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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, 2002

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:

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  þ.

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K  ¨.

Indicate by checkmark whether the registrant is an accelerated filer (as defined by Rule 12b-2 of the Securities Exchange Act of 1934, as amended). Yes  ¨  No  þ

The aggregate market value of registrant’s Common Stock held by non-affiliates based on the closing price on June 28, 2002 was approximately $33.2 million.

As of March 31, 2003, registrant had outstanding 9,473,929 shares of common stock, $.01 par value (“Common Stock”), which is registrant’s only class of common stock.

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 2003 Annual Meeting of Stockholders (the “Proxy Statement”) are incorporated by reference in Part III of this Report. The Proxy Statement will be filed with the Securities and Exchange Commission within 120 days of the close of the registrant’s fiscal year.

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The Wiser Oil Company

TABLE OF CONTENTS

DESCRIPTION

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THE WISER OIL COMPANY

PART I

Items 1 and 2. Business and Properties

General

The Wiser Oil Company (the “Company” or “Wiser”) is an independent oil and gas exploration and production company operating in Texas, New Mexico, the Gulf Coast and Western Canada. Historically, the Company’s growth has been attributed primarily to acquisition, development, exploitation and, to a lesser extent, exploration activities. The Company made significant acquisitions of proved properties in the Permian Basin between 1992 and 1996, and the Company began operating in Canada in 1994 with the acquisition of The Wiser Oil Company of Canada. The Company’s total proved reserves at December 31, 2002 are 34.9 MMBOE, with oil and NGL’s comprising 48% and natural gas comprising 52% of total reserves. Wiser’s proved reserves at December 31, 2002 were 82% developed with approximately 66% located in the U.S. and 34% located in Canada. Based on average realized prices of $25.10 per barrel of oil and $3.80 per Mcf of gas, the pre-tax present value of proved reserves at December 31, 2002 is $274.0 million discounted at 10%. Using SEC pricing guidelines, the pre-tax present value of the Company’s total proved reserves at December 31, 2002 is $323.1 million based on average realized prices of $29.12 per barrel for oil and $4.04 per Mcf for gas and discounted at 10%.

History

In 1905, Clinton B. Wiser pooled some oil leases and founded The Wiser Oil Company. The Company began operations in Kentucky in 1917 and maintained its headquarters in Sistersville, West Virginia, until 1991. The Company moved its headquarters to Dallas, Texas in 1991 and over the next five years Wiser expanded operations by acquiring and operating properties in the Permian Basin in West Texas and Southeast New Mexico and in Alberta, Canada. In 1999, the Company sold non-strategic properties in Appalachia and began focusing its exploration and production operations primarily in Texas, New Mexico, the Gulf Coast and Western Canada.

In May 2000, the Company completed a corporate restructuring and appointed George K. Hickox, Jr. as the new CEO. As part of the corporate restructuring, Wiser received a $23.7 million net capital infusion through the sale of convertible preferred stock in May 2000 and June 2001. In May 2001, Wiser acquired Invasion Energy, Inc. in northern Alberta for $37.5 million and the Company also expanded into the Gulf of Mexico in 2001 through joint venture agreements.

Strategy

Over the past three years, Wiser has increased the percentage of its natural gas reserves from 31% at December 31, 1999 to 52% at December 31, 2002. In addition, the percentage of reserves attributable to high-cost enhanced recovery projects in the Permian basin has decreased from 54% at December 31, 1999 to 30% at December 31, 2002. While the Company will continue to focus its efforts on adding reserves through acquisition of proved properties with exploitation potential, the Company will also place more emphasis on adding reserves through exploration activities in the future. Wiser expects to fund its future capital expenditure programs primarily with discretionary cash flow and any significant acquisition opportunities would be funded with borrowings under the Company’s credit facility.

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. The Internet address is http://www.wiseroil.com. You can review the filings the Company has made with the U.S. Securities and Exchange Commission (“SEC”), free of charge at the Internet address, where you can find our annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K and amendments of those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities and Exchange Act of 1934. The Company posts these reports as soon as reasonably practicable after electronically filing them with, or furnishing them to the SEC.

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Certain oil and gas industry terms used herein are defined in the “Glossary of Oil and Gas Terms” appearing at the end of this Items 1and 2.

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, 2002.

Permian Basin

Maljamar. The Company’s Maljamar properties are situated in Southeast New Mexico. At December 31, 2002, the Maljamar properties contained 9.9 MMBOE of proved reserves, which represented 28% of the Company’s total

proved reserves and 17% of the Company’s Present Value of total proved reserves.

