-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, Rnd+FkZeb/OgkUtQ91A+if5wMMOrCYPc9YJyRW4/7pYq//DO5BneSS2wiv4kq04K onruDgeu8cBn8wxevcYZDA== 0000930661-00-000932.txt : 20000413 0000930661-00-000932.hdr.sgml : 20000413 ACCESSION NUMBER: 0000930661-00-000932 CONFORMED SUBMISSION TYPE: 10-K405 PUBLIC DOCUMENT COUNT: 8 CONFORMED PERIOD OF REPORT: 19991231 FILED AS OF DATE: 20000412 FILER: COMPANY DATA: COMPANY CONFORMED NAME: WISER OIL CO CENTRAL INDEX KEY: 0000107874 STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311] IRS NUMBER: 550522128 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K405 SEC ACT: SEC FILE NUMBER: 001-12640 FILM NUMBER: 599460 BUSINESS ADDRESS: STREET 1: 8115 PRESTON RD STE 400 CITY: DALLAS STATE: TX ZIP: 75225 BUSINESS PHONE: 2142650080 MAIL ADDRESS: STREET 1: 8115 PRESTON ROAD STREET 2: SUITE 400 CITY: DALLAS STATE: TX ZIP: 75225 10-K405 1 FORM 10-K405 ================================================================================ SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 _____________ FORM 10-K ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 1999 Commission file number 0-5426 THE WISER OIL COMPANY A DELAWARE CORPORATION _____________ I.R.S. EMPLOYER IDENTIFICATION NO. 55-0522128 8115 PRESTON ROAD, SUITE 400 DALLAS, TEXAS 75225 TELEPHONE: (214) 265-0080 Securities registered pursuant to Section 12(b) of the Act: Name of exchange on Title of each class which registered ------------------- ----------------------- Common Stock-Par Value, $3.00 Per Share New York Stock Exchange Preferred Stock Purchase Rights New York Stock Exchange Indicate by check mark whether registrant has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months, and has been subject to such filing requirements for the past 90 days. X. --- Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. X. --- As of February 24, 2000, registrant had outstanding 8,951,965 shares of common stock, $3.00 par value ("Common Stock"), which is registrant's only class of common stock. The aggregate market value of registrant's Common Stock held by non-affiliates based on the closing price on February 24, 2000 was approximately $21.8 million. DOCUMENTS INCORPORATED BY REFERENCE (Specific incorporations are identified under the applicable item herein.) Portions of the registrant's proxy statement furnished to stockholders in connection with the 2000 Annual Meeting of Stockholders (the "Proxy Statement") are incorporated by reference in Part III of this Report. The Proxy Statement will be filed with the Securities and Exchange Commission within 120 days of the close of the registrant's fiscal year. ================================================================================ TABLE OF CONTENTS DESCRIPTION
Item Page - ---- ---- PART I 1. BUSINESS.............................................................. 3 2. PROPERTIES............................................................ 25 3. LEGAL PROCEEDINGS..................................................... 25 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS................... 25 PART II 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS............................................................. 26 6. SELECTED FINANCIAL DATA............................................... 27 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS............................................... 29 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA........................... 38 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE................................................ 38 PART III 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.................... 39 11. EXECUTIVE COMPENSATION................................................ 39 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.......................................................... 39 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS........................ 39 PART IV 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K....... 39
2 THE WISER OIL COMPANY PART I Item 1. Business General Founded in 1905, The Wiser Oil Company (the "Company" or "Wiser") is one of the oldest public independent oil and gas companies in the United States. The Company's total proved reserves at December 31, 1999 are 37.1 MMBOE (approximately 69% of which were oil and NGLs), and its annual net production in 1999 was 3.6 MMBOE. The Company's primary operations, representing approximately 62% of its proved reserves at December 31, 1999, are located in the Permian Basin in West Texas and Southeast New Mexico. Wiser has additional operations in Alberta, Canada and the San Juan Basin in New Mexico. Prior to 1991 the Company focused primarily on the acquisition of non-operated interests in oil and gas properties. In 1991 the Company moved its headquarters from Sistersville, West Virginia to Dallas, Texas and began to assemble a team of experienced management with substantial acquisition, exploitation and development expertise. After reviewing the Company's existing property portfolio and refining the new business strategy, the management team began disposing of the Company's non-strategic assets and acquiring and operating properties in new core areas with the potential for increased reserves and production volumes. Pursuant to this strategy, the Company acquired and developed properties in the Permian Basin and Canada, and added reserves and production through workovers, recompletions, waterfloods and CO2 gas injections, as well as the drilling of exploratory, development and infill wells. A substantial portion of the Company's growth in reserves and production volumes since 1991 has been the result of (i) two enhanced oil recovery projects on properties acquired from 1992 to 1996 in the Permian Basin and (ii) the Company's 1994 acquisition and subsequent exploration on and exploitation of properties in Alberta, Canada. From June 1993 through December 1999, the Company completed 168 producing wells on its Maljamar waterflood project in Southeast New Mexico. As a result, the Company's average daily net production from the three units in this project increased to 1,781 BOE in 1999 from 580 BOE in January 1993 (on a pro forma combined basis, assuming the Company had acquired all three units at January 1, 1993). At its Wellman Unit in West Texas, the Company used CO2 gas injection to increase average daily net production to 1,078 BOE in 1999 from 650 BOE in December 1993. In June 1994 the Company acquired oil and gas properties located primarily in Alberta, Canada for $52.0 million. From the date of their acquisition through December 1999, the Company completed 60 net wells on these properties. As a result, the Company's average daily net Canadian production increased to 3,184 BOE in 1999 from 1,860 BOE in June 1994. The Company's principal executive offices are located at 8115 Preston Road, Suite 400, Dallas, Texas 75225, and its telephone number is (214) 265-0080. Certain oil and gas industry terms used herein are defined in the "Glossary of Oil and Gas Terms" appearing at the end of this Item 1. 3 Principal Oil and Gas Properties The following table summarizes certain information with respect to each of the Company's principal areas of operation at December 31, 1999.
Proved Reserves --------------------------------------- 1999 Total Total Percent Average Gross Oil Proved of Total Net Oil and and NGLs Gas Reserves Proved Production Gas Wells (MBbls) (MMcf) (MBOE) Reserves (BOE/Day) ----------- --------- ------- --------- --------- ----------- Permian Basin Maljamar............. 208 10,377 2,937 10,867 29% 1,781 Wellman.............. 14 8,747 735 8,869 24% 1,078 Dimmitt/Slash Ranch.. 82 1,826 9,675 3,439 9% 894 ----- ------ ------ ------ --- ----- Total.............. 304 20,950 13,347 23,175 62% 3,753 San Juan Basin......... 2,400 45 18,888 3,193 9% 1,129 Other (1).............. 114 501 13,928 2,822 8% 1,910 ----- ------ ------ ------ --- ----- Total United States.... 2,818 21,496 46,163 29,190 79% 6,792 Canada................. 285 3,934 23,830 7,905 21% 3,184 ----- ------ ------ ------ --- ----- Total Company.......... 3,103 25,430 69,993 37,095 100% 9,976 ===== ====== ====== ====== === =====
(1) Other 1999 Average Net Production includes production from properties that were sold in the second quarter of 1999. Permian Basin Maljamar. The Company's Maljamar properties are situated in Southeast New Mexico. At December 31, 1999, the Maljamar properties contained 10.9 MMBOE of proved reserves, which represented 29% of the Company's total proved reserves and 27% of the Company's Present Value of total proved reserves. The Maljamar properties consist primarily of three oil producing units acquired by the Company in separate transactions between 1992 and 1996: the Maljamar Grayburg and Caprock Maljamar Units, both of which are in Lea County, New Mexico, and the Skelly Unit in Eddy County, New Mexico. The Maljamar Grayburg Unit produces from the Grayburg and San Andres formations at depths ranging from 3,800 to 4,500 feet, and the Caprock Maljamar Unit produces from the same formations at depths ranging from 4,000 to 5,000 feet. The Skelly Unit is located approximately five miles west of the two Lea County units and produces from the Seven Rivers, Grayburg and San Andres formations at depths ranging from 2,100 to 4,000 feet. The Company has a 100% working interest in each of these units, which, along with some smaller adjacent properties, have been combined into a single large scale waterflood project encompassing approximately 14,000 [see acreage table on page 15] gross leasehold acres. Exploitation efforts at the project are essentially complete and included conversion of existing wells to injection wells and the drilling of infill development wells on 20-acre spacing to create 40-acre five-spot water injection patterns. From June 1, 1993 through December 31, 1999, the Company made capital expenditures of approximately $75 million and completed 168 producing wells at the project. At December 31, 1999, the project included 208 producing wells and 163 water injection wells, virtually all of which were operated by the Company. No new wells were placed on production in 1999. The Company's net production from the Maljamar properties averaged 1,624 Bbls of oil, 45 Bbls of NGLs and 674 Mcf of natural gas per day in 1999. The Company's cumulative net production from the Maljamar properties since acquired by the Company has been 3,764 MBbls of oil and 1.9 Bcf of natural gas through December 31, 1999. 4 Wellman Unit. In 1993 the Company acquired a 62% working interest in and became operator of the Wellman Unit in Terry County, Texas, located in the northwestern edge of the Horseshoe Atoll. During 1998 and 1999, the Company acquired an additional 28% and 5% working interest, respectively, in the Wellman Unit which increased the Company's working interest to 95% as of December 31, 1999. At December 31, 1999, the Company's Wellman property contained 8.9 MMBOE of proved reserves, which represented 24% of the Company's total proved reserves and 22% of the Company's Present Value of total proved reserves. The Company owns approximately 2,300 gross (2,150 net) leasehold acres in the Wellman Unit. The Wellman Unit produces oil from the Wolfcamp Reef formation at depths ranging from 9,100 to 10,000 feet through the injection of water and CO2 into the reservoir. Water injection at the unit began in 1979, and CO2 injection began in 1983. The unit also includes a gas processing plant, which processes wellhead gas produced from the unit. Wiser's interest in this plant is proportionate to its working interest in the Wellman Unit. Processing at the plant involves subjecting the wellhead gas to high pressure and low temperature treatments that cause the gas to separate into various products, including NGLs, residual natural gas and CO2. The NGLs and residual natural gas are sold to pipeline companies, and the CO2 is reinjected into the unit's reservoir. At December 31, 1999, the unit included 14 productive wells, two water injection wells, three CO2 injection wells and three water disposal wells, all of which were operated by the Company. The Company's net production from the Wellman Unit averaged 672 Bbls of oil, 378 Bbls of NGLs and 166 Mcf of natural gas per day in 1999. The Company's cumulative net production from the unit since acquired by the Company has been 2,046 MBbls of oil, 739 MBbls of NGLs and 482 MMcf of natural gas through December 31, 1999. In 1994 the Company began reconditioning the gas processing plant at the Wellman Unit to enhance the extraction of NGLs and residual natural gas from the wellhead gas. The Company completed the reconditioning project in June 1995 at a total cost of approximately $6.0 million. For the year ended December 31, 1999, the gas plant processed an average of 31 MMcf of gross natural gas and CO2 per day and recovered an average of 452 Bbls of NGLs and 199 Mcf of residual natural gas per day. The plant currently operates at 89% of its maximum capacity of 35 MMcf of gas per day. Dimmitt/Slash Ranch Fields. The Company's Dimmitt/Slash Ranch properties are situated in Loving County, Texas, 80 miles west of Midland, Texas. At December 31, 1999, the Dimmitt/Slash Ranch properties contained 3.4 MMBOE of proved reserves, which represented 9% of the Company's total proved reserves and 9% of the Company's Present Value of total proved reserves. The Company owns approximately 4,650 gross (4,130 net) leasehold acres in the Dimmitt Field, and has working interests in this acreage ranging from 75% to 100%. The Company acquired its initial interest in and became operator of the field in 1993. The Dimmitt Field produces oil and gas from the Cherry Canyon and Bell Canyon formations at depths ranging from 4,700 to 6,700 feet. At December 31, 1999, the field included 78 productive wells. The Slash Ranch Field is a natural gas field that underlies the Dimmitt Field. The Company owns approximately 2,850 gross (2,350 net) leasehold acres in the Slash Ranch Field. The Slash Ranch Field produces from the Atoka, Fusselman and Ellenburger formations at depths ranging from 15,000 to 20,000 feet. At December 31, 1999, the field included four producing wells, all of which were operated by the Company. The Company's working interests in these wells range from 34% to 100%. The Company's net production from the Dimmitt/Slash Ranch properties averaged 391 Bbls of oil and 3,020 Mcf of natural gas per day in 1999. The Company's cumulative net production from the properties since acquired by the Company has been 759 MBbls of oil and 6.1 Bcf of natural gas through December 31, 1999. 5 San Juan Basin The Company's San Juan Basin properties are located in Rio Arriba County in northwestern New Mexico. At December 31, 1999, the San Juan Basin properties contained 3.2 MMBOE of proved reserves, which represented 9% of the Company's total proved reserves and 6% of the Company's Present Value of total proved reserves. The Company owns approximately 11,000 gross (6,000 net) [see acreage table on leasehold acres in the San Juan Basin. The Company's average 48% working interest in most of the acreage was contributed in connection with a unitization of the wells in the San Juan Basin fields in the 1950's, resulting in the ownership by the Company of small non-operated working interests in several large units. At December 31, 1999, the Company owned working interests in approximately 2,400 producing gas wells in the San Juan Basin. These working interests range from 0.26% to 50.0% and average approximately 1.8%. The Company's San Juan Basin properties produce from multiple formations ranging from depths of 3,000 feet to 8,000 feet. The Company's net production from these properties averaged 6,370 Mcf of natural gas and 67 Bbls of oil per day in 1999. During the year ended December 31, 1999, approximately 26% of the Company's net production from these properties was from the Fruitland Coal seams. Such production generates nonconventional fuels income tax credits for Wiser under Section 29 of the Internal Revenue Code of 1986, as amended. The Company expects that future development of the properties will depend on natural gas prices, and that its share of the costs of any such future development activities will not be significant. Other U.S. Properties The Company's other United States properties include properties located in the West Texas, New Mexico and the Gulf Coast onshore region. Canada In June 1994, Wiser established an important new core area with the completion of a $52.0 million acquisition of Canadian oil and gas properties from Eagle Resources, Ltd. The purchase included 7.2 MMBOE of proved reserves, approximately 127,000 net undeveloped acres, seven exploration prospects and an existing staff of 23 persons. At December 31, 1999, the Company's Canadian properties contained 7.9 MMBOE of proved reserves, which represented 21% of the Company's total proved reserves and 28% of the Present Value of the Company's total proved reserves. The following table summarizes certain information with respect to each of the Company's principal Canadian areas of operation at December 31, 1999:
Proved Reserves ---------------------------------------- Percent 1999 Total Total of Total Average Gross Oil Proved Canadian Net Oil and and NGLs Gas Reserves Proved Production Gas Wells (MBbls) (MMcf) (MBOE) Reserves (BOE/Day) --------------- --------- ------- --------- --------- ----------- Evi........... 14 1,666 -- 1,666 21% 758 Provost....... 71 805 1,029 977 12% 547 Pine Creek.... 9 219 2,467 630 8% 174 Portage....... 14 -- 3,047 508 6% 411 Elm........... 6 276 1,044 450 6% 98 Other......... 171 968 16,243 3,674 47% 1,196 --- ----- ------ ----- --- ----- Total Canada.. 285 3,934 23,830 7,905 100% 3,184 === ===== ====== ===== === =====
6 Evi. The Company's Evi Field is located approximately 400 miles north of Calgary. At December 31, 1999, the Evi Field contained 1,666 MBOE of proved reserves, which represented 21% of the Company's total Canadian proved reserves and 33% of the Present Value of the Company's total Canadian proved reserves. The Company owns approximately 6,560 gross (3,400 net) leasehold acres in the Evi Field, and has an average 42% working interest in this acreage. The Evi Field produces oil from the Granite Wash formation at depths ranging from 4,900 to 5,000 feet. The Company's net production from the Evi Field averaged 758 Bbls of oil per day in 1999. At December 31, 1999, the Company owned 14 gross (4.3 net) productive wells and 2 gross (0.7net) water disposal wells in the field, of which 11 productive wells and both water disposal wells were operated by Wiser. Provost. The Company's Provost properties are located approximately 210 miles northeast of Calgary. At December 31, 1999, the Provost properties contained 977 MBOE of proved reserves, which represented 12% of the Company's total Canadian proved reserves and 17% of the Present Value of the Company's total Canadian proved reserves. The Company owns approximately 7,010 gross (5,080 net) leasehold acres in the Provost properties, and has an average 65% working interest in this acreage. The Provost properties produce mainly from the Dina formation at depths of 3,070 to 3,170 feet. The Provost Dina `X' and Cummings W3W Pools are the Company's main producing pools in these properties and water injection in these pools began in 1990 and 1998, respectively. The Company drilled 1 well in the Provost properties in 1999 and plans to drill 9 additional wells in Provost in 2000. The Company's net production from the Provost properties averaged 527 Bbls of oil per day and 118 Mcf of natural gas per day in 1999. At December 31, 1999, the Company owned 71 gross (48.8 net) productive wells and 5 gross (3.5 net) water injection wells on the properties, of which 54 gross productive wells and all five water injection wells were operated by the Company. 7 Pine Creek. The Company's Pine Creek properties are located approximately 240 miles northwest of Calgary. At December 31, 1999, the Pine Creek properties contained 630 MBOE of proved reserves, which represented 8% of the Company's total Canadian proved reserves and 6% of the Present Value of the Company's total Canadian proved reserves. The Company owns approximately 10,400 gross (2,860 net) leasehold acres in the Pine Creek properties, and has a 27% working interest in this acreage. The Pine Creek properties produce gas from the Bluesky and Gething formations at depths of 8,000 to 8,200 feet. At December 31, 1999, the Company owned 9 gross (2.3 net) productive wells in the Pine Creek properties, all of which were operated by a third party. The Company's net production from the Pine Creek properties averaged 413 Mcf of natural gas per day and 105 Bbls of NGLs per day in 1999. Portage. The Company's Portage properties are located approximately 350 miles northeast of Calgary. At December 31, 1999, the Portage properties contained 508 MBOE of proved reserves, which represented 6% of the Company's total Canadian proved reserves and 4% of the Present Value of the Company's total Canadian proved reserves. The Company owns approximately 19,200 gross (11,490 net) leasehold acres in the Portage properties, and has an average 60% working interest in this acreage. The Portage properties produce from the Grand Rapids and Nisku formations at depths of 850 and 1,400 feet, respectively. At December 31, 1999, the Company owned 14 gross (11.5 net) productive wells, 11 of which were operated by Wiser. The Portage properties commenced production in March 1998 and net production from the Portage properties averaged 2,463 Mcf of natural gas per day in 1999. Elm. The Company's Elm properties are located approximately 500 miles northwest of Calgary in British Columbia. At December 31, 1999, the Elm properties contained 450 MBOE of proved reserves, which represented 6% of the Company's total Canadian proved reserves and 6% of the Present Value of the Company's total Canadian proved reserves. The Company owns approximately 13,460 gross (4,660 net) leasehold acres in the Elm properties, and has an average 50% working interest in this acreage. The Elm properties produce from the Gething formation at depths of 4,000 to 4,100 feet. At December 31, 1999, the Company owned 6 gross (3.0 net) productive wells, all of which were operated by Wiser. The Company's net production from the Elm properties averaged 51 Bbls of oil per day and 279 Mcf of natural gas per day in 1999. Other Canadian Properties. The Company owns interests in approximately 30 other Canadian properties, primarily located in its principal areas of operation. For the year ended December 31, 1999, these properties individually represented less than 7%, and in the aggregate represented approximately 47%, of the Company's total Canadian proved reserves. Exploration Activities United States The objective of Wiser's domestic exploration program is to generate exploration and exploitation drilling opportunities that have the potential of replacing produced reserves and providing a vehicle of growth for the Company. In 1999 the Company's US exploration efforts were significantly reduced from the previous year, due to depressed oil and gas prices in late 1998 and early 1999. Wiser's US exploration drilling efforts were initiated mid-year, and focused on low risk, South Texas Frio gas prospects. All wells drilled were internally generated and based on proprietary 3-D seismic surveys. 