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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, 2003 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, 2003 was approximately $51.0 million.

As of March 24, 2004, registrant had outstanding 15,470,007 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 2004 Annual Meeting of Stockholders (the “Proxy Statement”) are incorporated by reference in Part III of this Report. The Proxy Statement will be filed with the Securities and Exchange Commission within 120 days of the close of the registrant’s fiscal year.

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TABLE OF CONTENTS

DESCRIPTION

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THE WISER OIL COMPANY

PART I

Items 1, 2. Business and Properties

General

The Wiser Oil Company is an independent oil and gas exploration and production company operating primarily in Texas, New Mexico, the Gulf Coast and Western Canada. Our total proved reserves at December 31, 2003 were 191.2 Bcfe, with oil and NGL’s comprising 49% and natural gas comprising 51% of total reserves. Our proved reserves at December 31, 2003 were 85% developed with approximately 70% located in the U.S. and 30% located in Canada.

The pre-tax present value of our total proved reserves at December 31, 2003 was $349.6 million, discounted at 10% and based on average realized prices of $28.99 per barrel for oil and $5.40 per Mcf for gas, as computed under Securities and Exchange Commission (“SEC”) pricing guidelines. After taxes, the present value of our total proved reserves at December 31, 2003 was $270.3 million. See “Oil and Gas Reserves” below for additional information about our reserves.

Our principal executive offices are located at 8115 Preston Road, Suite 400, Dallas, Texas 75225, and our telephone number is (214) 265-0080. The Internet address is http://www.wiseroil.com. On our web site you can review, free of charge, 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 with or furnished to the SEC 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. References in this Form 10-K to “Wiser”, “we,” “our,” or “us”, except as otherwise indicated, refer to The Wiser Oil Company and our consolidated subsidiaries.

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

History

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

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

Strategy

Over the past four years, we have increased the percentage of our natural gas reserves from 31% at December 31, 1999 to 51% at December 31, 2003. We continue to focus our efforts on adding primarily gas reserves through exploration activities or strategic acquisitions in both the U.S. and Canada. We expect to fund our future capital expenditure programs primarily with discretionary cash flow and any significant acquisition opportunities would be funded with borrowings under our credit facility.

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Principal Oil and Gas Properties

The following table summarizes certain information with respect to each of our principal areas of operation at December 31, 2003.

Permian Basin

Maljamar. Our Maljamar properties are situated in Southeast New Mexico. At December 31, 2003, the Maljamar properties contained 56.0 Bcfe of proved reserves, which represented 29% of our total proved reserves and 14% of the Present Value of total proved reserves.

The Maljamar properties consist primarily of three oil producing units acquired by us 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 located 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. We have 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 17,000 gross developed leasehold acres.

A large scale development program was undertaken on the project from 1995 to 1998. This program 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 throughout most of the project area. At December 31, 2003, the project included 235 producing wells and 169 active water injection wells, virtually all of which were operated by us.

Our net production from the Maljamar properties averaged 970 Bbls of oil and 669 Mcf of natural gas (6,486 Mcfe) per day in 2003. Our cumulative net production from the Maljamar properties since acquired by us has been 5.5 MMBbls of oil and 2.74 Bcf of natural gas through December 31, 2003. Additional exploitation potential exists in the form of lease line development, extending water flood activities and the development of offsetting leases acquired in 2003.

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Dimmitt/Slash Ranch. Our Dimmitt/Slash Ranch properties are situated in Loving County, Texas, 80 miles west of Midland, Texas. At December 31, 2003, the Dimmitt/Slash Ranch properties contained 23.1 Bcfe of proved reserves, which represented 12% of our total proved reserves and 12% of the Present Value of total proved reserves.

We own 6,155 gross (5,499 net) developed leasehold acres in the Dimmitt/Slash Ranch area in Loving County, Texas. We acquired our 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, 2003, the Dimmitt/Slash Ranch Field included 88 producing wells, all of which were operated by us. Our average working interest in these wells is 97%.

Our net production from the Dimmitt/Slash Ranch properties averaged 339 Bbls of oil and 2,637 Mcf of natural gas (4,671 Mcfe) per day in 2003. Our cumulative net production from the properties since acquired by us has been 1.3 MMBbls of oil and 10.1 Bcf of natural gas through December 31, 2003.

