<PAGE>
 
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                      SECURITIES AND EXCHANGE COMMISSION
                            WASHINGTON, D.C. 20549
 
                               ----------------
 
                                   FORM 10-K
                                 ANNUAL REPORT
                      PURSUANT TO SECTION 13 OR 15(D) OF
                      THE SECURITIES EXCHANGE ACT OF 1934
 
   FOR THE FISCAL YEAR ENDED DECEMBER 31, 1996 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
 
                              TITLE OF EACH CLASS
 
                   COMMON STOCK--PAR VALUE, $3.00 PER SHARE
 
                        PREFERRED STOCK PURCHASE RIGHTS
 
                     NAME OF EXCHANGE ON WHICH REGISTERED
 
                            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 5-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 28, 1997, registrant had outstanding 8,948,840 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 28, 1997 was approximately
$168 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 19, 1997 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 Commission within 120 days of the close
of the registrant's fiscal year.
 
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<PAGE>
 
                               TABLE OF CONTENTS
 
                                  DESCRIPTION
 
<TABLE>
<CAPTION>
ITEM                                                                      PAGE
----                                                                      ----
<S>                                                                       <C>
                                 PART I
 1. BUSINESS.............................................................   3
 2. PROPERTIES...........................................................  26
 3. LEGAL PROCEEDINGS....................................................  27
 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS..................  27
                                 PART II
 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED STOCKHOLDER
    MATTERS..............................................................  27
 6. SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA...................  28
 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
    RESULTS OF OPERATIONS................................................  31
 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA..........................  38
 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
    FINANCIAL DISCLOSURES................................................  38
                                PART III
10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT...................  38
11. EXECUTIVE COMPENSATION...............................................  38
12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.......  38
13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.......................  38
                                 PART IV
14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K......  39
</TABLE>
 
                                       2
<PAGE>
 
                             THE WISER OIL COMPANY
 
                                    PART I
 
ITEM 1. BUSINESS
 
GENERAL
 
  Founded in 1905, The Wiser Oil Company 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 50.5 MMBOE (approximately 63% of which were oil and NGLs) at December 31,
1996 from 24.3 MMBOE at December 31, 1991, and its annual net production has
grown to 4.7 MMBOE in 1996 from 2.3 MMBOE in 1991. The Company's primary
operations, representing approximately 55% of its proved reserves at December
31, 1996, 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 CO\\2\\ 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 1996, the Company completed 113 producing wells on its Maljamar
waterflood project in Southeast New Mexico. As a result the Company's average
daily net oil production from the three units in this project increased to
2,800 Bbls in December 1996 from 580 Bbls 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 CO\\2\\ gas
injection to increase average daily net production to 930 Bbls of oil, 440
Bbls of NGLs and 540 Mcf of natural gas in December 1996 from 650 Bbls of oil
and no NGLs or natural gas 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 1996, the Company
completed 22 net wells on these properties. As a result, the Company's average
daily net Canadian production increased to 3,200 BOE in December 1996 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.
 
                                       3
<PAGE>
 
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, 1996.
 
<TABLE>
<CAPTION>
                                            PROVED RESERVES
                                   ----------------------------------    1996
                           TOTAL                     TOTAL   PERCENT   AVERAGE
                           GROSS     OIL    NATURAL  PROVED  OF TOTAL    NET
                          OIL AND  AND NGLS   GAS   RESERVES  PROVED  PRODUCTION
                         GAS WELLS (MBBLS)  (MMCF)   (MBOE)  RESERVES (BOE/DAY)
                         --------- -------- ------- -------- -------- ----------
<S>                      <C>       <C>      <C>     <C>      <C>      <C>
Permian Basin
  Maljamar..............     223    14,706    6,248  15,748     31%      2,074
  Wellman...............      14     7,067    2,494   7,482     15%      1,594
  Dimmitt/Slash Ranch...      59     2,548   12,954   4,707      9%        848
                           -----    ------  -------  ------    ---      ------
    Total Permian
     Basin..............     296    24,321   21,696  27,937     55%      4,516
Appalachian Basin.......     443       989   31,633   6,260     12%      1,343
San Juan Basin..........   2,200        48   20,831   3,520      7%      1,104
Other...................     542     2,722   15,386   5,287     11%      2,661
                           -----    ------  -------  ------    ---      ------
    Total United
     States.............   3,481    28,080   89,546  43,004     85%      9,624
Canada..................     287     3,532   23,831   7,504     15%      3,318
                           -----    ------  -------  ------    ---      ------
    Total Company.......   3,768    31,612  113,377  50,508    100%     12,942
                           =====    ======  =======  ======    ===      ======
</TABLE>
 
 Permian Basin
 
  Maljamar. The Company's Maljamar properties are situated in Southeast New
Mexico. At December 31, 1996, the Maljamar properties contained 15.7 MMBOE of
proved reserves, which represented 31% of the Company's total proved reserves
and 30% of the Company's Present Value of total proved reserves.
 
  The Maljamar properties consist 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 have been combined into a single large scale waterflood
project encompassing approximately 11,800 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, 1996, the Company made capital expenditures of $50.1 million and
completed 113 producing wells at the project. At December 31, 1996, the
project included 223 producing wells and 102 water injection wells, all of
which were operated by the Company. During 1996, Wiser placed a total of 68
wells on production, and had 33 additional wells in various stages of drilling
or completion at year end. At December 31, 1996, a total of 28 wells remain to
be drilled at the project, all of which are expected to be drilled in the
first half of 1997 as part of a total capital expenditure thereon of $17.4
million.
 
  The Company's average daily net production from the Maljamar properties
increased to 2,800 Bbls of oil and 1,760 Mcf of natural gas in December 1996
from 580 Bbls of oil and 220 Mcf of natural gas in January 1993 (on a pro
forma combined basis, assuming the Company had acquired all three units at
January 1, 1993). The Company's net production from the Maljamar properties
averaged 1,900 Bbls of oil and 1,044 Mcf of natural gas per day in 1996. The
Company's cumulative net production from the Maljamar properties since
acquired by the Company has been 1,360 MBbls of oil and 670 MMcf of natural
gas through December 31, 1996.
 
                                       4
<PAGE>
 
  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, 1996, the Company's
Wellman property contained 7.5 MMBOE of proved reserves, which represented 15%
of the Company's total proved reserves and 14% 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 CO\\2\\ into the reservoir. Water injection at the unit began in 1979,
and CO\\2\\ 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 CO\\2\\. The NGLs and
residual natural gas are sold to pipeline companies, and the CO\\2\\ is
reinjected into the unit's reservoir. At December 31, 1996, the unit included
14 productive wells, three water injection wells and three CO\\2\\ injection
wells, all of which were operated by the Company.
 
  The Company's net production from the Wellman Unit averaged 1,051 Bbls of
oil, 481 Bbls of NGLs and 374 Mcf of natural gas per day in 1996. The
Company's average daily net production from the unit was 930 Bbls of oil, 440
Bbls of NGLs and 540 Mcf of natural gas in December 1996, which was 8% lower
on an equivalent unit basis than the average daily net production from the
unit in 1996. This reduction was due primarily to weather-related delays in
drilling operations and plant processing and shortages of drilling rigs. The
Company's cumulative net production from the unit since acquired by the
Company has been 1,181 MBbls of oil, 278 MBbls of NGLs and 137 MMcf of natural
gas through December 31, 1996.
 
  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. Following completion of
this project, average daily net production from the unit increased to 1,180
Bbls of oil and 527 Bbls of NGLs during the six months ended December 31, 1995
from 982 Bbls of oil and no NGLs for the six months ended June 30, 1995. For
the year ended December 31, 1996, the gas plant processed an average of 31
MMcf of gross natural gas and CO\\2\\ per day and recovered an average of 882
Bbls of NGLs and 685 Mcf of residual natural gas per day. The plant currently
operates at 95% 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, 1996, the Dimmitt/Slash Ranch properties contained 4.7 MMBOE of proved
reserves, which represented 9% of the Company's total proved reserves and 11%
of the Company's Present Value of total proved reserves.
 
  The Company owns approximately 5,400 gross (4,100 net) leasehold acres in
the Dimmitt Field, and has working interests in this acreage ranging from 50%
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, 1996, the field included 56 productive wells. The Company
completed three wells in the Cherry Canyon formation and performed
recompletions on seven producing wells in the Bell Canyon formation in 1996.
The Company plans to drill three additional development wells in the Cherry
Canyon formation and to recomplete 13 additional Bell Canyon wells during the
next two years for an estimated total capital expenditure of approximately
$2.0 million. The Company's net production from the Dimmitt Field averaged 374
Bbls of oil and 1,172 Mcf of natural gas per day in 1996.
 
  The Slash Ranch Field is a natural gas field that underlies the Dimmitt
Field. The Company owns approximately 2,600 gross (1,800 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, 1996, the field included three producing wells, all of
which were operated by the Company. The
 
                                       5
<PAGE>
 
Company's working interests in these wells range from 34% to 100%. The
Company's net production from the Slash Ranch Field averaged 1,672 Mcf of
natural gas per day in 1996. 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 374 Bbls of oil and 2,844 Mcf of natural gas per day in 1996. The
Company's cumulative net production from the properties since acquired by the
Company has been 300 MBbls of oil and 3.4 Bcf of natural gas through December
31, 1996.
 
 Appalachian Basin
 
  The Company's Appalachian Basin properties are situated in Kentucky,
Tennessee and West Virginia. At December 31, 1996, these properties contained
6.3 MMBOE of proved reserves, which represented 12% of the Company's total
proved reserves and 12% 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, 1996,
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 four
development wells in Kentucky and Tennessee in 1996, three development wells
in early 1997 and plans to drill an additional four development wells later
this year. The Company expects to spend approximately $500,000 on development
drilling activities in Kentucky and Tennessee in 1997. The Company's net
production from its Kentucky and Tennessee properties averaged 5,346 Mcf of
natural gas per day in 1996.
 
  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, 1996, the Company owned 75 gross (48 net) productive gas wells in this
field, all of which were operated by another company. During 1996, the Company
participated in the drilling of 12 gross (nine net) development wells in the
Blue Creek Field. The Company has identified 35 exploratory drilling locations
in the field and plans to drill 20 of these locations in 1997 for an estimated
total capital expenditure of $2.5 million. The Company's net production from
its West Virginia properties averaged 913 Mcf of natural gas, 107 Bbls of oil
and 193 Bbls of NGLs per day in 1996.
 
  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, 16 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, 1996, the
pipelines gathered an average of 10.8 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, 1996, the plants processed an average of
10.8 MMcf of natural gas per day and recovered an average of 193 Bbls of NGLs
per day. See "--Marketing of Production."
 
  The Company's net production from its Appalachian Basin properties averaged
6,259 Mcf of natural gas, 107 Bbls of oil and 193 Bbls of NGLs per day in
1996.
 
                                       6
<PAGE>
 
 San Juan Basin
 
  The Company's San Juan Basin properties are located in Rio Arriba County in
northwestern New Mexico. At December 31, 1996, the San Juan Basin properties
contained 3.5 MMBOE of proved reserves, which represented 7% of the Company's
total proved reserves and 7% 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, 1996,
the Company owned working interests in 2,200 producing gas wells in the San
Juan Basin, which working interests ranged from 0.21% to 4.2% and averaged
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 6,539 Mcf of natural
gas and 14 Bbls of oil per day in 1996. During the year ended December 31,
1996, approximately 60% 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." In 1996
production from the San Juan Basin properties was diminished as a result of a
five-month curtailment due to a pipeline rupture. 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, the Gulf Coast onshore region and
Michigan. 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." The Company has entered into a contract to sell its Michigan
properties, and expects the sale to occur in April 1997. The Company's net
production from its Michigan properties averaged 386 Bbls of oil and 555 Mcf
of natural gas per day in 1996.
 
 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, 1996, the Company's Canadian properties contained 7.5 MMBOE of
proved reserves, which represented 15% of the Company's total proved reserves
and 15% 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, 1996:
 
<TABLE>
<CAPTION>
                                          PROVED RESERVES
                                 ---------------------------------
                                          PERCENT OF
                                  TOTAL     TOTAL     PERCENT OF   1996 AVERAGE
                     TOTAL GROSS  PROVED   CANADIAN  TOTAL COMPANY     NET
                       OIL AND   RESERVES   PROVED      PROVED      PRODUCTION
                      GAS WELLS   (MBOE)   RESERVES    RESERVES     (BOE/DAY)
                     ----------- -------- ---------- ------------- ------------
<S>                  <C>         <C>      <C>        <C>           <C>
Evi.................      15      1,224       16%         2.4%          825
Provost.............      46        616        8%         1.2%          742
Grande Prairie......      16        884       12%         1.8%          239
Leahurst............      16        355        5%         0.7%          356
Pine Creek..........       5        420        6%         0.8%          239
Other...............     189      4,005       53%         8.0%          917
                         ---      -----      ---         ----         -----
  Total Canada......     287      7,504      100%        14.9%        3,318
                         ===      =====      ===         ====         =====
</TABLE>
 
 
                                       7
<PAGE>
 
  Evi. The Company's Evi Field is located approximately 400 miles north of
Calgary. At December 31, 1996, the Evi Field contained 1,224 MBOE of proved
reserves, which represented 16% of the Company's total Canadian proved
reserves and 35% of the Present Value of the Company's total Canadian proved
reserves.
 
  The Company owns approximately 5,440 gross (1,870 net) leasehold acres in
the Evi Field, and has an average 34% 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
825 Bbls of oil per day in 1996. At December 31, 1996, the Company owned 15
gross (3.2 net) productive wells and two gross (0.4 net) water disposal wells
in the field, of which 12 productive wells and both water disposal wells were
operated by Wiser.
 
  Provost. The Company's Provost properties are located approximately 210
miles northeast of Calgary. At December 31, 1996, the Provost properties
contained 616 MBOE of proved reserves, which represented 8% of the Company's
total Canadian proved reserves and 11% of the Present Value of the Company's
total Canadian proved reserves.
 
  The Company owns approximately 9,280 gross (6,300 net) leasehold acres in
the Provost properties, and has an average 68% 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. Water injection in this pool began in
1990. The Company drilled 12 infill wells in the Dina 'X' Pool in 1996. This
increased the Company's average daily net production from the pool to 630 Bbls
of oil in December 1996 from 150 Bbls of oil in January 1996. The Company
plans to drill two additional infill wells in the pool in 1997.
 
  The Company's net production from the Provost properties averaged 679 Bbls
of oil and 380 Mcf of natural gas per day in 1996. At December 31, 1996, the
Company owned 46 gross (35.8 net) productive wells and two gross (two net)
water injection wells on the properties, of which 29 gross productive wells
and both water injection wells were operated by the Company. The Company has a
100% working interest in 22 of the productive wells and a 92% working interest
in one of the others.
 
  Grande Prairie. The Company's Grande Prairie properties are located
approximately 380 miles northwest of Calgary. At December 31, 1996, the Grande
Prairie properties contained 884 MBOE of proved reserves, which represented
12% of the Company's total Canadian proved reserves and 11% of the Present
Value of the Company's total Canadian proved reserves.
 