8 In 1999, Wiser participated in 8 gross (3.7 net) US exploration wells, compared with 29 gross (18 net) wells in 1998, spending $1.1 million in 1999 and $10.5 million in 1998 on US exploration. Of the 8 gross wells drilled by the Company in 1999, 6 were completed as gas wells, and 2 were unsuccessful, which yields a 75% US exploration success rate in 1999. In 2000, Wiser plans to drill approximately 15 gross wells in the US and the Company has budgeted approximately $4.0 million for its 2000 US exploration program. The Company is currently focusing its US exploration activities in the following geographical areas: South Texas. At the Roche Ranch prospect in Refugio County, the Company drilled 7 gross wells in 1999 of which 6 were completed as new gas field discoveries. The Company operates and has a 40% working interest in the Roche Ranch prospect. The primary objectives are Frio gas sands at a depth of 5,000 to 7,000 feet, which are defined utilizing proprietary 3-D seismic surveys. The Company plans to drill six exploration wells in the Roche Ranch prospect in 2000. Wiser also operates and has a 40% working interest in the Fitzsimmons prospect in Jim Wells County. Utilizing proprietary 3-D seismic surveys, the Company has identified several Frio and Yegua gas sand objectives at depths of 5,000 to 8,500 feet, respectively. Although no wells were drilled in this prospect in 1999, the Company plans to drill an exploratory well to approximately 8,200 feet to test the Yegua gas sand objective in 2000. The Company has recently acquired a 30% non-operating working interest in the Menefee prospect in Wharton County. Wiser plans to participate in drilling three to four wells in the Menefee prospect in 2000 which target high pressured Yegua gas sands at depths of 7,800 to 8,700 feet. The Yegua objective has been defined using 3-D seismic surveys. The first Menefee prospect exploration well, the Kathleen Appling GU #1, was drilled in February 2000 to approximately 8,600 feet and is currently being completed as a Yegua gas discovery well. At Welder Ranch in Refugio County, the Company drilled and abandoned one well in 1999. The Company does not anticipate any further exploration activity at Welder Ranch at this point in time. West Texas. Wiser has sold a portion of its working interest in both the Indian Mesa and Panther Bluff prospects in Pecos County and now has a carried interest in these prospects. The Indian Mesa and Panther Bluff prospects do not meet the Company's exploration objectives at this time. Gulf Coast. At the Little Crow prospect in Wilkinson County, Mississippi, the T.O.Sessions #1 exploration well was drilled to a total depth of 13,834 ft. The Cretaceous Tuscaloosa "A" sands are currently being production tested. Wiser has a 50% non-operating working interest in this prospect. The Company has reprocessed and interpreted the 3-D seismic survey data acquired at the Castleberry prospect in Conecuh County, Alabama, and is planning to drill the first exploration well on this prospect in 2000. The primary objectives are Jurassic, Lower Haynesville sands, which produce nearby in the Frisco City area. The first exploration well will be drilled to approximately 12,500 feet and is based on a 32 square mile 3-D seismic survey. Wiser operates and has a 50% working interest in the Castleberry prospect. Several other prospects have also been defined near the Castleberry prospect. 9 Canada Wiser focuses its Canadian exploration activities in specific regions within the Western Canadian Sedimentary Basin in close proximity to known producing horizons where the potential for significant reserves exists. The Company's technical personnel have considerable experience in this focus area. During 1999, the Company drilled one gross (one net) exploratory well which was a successful gas well. The Company spent $3.6 million on exploration in Canada in 1999 and has budgeted $2.8 million for its 2000 Canadian exploration program. The Company is currently focusing its Canadian exploration activities in the following geographical area: West Central Alberta. In 1999, the Company successfully completed the Wiser/Mobil Wild River 6-33 exploratory well at the Wild River prospect which added 352 MBOE to the Company's total proved reserves. The Wild River 6-33 well started production in January 2000 at an average rate of 500 Mcf per day. Wiser operates and has a 50% working interest in the well. The Company completed a 21 square mile 3-D seismic survey in the Wild River prospect in February 2000 and purchased an additional 1,280 acres of undeveloped leasehold acreage in March 2000. Wiser plans to drill one well in 2000 in the Wild River prospect. In 1999, the Company utilized 3-D seismic survey data to identify a possible Granite Wash formation trap in the Evi North prospect located 1 mile north of the Evi Field. Wiser operates and has a 100% working interest in the Evi North prospect and plans to drill 1 exploratory well in 2000 in the Evi North prospect International The Company did not participate in any international exploration activity in 1999 and currently has no plans to participate in future international exploration activities. Marketing of Production The Company markets its production of oil, natural gas and NGLs to a variety of purchasers, including large refiners and resellers, pipeline affiliate marketers, independent marketers, utilities and industrial end-users. To help manage the impact of potential price declines, Wiser has developed a portfolio of long- and short-term contracts with prices that are either fixed or related to market conditions in varying degrees. Most of the Company's production is sold pursuant to contracts that provide for market-related pricing for the areas in which the production is located. During the year ended December 31, 1999, revenues from the sale of production to Highland Energy Company, CXY Energy Marketing and EOTT Energy Operating Ltd. represented approximately 41%, 11% and 10%, respectively, of the Company's total oil and gas revenues. The Company believes it would be able to locate alternate purchasers in the event of the loss of any one or more of these purchasers, and that any such loss would not have a material adverse effect on the Company's financial condition or results of operations. Crude Oil. The Company sells its crude oil and condensate to various refiners and resellers in the United States and Canada at posting-related and spot- related prices that also depend on factors such as well location, production volume and product quality. The Company typically sells its crude oil and condensate production at or near the well site, although in some cases it is gathered by the Company or others and delivered to a central point of sale. The Company's crude oil and condensate production is transported by truck or by pipeline and is typically committed to arrangements having a term of one year or less. The Company has not engaged in crude oil trading activities. Revenue from the sale of crude oil and condensate totaled $25.6 million for the year ended December 31, 1999 and represented 54% of the Company's total oil and gas revenues for 1999. From time to time, the Company enters into crude oil and natural gas price hedges to reduce its exposure to commodity price fluctuation. See Item 7A - "Quantitative and Qualitative Disclosures about Market Risk - 10 Commodity Price Risk" and Note 1 to the Company's Consolidated Financial Statements included elsewhere in this Report. Natural Gas. The Company sells its produced natural gas and gathered gas to utilities, marketers, processor/resellers and industrial end-users primarily under market-sensitive, long-term contracts or daily, monthly or multi-month spot agreements. An insignificant amount of the Company's natural gas is committed to long-term, fixed-price sales agreements. To accomplish the delivery and sale of certain of its natural gas, the Company has entered into long-term agreements with various natural gas gatherers that deliver its gas to points of sale on major transmission pipelines. The Company believes that it has sufficient production from its properties, and from those of others tied to its gathering and transportation system, to meet the Company's delivery obligations under its existing natural gas sales contracts. NGLs. From its natural gas processing plants in West Texas, the Company sells NGLs to independent marketers for resale. A direct pipeline connection to the Texas Gulf Coast market area facilitates the sale of NGLs from the Company's Wellman Unit, and enables the Company to receive prices that are representative of the daily market value of NGLs on the Texas Gulf Coast, less transportation and fractionation costs. The Company's average price in 1999 for NGLs sold from Company-operated plants or under processing agreements with others was $13.01 per Bbl. Prices for NGLs attributable to natural gas sold to plants operated by others are generally included in the prices reported by the Company for the sale of its natural gas. Price Considerations. Crude oil prices are established in a highly liquid, international market, with average crude oil prices received by the Company generally fluctuating with changes in the futures price established on the NYMEX for West Texas Intermediate Crude Oil ("NYMEX-WTI"). The average crude oil price per Bbl received by the Company in 1999 was $15.18. The average NYMEX-WTI closing price per Bbl for 1999 was $19.24. Natural gas prices in each of the geographical areas in which the Company operates are closely tied to established price indices which are heavily influenced by national and regional supply and demand factors and the futures price per MMBtu for natural gas delivered at Henry Hub, Louisiana established on the NYMEX ("NYMEX-Henry Hub"). At times, these indices correlate closely with the NYMEX-Henry Hub price, but often there are significant variances between the NYMEX-Henry Hub price and the indices used to price the Company's natural gas. Average natural gas prices received by Wiser in each of its operating areas generally fluctuate with changes in these established indices. The average natural gas price per Mcf received by the Company in 1999 was $1.83. The average NYMEX-Henry Hub price per MMBtu for 1999 was $2.27, computed by averaging the closing price on the last three trading days of each month of the forward prompt month NYMEX natural gas futures contract price applicable to each month in 1999. The average natural gas price received by the Company in 1999 was lower than such 1999 NYMEX-Henry Hub price as a result of pricing differentials determined by the location of the Company's natural gas production relative to the Henry Hub trading point and lower natural gas prices generally applicable to Canadian natural gas production relative to U.S. production. 11 Oil and Gas Reserves The following table sets forth the proved developed and undeveloped reserves of the Company at December 31, 1999:
Oil and NGLs (MBbls) Gas (Mmcf) Total Reserves (MBOE) ------------------------------ ------------------------------ ------------------------------ Developed Undeveloped Total Developed Undeveloped Total Developed Undeveloped Total --------- ----------- ----- --------- ----------- ----- --------- ----------- ----- Permian Basin Maljamar................. 9,444 933 10,377 2,849 88 2,937 9,919 948 10,867 Wellman.................. 8,747 -- 8,747 735 -- 735 8,869 -- 8,869 Dimmitt/Slash Ranch...... 1,600 226 1,826 9,226 449 9,675 3,138 301 3,439 ------ ----- ------ ------ ----- ------ ------ ----- ------ Total.................. 19,791 1,159 20,950 12,810 537 13,347 21,926 1,249 23,175 San Juan Basin............. 37 8 45 17,375 1,513 18,888 2,933 260 3,193 Other...................... 499 2 501 13,586 342 13,928 2,763 59 2,822 ------ ----- ------ ------ ----- ------ ------ ----- ------ Total United States........ 20,327 1,169 21,496 43,771 2,392 46,163 27,622 1,568 29,190 Canada..................... 3,719 215 3,934 22,813 1,017 23,830 7,521 384 7,905 ------ ----- ------ ------ ----- ------ ------ ----- ------ Total Company.............. 24,046 1,384 25,430 66,584 3,409 69,993 35,143 1,952 37,095 ====== ===== ====== ====== ===== ====== ====== ===== ======
The following table summarizes the Company's proved reserves, the estimated future net revenues from such proved reserves and the Present Value and Standardized Measure of Discounted Future Net Cash Flows attributable thereto at December 31, 1999, 1998 and 1997:
At December 31, ----------------------------------------- 1999 1998 1997 -------- -------- -------- (000's except weighted average sales prices) Proved reserves: Oil and NGLs (Bbl).................................... 25,430 27,988 29,721 Gas (Mcf)............................................. 69,993 119,981 120,094 BOE.................................................. 37,095 47,985 49,737 Estimated future net revenues before income taxes..... $419,668 $218,969 $359,293 Present Value......................................... $222,539 $123,831 $210,087 Standardized Measure(1)............................... $176,916 $113,232 $174,489 Proved developed reserves: Oil and NGLs (Bbl).................................... 24,046 26,954 28,202 Gas (Mcf)............................................. 66,584 110,346 109,459 BOE.................................................. 35,143 45,345 46,444 Estimated future net revenues before income taxes..... $395,749 $207,884 $335,338 Present Value......................................... $212,263 $122,502 $200,647 Weighted average sales prices: Oil (per Bbl)......................................... $ 23.76 $ 10.39 $ 15.92 Gas (per Mcf)......................................... 1.99 1.98 2.35 NGLs (per Bbl)........................................ 19.11 8.44 11.40
(1) The Standardized Measure of Discounted Future Net Cash Flows prepared by the Company represents the present value (using an annual discount rate of 10%) of estimated future net revenues from the production of proved reserves, after giving effect to income taxes. See the Supplemental Financial Information attached to the Consolidated Financial Statements of the Company included elsewhere in this Report for additional information regarding the disclosure of the Standardized Measure information in accordance with the provisions of Statement of Financial Accounting Standards ("SFAS") No. 69, "Disclosures about Oil and Gas Producing Activities." 12 All information set forth in this Report relating to the Company's proved reserves, estimated future net revenues and Present Values is taken from reports prepared by DeGolyer and MacNaughton (with respect to the Company's United States properties) and Gilbert Lausten Jung Associates Ltd. (with respect to the Company's Canadian properties), each of which is a firm of independent petroleum engineers. The estimates of these engineers were based upon review of production histories and other geological, economic, ownership and engineering data provided by the Company. No reports on the Company's reserves have been filed with any federal agency. In accordance with guidelines of the Securities and Exchange Commission ("SEC"), the Company's estimates of proved reserves and the future net revenues from which Present Values are derived are made using year end oil and gas sales prices held constant throughout the life of the properties (except to the extent a contract specifically provides otherwise). A decline in prices relative to year end 1999 could cause a significant decline in the Present Value attributable to the Company's proved reserves at December 31, 1999. Operating costs, development costs and certain production-related taxes were deducted in arriving at estimated future net revenues, but such costs do not include debt service, general and administrative expenses and income taxes. There are numerous uncertainties inherent in estimating oil and gas reserves and their values, including many factors beyond the Company's control. The reserve data set forth in this Report represents estimates only. Reservoir engineering is a subjective process of estimating the sizes of underground accumulations of oil and gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation, and judgment. As a result, estimates of different engineers, including those used by the Company, may vary. In addition, estimates of reserves are subject to revision based upon actual production, results of future development, exploitation and exploration activities, prevailing oil and gas prices, operating costs and other factors, which revisions may be material. Accordingly, reserve estimates are often different from the quantities of oil and gas that are ultimately recovered and are highly dependent upon the accuracy of the assumptions upon which they are based. There can be no assurance that these estimates are accurate predictions of the Company's oil and gas reserves or their values. Estimates with respect to proved reserves that may be developed and produced in the future are often based upon volumetric calculations and upon analogy to similar types of reserves rather than actual production history. Estimates based on these methods are generally less reliable than those based on actual production history. Subsequent evaluation of the same reserves based upon production history will result in variations, which may be substantial, in the estimated reserves. 13 Net Production, Sales Prices and Costs The following table presents certain information with respect to oil and gas production, prices and costs attributable to all oil and gas property interests owned by the Company for the three-year period ended December 31, 1999.
Year Ended December 31, ----------------------------- 1999 1998 1997 ---- ---- ---- Production volumes: Oil (MBbl) United States............................ 1,085 1,577 1,769 Canada................................... 599 816 672 ------- ------- ------- Total Company.......................... 1,684 2,393 2,441 Gas (MMcf) United States (1)........................ 7,333 11,143 10,095 Canada................................... 2,915 3,221 2,734 ------- ------- ------- Total Company (1)...................... 10,248 14,364 12,829 NGLs (MBbl) United States............................ 172 260 267 Canada................................... 77 62 52 ------- ------- ------- Total Company.......................... 249 322 319 Weighted average sales prices (2): Oil (per Bbl) United States............................ $ 14.56 $ 12.68 $ 18.30 Canada................................... 16.29 12.04 17.28 Total Company.......................... 15.18 12.46 18.02 Gas (per Mcf) United States (1)........................ $ 1.95 $ 2.05 $ 2.46 Canada................................... 1.54 1.12 1.26 Total Company.......................... 1.83 1.84 2.21 NGLs (per Bbl) United States............................ $ 13.54 $ 9.41 $ 13.34 Canada................................... 11.84 8.56 16.64 Total Company.......................... 13.01 9.25 13.87 Selected expenses per BOE (3): Lease operating United States............................ $ 5.82 $ 5.01 $ 5.03 Canada................................... 3.48 3.05 3.50 Total Company.......................... 5.07 4.45 4.65 Production taxes (4) United States............................ $ 0.77 $ 0.84 $ 1.02 Depreciation, depletion and amortization United States............................ $ 4.34 $ 4.48 $ 3.88 Canada................................... 6.03 6.54 7.58 Total Company.......................... 4.88 5.15 4.79 General and administrative United States............................ $ 2.23 $ 2.11 $ 2.17 Canada................................... 1.15 1.41 1.54 Total Company.......................... 1.88 1.96 2.02
__________________ (1) Calculated by including volumes of natural gas purchased for resale as follows: 1999 - 148 MMcf, 1998 - 608 MMcf and 1997 - 629 MMcf. (2) Reflects results of hedging activities. See Item 7A - "Quantitative and Qualitative Disclosures about Market Risk." (3) Calculated without including volumes of natural gas purchased for resale. 14 (4) Canada does not assess production taxes on revenue derived from oil and gas production from Crown lands. However, in Canada, royalties are payable to the provincial governments on production from Crown lands, subject to certain programs that provide for royalty rate reductions, royalty holidays and tax credits for the purpose of encouraging oil and gas exploration and development. See "-Governmental Regulation-Canada." Productive Wells and Acreage Productive Wells The following table sets forth the Company's domestic and Canadian productive wells at December 31, 1999:
Productive Wells ---------------------------------------------------- Oil Gas Total -------------- --------------- --------------- Gross Net Gross Net Gross Net ----- --- ----- --- ----- --- United States............ 369 299 2,449 (1) 69 2,818 368 Canada................... 201 72 84 37 285 109 --- --- ----- --- ----- --- Total.................. 570 371 2,533 106 3,103 477 === === ===== === ===== ===
(1) 2,400 of the Company's gross natural gas wells are located in the San Juan Basin. The Company has non-operated working interests in these wells ranging from 0.26% to 50.0% and average approximately 1.8%. Acreage The following table sets forth the Company's undeveloped and developed gross and net leasehold acreage at December 31, 1999. Undeveloped acreage includes leased acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas, regardless of whether or not such acreage contains proved reserves.
Undeveloped Developed Total --------------- ------------------ ---------------- Gross Net Gross Net Gross Net ----- --- ----- --- ----- --- Permian Basin Maljamar............... 480 421 13,932 13,793 14,412 14,214 Wellman................ -- -- 2,280 2,165 2,280 2,165 Dimmitt/Slash Ranch.... 1,469 1,257 6,035 5,229 7,504 6,486 ------- ------ ------- ------ ------- ------- Total................ 1,949 1,678 22,247 21,187 24,196 22,865 San Juan Basin......... -- -- 10,880 6,239 10,880 6,239 Other.................. 41,247 18,811 13,321 6,384 54,568 25,195 ------- ------ ------- ------ ------- ------- Total United States.. 43,196 20,489 46,448 33,810 89,644 54,299 Canada................. 139,661 67,987 56,942 25,059 196,603 93,046 ------- ------ ------- ------ ------- ------- Total.................. 182,857 88,476 103,390 58,869 286,247 147,345 ======= ====== ======= ====== ======= =======
(1) Excluded is acreage in which the Company's interest is limited to a mineral or royalty interest. At December 31, 1999, the Company held mineral or royalty interests in 2,815 gross (759 net) developed acres and 30,056 gross (3,584 net) undeveloped acres. All the leases for the undeveloped acreage summarized in the preceding table will expire at the end of their respective primary terms unless prior to that date the existing leases are renewed or production has been obtained from the acreage subject to the lease, in which event the lease will remain in effect until the cessation of production. The following table sets forth the minimum remaining lease terms for the gross and net undeveloped acreage: 15
Acres Expiring ------------------ Gross Net ------- ------ Twelve Months Ending: December 31, 2000............... 30,296 14,218 December 31, 2001............... 61,677 26,487 Thereafter...................... 90,884 47,771 ------- ------ Total......................... 182,857 88,476 ======= ======
As is customary in the industry, the Company generally acquires oil and gas acreage without any warranty of title except as to claims made by, through or under the transferor. Although the Company has title to developed acreage examined prior to acquisition in those cases in which the economic significance of the acreage justifies the cost, there can be no assurance that losses will not result from title defects or from defects in the assignment of leasehold rights. In many instances, title opinions may not be obtained if in the Company's judgment it would be uneconomical or impractical to do so. Drilling Activity The following table sets forth for the three-year period ended December 31, 1999 the number of exploratory and development wells drilled by or on behalf of the Company.