San Juan Basin

Our San Juan Basin properties are located in Rio Arriba County in northwestern New Mexico. At December 31, 2003, the San Juan Basin properties contained 26.9 Bcfe of proved reserves, which represented 14% of our total proved reserves and 17% of the Present Value of total proved reserves. We own 4,479 gross (4,357 net) developed leasehold acres in the San Juan Basin. In the 1950’s, our 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 us of small non-operated working interests in several large units. At December 31, 2003, we owned working interests in approximately 3,049 producing gas wells and one oil well in the San Juan Basin. These working interests average approximately 1.8%. Our San Juan Basin properties produce from multiple formations ranging from depths of 3,000 to 8,000 feet. Our net production from these properties averaged 7,358 Mcf of natural gas, 40 Bbls of oil and 103 Bbls of NGLs (8,214 Mcfe) per day in 2003. We expect that future development of the properties will depend on natural gas prices.

Gulf of Mexico

We began operations in the Gulf of Mexico in 2001 and currently have non-operating working interests in 11 producing offshore blocks. At December 31, 2003, the Gulf of Mexico properties contained 11.5 Bcfe of proved reserves, which represented 6% of our total proved reserves and 15% of the Present Value of total proved reserves.

We own a 12.5% working interest in the Eugene Island 302, East Cameron 179, East Cameron 185, and South Marsh Island 93 blocks and a 25% working interest in the West Cameron 416, West Cameron 417, West Cameron 428, West Cameron 488, Ship Shoal 322, Vermilion 61 and West Cameron 347 blocks. All of these blocks are located in water depths of less than 325 feet and we own 50,000 gross (9,375 net) developed leasehold acres in the Gulf of Mexico. During 2003, we participated in drilling 6 gross wells in the Gulf of Mexico, only one of which was a dry hole. As of December 31, 2003, we have been successful on 14 out of 18 wells drilled in the Gulf of Mexico during the last three years for a 78% success rate. Our net production from the Gulf of Mexico averaged 7,336 Mcf of natural gas and 240 Bbls of oil (8,778 Mcfe) per day in 2003.

Other U.S. Properties

Our other United States properties are located in West Texas, Indiana and the Onshore Gulf Coast region. For the year ended December 31, 2003, these properties represented approximately 5% of our total proved reserves.

We own a 100% working interest in and operate the Wellman Unit, located in Terry County, Texas. In 2001, we decided to discontinue injecting CO2 into the Wellman Unit reservoir and entered into a contract to sell the previously injected CO2 to a third party. We estimate that the Wellman Unit reservoir contains approximately 35.8 Bcf of recoverable CO2 at December 31, 2003. Sales of CO2 commenced in May of 2003 at a rate of approximately 20 MMcf per day. Proceeds from the sale of CO2 are recorded as a reduction of production and operating expense.

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Canada

In June 1994, we 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., acquired by our wholly owned subsidiary The Wiser Oil Company of Canada. The purchase included 43.2 Bcfe of proved reserves and approximately 127,000 net undeveloped acres. In May 2001, The Wiser Oil Company of Canada acquired Invasion Energy, Inc. for $37.5 million. Also, in June 2001, The Wiser Oil Company of 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, 2003, our Canadian properties contained 57.4 Bcfe of proved reserves, which represented 30% of our total proved reserves and 33% of the Present Value of our total proved reserves.

Evi/Loon. Our Evi/Loon properties are located approximately 400 miles north of Calgary. At December 31, 2003, the Evi/Loon properties contained 11.2 Bcfe of proved reserves, which represented 6% of our total proved reserves and 8% of the Present Value of our total proved reserves.

We own 5,280 gross (1,960 net) developed leasehold acres in the Evi/Loon area, and have an average 57% working interest in the Evi Field and an average 30% working interest in the Loon Field. The Evi/Loon properties produce oil primarily from the Granite Wash formation at depths ranging from 4,900 to 5,000 feet. Our net production from the Evi/Loon Fields averaged 1,157 Bbls of oil (6,942 Mcfe) per day in 2003. At December 31, 2003, we owned 52 gross (18 net) productive wells and 2 gross (0.8 net) water disposal wells in the field, of which both disposal wells and 19 productive wells were operated by us.

Wolverine. Our Wolverine properties were acquired in May 2001 in the Invasion acquisition. At December 31, 2003, the Wolverine properties contained 10.9 Bcfe of proved reserves, which represented 6% of our total proved reserves and 6% of the Present Value of our total proved reserves.

We own 44,810 gross (39,465 net) developed leasehold acres in the Wolverine area. The Wolverine properties produce gas from the Wabamun, Bluesky and Gething formations at depths averaging 1,500 feet. Our net production from the Wolverine properties averaged 6,890 Mcf of gas and 4 Bbls of oil (6,912 Mcfe) per day in 2003. At December 31, 2003, we owned 118 gross and net productive wells and 4 gross and net water disposal wells in the field, all of which were operated by us.