The Maljamar properties consist primarily of three oil producing units acquired by the Company in separate transactions between 1992 and 1996: the Maljamar Grayburg and Caprock Maljamar Units, both of which are in Lea County, New Mexico, and the Skelly Unit in Eddy County, New Mexico. The Maljamar Grayburg Unit produces from the Grayburg and San Andres formations at depths ranging from 3,800 to 4,500 feet, and the Caprock Maljamar Unit produces from the same formations at depths ranging from 4,000 to 5,000 feet. The Skelly Unit is located approximately five miles west of the two Lea County units and produces from the Seven Rivers, Grayburg and San Andres formations at depths ranging from 2,100 to 4,000 feet. The Company has a 100% working interest in each of these units, which, along with some smaller adjacent properties, have been combined into a single large-scale waterflood project encompassing approximately 14,000 gross leasehold acres.

Exploitation efforts at the project are essentially complete and included conversion of existing wells to injection wells and the drilling of infill development wells on 20-acre spacing to create 40-acre five-spot water injection patterns. At December 31, 2002, the project included 242 producing wells and 223 water injection wells, virtually all of which were operated by the Company.

The Company’s net production from the Maljamar properties averaged 1,078 Bbls of oil and 474 Mcf of natural gas per day in 2002. The Company’s cumulative net production from the Maljamar properties since acquired by the Company has been 5,164 MBbls of oil and 2.5 Bcf of natural gas through December 31, 2002.

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Wellman Unit. In 1993 the Company acquired a 62% working interest in and became operator of the Wellman Unit in Terry County, Texas, located in the northwestern edge of the Horseshoe Atoll. During 1998 and 1999, the Company acquired an additional 28% and 5% working interest, respectively, in the Wellman Unit which increased the Company’s working interest to 95% as of December 31, 2002. At December 31, 2002, the Company’s Wellman property contained 0.8 MMBOE of proved reserves, which represented 2% of the Company’s total proved reserves and 2% of the Company’s Present Value of total proved reserves.

The Company owns 2,280 gross and net leasehold acres in the Wellman Unit. The Wellman Unit produces oil from the Wolfcamp Reef formation at depths ranging from 9,100 to 10,000 feet through the injection of water and CO2 into the reservoir. Water injection at the unit began in 1979, and CO2 injection began in 1983. The unit also includes a gas processing plant, which processes wellhead gas produced from the unit. Wiser’s interest in this plant is proportionate to its working interest in the Wellman Unit. Processing at the plant involves subjecting the wellhead gas to high pressure and low temperature treatments that cause the gas to separate into various products, including NGLs, residual natural gas and CO2. The NGLs and residual natural gas are sold to pipeline companies.

In 1995 the Company began reconditioning the gas processing plant at the Wellman Unit to enhance the extraction of NGLs and residual natural gas from the wellhead gas. The Company completed the reconditioning project in June 1995 at a total cost of approximately $6.0 million. For the year ended December 31, 2002, the gas plant processed an average of 28 MMcf of gross natural gas and CO2 per day and recovered an average of 207 Bbls of NGLs and 9 Mcf of residual natural gas per day. The plant currently operates at 88% of its maximum capacity of 32 MMcf of gas per day.

In 2001 the Company decided to discontinue injecting CO2 into the reservoir and entered into a contract to sell the previously injected CO2 to a third party. As a result of this decision, the oil and gas reserves at the Wellman Unit were reduced by 3.5 MMBOE and the Company estimates that the Wellman Unit reservoir contains approximately 40 Bcf of recoverable CO2. The Company anticipates that sales of CO2 will commence in the second quarter of 2003 at a rate of approximately 22.5 MMCF per day. Proceeds from the sale of CO2 will be recorded as a reduction of production and operating expense. At December 31, 2002, the unit included 32 productive wells, 2 water injection wells, 4 CO2 injection wells and 4 water disposal wells, all of which were operated by the Company.

The Company’s net production from the Wellman Unit averaged 445 Bbls of oil, 171 Bbls of NGLs and 4 Mcf of natural gas per day in 2002. The Company’s cumulative net production from the unit since acquired by the Company has been 2,613 MBbls of oil, 991 MBbls of NGLs and 551 MMcf of natural gas through December 31, 2002.

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, 2002, the Dimmitt/Slash Ranch properties contained 4.0 MMBOE of proved reserves, which represented 12% of the Company’s total proved reserves and 11% of the Company’s Present Value of total proved reserves.

