring
--------------
Gross Net
----- ---
Twelve Months Ending:
December 31, 1997...................................... 62,521 22,403
December 31, 1998...................................... 43,651 19,498
Thereafter............................................. 203,233 101,318
------- -------
Total................................................ 309,405 143,219
======= =======
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,
1997 the number of exploratory and development wells drilled by or on behalf of
the Company.
1997 1996 1995
------------------ --------------- ----------------
Gross Net Gross Net Gross Net
Exploratory Wells:
United States
Producing............................... 10 6 1 1 9 3
Dry..................................... 8 4 2 1 10 3
Canada
Producing............................... 3 2 1 1 3 2
Dry..................................... 1 1 6 4 4 2
Development Wells:
United States
Producing............................... 80 71 93 85 48 27
Dry..................................... 2 1 2 1 2 2
Canada
Producing............................... 39 18 21 15 4 2
Dry..................................... 6 4 5 3 2 2
Total Wells:
Producing............................... 132 97 116 102 64 34
Dry..................................... 17 10 15 9 18 9
--- --- --- --- -- --
Total................................. 149 107 131 111 82 43
=== === === === == ==
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, 1997, the Company
operated 100% of its properties in the Permian Basin, comprising approximately
51% of the Company's total proved reserves, including Maljamar (231 gross
wells), Wellman (18 gross wells) and Dimmitt/Slash Ranch (83 gross wells). At
December 31, 1997, the Company owned 358 gross wells on its Kentucky and
Tennessee properties, of which approximately 98% were operated by the Company.
At that same date, the Company also operated 100 (out of a total of 322) gross
wells on its Canadian properties.
17
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 1997 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, downhole 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 insurance coverage, including
a $1.0 million general liability insurance policy and a $20.0 million excess
liability policy. The Company believes that its insurance is adequate and
customary for companies of a similar size engaged
18
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, 1997, the Company's leaseholds for
approximately 61% 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.
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.
19
Since the mid-1980's, the FERC has issued a series of orders, culminating in
Order Nos. 636, 636-A and 636-B ("Order 636"), that have significantly altered
the marketing and transportation of natural gas. Order 636 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. One of the FERC's purposes in issuing the
orders was to increase competition within all phases of the natural gas
industry. Order 636 and subsequent FERC orders issued in individual pipeline
restructuring proceedings have been the subject of appeals, and the courts have
largely upheld Order 636. Because further review of certain of these orders is
still possible, and other appeals remain pending, it is difficult to exactly
predict the ultimate impact of the orders on the Company and its natural gas
marketing efforts. Generally, Order 636 has eliminated or substantially reduced
the interstate pipelines' traditional role as wholesalers of natural gas, and
has substantially increased competition and volatility in natural gas markets.
While significant regulatory uncertainty remains, Order 636 may ultimately
enhance the Company's ability to market and transport its natural gas, although
it may also subject the Company to greater competition, more restrictive
pipeline imbalance tolerances and greater associated penalties for violation of
such tolerances.
The FERC has announced several important transportation-related policy
statements and proposed rule changes, including the appropriate manner in which
interstate pipelines release capacity under Order 636 and, more recently, the
price which shippers can charge for their released capacity. In addition, in
1995, the FERC issued a policy statement on how interstate natural gas pipelines
can recover the costs of new pipeline facilities. In January 1997, the FERC
issued a policy statement and a request for comments concerning alternatives to
its traditional cost-of-service ratemaking methodology. A number of pipelines
have obtained FERC authorization to charge negotiated rates as one such
alternative. While any additional FERC action on these matters would affect the
Company only indirectly, these policy statements and proposed rule changes are
intended to further enhance competition in natural gas markets. The Company
cannot predict what action the FERC will take on these matters, nor can it
predict whether the FERC's actions will achieve its stated goal of increasing
competition in natural gas markets. However, the Company does not believe that
it will be treated materially differently than other natural gas producers and
marketers with which it competes.
Commencing in May 1994, the FERC issued a series of orders in individual cases
that delineate its new gathering policy. Among other matters, the FERC slightly
narrowed its statutory tests for establishing gathering status and reaffirmed
that, except in situations in which the gatherer acts in concert with an
interstate pipeline affiliate to frustrate the FERC's transportation policies,
it does not generally have jurisdiction over natural gas gathering facilities
and services, and that such facilities and services located in state
jurisdictions are properly regulated by state authorities. In addition, the FERC
has approved numerous transfers by interstate pipelines of gathering facilities
to unregulated independent or affiliated gathering companies, subject to the
transferee providing service for two years from the date of transfer to the
pipeline's existing customers pursuant to a default contract or pursuant to
mutually agreeable terms. In August 1997, the United States Court of Appeals for
the District of Columbia largely upheld the FERC's new gathering policy, but
remanded the FERC's default contract condition. The FERC has not yet issued an
order on remand. This new gathering policy may tend to increase competition
among gatherers, like the Company. This policy may also result in increased
state regulation of the Company's gathering facilities. However, the Company
does not believe that it will be affected materially differently by this policy
than other producers, gatherers 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.
20
The price the Company receives from the sale of oil and NGLs is affected by
the cost of transporting such products to market. Effective January 1, 1995, the
FERC implemented regulations establishing an indexing system for transportation
rates for oil pipelines, which, generally, would index such rates to inflation,
subject to certain conditions and limitations. These regulations could increase
the cost of transporting oil and NGLs by interstate pipelines, although the most
recent adjustment generally decreased rates. These regulations have generally
been approved on judicial review. The Company is not able to predict with
certainty the effect, if any, of these regulations on its operations. However,
the regulations may increase transportation costs or reduce wellhead prices for
oil and NGLs.
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
21
properties acquired from corporations claiming maximum entitlement to ARTC will
generally not be eligible for ARTC.
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
22
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. 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 27, 1998, the Company employed 143 full-time employees, of whom
five were executive officers, 28 were technical personnel, 57 were field
personnel and 53 were administrative personnel. Of the total employees, 115 were
located in the United States and 28 were located in Canada. At February 28,
1998, 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 Company also maintains a
regional office in Corbin, Kentucky consisting of a one-story building
containing approximately 7,400 square feet of office space. The Company owns
this building. 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 June 30, 1999. Rental payments are approximately $12,500 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.
23
"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.
"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.
24
"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%.
"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.
25
"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.
"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, 1997.
26
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, 1997, were as follows:
High Low Dividends
---- --- ---------
y
1997
First Quarter........................................... $ 22.38 $ 17.63 $ .03
Second Quarter.......................................... 18.88 15.13 .03
Third Quarter........................................... 18.75 14.06 .03
Fourth Quarter.......................................... 18.75 13.06 .03
1996
First Quarter........................................... $ 13.38 $ 11.00 $ .03
Second Quarter.......................................... 14.00 12.25 .03
Third Quarter........................................... 15.50 12.88 .03
Fourth Quarter.......................................... 21.13 14.38 .03
1995
First Quarter........................................... $ 14.75 $ 13.38 $ .10
Second Quarter.......................................... 15.00 13.13 .10
Third Quarter........................................... 14.38 13.00 .10
Fourth Quarter.......................................... 13.75 10.88 .10
At February 28, 1998, there were 8,951,965 shares of Common Stock outstanding
held by approximately 926 shareholders of record and approximately 2,569
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.
Although the Company does not have a written dividend policy, it has paid cash
dividends on the Common Stock for the previous 105 quarters. Dividends on the
Common Stock are reviewed by the Board of Directors of the Company each quarter,
and no assurances can be given that such cash dividends will continue in the
future or, if such dividends are paid, as to the amount of such dividends. In
addition, under the terms of the Credit Agreement (see Note 3 to the Company's
Consolidated Financial Statements), the payment of dividends in any year is
limited to the greater of (i) 80% of the Company's adjusted consolidated net
income (as defined in the Credit Agreement) for such year (which excludes gains
from sales of marketable securities) and (ii) $4.5 million.
27
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.