Hayter. Our Hayter properties were acquired in 2000. The Hayter properties are located approximately 200 miles northeast of Calgary near the Alberta, Saskatchewan border. At December 31, 2003, the Hayter properties contained 10.9 Bcfe of proved reserves, which represented 6% of our total proved reserves and 4% of the Present Value of our total proved reserves.

We own 1,492 gross (1,454 net) developed leasehold acres in the Hayter area. The Hayter properties produce heavy oil (13° gravity) mainly from the McLaren formation at depths averaging 2,600 feet. We drilled nine productive wells in the Hayter area in 2003 and plan to drill additional wells over the next few years, depending on oil prices.

Our net production from the Hayter area averaged 1,139 Bbls of oil per day and 870 Mcf (7,704 Mcfe) per day in 2003. At December 31, 2003, we owned 97 gross (95 net) productive wells and two gross and net water injection wells on the properties, all of which were operated by us.

Wild River. At December 31, 2003, the Wild River properties contained 8.2 Bcfe of proved reserves, which represented 4% of our total proved reserves and 5% of the Present Value of our total proved reserves.

We own 2,560 gross (1,280 net) developed leasehold acres in the Wild River area. The Wild River properties produce from the Gething, Cadomin and Wabamun formations at depths of 9,500 to 12,000 feet. At December 31, 2003, we owned 12 gross (6.0 net) productive wells, 8 of which were operated by us. Our net production from the Wild River area averaged 1,870 Mcf of gas per day and 44 Bbls of oil (2,136 Mcfe) per day in 2003. We made a significant discovery in the Wabamum formation in 2003, which began producing in January of 2004.

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Other Canadian Properties. We own interests in various other Canadian properties, generally located in or near our principal areas of operation. For the year ended December 31, 2003, these properties represented approximately 8% of our total proved reserves.

Exploration Activities

United States

In 2003, we drilled or participated in 11 gross (three net) U.S. exploration wells, compared with ten gross (two net) wells in 2002, spending $12.6 million in 2003 and $14.3 million in 2002 on U.S. exploration. Of the 11 gross wells we drilled or participated in during 2003, seven were successfully completed as oil or gas wells in the targeted interval, and one was completed as a shallower development well. In the Gulf of Mexico, we participated in six successful exploration wells and one dry hole, which were generated and drilled through a joint venture with Remington Oil and Gas Corp. In 2004, we plan to drill or participate in approximately 8 to 10 gross wells in the U.S. and have budgeted approximately $12.0 million for our 2004 U.S. exploration program, including seismic costs.

Onshore. The primary focus of our U.S. onshore exploration effort is the central and upper Gulf Coast areas of Texas and Louisiana. Within this core area, Wiser is actively working the Miocene, Frio, Yegua, Cook Mountain, and Wilcox plays. These are relatively gas-prone trends where state-of-the-art seismic techniques have proven to be effective tools for lowering risk. Our goal is to understand and apply the appropriate technology within these fairly mature areas, and to generate economically viable drilling opportunities. Wiser currently has over 2,500 square miles of proprietary or licensed 3D data within the Gulf Coast. We have also invested in geophysical modeling and processing software that allows pre- and post-stack data evaluation to be done in-house.

Within the U.S. onshore core area, we have ten ongoing exploration projects with over 50 defined but undrilled prospects in inventory. The key acreage is under lease on nearly all of these prospects. Two of the more important projects, the Sabine project and the Liberty project, were initiated in 2003 and are expected to generate numerous low to moderate risk drilling opportunities over the next several years.

The Sabine project, located in Beauregard Parish and Calcasieu Parish, Louisiana is a 157,000 acre block located immediately east of the Texas State line encompassing several active plays, including the prolific Frio, Hackberry, Yegua, and Wilcox trends. Multiple leads and prospects have been defined within this block to date, with drilling expected to commence in June 2004. We will be the operator of this project with a 45% working interest.

The Liberty project is located in Liberty County, Texas. A 51 square-mile proprietary 3D program was acquired in 2003 in this very active Yegua and Cook Mountain play. We co-operated the seismic acquisition and will operate drilling operations which are expected to commence mid-year 2004. Several prospects have been defined to date and interpretation of the seismic data continues. Our working interest in this project is 35%.