The Company owns 6,154 gross (5,539 net) leasehold acres in the Dimmitt/Slash Ranch Field. 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. The Slash Ranch Field is a natural gas field that underlies the Dimmitt 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, 2002, the Dimmitt/Slash Ranch Field included 83 producing wells, all of which were operated by the Company. The Company’s average working interest in these wells is 97%.

The Company’s net production from the Dimmitt/Slash Ranch properties averaged 378 Bbls of oil and 2,745 Mcf of natural gas per day in 2002. The Company’s cumulative net production from the properties since acquired by the Company has been 1,178 MBbls of oil and 9.1 Bcf of natural gas through December 31, 2002.

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San Juan Basin

The Company’s San Juan Basin properties are located in Rio Arriba County in northwestern New Mexico. At December 31, 2002, the San Juan Basin properties contained 4.4 MMBOE of proved reserves, which represented 13% of the Company’s total proved reserves and 12% of the Company’s Present Value of total proved reserves. The Company owns 10,079 gross (5,799 net) leasehold acres in the San Juan Basin. In the 1950’s, the Company’s average 48% working interest in most of the acreage was contributed in connection with a unitization of the wells in the San Juan Basin fields, resulting in the ownership by the Company of small non-operated working interests in several large units. At December 31, 2002, the Company owned working interests in approximately 2,893 producing gas wells in the San Juan Basin. These working interests average approximately 1.8%. The Company’s San Juan Basin properties produce from multiple formations ranging from depths of 3,000 feet to 8,000 feet.

The Company’s net production from these properties averaged 7,592 Mcf of natural gas, 44 Bbls of oil and 17 Bbls of NGLs per day in 2002. 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.

Gulf of Mexico. The Company began operations in the Gulf of Mexico in 2001 and currently has non-operating working interests in 6 producing offshore blocks. At December 31, 2002, the Gulf of Mexico properties contained 1.5 MMBOE of proved reserves, which represented 4% of the Company’s total proved reserves and 10% of the Company’s Present Value of total proved reserves.

The Company owns a 12.5% working interest in the Eugene Island 302, East Cameron 184 and South Marsh Island 93 blocks and a 25% working interest in the West Cameron 416, West Cameron 417 and West Cameron 347 blocks. All of these blocks are located in water depths of less than 250 feet. During 2002, the Company participated in drilling 6 gross wells in the Gulf of Mexico, of which 2 were dry holes. The Company’s net production from the Gulf of Mexico averaged 1,922 Mcf of natural gas and 111 Bbls of oil per day in 2002.

Other U.S. Properties

The Company’s other United States properties include properties located in the West Texas, New Mexico and the Gulf Coast region.

Canada

In June 1994, Wiser established an important new core area with the completion of a $52.0 million acquisition of Canadian oil and gas properties from Eagle Resources, Ltd. (“Wiser Canada”) (see Note 1 to the Company’s Consolidated Financial Statements). The purchase included 7.2 MMBOE of proved reserves and approximately 127,000 net undeveloped acres. In May 2001, Wiser Canada acquired Invasion Energy Inc. for $37.5 million and added approximately 28 Bcf of proved gas reserves in Canada. Also, in June 2001, Wiser Canada entered into an Asset Exchange Agreement and acquired the Loon and other producing properties in exchange for the Pine Creek, Portage, Groat, Windfall and Sunchild fields. At December 31, 2002, the Company’s Canadian properties contained 11.8 MMBOE of proved reserves, which represented 34% of the Company’s total proved reserves and 38% of the Present Value of the Company’s total proved reserves.

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The following table summarizes certain information with respect to each of the Company’s principal Canadian areas of operation at December 31, 2002:

Wolverine. The Company’s Wolverine Field was acquired in May 2001 in the Invasion acquisition. The Wolverine field is located approximately 450 miles north of Calgary. At December 31, 2002, the Wolverine Field contained 3.2 MMBOE of proved reserves, which represented 27% of the Company’s total Canadian proved reserves and 21% of the Present Value of the Company’s total Canadian proved reserves.

The Company owns 224,010 gross (214,907 net) leasehold acres in the Wolverine Field, and has an average 93% working interest in this acreage. The Wolverine Field produces gas from the Wabamun, Bluesky and Gething formations at depths averaging 1,500 feet. The Company’s net production from the Invasion Field commenced in May 2001 and averaged 8,886 Mcf of gas per day in 2002. At December 31, 2002, the Company owned 115 gross and net productive wells and 4 gross and net water disposal wells in the field, all of which were operated by Wiser.