1999 1998 1997 -------------- -------------- --------------- Gross Net Gross Net Gross Net ----- --- ----- --- ----- --- Exploratory Wells: - ----------------- United States Producing....... 6 2 16 11 10 6 Dry............. 2 1 14 7 8 4 Canada Producing....... 1 1 3 2 3 2 Dry............. -- -- 3 1 1 1 Development Wells: - ----------------- United States Producing....... 1 -- 58 44 80 71 Dry............. -- -- 2 1 2 1 Canada Producing....... 20 4 19 12 39 18 Dry............. 2 1 7 4 6 4 Total Wells: - ----------- Producing....... 28 7 96 69 132 97 Dry............. 4 2 26 13 17 10 ---- -- --- -- --- --- Total......... 32 9 122 82 149 107 ==== == === == === ===
Operations The Company generally seeks to be named as operator for wells in which it has acquired a significant interest, although, as is common in the industry, this typically occurs only when the Company owns the major portion of the working interest in a particular well or field. At December 31, 1999, the Company operated 100% of its properties in the Permian Basin, comprising approximately 62% of the Company's total proved reserves, including Maljamar (208 gross wells), Wellman (14 gross wells) and Dimmitt/Slash Ranch (82 gross wells). At December 31, 1999, the Company also operated 114 (out of a total of 285) gross wells on its Canadian properties. 16 As operator, the Company is able to exercise substantial influence over the development and enhancement of a well and to supervise operation and maintenance activities on a daily basis. The Company does not conduct the actual drilling of wells on properties for which it acts as operator, but engages independent contractors who are supervised by the Company. The Company employs petroleum engineers, geologists and other operations and production specialists who strive to improve production rates, increase reserves and/or lower the cost of operating its oil and gas properties. Oil and gas properties are customarily operated under the terms of a joint operating agreement, which provides for reimbursement of the operator's direct expenses and monthly per-well supervision fees. Per-well supervision fees vary widely depending on the geographic location and producing formation of the well, whether the well produces oil or gas and other factors. Such fees received by the Company in 1999 ranged from $95 to $870 per well per month. Competition The oil and gas industry is highly competitive. The Company encounters competition from other oil and gas companies in all areas of its operations, including the acquisition of producing properties. The Company's competitors include major integrated oil and gas companies and numerous independent oil and gas companies, individuals and drilling and income programs. Many of its competitors are large, well established companies with substantially larger operating staffs and greater capital resources than the Company. Such companies may be able to pay more for productive oil and gas properties and exploratory prospects and to define, evaluate, bid for and purchase a greater number of properties and prospects than the Company's financial or human resources permit. The Company's ability to acquire additional properties and to discover reserves in the future will depend upon its ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Drilling and Operating Risks Drilling activities are subject to many risks, including the risk that no commercially productive oil or gas reservoirs will be encountered. There can be no assurance that new wells drilled by the Company will be productive or that the Company will recover all or any portion of its investment. Drilling for oil and gas may involve unprofitable efforts, not only from dry wells, but from wells that are productive but do not produce sufficient net revenues to return a profit after drilling, operating and other costs. The cost of drilling, completing and operating wells is often uncertain. The Company's drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, many of which are beyond its control, including economic conditions, mechanical problems, pressure or irregularities in formations, title problems, weather conditions, compliance with governmental requirements and shortages in or delays in the delivery of equipment and services. Such equipment shortages and delays sometimes involve drilling rigs, especially in Canada, where weather conditions result in a short drilling season, causing a high demand for rigs by a large number of companies during a relatively short period of time. The Company's future drilling activities may not be successful. Lack of drilling success could have a material adverse effect on the Company's financial condition and results of operations. In addition, the Company's use of 3-D seismic requires greater pre-drilling expenditures than traditional drilling strategies. Although the Company believes that its use of 3-D seismic will increase the probability of success of its exploratory wells and should reduce average finding costs through the elimination of prospects that might otherwise be drilled solely on the basis of 2-D seismic and other traditional methods, unsuccessful wells are likely to occur. The Company's operations are subject to all the hazards and risks normally incident to the development, exploitation, production and transportation of, and the exploration for, oil and gas, including unusual or unexpected geologic formations, pressures, down-hole fires, mechanical failures, blowouts, cratering, explosions, uncontrollable flows of oil, gas or well fluids and pollution and other environmental risks. These hazards could result in substantial losses to the Company due to injury and loss of life, severe damage to and destruction of property and equipment, pollution and other environmental damage and suspension of operations. The Company maintains comprehensive 17 insurance coverage, including a $1.0 million general liability insurance policy and a $30.0 million excess liability policy. The Company believes that its insurance is adequate and customary for companies of a similar size engaged in comparable operations, but losses could occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. Title to Properties The Company's land department and contract land professionals have reviewed title records or other title review materials relating to substantially all of its producing properties. The title investigation performed by the Company prior to acquiring undeveloped properties is thorough, but less rigorous than that conducted prior to drilling, consistent with industry standards. The Company believes it has satisfactory title to all its producing properties in accordance with standards generally accepted in the oil and gas industry. The Company's properties are subject to customary royalty interests, liens incident to operating agreements, liens for current taxes and other inchoate burdens which the Company believes do not materially interfere with the use of or affect the value of such properties. At December 31, 1999, the Company's leaseholds for approximately 40% of its net acreage were being kept in force by virtue of production on that acreage in paying quantities. The remaining net acreage was held by lease rentals and similar provisions and requires production in paying quantities prior to expiration of various time periods to avoid lease termination. The Company expects to make acquisitions of oil and gas properties from time to time. In making an acquisition, the Company generally focuses most of its title and valuation efforts on the more significant properties. It is generally not feasible for the Company to review in-depth every property it purchases and all records with respect to such properties. However, even an in-depth review of properties and records may not necessarily reveal existing or potential problems, nor will it permit the Company to become familiar enough with the properties to assess fully their deficiencies and capabilities. Evaluation of future recoverable reserves of oil and gas, which is an integral part of the property selection process, is a process that depends upon evaluation of existing geological, engineering and production data, some or all of which may prove to be unreliable or not indicative of future performance. To the extent the seller does not operate the properties, obtaining access to properties and records may be more difficult. Even when problems are identified, the seller may not be willing or financially able to give contractual protection against such problems, and the Company may decide to assume environmental and other liabilities in connection with acquired properties. 18 Governmental Regulation The Company's operations are affected from time to time in varying degrees by political developments and federal, state, provincial and local laws and regulations. In particular, oil and gas production and related operations are or have been subject to price controls, taxes and other laws and regulations relating to the oil and gas industry. Failure to comply with such laws and regulations can result in substantial penalties. The regulatory burden on the oil and gas industry increases the Company's cost of doing business and affects its profitability. Although the Company believes it is in substantial compliance with all applicable laws and regulations, because such laws and regulations are frequently amended or reinterpreted, the Company is unable to predict the future cost or impact of complying with such laws and regulations. United States. Sales of natural gas by the Company are not regulated and are generally made at market prices. However, the Federal Energy Regulatory Commission ("FERC") regulates interstate natural gas transportation rates and service conditions, which affect the marketing of natural gas produced by the Company, as well as the revenues received by the Company for sales of such production. Sales of the Company's natural gas currently are made at uncontrolled market prices, subject to applicable contract provisions and price fluctuations which normally attend sales of commodity products. The FERC's jurisdiction over natural gas transportation was unaffected by the Decontrol Act. While sales by producers of natural gas, and all sales of crude oil, condensate and NGLs, can currently be made at uncontrolled market prices, Congress could re-enact prices controls in the future. Since the mid-1980's, the FERC has issued a series of orders that have significantly altered the marketing and transportation of natural gas. Such orders have mandated a fundamental restructuring of interstate pipeline sales and transportation service, including the unbundling by interstate pipelines of the sale, transportation, storage and other components of the city-gate sales services such pipelines previously performed. Further, they have eliminated or substantially reduced the interstate pipelines' traditional role as wholesalers of natural gas, and have substantially increased competition and volatility in natural gas markets. While the Company cannot predict what action the FERC will take on these or related matters in the future, the Company does not believe that it will be treated materially differently than other natural gas producers and marketers with which it competes. The Company's gathering operations are subject to safety and operational regulations relating to the design, installation, testing, construction, operation, replacement and management of facilities. Pipeline safety issues have recently been the subject of increasing focus in various political and administrative arenas at both the state and federal levels. The Company believes its operations, to the extent they may be subject to current gas pipeline safety requirements, comply in all material respects with such requirements. The Company cannot predict what effect, if any, the adoption of this or other additional pipeline safety legislation might have on its operations, but the industry could be required to incur additional capital expenditures and increased costs depending upon future legislative and regulatory changes. 19 The State of Texas and many other states require permits for drilling operations, drilling bonds and reports concerning operations and impose other requirements relating to the exploration for and production of oil and gas. Such states also have statutes or regulations addressing conservation matters, including provisions for the unitization or pooling of oil and gas properties, the establishment of maximum rates of production from wells and the regulation of spacing, plugging and abandonment of such wells. The statutes and regulations of certain states limit the rate at which oil and gas can be produced from the Company's properties. However, the Company does not believe it will be affected materially differently by these statutes and regulations than any other similarly situated oil and gas company. Canada. In Canada producers of oil negotiate sales contracts directly with oil purchasers, with the result that sales of oil are generally made at market prices. The price of oil received by the Company depends in part on oil quality, prices of competing fuels, distance to market, the value of refined products and the supply/demand balance. Oil exports may be made pursuant to export contracts with terms not exceeding one year in the case of light crude, and not exceeding two years in the case of heavy crude, provided that an order approving any such export has been obtained from the National Energy Board ("NEB"). Any oil export to be made pursuant to a contract of a longer duration requires an exporter to obtain an export license from the NEB and the issue of such license requires the approval of the Governor General in Council. In Canada the price of natural gas sold is determined by negotiation between buyers and sellers. Natural gas exported from Canada is subject to regulation by the NEB and the government of Canada. Exporters are free to negotiate prices and other terms with purchasers, provided that export contracts in excess of two years must continue to meet certain criteria prescribed by the NEB and the government of Canada. As is the case with oil, natural gas exports for a term of less than two years must be made pursuant to an NEB order, or, in the case of exports for a longer duration, pursuant to an NEB license and Governor General in Council approval. The government of Alberta also regulates the volume of natural gas that may be removed from Alberta for consumption elsewhere based on such factors as reserve availability, transportation arrangements and marketing considerations. In addition to Canadian federal regulation, Alberta and certain other provinces have legislation and regulations that govern royalties payable on production from Crown lands. The royalty regime that is in place at a particular time or location is a significant factor in the profitability of oil and gas production. Royalties payable on production from lands other than Crown lands are determined by negotiations between the mineral owner and the lessee. Crown royalties are determined by governmental regulation and are generally calculated as a percentage of the value of the gross production. The rate of royalties payable generally depends in part on prescribed reference prices, well productivity, geographical location, field discovery date and the type and quality of the petroleum product produced. From time to time the government of Alberta has established incentive programs that have included royalty rate reductions, royalty holidays and tax credits for the purpose of encouraging oil and gas exploration or enhanced production projects. For example, a producer of oil or gas is entitled to a credit against the royalties payable to the Crown by virtue of the Alberta Royalty Tax Credit ("ARTC") program. The ARTC program provides a rebate on Crown royalties paid in respect of eligible producing properties. The ARTC program is based on a price- sensitive formula, and the ARTC rate currently varies between 25% and 75% of the royalty otherwise payable on production. The ARTC rate is currently applied to a maximum of $2.0 million of Alberta Crown royalties otherwise payable by each producer or associated group of producers in each tax year. The rate is established quarterly based on average "par price," as determined by the Alberta Department of Energy for the previous quarterly period. Producing properties acquired from corporations claiming maximum entitlement to ARTC will generally not be eligible for ARTC. 20 Environmental Matters The Company's operations and properties are subject to extensive and changing federal, state, provincial and local laws and regulations relating to environmental protection, including the generation, storage, handling and transportation of oil and gas and the discharge of materials into the environment, and relating to safety and health. The recent trend in environmental legislation and regulation generally is toward stricter standards, and this trend will likely continue. These laws and regulations may require the acquisition of a permit or other authorization before construction or drilling commences and for certain other activities; limit or prohibit construction, drilling and other activities on certain lands lying within wilderness and other protected areas; and impose substantial liabilities for pollution resulting from the Company's operations. The permits required for various of the Company's operations are subject to revocation, modification and renewal by issuing authorities. Governmental authorities have the power to enforce compliance with their regulations, and violations are subject to fines, penalties or injunctions. In the opinion of management, the Company is in substantial compliance with current applicable environmental laws and regulations, and the Company has no material commitments for capital expenditures to comply with existing environmental requirements. Nevertheless, changes in existing environmental laws and regulations or in interpretations thereof could have a significant impact on the Company. The impact of such changes, however, would not likely be any more burdensome to the Company than to any other similarly situated oil and gas company. The Comprehensive Environmental Response, Compensation, and Liability Act ("CERCLA"), also known as the "Superfund" law, and similar state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a "hazardous substance" into the environment. These persons include the owner or operator of the disposal site or sites where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at the site. Persons who are or were responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources. Furthermore, neighboring landowners and other third parties may file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. The Company generates typical oil and gas field wastes, including hazardous wastes, that are subject to the federal Resources Conservation and Recovery Act and comparable state statutes. The United States Environmental Protection Agency and various state agencies have limited the approved methods of disposal for certain hazardous and nonhazardous wastes. Furthermore, certain wastes generated by the Company's oil and gas operations that are currently exempt from regulation as "hazardous wastes" may in the future be designated as "hazardous wastes," and therefore be subject to more rigorous and costly operating and disposal requirements. The Oil Pollution Act ("OPA") imposes a variety of requirements on responsible parties for onshore and offshore oil and gas facilities and vessels related to the prevention of oil spills and liability for damages resulting from such spills in waters of the United States. The "responsible party" includes the owner or operator of an onshore facility or vessel or the lessee or permittee of, or the holder of a right of use and easement for, the area where an onshore facility is located. OPA assigns liability to each responsible party for oil spill removal costs and a variety of public and private damages from oil spills. Few defenses exist to the liability for oil spills imposed by OPA. OPA also imposes financial responsibility requirements. Failure to comply with ongoing requirements or inadequate cooperation in a spill event may subject a responsible party to civil or criminal enforcement actions. The Company's Canadian operations are also subject to environmental regulation pursuant to local, provincial and federal legislation. Canadian environmental legislation provides for restrictions and prohibitions on releases or emissions of various substances produced in association with certain oil and gas industry operations and can affect the location of wells and facilities and the extent to which exploration and development is permitted. In addition, legislation requires that well and facilities sites be abandoned and reclaimed to the satisfaction of provincial authorities. In most cases, an environmental assessment and review is required prior to initiating exploration or development projects or undertaking significant changes to existing projects. A breach of such legislation may result in the imposition of fines and issuance of clean-up orders. Environmental legislation in Alberta has recently undergone a major revision and has been consolidated in the Environmental Protection and Enhancement Act. 21 Under the new Act, environmental standards and compliance for releases, clean-up and reporting are stricter. Also, the range of enforcement actions available and the severity of penalties have been significantly increased. These changes will have an incremental effect on the cost of conducting operations in Alberta. The Company owns, leases or operates numerous properties that for many years have produced or processed oil and gas. The Company also owns and operates natural gas gathering, transportation and processing systems. It is not uncommon for such properties to be contaminated with hydrocarbons or polychlorinated biphenyls. Although the Company or previous owners of these interests may have used operating and disposal practices that were standard in the industry at the time, hydrocarbons, polychlorinated biphenyls or other wastes may have been disposed of or released on or under the properties or on or under other locations where such wastes have been taken for disposal. These properties may be subject to federal or state requirements that could require the Company to remove any such wastes or to remediate the resulting contamination. In addition, some of the Company's properties are operated by third parties over whom the Company has no control. Notwithstanding the Company's lack of control over properties operated by others, the failure of the previous owners or operators to comply with applicable environmental regulations may, in certain circumstances, adversely impact the Company. Abandonment Costs The Company is responsible for payment of plugging and abandonment costs on its oil and gas properties pro rata to its working interest. Based on its experience, the Company anticipates that the ultimate aggregate salvage value of lease and well equipment located on its properties will exceed the costs of abandoning such properties. There can be no assurance, however, that the Company will be successful in avoiding additional expenses in connection with the abandonment of any of its properties. In addition, abandonment costs and their timing may change due to many factors, including actual production results, inflation rates and changes in environmental laws and regulations. Employees At February 24, 2000, the Company employed 67 full-time employees, of whom five were executive officers, 13 were technical personnel, 28 were field personnel and 21 were administrative personnel. Of the total employees, 53 were located in the United States and 14 were located in Canada. At February 24, 2000, none of the Company's employees were represented by a labor union. The Company considers its relations with its employees to be good. Facilities The Company's principal executive and administrative offices are located at 8115 Preston Road, Suite 400, Dallas, Texas. The offices contain approximately 21,000 square feet of space and are leased through December 31, 2001. Rental payments are approximately $37,000 per month. The office of the Company's Canadian subsidiary, The Wiser Oil Company of Canada, is located at 645 7th Avenue, S.W., Suite 2550, Calgary, Alberta. This office contains approximately 14,000 square feet of space and is leased through December 20, 2003. Rental payments are approximately $20,000 per month. Glossary of Oil and Gas Terms The following are abbreviations and definitions of terms commonly used in the oil and gas industry that are used in this Report. "Bbl" means a barrel of 42 U.S. gallons. "Bcf" means billion cubic feet. "BOE" means barrels of oil equivalent, converting volumes of natural gas to oil equivalent volumes using a ratio of six Mcf of natural gas to one Bbl of oil. 22 "completion" means the installation of permanent equipment for the production of oil or gas. "development well" means a well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive. "dry hole" or "dry well" means a well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes. "exploratory well" means a well drilled to find and produce oil or gas reserves not classified as proved, to find a new production reservoir in a field previously found to be productive of oil or gas in another reservoir or to extend a known reservoir. "farm-in" means an agreement pursuant to which the owner of a working interest in an oil and gas lease assigns the working interest or a portion thereof to another party who desires to drill on the leased acreage. Generally, the assignee is required to drill one or more wells in order to earn its interest in the acreage. The assignor usually retains a royalty or reversionary interest in the lease. The interest received by an assignee is a "farm-in." "gas" means natural gas. "gross" when used with respect to acres or wells, refers to the total acres or wells in which the Company has a working interest. "infill drilling" means drilling of an additional well or wells provided for by an existing spacing order to more adequately drain a reservoir. "MBbl" means thousand Bbls. "MBOE" means thousand BOE. "Mcf" means thousand cubic feet. "MMBOE" means million BOE. "MMBtu" means one million British Thermal Units. British Thermal Unit means the quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit. "MMcf" means million cubic feet. "net" when used with respect to acres or wells, refers to gross acres or wells multiplied, in each case, by the percentage working interest owned by the Company. "net production" means production that is owned by the Company less royalties and production due others. "NGL" means natural gas liquid. "operator" means the individual or company responsible for the exploration, development and production of an oil or gas well or lease. "Present Value" when used with respect to oil and gas reserves, means the estimated future gross revenues to be generated from the production of proved reserves calculated in accordance with the guidelines of the SEC, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation (except to the extent a contract specifically provides otherwise), without giving effect to non-property related expenses such as general and administrative expenses, debt service, future income tax expense and depreciation, depletion and amortization, and discounted using an annual discount rate of 10%. 23 "productive wells" or "producing wells" consist of producing wells and wells capable of production, including wells waiting on pipeline connections. "proved developed reserves" means reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery will be included as "proved developed reserves" only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved. "proved reserves" means the estimated quantities of crude oil, natural gas and NGLs which upon analysis of geological and engineering data appear with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions. (i) Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation tests. The area of a reservoir considered proved includes (A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and (B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir. (ii) Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the "proved" classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based. (iii) Estimates of proved reserves do not include the following: (A) oil that may become available from known reservoirs but is classified separately as "indicated additional reserves"; (B) crude oil, natural gas and NGLs, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics or economic factors; (C) crude oil, natural gas, and NGLs, that may occur in undrilled prospects; and (D) crude oil, natural gas and NGLs that may be recovered from oil shales, coal, gilsonite and other such resources. "proved undeveloped reserves" means reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for completion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir. "recompletion" means the completion for production of an existing well bore in another formation from that in which the well has been previously completed. "reserves" means proved reserves. "reservoir" means a porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs. 24 "royalty" means an interest in an oil and gas lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner's royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner. "2-D seismic" means an advanced technology method by which a cross-section of the earth's subsurface is created through the interpretation of reflecting seismic data collected along a single source profile. "3-D seismic" means an advanced technology method by which a three dimensional image of the earth's subsurface is created through the interpretation of reflection seismic data collected over surface grid. 3-D seismic surveys allow for a more detailed understanding of the subsurface than do conventional surveys and contribute significantly to field appraisal, development and production. "working interest" means an interest in an oil and gas lease that gives the owner of the interest the right to drill for and produce oil and gas on the leased acreage and requires the owner to pay a share of the costs of drilling and production operations. The share of production to which a working interest owner is entitled will always be smaller than the share of costs that the working interest owner is required to bear, with the balance of the production accruing to the owners of royalties. "workover" means operations on a producing well to restore or increase production. Item 2. Properties The information required by this Item is contained in Item 1. Business, and is incorporated herein by reference. Item 3. Legal Proceedings The Company and its subsidiaries and affiliates are named defendants in lawsuits and are involved in governmental proceedings from time to time, all arising in the ordinary course of business. Although the outcome of these lawsuits and proceedings cannot be predicted with certainty, management does not expect these matters to have a material adverse effect on the financial position of the Company. Item 4. Submission of Matters to a Vote of Security Holders No matters were submitted to security holders during the fourth quarter of the year ended December 31, 1998. 25 PART II Item 5. Market for Registrant's Common Equity and Related Stockholder Matters The Common Stock is traded on the New York Stock Exchange under the symbol WZR. The quarterly high and low sales prices and dividends per share of Common Stock during the three years ended December 31, 1999, were as follows:
High Low Dividends ------ ------ --------- 1999 First Quarter......................... $ 3.13 $ 1.44 $0.00 Second Quarter........................ 4.88 2.00 0.00 Third Quarter......................... 4.81 2.88 0.00 Fourth Quarter........................ 4.13 2.25 0.00 1998 First Quarter......................... $14.25 $11.75 $0.03 Second Quarter........................ 13.25 8.75 0.03 Third Quarter......................... 12.50 5.00 0.03 Fourth Quarter........................ 5.75 1.63 0.03 1997 First Quarter......................... $22.38 $17.63 $0.03 Second Quarter........................ 18.88 15.13 0.03 Third Quarter......................... 18.75 14.06 0.03 Fourth Quarter........................ 18.75 13.06 0.03
At February 24, 20000, there were 8,951,965 shares of Common Stock outstanding held by approximately 800 shareholders of record and approximately 3,700 beneficial owners. Each share of Common Stock also represents one preferred stock purchase right which entitles the holder thereof to purchase from the Company one-one thousandth of a share (a "Unit") of Series B Preferred Stock of the Company at an exercise price of $72.00 per Unit. On December 10, 1998, the Board of Directors approved a cost reduction plan which included suspending payments of cash dividends on the Company's common stock. In addition, under the terms of the BankOne Revover (see Note 4 to the Company's Consolidated Financial Statements) the payment of dividends is prohibited. 26 Item 6. Selected Financial Data The following selected consolidated financial data of the Company are derived from information contained in the Company's consolidated financial statements. The selected consolidated financial and operating data presented below should be read in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations" and the Company's Consolidated Financial Statements and notes thereto included elsewhere in this Report.