Year Ended December 31,
-------------------------------------------------------
1997 1996 1995 1994 1993
--------- --------- --------- --------- -------
INCOME STATEMENT DATA (000'S EXCEPT PER SHARE AMOUNTS):
Revenues:
Oil and gas sales......................................... $ 76,729 $ 72,012 $54,400 $ 53,559 $ 40,329
Dividends and interest.................................... 1,113 683 1,241 1,641 1,855
Marketable security sales gains........................... 7,495 12,977 13,101 7,475 --
Other..................................................... 2,478 1,017 2,939 2,681 737
-------- -------- -------- -------- ---------
Total revenues.......................................... 87,815 86,689 71,681 65,356 42,921
------- ------- ------- ------- -------
Costs and expenses:
Production and operating.................................. 27,183 23,970 20,690 22,313 17,864
Purchased natural gas..................................... 1,622 1,462 727 759 1,182
Depreciation, depletion and amortization ("DD&A")......... 22,977 19,653 19,778 18,313 14,659
Property impairments...................................... 3,289 12,112 4,893 -- 693
Exploration............................................... 9,655 4,176 5,801 4,130 3,639
General and administrative................................ 9,661 9,364 8,193 6,502 5,429
Interest expense.......................................... 9,845 5,452 5,618 3,907 530
-------- -------- -------- --------- ---------
Total costs and expenses................................ 84,232 76,189 65,700 55,924 43,996
------- ------- ------- -------- -------
Earnings (loss) before income taxes......................... 3,583 10,500 5,981 9,432 (1,075)
Income tax expense (benefit)................................ 264 4,072 3,788 444 (2,091)
-------- -------- -------- -------- --------
Net income.................................................. $ 3,319 $ 6,428 $ 2,193 $ 8,988 $ 1,016
======== ======== ======== ======== ========
Average outstanding shares (000's) (1)...................... 8,949 8,939 8,939 8,941 8,939
Basic earnings per share.................................... $ 0.37 $ 0.72 $ 0.25 $ 1.01 $ 0.11
Cash dividends per share.................................... $ 0.12 $ 0.12 $ .40 $ 0.40 $ 0.40
OTHER FINANCIAL DATA (000'S):
EBITDA (2).................................................. $ 40,741 $ 38,233 $ 27,729 $ 26,666 $ 16,591
Operating cash flow......................................... 34,486 34,287 20,541 24,334 16,892
Capital and exploration expenditures........................ 78,323 47,115 30,153 74,610 71,002
BALANCE SHEET DATA - END OF PERIOD (000'S):
Cash and cash equivalents................................... $ 13,255 $ 5,870 $ 1,397 $ 2,714 $ 3,499
Working capital (3)......................................... 7,809 3,493 1,034 2,313 6,454
Marketable securities....................................... -- 7,176 19,592 27,337 34,781
Net property, plant and equipment........................... 220,708 179,718 169,089 167,371 127,708
Total assets................................................ 254,556 208,617 203,407 210,791 177,782
Long term debt.............................................. 124,304 78,654 74,171 78,013 46,777
Stockholders' equity........................................ 97,424 99,262 101,132 105,427 105,116
28
Year Ended December 31,
--------------------------------------------------------
1997 1996 1995 1994 1993
-------- --------- -------- -------- --------
RESERVE AND OPERATING DATA:
Production and volumes:
Oil and NGLs (MBbl)....................................... 2,760 2,776 2,332 2,277 1,468
Gas (MMcf) (4)............................................ 12,829 12,288 12,171 11,076 8,296
BOE (000's) (4)......................................... 4,898 4,824 4,361 4,123 2,851
Weighted average sales prices (5):
Oil (per Bbl)............................................. $ 18.02 $ 18.81 $ 16.91 $ 15.60 $ 16.44
Gas (per Mcf)............................................. 2.21 1.77 1.37 1.73 2.07
NGLs (per Bbl)............................................ 13.87 13.36 10.11 9.00 9.42
BOE (per Bbl)........................................... 15.66 14.93 12.47 12.99 14.15
Selected expenses per BOE (6):
Lease operating........................................... $ 4.65 $ 4.14 $ 4.06 $ 4.54 $ 5.80
Production taxes.......................................... 1.02 0.93 0.78 0.97 0.72
DD&A...................................................... 4.79 4.16 4.62 4.53 5.35
General and administrative................................ 2.02 1.98 1.92 1.61 1.98
Proved reserves (end of year) (7):
Oil and NGLs (MBbls)...................................... 29,721 31,612 32,208 23,430 21,242
Gas (MMcf)................................................ 120,094 113,377 109,915 107,920 103,317
BOE (MBbls)............................................. 49,737 50,508 50,527 41,417 38,462
Estimated future net revenues before income taxes (000's). $ 359,293 $ 705,723 $ 401,037 $ 272,776 $ 241,251
Present Value............................................. 210,087 414,314 235,416 160,804 137,149
Standardized Measure (000's) (8).......................... 174,489 317,180 194,602 142,032 112,423
Weighted average sales prices (end of year) (7)(9):
Oil (per Bbl)............................................. $ 15.92 $ 24.63 $ 18.19 $ 16.11 $ 13.35
Gas (per Mcf)............................................. 2.35 3.45 1.84 1.57 2.34
NGLs (per Bbl)............................................ 11.40 19.79 12.87 9.80 9.07
(1) Basic earnings per share is calculated without including dilutive effect
of common stock equivalents consisting of stock options. See Note 11 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: 1997-629 MMcf, 1996-605 MMcf, 1995-500 MMcf, 1994-469 MMcf and
1993-666 MMcf.
(5) Reflects results of hedging activities. See "Management's Discussion and
Analysis of Financial Condition and Results of Operations-Other Matters."
(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.
29
(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.
30
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, 1997. 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 results of operations have been significantly affected by its
Maljamar waterflood project, Wellman Unit CO2 gas injection project and 1994
acquisition and subsequent development, exploitation and exploration of its
Canadian oil and gas properties. The Company has achieved increases in its oil
and gas production primarily as a result of these activities.
The Company has been liquidating portions of its marketable securities
portfolio in order to fund a portion of the Company's capital and exploration
expenditures. The Company recognized pretax gains from the sale of marketable
securities of $7.5 million, $13.0 million and $13.1 million in 1997, 1996 and
1995, respectively. In the absence of such gains, the Company would have
reported net losses in each year of the three year period ended December 31,
1997. The Company completed the liquidation of its marketable securities
portfolio in 1997. Accordingly, the positive impact that sales of marketable
securities have had on the Company's net income will not continue, and sales of
marketable securities will no longer be a source of funds, beyond 1997.
During 1995, the Company adopted SFAS No. 121, "Accounting for the Impairment
of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of," which
requires the Company to assess the need for an impairment of capitalized costs
of oil and gas properties on a property-by-property (rather than a company-wide)
basis. Applying SFAS No. 121, the Company recognized non-cash property
impairment charges of $3.3 million in 1997, $12.1 million in 1996 and $4.9
million in 1995.
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, 1997, the Company's proved reserves were comprised of
approximately 89% proved developed reserves, and the Company does not have a
large inventory of development drilling locations or enhanced recovery projects
to pursue after 1997. 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, and 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.
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 629 MMcf in 1997, 605 MMcf in 1996 and 500 MMcf in
1995.
COMPARISON OF 1997 TO 1996
REVENUES
31
OIL AND GAS SALES increased 7% to $76.7 million in 1997 from $72.0 million in
1996, primarily because of higher gas production and higher gas prices received
during 1997. Gas production during 1997 increased 4% to 12.8 Bcf from 12.3 Bcf
in 1996. The increase in gas production was primarily attributable to the
acquisition of the Welder Ranch field in South Texas which added 0.8 Bcf of gas
production during 1997. The average gas price received in 1997 increased 25% to
$2.21 per Mcf from $1.77 per Mcf in 1996. Oil production in 1997 increased less
than 1% to 2,441 MBbls from 2,425 MBbls in 1996. The Company completed 50 wells
in the Maljamar field during 1997 which increased 1997 production by 246 MBbls
over 1996 and offset declining oil production in other fields during 1997. The
average oil price received in 1997 decreased 4% to $18.02 per Bbl from $18.81
per Bbl in 1996. As a result of hedging activities, oil and gas sales were
reduced by $2.4 million and $6.9 million during 1997 and 1996, respectively. On
an equivalent unit basis, total production increased 2% to 4,898 MBOE in 1997
from 4,824 MBOE in 1996.
MARKETABLE SECURITY SALES GAINS decreased 42% to $7.5 million in 1997 from $13.0
million in 1996 as the Company completed the liquidation of its remaining
marketable securities in 1997.