Wild River. At December 31, 2002, the Wild River Field contained 1.8 MMBOE of proved reserves, which represented 15% of the Company’s total Canadian proved reserves and 9% of the Present Value of the Company’s total Canadian proved reserves.

The Company owns 18,080 gross (9,176 net) leasehold acres in the Wild River Field, and has an average 50% working interest in this acreage. The Wild River Field produces from the Gething and Cadomin formations at depths of 9,500 to 10,000 feet. At December 31, 2002, the Company owned 6 gross (3.0 net) productive wells, all of which were operated by Wiser. The Company’s net production from the Wild River Field averaged 1,342 Mcf of gas per day and 37 Bbls of oil per day in 2002. The Company completed pipeline hookup operations for several wells in the Wild River Field in 2002 and plans to drill 1 exploratory well and 5 development wells in 2003.

Hayter. The Company’s Hayter Field was acquired in 2000 and significant reserves were added in 2001 and 2002 through development activities. The Hayter field is located approximately 200 miles northeast of Calgary. At December 31, 2002, the Hayter Field contained 1.5 MMBOE of proved reserves, which represented 13% of the Company’s total Canadian proved reserves and 13% of the Present Value of the Company’s total Canadian proved reserves.

The Company owns 6,350 gross (6,060 net) leasehold acres in the Hayter Field, and has an average 95% working interest in this acreage. The Hayter Field produces heavy oil (13° gravity) mainly from the McLaren formation at depths averaging 2,600 feet. The Company drilled 1 productive well in the Hayter Field in 2002 and plans to drill another 20 to 50 wells over the next few years, depending on oil prices.

The Company’s net production from the Hayter Field commenced in June 2001 and averaged 1,038 Bbls of oil per day and 408 Mcf per day in 2002. At December 31, 2002, the Company owned 79 gross (77.3 net) productive wells and 2 gross and net water injection wells on the properties, all of which were operated by the Company.

Evi. The Company’s Evi Field is located approximately 400 miles north of Calgary. At December 31, 2002, the Evi Field contained 1.5 MMBOE of proved reserves, which represented 13% of the Company’s total Canadian proved reserves and 19% of the Present Value of the Company’s total Canadian proved reserves.

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The Company owns 6,880 gross (4,110 net) leasehold acres in the Evi Field, and has an average 57% 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 732 Bbls of oil per day in 2002. At December 31, 2002, the Company owned 23 gross (9.7 net) productive wells and 2 gross (0.8 net) water disposal wells in the field, of which 19 productive wells and both water disposal wells were operated by Wiser.

Other Canadian Properties. The Company owns interests in various other Canadian properties, primarily located in its principal areas of operation. For the year ended December 31, 2002, these properties individually represented less than 10%, and in the aggregate represented approximately 32%, of the Company’s total Canadian proved reserves.

Exploration Activities

United States

The objective of Wiser’s domestic exploration program is to generate exploration and exploitation drilling opportunities that have the potential of replacing produced reserves and providing a vehicle of growth for the Company. In 2002, Wiser drilled or participated in 10 gross (2.0 net) U.S. exploration wells, compared with 8 gross (4.0 net) wells in 2001, spending $14.3 million in 2002 and $11.0 million in 2001 on U.S. exploration. Of the 10 gross wells drilled by the Company in 2002, 6 were completed as oil or gas wells, and 4 were unsuccessful. The Company also continued exploration activities in the Gulf of Mexico in 2002 by participating in 4 successful exploration wells through joint venture agreements. In 2003, Wiser plans to drill or participate in approximately 8 to 10 gross wells in the U.S. and the Company has budgeted approximately $7.0 to $9.0 million for its 2003 U.S. exploration program, depending on cash flows and drilling results.

Canada

Wiser focuses its Canadian exploration activities in specific regions within the Western Canadian Sedimentary Basin in close proximity to known producing horizons where the potential for significant reserves exists. The Company’s technical personnel have considerable experience in this focus area. During 2002, the Company participated in 13 gross (12.0 net) exploratory wells of which 1 was completed as successful oil or gas wells. The Company spent $3.1 million on exploration in Canada in 2002, compared to $1.3 million in 2001, and has budgeted approximately $10.0 million for its 2003 Canadian exploration program.

International

The Company did not participate in any other international exploration activity in 2002 and currently has no plans to participate in future international exploration activities.