Year Ended December 31, --------------------------------------------------- 1999 1998 1997 1996 1995 -------- -------- -------- -------- -------- Income Statement Data (000's except per share amounts): Revenues: Oil and gas sales...................................... $ 47,602 $ 59,197 $ 76,729 $ 72,012 $ 54,400 Dividends and interest................................. 739 269 1,113 683 1,241 Marketable security sales gains........................ -- -- 7,495 12,977 13,101 Other.................................................. 4,453 1,942 2,478 1,017 2,939 -------- -------- -------- -------- -------- Total revenues....................................... 52,794 61,408 87,815 86,689 71,681 -------- -------- -------- -------- -------- Costs and expenses: Production and operating............................... 21,111 26,529 27,183 23,970 20,690 Purchased natural gas.................................. 336 1,440 1,622 1,462 727 Depreciation, depletion and amortization ("DD&A")...... 17,663 25,811 22,977 19,653 19,778 Property impairments................................... 2,214 3,838 3,289 12,112 4,893 Exploration............................................ 7,059 15,328 9,655 4,176 5,801 General and administrative............................. 6,816 10,571 9,661 9,364 8,193 Interest expense....................................... 13,310 13,097 9,845 5,452 5,618 -------- -------- -------- -------- -------- Total costs and expenses............................. 68,509 96,614 84,232 76,189 65,700 -------- -------- -------- -------- -------- Earnings (loss) before income taxes...................... (15,715) (35,206) 3,583 10,500 5,981 Income tax expense (benefit)............................. (859) (10,740) 264 4,072 3,788 -------- -------- -------- -------- -------- Net income (loss)........................................ $(14,856) $(24,466) $ 3,319 $ 6,428 $ 2,193 ======== ======== ======== ======== ======== Average outstanding shares (000's) (1)................... 8,952 8,952 8,949 8,939 8,939 Basic earnings (loss) per share.......................... $ (1.66) $ (2.73) $ 0.37 $ 0.72 $ 0.25 Cash dividends per share................................. $ 0.00 $ 0.12 $ 0.12 $ 0.12 $ 0.40 Other Financial Data (000's): EBITDA (2)............................................... $ 23,792 $ 22,599 $ 40,741 $ 38,233 $ 27,729 Operating cash flows..................................... 6,478 (3,316) 26,372 33,228 19,239 Capital expenditures..................................... 8,327 29,980 70,209 46,056 28,851 Balance Sheet Data - end of period (000's): Cash and cash equivalents................................ $ 21,447 $ 2,779 $ 13,255 $ 5,870 $ 1,397 Working capital (3)...................................... 17,875 (19,911) 7,809 3,493 1,034 Marketable securities.................................... -- -- -- 7,176 19,592 Net property and equipment............................... 159,973 213,295 220,708 179,718 169,089 Total assets............................................. 196,726 231,810 254,556 208,617 203,407 Long-term debt........................................... 124,526 124,452 124,304 78,654 74,171 Stockholders' equity..................................... 57,141 72,091 97,424 99,262 101,132
27
Year Ended December 31, ---------------------------------------------------- 1999 1998 1997 1996 1995 -------- -------- -------- -------- -------- Reserve and Operating Data: Production and volumes: Oil and NGLs (MBbl)............................................ 1,933 2,715 2,760 2,776 2,332 Gas (MMcf) (4)................................................. 10,248 14,364 12,829 12,288 12,171 BOE (000's) (4).............................................. 3,641 5,109 4,898 4,824 4,361 Weighted average sales prices (5): Oil (per Bbl).................................................. $ 15.18 $ 12.46 $ 18.02 $ 18.81 $ 16.91 Gas (per Mcf).................................................. 1.83 1.84 2.21 1.77 1.37 NGLs (per Bbl)................................................. 13.01 9.25 13.87 13.36 10.11 BOE (per Bbl)................................................ 11.59 11.59 15.66 14.93 12.47 Selected expenses per BOE (6): Lease operating................................................ $ 5.07 $ 4.45 $ 4.65 $ 4.14 $ 4.06 Production taxes............................................... 0.77 0.84 1.02 0.93 0.78 DD&A........................................................... 4.88 5.15 4.79 4.16 4.62 General and administrative..................................... 1.88 1.96 2.02 1.98 1.92 Proved reserves (end of year) (7): Oil and NGLs (MBbls)........................................... 25,430 27,988 29,721 31,612 32,208 Gas (MMcf)..................................................... 69,993 119,981 120,094 113,377 109,915 BOE (MBbls).................................................. 37,095 47,985 49,737 50,508 50,527 Estimated future net revenues before income taxes (000's)...... $419,668 $218,969 $359,293 $705,723 $401,037 Present Value.................................................. 222,539 123,831 210,087 414,314 235,416 Standardized Measure (000's) (8)............................... 176,916 113,232 174,489 317,180 194,602 Weighted average sales prices (end of year) (7)(9): Oil (per Bbl).................................................. $ 23.76 $ 10.39 $ 15.92 $ 24.63 $ 18.19 Gas (per Mcf).................................................. 1.99 1.98 2.35 3.45 1.84 NGLs (per Bbl)................................................. 19.11 8.44 11.40 19.79 12.87
(1) Basic earnings per share is calculated without including dilutive effect of common stock equivalents consisting of stock options. See Note 12 to the Company's Consolidated Financial Statements. (2) EBITDA is not a generally accepted accounting measure, but is presented as a supplemental financial indicator of the Company's ability to service or incur debt. EBITDA is calculated by adding interest expense, income tax expense, depreciation, depletion and amortization, property impairment costs and exploration costs to net income (excluding marketable security sales gains and dividends and interest). EBITDA should not be considered in isolation or as a substitute for net income, operating cash flows or any other measure of financial performance prepared in accordance with generally accepted accounting principles or as a measure of the Company's profitability or liquidity. (3) Working capital represents the difference between current assets and current liabilities. (4) Calculated by including volumes of natural gas purchased for resale as follows: 1999 - 148 MMcf, 1998 - 608 MMcf, 1997 - 629 MMcf, 1996 - 605 MMcf and 1995 - 500 MMcf. (5) Reflects results of hedging activities. See Item 7A - "Quantitative and Qualitative Disclosures about Market Risk." (6) Calculated without including volumes of natural gas purchased for resale. (7) Estimates of proved reserves and future net revenues from which Present Values are derived are based on year end prices of oil and gas held constant (except to the extent a contract specifically provides otherwise) in accordance with SEC regulations. (8) The Standardized Measure of Discounted Future Net Cash Flows prepared by the Company represents the present value (using an annual discount rate of 10%) of estimated future net revenues from the production of proved reserves, after giving effect to income taxes. See the Supplemental Financial Information attached to the Company's Consolidated Financial Statements included elsewhere in this Report for additional information regarding the disclosure of the Standardized Measure of Discounted Future Net Cash Flows. (9) Year end prices used to estimate proved reserves and future net revenues from which Present Values are derived. See footnotes 7 and 8 above. 28 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations The following discussion is intended to assist in an understanding of the Company's historical financial position and results of operations for each year in the three-year period ended December 31, 1999. The Company's Consolidated Financial Statements and notes thereto included elsewhere in this Report contain detailed information that should be referred to in conjunction with the following discussion. General The Company's future results of operations and growth are substantially dependent upon (i) its ability to acquire or find and successfully develop additional oil and gas reserves and (ii) the prevailing prices for oil and gas. At December 31, 1999, the Company's proved reserves were comprised of approximately 95% proved developed reserves, and the Company does not have a large inventory of development drilling locations or enhanced recovery projects to pursue after 1999. If the Company is unable to economically acquire or find significant new reserves for development and exploitation, the Company's oil and gas production, and thus its revenues, would likely decline gradually as its reserves are produced. In addition, oil and gas prices are dependent upon numerous factors beyond the Company's control, such as economic, political and regulatory developments and competition from other sources of energy. The oil and gas markets have historically been very volatile. In particular, oil prices during 1998 were at their lowest levels since 1986. As a result, the Company's results of operations were adversely affected. During the last half of 1999 and early 2000, oil prices increased significantly from 1998. Any significant and extended decline in the price of oil or gas would have a material adverse effect on the Company's financial condition and results of operations, and could result in a reduction in the carrying value of the Company's proved reserves and adversely affect its access to capital. The Company completed the liquidation of its marketable securities portfolio in 1997 and used the proceeds from the sale of its marketable securities to fund a portion of the Company's capital and exploration expenditures in 1997. The Company recognized pretax gains from the sale of marketable securities of $7.5 million in 1997. In the absence of such gains, the Company would have reported net losses in 1997. SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long- Lived Assets to Be Disposed Of," requires the Company to assess the need for an impairment of capitalized costs of proved oil and gas properties and the costs of wells and related equipment and facilities on a property-by-property basis. Applying SFAS No. 121, the Company recognized non-cash property impairment charges of $2.2 million in 1999, $3.8 million in 1998 and $3.3 million in 1997. Subsequent Event As described in Note 13 to the Company's Consolidated Financial Statements, the Company and Wiser Investment Company, LLC ("WIC") have entered into an Amended and Restated Stock Purchase Agreement and an Amended and Restated Warrant Purchase Agreement providing for, among other things, the issuance and sale by the Company to WIC of up to 1,000,000 Preferred Shares at a purchase price of $25.00 per share and the issuance of Warrants to purchase up to that number of shares of Common Stock representing approximately 5% of the outstanding shares of Common Stock at any given time. Results of Operations Production information presented below includes volumes of natural gas purchased for resale; however, per unit of production information with respect to production and operating expenses, depreciation, depletion and amortization and general and administrative costs is calculated without including such volumes. Such volumes were 148 MMcf in 1999, 608 MMcf in 1998 and 629 MMcf in 1997. 29 Comparison of 1999 to 1998 In April and May 1999, the Company entered into three separate agreements to sell its oil and gas properties in the Appalachia area, certain oil and gas properties in Texas and New Mexico and virtually all of its oil and gas royalty interests in the United States ("Second Quarter Property Sales"). The Second Quarter Property Sales were closed in April and May 1999 for an aggregate sales price of $42.3 million before fees and adjustments, and represented approximately 19% of the Company's proved reserves as of December 31, 1998. The Company recognized a net gain of $3.4 million in 1999 from the Second Quarter Property Sales and the revenues and expenses associated with the sold properties are included in the Company's consolidated statements of income through the various closing dates. The following table sets forth the production, oil and gas revenues, production and operating expenses and purchased gas related to the Second Quarter Property Sales for the years ended December 31,1999 and 1998 (000's):
1999 1998 ------ ------- Oil production (Bbls)................. 56 224 Gas production (Mcf).................. 1,215 4,189 NGL production (Bbls)................. 16 69 BOE production (Bbls)................. 275 991 Oil and gas revenues.................. $3,162 $12,969 Production and operating expenses..... 1,142 4,625 Purchased gas......................... 336 1,440
Revenues Oil and gas sales decreased $11.6 million or 20% to $47.6 million in 1999 from $59.2 million in 1998, due to the Second Quarter Property Sales, which accounted for $9.8 million of the decrease and also due to lower oil and gas production which was partially offset by higher oil and NGL prices. Oil production in 1999 was 709 MBbls lower than 1998 oil production, with 89% of the decrease attributed to lower oil production from the Maljamar field in New Mexico of 249 MBbls, lower oil production in Canada of 217 MBbls, primarily attributable to the Evi and Provost fields, and a reduction of 168 MBbls related to the Second Quarter Property Sales . The average oil price received in 1999 increased 22% to $15.18 per Bbl from $12.46 per Bbl in 1998. Gas production during 1999 decreased 29% to 10.2 Bcf from 14.4 Bcf in 1998. Approximately 21% of the decrease in gas production was attributable to the Second Quarter Property Sales and approximately 3% of the decrease in gas production was due to lower gas production in South Texas, which was 499 MMcf lower than 1998. The average gas price received in 1999 was $1.83 per Mcf or $0.01 less than 1998. As a result of hedging activities, oil and gas sales were decreased by $3.6 million in 1999 and increased by $0.2 million in 1998. On an equivalent unit basis, total production decreased 29% to 3,641 MBOE in 1999 from 5,109 MBOE in 1998. Dividends and interest increased 133% to $0.7 million in 1999 compared to $0.3 million in 1998 as a result of higher interest income earned on the net proceeds from the Second Quarter Property Sales which were invested in short-term investments. Pension plan curtailment gain of $0.8 million in 1998 was recognized as a result of amendments to the Company's pension plan in December 1998 which curtailed certain pension benefits. There were no such amendments in 1999. Gain on sales of properties were $3.6 million in 1999 compared to $0.6 million in 1998 due to the Second Quarter Property Sales as discussed above. Property sales in 1998 consisted of several non-strategic oil and gas properties. 30 Costs and Expenses Production and operating expense decreased 20% to $21.1 million in 1999 from $26.5 million in 1998 primarily due to the Second Quarter Property Sales, which reduced production and operating expenses by $3.5 million in 1999, and also due to cost cutting measures implemented at the Maljamar field which reduced production and operating expenses in 1999 by $1.5 million compared to 1998. On a BOE basis, production and operating expense increased 10% to $5.84 per BOE in 1999 from $5.29 per BOE in 1998 primarily as a result of higher production and operating expenses per BOE at the Maljamar and Wellman fields and the Second Quarter Property Sales which included properties with a lower than average production and operating expense per BOE. Purchase natural gas decreased 79% to $0.3 million in 1999 from $1.4 million in 1998 due to the Second Quarter Property Sales. DD&A decreased $8.1 million or 31% to $17.7 million in 1999 from $25.8 million in 1998 and DD&A per BOE decreased 5% to $4.88 per BOE in 1999 from $5.15 per BOE in 1998. U.S. DD&A decreased $5.9 million, due primarily to the Second Quarter Property Sales, and Canadian DD&A decreased $2.2 million. Impairment expense decreased 42% to $2.2 million in 1999 from $3.8 million in 1998. Impairment expense in 1999 was resulted from lower than expected reserve estimates for certain properties and impairment expense in 1998 was due primarily to unusually low oil prices used to value reserves at year-end 1998. Exploration expense decreased 54% to $7.1 million in 1999 from $15.3 million in 1998 as the Company significantly curtailed its exploration activities in 1999 due to low oil prices experienced in 1998 and the first quarter of 1999. Dry hole expense decreased 79% to $1.3 million in 1999 from $6.1 million in 1998. Geological and geophysical expenses in 1999 were $0.8 million, down 76% from $3.4 million in 1998. General and administrative expense ("G&A") decreased 36% to $6.8 million in 1999 from $10.6 million in 1998 and G&A per BOE decreased 4% to $1.88 per BOE in 1999 from $1.96 per BOE in 1998. The decrease in G&A was attributable in part to an informal cost reduction program that was implemented by the Company in December 1998 that involved reducing its workforce by approximately 36% and reducing other discretionary administrative expenses. In connection with this cost reduction program, the Company recognized approximately $545,000 of employee severance expense in 1998. Income tax benefit decreased $9.8 million to a tax benefit of $0.9 million in 1999 from a tax benefit of $10.7 million in 1998. The Company had a net operating loss carryforward of approximately $16 million at December 31, 1999 and since full realization of the future tax benefits of the net operating loss carryforward was determined by the Company to not be "more likely than not" at December 31, 1999, only $0.9 million of income tax benefit was recognized in 1999. Net loss decreased $9.6 million to a net loss of $14.9 million in 1999 from a net loss of $24.5 million in 1998 as total costs and expenses and income taxes for 1999 were $18.2 million lower than 1998 and total revenues for 1999 were only $8.6 million lower than 1998. Comparison of 1998 to 1997 Revenues 31 Oil and gas sales decreased $17.5 million or 23% to $59.2 million in 1998 from $76.7 million in 1997, as lower oil and gas prices decreased oil and gas sales by $19.8 million which was offset by $2.3 million attributed to higher gas and NGL production. The average oil price received in 1998 decreased 31% to $12.46 per Bbl from $18.02 per Bbl in 1997 and the average gas price received in 1998 decreased 17% to $1.84 per Mcf from $2.21 per Mcf in 1997. Gas production during 1998 increased 12% to 14.4 Bcf from 12.8 Bcf in 1997. The increase in gas production was primarily attributable to the Welder Ranch field in South Texas which produced 2.3 Bcf of gas during 1998 compared to 0.8 Bcf of gas in 1997. The Welder Ranch field was acquired in June 1997. Oil production in 1998 decreased 2% to 2,393 MBbls from 2,441 MBbls in 1997. As a result of development activity in 1997 and 1998, oil production in 1998 from the Evi and Provost fields in Canada was 88 MBbls and 150 MBbls higher than 1997, respectively. Oil production from the Maljamar and Wellman fields in 1998 was 102 MBbls and 70 MBbls lower than 1997, respectively, as development activities at these fields was substantially complete in 1997. As a result of hedging activities, oil and gas sales were increased by $0.2 million in 1998 and reduced by $2.4 million during 1997. On an equivalent unit basis, total production increased 4% to 5,109 MBOE in 1998 from 4,898 MBOE in 1997. Dividends and interest decreased 76% to $0.3 million in 1998 compared to $1.1 million in 1997 as the Company completed the liquidation of its remaining marketable securities in 1997. Marketable security sales gains were $7.5 million in 1997 as the Company completed the liquidation of its remaining marketable securities in 1997. Pension plan curtailment gain of $0.8 million in 1998 was recognized as a result of amendments to the Company's pension plan in December 1998 which curtailed certain pension benefits. There were no such amendments in 1997. Costs and Expenses Production and operating expense decreased 2% to $26.5 million in 1998 from $27.2 million in 1997 primarily due to a decrease of $0.7 million in production taxes associated with lower oil and gas sales in 1998. On a BOE basis, production and operating expense decreased 7% to $5.29 per BOE in 1998 from $5.67 per BOE in 1997 as a result of higher BOE production and lower production taxes in 1998. DD&A increased 12% to $25.8 million in 1998 from $23.0 million in 1997 and increased 8% to $5.15 per BOE in 1998 from $4.79 per BOE in 1997. The increases were primarily attributable to additional wells drilled at the Maljamar field combined with increased depletion from the Welder field in South Texas. Impairment expense increased 17% to $3.8 million in 1998 from $3.3 million in 1997. Impairment expense in 1998 and 1997 was due primarily to low oil prices used to value reserves at year-end 1998 and year-end 1997. Exploration expense increased 59% to $15.3 million in 1998 from $9.7 million in 1997 as the Company increased its exploration activities during 1998. Dry hole expense increased 49% to $6.1 million in 1998 from $4.1 million in 1997 and included dry hole expense of $1.6 million in Peru and $2.0 million in South Texas during 1998. Surrendered and abandoned lease expense in 1998 increased 227% to $4.9 million from $1.5 million in 1997 primarily as a result of increased lease abandonment expense associated with unsuccessful exploration drilling in 1998 and the curtailment of exploration activities due to low oil prices. G&A increased 9% to $10.6 million in 1998 from $9.7 million in 1997 and increased 4% to $2.11 per BOE in 1998 from $2.02 per BOE in 1997. The increase in G&A was attributable primarily to an informal cost reduction program that was implemented by the Company in December 1998 that involved reducing its workforce by approximately 36% and reducing other discretionary administrative expenses. In connection with this cost reduction program, the Company recognized $545,000 of employee severance expense in 1998. 