  The Company owns approximately 8,320 gross (2,260 net) leasehold acres in
the Grande Prairie properties, and has an average 27% working interest in this
acreage. The Grande Prairie properties produce from the Halfway formation at
depths of 6,200 to 6,300 feet. At December 31, 1996, the Company owned 16
gross (3.9 net) productive wells and one gross (0.23 net) gas injection well
at Grande Prairie, all of which were operated by Wiser. All but one well has
been unitized in the Grande Prairie Halfway 'A' Unit, in which the Company has
a 22.9% working interest. Gas re-injection in the unit began in 1989 to
enhance oil recovery. The Company's net production from the Grande Prairie
properties averaged 158 Bbls of oil and 487 Mcf of natural gas per day in
1996.
 
  Leahurst. The Company's Leahurst properties are located approximately 180
miles northeast of Calgary. At December 31, 1996, the Leahurst properties
contained 355 MBOE of proved reserves, which represented 5% of the Company's
total Canadian proved reserves and 8% 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, 1996, the Company owned 16 gross (2.6
net) productive wells and two gross (0.63 net) water injection wells on the
Leahurst properties. All of the wells in the properties have
 
                                       8
<PAGE>
 
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 is currently
participating in a six-well infill drilling program at the unit. Five of these
wells have proved undeveloped reserves assigned to them. The Company's net
production from the Leahurst properties averaged 334 Bbls of oil and 130 Mcf
of natural gas per day in 1996.
 
  Pine Creek. The Company's Pine Creek Field is located approximately 240
miles northwest of Calgary. At December 31, 1996, the Pine Creek Field
contained 420 MBOE of proved reserves, which represented 6% of the Company's
total Canadian proved reserves and 4% of the Present Value of the Company's
total Canadian proved reserves. The Company owns approximately 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, 1996,
the Company owned five 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 967 Mcf of natural gas and 78
Bbls of NGLs per day in 1996.
 
  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, 1996, these properties individually
represented less than 5%, and in the aggregate represented approximately 28%,
of the Company's average daily net Canadian production.
 
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 1996, Wiser
participated in three gross (two net) domestic exploration wells, compared
with 19 gross (six net) wells in 1995, spending $0.9 million in 1996 and $2.0
million in 1995 on domestic exploration. The Company has budgeted $7.9 million
for its 1997 domestic exploration program.
 
  The Company is currently focusing its domestic exploration activities in the
following geographical areas:
 
    West Texas. The Company has identified deep exploratory prospects in the
  Slash Ranch Field in Loving County where it is currently producing at
  shallower depths. The Company intends to define these prospects further
  with 3-D seismic. In Pecos County, Wiser has a 23.5% working interest in
  both the Indian Mesa and Panther Bluff prospects. The Company has completed
  3-D seismic on the Indian Mesa prospect and intends to drill an exploratory
  well on this prospect in the second quarter of 1997. The Company will be
  carried at no cost to casing point in the well and will have a 23.5%
  working interest after casing point. The Company has identified unproven
  drilling potential in the Panther Bluff prospect to be defined further with
  3-D seismic data. The Company is in the process of obtaining necessary
  permits to commence exploration of this prospect.
 
    Gulf Coast. The Company plans to develop exploration projects in the Gulf
  Coast onshore region. The Company intends to seek a mix of moderate risk,
  moderate cost prospects and some higher cost, higher potential prospects.
  Wiser is currently involved in discussions with other companies regarding
  participation in 3-D seismic projects for multiple prospects, and is
  investigating self-generation of prospects in certain other locations.
  Wiser owns approximately 2,300 gross (540 net) leasehold acres in the South
  Lakeside prospect in Cameron Parish, Louisiana, and has acquired extensive
  2-D seismic over this area. The Company considers this prospect to be a
  very high risk project with potential for substantial reserves. Spudding of
  a well on the prospect occurred in March 1997. The well is being drilled
  under a turnkey contract. The Company will pay 12.5% of the drilling costs
  of the well to casing point and will have a 23.4% working interest after
  casing point.
 
                                       9
<PAGE>
 
    Anadarko Basin.  The Company owns approximately 6,500 gross (1,300 net)
  leasehold acres and has a 20% working interest in the Mustang prospect,
  where it participated in a 35-mile 3-D seismic program targeting the Upper
  Morrow and Hunton formations. The Company has commenced drilling the
  Mustang prospect. Wiser is currently evaluating two other exploratory
  projects in Oklahoma. The Company is investigating the possibility of
  conducting 3-D seismic on these two projects to delineate exploratory
  prospects.
 
  Canada. Wiser focuses its Canadian exploration activities in specific
regions within the Western Canadian Sedimentary Basin in close proximity to
known producing horizons where the potential for significant reserves exists.
The Company's technical personnel have considerable experience in this focus
area. From the date of the Company's acquisition of its Canadian properties
through December 31, 1996, the Company's Canadian exploration activities have
resulted in the successful completion of five net wells (out of 14 net wells
drilled). The Company has budgeted $4.3 million for its 1997 Canadian
exploration program.
 
  The Company is currently focusing its Canadian exploration activities in the
following geographical areas:
 
    Northeast British Columbia. The Company owns approximately 2,760 gross
  (1,380 net) leasehold acres in the Beatton River/Elm area, and has an
  average 50% working interest in this acreage. This project targets the
  Gething formation at 4,000 feet and the Triassic Halfway formation located
  directly beneath the Gething formation. In the fourth quarter of 1996, the
  Company drilled an exploratory well on this acreage. This well has been
  cased and production tested and is currently undergoing pressure build-up
  analysis to determine the optimum rate of recovery. Based on an analysis of
  the final flow rates, the Company believes this well has significant
  reserve potential. If successful, this well will qualify under a provincial
  program encouraging exploration activity which would exempt the Company
  from paying royalties on production to the provincial government for a
  period of 36 months. Another exploratory well and a development well are
  planned for 1997 to further delineate this field. The Company is currently
  negotiating an off-setting opportunity for this prospect.
 
    Northern Alberta. The Company's Gage project is presently undergoing land
  assembly as an oil prospect targeting the deeper Triassic formation at
  approximately 4,000 feet. A number of wells drilled by others in this area
  have previously tested oil and gas, but have never produced because of a
  lack of pipelines in the area. The Company is engaged in a shallower
  competitive venture in this area to determine whether there are sufficient
  natural gas reserves to justify the construction of production facilities.
  The Company owns approximately 5,440 gross (3,560 net) leasehold acres in
  the Gage project and has working interests in the gas rights ranging from
  50% to 100%. The Company has purchased and intends to continue to purchase
  the oil rights to this project in private sales from the Province of
  Alberta. An exploratory well is planned upon completion of land assembly
  activities.
 
    The Company is also developing the Evi West project, targeting the
  Granite Wash sands located in an area near certain of the Company's
  production facilities. The Company has completed a detailed 2-D seismic
  analysis which revealed sands draped over a Precambrian structure at a
  depth of approximately 5,000 feet. The Company owns a 100% working interest
  in approximately 640 gross leasehold acres on this project.
 
    West Central Alberta. The Company owns approximately 16,000 gross (7,050
  net) leasehold acres in the Bronson project with working interests ranging
  from 50% to 100%. An exploratory well on this acreage has been drilled and
  cased for further evaluation. The Company has obtained a license to drill
  another exploratory well and is waiting for a drilling rig to commence
  drilling. Wiser is also producing gas from the shallower Cardium formation.
 
    The Company owns approximately 1,920 gross (960 net) leasehold acres in
  the Ferrier prospect, and has a 50% working interest in this acreage. Based
  on a 2-D seismic analysis of this area, the Company intends to drill an
  exploratory well through the Cretaceous and into the Mississippian
  formations at a depth of approximately 10,000 feet. The Company recently
  obtained a license to drill the test well and a drilling rig is on
  location. In addition, the Company has secured a five section farm-in of
  adjacent acreage. Plant capacity and infrastructure are currently available
  in the area.
 
                                      10
<PAGE>
 
    The Company owns approximately 640 gross (213 net) leasehold acres and
  has a 33% working interest with two equal partners in the Windfall project.
  A shallow natural gas target has been confirmed, and Wiser is currently
  interpreting 2-D seismic on a second, deeper target. An exploratory test
  well is expected to spud during the third quarter of 1997.
 
    The Company has secured a farm-in of 480 acres of land in the Provost
  area. An exploratory well targeting the Cretaceous formation at
  approximately 4,200 feet is expected to spud in the second quarter of 1997.
  The Company is waiting for a drilling rig to commence drilling on this
  location.
 
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, 1996, revenues from the sale of
production to Highland Energy Company, Koch Oil Co. Ltd. and Texaco Trading
and Transportation represented approximately 35%, 18% and 15%, 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 1996. The Company believes it would be able to locate
alternate purchasers in the event of the loss of any one or more of these
purchasers, and that any such loss would not have a material adverse effect on
the Company's financial condition or results of operations.
 
  Crude Oil. The Company sells its crude oil and condensate to various
refiners and resellers in the United States and Canada at posting-related and
spot-related prices that also depend on factors such as well location,
production volume and product quality. The Company typically sells its crude
oil and condensate production at or near the well site, although in some cases
it is gathered by the Company or others and delivered to a central point of
sale. The Company's crude oil and condensate production is transported by
truck or by pipeline and is typically committed to arrangements having a term
of one year or less. The Company has not engaged in crude oil trading
activities. Revenue from the sale of crude oil and condensate totaled $45.6
million for the year ended December 31, 1996 and represented 63% of the
Company's total oil and gas revenues for that period.
 
  From time to time, the Company enters into crude oil price hedges to reduce
its exposure to commodity price fluctuation. At December 31, 1996,
approximately 41% of the Company's total expected crude oil production through
December 1997 was hedged under such arrangements at a weighted average volume
of 3,496 Bbls of oil per day and at a weighted average hedge floor price of
$16.39 and hedge ceiling price of $19.06 per Bbl. 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
 
                                      11
<PAGE>
 
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 11,000 Mcf per day. For the year ended December
31, 1996, approximately 10% 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 1996
for NGLs sold from Company-operated plants or under processing agreements with
others was $13.36 per Bbl. At December 31, 1996, approximately 40% of the
Company's total expected NGL production from January 1 through March 31, 1997
was hedged at a weighted average swap price of $18.76 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 1996 was $18.81, compared to an
average price per Bbl of $20.86 that would have been received before the
effects of the Company's hedging activities. The average NYMEX-WTI closing
price per Bbl for 1996 was $22.01.
 
  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, as in early 1996, 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 1996 was $1.77, compared to an average price per Mcf of $1.92 that
would have been received before the effects of the Company's hedging
activities. The NYMEX-Henry Hub price per MMBtu for 1996, 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
1996, was $2.55. The average natural gas price received by the Company in 1996
was lower than such 1996 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, lower natural gas prices
generally applicable to Canadian natural gas production relative to U.S.
production and the Company's hedging activities.
 
                                      12
<PAGE>
 
OIL AND GAS RESERVES
 
  The following table sets forth the proved developed and undeveloped reserves
of the Company at December 31, 1996:
 
<TABLE>
<CAPTION>
                              OIL AND NGLS (MBBLS)          NATURAL GAS (MMCF)          TOTAL RESERVES (MBOE)
                          ---------------------------- ----------------------------- ----------------------------
                          DEVELOPED UNDEVELOPED TOTAL  DEVELOPED UNDEVELOPED  TOTAL  DEVELOPED UNDEVELOPED TOTAL
                          --------- ----------- ------ --------- ----------- ------- --------- ----------- ------
<S>                       <C>       <C>         <C>    <C>       <C>         <C>     <C>       <C>         <C>
Permian Basin
 Maljamar...............   11,914      2,792    14,706    5,266       982      6,248  12,792      2,956    15,748
 Wellman................    7,067        --      7,067    2,494       --       2,494   7,482        --      7,482
 Dimmitt/Slash Ranch....    2,191        357     2,548   12,276       678     12,954   4,237        470     4,707
                           ------      -----    ------  -------    ------    -------  ------      -----    ------
 Total Permian Basin....   21,172      3,149    24,321   20,036     1,660     21,696  24,511      3,426    27,937
Appalachian Basin.......      967         22       989   26,173     5,460     31,633   5,328        932     6,260
San Juan Basin..........       48        --         48   20,358       473     20,831   3,442         78     3,520
Other...................    2,705         17     2,722   14,085     1,301     15,386   5,053        234     5,287
                           ------      -----    ------  -------    ------    -------  ------      -----    ------
 Total United States....   24,892      3,188    28,080   80,652     8,894     89,546  38,334      4,670    43,004
Canada..................    3,225        307     3,532   22,477     1,354     23,831   6,971        533     7,504
                           ------      -----    ------  -------    ------    -------  ------      -----    ------
 Total Company..........   28,117      3,495    31,612  103,129    10,248    113,377  45,305      5,203    50,508
                           ======      =====    ======  =======    ======    =======  ======      =====    ======
</TABLE>
 
  The following table summarizes the Company's proved reserves, the estimated
future net revenues from such proved reserves and the Present Value and
Standardized Measure of Discounted Future Net Cash Flows attributable thereto
at December 31, 1996, 1995 and 1994:
 
<TABLE>
<CAPTION>
                                                         AT DECEMBER 31,
                                                  -----------------------------
                                                    1996      1995      1994
                                                  --------- --------- ---------
                                                  (DOLLARS IN THOUSANDS, EXCEPT
                                                   FOR WEIGHTED AVERAGE SALES
                                                             PRICES)
   <S>                                            <C>       <C>       <C>
   Proved reserves:
     Oil and NGLs (MBbl)........................     31,612    32,208    23,430
     Natural gas (MMcf).........................    113,377   109,915   107,920
      Oil equivalents (MBOE)....................     50,508    50,527    41,417
     Estimated future net revenues before income
      taxes.....................................  $ 705,723 $ 401,037 $ 272,776
     Present Value..............................  $ 414,314 $ 235,416 $ 160,804
     Standardized Measure of Discounted Future
      Net Cash Flows(1).........................  $ 317,180 $ 194,602 $ 142,032
   Proved developed reserves:
     Oil and NGLs (MBbl)........................     28,117    21,556    18,799
     Natural gas (MMcf).........................    103,129   102,026    98,370
      Oil equivalents (MBOE)....................     45,305    38,560    35,194
     Estimated future net revenues before income
      taxes.....................................  $ 631,406 $ 310,034 $ 251,003
     Present Value..............................  $ 381,169 $ 195,439 $ 155,642
   Weighted average sales prices:
     Oil (per Bbl)..............................  $   24.63 $   18.19 $   16.11
     Natural gas (per Mcf)......................       3.45      1.84      1.57
     NGLs (per Bbl).............................      19.79     12.87      9.80
</TABLE>
--------
(1) The Standardized Measure of Discounted Future Net Cash Flows prepared by
    the Company represents the present value (using an annual discount rate of
    10%) of estimated future net revenues from the production of proved
    reserves, after giving effect to income taxes. See the Supplemental
    Financial Information attached to the Consolidated Financial Statements of
    the Company included elsewhere in this Report for additional information
    regarding the disclosure of the Standardized Measure information in
    accordance with the provisions of Statement of Financial Accounting
    Standards No. 69, "Disclosures about Oil and Gas Producing Activities."
 