Marketing of Production

The Company markets its production of oil, natural gas and NGLs to a variety of purchasers, including large refiners and resellers, pipeline affiliate marketers, independent marketers, utilities and industrial end-users. To help manage the impact of potential price declines, Wiser has developed a portfolio of long- and short-term contracts with prices that are either fixed or related to market conditions in varying degrees. Most of the Company’s production is sold pursuant to contracts that provide for market-related pricing for the areas in which the production is located.

During the year ended December 31, 2002, revenues from the sale of production to Nexen Inc. represented approximately 37% of the Company’s total oil and gas revenues. The Company believes it would be able to locate

alternate purchasers in the event of the loss of any one or more purchaser, 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

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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 $41.7 million for the year ended December 31, 2002 and represented 54% of the Company’s total oil and gas revenues for 2002.

From time to time, the Company enters into crude oil and natural gas price hedges to reduce its exposure to commodity price fluctuation. See Item 7A – “Quantitative and Qualitative Disclosures about Market Risk – Commodity Price Risk” and Note 1 to the Company’s Consolidated Financial Statements included elsewhere in this Report.

Natural Gas. The Company sells its produced natural gas and gathered gas to utilities, marketers, processor/resellers and industrial end-users primarily under market-sensitive, long-term contracts or daily, monthly or multi-month spot agreements. An insignificant amount of the Company’s natural gas is committed to long-term, fixed-price sales agreements. To accomplish the delivery and sale of certain of its natural gas, the Company has entered into long-term agreements with various natural gas gatherers that deliver its gas to points of sale on major transmission pipelines.

The Company believes that it has sufficient production from its properties, and from those of others tied to its gathering and transportation system, to meet the Company’s delivery obligations under its existing natural gas sales contracts.

NGLs. From its natural gas processing plants in West Texas, the Company sells NGLs to independent marketers for resale. A direct pipeline connection to the Texas Gulf Coast market area facilitates the sale of NGLs from the Company’s Wellman Unit, and enables the Company to receive prices that are representative of the daily market value of NGLs on the Texas Gulf Coast, less transportation and fractionation costs. The Company’s average price in 2002 for NGLs sold from Company-operated plants or under processing agreements with others was $19.11 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 2002 was $23.07. The average NYMEX-WTI closing price per Bbl for 2002 was $26.08.

Natural gas prices in each of the geographical areas in which the Company operates are closely tied to established price indices which are heavily influenced by national and regional supply and demand factors and the futures price per MMBtu for natural gas delivered at Henry Hub, Louisiana established on the NYMEX (“NYMEX-Henry Hub”). At times, these indices correlate closely with the NYMEX-Henry Hub price, but often there are significant variances between the NYMEX-Henry Hub price and the indices used to price the Company’s natural gas. Average natural gas prices received by Wiser in each of its operating areas generally fluctuate with changes in these established indices. The average natural gas price per Mcf received by the Company in 2002 was $2.69. The average NYMEX-Henry Hub price per MMBtu for 2002 was $3.25, computed by averaging the closing price on the last three trading days of each month of the forward prompt month NYMEX natural gas futures contract price applicable to each month in 2001. The average natural gas price received by the Company in 2002 was lower than such 2002 NYMEX-Henry Hub price as a result of pricing differentials determined by the location of the Company’s natural gas production relative to the Henry Hub trading point and lower natural gas prices generally applicable to Canadian natural gas production relative to U.S. production.

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Oil and Gas Reserves

The following table sets forth the proved developed and undeveloped reserves of the Company at December 31, 2002:

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, 2002, 2001 and 2000:

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All information set forth in this Report relating to the Company’s proved reserves, estimated future net revenues and Present Values is taken from reports prepared by DeGolyer and MacNaughton (with respect to the Company’s United States properties) and Gilbert Lausten Jung Associates Ltd. (with respect to the Company’s Canadian properties), each of which is a firm of independent petroleum engineers. The estimates of these engineers were based upon review of production histories and other geological, economic, ownership and engineering data provided by the Company. No reports on the Company’s reserves have been filed with any federal agency. In accordance with guidelines of the Securities and Exchange Commission (“SEC”), the Company’s estimates of proved reserves and the future net revenues from which Present Values are derived are made using year end oil and gas sales prices held constant throughout the life of the properties (except to the extent a contract specifically provides otherwise). A decline in prices relative to year-end 2002 could cause a significant decline in the Present Value attributable to the Company’s proved reserves at December 31, 2002. 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.

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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, 2002.