In addition to the Liberty and Sabine projects, we are actively exploring in several other areas of Texas and Louisiana. As a result of these efforts, we will have the opportunity to participate in a diverse set of exploration plays located in West Texas, South Texas, and in southeast Louisiana. The evaluation of these prospects is ongoing.

Offshore. To complement our stepped-up onshore exploration effort we continue to participate in offshore exploration in the Gulf of Mexico. Our offshore interests are concentrated in the shallow water (less than 350 feet) Louisiana shelf play. In 2003, we participated in seven wells, six of which were completed as producers for an 86% success rate. We have a 25% working interest in all of these wells except one, where we have a 12.5% working interest. From 2001, when we started work in the Gulf of Mexico, through March 2004, we have participated in drilling 19 offshore wells, 15 of which were completed as producers for a 79% overall success rate. We also have a working interest in a number of additional undrilled offshore blocks. Each of these blocks has a 3-D seismic defined prospect, and it is anticipated that many of these prospects will be proposed for our participation in the next three years.

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Canada

In addition to the exploitation and development of our existing fields, we are also committed to the exploration of new oil and gas fields in western Canada. With the aid of the latest 3-D seismic evaluation techniques, we continue to explore for high impact exploration opportunities in western Canada. Our exploration efforts are concentrated primarily in the western half of Alberta and in northeast British Columbia. These are historically prolific, gas prone areas where we have a significant acreage position, access to large grids of 3-D seismic data, and the technical expertise to uncover significant new reserves. During 2003, we participated in nine gross (six net) exploratory wells of which two were completed as successful oil or gas wells. We spent $6.1 million on exploration in Canada in 2003, compared to $3.1 million in 2002, and have budgeted approximately $7.7 million for our 2004 Canadian exploration program.

Wild River. The Wild River area of western Canada continues to supply us with multiple gas bearing targets ranging in depth from 5,000 to 14,000 feet. We have acquired a contiguous land base of approximately 26,000 gross acres of highly prospective lands on which we have identified 30 additional exploration and development locations. We are actively developing the Cretaceous aged “field pay” and the deeper Devonian gas pay in the area during 2004.

During March 2003, we made a significant new gas discovery below the main field pay in an underlying Devonian reservoir. The 15-30 well (50% working interest) was brought on stream in January 2004 and is currently producing at a gross rate of 20 MMcf per day. The 3-D seismic anomaly, which the 15-30 well targeted, appears sizeable enough to support one or two additional development locations. A follow-up well to the 15-30 discovery is planned for drilling during the summer of 2004.

Hinton Obed. Over the past several years, we have acquired seismic data over much of our large land base in the Hinton Obed area of western Alberta. During 2003, we began to harvest some of the opportunities that have been generated through our exploration efforts. During the spring of 2003, we participated in the re-entry of the 5-7 suspended well which was re-completed in two gas bearing zones. The 5-7 well was offset with the 13-8 well (16.6% working interest) during the fall 2003 which encountered the same two gas bearing zones. Production at 13-8 was brought on stream in early 2004.

Northeast British Columbia. Over the past 12 months, we have acquired a large land position in northeast British Columbia where discovery wells along this trend have produced gas rates of 25 to 100 MMcf per day per well. We have acquired 3-D seismic coverage over all of our lands in 2003 and have identified a seismic anomaly on our acreage. The Buick Creek exploration well (50% working interest) started drilling during the first quarter of 2004 and is expected to reach its target depth by late March 2004.

We are also working on several new exploration gas plays in Alberta and British Columbia ranging from early grass roots exploration through to land acquisition on defined drillable prospects. We currently plan to retain a 50% working interest in these projects, some of which could be drilled in 2004.

International

We did not participate in any other international exploration activity other than Canada in 2003 and currently have no plans to participate in future international exploration activities outside of Canada.

Marketing of Production

General. We market our 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, we have developed a portfolio of long-term and short-term contracts with prices that are either fixed or related to market conditions in varying degrees. Most of our production is sold pursuant to contracts that provide for market-related pricing for the areas in which the production is located.

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During the year ended December 31, 2003, revenues from the sale of production to Nexen Inc. and Sempra Energy Trading Corp. represented approximately 34% and 22%, respectively, of our total oil and gas revenues. We believe we 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 our financial condition or results of operations.

Crude Oil. We sell our 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. We typically sell our crude oil and condensate production at or near the well site, although in some cases it is gathered by us or others and delivered to a central point of sale. Our 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. Revenue from the sale of crude oil and condensate totaled $44.5 million for 2003 and represented 41% of our total oil and gas revenues for 2003.