OTHER REVENUES increased 144% to $2.5 million in 1997 from $1.0 million in 1996
primarily as a result of the sale of non-strategic oil and gas properties in
Michigan during 1997.
COSTS AND EXPENSES
PRODUCTION AND OPERATING EXPENSE increased 13% to $27.2 million in 1997 from
$24.0 million in 1996 and also increased 12% to $5.67 per BOE in 1997 from $5.07
per BOE in 1996. The increases were primarily attributable to additional wells
drilled at the Maljamar and Provost fields and increased production taxes
associated with the 7% increase in oil and gas sales during 1997.
DEPRECIATION, DEPLETION AND AMORTIZATION increased 17% to $23.0 million in 1997
from $19.7 million in 1996 and increased 15% to $4.79 per BOE in 1997 from $4.16
per BOE in 1996. The increases were primarily attributable to additional wells
drilled at the Maljamar field to develop proved undeveloped reserves combined
with increased depletion from the Shouldice and other Canadian properties which
have a higher than average cost basis and shorter than average reserve life.
IMPAIRMENT EXPENSE decreased 73% to $3.3 million in 1997 from $12.1 million in
1996. Impairment expense in 1997 was due primarily to low oil prices used to
value reserves at year-end 1997 while impairment expense in 1996 was due
primarily to downward revisions in reserve estimates for certain properties in
Michigan and Canada.
EXPLORATION EXPENSE increased 131% to $9.7 million in 1997 from $4.2 million in
1996 as the Company increased its exploration activities in the U.S. during
1997. Dry hole expense increased 141% to $4.1 million in 1997 from $1.7 million
in 1996. Dry hole expense in 1997 included $1.2 million at the South Lakeside
prospect in Louisiana, $1.0 million at the Tecumseh prospect in Louisiana and
$0.7 million at the Bronson prospect in Canada. Seismic expense also increased
to $3.4 million in 1997 from $0.3 million in 1996.
GENERAL AND ADMINISTRATIVE EXPENSE ("G&A") increased 3% to $9.7 million in 1997
from $9.4 million in 1996 and also increased 2% to $2.02 per BOE in 1997 from
$1.98 per BOE in 1996. The increase in G&A was attributable primarily to the
addition of exploration personnel and higher compensation costs.
INTEREST EXPENSE increased 81% to $9.8 million in 1997 from $5.5 million in 1996
as a result of the increase in long term debt and the higher interest rate
associated with the sale of 9 1/2% Senior Subordinated Notes ("2007 Notes") on
May 21, 1997.
INCOME TAX EXPENSE decreased $3.8 million to $0.3 million in 1997 from $4.1
million in 1996 as a result of a decrease in earnings before income taxes of
$6.9 million combined with a lower effective tax rate of 7% in 1997 compared to
39% in 1996. The lower effective tax rate in 1997 was attributable primarily to
the inclusion of Canadian operations in the Company's consolidated tax return
beginning in 1997.
32
NET INCOME
Net income decreased 48% to $3.3 million in 1997 from $6.4 million in 1996
primarily as a result of higher production and operating expense, DD&A,
exploration and interest expense in 1997.
COMPARISON OF 1996 TO 1995
REVENUES
OIL AND GAS SALES increased 32% to $72.0 million in 1996 from $54.4 million in
1995 due to higher production and higher prices received during 1996. Oil
production in 1996 increased 17% to 2,425 MBbls from 2,080 MBbls in 1995. The
increase in oil production was primarily attributable to development activities
which resulted in the addition of 102 net wells in 1996. The average oil price
received in 1996 increased 11% to $18.81 per Bbl from $16.91 per Bbl in 1995.
Gas production during 1996 increased 1% to 12.3 Bcf from 12.2 Bcf in 1995 and
the average gas price received in 1996 increased 29% to $1.77 per Mcf from $1.37
per Mcf in 1995. As a result of hedging activities, oil and gas sales were
reduced by $6.9 million during 1996. On an equivalent unit basis, total
production increased 11% to 4,824 MBOE in 1996 from 4,361 MBOE in 1995.
MARKETABLE SECURITY SALES GAINS decreased 1% to $13.0 million in 1996 from $13.1
million in 1995 as the Company continued the liquidation of its marketable
securities portfolio in 1996.
OTHER REVENUES decreased 66% to $1.0 million in 1996 from $2.9 million in 1995
primarily as a result of fewer sales of non-strategic oil and gas properties
during 1996.
COSTS AND EXPENSES
PRODUCTION AND OPERATING EXPENSE increased 16% to $24.0 million in 1996 from
$20.7 million in 1995 and also increased 5% to $5.07 per BOE in 1996 from $4.84
per BOE in 1995. The increases were primarily attributable to increased
production taxes associated with the 32% increase in oil and gas sales during
1996.
DD&A decreased 1% to $19.7 million in 1996 from $19.8 million in 1995 and
decreased 10% to $4.16 per BOE in 1996 from $4.62 per BOE in 1995. The decreases
were primarily attributable to upward revisions in reserve estimates during 1996
for the Maljamar, Wellman and Evi fields.
IMPAIRMENT EXPENSE increased 148% to $12.1 million in 1996 from $4.9 million in
1995. Impairment expense in 1996 was due primarily to downward revisions in
reserve estimates for certain properties in Michigan and Canada while impairment
expense in 1995 was due to downward revisions in reserve estimates for certain
Canadian properties.
EXPLORATION EXPENSE decreased 28% to $4.2 million in 1996 from $5.8 million in
1995, primarily as a result of a temporary reduction by the Company in its 1996
domestic exploration activities due to a redirection of its exploration program
in the fourth quarter of 1996.
G&A increased 15% to $9.4 million in 1996 from $8.2 million in 1995 and also
increased 3% to $1.98 per BOE from $1.92 per BOE in 1995. The increase in G&A
was attributable primarily to higher compensation costs and professional fees
relating to acquisition and taxation matters.
INTEREST EXPENSE decreased 2% to $5.5 million in 1996 from $5.6 million in 1995.
INCOME TAX EXPENSE increased 7% to $4.1 million in 1996 from $3.8 million in
1995 as a result of an increase in earnings before income taxes of $4.5 million
offset by a lower effective tax rate of 39% in 1996 compared to 63% in 1995. The
lower effective tax rate in 1996 was attributable to a decrease in the amount of
tax loss attributable to the Company's Canadian operations that was not
deductible for U.S. federal income tax purposes. In addition, the
33
Company's Section 29 income tax credits relating to its San Juan Basin
properties increased 15% to $1.5 million in 1996 from $1.3 million in 1995.
NET INCOME
Net income increased 191% to $6.4 million in 1996 from $2.2 million in 1995
primarily as a result of higher production and net realized prices received in
1996.
LIQUIDITY AND CAPITAL RESOURCES
CASH FLOWS
Cash flows from operating activities were $34.5 million and $34.3 million in
1997 and 1996, respectively. Cash flows in 1997 were increased by higher oil and
gas sales and decreased by higher interest expense and production and operating
expense resulting in a small net increase over 1996. Cash flows from financing
activities were $39.8 million in 1997, up $37.6 million from 1996 as a result of
the sale of $125 million of 2007 Notes. The sale of the 2007 Notes provided
$120.9 million of net cash proceeds to the Company, and $78.7 million of
borrowings under the Credit Agreement and the Company's Maljamar Credit Facility
were repaid during 1997. The Maljamar Credit Facility was terminated in 1997 in
connection with such repayment of borrowings. Cash flows used in investing
activities were $66.9 million in 1997 compared to $32.1 million in 1996. Capital
and exploration expenditures were $78.3 million in 1997, an increase of $31.2
million over 1996. The major components of capital and exploration expenditures
for 1997 were: $17.9 million for Maljamar development; $21.6 million for proved
property acquisitions; and $12.4 million for exploration. Proceeds from the sale
of marketable securities and oil and gas properties were $11.4 million in 1997,
down $3.6 million from 1996, primarily as a result of reduced sales of
marketable securities in 1997.