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Productive Wells and Acreage

Productive Wells

The following table sets forth the Company’s domestic and Canadian productive wells at December 31, 2002:

Acreage

The following table sets forth the Company’s undeveloped and developed gross and net leasehold acreage at December 31, 2002. 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.

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:

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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, 2002 the number of exploratory and development wells drilled by or on behalf of the Company.

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, 2002, the Company operated 98% of its properties in the Permian Basin, comprising approximately 42% of the Company’s total proved reserves, including Maljamar (243 gross wells), Wellman (32 gross wells) and Dimmitt/Slash Ranch (83 gross wells). At December 31, 2002, the Company also operated 232 (out of a total of 367) gross wells on its Canadian properties.

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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 2002 ranged from $99 to $980 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 also from wells that are productive but do not produce sufficient net revenues to return a profit after drilling, operating and other costs. The cost of drilling, completing and operating wells is often uncertain. The Company’s drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, many of which are beyond its control, including economic conditions, mechanical problems, pressure or irregularities in formations, title problems, weather conditions, compliance with governmental requirements and shortages in or delays in the delivery of equipment and services. Such equipment shortages and delays sometimes involve drilling rigs, especially in Canada, where weather conditions result in a short drilling season, causing a high demand for rigs by a large number of companies during a relatively short period of time. The Company’s future drilling activities may not be successful. Lack of drilling success could have a material adverse effect on the Company’s financial condition and results of operations.

In addition, the Company’s use of 3-D seismic requires greater pre-drilling expenditures than traditional drilling strategies. Although the Company believes that its use of 3-D seismic will increase the probability of success of its exploratory wells and should reduce average finding costs through the elimination of prospects that might otherwise be drilled solely on the basis of 2-D seismic and other traditional methods, unsuccessful wells are likely to occur.

The Company’s operations are subject to all the hazards and risks normally incident to the development, exploitation, production and transportation of, and the exploration for, oil and gas, including unusual or unexpected geologic formations, pressures, down-hole fires, mechanical failures, blowouts, cratering, explosions, uncontrollable flows of oil, gas or well fluids and pollution and other environmental risks. These hazards could result in substantial losses to the Company due to injury and loss of life, severe damage to and destruction of property and equipment, pollution and other environmental damage and suspension of operations. The Company maintains comprehensive

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insurance coverage, including a $2.0 million general liability insurance policy and a $25.0 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, 2002, the Company’s leaseholds for approximately 23% of its net acreage were being kept in force by virtue of production on that acreage in paying quantities. The remaining net acreage was held by lease rentals and similar provisions and requires production in paying quantities prior to expiration of various time periods to avoid lease termination.

The Company expects to make acquisitions of oil and gas properties from time to time. In making an acquisition, the Company generally focuses most of its title and valuation efforts on the more significant properties. It is generally not feasible for the Company to review in-depth every property it purchases and all records with respect to such properties. However, even an in-depth review of properties and records may not necessarily reveal existing or potential problems, nor will it permit the Company to become familiar enough with the properties to assess fully their deficiencies and capabilities. Evaluation of future recoverable reserves of oil and gas, which is an integral part of the property selection process, is a process that depends upon evaluation of existing geological, engineering and production data, some or all of which may prove to be unreliable or not indicative of future performance. To the extent the seller does not operate the properties, obtaining access to properties and records may be more difficult. Even when problems are identified, the seller may not be willing or financially able to give contractual protection against such problems, and the Company may decide to assume environmental and other liabilities in connection with acquired properties.

Governmental Regulation

The Company’s operations are affected from time to time in varying degrees by political developments and federal, state, provincial and local laws and regulations. In particular, oil and gas production and related operations are or have been subject to price controls, taxes and other laws and regulations relating to the oil and gas industry. Failure to comply with such laws and regulations can result in substantial penalties. The regulatory burden on the oil and gas industry increases the Company’s cost of doing business and affects its profitability. Although the Company believes it is in substantial compliance with all applicable laws and regulations, because such laws and regulations are frequently amended or reinterpreted, the Company is unable to predict the future cost or impact of complying with such laws and regulations.

United States. Sales of natural gas by the Company are not regulated and are generally made at market prices. However, the Federal Energy Regulatory Commission (“FERC”) regulates interstate natural gas transportation rates and service conditions, which affect the marketing of natural gas produced by the Company, as well as the revenues received by the Company for sales of such production. Sales of the Company’s natural gas currently are made at uncontrolled market prices, subject to applicable contract provisions and price fluctuations which normally attend sales of commodity products. 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.