From time to time, we enter into crude oil and natural gas price derivatives to reduce our exposure to commodity price fluctuation. See Item 7A. - “Quantitative and Qualitative Disclosures about Market Risk - Commodity Price Risk” and Note 1 to our Consolidated Financial Statements included elsewhere in this Report.

Natural Gas. We sell our 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 our natural gas is committed to long-term, fixed-price sales agreements. To accomplish the delivery and sale of certain natural gas, we have entered into long-term agreements with various natural gas gatherers that deliver our gas to points of sale on major transmission pipelines. We believe that we have sufficient production from our properties, and from those of others tied to our gathering and transportation system, to meet our delivery obligations under such agreements. Revenues from the sale of natural gas totaled $60.5 million for 2003 and represented 56% of our total oil and gas revenues for 2003.

NGLs. From our natural gas processing plants in West Texas, we sell NGLs to independent marketers for resale. A direct pipeline connection to the Texas Gulf Coast market area facilitates the sale of NGLs from our Wellman Unit, and enables us to receive prices that are representative of the daily market value of NGLs on the Texas Gulf Coast, less transportation and fractionation costs. Our average price in 2003 for NGLs sold from our operated plants or under processing agreements with others was $19.67 per Bbl. The value of NGLs attributable to natural gas sold to plants operated by others are generally included in the prices reported by us for the sale of our natural gas.

Price Considerations. Crude oil prices are established in a highly liquid, international market, with average crude oil prices received by us in both the U.S and Canada 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 us in 2003 was $27.19. The average NYMEX-WTI closing price per Bbl for 2003 was $31.04.

Natural gas prices in each of the geographical areas in which we operate, including Canada, 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 our natural gas. Average natural gas prices received by us in each of our operating areas generally fluctuate with changes in these established indices. The average natural gas price per Mcf received by us in 2003 was $4.72. The average NYMEX-Henry Hub price per MMBtu for 2003 was $5.44, 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 2003. The average natural gas price received by us in 2003 was lower than such 2003 NYMEX-Henry Hub price as a result of pricing differentials determined by the location of our 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. Sales of Canadian natural gas are priced in relation to AECO-C hub, which is a major pricing point for Canadian natural gas, and AECO-C prices have historically been lower than NYMEX. The average AECO-C price per MMBtu for 2003 was $0.80 lower than the average NYMEX price per MMBtu for the same period.

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Oil and Gas Reserves

The following table sets forth our proved developed and undeveloped reserves at December 31, 2003:

The following table summarizes our 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 to such reserves at December 31, 2003, 2002 and 2001:

Our proved oil and gas reserves declined approximately 18.1 Bcfe in 2003 as compared to 2002. The bulk of negative revisions occurred in our Canadian reserve base. These revisions were due to poorer than expected performance on certain properties and the sale of approximately 1.4 Bcfe of non-core Canadian reserves during 2003.

Excluding revisions and sales, we replaced 94% of our 2003 production through discoveries and extensions, and there were no acquisitions of reserves during the year.

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All information in this Form 10-K relating to our 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 our Canadian properties), each of which is a firm of independent petroleum engineers. The estimates of these engineers were based upon review of information provided by us, including, production histories, geological data, economic data, ownership, and engineering data.

As required by the SEC, our estimate 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 change in prices subsequent to December 31, 2003 could cause a significant change in the Present Value attributable to our proved reserves. 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 our control. The reserve data included in this Form 10-K 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 dependent upon assumptions of future variables, such as:

Any significant variance in these assumptions could materially affect the estimated quantity and value of reserve estimates reported. As a result, estimates of different engineers, including those used by us, may vary. There can be no assurance that these estimates are accurate predictions of our oil and gas reserves or their values. 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. 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.

In addition, our estimates of reserves might be subject to revision based upon:

Revisions to our estimates of reserves may be material. Except for the effect of changes in oil and gas prices, no other favorable or adverse event is believed to have caused a significant change in these estimates of proved reserves since December 31, 2003. No reports on our reserves have been filed with any federal agency.

In general, the volumes of production from crude oil and natural gas properties decline as reserves are depleted. Except to the extent we acquire additional properties or additional interests in existing properties containing proved reserves or conduct successful exploration and development activities associated with our proven and unproven reserves, or both, our proved reserves will decline as reserves are produced.

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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 us for the three-year period ended December 31, 2003.