                                      13
<PAGE>
 
  All information set forth in this Report relating to the Company's proved
reserves, estimated future net revenues and Present Values is taken from
reports prepared by DeGolyer and MacNaughton (with respect to the Company's
United States properties) and Gilbert Lausten Jung Associates Ltd. (with
respect to the Company's Canadian properties), each of which is a firm of
independent petroleum engineers. The estimates of these engineers were based
upon review of production histories and other geological, economic, ownership
and engineering data provided by the Company. No reports on the Company's
reserves have been filed with any federal agency. In accordance with
guidelines of the Securities and Exchange Commission ("SEC"), the Company's
estimates of proved reserves and the future net revenues from which Present
Values are derived are made using year end oil and gas sales prices held
constant throughout the life of the properties (except to the extent a
contract specifically provides otherwise). The prices of oil and gas at
December 31, 1996 used to estimate the Company's proved reserves and the
future net revenues from which Present Value is derived were substantially
higher than the prices used in previous years to make such estimates and
substantially higher than oil and gas prices at February 28, 1997. The closing
price on the NYMEX for the prompt month futures contract for delivery of West
Texas Intermediate Crude Oil on December 31, 1996 and February 28, 1997 was
$25.92 and $20.30 per Bbl, respectively. The closing price on the NYMEX for
the prompt month futures contract for natural gas delivered at Henry Hub,
Louisiana on December 31, 1996 and February 28, 1997 was $2.76 and $1.82 per
MMBtu, respectively. A decline in prices relative to year end 1996 could cause
a significant decline in the Present Value attributable to the Company's
proved reserves at December 31, 1996. For example, a $1.00 decline in oil and
NGL prices, holding all other variables constant, would decrease such Present
Value by 4%, or $14.8 million, and a $0.10 decline in natural gas prices,
holding all other variables constant, would decrease such Present Value by 1%,
or $5.1 million. 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
<PAGE>
 
NET PRODUCTION, SALES PRICES AND COSTS
 
  The following table presents certain information with respect to oil and gas
production, prices and costs attributable to all oil and gas property
interests owned by the Company for the three-year period ended December 31,
1996.
 
<TABLE>
<CAPTION>
                                                        YEAR ENDED DECEMBER 31,
                                                        -----------------------
                                                         1996    1995    1994
                                                        ------- ------- -------
<S>                                                     <C>     <C>     <C>
PRODUCTION VOLUMES:
 Oil (MBbl)
  United States........................................   1,732   1,445   1,794
  Canada...............................................     693     635     310
                                                        ------- ------- -------
   Total Company.......................................   2,425   2,080   2,104
 Natural gas (MMcf)
  United States (1)....................................   9,479   9,418   9,804
  Canada...............................................   2,809   2,753   1,272
                                                        ------- ------- -------
   Total Company (1)...................................  12,288  12,171  11,076
 NGLs (MBbl)
  United States........................................     301     212     163
  Canada...............................................      50      40      10
                                                        ------- ------- -------
   Total Company.......................................     351     252     173
WEIGHTED AVERAGE SALES PRICES (2):
 Oil (per Bbl)
  United States........................................ $ 18.91 $ 17.14 $ 15.48
  Canada...............................................   18.55   16.38   16.32
   Total Company.......................................   18.81   16.91   15.60
 Natural gas (per Mcf)
  United States (1).................................... $  1.95 $  1.46 $  1.79
  Canada...............................................    1.16    1.05    1.23
   Total Company (1)...................................    1.77    1.37    1.73
 NGLs (per Bbl)
  United States........................................ $ 12.88 $  9.67 $  8.93
  Canada...............................................   16.21   12.45   10.15
   Total Company.......................................   13.36   10.11    9.00
SELECTED EXPENSES PER BOE (3):
 Lease operating
  United States........................................ $  4.53 $  4.59 $  4.74
  Canada...............................................    3.04    2.58    3.22
   Total Company.......................................    4.14    4.06    4.54
 Production taxes (4)
  United States........................................ $  0.93 $  0.78 $  0.97
 Depreciation, depletion and amortization
  United States........................................ $  3.36 $  3.63 $  4.20
  Canada...............................................    6.49    7.37    6.72
   Total Company.......................................    4.16    4.62    4.53
 General and administrative
  United States........................................ $  2.11 $  1.99 $  1.58
  Canada...............................................    1.61    1.70    1.76
   Total Company.......................................    1.98    1.92    1.61
</TABLE>
--------
(1) Calculated giving effect to volumes of natural gas purchased for resale as
    follows: 1996--605 MMcf, 1995--500 MMcf and 1994--469 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 giving effect to volumes of natural gas purchased for
    resale.
(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."
 
                                      15
<PAGE>
 
PRODUCTIVE WELLS AND ACREAGE
 
 Productive Wells
 
  The following table sets forth the Company's domestic and Canadian
productive wells at December 31, 1996:
 
<TABLE>
<CAPTION>
                                                      PRODUCTIVE WELLS
                                                --------------------------------
                                                   OIL       GAS         TOTAL
                                                --------- ------------ ---------
                                                GROSS NET GROSS    NET GROSS NET
                                                ----- --- -----    --- ----- ---
<S>                                             <C>   <C> <C>      <C> <C>   <C>
United States..................................   830 514 2,651(1) 355 3,481 869
Canada.........................................   220  57    67     24   287  81
                                                ----- --- -----    --- ----- ---
  Total........................................ 1,050 571 2,718    379 3,768 950
                                                ===== === =====    === ===== ===
</TABLE>
--------
(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, 1996. Undeveloped acreage includes
leased acres on which wells have not been drilled or completed to a point that
would permit the production of commercial quantities of oil and gas,
regardless of whether or not such acreage contains proved reserves.
 
<TABLE>
<CAPTION>
                               UNDEVELOPED ACRES DEVELOPED ACRES TOTAL ACRES(1)
                               ----------------- --------------- ---------------
                                GROSS     NET     GROSS    NET    GROSS    NET
                               ----------------- ------- ------- ------- -------
<S>                            <C>      <C>      <C>     <C>     <C>     <C>
Permian Basin
  Maljamar....................        0        0  11,773  11,761  11,773  11,761
  Wellman.....................        0        0   2,280   1,432   2,280   1,432
  Dimmitt/Slash Ranch.........      480      440   7,487   5,457   7,967   5,897
                               -------- -------- ------- ------- ------- -------
    Total Permian Basin.......      480      440  21,540  18,650  22,020  19,090
Appalachian Basin.............   26,846   21,195 116,330 100,695 143,176 121,890
San Juan Basin................        0        0  11,140   5,281  11,140   5,281
Other.........................   62,365   10,939  71,856  24,552 134,221  35,491
                               -------- -------- ------- ------- ------- -------
    Total United States.......   89,691   32,574 220,866 149,178 310,557 181,752
Canada........................  166,487   74,595  56,919  21,051 223,406  95,646
                               -------- -------- ------- ------- ------- -------
    Total Company.............  256,178  107,169 277,785 170,229 533,963 277,398
                               ======== ======== ======= ======= ======= =======
</TABLE>
--------
(1) Excluded is acreage in which the Company's interest is limited to a
    mineral or royalty interest. At December 31, 1996, the Company held
    mineral or royalty interests in 227,180 gross (31,465 net) developed acres
    and 1,371,809 gross (203,346 net) undeveloped acres.
 
                                      16
<PAGE>
 
  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:
 
<TABLE>
<CAPTION>
                                                                 ACRES EXPIRING
                                                                 ---------------
                                                                  GROSS    NET
                                                                 ------- -------
   <S>                                                           <C>     <C>
   Twelve Months Ending:
     December 31, 1997..........................................  35,579  10,840
     December 31, 1998..........................................  30,874   8,657
     Thereafter................................................. 189,725  87,672
                                                                 ------- -------
       Total.................................................... 256,178 107,169
                                                                 ======= =======
</TABLE>
 
  As is customary in the industry, the Company generally acquires oil and gas
acreage without any warranty of title except as to claims made by, through or
under the transferor. Although the Company has title to developed acreage
examined prior to acquisition in those cases in which the economic
significance of the acreage justifies the cost, there can be no assurance that
losses will not result from title defects or from defects in the assignment of
leasehold rights. In many instances, title opinions may not be obtained if in
the Company's judgment it would be uneconomical or impractical to do so.
 
DRILLING ACTIVITY
 
  The following table sets forth for the three-year period ended December 31,
1996 the number of exploratory and development wells drilled by or on behalf
of the Company.
 
<TABLE>
<CAPTION>
                                                      YEAR ENDED DECEMBER 31,
                                                   -----------------------------
                                                     1996      1995      1994
                                                   --------- --------- ---------
                                                   GROSS NET GROSS NET GROSS NET
                                                   ----- --- ----- --- ----- ---
   <S>                                             <C>   <C> <C>   <C> <C>   <C>
   Exploratory Wells:
     United States
       Producing..................................    1    1    9    3    4    1
       Dry........................................    2    1   10    3    7    2
     Canada
       Producing..................................    1    1    3    2    3    2
       Dry........................................    6    4    4    2    7    3
   Development Wells:
     United States
       Producing..................................   93   85   48   27   34   15
       Dry........................................    2    1    2    2    6    2
     Canada
       Producing..................................   21   15    4    2    1    0
       Dry........................................    5    3    2    2    1    0
   Total Wells:
       Producing..................................  116  102   64   34   42   18
       Dry........................................   15    9   18    9   21    7
                                                    ---  ---  ---  ---  ---  ---
         Total....................................  131  111   82   43   63   25
                                                    ===  ===  ===  ===  ===  ===
</TABLE>
 
                                      17
<PAGE>
 
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, 1996, the
Company operated 100% of its properties in the Permian Basin, comprising
approximately 55% of the Company's total proved reserves, including Maljamar
(223 gross wells), Wellman (14 gross wells) and Dimmitt/Slash Ranch (59 gross
wells). At December 31, 1996, the Company owned 368 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 82 (out of a total
of 287) gross wells on its Canadian properties.
 
  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 1996 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.
 
                                      18
<PAGE>
 
  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 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, 1996, 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
 
                                      19
<PAGE>
 
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. Although maximum selling prices of natural gas were formerly
regulated, on July 26, 1989, the Natural Gas Wellhead Decontrol Act
("Decontrol Act") was enacted, completely removing by January 1, 1993, price
and non-price controls for all "first sales" of natural gas, which include all
sales by the Company of its own production; consequently, sales of the
Company's natural gas currently may be made at uncontrolled market prices,
subject to applicable contract provisions. The FERC's jurisdiction over
natural gas transportation was unaffected by the Decontrol Act. While sales by
producers of natural gas, and all sales of crude oil, condensate and NGLs, can
currently be made at uncontrolled market prices, Congress could re-enact
prices controls in the future.
 
  Since the mid-1980's, the FERC has issued a series of orders, 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 mandates 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 is 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, the results of
which have generally been supportive of the FERC's open-access policy. Last
year the United States Court of Appeals for the District of Columbia largely
upheld Order No. 636. Because further review of certain of these orders is
still possible, and other appeals remain pending, it is difficult to 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 1996, 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
 
                                      20
<PAGE>
 
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 1996, 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.
 
  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 Counsel.
 
  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.
 
                                      21
<PAGE>
 
  In addition to Canadian federal regulation, Alberta and certain other
provinces have legislation and regulations that govern royalties payable on
production from Crown lands. The royalty regime that is in place at a
particular time or location is a significant factor in the profitability of
oil and gas production. Royalties payable on production from lands other than
Crown lands are determined by negotiations between the mineral owner and the
lessee. Crown royalties are determined by governmental regulation and are
generally calculated as a percentage of the value of the gross production. The
rate of royalties payable generally depends in part on prescribed reference
prices, well productivity, geographical location, field discovery date and the
type and quality of the petroleum product produced.
 
  From time to time the government of Alberta has established incentive
programs that have included royalty rate reductions, royalty holidays and tax
credits for the purpose of encouraging oil and gas exploration or enhanced
production projects. For example, a producer of oil or gas is entitled to a
credit against the royalties payable to the Crown by virtue of the Alberta
Royalty Tax Credit ("ARTC") program. The ARTC program provides a rebate on
Crown royalties paid in respect of eligible producing properties. The ARTC
program is based on a price-sensitive formula, and the ARTC rate currently
varies between 25% and 75% of the royalty otherwise payable on production. The
ARTC rate is currently applied to a maximum of $2.0 million of Alberta Crown
royalties otherwise payable by each producer or associated group of producers
in each tax year. The rate is established quarterly based on average "par
price," as determined by the Alberta Department of Energy for the previous
quarterly period. Producing properties acquired from corporations claiming
maximum entitlement to ARTC will generally not be eligible for ARTC.
 
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
 
                                      22
<PAGE>
 
Environmental Protection Agency and various state agencies have limited the
approved methods of disposal for certain hazardous and nonhazardous wastes.
Furthermore, certain wastes generated by the Company's oil and gas operations
that are currently exempt from regulation as "hazardous wastes" may in the
future be designated as "hazardous wastes," and therefore be subject to more
rigorous and costly operating and disposal requirements.
 
  The Oil Pollution Act ("OPA") imposes a variety of requirements on
responsible parties for onshore and offshore oil and gas facilities and
vessels related to the prevention of oil spills and liability for damages
resulting from such spills in waters of the United States. The "responsible
party" includes the owner or operator of an onshore facility or vessel or the
lessee or permittee of, or the holder of a right of use and easement for, the
area where an onshore facility is located. OPA assigns liability to each
responsible party for oil spill removal costs and a variety of public and
private damages from oil spills. Few defenses exist to the liability for oil
spills imposed by OPA. OPA also imposes financial responsibility requirements.
Failure to comply with ongoing requirements or inadequate cooperation in a
spill event may subject a responsible party to civil or criminal enforcement
actions.
 
  The Company's Canadian operations are also subject to environmental
regulation pursuant to local, provincial and federal legislation. Canadian
environmental legislation provides for restrictions and prohibitions on
releases or emissions of various substances produced in association with
certain oil and gas industry operations and can affect the location of wells
and facilities and the extent to which exploration and development is
permitted. In addition, legislation requires that well and facilities sites be
abandoned and reclaimed to the satisfaction of provincial authorities. In most
cases, an environmental assessment and review is required prior to initiating
exploration or development projects or undertaking significant changes to
existing projects. A breach of such legislation may result in the imposition
of fines and issuance of clean-up orders. Environmental legislation in Alberta
has recently undergone a major revision and has been consolidated in the
Environmental Protection and Enhancement Act. 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.
 
                                      23
<PAGE>
 
EMPLOYEES
 
  At February 28, 1997, the Company employed 148 full-time employees, of whom
five were executive officers, 29 were technical personnel, 61 were field
personnel and 53 were administrative personnel. Of the total employees, 121
were located in the United States and 27 were located in Canada. At February
28, 1997, except for nine employees of the Company associated with its
Michigan properties, which properties are currently under contract to be sold,
none of the Company's employees was 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 $33,500 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.
 
  "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."
 
  "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.
 
                                      24
<PAGE>
 
  "MCF" means thousand cubic feet.
 