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Since the mid-1980’s, the FERC has issued a series of orders that have significantly altered the marketing and transportation of natural gas. Such orders mandated a fundamental restructuring of interstate pipeline sales and transportation service, including the unbundling by interstate pipelines of the sale, transportation, storage and other components of the city-gate sales services such pipelines previously performed. Further, they have eliminated or substantially reduced the interstate pipelines’ traditional role as wholesalers of natural gas, and have substantially increased competition and volatility in natural gas markets.

While the Company cannot predict what action the FERC will take on these or related matters in the future, the Company does not believe that it will be treated materially differently than other natural gas producers and marketers with which it competes.

The Company’s gathering operations are subject to safety and operational regulations relating to the design, installation, testing, construction, operation, replacement and management of facilities. Pipeline safety issues have recently been the subject of increasing focus in various political and administrative arenas at both the state and federal levels. The Company believes its operations, to the extent they may be subject to current gas pipeline safety requirements, comply in all material respects with such requirements. The Company cannot predict what effect, if any, the adoption of this or other additional pipeline safety legislation might have on its operations, but the industry could be required to incur additional capital expenditures and increased costs depending upon future legislative and regulatory changes.

The State of Texas and many other states require permits for drilling operations, drilling bonds and reports concerning operations and impose other requirements relating to the exploration for and production of oil and gas. Such states also have statutes or regulations addressing conservation matters, including provisions for the unitization or pooling of oil and gas properties, the establishment of maximum rates of production from wells and the regulation of spacing, plugging and abandonment of such wells. The statutes and regulations of certain states limit the rate at which oil and gas can be produced from the Company’s properties. However, the Company does not believe it will be affected materially differently by these statutes and regulations than any other similarly situated oil and gas company.

Canada. In Canada producers of oil negotiate sales contracts directly with oil purchasers, with the result that sales of oil are generally made at market prices. The price of oil received by the Company depends in part on oil quality, prices of competing fuels, distance to market, the value of refined products and the supply/demand balance. Oil exports may be made pursuant to export contracts with terms not exceeding one year in the case of light crude, and not exceeding two years in the case of heavy crude, provided that an order approving any such export has been obtained from the National Energy Board (“NEB”). Any oil export to be made pursuant to a contract of a longer duration requires an exporter to obtain an export license from the NEB and the issue of such license requires the approval of the Governor General in Council.

In Canada the price of natural gas sold is determined by negotiation between buyers and sellers. Natural gas exported from Canada is subject to regulation by the NEB and the government of Canada. Exporters are free to negotiate prices and other terms with purchasers, provided that export contracts in excess of two years must continue to meet certain criteria prescribed by the NEB and the government of Canada. As is the case with oil, natural gas exports for a term of less than two years must be made pursuant to an NEB order, or, in the case of exports for a longer duration, pursuant to an NEB license and Governor General in Council approval. The government of Alberta also regulates the volume of natural gas that may be removed from Alberta for consumption elsewhere based on such factors as reserve availability, transportation arrangements and marketing considerations.

In addition to Canadian federal regulation, Alberta and certain other provinces have legislation and regulations that govern royalties payable on production from Crown lands. The royalty regime that is in place at a particular time or location is a significant factor in the profitability of oil and gas production. Royalties payable on production from lands other than Crown lands are determined by negotiations between the mineral owner and the lessee. Crown royalties are determined by governmental regulation and are generally calculated as a percentage of the value of the gross production. The rate of royalties payable generally depends in part on prescribed reference prices, well productivity, geographical location, field discovery date and the type and quality of the petroleum product produced.

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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 Environmental Protection Agency and various state agencies have limited the approved methods of disposal for certain hazardous and non-hazardous 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.

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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 substantially offset 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.

In accordance with Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations”, the Company estimates future abandonment cost are in the range of $5 to $6 million. See Note 1 to the Company’s Consolidated Financial Statements.

Employees

At March 24, 2003, the Company employed 74 full-time employees; 7 were executive officers, 41 were professional and administrative personnel and 26 were field personnel. Of the total employees, 53 were located in the United States and 21 were located in Canada. At March 24, 2003, none of the Company’s employees were represented by a labor union. The Company considers its relations with its employees to be good.

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Facilities

The Company’s principal executive and administrative offices are located at 8115 Preston Road, Suite 400, Dallas, Texas. The offices contain approximately 15,200 square feet of space and are leased through June 30, 2003. Rental payments are approximately $30,000 per month. The office of the Company’s Canadian subsidiary, The Wiser Oil Company of Canada, is located at 645 7^th Avenue, S.W., Suite 2550, Calgary, Alberta. This office contains approximately 14,000 square feet of space and is leased through December 20, 2003. Rental payments are approximately $20,000 per month.