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Productive Wells and Acreage

Productive Wells

The following table sets forth our domestic and Canadian productive wells at December 31, 2003:

Acreage

The following table sets forth our undeveloped and developed gross and net leasehold acreage at December 31, 2003. 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 of 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:

As is customary in the industry, we generally acquire oil and gas acreage without any warranty of title except as to claims made by, through or under the transferor. Although we have title to developed acreage examined prior to

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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 our 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, 2003 the number of exploratory and development wells drilled by or on behalf of Wiser.

Operations

We generally seek to be named as operator for wells in which we have acquired a significant interest, although, as is common in the industry, this typically occurs only when we own the major portion of the working interest in a particular well or field. At December 31, 2003, we operated 98% of our properties in the Permian Basin, comprising approximately 45% of our total proved reserves, including Maljamar (235 gross wells), Wellman (32 gross wells) and Dimmitt/Slash Ranch (88 gross wells). At December 31, 2003, we also operated 249 (out of a total of 382) gross wells on our Canadian properties.

As operator, we are able to exercise substantial influence over the development and enhancement of a well and to supervise operation and maintenance activities on a daily basis. We do not conduct the actual drilling of wells on properties for which we act as operator, but engage independent contractors who are supervised by us. We employ petroleum engineers, geologists and other operations and production specialists who strive to improve production rates, increase reserves and/or lower the cost of operating our 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. Per well supervision fees received by us in 2003 ranged from $1 to $790 per well per month.

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Competition

The oil and gas industry is highly competitive. We encounter competition from other oil and gas companies in all areas of our operations, including the acquisition of producing properties. Our competitors include major integrated oil and gas companies and numerous independent oil and gas companies, individuals and drilling and income programs. Many of our competitors are large, well established companies with substantially larger operating staffs and greater capital resources than us. 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 our financial or human resources permit. Our ability to acquire additional properties and to discover reserves in the future will depend upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. See Item 7. – “ Management’s Discussion and Analysis of Financial Condition and Results of Operations – Risk Factors – We Face Significant Competition, and Many of Our Competitors Have Resources in Excess of Our Available Resources” and “– We Have Substantial Capital Requirements For Which We May Not Be Able to Obtain Adequate Financing.”

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 us will be productive or that we will recover all or any portion of our 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. Our drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, many of which are beyond our control, including:

Our future drilling activities may not be successful. Lack of drilling success could have a material adverse effect on our financial condition and results of operations.

In addition, our use of 3-D seismic requires greater pre-drilling expenditures than traditional drilling strategies. Although we believe that our use of 3-D seismic will increase the probability of success of our 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.

Our 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:

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These hazards could result in substantial losses to us 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.

We maintain comprehensive insurance coverage, including a $2.0 million general liability insurance policy and a $30.0 million excess liability policy. We believe that our 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. See Item 7. – “ Management’s Discussion and Analysis of Financial Condition and Results of Operations – Risk Factors – We Are Subject to Various Drilling and Operating Risks That Could Result in Liability Exposure or the Loss of Production and Revenues.”

Title to Properties

Our land department and contract land professionals have reviewed title records or other title review materials relating to substantially all of our producing properties. The title investigation performed by us prior to acquiring undeveloped properties is thorough, but less rigorous than that conducted prior to drilling, consistent with industry standards. We believe we have satisfactory title to all our producing properties in accordance with standards generally accepted in the oil and gas industry. Our properties are subject to customary royalty interests, liens incident to operating agreements, liens for current taxes and other inchoate burdens which we believe do not materially interfere with the use of or affect the value of such properties. At December 31, 2003, our leaseholds for approximately 32% of our 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.

We expect to make acquisitions of oil and gas properties from time to time. In making an acquisition, we generally focus most of our title and valuation efforts on the more significant properties. It is generally not feasible for us to review in-depth every property we purchase 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 and it may not permit us 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. See Item 7. – “ Management’s Discussion and Analysis of Financial Condition and Results of Operations – Risk Factors – We Are Subject to Uncertainties In Reserve Estimates and Future Net Revenues.” 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 we may decide to assume environmental and other liabilities in connection with acquired properties. See Item 7. – “ Management’s Discussion and Analysis of Financial Condition and Results of Operations – Risk Factors – We Are Subject to Uncertainties and Risks in Connection with Acquisitions That Could Have a Material Impact on Our Future Net Revenues and Financial Condition.”

Governmental Regulation

Our 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 our cost of doing business and affects our profitability. Although we believe we are in substantial compliance with all applicable laws and regulations, because such laws and regulations are frequently amended or reinterpreted, we are unable to predict the future cost or impact of complying with such laws and regulations.