FINANCIAL POSITION
Cash and cash equivalents increased $7.4 million during 1997 to $13.3 million at
December 31, 1997 primarily because of the sale of the 2007 Notes. Working
capital of $7.8 million at December 31, 1997 was also higher than working
capital at December 31, 1996 due primarily to the sale of the 2007 Notes. Total
assets increased $45.9 million during 1997 to $254.6 million at December 31,
1997, and long term debt increased $45.7 million during 1997 to $124.3 million
at December 31, 1997.
At December 31, 1997, capitalization totaled $221.7 million and consisted of
$124.3 million of long term debt (56%) and $97.4 million of stockholders' equity
(44%).
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. The Company
believes that cash flows from operations and borrowings under the Credit
Agreement will be sufficient to meet anticipated capital and exploration
expenditure requirements (excluding any material property acquisitions) in 1998.
If the Company's cash flows from operations and borrowings under the Credit
Agreement 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.
The Company has 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"). The Credit Agreement's borrowing base is
currently $80 million. There were no outstanding borrowings at December 31,
1997. The borrowing base is redetermined annually by the lenders based on the
most recent valuation
34
of the Company's oil and gas reserves. Accordingly, the current borrowing base
of $80 million could be reduced in 1998. See Note 3 to the Company's
Consolidated Financial Statements.
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 1998, subject to
market conditions and drilling and operating results, the Company expects to
spend approximately $52 million on acquisition, development, exploitation and
exploration activities. Of this amount, the Company has budgeted $12 million for
acquisition of proved and unproved properties, $18 million for development and
exploitation activities and $22 million for exploration activities.
OTHER MATTERS
HEDGING ACTIVITIES
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 adjusts the
price received for the hedged production during the period the hedged
transactions occur. Adjustments to oil and gas sales from the Company's hedging
activities resulted in a reduction of $2.4 million and $6.9 million in the
Company's revenues for the years ended December 31, 1997 and 1996, respectively.
Hedging activities in 1995 did not result in any material increase or decrease
in oil and gas revenues. The Company expects that the amount of production it
hedges will vary from time to time. The Company continuously reevaluates its
hedging program in light of market conditions, commodity price forecasts,
capital spending and debt service requirements. There are currently no hedging
agreements in place. See Note 1 to the Company's Consolidated Financial
Statements.
EFFECTS OF FLUCTUATIONS IN EXCHANGE RATES
The Company receives a substantial portion of its revenue in Canadian dollars
(18% in 1997). 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, exchange
rate fluctuations have not been material to the Company.
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
The Company has assessed and continues to assess the impact of the "year 2000"
issue on its reporting systems and operations. The "year 2000" issue exists
because many computer systems and applications currently use two-digit
35
date fields to designate a year. As the century date occurs, two-digit date
systems will 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. The Company anticipates that
all its significant computer systems and software will be year 2000 compliant
during 1998. Management does not estimate future expenditures related to the
year 2000 exposure to be material.
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 in 1998 and thereafter 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.
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.
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
36
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.
37
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 and Retained Earnings
Consolidated Balance Sheets
Consolidated Statements of Cash Flows
Notes to Consolidated Financial Statements
2. Scheduled are omitted because of the absence of conditions under which
they are required information is given in the financial statements or
notes thereto.
B. Reports on Form 8-K.
The following reports on Form 8-K were filed by the Company during the last
quarter of 1997:
Date of Report Item Reported Financial Statements Filed
-------------- ------------- --------------------------
October 15, 1997 Item 5 None
November 12, 1997 Item 5 None
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) Amendment No. 1 to the 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
the Company's report on Form 8 -K/A filed on September 29,1995.
(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.
38
(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 dated 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.
(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
4.5 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.
(4.12) Credit Agreement dated November 29, 1995 among The Wiser Oil Company
and Maljamar Development Partnership, L.P. as Borrowers, and
NationsBank of Texas, N.A., as Agent, and Certain Financial
Institutions Listed on the Signature Pages thereto, as Banks.
(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.
39
(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 as amended by Form 8-K/A filed on August 17, 1994.
(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.
(10.5)+ 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 May 20, 1997.
(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.
(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 May 20, 1997.
(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 May 20, 1997.
(10.10)+ Employment Agreement dated September 30, 1997 between the Company and
Kent E. Johnson, incorporated by reference to Exhibit 10.10 to the
Company's Annual Report on Form 10-K (Commission File No. 0-5426),
filed on March 26, 1997.
(10.10a)+* Amendment to Employment Agreement dated September 30, 1997 between
the Company and Kent E. Johnson dated May 20, 1997.
(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 (Commission File No. 0-5426),
filed on March 26, 1997.
(10.12)* The Wiser Oil Company Savings Restoration Plan dated February 24,
1998.
40
(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 Lausten Jung Associates Ltd., Independent
Petroleum Engineers.
(27)* Financial Data Schedule.
______________
+ Represent management compensatory plans or agreements.
* Filed herewith.
41
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 30TH DAY OF
MARCH 1998.
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.
SIGNATURE TITLE DATE
/s/ ANDREW J. SHOUP, JR. President, Chief Executive March 30, 1998
- ------------------------------ Officer and Director
(Principal Executive
Officer)
/s/ PAUL D. NEUENSHWANDER Director March 30, 1998
- ------------------------------
/s/ C. FRAYER KIMBALL Director March 30, 1998
- ------------------------------
/s/ HOWARD G. HAMILTON Director March 30, 1998
- ------------------------------
/s/ A. W. SCHENCK, III Director March 30, 1998
- ------------------------------
/s/ JOHN W. CUSHING, III Director March 30, 1998
- ------------------------------
/s/ JON L. MOSLE, JR. Director March 30, 1998
- ------------------------------
/s/ LORNE H. LARSON Director March 30, 1998
- ------------------------------
/s/ LAWRENCE J. FINN Vice President and Chief March 30, 1998
- ------------------------------ Financial Officer
(Principal Financial and
Accounting Officer)
42
THE WISER OIL COMPANY
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
PAGE
----
Report of Independent Public Accountants........................... F-2
Consolidated Statements of Income and Retained Earnings............ F-3
Consolidated Balance Sheets........................................ F-4
Consolidated Statements of Cash Flows.............................. F-5
Notes to Consolidated Financial Statements......................... F-6
F-1
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, 1997 and
1996 and the related consolidated statements of income and retained earnings and
cash flows for the years ended December 31, 1997, 1996 and 1995. These financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the consolidated financial position of The Wiser Oil
Company and subsidiaries as of December 31, 1997 and 1996 and the results of
their operations and their cash flows for each of the three years in the period
ended December 31, 1997, in conformity with generally accepted accounting
principles.
As discussed in Note 1 to the consolidated financial statements, at December 31,
1995, the Company changed its method of accounting for the impairment of
long-lived assets.
ARTHUR ANDERSEN LLP
Dallas, Texas,
February 18, 1998
F-2
THE WISER OIL COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND RETAINED EARNINGS
For the Years Ended December 31, 1997, 1996 and 1995
1997 1996 1995
-------- --------- ---------
(000's except per share data)
Revenues:
Oil and gas sales.................................... $ 76,729 $ 72,012 $ 54,400
Dividends and interest............................... 1,113 683 1,241
Marketable security sales............................ 7,495 12,977 13,101
Other................................................ 2,478 1,017 2,939
----------------------------------------
87,815 86,689 71,681
----------------------------------------
Costs and Expenses:
Production and operating............................. 27,183 23,970 20,690
Purchased natural gas................................ 1,622 1,462 727
Depreciation, depletion and amortization............. 22,977 19,653 19,778
Property impairments................................. 3,289 12,112 4,893
Exploration.......................................... 9,655 4,176 5,801
General and administrative........................... 9,661 9,364 8,193
Interest expense..................................... 9,845 5,452 5,618
----------------------------------------
84,232 76,189 65,700
----------------------------------------
Earnings Before Income Taxes.............................. 3,583 10,500 5,981
Income Tax Expense........................................ 264 4,072 3,788
----------------------------------------
NET INCOME................................................ 3,319 6,428 2,193
Retained Earnings, beginning of year...................... 66,385 61,030 62,414
Dividends Paid............................................ (1,074) (1,073) (3,577)
----------------------------------------
Retained Earnings, end of year............................ $ 68,630 $ 66,385 $ 61,030
========================================
Earnings Per Share (Note 11):
Basic................................................... $.37 $.72 $.25
========================================
Diluted................................................. $.37 $.72 $.25
========================================
Cash Dividends Per Share.................................. $.12 $.12 $.40
========================================
The accompanying notes are an integral part of these financial statements.