  "MMBOE" means million BOE.
 
  "MMBTU" means one million British Thermal Units. British Thermal Unit means
the quantity of heat required to raise the temperature of one pound of water
by one degree Fahrenheit.
 
  "MMCF" means million cubic feet.
 
  "NET" when used with respect to acres or wells, refers to gross acres or
wells multiplied, in each case, by the percentage working interest owned by
the Company.
 
  "NET PRODUCTION" means production that is owned by the Company less
royalties and production due others.
 
  "NGL" means natural gas liquid.
 
  "OPERATOR" means the individual or company responsible for the exploration,
development and production of an oil or gas well or lease.
 
  "PRESENT VALUE" when used with respect to oil and gas reserves, means the
estimated future gross revenues to be generated from the production of proved
reserves calculated in accordance with the guidelines of the SEC, net of
estimated production and future development costs, using prices and costs as
of the date of estimation without future escalation (except to the extent a
contract specifically provides otherwise), without giving effect to non-
property related expenses such as general and administrative expenses, debt
service, future income tax expense and depreciation, depletion and
amortization, and discounted using an annual discount rate of 10%.
 
  "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.
 
                                      25
<PAGE>
 
  (iii) Estimates of proved reserves do not include the following: (A) oil
  that may become available from known reservoirs but is classified
  separately as "indicated additional reserves"; (B) crude oil, natural gas
  and NGLs, the recovery of which is subject to reasonable doubt because of
  uncertainty as to geology, reservoir characteristics or economic factors;
  (C) crude oil, natural gas, and NGLs, that may occur in undrilled
  prospects; and (D) crude oil, natural gas and NGLs that may be recovered
  from oil shales, coal, gilsonite and other such resources.
 
  "PROVED UNDEVELOPED RESERVES" means reserves that are expected to be
recovered from new wells on undrilled acreage, or from existing wells where a
relatively major expenditure is required for completion. Reserves on undrilled
acreage shall be limited to those drilling units offsetting productive units
that are reasonably certain of production when drilled. Proved reserves for
other undrilled units can be claimed only where it can be demonstrated with
certainty that there is continuity of production from the existing productive
formation. Under no circumstances should estimates for proved undeveloped
reserves be attributable to any acreage for which an application of fluid
injection or other improved recovery technique is contemplated, unless such
techniques have been proved effective by actual tests in the area and in the
same reservoir.
 
  "RECOMPLETION" means the completion for production of an existing well bore
in another formation from that in which the well has been previously
completed.
 
  "RESERVES" means proved reserves.
 
  "RESERVOIR" means a porous and permeable underground formation containing a
natural accumulation of producible oil and/or gas that is confined by
impermeable rock or water barriers and is individual and separate from other
reservoirs.
 
  "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.
 
                                      26
<PAGE>
 
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, 1996.
 
                                    PART II
 
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK 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, 1996, were as follows:
 
<TABLE>
<CAPTION>
                                                          HIGH   LOW   DIVIDENDS
                                                         ------ ------ ---------
   <S>                                                   <C>    <C>    <C>
   1996
     1st Quarter........................................ $13.38 $11.00   $.03
     2nd Quarter........................................  14.00  12.25    .03
     3rd Quarter........................................  15.50  12.88    .03
     4th Quarter........................................  21.13  14.38    .03
   1995
     1st Quarter........................................  14.75  13.38    .10
     2nd Quarter........................................  15.00  13.13    .10
     3rd Quarter........................................  14.38  13.00    .10
     4th Quarter........................................  13.75  10.88    .10
   1994
     1st Quarter........................................  18.88  15.75    .10
     2nd Quarter........................................  16.63  15.00    .10
     3rd Quarter........................................  17.38  15.75    .10
     4th Quarter........................................  17.75  13.13    .10
</TABLE>
 
  At February 28, 1997, there were 8,948,840 shares of Common Stock
outstanding held by approximately 1,092 shareholders of record and
approximately 3,900 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 par value
$10.00 per share, 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 (as such term
is defined in "Management's Discussion and Analysis of Financial Condition and
Results of Operations--Liquidity and Capital Resources"), 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
<PAGE>
 
ITEM 6. SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA
 
  The following selected consolidated financial data of the Company are
derived from information contained in the Company's consolidated financial
statements. The selected consolidated financial and operating data presented
below should be read in conjunction with "Management's Discussion and Analysis
of Financial Condition and Results of Operations" and the Company's
Consolidated Financial Statements and notes thereto included elsewhere in this
Report.
 
<TABLE>
<CAPTION>
                                        YEAR ENDED DECEMBER 31,
                         -------------------------------------------------------
                            1996       1995       1994       1993        1992
                         ---------- ---------- ---------- ----------  ----------
                          (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS AND RATIOS)
<S>                      <C>        <C>        <C>        <C>         <C>
INCOME STATEMENT DATA:
 Revenues:
  Oil and gas sales..... $   72,012 $   54,400 $   53,559 $   40,329  $   37,157
  Dividends and
   interest.............        683      1,241      1,641      1,855       2,000
  Marketable security
   sales gains..........     12,977     13,101      7,475        --          --
  Other.................      1,017      2,939      2,681        737       1,025
                         ---------- ---------- ---------- ----------  ----------
    Total revenues......     86,689     71,681     65,356     42,921      40,182
                         ---------- ---------- ---------- ----------  ----------
 Costs and expenses:
  Production and
   operating............     23,970     20,690     22,313     17,864      15,083
  Purchased natural
   gas..................      1,462        727        759      1,182         993
  Depreciation,
   depletion and
   amortization.........     19,653     19,778     18,313     14,659      13,803
  Property impairments..     12,112      4,893        --         693         --
  Exploration...........      4,176      5,801      4,130      3,639       6,308
  General and
   administrative.......      9,364      8,193      6,502      5,429       4,199
  Interest expense......      5,452      5,618      3,907        530          31
                         ---------- ---------- ---------- ----------  ----------
    Total costs and
     expenses...........     76,189     65,700     55,924     43,996      40,417
                         ---------- ---------- ---------- ----------  ----------
 Income (loss) before
  income taxes..........     10,500      5,981      9,432     (1,075)       (235)
 Income tax expense
  (benefit).............      4,072      3,788        444     (2,091)       (712)
                         ---------- ---------- ---------- ----------  ----------
 Net income............. $    6,428 $    2,193 $    8,988 $    1,016  $      477
                         ========== ========== ========== ==========  ==========
 Average outstanding
  shares (1)............      8,954      8,939      8,941      8,939       8,938
 Per share data:
  Net income per share.. $     0.72 $     0.25 $     1.01 $     0.11  $     0.05
  Cash dividends per
   share................ $     0.12 $     0.40 $     0.40 $     0.40  $     0.40
OTHER FINANCIAL DATA:
 EBITDAX (2)............ $   38,233 $   27,729 $   26,666 $   16,591  $   17,907
 Operating cash flow....     33,228     19,239     23,134     16,777      17,653
 Capital expenditures
  (3)...................     46,231     31,052     73,186     72,321      17,218
BALANCE SHEET DATA (END
 OF PERIOD):
 Cash and cash
  equivalents........... $    5,870 $    1,397 $    2,714 $    3,499  $   14,525
 Working capital (4)....      3,493      1,034      2,313      6,454      16,401
 Marketable securities..      7,176     19,592     27,337     34,781       3,845
 Net property, plant and
  equipment.............    179,718    169,089    167,371    127,708      75,697
 Total assets...........    208,617    203,407    210,791    177,782     102,340
 Long-term debt.........     78,654     74,171     78,013     46,777         135
 Stockholders' equity...     99,262    101,132    105,427    105,116      87,241
</TABLE>
 
                                             (See footnotes on following pages)
 
                                      28
<PAGE>
 
<TABLE>
<CAPTION>
                                             YEAR ENDED DECEMBER 31,
                                   --------------------------------------------
                                     1996     1995     1994     1993     1992
                                   -------- -------- -------- -------- --------
<S>                                <C>      <C>      <C>      <C>      <C>
RESERVE AND OPERATING DATA:
 Production volumes:
  Oil and NGLs (MBbl).............    2,776    2,332    2,277    1,468    1,298
  Natural gas (MMcf)(5)...........   12,288   12,171   11,076    8,296    6,996
   Oil equivalents (MBOE)(5)......    4,824    4,361    4,123    2,851    2,464
 Weighted average sales prices(6):
  Oil (per Bbl)................... $  18.81 $  16.91 $  15.60 $  16.44 $  19.07
  Natural gas (per Mcf)(5)             1.77     1.37     1.73     2.07     1.95
  NGLs (per Bbl)..................    13.36    10.11     9.00     9.42    10.11
   Oil equivalents (per BOE)(5)...    14.93    12.47    12.99    14.15    15.08
 Selected expenses per BOE(7):
  Lease operating................. $   4.14 $   4.06 $   4.54 $   5.80 $   5.63
  Production taxes................     0.93     0.78     0.97     0.72     0.75
  Depreciation, depletion and
   amortization...................     4.16     4.62     4.53     5.35     5.24
  General and administrative......     1.98     1.92     1.61     1.98     1.78
 Proved reserves (end of
  period)(8):
  Oil and NGLs (MBbl).............   31,612   32,208   23,430   21,242   11,756
  Natural gas (MMcf)..............  113,377  109,915  107,920  103,317   70,034
   Oil equivalents (MBOE).........   50,508   50,527   41,417   38,462   23,428
  Estimated future net revenues
   before income taxes (in
   thousands)..................... $705,723 $401,037 $272,776 $241,251 $210,591
  Present Value (in thousands).... $414,314 $235,416 $160,804 $137,149 $116,611
  Standardized Measure of
   Discounted Future Net Cash
   Flows (in thousands)(9)........ $317,180 $194,602 $142,032 $112,423 $ 86,559
 Weighted average sales prices
  (end of period)(8)(10):
  Oil (per Bbl)................... $  24.63 $  18.19 $  16.11 $  13.35 $  17.29
  Natural gas (per Mcf)........... $   3.45 $   1.84 $   1.57 $   2.34 $   2.36
  NGLs (per Bbl).................. $  19.79 $  12.87 $   9.80 $   9.07 $   8.04
</TABLE>
--------
(1) Calculated using the treasury stock method. Under this method, average
    outstanding shares for the year ended December 31, 1996 exclude 864,582
    shares issuable pursuant to the Company's stock incentive plans at that
    date.
(2) EBITDAX 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. EBITDAX 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). EBITDAX 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) Consist of costs incurred by the Company in connection with its oil and
    gas acquisition, development and exploration activities, and, in certain
    years, costs relating to the reconditioning of its gas plants. See Note 6
    to the Company's Consolidated Financial Statements included elsewhere in
    this Report.
(4) Working capital represents the difference between current assets and
    current liabilities.
(5) Calculated giving effect to volumes of natural gas purchased for resale as
    follows: 1996--605 MMcf, 1995--500 MMcf, 1994--469 MMcf, 1993--666 MMcf
    and 1992--600 MMcf.
(6) Reflects results of hedging activities. See "Management's Discussion and
    Analysis of Financial Condition and Results of Operations--Other Matters."
(7) Calculated without giving effect to volumes of natural gas purchased for
    resale.
 
                                      29
<PAGE>
 
(8) 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. The prices of oil and gas at
    December 31, 1996 used to estimate the Company's proved reserves and future
    net revenues from which Present Values are derived were substantially
    higher than the prices used in previous years to make such estimates and
    substantially higher than oil and gas prices at February 28, 1997.
(9) 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.
(10) Year end prices used to estimate proved reserves and future net revenues
     from which Present Values are derived. See footnote 8 above.
 
                                       30
<PAGE>
 
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
 
  The following discussion is intended to assist in an understanding of the
Company's historical financial position and results of operations for each
year in the three-year period ended December 31, 1996. 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 CO/2/ 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 owns certain marketable securities and, in connection with its
change in business strategy, has been liquidating portions thereof in order to
fund a portion of the Company's capital expenditures. The Company recognized
pretax gains from the sale of marketable securities of $13.0 million, $13.1
million and $7.5 million in 1996, 1995 and 1994, respectively. In the absence
of such gains, the Company would have reported net losses in 1996 and 1995,
and its net income in 1994 would have been reduced. The Company plans to
liquidate the remainder of its marketable securities (valued at $7.2 million
at December 31, 1996) in 1997. Accordingly, the positive impact that sales of
marketable securities have had on the Company's net income is not expected to
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 $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, 1996, the Company's proved reserves were comprised of
approximately 90% 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.
 
  The Company follows the successful efforts method of accounting for oil and
gas producing activities. Under this method, the Company capitalizes all costs
incurred to acquire interests in oil and gas properties, to drill and equip
exploratory wells in which proved reserves are discovered and to drill and
equip development wells. Geological and geophysical costs, delay rentals and
technical support costs are expensed as incurred. The costs of drilling and
equipping exploratory wells in which proved reserves are not discovered are
expensed upon a determination that a well does not justify commercial
development. The capitalized costs of producing oil and gas properties are
depreciated and depleted using the units-of-production method based on
estimated proved reserves. Unproved oil and gas properties are periodically
assessed for impairment of value, and if an impairment is determined to exist,
such impairment is expensed. The successful efforts method of accounting could
affect the Company's income from operations depending upon the Company's level
of drilling activities and the results of such drilling in any year.
 
                                      31
<PAGE>
 
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 giving effect to
such volumes. Such volumes were 605 MMcf in 1996, 500 MMcf in 1995 and 469
MMcf in 1994.
 
 Comparison of 1996 to 1995
 
  Income Before Income Taxes and Net Income. Income before income taxes
increased 75% to $10.5 million for 1996 from $6.0 million in 1995. Net income
increased 191% to $6.4 million in 1996 from $2.2 million in 1995. The
improvement in income before income taxes and net income was attributable
primarily to higher production and higher net realized prices during 1996.
 
  Production. The Company's net oil production rose 17% to 2,425 MBbls in 1996
from 2,080 MBbls in 1995. Net natural gas production increased 1% to 12,288
MMcf in 1996 from 12,171 MMcf in 1995. On an equivalent unit basis, net
production increased 11% to 4,824 MBOE in 1996 from 4,361 MBOE in 1995. The
increase in production was primarily attributable to development activities
which resulted in the addition of 102 net producing wells in 1996.
 
  Revenues. Total revenues increased 21% to $86.7 million in 1996 from $71.7
million in 1995, primarily because of higher production and higher net
realized prices during 1996. Average net realized oil prices rose 11% to
$18.81 per Bbl in 1996 from $16.91 per Bbl in 1995. Average net realized
natural gas prices rose 29% to $1.77 per Mcf in 1996 from $1.37 per Mcf in
1995. Average net realized NGL prices rose 32% to $13.36 per Bbl in 1996 from
$10.11 per Bbl in 1995. The average net realized oil, gas and NGL prices
received in 1996 of $18.81 per Bbl, $1.77 per Mcf and $13.36 per Bbl,
respectively, compared to average prices of $20.86 per Bbl, $1.92 per Mcf and
$13.64 per Bbl, respectively, which would have been received before the
effects of the Company's hedging activities, which activities resulted in a
reduction of $6.9 million in the Company's oil and gas sales for 1996. Effects
of hedging activities were not significant in 1995.
 