United States. Sales of natural gas by us 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 us, as well as the revenues received by us for sales of such production. Sales of our 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

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gas, and all sales of crude oil, condensate and NGLs, can currently be made at uncontrolled market prices, Congress could re-enact prices controls in the future.

Since the mid-1980’s, the FERC has issued a series of orders that have significantly altered the marketing and transportation of natural gas. Such orders mandated a fundamental restructuring of interstate pipeline sales and transportation services, 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 we cannot predict what action the FERC or other regulatory agencies will take in the future, we do not believe that we will be treated materially differently than other natural gas producers and marketers with which we compete.

Our 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. We believe our operations, to the extent they may be subject to current gas pipeline safety requirements, comply in all material respects with such requirements. We cannot predict what effect, if any, the adoption of this or other additional pipeline safety legislation might have on our 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 have the potential to limit the rate at which oil and gas can be produced from our properties. However, we do not believe Wiser 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 us 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

Our 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 our operations. The permits required for our 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, we are in substantial compliance with current applicable environmental laws and regulations, and we have 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 us. The impact of such changes, however, would not likely be any more burdensome to us 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.

We generate typical oil and gas field wastes, including, in limited circumstances, 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 our 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.

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Our 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.

We own, lease or operate numerous properties that for many years have produced or processed oil and gas. We also own and operate natural gas gathering, transportation and processing systems. It is not uncommon for such properties to be contaminated with hydrocarbons or polychlorinated biphenyls. Although we 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 us to remove any such wastes or to remediate the resulting contamination. In addition, some of our properties are operated by third parties we have no control over. Regardless of our 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 us.

Abandonment Costs

We are responsible for payment of well plugging and abandonment costs on our oil and gas properties pro rata to our working interest. Based on our experience, we anticipate that the ultimate aggregate salvage value of lease and well equipment located on our onshore properties will substantially offset the costs of abandoning such properties. Abandonment costs for our Gulf of Mexico properties are significantly higher than our onshore properties and offshore abandonment costs significantly exceed the salvage value. There can be no assurance, however, that we will be successful in avoiding additional expenses in connection with the abandonment of any of our 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 Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations,” we estimate future abandonment costs are $7.0 million at December 31, 2003. See Note 1 to our Consolidated Financial Statements.

Employees

At March 8, 2004, we employed 81 full-time employees; six were executive officers, 48 were professional and administrative personnel and 27 were field personnel. Of the total employees, 56 were located in the United States and 25 were located in Canada. At March 8, 2004, none of our employees were represented by a labor union. We consider our relations with our employees to be good.

Facilities

Our principal executive and administrative office is located at 8115 Preston Road, Suite 400, Dallas, Texas. The office contains approximately 16,600 square feet of space and is leased through June 30, 2008. Rental payments are approximately $22,000 per month. On February 1, 2004, we leased an additional 4,775 square feet of office space at the same location through February 28, 2007. Commencing March 1, 2004, rental payments for this additional space are approximately $7,000 per month for 2004 and escalate to approximately $8,400 per month for the remainder of the lease. The office of our 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 April 30, 2008. Rental payments are approximately $14,000 per month.

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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.

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

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

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

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

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

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

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

“gas” means natural gas.

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

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

“MBbl” means thousand Bbls.

“MBOE” means thousand BOE.

“Mcf” means thousand cubic feet.

“MMBOE” means million BOE.

“MMBtu” means one million British Thermal Units. British Thermal Unit means the quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.

“MMcf” means million cubic feet.

“net” when used with respect to acres or wells, refers to gross acres or wells multiplied, in each case, by the percentage working interest owned by us.

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“net production” means production that is owned by us 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.

“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.

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“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

We and our 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 our financial position.

We have filed proofs of claims against Enron North America (“ENA”) and Enron Corporation (jointly, “Enron”) to collect the $6.9 million owed us under hedging contracts, calculated as of the Enron Chapter 11 Petition Date. Based on the uncertainty of collecting this amount from Enron, we 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 us 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 has developed. Periodically, we have discussed with several market participants selling our claims, but none are currently active. Any proceeds received from the sale of our claims will be recognized in the year received.

In January 2002 we were notified by a gas marketing company that it would not pay approximately $730,000 owed to Wiser for our November 2001 gas sales because the gas marketing company claimed it had not been paid by Enron Corporation. We filed suit against the gas marketing company in 2002 to recover the $730,000 plus court costs. In 2003 we received approximately $280,000 from the gas company as a by-product of a settlement it reached with Enron on a number of claim items. The remaining suit amount is the subject of cross motions for summary judgment. While we believe the amount is owed to Wiser, we cannot at this point predict the litigation outcome.