F-3
THE WISER OIL COMPANY
CONSOLIDATED BALANCE SHEETS
December 31, 1997 and 1996
1997 1996
---------- ----------
(000's)
ASSETS
Current Assets:
Cash and cash equivalents................................. $ 13,255 $ 5,870
Accounts receivable....................................... 13,765 14,091
Inventories............................................... 1,007 1,289
Prepaid income taxes...................................... 725 --
Prepaid expenses.......................................... 438 473
--------------------------
Total current assets.................................. 29,190 21,723
--------------------------
Marketable Securities.......................................... -- 7,176
Property, Plant and Equipment, at cost:
Oil and gas properties (successful efforts method)........ 346,655 306,716
Other properties.......................................... 5,399 4,974
--------------------------
352,054 311,690
Accumulated depreciation, depletion and amortization...... (131,346) (131,972)
--------------------------
Net property, plant and equipment......................... 220,708 179,718
Other Assets................................................... 4,658 --
--------------------------
$ 254,556 $ 208,617
==========================
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Accounts payable.......................................... $ 18,396 $ 14,996
Accrued income taxes...................................... -- 1,697
Accrued liabilities....................................... 2,985 1,537
--------------------------
Total current liabilities............................... 21,381 18,230
--------------------------
Long Term Debt................................................. 124,304 78,654
Deferred Benefit Cost.......................................... 1,169 1,496
Deferred Income Taxes.......................................... 10,278 10,975
Stockholders' Equity:
Common stock - $3 par value; 20,000,000 shares authorized;
shares issued, 1997 - 9,128,169, 1996 - 9,115,572;
shares outstanding, 1997 - 8,951,965, 1996 - 8,939,368 . 27,385 27,347
Paid-in capital........................................... 3,223 3,078
Retained earnings......................................... 68,630 66,385
Marketable securities valuation adjustment................ -- 4,328
Foreign currency translation.............................. 915 853
Treasury stock; 176,204 shares, at cost................... (2,729) (2,729)
--------------------------
Total stockholders' equity.............................. 97,424 99,262
--------------------------
$ 254,556 $ 208,617
==========================
The accompanying notes are an integral part of these financial statements.
F-4
THE WISER OIL COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 1997, 1996 and 1995
1997 1996 1995
-------- --------- ---------
(000's except per share data)
Cash Flows from Operating Activities:
Net income........................................... $ 3,319 $ 6,428 $ 2,193
Adjustments to reconcile to cash flows from
operating activities:
Depreciation, depletion and amortization......... 22,977 19,653 19,778
Deferred income taxes............................ 1,530 2,056 1,914
Marketable securities and property sales gains... (9,370) (13,099) (14,092)
Exploration expense.............................. 9,655 4,176 5,801
Property impairments............................. 3,289 12,112 4,893
Foreign currency translation..................... 62 (2) (34)
Amortization of other assets..................... 282 -- --
Other changes:
Accounts receivable............................ 326 (3,665) 474
Inventories.................................... 282 228 (373)
Prepaid income taxes........................... (725)
-- --
Prepaid expenses............................... 35 360 19
Other assets................................... -- 553 (80)
Accounts payable............................... 3,400 4,853 661
Accrued income taxes........................... (1,697) 170 9
Accrued liabilities............................ 1,449 88 (690)
Deferred benefit costs......................... (328) 376 68
------------------------------------------
Operating Cash Flows......................... 34,486 34,287 20,541
-----------------------------------------
Cash Flows From Investing Activities:
Capital and exploration expenditures................. (78,323) (47,115) (30,153)
Proceeds from sales of property, plant and equipment. 3,288 1,022 1,280
Proceeds from sales of marketable securities......... 8,115 14,035 14,492
------------------------------------------
Investing Cash Flows......................... (66,920) (32,058) (14,381)
----------------------------------------
Cash Flows From Financing Activities:
Borrowings of long term debt......................... 125,000 25,508 11,170
Repayments of long term debt......................... (78,654) (22,191) (15,070)
Long term debt issuance costs and fees............... (5,636) -- --
Common stock issued.................................. 183 -- --
Dividends paid....................................... (1,074) (1,073) (3,577)
-----------------------------------------
Financing Cash Flows......................... 39,819 2,244 (7,477)
-----------------------------------------
Net Increase (Decrease) in Cash........................... 7,385 4,473 (1,317)
Cash and Cash Equivalents, beginning of year.............. 5,870 1,397 2,714
-----------------------------------------
Cash and Cash Equivalents, end of year.................... $ 13,255 $ 5,870 $ 1,397
========================================
The accompanying notes are an integral part of these financial statements.
F-5
THE WISER OIL COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 1997, 1996 and 1995
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: T.W.O.C., Inc., The Wiser
Marketing Company, Maljamar Wiser Inc., Maljamar Development Partnership,
L.P., and The Wiser Oil Company of Canada ("Wiser Canada"). T.W.O.C., Inc.
is a Delaware holding company responsible for the management of investment
activities. The Wiser Marketing Company functions as a natural gas marketer
and broker. Maljamar Wiser Inc. was formed in 1995 as a wholly-owned
subsidiary of the Company. It was formed in order for the Company to fund
its $53,000,000 development of the Maljamar area with the use of
nonrecourse debt. The Maljamar Development Partnership, L.P. was formed in
1995 for the same reason. The Company is the limited partner of the
Maljamar Development Partnership, L.P. and owns 99% of the partnership.
Maljamar Wiser Inc. owns 1% of the Maljamar Development Partnership, L.P.
as a general partner. Effective May 14, 1997, Maljamar Wiser, Inc. was
merged into The Wiser Oil Company and Maljamar Development Partnership,
L.P. was terminated. 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. 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 generally accepted accounting principles requires
management to make estimates and assumptions that affect the reported
amounts of assets and liabilities and disclosure of contingent assets and
liabilities at the date of the financial statements and the reported
amounts of revenues and expenses during the reporting period. Actual
results could differ from those estimates.
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. 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. 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.
Prior to 1995, the Company evaluated the carrying value of its oil and gas
properties based on undiscounted future net revenues on a company wide
basis. During 1995, the Company adopted 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 oil
and gas properties on a property-by-property basis. If an impairment is
indicated based on undiscounted expected future cash flows, then an
impairment is recognized to the extent that net capitalized costs exceed
discounted future cash flows. During 1997, 1996 and 1995, the Company
provided impairments of $3,289,000, $12,112,000 and $4,893,000,
respectively. Management's estimate of future cash flows is based on their
estimate of reserves and prices. 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.
F-6
THE WISER OIL COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
December 31, 1997, 1996 and 1995
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. Depreciation of transportation, office and other
properties is computed generally using the straight-line method over the
estimated useful lives of these assets.
e. Cash and Cash Equivalents - Cash equivalents generally consist of
short-term investments maturing in three months or less from the date of
acquisition. These investments of $15,083,000 in 1997 and $3,801,000 in
1996 are recorded at cost plus accrued interest, which approximates market.
f. Inventories - Oil and gas product inventories are recorded at the
average cost of production. Materials and supplies are recorded at the
lower of average cost or market.
g. Accrued Liabilities - Accrued liabilities include accrued vacation and
payroll of $334,000 in 1997 and $576,000 in 1996.
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, 1997 and 1996.
j. Hedging Arrangements - During 1997 and 1996, the Company entered into
numerous oil price collar agreements to hedge against price fluctuations
during those years. There were no hedging agreements in place after
December 31, 1997. Gains or losses from hedging transactions are recognized
as oil and gas sales in the accompanying Consolidated Statements of Income
and Retained Earnings as the underlying hedged production is sold. As of
December 31, 1996, the Company had no deferred net gains or net losses. The
Company incurred hedging losses of $2,372,000 and $6,923,000 in 1997 and
1996, respectively. The Company did not incur any material hedging gains or
losses in 1995.
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 $915,000 for 1997 and $853,000 for 1996 classified in Stockholders'
Equity.
2. 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. The market value of these securities at December 31,
1996 was $7,176,000 and all of these securities were liquidated during
1997.