  Dividends and interest decreased 42% to $0.7 million in 1996 from $1.2
million in 1995, primarily as a result of sales of marketable securities in
1996 and 1995. The Company recognized a pretax gain of $13.0 million from
marketable security sales in 1996, compared with a pretax gain of $13.1
million from similar sales in 1995. Other revenues of the Company decreased
66% to $1.0 million in 1996 from $2.9 million in 1995, primarily as a result
of fewer sales of non-strategic properties in 1996.
 
  Production and Operating Expenses. Production and operating expenses
increased 16% to $24.0 million in 1996 from $20.7 million in 1995, primarily
due to higher production taxes resulting from higher revenues from sales of
oil and gas. On an equivalent unit of production basis, such expenses
increased 5% to $5.07 per BOE in 1996 from $4.84 per BOE in 1995.
 
  Depreciation, Depletion and Amortization ("DD&A"). DD&A decreased 1% to
$19.7 million in 1996 from $19.8 million in 1995. The DD&A rate per BOE
decreased 10% to $4.16 in 1996 from $4.62 in 1995. The decrease in the DD&A
rate per BOE in 1996 was due primarily to upward revisions of previous
estimates of the Company's proved reserves attributable to certain of its
properties in the Permian Basin and Canada during 1996, while capitalized
costs relating to such properties remained relatively constant.
 
  Property Impairment Charges. The Company recognized non-cash property
impairment charges of $12.1 million in 1996 and $4.9 million in 1995 as a
result of applying the provisions of SFAS No. 121. The impairment charge for
1996 resulted from a downward revision of previous estimates of the Company's
proved reserves attributable to certain of its properties in Michigan and
Canada. The impairment charge for 1995 resulted from a downward revision of
previous estimates of the Company's proved reserves attributable to certain of
its Canadian properties.
 
                                      32
<PAGE>
 
  Exploration Costs. Exploration costs 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.
 
  General and Administrative Costs. General and administrative costs increased
15% to $9.4 million in 1996 from $8.2 million in 1995, primarily as a result
of higher compensation costs and professional fees relating to acquisition and
tax matters. On an equivalent unit of production basis, general and
administrative costs increased 3% to $1.98 per BOE in 1996 from $1.92 per BOE
in 1995.
 
  Interest Expense. Interest expense decreased 2% to $5.5 million in 1996 from
$5.6 million in 1995.
 
  Effective Tax Rate. The Company's effective tax rate decreased to 39% in
1996 from 63% in 1995. This decrease was due primarily to a decrease in 1996
in the amount of tax loss attributable to the Company's Canadian operations
that was not deductible for purposes of United States federal income taxes. In
addition, the Company's Internal Revenue Code 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.
 
 Comparison of 1995 to 1994
 
  Income Before Income Taxes and Net Income. Income before income taxes
decreased 36% to $6.0 million in 1995 from $9.4 million in 1994. Net income
decreased 76% to $2.2 million in 1995 from $9.0 million in 1994. The decrease
in income before income taxes was due primarily to a non-cash property
impairment charge of $4.9 million against 1995 income, all of which related to
impairments of certain of Wiser's Canadian properties, compared with no such
charge in 1994. The decrease in net income was due primarily to (i) such
property impairment charge and (ii) an increase in income tax expense to $3.8
million in 1995 from $0.4 million in 1994, due principally to a decrease in
the deferred tax asset valuation reserve in 1994 which did not occur in 1995.
The property impairment charge and the increase in income tax expense in 1995
were partially offset by a pretax gain of $13.1 million from the sale by the
Company of a portion of its marketable securities portfolio in 1995, compared
with a pretax gain of $7.5 million from similar sales in 1994.
 
  Production. Net oil production decreased 1% to 2,080 MBbls in 1995 from
2,104 MBbls in 1994, while net natural gas production increased 10% to 12,171
MMcf in 1995 from 11,076 MMcf in 1994. The Company's total net equivalent
production increased 6% to 4,361 MBOE in 1995 from 4,123 MBOE in 1994,
primarily as a result of 34 net producing wells completed in 1995.
 
  Revenues. Total revenues increased 10% to $71.7 million in 1995 from $65.4
million in 1994, primarily because of an increase of $5.6 million in pretax
gains from the sale by the Company of marketable securities in 1995 compared
with pretax gains from similar sales in 1994. Oil and gas revenues for 1995
remained relatively constant, increasing 1% to $54.4 million in 1995 from
$53.6 million in 1994. This increase was due primarily to higher production in
1995, partially offset by a 4% decrease in 1995 in average net realized prices
on an oil equivalent basis. Average net realized oil prices rose 8% to $16.91
per Bbl in 1995 from $15.60 per Bbl in 1994, while average net realized
natural gas prices declined 21% to $1.37 per Mcf in 1995 from $1.73 per Mcf in
1994. Average net realized NGL prices rose 12% to $10.11 per Bbl in 1995 from
$9.00 per Bbl in 1994.
 
  Production and Operating Expenses. Production and operating expenses
decreased 7% to $20.7 million in 1995 from $22.3 million in 1994, primarily as
a result of sales by the Company of non-strategic properties in late 1994. On
an equivalent unit of production basis, such expenses decreased 12% to $4.84
per BOE in 1995 from $5.51 per BOE in 1994.
 
  Depreciation, Depletion and Amortization. DD&A increased 8% to $19.8 million
in 1995 from $18.3 million in 1994, primarily as a result of an additional
$4.8 million in DD&A attributable to a full year of ownership of the Company's
Canadian properties in 1995, partially offset by a decrease of $3.2 million in
DD&A due to sales by the Company in late 1994 of certain non-strategic
properties with high DD&A rates. The DD&A rate per BOE increased 2% to $4.62
in 1995 from $4.53 in 1994.
 
                                      33
<PAGE>
 
  Exploration Costs. Exploration costs increased 41% to $5.8 million in 1995
from $4.1 million in 1994, primarily as a result of higher dry hole costs in
1995.
 
  General and Administrative Costs. General and administrative costs increased
26% to $8.2 million in 1995 from $6.5 million in 1994. Of this increase, $1.0
million was due to the inclusion in 1995 operating results of a full year of
Canadian operations and $0.7 million was attributable to higher legal
expenses. On an equivalent unit of production basis, general and
administrative costs increased 19% to $1.92 per BOE in 1995 from $1.61 per BOE
in 1994.
 
  Interest Expense. Interest expense increased 44% to $5.6 million in 1995
from $3.9 million in 1994. This increase was due primarily to the inclusion in
1995 operating results of a full year's interest expense related to the $52.0
million of bank debt incurred in connection with the Company's purchase of its
Canadian properties in 1994.
 
  Effective Tax Rate. The Company's effective tax rate increased to 63% in
1995 from 5% in 1994. The increase was due primarily to an increase in net
operating losses attributable to the Company's Canadian operations for which
no current U.S. federal income tax benefit was available and benefits realized
in 1994 from the recognition of previously reserved deferred tax assets which
were not available in 1995.
 
LIQUIDITY AND CAPITAL RESOURCES
 
 General
 
  Working capital at December 31, 1996 was $3.5 million, representing a $2.5
million increase over the corresponding amount at December 31, 1995. At
December 31, 1996, the Company had $5.9 million in cash and cash equivalents
and $208.6 million of total assets. During 1996, long-term debt rose to $78.7
million from $74.2 million in 1995.
 
  At December 31, 1996, capitalization totaled $177.9 million, of which
approximately 56% was represented by stockholders' equity and 44% by long-term
debt. At that date, approximately $58.0 million of the long-term debt was
comprised of borrowings under the Credit Agreement, and the remaining $20.7
million was comprised of indebtedness under the Maljamar Credit Facility. See
Note 3 to the Company's Consolidated Financial Statements included elsewhere
in this Report.
 
 Capital Sources
 
  Funding for the Company's business activities has been provided by cash flow
from operations, bank financing and sales of marketable securities. The
Company anticipates liquidating the remainder of its marketable securities
during 1997. Accordingly, this source of funds is not expected to be available
after 1997.
 
  While the Company regularly engages in discussions relating to potential
acquisitions of oil and gas properties (some of which may be material to the
Company), the Company has no current agreement or commitment with respect to
any such acquisition, other than relatively minor acquisitions of oil and gas
properties and interests in its normal course of business. Any future
acquisitions may require additional financing and will be dependent upon
financing arrangements available at the time.
 
  The Company believes that funds provided by internally generated cash flows,
including the sale of its remaining marketable securities, will be sufficient
to meet anticipated operating and capital expenditure requirements (excluding
any property acquisitions) in 1997. If the Company's internally generated cash
flows are less than anticipated or its capital needs are greater than
anticipated, the Company may borrow funds under the Credit Agreement (as
defined below). If the Company's cash flow from operations and the
availability under the Credit Agreement are not sufficient to satisfy its cash
requirements, there can be no assurance that additional equity or debt
financing will be available to meet such requirements.
 
                                      34
<PAGE>
 
 Long-Term Debt
 
  On June 23, 1994, the Company entered into a credit agreement with
NationsBank of Texas, N.A. as agent (the "Credit Agreement") which currently
provides for a term loan to the Company's Canadian subsidiary and a revolving
credit facility to the Company. At December 31, 1996, the outstanding
principal balance of indebtedness under the Credit Agreement was $58.0
million, all of which was bearing interest at 6.31% per annum. These
borrowings were used by the Company to finance property acquisitions and for
other general corporate purposes. The average interest rate paid by the
Company on borrowings under the Credit Agreement during 1996 was 6.04% per
annum.
 
  On November 29, 1995, the Company entered into a credit agreement with
NationsBank of Texas, N.A. as agent (the "Maljamar Credit Facility"). The
Maljamar Credit Facility provides the Company with up to a $50.0 million
nonrecourse facility to develop the Maljamar project area. At December 31,
1996, indebtedness under the Maljamar Credit Facility was approximately $20.7
million. The average interest rate paid by the Company on borrowings under the
Maljamar Credit Facility during 1996 was 7.5% per annum.
 
  See Note 3 to the Company's Consolidated Financial Statements included
elsewhere in this Report for additional information regarding the Credit
Agreement and the Maljamar Credit Facility.
 
 Cash Flow Analysis
 
  Cash Flows from Operating Activities. Cash flows from operating activities
were $33.2 million in 1996, $19.2 million in 1995 and $23.1 million in 1994.
The increase in cash flows from operating activities for 1996 was due
primarily to higher production and higher net realized prices in 1996. The
decrease in cash flows for 1995 compared to 1994 was due primarily to higher
interest expense and income taxes paid in 1995.
 
  Cash Flows from Investing Activities. Cash flows used in investing
activities increased to $31.0 million in 1996 from $13.1 million in 1995. This
increase was caused primarily by an increase in capital expenditures. Capital
expenditures were $46.2 million in 1996 compared with $31.1 million in 1995.
Cash flows used in investing activities decreased to $13.1 million in 1995
from $51.6 million in 1994. Cash flows used in investing activities in 1994
included $52.0 million for the acquisition by the Company of Canadian oil and
gas properties in June 1994. Cash flows from investing activities in 1996,
1995 and 1994 included $14.0 million, $14.5 million and $8.3 million,
respectively, in proceeds from marketable security sales. At December 31,
1996, the Company's marketable securities portfolio had been reduced to $7.2
million in value. The Company anticipates liquidating the remainder of its
marketable securities during 1997.
 
  Cash Flows from Financing Activities. Cash flows from financing activities
were $2.2 million in 1996 compared to $7.5 million used in financing
activities in 1995. During 1996, the Company increased its total long-term
debt by $4.5 million in connection with financing development activities in
the Maljamar area. The Company also reduced its cash dividends to $1.1 million
in 1996 from $3.6 million in 1995. During 1995, the Company reduced its total
long-term debt by $3.8 million. Cash flows used in financing activities were
$7.5 million in 1995 compared with $27.7 million in cash flows from financing
activities in 1994. During 1994, total long-term debt increased $31.2 million
as a result of financing the acquisition of the Canadian oil and gas
properties.
 
 Capital 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.
 
  Capital expenditures of the Company increased approximately 49% to $46.2
million in 1996 from $31.1 million in 1995, primarily as a result of an
increase in capital expenditures related to the Company's Maljamar waterflood
project. Capital expenditures decreased approximately 58% to $31.1 million in
1995 from $73.2 million in 1994. Capital expenditures in 1994 included $52.0
million for the purchase of certain Canadian oil and gas properties in June
1994. Excluding the 1994 Canadian acquisition, capital expenditures increased
approximately 47% to $31.1 million in 1995 from $21.2 million in 1994. The
increase reflected a full year of
 
                                      35
<PAGE>
 
capital expenditures in Canada, the completion of modifications to a gas
processing plant at the Company's Wellman Unit and an increase in capital
expenditures related to the Company's Maljamar waterflood project.
 
  During 1997, subject to market conditions and drilling and operating results,
the Company expects to spend approximately $44.3 million on development,
exploitation and exploration activities. Of this amount, the Company has
budgeted $31.3 million for development and exploitation activities and $13.0
million for exploration activities.
 
OTHER MATTERS
 
 Hedging Activities
 
  The Company has 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 $6.9 million in the Company's revenues
for the year ended December 31, 1996. Hedging activities in 1995 and 1994 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.
 
  At December 31, 1996, approximately 41% of the Company's total expected oil
production through December 1997 was hedged under collar arrangements as
follows:
 
<TABLE>
<CAPTION>
                                     DAILY VOLUME FLOOR PRICE  CEILING PRICE
 BEGINNING DATE      ENDING DATE        (BBLS)     (PER BBL)     (PER BBL)
 --------------      -----------     ------------ -----------  -------------
 <S>              <C>                <C>          <C>          <C>
 January 1, 1997  December 31, 1997     1,000       $16.00        $18.85
 January 1, 1997  December 31, 1997     1,000        21.80(1)      25.55(1)
 January 1, 1997  March 31, 1997        2,000        16.00         19.41
 April 1, 1997    June 30, 1997         2,000        17.00         19.00
 July 1, 1997     September 30, 1997    2,000        17.00         19.00
</TABLE>
--------
(1) Canadian dollars.
 
  At December 31, 1996, approximately 40% of the Company's total expected NGL
production from January 1 through March 31, 1997 was hedged at a weighted
average swap price of $18.76 per Bbl. See Note 1 to the Company's Consolidated
Financial Statements included elsewhere in this Report.
 
 Effects of Fluctuations in Exchange Rates
 
  The Company receives a substantial portion of its revenue in Canadian
dollars. 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,
 
                                       36
<PAGE>
 
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.
 
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 1997 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.
 
                                      37
<PAGE>
 
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 DISCLOSURES
 
  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
 
  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.
 
 
                                       38
<PAGE>
 
                                     PART IV
 
ITEM 14 EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
 
A. FINANCIAL STATEMENTS
 
  The following documents are filed as part of this Report:
 
  1. Report of Independent Accountants
 
    Consolidated Statements of Income and Retained Earnings
 
    Consolidated Balance Sheets
 
    Consolidated Statements of Cash Flows
 
    Notes to Consolidated Financial Statements
 
  2. Schedules are omitted because of the absence of conditions under which
    they are required or because the required information is given in the
    financial statements or notes thereto.
 