We purchased tubing and casing from Trident Steel, a pipe-distributing company, for use at our West Texas Wellman Unit and in the drilling of a South Texas exploratory well. With only limited use, the tubing and surface casing generally became unusable. We requested relief from Trident, and when none was offered we brought suit in Terry County. A trial was conducted in January, 2004 and resulted in a jury verdict favorable to us. Judgment has yet to be entered but the aggregate jury findings total in excess of $900,000. We have not recognized a receivable for this amount in our December 31, 2003 Consolidated Balance Sheet because Trident Steel may appeal the judgment.

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, 2003.

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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. During December 2002, the New York Stock Exchange (“NYSE”) informed us that our total market capitalization and our stockholders’ equity had fallen below the NYSE’s continued listing standards. During December 2003, the NYSE informed us that we were back in compliance with the NYSE’s continued listing standards. See Item 7 – “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Other Matters” for additional information regarding compliance with the NYSE’s continued listing standards.

The quarterly high and low sales prices per share of Common Stock during the two years ended December 31, 2003, were as follows:

At March 5, 2004, there were 15,470,007 shares of Common Stock outstanding held by approximately 608 shareholders of record and approximately 4,250 beneficial owners.

There were no dividends declared on the Common Stock for the two years ended December 31, 2003. Our Board of Directors suspended payments of cash dividends on our Common Stock as part of a cost reduction plan instituted in December 1998.

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

Recent Sales of Unregistered Securities

On December 13, 1999, the Board of Directors approved the sale of not less than 600,000 shares and not more than 1,000,000 shares of Series C Cumulative Convertible Preferred Stock (“preferred stock”) through a private placement exempt from registration under section 4(2) of the Securities Act of 1933, as amended (the “Securities Act”) at $25.00 per share. The sale of preferred stock was approved by our shareholders on May 16, 2000, and 600,000 shares were issued to Wiser Investment Company, LLC (“WIC”) and another investor on May 26, 2000 for $15 million. On June 1, 2001, we sold an additional 396,000 shares of preferred stock to Wiser Investors, L.P., a Delaware limited partnership (“Investors”) for $9.9 million, and 4,000 shares of preferred stock to A. Wayne Ritter for $100,000. WIC is the general partner of Investors. The preferred stock paid quarterly dividends in cash or in shares of our common stock, at our option, at an annual rate of 7%. From the date the preferred stock was issued until May 26, 2003, the mandatory conversion date of the preferred stock, the holders of preferred stock were issued 541,726 shares of common stock as dividends. The holders of the preferred stock had the same voting rights as the holders of our common stock with each share of the preferred stock having one vote for each share of common stock into which it is convertible. We received $23.7 million in net proceeds from the sale of preferred stock in May 2000 and June 2001.

On May 26, 2003, the preferred stock converted into 5,882,353 shares of common stock based on a conversion price of $4.25 per share. Accordingly, there will be no preferred stock dividends payable on the preferred stock after May 26, 2003. The common stock issued upon the conversion of the preferred stock and as dividends on the preferred stock has not been registered under the Securities Act and may not be offered or sold except pursuant to a registration statement under the Securities Act or an exemption thereto and is subject to certain restrictions on transfer described in the legends on the certificates.

In addition, WIC acquired warrants to purchase 741,716 shares of our common stock at $4.25 per share. The purchase price of the warrants is $0.02 per warrant. The warrants became exercisable on May 26, 2002 and will expire on May 26, 2007.

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Item 6. Selected Financial Data

The following selected consolidated financial data for each of the five years in the period ended December 31, 2003 are derived from information contained in our Consolidated Financial Statements. The selected consolidated financial and operating data presented below should be read in conjunction with Item 7. – “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our Consolidated Financial Statements and the related notes included in this Form 10-K. For additional information about accounting changes, see Item 7. – “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Critical Accounting Policies” and Note 1 to the financial statements describing our change of method of accounting for asset retirement obligations and derivative instruments and hedging transactions, effective January 1, 2003 and January 1, 2001, respectively. For additional information about business combinations, see Note 3 to the financial statements, describing our acquisition of Invasion Energy Inc. For additional information on property sale gains, see Item 7. – “Management’s Discussion and Analysis of Financial Condition and Results of Operations” describing the Asset Exchange Agreement entered into between Wiser Canada and Talisman Energy, Inc. dated June 29, 2001.