The Company recognized a pretax gain of $7,495,000, $12,977,000 and
$13,101,000 for 1997, 1996 and 1995, respectively, from the sale of its
marketable securities.
F-7
THE WISER OIL COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
December 31, 1997, 1996 and 1995
3. 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 indebtedness under the
Credit Agreement and the Maljamar Credit Facility 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.
b. 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 provides the Company with up to a
$150 million line of credit through March 31, 2002. The amounts
available for borrowing are determined under formulas related to oil
and gas reserves and the Company's borrowing base at December 31, 1997
was $80 million. The indebtedness outstanding under the Credit
Agreement is secured by a guaranty from Wiser Canada. Available loan
and interest options are (i) Base Rate Advances, at the bank's prime
interest rate plus the Applicable Margin and (ii) Eurodollar Advances,
at LIBOR plus the Applicable Margin. Based on the amount of outstanding
advances, the Applicable Margin ranges between 0% and 1.25% and the
commitment fee on the unused borrowing base ranges from 0.25% to
0.375%. The average interest rate during 1997 under the Credit
Agreement was 6.24%. The Credit Agreement requires the Company to,
among other things, maintain certain financial ratios and imposes
certain restrictions on sales of assets, payment of dividends and
incurrence of indebtedness.
c. On November 29, 1995, the Company entered into a credit agreement with
NationsBank of Texas, NA as agent (the "Maljamar Credit Facility").
The Maljamar Credit Facility provided the Company with up to a $50
million nonrecourse facility to develop the expanded Maljamar project
area. The average interest rate during 1997 under the Maljamar Credit
Facility was 7.49%. The Maljamar Credit Facility was repaid and
canceled in May 1997.
F-8
THE WISER OIL COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
December 31, 1997, 1996 and 1995
The Company paid $8,120,000 in interest during 1997, $4,971,000 during 1996, and
$5,618,000 during 1995.
Long term debt consists of the following (000's):
December 31,
-----------
1997 1996
--------- ---------
2007 Notes - 9.5% interest rate at December 31, 1997......... $ 124,304 $ --
Credit Agreement - 6.31% interest rate at December 31, 1996.. -- 58,000
Maljamar Credit Facility - 7.63% interest rate at
December 31, 1996......................................... -- 20,654
----------------------
124,304 78,654
Less current maturities...................................... -- --
----------------------
$ 124,304 $ 78,654
======================
The annual requirements for reduction of principal of long term debt
outstanding as of December 31, 1997 are estimated as follows (000's):
1998......................................................... $ --
1999......................................................... --
2000......................................................... --
2001......................................................... --
Thereafter................................................... 124,304
----------
$ 124,304
==========
4. 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 paid income taxes
of $566,000 in 1997, $900,000 in 1996 and $1,967,000 in 1995.
Income tax expense for the three years ended December 31, 1997 were as
follows (000's):
1997 1996 1995
-------- -------- --------
Current:
Federal............................................ $ 375 $ 1,911 $ 1,607
State.............................................. 200 105 150
------- --------- --------
575 2,016 1,757
------- -------- -------
Deferred:
Federal............................................ (311) 1,919 1,934
State.............................................. -- 137 97
--------- --------- ---------
(311) 2,056 2,031
------ -------- -------
Total income tax expense............................. $ 264 $ 4,072 $3,788
====== ======= ======
F-9
THE WISER OIL COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
December 31, 1997, 1996 and 1995
A reconciliation of the statutory federal income tax rate to the Company's
effective tax rate follows:
1997 1996 1995
-------- -------- ---------
Statutory federal income tax rate.................... 34.0% 34.0% 34.0%
Statutory depletion in excess of cost basis.......... (5.4) (2.0) (1.7)
Non-deductible Canadian operating loss............... -- 22.6 55.4
State taxes, net of federal income taxes............. 5.8 1.5 1.6
Dividends received credit............................ (1.3) (1.2) (4.4)
Non-conventional fuels credit........................ (7.3) (14.6) (22.4)
Other................................................ (18.4) (1.5) 0.8
-------- -------- --------
Effective tax rate................................... 7.4% 38.8% 63.3%
======== ======== ========
The deferred tax liabilities and assets at December 31, 1997 and 1996 were as
follows (000's):
1997 1996
--------- ---------
Deferred tax liabilities (assets):
Intangible drilling and development cost........... $ 14,966 $ 12,998
Marketable securities valuation adjustment......... -- 2,229
Deferred pensions and compensation................. (468) (579)
Alternative minimum tax credit carryforwards....... (3,040) (2,318)
Property impairment reserve........................ (1,118) (1,767)
Wiser Canada excess property basis................. (3,866) (4,051)
Valuation allowance................................ 3,866 4,600
Other.............................................. (62) (137)
----------- ----------
$ 10,278 $ 10,975
=========== ==========
The Company will only realize the benefits of alternative minimum tax
credit carryforwards by generating future regular tax liability in excess
of alternative minimum tax liability. The Company believes it is more
likely than not that the alternative minimum tax credits will be fully
realized. As of December 31, 1997, Wiser had Canadian net deferred tax
assets of $3,866,000 and a valuation allowance has been provided against
the Canadian net deferred tax assets at December 31, 1997. Beginning in
1997, Wiser Canada's operating results are included in the Company's
consolidated federal income tax return.
F-10
THE WISER OIL COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
December 31, 1997, 1996 and 1995
5. 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):
U.S. Canada Total
---------- --------- ----------
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
December 31, 1996:
Capitalized Costs:
Proved properties................................. $ 226,411 $ 62,937 $ 289,348
Unproved properties............................... 9,659 7,709 17,368
---------- ---------- ----------
Total .......................................... 236,070 70,646 306,716
Accumulated DD&A................................ (100,016) (29,094) (129,110)
---------- --------- ----------
Net capitalized cost.............................. $ 136,054 $ 41,552 $ 177,606
========= ========= ==========
Costs Incurred during 1996:
Property acquisition.............................. $ 1,782 $ 1,054 $ 2,836
Exploration....................................... 875 1,888 2,763
Development....................................... 33,994 6,230 40,224
Gas plants........................................ 408 -- 408
December 31, 1995:
Capitalized Costs:
Proved properties................................. $ 191,567 $ 56,427 $ 247,994
Unproved properties............................... 10,110 7,588 17,698
----------- ---------- ----------
Total .......................................... 201,677 64,015 265,692
Accumulated DD&A................................ (81,561) (16,766) (98,327)
---------- --------- ----------
Net capitalized cost.............................. $ 120,116 $ 47,249 $ 167,365
========= ========= ==========
Costs Incurred during 1995:
Property acquisition.............................. $ 3,027 $ 3,210 $ 6,237
Exploration....................................... 2,753 2,270 5,023
Development....................................... 12,477 4,123 16,600
Gas plants........................................ 3,192 -- 3,192
F-11
THE WISER OIL COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
December 31, 1997, 1996 and 1995
6. 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.
The net periodic pension costs were determined as follows (000's):
1997 1996 1995
-------- -------- --------
Current service cost................................. $ 345 $ 381 $ 368
Interest cost on projected benefit obligation........ 682 824 802
Actual return on assets.............................. (930) 1,890 (1,575)
Net amortization and deferral........................ 384 (2,652) 932
------- -------- --------
Net periodic pension cost............................ $ 481 $ 443 $ 527
======= ======== ========
The principal assumptions for 1997, 1996 and 1995 utilized in computing
pension expense include an 8.0% discount rate, an 8.5% rate of return on
plan assets, and a 5.0% rate of increase in compensation levels.
amendment to the pension plan, effective January 1, 1993, reduced the
normal retirement age from 65 years to 62 years.
The following table presents the actuarial valuation of the plan's funded
status, as of December 31 (000's):
1997 1996 1995
------- -------- -------
Actuarial present value of pension benefits obligations:
Vested............................................. $ 8,212 $ 8,155 $ 9,817
Nonvested.......................................... 289 415 354
------- -------- -------
Accumulated........................................ 8,501 8,570 10,171
Projected salary increases......................... 768 751 705
------- -------- -------
Projected benefits obligations...................... 9,269 9,321 10,876
Plan assets at fair value.......................... 8,547 8,010 10,247
------- -------- -------
Plan assets less than projected benefits obligations $ 722 $ 1,311 $ 629
======= ======== =======
Items not yet recognized:
Unrecognized net gain.............................. $ 1,032 $ 473 $ 1,169
Unamortized transition amount...................... 87 121 208
Unamortized prior service cost..................... (812) (957) (1,106)
------- -------- -------
Net pension liability.............................. $ 1,029 $ 948 $ 900
======= ======== ========
F-12
THE WISER OIL COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
December 31, 1997, 1996 and 1995
7. 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 $142,000, $126,000 and
$122,000, in 1997, 1996 and 1995, respectively.