B. NO REPORTS ON FORM 8-K WERE FILED DURING THE LAST QUARTER OF THE YEAR
     COVERED BY THIS ANNUAL REPORT.
 
C. EXHIBITS
 
<TABLE>
<CAPTION>
 EXHIBIT
 NUMBERS
 -------
 <C>     <S>
  (3.1)  Certificate of Incorporation, 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).
 (10.1)  Credit Agreement dated June 23, 1994 among The Wiser Oil Company and
         The Wiser Oil Company of Canada, as Borrowers, and Nations Bank of
         Texas, N.A., as Agent, and Certain Financial Institutions Listed on
         the Signature Pages Thereto, as Banks, incorporated by reference to
         the Exhibit 10.1 to the report on Form 8-K dated July 11, 1994 as
         amended August 17, 1994.
 (10.2)  Credit Agreement dated November 29, 1995 among The Wiser Oil Company
         and Maljamar Development Partnership, L.P. as Borrowers, and Nations
         Bank of Texas, N.A., as Agent, and Certain 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 report on Form 8-K dated July 11, 1994
         as amended August 17, 1994.
 (10.4)* Employment Agreement dated August 1, 1994 between the Company and
         Allen 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.
</TABLE>
 
 
                                      39
<PAGE>
 
<TABLE>
<CAPTION>
 <C>       <S>
 (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.
 (10.7)*   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.
 (10.9)*   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.
 (10.10)*+ Employment Agreement dated September 30, 1996 between the Company
           and Kent E. Johnson.
 (10.11)*+ The Wiser Oil Company Equity Compensation Plan For Non-Employee
           Directors.
 (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
</TABLE>
--------
* The documents filed or incorporated by reference as Exhibits 10.4, 10.5,
  10.6, 10.7, 10.8 and 10.9, 10.10 and 10.11 represent management compensatory
  plans or agreements.
+ Filed herewith
 
                                      40
<PAGE>
 
  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 26TH DAY
OF MARCH 1997.
                                          The Wiser Oil Company
 
                                                 /s/ Andrew J. Shoup, Jr.
                                          By: _________________________________
                                            ANDREW J. SHOUP, JR. PRESIDENT AND
                                                  CHIEF EXECUTIVE OFFICER
 
  PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS
REPORT IS SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE REGISTRANT
AND IN THE CAPACITIES AND ON THE DATES INDICATED. THE SIGNATURES BELOW ARE FOR
THE FORM 10-K ANNUAL REPORT FOR CALENDAR YEAR 1994.
 
              SIGNATURE                        TITLE                 DATE
 
      /s/ Andrew J. Shoup, Jr.         President, Chief         March 26, 1997
-------------------------------------   Executive Officer
                                        and Director
                                        (Principal
                                        Executive Officer)
 
     /s/ Paul D. Neuenschwander        Director                 March 26, 1997
-------------------------------------
 
     /s/ C. Frayer Kimball, III        Director                 March 26, 1997
-------------------------------------
 
       /s/ Howard G. Hamilton          Director                 March 26, 1997
-------------------------------------
 
       /s/ A. W. Schenck, III          Director                 March 26, 1997
-------------------------------------
 
      /s/ John W. Cushing, III         Director                 March 26, 1997
-------------------------------------
 
        /s/ Jon L. Mosle, Jr.          Director                 March 26, 1997
-------------------------------------
 
         /s/ Lorne H. Larson           Director                 March 26, 1997
-------------------------------------
 
        /s/ Lawrence J. Finn           Vice President and       March 26, 1997
-------------------------------------   Chief Financial
                                        Officer (Principal
                                        Financial and
                                        Accounting Officer)
 
                                      41
<PAGE>
 
                             THE WISER OIL COMPANY
 
                   INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
 
<TABLE>
<CAPTION>
                                                                            PAGE
                                                                            ----
<S>                                                                         <C>
Report of Independent Public Accountants................................... F-2
Consolidated Statements of Income and Retained Earnings.................... F-3
Consolidated Balance Sheets................................................ F-4
Consolidated Statements of Cash Flows...................................... F-5
Notes to Consolidated Financial Statements................................. F-6
</TABLE>
 
                                      F-1
<PAGE>
 
                   REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
 
To the Shareholders of The Wiser Oil Company:
 
  We have audited the accompanying consolidated balance sheets of The Wiser
Oil Company (a Delaware corporation) and subsidiaries as of December 31, 1996,
1995 and 1994 and the related consolidated statements of income and retained
earnings and cash flows for the years then ended. 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, 1996, 1995 and 1994 and the
results of their operations and their cash flows in conformity with generally
accepted accounting principles.
 
  As discussed in Note 1 to the consolidated financial statements, during
1995, the Company changed its method of accounting for the impairment of long-
lived assets.
 
                                          ARTHUR ANDERSEN LLP
 
Dallas, Texas,
February 18, 1997
 
                                      F-2
<PAGE>
 
                             THE WISER OIL COMPANY
 
            CONSOLIDATED STATEMENTS OF INCOME AND RETAINED EARNINGS
              FOR THE YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994
 
<TABLE>
<CAPTION>
                                                  1996       1995       1994
                                                ---------  ---------  ---------
                                                (000'S EXCEPT PER SHARE DATA)
<S>                                             <C>        <C>        <C>
Revenues:
  Oil and gas sales............................   $72,012    $54,400    $53,559
  Dividends and interest.......................       683      1,241      1,641
  Marketable security sales gains..............    12,977     13,101      7,475
  Other........................................     1,017      2,939      2,681
                                                ---------  ---------  ---------
                                                   86,689     71,681     65,356
                                                ---------  ---------  ---------
Costs and Expenses:
  Production and operating.....................    23,970     20,690     22,313
  Purchased natural gas........................     1,462        727        759
  Depreciation, depletion and amortization.....    19,653     19,778     18,313
  Property impairments.........................    12,112      4,893        --
  Exploration..................................     4,176      5,801      4,130
  General and administrative...................     9,364      8,193      6,502
  Interest expense.............................     5,452      5,618      3,907
                                                ---------  ---------  ---------
                                                   76,189     65,700     55,924
                                                ---------  ---------  ---------
Income Before Income Taxes.....................    10,500      5,981      9,432
Income Tax Expense.............................     4,072      3,788        444
                                                ---------  ---------  ---------
NET INCOME.....................................     6,428      2,193      8,988
Retained Earnings, beginning of year...........    61,030     62,414     57,002
Dividends Paid.................................    (1,073)    (3,577)    (3,576)
                                                ---------  ---------  ---------
Retained Earnings, end of year................. $  66,385  $  61,030  $  62,414
                                                =========  =========  =========
Average Outstanding Shares.....................     8,954      8,939      8,941
                                                =========  =========  =========
Earnings Per Share............................. $     .72  $     .25  $    1.01
                                                =========  =========  =========
Cash Dividends Per Share....................... $     .12  $     .40  $     .40
                                                =========  =========  =========
</TABLE>
 
 
   The accompanying notes are an integral part of these financial statements.
 
                                      F-3
<PAGE>
 
                             THE WISER OIL COMPANY
 
                          CONSOLIDATED BALANCE SHEETS
                        DECEMBER 31, 1996, 1995 AND 1994
 
<TABLE>
<CAPTION>
                                                  1996       1995       1994
                                                ---------  ---------  --------
                                                          (000'S)
<S>                                             <C>        <C>        <C>
ASSETS
Current Assets:
  Cash and cash equivalents.................... $   5,870  $   1,397  $  2,714
  Accounts receivable..........................    14,091     10,426    10,900
  Inventories..................................     1,289      1,517     1,144
  Prepaid expenses.............................       473        833       852
                                                ---------  ---------  --------
    Total current assets.......................    21,723     14,173    15,610
                                                ---------  ---------  --------
Marketable Securities..........................     7,176     19,592    27,337
Property, Plant and Equipment, at cost:
  Oil and gas properties (successful efforts
   method).....................................   306,716    265,692   250,156
  Other properties.............................     4,974      4,422     5,443
                                                ---------  ---------  --------
                                                  311,690    270,114   255,599
  Accumulated depreciation and depletion.......  (131,972)  (101,025)  (88,228)
                                                ---------  ---------  --------
Net Property, Plant and Equipment..............   179,718    169,089   167,371
Other Assets...................................       --         553       473
                                                ---------  ---------  --------
                                                $ 208,617  $ 203,407  $210,791
                                                =========  =========  ========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
  Accounts payable............................. $  14,996  $  10,143  $  9,562
  Accrued income taxes.........................     1,697      1,527     1,518
  Accrued liabilities..........................     1,537      1,449     2,139
  Current portion of long term debt............       --          20        78
                                                ---------  ---------  --------
    Total current liabilities..................    18,230     13,139    13,297
                                                ---------  ---------  --------
Long Term Debt.................................    78,654     74,171    78,013
Deferred Benefit Cost..........................     1,496      1,120     1,052
Deferred Income Taxes..........................    10,975     12,699    13,002
Other Long Term Liabilities....................       --       1,146       --
Stockholders' Equity:
  Common stock--$3 par value 20,000,000 shares
   authorized; 9,115,572 shares issued;
   8,939,368 shares outstanding................    27,347     27,347    27,347
  Paid-in capital..............................     3,078      3,078     3,078
  Retained earnings............................    66,385     61,030    62,414
  Marketable securities valuation adjustment...     4,328     11,684    16,013
  Foreign currency translation.................       853        722      (696)
  Treasury stock; 176,204 shares, at cost at
   December 31, 1996, 1995 and 1994............    (2,729)    (2,729)   (2,729)
                                                ---------  ---------  --------
    Total stockholders' equity.................    99,262    101,132   105,427
                                                ---------  ---------  --------
                                                $ 208,617  $ 203,407  $210,791
                                                =========  =========  ========
</TABLE>
 
   The accompanying notes are an integral part of these financial statements.
 
                                      F-4
<PAGE>
 
                             THE WISER OIL COMPANY
 
                     CONSOLIDATED STATEMENTS OF CASH FLOWS
              FOR THE YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994
 
<TABLE>
<CAPTION>
                                                    1996      1995      1994
                                                  --------  --------  --------
                                                           (000'S)
<S>                                               <C>       <C>       <C>
Cash Flows From Operating Activities:
Net income......................................  $  6,428  $  2,193  $  8,988
Adjustments to reconcile net income to operating
 cash flows:
  Depreciation, depletion and amortization......    19,653    19,778    18,313
  Deferred income taxes.........................     2,056     1,914    (1,145)
  Marketable securities & property sale gains...   (13,099)  (14,092)   (9,367)
  Foreign currency translation..................        (2)      (34)       87
  Property impairments and abandonments.........    15,229     9,392     2,930
  Other Changes--
    Accounts receivable.........................    (3,665)      474    (1,473)
    Inventories.................................       228      (373)     (344)
    Prepaid expenses............................       360        19      (204)
    Other assets................................       553       (80)       11
    Accounts payable............................     4,853       661     3,438
    Accrued income taxes........................       170         9     1,516
    Accrued liabilities.........................        88      (690)      424
    Deferred benefits cost......................       376        68       (40)
                                                  --------  --------  --------
      Operating Cash Flows......................    33,228    19,239    23,134
                                                  --------  --------  --------
Cash Flows From Investing Activities:
  Additions to property, plant and equipment....   (46,056)  (28,851)  (73,410)
  Proceeds from sales of property, plant and
   equipment....................................     1,022     1,280    13,581
  Proceeds from marketable security sales.......    14,035    14,492     8,250
                                                  --------  --------  --------
    Investing Cash Flows........................   (30,999)  (13,079)  (51,579)
                                                  --------  --------  --------
Cash Flows From Financing Activities:
  Long term debt issued.........................    25,508    11,170    55,600
  Payments on long term debt and other liabili-
   ties.........................................   (22,191)  (15,070)  (24,364)
  Dividends paid................................    (1,073)   (3,577)   (3,576)
                                                  --------  --------  --------
    Financing Cash Flows........................     2,244    (7,477)   27,660
                                                  --------  --------  --------
Net Increase (Decrease) In Cash.................     4,473    (1,317)     (785)
Cash and Cash Equivalents, beginning of year....     1,397     2,714     3,499
                                                  --------  --------  --------
Cash and Cash Equivalents, end of year..........  $  5,870  $  1,397  $  2,714
                                                  ========  ========  ========
</TABLE>
 
 
   The accompanying notes are an integral part of these financial statements.
 
                                      F-5
<PAGE>
 
                             THE WISER OIL COMPANY
 
                  NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 
                       DECEMBER 31, 1996, 1995 AND 1994
 
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 and is 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. 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 an
exploratory 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, 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 No. 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 1996 and 1995, the Company provided impairments of
$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
<PAGE>
 
                             THE WISER OIL COMPANY
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
                       DECEMBER 31, 1996, 1995 AND 1994
 
 
  d. Depreciation and Depletion--Depreciation and depletion 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 $3,801,000 in 1996, $504,000 in 1995 and
$1,662,000 in 1994 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 $576,000 in 1996, $535,000 in 1995 and $519,000 in 1994.
 
  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, 1996,
1995 and 1994.
 
  j. Hedging Arrangements--During 1995 and 1996, the Company entered into
numerous oil price collar agreements to hedge against price fluctuations
during 1997. The Company is exposed to losses in the event of nonperformance
by the counter parties to its hedging agreements.
 
  These arrangements are summarized as follows:
 
<TABLE>
<CAPTION>
                                    DAILY VOLUME FLOOR PRICE  CEILING PRICE
BEGINNING DATES  ENDING DATE           (BBLS)     (PER BBL)     (PER BBL)
---------------  -----------        ------------ -----------  -------------
<S>              <C>                <C>          <C>          <C>
January 1, 1997  December 31, 1997     1,000       $16.00        $18.85
January 1, 1997  December 31, 1997     1,000        21.80(1)      25.55(1)
January 1, 1997  March 31, 1997        2,000        16.00         19.41
April 1, 1997    June 30, 1997         2,000        17.00         19.00
July 1, 1997     September 30, 1997    2,000        17.00         19.00
</TABLE>
--------
(1)Canadian Dollars
 
  In addition, the Company has hedged 367 barrels per day of natural gas
liquids production from January 1, 1997 to March 31, 1997 at a weighted
average price of $18.76 per barrel. 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, 1994, the Company had deferred $135,017 in net
gains related to hedging activities. As of December 31, 1996 and 1995, the
Company had no deferred net gains or net losses related to hedging activities.
During 1996, revenues from oil and gas
 
                                      F-7
<PAGE>
 
                             THE WISER OIL COMPANY
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
                       DECEMBER 31, 1996, 1995 AND 1994
 
production were reduced $6,923,000 as a result of hedging activities. The
Company did not incur any material hedging gains or losses in 1995 or 1994.
 
  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 $853,000 for 1996, $722,000 for 1995 and a loss of $696,000 for 1994
classified in Stockholders' Equity.
 
2. MARKETABLE SECURITIES
 
  During 1993, the Company adopted 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, 1995 and 1994 were $7,176,000, $19,592,000 and $27,337,000 respectively.
 