Glossary of Oil and Gas Terms

The following are abbreviations and definitions of terms commonly used in the oil and gas industry that are used in this Report.

“Bbl” means a barrel of 42 U.S. gallons.

“Bcf” means billion cubic feet.

“BOE” means barrels of oil equivalent, converting volumes of natural gas to oil equivalent volumes using a ratio of six Mcf of natural gas to one Bbl of oil.

“completion” means the installation of permanent equipment for the production of oil or gas.

“development well” means a well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

“dry hole” or “dry well” means a well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

“exploratory well” means a well drilled to find and produce oil or gas reserves not classified as proved, to find a new production reservoir in a field previously found to be productive of oil or gas in another reservoir or to extend a known reservoir.

“farm-in” means an agreement pursuant to which the owner of a working interest in an oil and gas lease assigns the working interest or a portion thereof to another party who desires to drill on the leased acreage. Generally, the assignee is required to drill one or more wells in order to earn its interest in the acreage. The assignor usually retains a royalty or reversionary interest in the lease. The interest received by an assignee is a “farm-in.”

“gas” means natural gas.

“gross” when used with respect to acres or wells, refers to the total acres or wells in which the Company has a working interest.

“infill drilling” means drilling of an additional well or wells provided for by an existing spacing order to more adequately drain a reservoir.

“MBbl” means thousand Bbls.

“MBOE” means thousand BOE.

“Mcf” means thousand cubic feet.

“MMBOE” means million BOE.

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“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.

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“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.

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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.

The Company has filed proofs of claims against Enron North America (“ENA”) and Enron Corporation to collect $6,872,000 owed the Company under hedging contracts. Based on the uncertainty of collecting this amount from Enron, the Company decided to write-off the full amount at December 31, 2001. ENA is a wholly-owned subsidiary of Enron Corporation and Enron Corporation has provided the Company with a guarantee on behalf of ENA of up to $10 million. A secondary market for the purchase and sale of claims against ENA and Enron Corporation (jointly “Enron”) has developed. Periodically, the Company has discussed with several market participants selling its claims. The Company is currently negotiating to sell its claims against Enron to a third party. If a sale is concluded, any proceeds received from the sale of its claims will be recognized in the year received.

In January 2002 the Company was notified by a gas marketing company that it would not pay the Company approximately $730,000 owed to Wiser for its November 2001 gas sales because the gas marketing company claimed it had not been paid by Enron Corporation. The Company believes that the gas marketing company has no basis under the gas sales contract to withhold payment and the Company filed suit against the gas marketing company in 2002 to recover the $730,000 plus court costs.

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, 2002.

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PART II

Item 5. Market for Registrant’s Common Equity and Related Stockholder Matters

The Common Stock is traded on the New York Stock Exchange under the symbol WZR.

The quarterly high and low sales prices and dividends per share of Common Stock during the two years ended December 31, 2002, were as follows:

At March 24, 2003, there were 9,473,929 shares of Common Stock outstanding held by approximately 652 shareholders of record and approximately 4,200 beneficial owners.

Each share of Common Stock also represents one preferred stock purchase right which entitles the holder thereof to purchase from the Company one-one thousandth of a share (a “Unit”) of Series B Preferred Stock of the Company at an exercise price of $72.00 per Unit.

On December 10, 1998, the Board of Directors approved a cost reduction plan which included suspending payments of cash dividends on the Company’s common stock.

The Company has two equity compensation plans, the 1991 Stock Incentive Plan and the 1991 Non-Employee Directors’ Plan. The Stockholders have approved both plans.

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Item 6. Selected Financial Data

The following selected consolidated financial data of the Company are derived from information contained in the Company’s consolidated financial statements. The selected consolidated financial and operating data presented below should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the Company’s Consolidated Financial Statements and notes thereto included elsewhere in this Report. For additional information about accounting changes, see Note 1 to the financial statements, effective January 1, 2001, describing the Company’s change of its method of accounting for derivative instruments and hedging transactions. For additional information about business combinations, see Note 3 to the financial statements, describing the Company’s acquisition of Invasion Energy Inc. For additional information on property sale gains, see “Results of Operations” in Item 7, describing the Asset Exchange Agreement entered into between Wiser Canada and Talisman Energy, Inc. dated June 29, 2001.