32 Interest expense increased 33% to $13.1 million in 1998 from $9.8 million in 1997 due primarily to incurring a full year of interest expense in 1998 under the 9 1/2% Senior Subordinated Notes ("2007 Notes"), which were issued in May 1997, and increased long-term debt in 1998 compared to 1997. Income tax expense decreased $11.0 million to a benefit of $10.7 million in 1998 from tax expense of $0.3 million in 1997 primarily as a result of a decrease in earnings before income taxes of $38.8 million. Net income decreased $27.8 million to a net loss of $24.5 million in 1998 from net income of $3.3 million in 1997 primarily as a result of lower oil and gas prices and higher DD&A, exploration and interest expense in 1998. Liquidity and Capital Resources Cash flows Cash flows from operating activities increased $9.8 million to $6.5 million in 1999 from a deficit of $3.3 million in 1998. The major factors contributing to the increase in cash flows during 1999 were lower costs and expenses of $16.9 million offset by lower revenues of $11.6 million and changes in working capital of $4.5 million from 1998 to 1999 that provided operating cash flows. The net proceeds from the Second Quarter Property Sales of $41.0 million provided most of the $32.7 million of cash flows from investing activities. Capital expenditures were $8.3 million in 1999, a decrease of $21.7 million from $30.0 million in 1998. Capital expenditures were curtailed in 1999 as a result of low oil prices in 1998 and the first quarter of 1999. The major components of capital expenditures for 1999 were $5.4 million for development activities and $2.7 million for exploration activities. Cash flows from financing activities in 1999 consisted of repaying $21 million of borrowings under the Credit Agreement, formerly with NationsBank of Texas, N.A., and borrowing $0.5 million under the Restated Credit Agreement with Bank One Texas, NA. Financial Position Cash and cash equivalents increased $18.7 million from $2.8 million at December 31, 1998 to $21.5 million at December 31, 1999. The increase was attributable primarily to $41.0 million of sales proceeds from the Second Quarter Property Sales less $20.5 million of repayments of long-term debt. Working capital of $18.4 million at December 31, 1999 was $38.3 million higher than the working capital deficit of $19.9 million at December 31, 1998 due primarily to increased cash and cash equivalents of $18.7 million and the repayment of $21.0 million of current portion of long-term debt. Net property and equipment decreased $53.3 million, of which $36.5 million is attributable to the Second Quarter Property Sales. Total assets decreased $35.1 million during 1999 to $196.7 million at December 31, 1999, and stockholders' equity decreased $15.0 million during 1999 to $57.1 million at December 31, 1999. At December 31, 1999, capitalization totaled $182.1 million and consisted of $125.0 million of long-term debt (69%) and $57.1 million of stockholders' equity (31%). Capital Sources Funding for the Company's business activities has been provided by cash flow from operations, borrowings and sales of marketable securities. The Company completed the liquidation of its marketable securities in 1997 and, accordingly, this source of funds is no longer available. While the Company regularly engages in discussions relating to potential acquisitions of oil and gas properties, the Company has no current agreement or commitment with respect to any such acquisitions which would be material to the Company. Any future acquisitions may require additional financing and will be dependent upon financing arrangements available at the time. 33 The Company entered into a Credit Agreement with a group of banks which provides for the issuance of letters of credit and for revolving credit loans to the Company (the "Credit Agreement"). On March 23, 1999, a financial institution ("New Lender") purchased all of the rights and obligations of the Credit Agreement from Nations Bank of Texas, N.A. and the Bank of Montreal and became the new Agent under the Credit Agreement. In April 1999, the Company used $10 million of proceeds from the sale of oil and gas properties to reduce the outstanding balance under the Credit Agreement to $11 million. On May 10, 1999, the Company entered into a Restated Credit Agreement with Bank One, Texas, N.A. (the "BankOne Revolver"). The Company borrowed $11 million under the BankOne Revolver and repaid in full the outstanding principal balance of $11 million under the Credit Agreement and the Credit Agreement was terminated. Also in May 1999, the Company used $10.5 million of proceeds from the sale of oil and gas properties to reduce the BankOne Revolver balance to $0.5 million. The BankOne Revolver provides the Company with up to a $25 million line of credit through April 30, 2001. The amounts available for borrowing are based on the Company's oil and gas reserves and the Company's Borrowing Base at December 31, 1999 was $8 million. Available loan and interest options are (i) Prime Rate Loans, at the bank's prime interest rate and (ii) Eurodollar Loans, at LIBOR plus 2.5%, 2.75% or 3% depending on the percentage of the Borrowing Base actually borrowed by the Company. The commitment fee on the unused Borrowing Base is 0.5%. The BankOne Revolver imposes certain restrictions on sales of assets, payment of dividends and incurrence of indebtedness and requires the Company to, among other things, maintain certain financial ratios and make monthly escrow deposits of $1.0 million to fund the semi-annual interest payments on the 9 1/2% Senior Subordinated Notes. The Company is currently negotiating certain amendments to the BankOne Revolver and, subject to the completion of the negotiations, the Company has classified the entire $500,000 balance outstanding at December 31, 1999 as a current liability in the Consolidated Balance Sheets. On April 13, 1999, the Company entered into a Purchase and Sale Agreement with Prince Minerals, Ltd. to sell certain producing and non-producing mineral interests ("Mineral Properties") for $10 million effective April 1, 1999. The sale closed on April 21, 1999. The producing portion of the oil and gas properties comprising the Mineral Properties represented approximately 2% of the Company's total proved oil and gas reserves at December 31, 1998. The sales proceeds were used to reduce the outstanding balance under the Credit Agreement to approximately $11 million. On April 12, 1999, the Company entered into a Purchase and Sale Agreement with Columbia Natural Resources to sell all of the Company's oil and gas properties in Kentucky, Tennessee and West Virginia ("Appalachia Properties") for $28 million effective April 1, 1999. The sale closed on May 12, 1999. The oil and gas properties comprising the Appalachia Properties represented approximately 15% of the Company's total proved oil and gas reserves at December 31, 1998. The sales proceeds were used to reduce the outstanding balance under the Credit Agreement to approximately $11 million, and for general corporate purposes. In addition, the Company sold a number of smaller, non-strategic oil and gas properties in Texas and New Mexico for an aggregate sales price of $4.3 million. This sale closed on May 25, 1999. The sales proceeds from these properties were used for general corporate purposes. The Company believes that cash flows from operations and borrowings under the BankOne Revolver will be sufficient to meet anticipated capital and exploration expenditure requirements (excluding any material property acquisitions) in 2000. If the Company's cash flows from operations and borrowings under the BankOne Revolver are not sufficient to satisfy its capital and exploration expenditure requirements, there is no assurance that additional equity or debt financing will be available to meet such requirements. 34 Capital and Exploration Expenditures The Company requires capital primarily for the acquisition, development and exploitation of, and the exploration for, oil and gas properties, the repayment of indebtedness and general working capital needs. During 2000, subject to market conditions and drilling and operating results, the Company expects to spend approximately $15.0 million on acquisition, development, exploitation and exploration activities. Other Matters Environmental and Other Regulatory Matters The Company's business is subject to certain federal, state, provincial and local laws and regulations relating to the development, exploitation, production and gathering of, and the exploration for, oil and gas, including those relating to the protection of the environment. Many of these laws and regulations have become more stringent in recent years, often imposing greater liability on a larger number of potentially responsible parties. Although the Company believes it is in substantial compliance with all applicable laws and regulations, the requirements imposed by laws and regulations are frequently changed and subject to interpretation, and the Company is unable to predict the ultimate cost of compliance with these requirements or their effect on its operations. Although significant expenditures may be required to comply with governmental laws and regulations applicable to the Company, compliance has not had a material adverse effect on the earnings or competitive position of the Company. Year 2000 Issue Although the transition to the year 2000 did not have any significant impact on the Company or its reporting systems and operations, the Company will continue to assess the impact of the "Year 2000" ("Y2K") issue on its reporting systems and those of its primary business partners, suppliers and vendors during the Year 2000. The Y2K issue exists because many computer systems and applications used two-digit date fields to designate a year, which meant that two-digit date systems would recognize the year 2000 as 1900 or not at all. This inability to recognize or properly treat the year 2000 may cause systems to process critical financial and operational information incorrectly. In 1998 and the first quarter of 1999, the Company's U.S. and Canadian computerized accounting systems were upgraded to versions which are Y2K compliant. These upgrades were completed at a nominal cost to the Company. In addition, the Company's personal computer systems were analyzed for Y2K compliance during 1998 and certain components were upgraded at a nominal cost to the Company. Virtually all of the Company's personal computer systems are currently Y2K compliant. 35 New Accounting Standards The Company adopted the following pronouncements in 1998: SFAS No. 130, "Reporting Comprehensive Income" requires that all items that are to be recognized under accounting standards as components of comprehensive income be reported in a financial statement that is displayed with the same prominence as other financial statements, and SFAS No. 131, "Disclosures about Segments of an Enterprise and Related Information" requires reporting of financial and descriptive information about a company's reportable operating segments. The Company has identified only one operating segment, which is the exploration for and production of oil and gas. In June 1998, the Financial Accounting Standards Board issued SFAS 133 "Accounting for Derivative Instruments and Hedging Activities" which is effective for all fiscal years beginning after June 15, 2000 (January 1, 2001 for the Company). SFAS No. 133 requires that derivatives be reported on the balance sheet at fair value and, if the derivative is not designated as a hedging instrument, changes in fair value must be recognized in earnings in the period of change. If the derivative is designated as a hedge and to the extent such hedge is determined to be effective, changes in fair value are either offset by the change in fair value of the hedged asset or liability (if applicable) or reported as a component of other comprehensive income in the period of change, and subsequently recognized in earnings when the offsetting hedged transaction occurs. The definition of derivatives has also been expanded to include contracts that require physical delivery of oil and gas if the contract allows for net cash settlement. The Company currently uses derivatives to hedge oil and gas price risk and gains or losses on such derivatives are recorded as adjustments to oil and gas sales. Accordingly, adoption of SFAS No. 133 should not have a significant impact on reported earnings, but could have a material impact on comprehensive income and the reported financial position of the Company. Disclosure Regarding Forward-Looking Statements This Report includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements other than statements of historical facts included in this Report, including without limitation statements in this "Management's Discussion and Analysis of Financial Condition and Results of Operations" and under "Business" and "Properties" regarding proved reserves, estimated future net revenues, Present Values, planned capital expenditures (including the amount and nature thereof), increases in oil and gas production, the number of wells anticipated to be drilled and the Company's financial position, business strategy and other plans and objectives for future operations, are forward-looking statements. Although the Company believes that the expectations reflected in such forward-looking statements are reasonable, there can be no assurance that the actual results or developments anticipated by the Company will be realized or, even if substantially realized, that they will have the expected consequences to or effects on its business or operations. Among the factors that could cause actual results to differ materially from the Company's expectations are the volatility of oil and gas prices, the ability to acquire or find and successfully develop additional oil and gas reserves, the uncertainty of estimates of reserves and future net revenues, risks relating to acquisitions of producing properties, drilling and operating risks, general economic conditions, competition, domestic and foreign government regulations and other factors which are beyond the Company's control. All subsequent written and oral forward-looking statements attributable to the Company or persons acting on its behalf are expressly qualified in their entirety by such factors. The Company assumes no obligation to update any such forward-looking statements. 36 Item 7A. Quantitative and Qualitative Disclosures about Market Risk The Company only uses derivative financial instruments such as commodity futures agreements to hedge against fluctuations in oil and gas prices. Gains and losses on these derivative instruments are recorded as adjustments to oil and gas sales. The Board of Directors of the Company have adopted a policy governing the use of derivative instruments which requires that all derivatives used by the Company relate to an anticipated transaction and prohibits the use of speculative or leveraged derivatives. Interest Rate Risk Total debt at December 31, 1999 included $124.5 million of fixed-rate debt and $0.5 million of floating-rate debt attributed to borrowings under the BankOne Revolver. As a result, the Company's annual interest cost will fluctuate based on changes in short-term interest rates. The impact on annual cash flow of a 10% change in the short-term interest rate (approximately 85 basis points) would be less than $0.01 million. At December 31, 1999, the estimated fair value of the Company's fixed-rate debt of $125.0 million was $98.8 million. The fixed-rate debt will mature in May 2007 and the floating-rate debt will mature in May 2001. Commodity Price Risk The Company has in the past entered into and may in the future enter into hedging arrangements with respect to portions of its oil, natural gas and NGL production to reduce its sensitivity to volatile commodity prices. The Company believes that hedging, although not free of risk, allows the Company to achieve a more predictable cash flow and to reduce exposure to price fluctuations. However, hedging arrangements limit the benefit to the Company of increases in the prices of the hedged commodity. Moreover, the Company's hedging arrangements apply only to a portion of its production and provide only partial price protection against declines in prices. Such arrangements may expose the Company to risk of financial loss in certain circumstances. The Company expects that the amount of production it hedges will vary from time to time. During 1999, 1998 and 1997, the Company entered into various natural gas and crude oil forward sale agreements, natural gas price swaps and oil price collar agreements to hedge against price fluctuations. Oil and gas sales are adjusted for the effects of hedging transactions as the underlying hedged production is sold. Adjustments to oil and gas sales from the Company's hedging activities resulted in a decrease in revenues of $3.6 million in 1999, an increase in revenues of $0.2 million in 1998 and a decrease in revenues of $2.4 million in 1997. Based on December 31, 1999 NYMEX futures prices, the fair value of the Company's hedging arrangements at December 31, 1999 was a loss of $1.2 million. A 10% increase in both the oil price and the gas price would increase this loss by $3.0 million and a 10% decrease in both the oil price and the gas price would decrease this loss by $3.0 million. 37 As of February 24, 2000 the Company's hedging arrangements were as follows:
Period Daily Volume Price (Floor / Ceiling) - ------ ------------ ----------------------- Crude Oil: ---------- January 1, 2000 to March 31, 2000 1,000 Bbls (1) $18.50 / 26.60 per Bbl January 1, 2000 to March 31, 2000 2,700 Bbls $24.00 per Bbl April 1, 2000 to June 30, 2000 3,500 Bbls $22.30 per Bbl July 1, 2000 to September 30, 2000 3,400 Bbls $21.07 per Bbl October 1, 2000 to December 31, 2000 3,300 Bbls $19.78 per Bbl Natural Gas: ------------ February 1, 2000 to September 30, 2000 5,261 MMBTU (2) $2.29 per MMBTU (2) February 1, 2000 to September 30, 2000 5,226 MMBTU (2)(3) $2.01 (Put) per MMBTU (2) March 1, 2000 to September 30, 2000 5,174 MMBTU (2)(3) $2.20 (Put) per MMBTU (2)
(1) The 1,000 Bbls per day crude oil hedge is a "collar" hedge whereby the Company will receive the actual market price if the actual market price is between the floor price of $18.50 per Bbl and the ceiling price of $26.60 per Bbl. If the actual market price is below or above the floor or ceiling prices, the price received by the Company will be limited to the floor price or ceiling price, respectively. (2) Average for period. (3) The 5,226 MMBTU per day the and 5,174 MMBTU per day natural gas hedges are "Put" agreements whereby the Company will receive the actual market price if the actual market price is above the put prices of $2.01 and $2.20 per MMBTU, respectively. If the actual market price is below the put price, the price received by the Company will be limited to the put price. The Company continuously reevaluates its hedging program in light of market conditions, commodity price forecasts, capital spending and debt service requirements. Also see Note 1 to the Company's Consolidated Financial Statements included elsewhere in this Report. Foreign Currency Exchange Risk The Company receives a substantial portion of its revenue in Canadian dollars (29% in 1999). As a result, fluctuations in the exchange rates of the Canadian dollar with respect to the U.S. dollar could have an adverse effect on the Company's financial condition and results of operations. Historically however, exchange rate fluctuations have not been material to the Company. Item 8. Financial Statements and Supplementary Data The Report of Independent Accountants, Consolidated Financial Statements and supplementary financial data required by this Item are set forth on pages F-1 through F-20 of this Report and are incorporated herein by reference. Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure Not applicable. 38 PART III Item 10. Directors and Executive Officers of the Registrant The information required by this Item will be contained in the Proxy Statement under the headings "Election of Directors" and "Executive Officers" and is incorporated herein by reference. Item 11. Executive Compensation The information required by this Item will be contained in the Proxy Statement under the heading "Executive Compensation" and is incorporated herein by reference. Item 12. Security Ownership of Certain Beneficial Owners and Management The information required by this Item will be contained in the Proxy Statement under the heading "Beneficial Ownership of Common Stock" and is incorporated herein by reference. Item 13. Certain Relationships and Related Transactions The information required by this Item, if any, will be contained in the Proxy Statement under the heading "Executive Compensation" and is incorporated herein by reference. PART IV Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K A. Financial Statements The following documents are filed as part of this Report: 1. Report of Independent Accountants Consolidated Statements of Income Consolidated Balance Sheets Consolidated Statements of Changes in Stockholders' Equity Consolidated Statements of Cash Flows Notes to Consolidated Financial Statements 2. Schedules are omitted because of the absence of conditions under which they are required or because the required information is given in the financial statements or notes thereto. B. Reports on Form 8-K. The Company filed a report on Form 8-K on December 23, 1999 disclosing under Item 5. thereof that the Company entered into a Stock Purchase Agreement and Warrant Purchase Agreement, each dated as of December 13, 1999, with Wiser Investment Company, LLC. 39 C. Exhibits Exhibits not incorporated herein by reference to a prior filing are designated by an asterisk (*) and are filed herewith; all exhibits not so designated are incorporated herein by reference as indicated. Exhibit Numbers - ------- (3.1) Certificate of Incorporation of the Company, as amended, incorporated by reference to Exhibit 4.2 to the Company's report on Form 8-K (Commission File No. 0-5426), dated November 9, 1993 (Date of Event: October 25, 1993). (3.2) Bylaws of the Company, as amended, incorporated by reference to Exhibit 4.3 to the Company's report on Form 8-K (Commission File No. 0-5426), dated November 9, 1993 (Date of Event: October 25, 1993). (4) Rights Agreement dated as of October 25, 1993 by and between the Company and The Chase Manhattan Bank (as successor to Chemical Bank), as Rights Agent, which includes as Exhibit 2 thereto the Form of Rights Certificate, incorporated by reference to Exhibit 4.1 to the Company's report on Form 8-K (Commission File No. 0-5426), dated November 9, 1993 (Date of Event: October 25, 1993). (4a) First Amendment to Rights Agreement dated as of October 25, 1993 by and between the Company and ChaseMellon Shareholder Services, L.L.C. (as successor to Chemical Bank), as Rights Agent, incorporated by reference to Exhibit 4.1 to the Company's report on Form 8 -K (Commission File No. 0-5426), dated December 23, 1999 (Date of Event: December 13, 1999). (4.1) Indenture dated May 21, 1997, among the Company, certain subsidiaries of the Company and Texas Commerce Bank National Association, as Trustee, incorporated by reference to Exhibit 4.1 to the Company's Registration Statement on Form S-4 (Commission File No. 333-29211), filed on June 13, 1997. (4.2) Form of 9 1/2% Senior Subordinated Notes due 2007 (included in the indenture filed as Exhibit 4.1), incorporated by reference to Exhibit 4.2 to the Company's Registration Statement on Form S-4 (Commission File No. 333-29211), filed on June 13, 1997. (4.3) Registration Agreement dated May 21, 1997, among the Company, certain subsidiaries of the Company and Salomon Brothers Inc., NationsBanc Capital Markets, Inc. and Nesbitt Burns Securities Inc., as the Initial Purchasers, incorporated by reference to Exhibit 4.3 to the Company's Registration Statement on Form S-4 (Commission File No. 333-29211), filed on June 13, 1997. (4.4) Credit Agreement dated June 23, 1994 among The Wiser Oil Company and The Wiser Oil Company of Canada, as Borrowers, and NationsBank of Texas, N.A. (NationsBank), as Agent, and Certain Financial Institutions Listed on the Signature Pages Thereto, as Banks, incorporated by reference to the Exhibit 10.1 to the Company's report on Form 8-K (Commission File No. 0-5426), dated July 11, 1994 (Date of Event: July 11, 1994), as amended on Form 8-K/A filed on August 17, 1994. (4.5) First Amendment to Credit Agreement dated November 29, 1995 among The Wiser Oil Company and The Wiser Oil Company of Canada, as Borrowers, and NationsBank, as Agent, and Certain Financial Institutions Listed on the Signature Pages Thereto, as Banks, incorporated by reference to Exhibit 4.5 to the Company's Registration Statement on Form S-4 (Commission File No. 333-29211), filed on June 13, 1997. 