  The Company liquidated a portion of its marketable securities portfolio and
recognized a pretax gain of $12,977,000, $13,101,000 and $7,475,000 for 1996,
1995 and 1994 respectively.
 
3. LONG TERM DEBT
 
  On June 23, 1994, the Company entered into a Credit Agreement with
NationsBank of Texas, N. A. as agent, which provides for a term loan to the
Company's Canadian subsidiary and a revolving credit facility to the Company.
The Credit Agreement provides the Company with up to a $150 million line of
credit through September 30, 2000. The amounts available for borrowing are
determined under formulas related to oil and gas reserves. The Company's
borrowing base at December 31, 1996 was $80,000,000. The indebtedness
outstanding under the Credit Agreement is secured by a pledge of 66% of the
Company's ownership interests in its Canadian subsidiary (Wiser Canada).
Available loan and interest options are base rate loans, at the bank's prime
interest rate and one to six month term loans with fixed interest at either
the LIBOR or CD rate plus 0.625%. The average interest rate during 1996 under
the Credit Agreement was 6.04%. A 0.25% commitment fee is paid on the unused
borrowing base. The Credit Agreement requires the Company to, among other
things, maintain certain minimum net worth and current ratio requirements as
well as certain restrictions on sales of assets, payment of dividends,
incurrence of indebtedness and hedged transactions.
 
  On November 29, 1995, the Company entered into a credit agreement with
NationsBank of Texas, N.A. as agent (the "Maljamar Credit Facility"). The
Maljamar Credit Facility provides the Company with up to a $50 million
nonrecourse facility to develop the expanded Maljamar project area. The
amounts available for borrowing are determined under formulas related to oil
and gas reserves and capital spent on the Maljamar area properties offset by
net operating income from these same properties. The Company's borrowing base
at December 31, 1996 was $40,000,000. Available loan and interest options are
base rate loans, at the bank's prime interest rate and one to six month term
loans with fixed interest at LIBOR plus 2.0%. The average interest rate during
1996 under the Maljamar Credit Facility was 7.51%. A 0.375% commitment fee is
paid on the unused borrowing base. The Maljamar Credit Facility requires the
Company to, among other things, maintain certain minimum collateral value
requirements as well as certain restrictions on sales of assets, payment of
dividends and incurrence of indebtedness. In addition, the credit agreement
also requires the Company to hedge a portion of its crude oil production.
 
  The Company paid $4,971,000 in interest during 1996, $5,618,000 during 1995,
and $3,889,000 during 1994.
 
                                      F-8
<PAGE>
 
                             THE WISER OIL COMPANY
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
                       DECEMBER 31, 1996, 1995 AND 1994
 
 
  Long term debt consists of the following (000's):
 
<TABLE>
<CAPTION>
                                                           DECEMBER 31,
                                                      ------------------------
                                                       1996    1995     1994
                                                      ------- -------  -------
<S>                                                   <C>     <C>      <C>
Maljamar Credit Facility--7.63% and 7.94% interest
 rate at December 31, 1996 and 1995, respectively.... $20,654 $ 1,171  $   --
Credit Agreement--6.31%, 6.38% and 6.56% interest
 rate at December 31, 1996, 1995 and 1994,
 respectively .......................................  58,000  73,000   78,000
Other, at 11.00%.....................................     --       20       91
                                                      ------- -------  -------
                                                       78,654  74,191   78,091
Less current maturities..............................     --      (20)     (78)
                                                      ------- -------  -------
                                                      $78,654 $74,171  $78,013
                                                      ======= =======  =======
</TABLE>
 
  The annual requirements for reduction of principal of long term debt
outstanding as of December 31, 1996 are estimated as follows (000's):
 
<TABLE>
           <S>                                        <C>
           1997...................................... $   --
           1998......................................  20,654
           1999......................................   7,998
           2000......................................  10,664
           Thereafter................................  39,338
                                                      -------
                                                      $78,654
                                                      =======
</TABLE>
 
4. PROPERTY ACQUISITIONS AND SALES
 
  During 1995, the Company traded some of its Permian Basin properties for
properties located mainly in New Mexico (The Skelly Unit) and West Virginia.
The acquisition of these properties was accounted for as an exchange of
similar assets. As a result of these trades, Wiser's total proved reserves as
of December 31, 1995 increased by 5,846,000 BOE.
 
  On June 24, 1994, the Company acquired the Eagle Properties, which consist
of certain oil and gas properties located in Alberta, Canada, for $52 million
dollars. The purchase was funded through the Company's Credit Agreement, see
Note 3, and with existing cash and cash equivalents. The purchase method of
accounting was followed.
 
  Unaudited pro forma results of operations, as if the 1994 acquisition of the
Eagle properties took place at January 1, 1994, are as follows (000's):
 
<TABLE>
<CAPTION>
                                                      1994(1)
                                                      -------
           <S>                                        <C>
           Revenues.................................. $63,888
           Expenses..................................  57,341
                                                      -------
           Net Income................................ $ 6,547
                                                      =======
           Earnings per share........................ $   .73
                                                      =======
</TABLE>
--------
(1) The pro forma results exclude the gain of $1.9 million of property sales
    recognized in 1994.
 
                                      F-9
<PAGE>
 
                             THE WISER OIL COMPANY
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
                       DECEMBER 31, 1996, 1995 AND 1994
 
 
5. INCOME TAXES
 
  The Company provides deferred income taxes for differences between the tax
reporting basis and the financial reporting basis of assets and liabilities.
The Company follows the accounting procedures as established by SFAS No. 109,
"Accounting for Income Taxes". The Company paid $900,000 in 1996, $1,967,000
in 1995 and $0 income taxes in 1994.
 
  Income tax expense (benefit) for the three years ended December 31, 1996
were as follows (000's):
 
<TABLE>
<CAPTION>
                                                           1996   1995   1994
                                                          ------ ------ -------
   <S>                                                    <C>    <C>    <C>
   Current:
     Federal............................................. $1,911 $1,607 $ 1,473
     State...............................................    105    150     116
                                                          ------ ------ -------
                                                           2,016  1,757   1,589
                                                          ------ ------ -------
   Deferred:
     Federal.............................................  1,919  1,934   1,085
     State...............................................    137     97     107
     Reversal of valuation allowance.....................    --     --   (2,337)
                                                          ------ ------ -------
                                                           2,056  2,031  (1,145)
                                                          ------ ------ -------
   Total income tax expense.............................. $4,072 $3,788 $   444
                                                          ====== ====== =======
</TABLE>
 
  A reconciliation of the statutory federal income tax rate to the Company's
effective tax rate follows:
 
<TABLE>
<CAPTION>
                                                            1996   1995   1994
                                                            -----  -----  -----
   <S>                                                      <C>    <C>    <C>
   Statutory federal income tax rate.......................  34.0%  34.0%  34.0%
   Statutory depletion in excess of cost basis.............  (2.0)  (1.7)  (2.2)
   Non-deductibility of foreign operating loss.............  22.6   55.4    8.6
   Reversal of tax credit valuation allowance..............   --     --   (24.8)
   State taxes net of FIT benefits.........................   1.5    1.6    2.0
   Dividends received credit...............................  (1.2)  (4.4)  (3.8)
   Nonconventional fuels credit............................ (14.6) (22.4) (14.1)
   Other, net..............................................  (1.5)   0.8    5.0
                                                            -----  -----  -----
   Effective tax rate......................................  38.8%  63.3%   4.7%
                                                            =====  =====  =====
</TABLE>
 
                                     F-10
<PAGE>
 
                             THE WISER OIL COMPANY
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
                       DECEMBER 31, 1996, 1995 AND 1994
 
 
  The deferred tax liabilities and assets for the three years ended December
31, 1996 were as follows (000's):
 
<TABLE>
<CAPTION>
                                                       1996     1995     1994
                                                      -------  -------  -------
<S>                                                   <C>      <C>      <C>
Deferred tax liabilities (assets):
Intangible drilling and development cost............. $12,998  $ 9,203  $ 7,052
Marketable securities valuation adjustment...........   2,229    6,015    8,241
Deferred pensions and compensation...................    (579)    (527)    (520)
Alternative minimum tax credit carry forwards........  (2,318)  (2,429)  (2,010)
Property impairment reserve..........................  (1,767)    (277)     --
Excess property basis on Wiser Canada................  (4,051)  (3,930)  (3,978)
Valuation allowance..................................   4,600    4,479    3,978
Other................................................    (137)     165      239
                                                      -------  -------  -------
                                                      $10,975  $12,699  $13,002
                                                      =======  =======  =======
</TABLE>
 
  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. Prior to 1994, a valuation allowance was
provided due to uncertainty of realizing these tax credits. Due to the
Company's sale of a portion of its marketable securities portfolio during
1996, 1995 and 1994, and the Company's plans relating to its remaining
marketable securities, the Company believes it is more likely than not that
the alternative minimum tax credits will be fully realized. Accordingly,
during 1994 the valuation allowance was reversed. As of December 31, 1996, a
valuation allowance has been provided against Canadian net deferred tax assets
of $4,051,000 and United States deferred tax assets of $549,000.
 
6. OIL AND GAS PRODUCING ACTIVITIES
 
  Set forth below is certain information regarding the aggregate capitalized
costs of oil and gas properties and costs incurred in oil and gas property
acquisitions, exploration and development activities (000's):
 
<TABLE>
<CAPTION>
                                                 U.S.      CANADA     TOTAL
                                               ---------  --------  ---------
<S>                                            <C>        <C>       <C>
DECEMBER 31, 1996:
Capitalization Costs:
 Proved properties............................ $ 226,411  $ 62,937  $ 289,348
 Unproved properties..........................     9,659     7,709     17,368
                                               ---------  --------  ---------
                                                 236,070    70,646    306,716
Accumulated depreciation, depletion and
 amortization.................................  (100,016)  (29,094)  (129,110)
                                               ---------  --------  ---------
Net capitalized costs......................... $ 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
</TABLE>
 
                                     F-11
<PAGE>
 
                             THE WISER OIL COMPANY
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
                       DECEMBER 31, 1996, 1995 AND 1994
 
<TABLE>
<CAPTION>
                                                   U.S.     CANADA    TOTAL
                                                 --------  --------  --------
<S>                                              <C>       <C>       <C>
DECEMBER 31, 1995:
Capitalization Costs:
 Proved properties.............................. $191,567  $ 56,427  $247,994
 Unproved properties............................   10,110     7,588    17,698
                                                 --------  --------  --------
                                                  201,677    64,015   265,692
Accumulated depreciation, depletion and
 amortization...................................  (81,561)  (16,766)  (98,327)
                                                 --------  --------  --------
Net capitalized costs........................... $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
DECEMBER 31, 1994:
Capitalization Costs:
 Proved properties.............................. $183,978  $ 47,629  $231,607
 Unproved properties............................   11,427     7,122    18,549
                                                 --------  --------  --------
                                                  195,405    54,751   250,156
Accumulated depreciation, depletion and
 amortization...................................  (80,189)   (3,555)  (83,744)
                                                 --------  --------  --------
Net capitalized costs........................... $115,216  $ 51,196  $166,412
                                                 ========  ========  ========
Costs Incurred during 1994:
 Property acquisition........................... $  2,544  $ 52,988  $ 55,532
 Exploration....................................    2,036     2,057     4,093
 Development....................................   11,059     1,727    12,786
 Gas plants.....................................      775       --        775
</TABLE>
 
7. EMPLOYEE PENSION PLAN
 
  The Company has a noncontributory defined benefit pension plan, which covers
substantially all full-time employees. Plan participants become fully vested
after five years of continuous service. The retirement benefit formula is
based on the employee's earnings, length of service and age at retirement.
Contributions required to fund plan benefits are determined according to the
Projected Unit Credit Method. The assets of the plan are primarily invested in
equity and debt securities.
 
  The net periodic pension costs were determined as follows (000's):
 
<TABLE>
<CAPTION>
                                                         1996     1995    1994
                                                        -------  -------  -----
<S>                                                     <C>      <C>      <C>
Current service cost................................... $   381  $   368  $ 362
Interest cost on projected benefit obligation..........     824      802    779
Actual return on assets................................   1,890   (1,575)   (37)
Net amortization and deferral..........................  (2,652)     932   (648)
                                                        -------  -------  -----
Net periodic pension cost.............................. $   443  $   527  $ 456
                                                        =======  =======  =====
</TABLE>
 
                                     F-12
<PAGE>
 
                             THE WISER OIL COMPANY
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
                       DECEMBER 31, 1996, 1995 AND 1994
 
 
  The principal assumptions for 1996, 1995 and 1994 utilized in computing
pension expense include an 8.0% discount rate and a 5.0% rate of increase in
compensation levels. The assumed rate of return on plan assets was 9% for 1996
and 8.5% for 1995 and 1994. An 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):
 
<TABLE>
<CAPTION>
                                                      1996    1995     1994
                                                     ------  -------  -------
<S>                                                  <C>     <C>      <C>
Actuarial present value of pension benefits obliga-
 tions:
 Vested............................................. $8,155  $ 9,817  $ 9,369
 Nonvested..........................................    415      354      172
                                                     ------  -------  -------
 Accumulated........................................  8,570   10,171    9,541
 Projected salary increases.........................    751      705    1,069
                                                     ------  -------  -------
 Projected benefits obligations.....................  9,321   10,876   10,610
 Plan assets at fair value..........................  8,010   10,247    9,315
                                                     ------  -------  -------
 Plan assets less than projected benefits
  obligations....................................... $1,311  $   629  $ 1,295
                                                     ======  =======  =======
Items not yet recognized:
 Unrecognized net gain.............................. $  473  $ 1,169  $   490
 Unamortized transition amount......................    121      208      241
 Unamortized prior service cost.....................   (957)  (1,106)  (1,254)
                                                     ------  -------  -------
 Net pension liability.............................. $  948  $   900  $   772
                                                     ======  =======  =======
</TABLE>
 
8. EMPLOYEE SAVINGS PLAN
 
  The Company has a qualified Savings Plan available to all employees. An
employee may elect to have up to 15% of the employee's base monthly
compensation, exclusive of other forms of special or extra compensation,
withheld and placed in the Savings Plan account. On a monthly basis, the
Company contributes to this account an amount equal to 50% of the employee's
contribution, limited to 3% of the employee's base compensation. Company
contributions to the Savings Plan were $126,000, $122,000 and $116,000, in
1996, 1995 and 1994, respectively.
 
                                     F-13
<PAGE>
 
                             THE WISER OIL COMPANY
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
                       DECEMBER 31, 1996, 1995 AND 1994
 
 
9. 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 activity of the Company by geographic
area for 1996, 1995 and 1994.
 