8. BUSINESS SEGMENT INFORMATION
The Company operates in one industry segment, the exploration for and
production of reserves of oil and gas, with sales made to domestic and
Canadian energy customers.
The following table summarizes the oil and gas activity of the Company by
geographic area for the years ended December 31, 1997, 1996 and 1995.
U.S. Canada Total
-------- -------- ---------
1997:
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
========= ========== =========
Identifiable assets (end of year).................... $ 202,474 $ 52,082 $ 254,556
========= ========== =========
F-13
THE WISER OIL COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
December 31, 1997, 1996 and 1995
U.S. Canada Total
--------- ---------- ----------
1996:
Total revenues....................................... $ 69,595 $ 17,094 $ 86,689
Costs and expenses:
Production and operating........................... 20,288 3,682 22,970
Purchased natural gas.............................. 1,462 -- 1,462
DD&A............................................... 11,783 7,870 19,653
Property impairments............................... 7,276 4,836 12,112
Exploration........................................ 1,837 2,339 4,176
Other operating.................................... 9,475 5,341 14,816
--------- ---------- ---------
Total costs and expenses........................ 52,121 24,068 76,189
--------- ---------- ---------
Earnings before income taxes......................... 17,474 (6,974) 10,500
Income tax expense................................... 4,072 -- 4,072
--------- ---------- ---------
Net income........................................... $ 13,402 $ (6,974) $ 6,428
========= ========== =========
Identifiable assets (end of year).................... $ 161,687 $ 46,930 $ 208,617
========= ========== =========
1995:
Total revenues....................................... $ 57,839 $ 13,842 $ 71,681
Costs and expenses:
Production and operating........................... 17,555 3,135 20,690
Purchased natural gas.............................. 727 -- 727
DD&A............................................... 11,418 8,360 19,778
Property impairments............................... -- 4,893 4,893
Exploration........................................ 4,173 1,628 5,801
Other operating.................................... 8,250 5,561 13,811
Total costs and expenses........................ 42,123 23,577 65,700
--------- ---------- ---------
Earnings before income taxes......................... 15,716 (9,735) 5,981
Income tax expense................................... 3,788 -- 3,788
--------- ---------- ---------
Net income........................................... $ 11,928 $ (9,735) $ 2,193
========= ========== =========
Identifiable assets (end of year).................... $ 152,710 $ 50,034 $ 202,744
========= ========== =========
Annually, four or five of the Company's purchasers of oil and gas
individually account for 10% to 37% of oil and gas sales. In Canada, one
purchaser accounts for approximately 75% of Wiser Canada's oil and gas
sales. However, due to the nature of the oil and gas industry, the Company
is not dependent upon any of these purchasers. The loss of any major
customer would not have a material adverse impact on the Company's
business.
9. 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
F-14
THE WISER OIL COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
December 31, 1997, 1996 and 1995
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.
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, 1997, 1996 and 1995 and changes during the years then ended follows:
1997 1996 1995
------------------- ------------------- -------------------
Exercise Exercise Exercise
Shares Price(1) Shares Price(1) Shares Price(1)
--------- -------- -------- -------- -------- --------
Outstanding at beginning of year....... 879,500 $ 15.02 254,500 $ 16.88 253,500 $ 17.20
Granted................................ 164,500 18.87 647,250 14.35 16,000 13.81
Exercised............................. . (15,025) 15.68 -- -- -- --
Expired and cancelled.................. (6,500) 15.76 (22,250) 16.88 (15,000) 17.36
--------- -------- -------- -------- -------- --------
Outstanding at end of year............. 1,022,475 $ 15.62 879,500 $ 15.02 254,500 $ 16.88
========= ======= ======= ======= ======= =======
Exercisable at end of year............. 773,975 $ 15.23 145,650 $ 16.47 56,725 $ 16.59
========= ======= ======= ======= ======= =======
Fair value of options granted(1)....... $ 6.07 $ 4.30 $ 4.08
========= ======== ========
1 Weighted average per option granted.
662,875 of the 1,022,475 options outstanding at December 31, 1997 have
exercise prices between $11 and $15, with a weighted average exercise price
of $14.37 and a weighted average remaining contractual life of 8.7 years.
586,250 of these options are currently exercisable with a weighted average
exercise price of $14.71. The remaining 359,600 options have exercise
prices between $15 and $20, with a weighted average exercise price of
$17.94 and a weighted average contractual life of 7.3 years. 187,725 of
these options are currently exercisable with a weighted average exercise
price of $16.85.
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:
1997 1996 1995
---- ---- ----
Risk free interest rate............................ 6.29% 6.36% 6.01%
Expected dividend yields........................... .64% .84% .87%
Expected lives, in years........................... 5.06 4.85 5.00
Expected volatility................................ 23.66% 22.22% 22.05%
F-15
THE WISER OIL COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
December 31, 1997, 1996 and 1995
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:
1997 1996 1995
---- ---- ----
Net income - as reported (in thousands)............ $ 3,319 $ 6,428 $ 2,193
Net income - pro forma (in thousands).............. 2,256 5,576 2,179
Earnings per share - as reported................... $ .37 $ .72 $ .25
Earnings per share - pro forma..................... .25 .62 .24
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. The holders of the SARs vest at 25% per year and the
SARs expire at the earlier of 5 years or termination of employment. At
December 31, 1997, 85,000 SARs were outstanding with an exercise price of
$14.63 per share.
10. 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.
11. 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, 1997, 1996 and 1995 (000's):
1997 1996 1995
---- ---- ----
Basic EPS shares................................ 8,949 8,939 8,939
===== ===== =====
Diluted EPS shares.............................. 8,982 8,954 8,939
===== ===== =====
F-16
THE WISER OIL COMPANY
SUPPLEMENTAL FINANCIAL INFORMATION
For the years ended December 31, 1997, 1996 and 1995 (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.
12. 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.
F-17
THE WISER OIL COMPANY
SUPPLEMENTAL FINANCIAL INFORMATION
For the years ended December 31, 1997, 1996 and 1995 (Unaudited)
Following is a reconciliation of the Company's estimated net quantities of
proved oil and gas reserves, as estimated by independent petroleum consultants.
OIL (MBBLS) GAS (MMCF)
------------------------------ --------------------------------
U.S. Canada Total U.S. Canada Total
------- ------ -------- -------- -------- --------
Balance December 31, 1994................. 20,013 3,417 23,430 86,548 21,372 107,920
Revisions of previous estimates......... 4,322 563 4,885 4,912 (1,140) 3,772
Properties sold and abandoned........... (187) -- (187) (333) -- (333)
Reserves purchased in place............. 5,825 307 6,132 695 1,132 1,827
Extensions, discoveries and other additions 124 157 281 2,046 6,354 8,400
Production.............................. (1,657) (676) (2,333) (8,918) (2,753) (11,671)
------- ------ -------- -------- -------- --------
Balance December 31, 1995................. 28,440 3,768 32,208 84,950 24,965 109,915
Revisions of previous estimates......... (301) (25) (326) 2,738 (535) 2,203
Properties sold and abandoned........... (78) -- (78) (72) -- (72)
Reserves purchased in place............. 12 -- 12 17 505 522
Extensions, discoveries and other additions 2,040 533 2,573 10,787 1,705 12,492
Production.............................. (2,033) (744) (2,777) (8,874) (2,809) (11,683)
------- ------ -------- -------- -------- --------
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, discoveries and other additions 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
======= ====== ======== ======== ======== ========
Proved Developed Reserves at December 31, (1):
1994.................................... 15,950 3,209 19,159 84,715 13,655 98,370
1995.................................... 17,939 3,617 21,556 77,915 24,111 102,026
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
(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 397 MBBL and
2,744 MMCF for 1995, 186 MBBL and 1,258 MMCF for 1996 and 364 MBBL and
1,914 MMCF for 1997.