40 (4.6) Second Amendment to Credit Agreement dated May 20, 1997 among The Wiser Oil Company and The Wiser Oil Company of Canada, Inc., as Borrowers, and NationsBank, as Agent, and Certain Financial Institutions Listed on the Signature Pages thereto, as Banks, incorporated by reference to Exhibit 4.6 to the Company's Registration Statement on Form S-4 (Commission File No. 333-29211), filed on June 13, 1997. (4.7) Guaranty Agreement dated May 20, 1997, by Wiser Oil Delaware, Inc., in favor of NationsBank and PNC Bank, National Association ("PNC"), incorporated by reference to Exhibit 4.7 to the Company's Registration Statement on Form S-4 (Commission File No. 333-29211), filed on June 13, 1997. (4.8) Guaranty Agreement dated May 20, 1997, by Wiser Delaware LLC, in favor of NationsBank and PNC, incorporated by reference to Exhibit 4.8 to the Company's Registration Statement on Form S-4 (Commission File No. 333- 29211), filed on June 13, 1997. (4.9) Guaranty Agreement dated May 20, 1997, by The Wiser Marketing Company, in favor of NationsBank and PNC, incorporated by reference to Exhibit 4.9 to the Company's Registration Statement on Form S-4 (Commission File No. 333-29211), filed on June 13, 1997. (4.10) Guaranty Agreement dated May 20, 1997, by The Wiser Oil Company of Canada, in favor of NationsBank and PNC, incorporated by reference to Exhibit 4.10 to the Company's Registration Statement on Form S-4 (Commission File No. 333-29211), filed on June 13, 1997. (4.11) Guaranty Agreement dated May 20, 1997, by T.W.O.C., Inc., in favor of NationsBank and PNC, incorporated by reference to Exhibit 4.11 to the Company's Registration Statement on Form S-4 (Commission File No. 333- 29211), filed on June 13, 1997. (4.13) Credit Agreement dated December 23, 1997 among The Wiser Oil Company, as borrowers, and NationsBank of Texas, N.A., as agent, and The Financial Institutions Listed on the Signature Pages thereto, as Banks, incorporated by reference to Exhibit 4.13 to the Company's Annual Report on Form 10-K for the year ended December 31, 1997. (4.13a) First Amendment to Credit Agreement dated September 30, 1998 among The Wiser Oil Company, as borrowers, and NationsBank of Texas, N.A., as agent, and The Financial Institutions Listed on the Signature Pages thereto, as Banks, incorporated by reference to Exhibit 4.13a to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 1998. (4.13b) Second Amendment to Credit Agreement dated January 11, 1999 among The Wiser Oil Company, as borrowers, and NationsBank of Texas, N.A., as agent, and The Financial Institutions Listed on the Signature Pages thereto, as Banks, incorporated by reference to Exhibit 4.13b to the Company's Annual Report on Form 10-K for the year ended December 31, 1998. (4.15) Restated Credit Agreement dated May 10, 1999 among The Wiser Oil Company, as borrower, and Bank One Texas, N.A., as agent, and the Institutions as listed on the signature pages thereto, as Banks, incorporated by reference to Exhibit 4.15 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1999. (10.3) Purchase and Sale Agreements made as of May 31, 1994 among Eagle Resources Ltd., Caneagle Resources Corporation, The Erin Mills Investment Corporation and The Wiser Oil Company, incorporated by reference to Exhibit 10 to the Company's report on Form 8-K dated July 11, 1994 (Date of Event: July 11, 1994), as amended by Form 8-K/A filed on August 17, 1994. 41 (10.3a) Purchase and Sale Agreement dated April 12, 1999 between Columbia Natural Resources, Inc. and The Wiser Oil Company, incorporated by reference to Exhibit 10.3a to the Company's Annual Report on Form 10- K for the year ended December 31, 1998. (10.4) + Employment Agreement dated August 1, 1994 between the Company and Allan J. Simus, incorporated by reference to Exhibit 10(d) to the Company's Annual Report on Form 10-K for the year ended December 31, 1994. (10.4a) + Amendment to Employment Agreement dated August 1, 1994 between the Company and Alan J. Simus dated March 22, 1996, incorporated by reference to Exhibit 10.4a to the Company's Annual Report on Form 10- K for the year ended December 31, 1998. (10.4b) + Second Amendment to Employment Agreement dated August 1, 1994 between the Company and Alan J. Simus dated May 20, 1997, incorporated by reference to Exhibit 10.4a to the Company's Annual Report on Form 10- K for the year ended December 31, 1997. (10.4c) + Third Amendment to Employment Agreement dated August 1, 1994 between the Company and Alan J. Simus dated January 1, 1999, incorporated by reference to Exhibit 10.4c to the Company's Annual Report on Form 10- K for the year ended December 31, 1998. (10.4d) + Fourth Amendment to Employment Agreement dated August 4, 1994 between the Company and Alan J. Simus dated June 1, 1999, incorporated by reference to Exhibit 10.4d to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 1999. (10.5) + Employment Agreement dated July 1, 1991 between the Company and Andrew J. Shoup, Jr., incorporated by reference to Exhibit 10(a) to the Company's Annual Report on Form 10-K for the year ended December 31, 1993. (10.5a) + Amendment to Employment Agreement dated July 1, 1991 between the Company and Andrew J. Shoup, Jr. dated June 1, 1994, incorporated by reference to Exhibit 10.5a to the Company's Form 10-K for the year ended December 31, 1998. (10.5b) + Second Amendment to Employment Agreement dated July 1, 1991 between the Company and Andrew J. Shoup, Jr. dated May 20, 1997, incorporated by reference to Exhibit 10.5a to the Company's Annual Report on Form 10-K for the year ended December 31, 1997. (10.5c) + Third Amendment to Employment Agreement dated July 1, 1991 between the Company and Andrew J. Shoup, Jr. dated January 1, 1999, incorporated by reference to Exhibit 10.5c to the Company's Annual Report on Form 10-K for the year ended December 31, 1998. (10.5d) + Fourth Amendment to Employment Agreement dated July 1, 1991 between the Company and Andrew J. Shoup Jr. dated June 1, 1999, incorporated by reference to Exhibit 10.5d to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 1999. (10.6) + The Wiser Oil Company 1991 Stock Incentive Plan, as amended, incorporated by reference to Exhibit 4.1 to the Company's Registration Statement on Form S-8 (Commission File No. 33-62441), filed on September 8, 1995. (10.6a) + Amendment to The Wiser Oil Company 1991 Stock Incentive Plan, incorporated by reference to the Company's Registration Statement on Form S-8 (Commission File No. 333-29973), filed on June 25, 1997. 42 (10.7) + The Wiser Oil Company 1991 Non-Employee Directors' Stock Option Plan, as amended, incorporated by reference to Exhibit 99.1 to the Company's Registration Statement on Form S-8 (Commission File No. 333-22525), filed on February 28, 1997. (10.8) + Employment Agreement dated November 1, 1993 between the Company and Lawrence J. Finn, incorporated by reference to Exhibit 10(b) to the Company's Annual Report on Form 10-K for the year ended December 31, 1993. (10.8a) + Amendment to Employment Agreement dated November 1, 1993 between the Company and Lawrence J. Finn dated March 22, 1996, incorporated by reference to Exhibit 10.8a to the Company's Annual Report on Form 10-K for the year ended December 31, 1998. (10.8b) + Second Amendment to Employment Agreement dated November 1, 1993 between the Company and Lawrence J. Finn dated May 20, 1997, incorporated by reference to Exhibit 10.8a to the Company's Annual Report on Form 10-K for the year ended December 31, 1997. (10.8c) + Third Amendment to Employment Agreement dated November 1, 1993 between the Company and Lawrence J. Finn dated January 1, 1999, incorporated by reference to Exhibit 10.8c to the Company's Annual Report on Form 10-K for the year ended December 31, 1998. (10.8d) + Fourth Amendment to Employment Agreement dated November 1, 1991 between the Company and Lawrence J. Finn dated June 1, 1999, incorporated by reference to Exhibit 10.8d to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 1999. (10.9) + Employment Agreement dated January 24, 1994 between the Company and A. Wayne Ritter, incorporated by reference to Exhibit 10(c) to the Company's Annual Report on Form 10-K for the year ended December 31, 1993. (10.9a) + Amendment to Employment Agreement dated January 24, 1994 between the Company and A. Wayne Ritter dated March 22, 1996, incorporated by reference to Exhibit 10.9a to the Company's Annual Report on Form 10-K for the year ended December 31, 1998. (10.9b) + Second Amendment to Employment Agreement dated January 24, 1994 between the Company and A. Wayne Ritter dated May 20, 1997, incorporated by reference to Exhibit 10.9a to the Company's Annual Report on Form 10-K for the year ended December 31, 1997. (10.9c) + Third Amendment to Employment Agreement dated January 24, 1994 between the Company and A. Wayne Ritter dated January 1, 1999, incorporated by reference to Exhibit 10.9c to the Company's Annual Report on Form 10-K for the year ended December 31, 1998. (10.9d) + Fourth Amendment to Employment Agreement dated January 24, 1994 between the Company and A. Wayne Ritter dated June 1, 1999, incorporated by reference to Exhibit 10.9d to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 1999. (10.10) + Employment Agreement dated September 30, 1996 between the Company and Kent E. Johnson, incorporated by reference to Exhibit 10.10 to the Company's Annual Report on Form 10-K for the year ended December 31, 1996. (10.10a)+ Amendment to Employment Agreement dated September 30, 1996 between the Company and Kent E. Johnson dated May 20, 1997, incorporated by reference to Exhibit 10.2 of the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1997. 43 (10.10b)+ Second Amendment to Employment Agreement dated September 30, 1996 between the Company and Kent E. Johnson dated January 1, 1999, incorporated by reference to Exhibit 10.10b to the Company's Annual Report on Form 10-K for the year ended December 31, 1998. (10.11) + The Wiser Oil Company Equity Compensation Plan For Non-Employee Directors, incorporated by reference to Exhibit 10.11 to the Company's Annual Report on Form 10-K for the year ended December 31, 1996. (10.12) The Wiser Oil Company Savings Restoration Plan dated February 24, 1998, incorporated by reference to Exhibit 10.12 to the Company's Annual Report on Form 10-K for the year ended December 31, 1997. (10.13) Retirement Restoration Plan dated March 23, 1995, incorporated by reference to Exhibit 10.13 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1998. (10.14) +* The Wiser Oil Company 1997 Share Appreciation Rights Plan dated as of August 19, 1997. (10.14a)+* Amendment to the Wiser Oil Company 1997 Share Appreciation Rights Plan dated May 18, 1999. (10.15) Amended and Restated Stock Purchase Agreement dated as of December 13, 1999 between the Company and Wiser Investment Company, LLC, incorporated by reference to Exhibit 10.1 to the Company's report on Form 8-K (Commission File No. 0-5426), dated March 20, 2000 (Date of Event: March 10, 2000). (10.15) Amended and Restated Warrant Purchase Agreement dated as of December 13, 1999 between the Company and Wiser Investment Company, LLC, incorporated by reference to Exhibit 10.2 to the Company's report on Form 8-K (Commission File No. 0-5426), dated March 20, 2000 (Date of Event: March 10, 2000). (21) * Subsidiaries of registrant. (23.1) * Consent of Independent Public Accountants. (23.2) * Consent of DeGolyer and MacNaugton, Independent Petroleum Engineers. (23.3) * Consent of Gilbert Laustsen Jung Associates Ltd., Independent Petroleum Engineers. (27) * Financial Data Schedule. ______________ + Represent management compensatory plans or agreements. * Filed herewith. 44 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on the 12th day of April 2000. The Wiser Oil Company By: /s/ Andrew J. Shoup, Jr. ----------------------------------- Andrew J. Shoup, Jr. President and Chief Executive Officer Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
Signature Title Date --------- ----- ---- /s/ ANDREW J. SHOUP, JR. President, Chief Executive April 12, 2000 - -------------------------------- Officer and Director ANDREW J. SHOUP, JR. (Principal Executive Officer) /s/ C. FRAYER KIMBALL Director April 12, 2000 - -------------------------------- C. FRAYER KIMBALL /s/ HOWARD G. HAMILTON Director April 12, 2000 - -------------------------------- HOWARD G. HAMILTON /s/ A. W. SCHENCK, III Director April 12, 2000 - -------------------------------- A. W. SCHENCK, III /s/ JOHN W. CUSHING, III Director April 12, 2000 - -------------------------------- JOHN W. CUSHING, III /s/ JON L. MOSLE, JR. Director April 12, 2000 - -------------------------------- JON L. MOSLE, JR. /s/ LORNE H. LARSON Director April 12, 2000 - -------------------------------- LORNE H. LARSON /s/ LAWRENCE J. FINN Vice President and Chief April 12, 2000 - -------------------------------- Financial Officer LAWRENCE J. FINN (Principal Financial and Accounting Officer)
45 THE WISER OIL COMPANY INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Page ---- Report of Independent Public Accountants........................ F-2 Consolidated Statements of Income............................... F-3 Consolidated Balance Sheets..................................... F-4 Consolidated Statements of Changes in Stockholders' Equity...... F-5 Consolidated Statements of Cash Flows........................... F-6 Notes to Consolidated Financial Statements...................... F-7
F-1 Report of Independent Public Accountants To the Shareholders of The Wiser Oil Company: We have audited the accompanying consolidated balance sheets of The Wiser Oil Company (a Delaware corporation) and subsidiaries as of December 31, 1999 and 1998, and the related consolidated statements of income, changes in stockholders' equity, and cash flows for the years ended December 31, 1999, 1998 and 1997. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of The Wiser Oil Company and subsidiaries as of December 31, 1999 and 1998, and the results of their operations and their cash flows for the years ended December 31, 1999, 1998 and 1997, in conformity with accounting principles generally accepted in the United States. ARTHUR ANDERSEN LLP Dallas, Texas, February 24, 2000 F-2 THE WISER OIL COMPANY CONSOLIDATED STATEMENTS OF INCOME For the Years Ended December 31, 1999, 1998 and 1997
1999 1998 1997 -------- -------- -------- (000's except per share data) Revenues: Oil and gas sales......................... $ 47,602 $ 59,197 $76,729 Dividends and interest.................... 739 269 1,113 Marketable security sales................. -- -- 7,495 Gain on sales of properties............... 3,555 615 1,875 Pension plan curtailment gain............. -- 778 -- Other..................................... 898 549 603 ------------------------------- 52,794 61,408 87,815 ------------------------------- Costs and Expenses: Production and operating.................. 21,111 26,529 27,183 Purchased natural gas..................... 336 1,440 1,622 Depreciation, depletion and amortization.. 17,663 25,811 22,977 Property impairments...................... 2,214 3,838 3,289 Exploration............................... 7,059 15,328 9,655 General and administrative................ 6,816 10,571 9,661 Interest expense.......................... 13,310 13,097 9,845 ------------------------------- 68,509 96,614 84,232 ------------------------------- Earnings (Loss) Before Income Taxes......... (15,715) (35,206) 3,583 Income Tax Expense (Benefit)................ (859) (10,740) 264 ------------------------------- NET INCOME (LOSS)........................... $(14,856) $(24,466) $ 3,319 =============================== Earnings (Loss) Per Share (Note 12): Basic..................................... $ (1.66) $ (2.73) $ 0.37 =============================== Diluted................................... $ (1.66) $ (2.73) $ 0.37 =============================== Cash Dividends Per Share.................... $ -- $ 0.12 $ 0.12 ===============================
The accompanying notes are an integral part of these financial statements. F-3 THE WISER OIL COMPANY CONSOLIDATED BALANCE SHEETS December 31, 1999 and 1998
1999 1998 -------- -------- (000's) Assets Current Assets: Cash and cash equivalents.................................. $ 21,447 $ 2,779 Restricted cash............................................ 992 -- Accounts receivable........................................ 9,565 9,102 Inventories................................................ 335 669 Income taxes receivable.................................... -- 1,270 Prepaid expenses........................................... 379 472 ----------------------- Total current assets.................................... 32,718 14,292 ----------------------- Property and Equipment, at cost: Oil and gas properties (successful efforts method)......... 274,760 367,974 Other properties........................................... 3,781 5,523 ----------------------- 278,541 373,497 Accumulated depreciation, depletion and amortization....... (118,568) (160,202) ----------------------- Net property and equipment................................. 159,973 213,295 Other Assets................................................ 4,035 4,223 ----------------------- $ 196,726 $ 231,810 ======================= Liabilities and Stockholders' Equity Current Liabilities: Accounts payable........................................... $ 11,694 $ 10,473 Current portion of long-term debt.......................... 500 21,000 Accrued liabilities........................................ 2,649 2,730 ----------------------- Total current liabilities................................ 14,843 34,203 ----------------------- Long-term Debt.............................................. 124,526 124,452 Deferred Benefit Cost....................................... 216 378 Deferred Income Taxes....................................... -- 686 Stockholders' Equity: Common stock - $3 par value; 20,000,000 shares authorized; 9,128,169 shares issued; 8,951,965 shares outstanding... 27,385 27,385 Paid-in capital............................................ 3,223 3,223 Retained earnings.......................................... 28,234 43,090 Foreign currency translation............................... 1,028 1,122 Treasury stock; 176,204 shares, at cost.................... (2,729) (2,729) ----------------------- Total stockholders' equity............................... 57,141 72,091 ----------------------- $ 196,726 $ 231,810 =======================
The accompanying notes are an integral part of these financial statements. F-4 THE WISER OIL COMPANY CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY For the Years Ended December 31, 1999, 1998 and 1997
Marketable Securities Foreign Common Paid-in Retained Valuation Currency Treasury Total Stock Capital Earnings Adjustment Translation Stock -------- -------- ------- -------- ---------- ----------- -------- (000's) December 31, 1996................. $ 99,262 $ 27,347 $3,078 $ 66,385 $ 4,328 $ 853 $(2,729) Net income...................... 3,319 -- -- 3,319 -- -- -- Other comprehensive income (loss), net of tax........... (4,266) -- -- -- (4,328) 62 -- -------- Comprehensive income (loss)..... (947) Stock options exercised......... 183 38 145 -- -- -- -- Dividends paid.................. (1,074) -- -- (1,074) -- -- -- -------- -------- ------- -------- ---------- ----------- -------- December 31, 1997................. 97,424 27,385 3,223 68,630 -- 915 (2,729) Net income (loss)............... (24,466) -- -- (24,466) -- -- -- Other comprehensive income (loss), net of tax........... 207 -- -- -- -- 207 -- -------- Comprehensive income (loss)..... (24,259) Dividends paid.................. (1,074) -- -- (1,074) -- -- -- -------- -------- ------- -------- ---------- ----------- -------- December 31, 1998................. 72,091 27,385 3,223 43,090 -- 1,122 (2,729) Net income (loss)............... (14,856) -- -- (14,856) -- -- -- Other comprehensive income (loss), net of tax (94) -- -- -- -- (94) -- -------- Comprehensive income (loss)..... (14,950) Dividends paid.................. -- -- -- -- -- -- -- -------- -------- ------- -------- ---------- ----------- -------- December 31, 1999................. $ 57,141 $ 27,385 $3,223 $ 28,234 $ -- $1,028 $(2,729) ======== ======== ======= ======== ========== =========== ========