<TABLE>
<CAPTION>
                                                      U.S.    CANADA    TOTAL
                                                    -------- --------  --------
<S>                                                 <C>      <C>       <C>
YEAR ENDED DECEMBER 31, 1996:
Total revenues..................................... $ 69,595 $ 17,094  $ 86,689
Cost and expenses:
 Production and operating..........................   20,288    3,682    23,970
 Purchased natural gas.............................    1,462      --      1,462
 Exploration.......................................    1,837    2,339     4,176
 Depreciation, depletion and amortization..........   11,783    7,870    19,653
 Property impairments..............................    7,276    4,836    12,112
 Other operating ..................................    9,475    5,341    14,816
                                                    -------- --------  --------
                                                      52,121   24,068    76,189
                                                    -------- --------  --------
Pretax income (loss)...............................   17,474   (6,974)   10,500
Income tax expense.................................    4,072      --      4,072
                                                    -------- --------  --------
Results of operations.............................. $ 13,402 $ (6,974) $  6,428
                                                    ======== ========  ========
Identifiable assets................................ $161,687 $ 46,930  $208,617
                                                    ======== ========  ========
YEAR ENDED DECEMBER 31, 1995:
Total revenues..................................... $ 57,839 $ 13,842  $ 71,681
Cost and expenses:
 Production and operating..........................   17,555    3,135    20,690
 Purchased natural gas.............................      727      --        727
 Abandonments......................................    4,173    1,628     5,801
 Exploration.......................................   11,418    8,360    19,778
 Depreciation, depletion and amortization..........      --     4,893     4,893
 Other operating...................................    8,250    5,561    13,811
                                                    -------- --------  --------
                                                      42,123   23,577    65,700
                                                    -------- --------  --------
Pretax income (loss)...............................   15,716   (9,735)    5,981
Income tax expense.................................    3,788      --      3,788
                                                    -------- --------  --------
Results of operations.............................. $ 11,928 $ (9,735) $  2,193
                                                    ======== ========  ========
Identifiable assets................................ $152,710  $50,034  $202,744
                                                    ======== ========  ========
</TABLE>
 
                                     F-14
<PAGE>
 
                             THE WISER OIL COMPANY
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
                       DECEMBER 31, 1996, 1995 AND 1994
 
<TABLE>
<CAPTION>
                                                       U.S.   CANADA    TOTAL
                                                     -------- -------  --------
<S>                                                  <C>      <C>      <C>
YEAR ENDED DECEMBER 31, 1994:
Total revenues...................................... $ 58,586 $ 6,770  $ 65,356
Cost and expenses:
 Production and operating...........................   20,598   1,715    22,313
 Purchased natural gas..............................      759     --        759
 Exploration........................................    2,757   1,373     4,130
 Depreciation, depletion and amortization...........   14,737   3,576    18,313
 Other operating ...................................    7,921   2,488    10,409
                                                     -------- -------  --------
                                                       46,772   9,152    55,924
                                                     -------- -------  --------
Pretax income (loss)................................   11,814  (2,382)    9,432
Income tax expense..................................      444     --        444
                                                     -------- -------  --------
Results of operations............................... $ 11,370 $(2,382) $  8,988
                                                     ======== =======  ========
Identifiable assets................................. $157,498 $54,075  $211,573
                                                     ======== =======  ========
</TABLE>
 
  Annually, four or five of the Company's purchasers of oil and natural gas
individually account for 10% to 35% of gross revenues. In Canada, one
purchaser accounts for approximately 75% of Wiser Canada's sales. However, due
to the nature of the oil and natural gas industry, the Company is not
dependent upon any of these purchasers. The loss of any major purchaser would
not have a material adverse impact on the Company's business.
 
10. STOCK OPTION PLANS
 
  SFAS No. 123, "Accounting for Stock-Based Compensation," encourages but does
not require companies to record compensation cost for stock-based employee
compensation plans at fair value. During 1996, the Company adopted the
disclosure provisions of SFAS No. 123. The Company continues to apply the
accounting provisions of APB Opinion 25, "Accounting for Stock Issued to
Employees," and related interpretations to account for stock-based
compensation. Accordingly, compensation cost for stock options is measured as
the excess, if any, of the quoted market price of the Company's stock at the
date of the grant over the amount an employee must pay to acquire the stock.
 
  The Company has two stock option plans, the 1991 Stock Incentive Plan ("1991
Incentive Plan") and the 1991 Non-Employee Directors' Stock Option Plan ("1991
Directors' Plan"). The 1991 Incentive Plan provides for the issuance of ten
year options with a variable vesting period and a grant price equal to fair
market value. The 1991 Directors' Plan provides for the issuance of five year
options with a six month vesting period and a grant price equal to or above
market value.
 
 
                                     F-15
<PAGE>
 
                             THE WISER OIL COMPANY
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
                       DECEMBER 31, 1996, 1995 AND 1994
 
 
  A summary of the status of the Company's two stock option plans at December
31, 1996, 1995 and 1994 and changes during the years then ended follows:
 
<TABLE>
<CAPTION>
                                1996               1995               1994
                          ------------------ ------------------ ----------------
                                    EXERCISE           EXERCISE         EXERCISE
                           SHARES   PRICE(1)  SHARES   PRICE(1) SHARES  PRICE(1)
                          --------  -------- --------  -------- ------- --------
<S>                       <C>       <C>      <C>       <C>      <C>     <C>
Outstanding at beginning
 of year................   254,500   $16.88   253,500   $17.20   95,750  $15.95
Granted.................   647,250    14.35    16,000    13.81  157,750   17.36
Exercised...............       --       --        --       --       --      --
Expired and cancelled...   (22,250)   16.88   (15,000)   17.36      --      --
                          --------   ------  --------   ------  -------  ------
Outstanding at end of
 year...................   879,500   $15.02   254,500   $16.88  253,500  $17.20
                          ========   ======  ========   ======  =======  ======
Exercisable at end of
 year...................   145,650   $16.47    56,725   $16.59   60,000  $16.70
                          ========   ======  ========   ======  =======  ======
Fair value of options
 granted(1).............  $   4.30           $   4.08
                          ========           ========
</TABLE>
--------
(1) Weighted average per option granted.
 
  657,500 of the 879,500 options outstanding at December 31, 1996 have
exercise prices between $11 and $15, with a weighted average exercise price of
$14.35 and a weighted average remaining contractual life of 9.6 years. 14,500
of these options are exercisable with a weighted average exercise price of
$13.70. The remaining 222,000 options have exercise prices betwen $15 and $19,
with a weighted average exercise price of $17.02 and a weighted average
contractual life of 6.6 years. 131,150 of these options are exercisable with a
weighted average exercise price of $16.78.
 
  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 in 1996 and 1995 for both the 1991 Incentive Plan
and the 1991 Directors' Plan:
 
<TABLE>
<CAPTION>
                                                                   1996   1995
                                                                   -----  -----
       <S>                                                         <C>    <C>
       Risk free interest rate....................................  6.36%  6.01%
       Expected dividend yields...................................   .84%   .87%
       Expected lives, in years...................................  4.85   5.00
       Expected volatility........................................ 22.22% 22.05%
</TABLE>
 
  Had compensation cost been determined consistent with SFAS No. 123, the
Company's net income and earnings per share would have been reduced to the
following pro forma amounts:
 
<TABLE>
<CAPTION>
                                                                   1996   1995
                                                                  ------ ------
       <S>                                                        <C>    <C>
       Net income--as reported (000's)........................... $6,428 $2,193
       Net income--pro forma (000's).............................  5,576  2,179
       Earnings per share--as reported........................... $  .72 $  .25
       Earnings per share--pro forma.............................    .62    .24
</TABLE>
 
  Because the SFAS No. 123 method of accounting has not been applied to
options granted prior to January 1, 1995, the resulting pro forma compensation
cost may not be representative of that to be expected in future years.
 
11. PREFERRED STOCK
 
  In addition to Common Stock, the Company is authorized to issue 300,000
shares of Preferred Stock with a par value of $10 per share, none of which has
been issued.
 
                                     F-16
<PAGE>
 
                             THE WISER OIL COMPANY
                      SUPPLEMENTAL FINANCIAL INFORMATION
       FOR THE YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994 (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. OIL AND GAS RESERVES
 
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
<PAGE>
 
  Following is a reconciliation of the Company's estimated net quantities of
proved oil and gas reserves, as estimated by independent petroleum
consultants.
 
<TABLE>
<CAPTION>
                                    OIL (MBBLS)              GAS (MMCF)
                               ----------------------  ------------------------
                                U.S.   CANADA  TOTAL    U.S.    CANADA   TOTAL
                               ------  ------  ------  -------  ------  -------
<S>                            <C>     <C>     <C>     <C>      <C>     <C>
Balance December 31, 1993..... 21,242    --    21,242  103,317     --   103,317
  Revisions of previous
   estimates..................  1,801    --     1,801   (2,205)    --    (2,205)
  Properties sold and
   abandoned.................. (1,513)   --    (1,513)  (7,031)    --    (7,031)
  Reserves purchased in
   place......................     97  3,666    3,763      314  21,395   21,709
  Extensions, discoveries and
   other additions............    343     71      414    1,488   1,249    2,737
  Production.................. (1,957)  (320)  (2,277)  (9,335) (1,272) (10,607)
                               ------  -----   ------  -------  ------  -------
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
                               ======  =====   ======  =======  ======  =======
Proved Developed Reserves:
  Balance, December 31, 1993.. 17,112    --    17,112   96,069     --    96,069
  Balance, December 31, 1994
   (1)........................ 15,950  3,209   19,159   84,715  13,655   98,370
  Balance, December 31, 1995
   (1)........................ 17,939  3,617   21,556   77,915  24,111  102,026
  Balance, December 31, 1996
   (1)........................ 24,892  3,225   28,117   80,652  22,477  103,129
</TABLE>
--------
(1) Canadian reserve volumes as assigned by third party engineers have been
    increased to reflect the effect of the Alberta Royalty Tax Credit refund.
    Total proved and proved developed reserves were increased by 364 MBbl and
    2,323 MMcf for 1994, 397 MBbl and 2,744 MMcf for 1995 and 186 MBbl and
    1,258 MMcf for 1996.
 
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 SFAS No. 69, "Disclosure About
Oil and Gas Producing Activities". The estimates of future cash inflows and
future production and development costs 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 based on
current costs and economic conditions.
 
  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.
 
                                     F-18
<PAGE>
 
  The following are the Company's estimated standardized measure of discounted
future net cash flows from proved reserves (000's):
 
<TABLE>
<CAPTION>
                                                 U.S.      CANADA     TOTAL
                                              ----------  --------  ----------
<S>                                           <C>         <C>       <C>
December 31, 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 future
  net 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 future
  net cash flows............................. $  150,261  $ 44,341  $  194,602
                                              ==========  ========  ==========
December 31, 1994:
 Future cash flows........................... $  449,797  $ 79,208  $  529,005
 Future production and development costs.....   (234,189)  (22,040)   (256,229)
 Future income tax expense...................    (34,690)      --      (34,690)
                                              ----------  --------  ----------
 Future net cash flows.......................    180,918    57,168     238,086
 10% Annual discount for estimated timing of
  cash flows.................................    (77,178)  (18,876)    (96,054)
                                              ----------  --------  ----------
 Standardized measure of discounted future
  net cash flows............................. $  103,740  $ 38,292  $  142,032
                                              ==========  ========  ==========
 
  The following are the sources of changes in the standardized measure of
discounted net cash flows (000's):
 
<CAPTION>
                                                 1996       1995       1994
                                              ----------  --------  ----------
<S>                                           <C>         <C>       <C>
Standardized measure, beginning of year...... $  194,602  $142,032  $  112,423
Sales, net of production costs...............    (46,580)  (32,907)    (29,949)
Net change in price and production cost......    142,806    19,536       6,471
Reserves purchased in place..................        581    26,087      46,169
Extensions, discoveries and improved
 recoveries..................................     42,582     9,297       4,543
Change in future development cost............     27,080    12,652     (14,265)
Revision of previous quantity estimates and
 disposals...................................        314    26,525       5,080
Sales of reserves in place...................       (987)     (798)     (9,562)
Accretion of discount........................     23,542    16,081      13,715
Changes in timing and other..................    (10,440)   (1,863)      1,455
Net change in income taxes...................    (56,320)  (22,040)      5,952
                                              ----------  --------  ----------
Standardized measure, end of year............ $  317,180  $194,602  $  142,032
                                              ==========  ========  ==========
</TABLE>
 
                                     F-19
<PAGE>
 
13. QUARTERLY FINANCIAL DATA
 
  The supplementary financial data in the table below for each quarterly
period within the years ended December 31, 1996 and 1995 are derived from the
unaudited consolidated financial statements of the Company.
 
<TABLE>
<CAPTION>
                                                          NET
                                                        INCOME      EARNINGS
                                               REVENUES (LOSS)   (LOSS)PER SHARE
                                               -------- -------  ---------------
                                                (DOLLARS IN THOUSANDS, EXCEPT
                                                       PER SHARE DATA)
     <S>                                       <C>      <C>      <C>
     1996:
       First.................................. $18,567  $ 1,511       $ .17
       Second (1).............................  21,363   (5,368)       (.60)
       Third..................................  19,468    2,444         .27
       Fourth.................................  27,291    7,841         .88
     1995:
       First.................................. $16,247   $1,238       $ .14
       Second.................................  14,583     (720)       (.08)
       Third..................................  18,265    1,854         .21
       Fourth.................................  22,586     (179)       (.02)
</TABLE>
--------
(1) During the second quarter of 1996, the Company recognized an impairment
    write-down of oil and gas properties of $12,112,000 before income taxes.
 
                                     F-20
<PAGE>
 
                               INDEX TO EXHIBITS
<TABLE>
<CAPTION>
  EXHIBIT
  NUMBER
  -------
 <C>       <S>
  (3.1)    Certificate of Incorporation, 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).
 (10.1)    Credit Agreement dated June 23, 1994 among The Wiser Oil Company and
           The Wiser Oil Company of Canada, as Borrowers, and Nations Bank of
           Texas, N.A., as Agent, and Certain Financial Institutions Listed on
           the Signature Pages Thereto, as Banks, incorporated by reference to
           the Exhibit 10.1 to the report on Form 8-K dated July 11, 1994 as
           amended August 17, 1994.
 (10.2)    Credit Agreement dated November 29, 1995 among The Wiser Oil Company
           and Maljamar Development Partnership, L.P. as Borrowers, and Nations
           Bank of Texas, N.A., as Agent, and Certain 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 report on Form 8-K dated July 11,
           1994 as amended August 17, 1994.
 (10.4)*   Employment Agreement dated August 1, 1994 between the Company and
           Allen 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.
 (10.6)*   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.
 (10.7)*   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.
 (10.9)*   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.
 (10.10)*+ Employment Agreement dated September 30, 1996 between the Company
           and Kent E. Johnson.
 (10.11)*+ The Wiser Oil Company Equity Compensation Plan For Non-Employee
           Directors.
 (21)+     Subsidiaries of registrant
 (23.1)+   Consent of Independent Public Accountants
 (23.2)+   Consent of DeGolyer and MacNaughton, Independent Petroleum Engineers
 (23.3)+   Consent of Gilbert Lausten Jung Associates Ltd., Independent
           Petroleum Engineers
 (27)+     Financial Data Schedule
</TABLE>
--------
* The documents filed or incorporated by reference as Exhibits 10.4, 10.5,
  10.6, 10.7, 10.8 and 10.9, 10.10 and 10.11 represent management compensatory
  plans or agreements.
+ Filed herewith