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 and future production and development cost are based on current
year end sales prices for oil and gas. Estimated future production of
proved reserves and estimated future production and development costs of
proved reserves are based on current costs and economic conditions.
F-18
THE WISER OIL COMPANY
SUPPLEMENTAL FINANCIAL INFORMATION
For the years ended December 31, 1997, 1996 and 1995 (Unaudited)
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):
U.S. Canada Total
-------- ---------- -----------
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
========== ========= ==========
December 31, 1996:
Future cash flows........................................ $ 1,029,971 $ 116,203 $ 1,146,174
Future production and development costs.................. (415,276) (25,175) (440,451)
Future income tax expense................................ (172,024) -- (172,024)
----------- --------- -----------
Future net cash flows.................................... 442,671 91,028 533,699
10% Annual discount for estimated timing of cash flows... (187,332) (29,187) (216,519)
----------- --------- -----------
Standardized measure of discounted cash flows............ $ 255,339 $ 61,841 $ 317,180
=========== ========= ===========
December 31, 1995:
Future cash flows........................................ $ 679,754 $ 90,978 $ 770,732
Future production and development costs.................. (343,867) (25,828) (369,695)
Future income tax expense................................ (74,433) -- (74,433)
---------- --------- ----------
Future net cash flows.................................... 261,454 65,150 326,604
10% Annual discount for estimated timing of cash flows... (111,193) (20,809) (132,002)
---------- --------- ----------
Standardized measure of discounted cash flows............ $ 150,261 $ 44,341 $ 194,602
========== ========= ==========
F-19
THE WISER OIL COMPANY
SUPPLEMENTAL FINANCIAL INFORMATION
For the years ended December 31, 1997, 1996 and 1995 (Unaudited)
The following are the sources of changes in the standardized measure of
discounted net cash flows (000's):
1997 1996 1995
-------- -------- ---------
Standardized measure, beginning of year................... $ 317,180 $ 194,602 $ 142,032
Sales, net of production costs............................ (47,959) (46,580) (32,907)
Net change in price and production costs.................. (204,859) 142,806 19,536
Reserves purchased in place............................... 30,570 581 26,087
Extensions, discoveries and improved recoveries........... 11,751 42,582 9,297
Change in future development costs........................ 16,339 27,080 12,652
Revisions of previous quantity estimates and disposals.... (6,992) 314 26,525
Sales of reserves in place................................ (10,756) (987) (798)
Accretion of discount..................................... 41,431 23,542 16,081
Changes in timing and other............................... (33,752) (10,440) (1,863)
Net change in income taxes................................ 61,536 (56,320) (22,040)
--------- --------- ---------
Standardized measure, end of year......................... $ 174,489 $ 317,180 $ 194,602
========= ========= =========
12 QUARTERLY FINANCIAL DATA
The supplementary financial data in the table below for each quarterly
period within the years ended December 31, 1997 and 1996 are derived from
the unaudited consolidated financial statements of the Company.
Net Earnings
Income (Loss)
Revenues (Loss) Per Share
-------- ------- ---------
(000's) (000's)
1997:
First quarter........................................... $ 25,575 $ 6,141 $ .69
Second quarter.......................................... 17,826 (1,944) (.22)
Third quarter........................................... 17,027 (1,878) (.21)
Fourth quarter.......................................... 27,387 1,000 .11
1996:
First quarter........................................... $ 18,567 $ 1,511 $ .17
Second quarter.......................................... 21,363 (5,368) (.60)
Third quarter........................................... 19,468 2,444 .27
Fourth quarter.......................................... 27,291 7,841 .88
13. SUMMARY OF GUARANTIES OF 91/2% 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
F-20
of the Company (the "Subsidiary Guarantors"). At the time of the initial
issuance of the notes, Wiser Oil Delaware, Inc., The Wiser Marketing Company,
Wiser Delaware LLC, T.W.O.C., Inc. and The Wiser Oil Company of Canada 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.
Sections 13 and 15(d) of the Securities Exchange Act of 1934 require
presentation of the following unaudited summarized financial information of the
Subsidiary Guarantors. The Company has not presented separate financial
statements and other disclosures concerning each Subsidiary Guarantor because
such information is not material to investors. There are no significant
contractual restrictions on distributions from each of the Subsidiary Guarantors
to the Company.
SUBSIDIARY GUARANTORS
----------------------------------------------------------
THE WISER
WISER T.W.O.C. MARKETING COMBINED
CANADA(1) INC. COMPANY TOTAL
----------- ---------- ---------- ---------
REVENUES:
For the Year Ended December 31, 1997............ $ 16,109 $ 7,687 $ 2,304 $ 26,100
For the Year Ended December 31, 1996............ 17,094 16,304 2,237 35,635
For the Year Ended December 31, 1995............ 13,842 15,884 1,217 30,943
EARNINGS (LOSS) BEFORE INCOME TAXES:
For the Year Ended December 31, 1997............ $ (4,262) $ 7,671 $ 231 $ 3,640
For the Year Ended December 31, 1996............ (6,974) 16,287 338 9,651
For the Year Ended December 31, 1995............ (9,735) 15,867 131 6,263
NET INCOME (LOSS):
For the Year Ended December 31, 1997............ $ (3,947) $ 7,103 $ 214 $ 3,370
For the Year Ended December 31, 1996............ (6,974) 12,492 259 5,777
For the Year Ended December 31, 1995............ (9,735) 12,043 99 2,406
CURRENT ASSETS:
December 31, 1997............................... $ 4,808 $ 44 $ 165 $ 5,017
December 31, 1996............................... 4,958 53 170 5,181
December 31, 1995............................... 3,039 27 94 3,160
TOTAL ASSETS:
December 31, 1997............................... $ 52,083 $ 44 $ 492 $ 52,619
December 31, 1996............................... 39,132 7,229 718 47,079
December 31, 1995............................... 43,763 19,619 332 63,714
CURRENT LIABILITIES:
December 31, 1997............................... $ 6,646 $ -- $ 250 $ 6,896
December 31, 1996............................... 4,931 -- 508 5,439
December 31, 1995............................... 2,779 -- 200 2,979
NONCURRENT LIABILITIES:
December 31, 1997............................... $ 9,474 $ -- $ -- $ 9,474
December 31, 1996............................... 52,439 2,227 -- 54,666
December 31, 1995............................... 52,380 6,007 -- 58,387
STOCKHOLDERS' EQUITY (DEFICIT):
December 31, 1997............................... $ 35,963 $ 44 $ 242 $ 36,249
December 31, 1996............................... (18,238) 5,002 210 (13,026)
December 31, 1995............................... (11,396) 13,612 132 2,348
(1) Includes the accounts of Wiser Oil Delaware, Inc., Wiser Delaware LLC and
The Wiser Oil Company of Canada.
F-21
INDEX TO 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) Amendment No. 1 to the 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
the Company's report on Form 8 -K/A filed on September 29,1995.
(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 dated 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.
(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
4.5 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.
(4.12) Credit Agreement dated November 29, 1995 among The Wiser Oil Company
and Maljamar Development Partnership, L.P. as Borrowers, and
NationsBank of Texas, N.A., as Agent, and Certain Financial
Institutions Listed on the Signature Pages thereto, as Banks.
(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.
(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 as amended by Form 8-K/A filed on August 17, 1994.
(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.
(10.5)+ 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 May 20, 1997.
(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.
(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 May 20, 1997.
(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 May 20, 1997.
(10.10)+ Employment Agreement dated September 30, 1997 between the Company and
Kent E. Johnson, incorporated by reference to Exhibit 10.10 to the
Company's Annual Report on Form 10-K (Commission File No. 0-5426),
filed on March 26, 1997.
(10.10a)+* Amendment to Employment Agreement dated September 30, 1997 between
the Company and Kent E. Johnson dated May 20, 1997.
(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 (Commission File No. 0-5426),
filed on March 26, 1997.
(10.12)* The Wiser Oil Company Savings Restoration Plan dated February 24,
1998.
(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 Lausten Jung Associates Ltd., Independent
Petroleum Engineers.
(27)* Financial Data Schedule.
______________
+ Represent management compensatory plans or agreements.
* Filed herewith.