The accompanying notes are an integral part of these financial statements. F-5 THE WISER OIL COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS For the Years Ended December 31, 1999, 1998 and 1997
1999 1998 1997 --------- --------- -------- (000's except per share data) Cash Flows from Operating Activities: Net income (loss) $(14,856) $(24,466) $ 3,319 Adjustments to reconcile to cash flows from operating activities: Depreciation, depletion and amortization........ 17,663 25,811 22,977 Deferred income taxes........................... (686) (9,592) 1,530 Marketable securities and property sales gains.. (3,555) (615) (9,370) Property impairments and abandonments........... 6,824 8,744 4,830 Foreign currency translation.................... (94) 207 62 Amortization of debt issuance costs............. 607 556 282 Other changes: Restricted cash............................... (992) -- -- Accounts receivable........................... (463) 4,663 326 Inventories................................... 39 338 282 Income taxes receivable....................... 1,270 (545) (725) Prepaid expenses.............................. 93 (597) 35 Accounts payable.............................. 1,221 (7,923) 3,400 Accrued income taxes.......................... -- -- (1,697) Accrued liabilities........................... (81) (255) 1,449 Deferred benefit costs........................ (162) (791) (328) Other......................................... (350) 1,149 -- ------------------------------- Operating Cash Flows........................ 6,478 (3,316) 26,372 ------------------------------- Cash Flows From Investing Activities: Capital expenditures.............................. (8,327) (29,980) (70,209) Proceeds from sales of property and equipment..... 41,017 2,894 3,288 Proceeds from sales of marketable securities...... -- -- 8,115 ------------------------------- Investing Cash Flows........................ 32,690 (27,086) (58,806) ------------------------------- Cash Flows From Financing Activities: Borrowings of long-term debt...................... 500 21,000 125,000 Repayments of long-term debt...................... (21,000) -- (78,654) Long-term debt issuance costs and fees............ -- -- (5,636) Common stock issued............................... -- -- 183 Dividends paid.................................... -- (1,074) (1,074) ------------------------------- Financing Cash Flows........................ (20,500) 19,926 39,819 ------------------------------- Net Increase (Decrease) in Cash.......................... 18,668 (10,476) 7,385 Cash and Cash Equivalents, beginning of year............. 2,779 13,255 5,870 ------------------------------- Cash and Cash Equivalents, end of year................... $ 21,447 $ 2,779 $ 13,255 ===============================
The accompanying notes are an integral part of these financial statements. F-6 THE WISER OIL COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS December 31, 1999, 1998 and 1997 1. Summary of Significant Accounting Policies a. Principles of Consolidation - The consolidated financial statements include the accounts of The Wiser Oil Company (Company), a Delaware corporation, and its wholly owned subsidiaries: The Wiser Oil Company of Canada ("Wiser Canada"), The Wiser Marketing Company, and T.W.O.C., Inc. Wiser Canada was formed in 1994 to conduct the Company's Canadian activities. Prior to the formation of Wiser Canada, the Company's oil and gas operations were conducted primarily in the United States. The Wiser Marketing Company functions as a natural gas marketer and broker. T.W.O.C., Inc. is a Delaware holding company responsible for the management of investment activities. Intercompany accounts and transactions have been eliminated. Certain reclassifications have been made to conform prior years' amounts to current presentation. b. Risks and Uncertainties - The preparation of financial statements in conformity with accounting principles generally accepted in the U.S. requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. c. Oil and Gas Properties - The Company is engaged in the exploration and development of oil and gas in the United States and Canada. The Company follows the "successful efforts" method of accounting for its oil and gas properties. Under this method of accounting, all costs of property acquisitions and exploratory wells are initially capitalized. If a well is unsuccessful, the capitalized costs of drilling the well, net of any salvage value, are charged to expense. If a well finds oil and gas reserves that cannot be classified as proved within a year after discovery, the well is assumed to be impaired and the capitalized costs of drilling the well, net of any salvage value, are charged to expense. The capitalized costs of unproven properties are periodically assessed to determine whether their value has been impaired below the capitalized cost, and if such impairment is indicated, a loss is recognized. The Company considers such factors as exploratory drilling results, future drilling plans and the lease expiration terms when assessing unproved properties for impairment. Geological and geophysical costs and the costs of retaining undeveloped properties are expensed as incurred. Expenditures for maintenance and repairs are charged to expense, and renewals and betterments are capitalized. Upon disposal, the asset and related accumulated depreciation, depletion and amortization are removed from the accounts, and any resulting gain or loss is reflected currently in income. Long-lived assets are assessed for possible impairment in accordance with Statement of Financial Accounting Standards ("SFAS") No. 121, "Accounting for the Impairment of Long-Lived assets and for Long-Lived Assets to Be Disposed Of". SFAS 121 requires the Company to assess the need for an impairment of capitalized costs of proved oil and gas properties and the costs of wells and related equipment and facilities on a property-by- property basis. If an impairment is indicated based on undiscounted expected future cash flows, then an impairment is recognized to the extent that net capitalized costs exceed the estimated fair value of the property. Fair value of the property is estimated by the Company using the present value of future cash flows discounted at 10%. F-7 THE WISER OIL COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued) December 31, 1999, 1998 and 1997 The following expected future prices were used to estimate future cash flows to assess properties for impairment: Price starting after December 31, 1999, 1998 and 1997, respectively:
1999 1998 1997 ------- ------------ ------------ Oil Price per barrel: Year 1.............. $25.60 $12.35 $16.75 Year 2.............. 25.60 13.73 17.25 Year 3.............. 25.60 14.57 17.77 Year 4.............. 25.60 15.81 18.30 Thereafter.......... 25.60 Escalated 3% Escalated 3% Maximum............. 25.60 20.00 21.85 Gas Price per MMBTU: Year 1.............. $ 2.34 $ 1.96 $ 2.68 Year 2.............. 2.34 2.25 2.68 Year 3.............. 2.34 2.34 2.68 Year 4.............. 2.34 2.55 2.68 Thereafter.......... 2.34 Escalated 3% 2.68 Maximum............. 2.34 3.50 2.68
Oil and gas expected future price estimates were based on NYMEX future prices at each year-end. Expected future prices were escalated if such prices were unusually low at year-end compared to historical averages. These prices were applied to production profiles developed by the Company's engineers using proved developed and undeveloped reserves at December 31, 1999, 1998 and 1997, respectively. The Company's price assumptions change based on current industry conditions and the Company's future plans. During 1999, 1998 and 1997, the Company recognized impairments of $2,214,000, $3,838,000 and $3,289,000, respectively. The impairments were determined based on the difference between the carrying value of the assets and the present value of future cash flows discounted at 10%. It is reasonably possible that a change in reserve or price estimates could occur in the near term and adversely impact management's estimate of future cash flows and consequently the carrying value of properties. d. Depreciation, Depletion and Amortization ("DD&A") - DD&A of the capitalized costs of producing oil and gas properties are computed for individual properties using the units-of-production method based on total proved reserves. Other properties consist primarily of computer systems, vehicles and office equipment and depreciation is computed generally using the straight-line method over the estimated useful lives of these assets which range from 5 to 10 years. e. Cash and Cash Equivalents - Cash equivalents consist of short-term investments maturing in three months or less from the date of acquisition. These investments of $24,020,000 at December 31, 1999 and $2,675,000 at December 31, 1998 are recorded at cost plus accrued interest, which approximates market. f. Inventories - Natural gas product inventories in pipelines are recorded at the lower of average cost or market. Materials and supplies are recorded at the lower of average cost or market. F-8 THE WISER OIL COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued) December 31, 1999, 1998 and 1997 g. Accrued Liabilities - In December 1998, the Company reduced its workforce by approximately 36% and accrued liabilities at December 31, 1998 includes $545,000 for employee severance payments. The employee severance liability of $545,000 is included in general and administrative expense in the consolidated statements of income for the year ended December 31, 1998 and the entire liability was paid in 1999. Accrued liabilities also include accrued vacation and payroll of $379,000 at December 31, 1999 and $323,000 at December 31, 1998. h. Postretirement Benefits - SFAS No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions", has no significant impact on the Company. The Company has no significant liabilities for postretirement benefits, other than pensions, and has historically recognized such liabilities as they are incurred. i. Gas Imbalances - Gas imbalances are accounted for using the sales method. The Company's net imbalance position is not material at December 31, 1999 and 1998. j. Financial Instruments - The following table sets forth the book value and estimated fair values of financial instruments at December 31, 1999 and 1998, respectively (000's):
1999 1998 -------------- ------------- Book Fair Book Fair Value Value Value Value -------- -------- -------- ------- Cash and equivalents $ 21,447 $21,447 $ 2,779 $ 2,779 Restricted cash 992 992 -- -- Floating-rate debt 500 500 21,000 21,000 Fixed-rate debt 124,526 98,750 124,452 86,250
The fair value of the fixed-rate debt was based on quoted market prices of the Company's fixed-rate debt at December 31, 1999 and 1998, respectively. During 1999, 1998 and 1997, the Company entered into various natural gas forward sale agreements and natural gas price swap and oil price collar agreements to hedge against price fluctuations. Oil and gas sales in the accompanying Consolidated Statements of Income are adjusted for the effects of hedging transactions as the underlying hedged production is sold. Adjustments to oil and gas sales from the Company's hedging activities resulted in a reduction in revenues of $3,609,000 in 1999, an increase in revenues of $210,000 in 1998 and a reduction in revenues of $2,372,000 in 1997. As of December 31, 1999 and December 31, 1998, the Company had no deferred net gains or net losses. As of February 24, 2000 the Company's hedging arrangements were as follows:
Crude Oil: Daily Volume Price (Floor / Ceiling) --------- ------------ ----------------------- January 1, 2000 to March 31, 2000 1,000 Bbls (1) $18.50 / 26.60 per Bbl January 1, 2000 to March 31, 2000 2,700 Bbls $24.00 per Bbl April 1, 2000 to June 30, 2000 3,500 Bbls $22.30 per Bbl July 1, 2000 to September 30, 2000 3,400 Bbls $21.07 per Bbl October 1, 2000 to December 31, 2000 3,300 Bbls $19.78 per Bbl Natural Gas: ----------- February 1, 2000 to September 30, 2000 5,261 MMBTU (2) $2.29 per MMBTU (2) February 1, 2000 to September 30, 2000 5,226 MMBTU (2)(3) $2.01 (Put) per MMBTU (2)(3) March 1, 2000 to September 30, 2000 5,174 MMBTU (2)(3) $2.20 (Put) per MMBTU (2)(3)
F-9 THE WISER OIL COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued) December 31, 1999, 1998 and 1997 (1) The 1,000 Bbls per day crude oil hedge is a "collar" hedge whereby the Company will receive the actual market price if the actual market price is between the floor price of $18.50 per Bbl and the ceiling price of $26.60 per Bbl. If the actual market price is below or above the floor or ceiling prices, the price received by the Company will be limited to the floor price or ceiling price, respectively. (2) Average for period. (3) The 5,226 MMBTU per day the and 5,174 MMBTU per day natural gas hedges are "Put" agreements whereby the Company will receive the actual market price if the actual market price is above the put prices of $2.01 and $2.20 per MMBTU, respectively. If the actual market price is below the put price, the price received by the Company will be limited to the put price. k. Foreign Currency Translation - The functional currency of Wiser Canada is the Canadian dollar. In accordance with SFAS No. 52, "Foreign Currency Translation", Wiser Canada's financial statements have been translated from Canadian dollars to U.S. dollars with the cumulative translation adjustment gain of $1,028,000 for 1999 and $1,122,000 for 1998 classified in Stockholders' Equity. l. Comprehensive Income - In 1998, the Company adopted Statement of Financial Accounting Standards No. 130 "Reporting Comprehensive Income"("SFAS 130") which establishes standards for reporting and display of comprehensive income and its components in a full set of general purpose financial statements. Comprehensive income includes net income and other comprehensive income, which includes, but is not limited to, unrealized gains for marketable securities and future contracts, foreign currency translation adjustments and minimum pension liability adjustments. The impact of adopting SFAS No. 130 for the three years ended December 31, 1999 was not material. m. Recent Accounting Pronouncements - In June 1998, the Financial Accounting Standards Board issued SFAS 133 "Accounting for Derivative Instruments and Hedging Activities" which, as amended, is effective for all fiscal years beginning after June 15, 2000 (January 1, 2001 for the Company). SFAS No. 133 requires that derivatives be reported on the balance sheet at fair value and, if the derivative is not designated as a hedging instrument, changes in fair value must be recognized in earnings in the period of change. If the derivative is designated as a hedge and to the extent such hedge is determined to be effective, changes in fair value are either offset by the change in fair value of the hedged asset or liability (if applicable) or reported as a component of other comprehensive income in the period of change, and subsequently recognized in earnings when the offsetting hedged transaction occurs. The definition of derivatives has also been expanded to include contracts that require physical delivery of oil and gas if the contract allows for net cash settlement. The Company currently uses derivatives to hedge oil and gas price risk and gains or losses on such derivatives are recorded as adjustments to oil and gas sales. Accordingly, adoption of SFAS No. 133 should not have a significant impact on reported earnings, but could have a material impact on comprehensive income and the reported financial position of the Company. For the year ended December 31, 1998, the Company elected early adoption of SOP 98-5, "Reporting the Costs of Start-Up Activities", which requires that costs associated with start-up activities be expensed as incurred. Initial application of the SOP is required to be reported as the cumulative effect of a change in accounting principle. The adoption of SOP 98-5 did not have a material impact on the Company's financial position or the results of its operations. F-10 THE WISER OIL COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued) December 31, 1999, 1998 and 1997 2. Divestitures In April and May 1999, the Company entered into three separate agreements to sell its oil and gas properties in the Appalachia area, certain properties in Texas and New Mexico and virtually all of its royalty interests in the United States (the "Second Quarter Property Sales"). The Second Quarter Property Sales were closed in April and May 1999 for an aggregate sales price of $42,300,000, before fees and adjustments, and represented approximately 19% of the Company's proved reserves as of December 31, 1998. The Company recognized a net gain of $3,361,000 from the Second Quarter Property Sales and the revenues and expenses associated with the sold properties are included in the Company's consolidated statements of income through the various closing dates. 3. Marketable Securities The Company follows the accounting procedures as established by SFAS No. 115, "Accounting for Certain Investments in Debt and Equity Securities". Under SFAS No. 115 marketable securities, such as those owned by the Company, are classified as available-for-sale securities and are to be reported at market value, with unrealized gains and losses, net of income taxes, excluded from earnings and reported as a separate component of stockholders' equity. All marketable securities were liquidated during 1997. The Company recognized a pretax gain of $7,495,000 in 1997 from the sale of its marketable securities. 4. Long-term Debt a. On May 21, 1997, the Company sold $125 million in principal amount of 9 1/2% Senior Subordinated Notes ("2007 Notes") due May 15, 2007, providing net proceeds to the Company of $120,898,000. The original issue price was 99.718%. The Company used the net proceeds from the sale of the 2007 Notes to repay all outstanding bank indebtedness and for general corporate purposes. The 2007 Notes are redeemable at the option of the Company, in whole or in part, at any time on or after May 15, 2002 at a redemption price of 104.75%, plus accrued interest to the date of redemption, and declining at the rate of 1.583% per year to May 15, 2005 and 100% thereafter. Prior to May 15, 2000, the Company may, at its option, redeem up to 33 1/3% of the original principal amount at a redemption price of 109.5%, plus accrued interest to the date of redemption, with the net proceeds from any future public offering of Company stock. Under the terms of the 2007 Notes, the Company must meet certain tests before it is able to pay cash dividends or make other restricted payments, incur additional indebtedness, engage in transactions with its affiliates, incur liens and engage in certain sale and leaseback arrangements. The terms of the 2007 Notes also limit the Company's ability to undertake a consolidation, merger or transfer of all or substantially all of its assets. In addition, the Company is, subject to certain conditions, obligated to offer to repurchase the 2007 Notes at par value plus accrued interest to the date of repurchase with the net cash proceeds of certain sales or dispositions of assets. Upon a change of control, as defined, the Company will be required to make an offer to purchase the 2007 Notes at 101% of the principal amount thereof, plus accrued interest to the date of purchase. F-11 THE WISER OIL COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued) December 31, 1999, 1998 and 1997 b. On May 10, 1999 the Company entered into a $25 million Restated Credit Agreement ("BankOne Revolver") with Bank One, Texas, NA. The BankOne Revolver provides the Company with up to a $25 million line of credit through April 30, 2001. The amounts available for borrowing are based on the Company's oil and gas reserves and the Company's Borrowing Base at December 31, 1999 was $8 million. Available loan and interest options are (i) Prime Rate Loans, at the bank's prime interest rate and (ii) Eurodollar Loans, at LIBOR plus 2.5%, 2.75% or 3% depending on the percentage of the Borrowing Base actually borrowed by the Company. The average interest rate during 1999 under the Credit Agreement was 6.56%. The commitment fee on the unused Borrowing Base is 0.5%. The BankOne Revolver imposes certain restrictions on sales of assets, payment of dividends and incurrence of indebtedness and requires the Company to, among other things, maintain certain financial ratios and make monthly escrow deposits of $990,000 to fund the semi-annual interest payments on the 9 1/2% Senior Subordinated Notes. At December 31, 1999, restricted cash included $992,000 of escrow deposits which are restricted to fund the May 15, 2000 interest payment on the 9 1/2% Senior Subordinated Notes. The Company is currently negotiating certain amendments to the BankOne Revolver and, subject to the completion of the negotiations, the Company has classified the entire $500,000 balance outstanding at December 31, 1999 as a current liability in the Consolidated Balance Sheets. c. On June 23, 1994, the Company entered into a Credit Agreement with NationsBank of Texas, N. A. as agent, which provided for a term loan to Wiser Canada and a revolving credit facility to the Company. On December 23, 1997, the Credit Agreement was renewed under the same basic terms. The Credit Agreement provided the Company with up to a $150 million line of credit through March 31, 2002. The amounts available for borrowing were determined under formulas related to oil and gas reserves and the Company's borrowing base at December 31, 1998 was $25 million. The indebtedness outstanding under the Credit Agreement was secured by a guaranty from Wiser Canada. The average interest rate during 1998 under the Credit Agreement was 6.15%. The Credit Agreement required the Company to, among other things, maintain certain financial ratios and imposes certain restrictions on sales of assets, payment of dividends and the incurrence of indebtedness. At December 31, 1998 and through March 31, 1999, the Company was not able to maintain one of the financial ratios required by the Credit Agreement. After March 31, 1999 and through April 15, 1999, the Company was not able to maintain two of the financial ratios required by the Credit Agreement. On May 11, 1999 the Company repaid the outstanding balance under the Credit Agreement and the Credit Agreement was terminated. The Company paid $12,993,000, $12,375,000 and $8,120,000 in interest during 1999, 1998 and 1997, respectively.
Long-term debt consists of the following (000's): December 31, ------------------ 1999 1998 ------ ------ 2007 Notes - 9.5% interest rate at December 31, 1999........ $124,526 $124,452 BankOne Revolver - 8.5% interest rate at December 31, 1999.. 500 -- Credit Agreement............................................ -- 21,000 -------- -------- 125,026 145,452 Less current maturities..................................... 500 21,000 -------- -------- $124,526 $124,304 ======== ========
F-12 THE WISER OIL COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued) December 31, 1999, 1998 and 1997 The annual requirements for reduction of principal of long-term debt outstanding as of December 31, 1999 are estimated as follows (000's): 2000 ........................... $ 500 2001 ........................... -- 2002 ........................... -- 2003 ........................... -- Thereafter ..................... 124,526 --------- $ 125,026 ========= 5. Income Taxes The Company provides deferred income taxes for differences between the tax reporting basis and the financial reporting basis of assets and liabilities. The Company follows the accounting procedures established by SFAS No. 109, "Accounting for Income Taxes". The Company did not pay any Federal income taxes in 1999 or 1998 and paid $566,000 in 1997. Income tax expense (benefit) for the three years ended December 31, 1999 was as follows (000's):
1999 1998 1997 ------- -------- ------ Current: Federal.......................................... $ (173) $ (1,248) $ 375 State............................................ -- 100 200 ------ -------- ------ (173) (1,148) 575 ------ -------- ------ Deferred: Federal....................................... (686) (9,592) (311) ------ -------- ------ Total income tax expense (benefit)................ $ (859) $(10,740) $ 264 ====== ======== ======
A reconciliation of the statutory federal income tax rate to the Company's effective tax rate follows:
1999 1998 1997 ------ ------ ------ Statutory federal income tax rate.................................. 34.0% 34.0% 34.0% Statutory depletion in excess of cost basis........................ -- -- (5.4) State taxes, net of federal income taxes........................... -- -- 5.8 Dividends received credit.......................................... -- -- (1.3) Non-conventional fuels credit...................................... -- -- (7.3) Net operating loss................................................. (28.5) (3.5) -- Reversal of valuation allowance................................... -- -- (15.3) Adjustment of accrued tax position................................. -- -- (3.1) ------ ------ ------ Effective tax rate................................................. 5.5% 30.5% 7.4% ====== ====== ======
F-13 THE WISER OIL COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued) December 31, 1999, 1998 and 1997 The deferred tax liabilities and assets at December 31, 1999 and 1998 were as follows (000's):
1999 1998 -------- -------- Deferred tax assets: Net operating loss carryforwards..................... $ 5,530 $ 6,013 Alternative minimum tax credit carryforwards......... 3,040 3,040 Other................................................ 265 349 ------- -------- Total gross deferred tax assets.................... 8,835 9,053 Less valuation allowance........................... (3,069) -- ------- -------- Net deferred tax assets............................ 5,766 9,402 Deferred tax liabilities: Property and equipment, principally due to differences in depreciation and the expensing of intangible drilling costs for tax purposes......... (5,766) (10,088) ------- -------- Net deferred tax liability........................... $ -- $ (686) ======= ========
In 1998, the Company had a net operating loss (NOL) for Federal income tax purposes of $20,736,000. In 1999, the Company received a Federal income tax refund of $1,442,000 as a result of carrying back $8,335,000 of the 1998 NOL. The majority of the NOL carryforwards do not expire until 2018 and the alternative minimum tax credit carryforwards can be carried forward indefinitely. The tax benefits of carryforwards are recorded as an asset to the extent that management assesses the future utilization of such carryforwards as "more likely than not". When the future utilization of some portion of the carryforwards is determined not to be "more likely than not", a valuation allowance is provided to reduce the recorded tax benefits from such assets. At December 31, 1999, a valuation allowance of $3,069,000 was provided to reduce deferred tax assets to an amount equal to deferred tax liabilities. 6. Oil and Gas Producing Activities Set forth below is certain information regarding the aggregate capitalized costs of oil and gas properties and costs incurred in oil and gas property acquisitions, exploration and development activities (000's):
U.S. Canada Total ---------- --------- --------- December 31, 1999: ------------------ Capitalized Costs: Proved properties......... $172,428 $ 87,295 $ 259,723 Unproved properties....... 10,480 4,557 15,037 -------- -------- --------- Total................... 182,908 91,852 274,760 Accumulated DD&A.......... (66,519) (49,369) (115,888) -------- -------- --------- Net capitalized cost...... $116,389 $ 42,483 $ 158,872 ======== ======== ========= Costs Incurred during 1999: Property acquisition...... $ 409 $ 227 $ 636 Exploration............... 1,108 3,566 4,674 Development............... 2,524 2,838 5,362
F-14 THE WISER OIL COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued) December 31, 1999, 1998 and 1997
December 31, 1998: ------------------ Capitalized Costs: Proved properties...................................... $ 261,361 $ 83,668 $ 345,029 Unproved properties.................................... 18,007 4,938 22,945 --------- -------- --------- Total................................................ 279,368 88,606 367,974 Accumulated DD&A....................................... (114,769) (41,825) (156,594) --------- -------- --------- Net capitalized cost................................... $ 164,599 $ 46,781 $ 211,380 ========= ======== ========= Costs Incurred during 1998: Property acquisition................................... $ 2,946 $ 1,181 $ 4,127 Exploration (A)........................................ 12,162 2,147 14,309 Development............................................ 10,226 11,397 21,623 (A) U.S. includes $1,615 for exploration in Peru, S.A. December 31, 1997: ------------------ Capitalized Costs: Proved properties...................................... $ 247,809 $ 76,325 $ 324,134 Unproved properties.................................... 17,315 5,206 22,521 --------- -------- --------- Total................................................ 265,124 81,531 346,655 Accumulated DD&A....................................... (95,038) (34,589) (129,627) --------- -------- --------- Net capitalized cost................................... $ 170,086 $ 46,942 $ 217,028 ========= ======== ========= Costs Incurred during 1997: Property acquisition................................... $ 22,399 $ 5,377 $ 27,776 Exploration............................................ 8,906 3,461 12,367 Development............................................ 27,380 9,593 36,973
7. Employee Pension Plan The Company has a noncontributory defined benefit pension plan, which covers substantially all full-time employees. Plan participants become fully vested after five years of continuous service. The retirement benefit formula is based on the employee's earnings, length of service and age at retirement. Contributions required to fund plan benefits are determined according to the Projected Unit Credit Method. The assets of the plan are primarily invested in equity and debt securities. An amendment to the pension plan, effective January 1, 1993, reduced the normal retirement age from 65 years to 62 years. Effective December 11, 1998, the pension plan was further amended to curtail certain pension benefits. F-15 THE WISER OIL COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued) December 31, 1999, 1998 and 1997 The net pension expense and principal assumptions utilized in computing net pension expense were as follows (000's):
1999 1998 1997 -------- -------- --------- Service cost..................................................... $ -- $ 375 $ 345 Interest cost.................................................... 676 729 682 Expected return on plan assets................................... (780) (711) (654) Amortization of prior service cost............................... -- 148 149 Amortization of transition obligation............................ (25) (22) (35) Recognized gain (loss)........................................... -- -- (6) Plan curtailment adjustment...................................... -- (778) -- ------- ------- ------- Net periodic pension cost (credit)............................... $ (129) $ (259) $ 481 ======= ======= ======= Discount rate.................................................... 8.0% 7.0% 8.0% Rate of return on plan assets.................................... 8.5% 8.5% 8.5% Rate of increase in compensation levels.......................... 0.0% 0.0% 5.0%
The following table presents the funded status of the Company's pension plan as of December 31 (000's):
Change in benefit obligations: 1999 1998 1997 ------- ------- ------- Benefit obligation at beginning of year.......................... $ 9,666 $ 9,269 $ 9,321 Service cost..................................................... -- 375 345 Interest cost.................................................... 676 729 682 Actuarial gain (loss)............................................ (712) 1,333 (480) Benefits paid.................................................... (623) (602) (599) Effect of plan curtailment....................................... -- (1,438) -- ------- ------- ------- Benefit obligation at end of year................................ 9,007 9,666 9,269 Change in plan assets: Fair value of plan assets at beginning of year................... 9,477 8,547 8,010 Actual return on plan assets..................................... 1,789 1,032 736 Employer contributions........................................... -- 500 400 Benefits paid.................................................... (623) (602) (599) ------- ------- ------- Fair value of plan assets at end of year......................... 10,643 9,477 8,547 Plan assets over (under) benefits obligations....................... 1,636 (189) (722) Unrecognized net actuarial loss (gain).............................. (1,740) (16) (1,032) Unrecognized transition obligation.................................. (43) (65) (87) Unrecognized prior service cost..................................... -- -- 812 ------- ------- ------- Net amount recognized............................................... $ (147) $ (270) $(1,029) ======= ======= =======
The net amounts recognized in the consolidated balance sheets consist of the following (000's):
1999 1998 1997 ------- ------- ------- Accrued benefit cost............................................ $ (147) $ (270) $(1,029) ======= ======= =======
F-16 THE WISER OIL COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued) December 31, 1999, 1998 and 1997 8. Employee Savings Plan The Company has a qualified Savings Plan available to all employees. An employee may elect to have up to 15% of the employee's base monthly compensation, exclusive of other forms of special or extra compensation, withheld and placed in the Savings Plan account. On a monthly basis, the Company contributes to this account an amount equal to 50% of the employee's contribution, limited to 3% of the employee's base compensation. Company contributions to the Savings Plan were $99,000, $156,000 and $142,000, in 1999, 1998 and 1997, respectively. 9. Business Segment Information In 1998, the Company adopted SFAS No. 131, "Disclosures about Segments of an Enterprise and Related Information" which requires reporting of financial and descriptive information about a company's reportable operating segments. The Company has identified only one operating segment, which is the exploration for and production of oil and gas with sales made to domestic and Canadian energy customers. Sales to major customers for the year ended December 31, 1999 were $19,345,000 to Highland Energy Company, $5,013,000 to CXY Energy Marketing and $4,972,000 to EOTT Energy Operating Ltd. which represented 41%, 11% and 10%, respectively, of the Company's total oil and gas revenues. Sales to major customers for the year ended December 31, 1998 were $20,684,000 to Highland Energy Company and $7,656,000 to Koch Oil Co. Ltd. which represented 34% and 13%, respectively, of the Company's total oil and gas revenues. The sales to Koch Oil Co. Ltd. accounted for approximately 55% of the Company's revenues from sales of its Canadian production in 1998. Sales to major customers for the year ended December 31, 1997 were $28,352,000 to Highland Energy Company, $11,617,000 to Koch Oil Co. Ltd. and $9,474,000 to Enron Oil Trading and Transportation which represented 37%, 15% and 12%, respectively, of the Company's total oil and gas revenues. The sales to Koch Oil Co. Ltd. accounted for approximately 73% of the Company's revenues from sales of its Canadian production in 1997. However, due to the nature of the oil and gas industry, the Company is not dependent upon any of these customers. The loss of any major customer would not have a material adverse impact on the Company's business. The following table summarizes the oil and gas activity of the Company by geographic area for the years ended December 31, 1999, 1998 and 1997.
U.S. Canada Total --------- -------- --------- 1999: ----- Total revenues................................ $ 37,389 $15,405 $ 52,794 Costs and expenses: Production and operating.................... 17,062 4,049 21,111 Purchased natural gas....................... 336 -- 336 DD&A........................................ 10,655 7,008 17,663 Property impairments........................ 900 1,314 2,214 Exploration................................. 4,760 2,299 7,059 Other operating............................. 18,784 1,342 20,126 -------- ------- -------- Total costs and expenses................. 52,497 16,012 68,509 -------- ------- -------- Earnings (loss) before income taxes........... (15,108) (607) (15,715) Income tax expense (benefit).................. (859) -- (859) -------- ------- -------- Net income (loss)............................. $(14,249) $ (607) $(14,856) ======== ======= ======== At year end: Property and equipment, net of accumulated DD&A.. $117,378 $42,595 $159,973 ======== ======= ======== Total assets..................................... $148,773 $47,953 $196,726 ======== ======= ========
F-17 THE WISER OIL COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued) December 31, 1999, 1998 and 1997
1998: ----- Total revenues...................................... $ 47,106 $14,302 $ 61,408 Costs and expenses: Production and operating.......................... 22,217 4,312 26,529 Purchased natural gas............................. 1,440 -- 1,440 DD&A.............................................. 16,548 9,263 25,811 Property impairments.............................. 1,766 2,072 3,838 Exploration....................................... 13,046 2,282 15,328 Other operating................................... 21,669 1,999 23,668 -------- ------- -------- Total costs and expenses....................... 76,686 19,928 96,614 -------- ------- -------- Earnings (loss) before income taxes.................. (29,580) (5,626) (35,206) Income tax expense (benefit)......................... (10,740) -- (10,740) -------- ------- -------- Net income (loss).................................... $(18,840) $(5,626) $(24,466) ======== ======= ======== At year end: Property and equipment, net of accumulated DD&A...... $166,281 $47,014 $213,295 ======== ======= ======== Total assets......................................... $181,013 $50,797 $231,810 ======== ======= ======== 1997: ----- Total revenues...................................... $ 71,706 $16,109 $ 87,815 Costs and expenses: Production and operating.......................... 23,058 4,125 27,183 Purchased natural gas............................. 1,622 -- 1,622 DD&A.............................................. 14,032 8,945 22,977 Property impairments.............................. 1,786 1,503 3,289 Exploration....................................... 6,956 2,699 9,655 Other operating................................... 16,407 3,099 19,506 -------- ------- -------- Total costs and expenses....................... 63,861 20,371 84,232 -------- ------- -------- Earnings before income taxes........................ 7,845 (4,262) 3,583 Income tax expense.................................. 264 -- 264 -------- ------- -------- Net income.......................................... $ 7,581 $(4,262) $ 3,319 ======== ======= ======== At year end: Property and equipment, net of accumulated DD&A..... $173,433 $47,275 $220,708 ======== ======= ======== Total assets........................................ $202,474 $52,082 $254,556 ======== ======= ========
10. Stock Compensation Plans Stock Options SFAS No. 123, "Accounting for Stock-Based Compensation," encourages but does not require companies to record compensation cost for stock-based employee compensation plans at fair value. During 1996, the Company adopted the disclosure provisions of SFAS No. 123. The Company continues to apply the accounting provisions of APB Opinion 25, "Accounting for Stock Issued to Employees," and related interpretations to account for stock-based compensation. Accordingly, compensation cost for stock options is measured as the excess, if any, of the quoted market price of the Company's stock at the date of the grant over the amount an employee must pay to acquire the stock. F-18 THE WISER OIL COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued) December 31, 1999, 1998 and 1997 The Company has two stock option plans, the 1991 Stock Incentive Plan ("Incentive Plan") and the 1991 Non-Employee Directors' Stock Option Plan ("Directors' Plan"). The Incentive Plan provides for the issuance of ten- year options with a variable vesting period and a grant price equal to the fair market value at the issue date. The Directors' Plan, as amended, provides for the issuance of ten-year options with a six month vesting period and a grant price equal to the fair market value at the issue date. A summary of the status of the Company's two stock option plans at December 31, 1999, 1998 and 1997 and changes during the years then ended follows:
1999 1998 1997 ----------------------- ------------------------- ------------------------ Exercise Exercise Exercise Shares Price(1) Shares Price(1) Shares Price(1) ----------- ----------- ----------- ----------- ----------- ----------- Outstanding at beginning of year.. 1,027,350 $15.61 1,022,475 $15.62 876,500 $15.02 Granted........................... 223,825 4.96 10,500 11.94 164,500 18.87 Exercised......................... -- -- -- -- (15,025) 15.68 Expired and cancelled............. (32,600) 14.71 (5,625) 11.25 (6,500) 15.76 ---------- ------ ---------- ------ ---------- ------ Outstanding at end of year........ 1,218,575 $13.68 1,027,350 $15.61 1,022,475 $15.62 ========== ====== ========== ====== ========== ====== Exercisable at end of year........ 1,137,450 $13.27 868,850 $15.40 773,975 $15.23 ========== ====== ========== ====== ========== ====== Fair value of options granted(1).. $1.02 $3.66 $6.07 ===== ===== =====
(1) Weighted average per option granted. 223,825 of the options outstanding at December 31, 1999 have exercise prices between $3.50 and $5, with a weighted average exercise price of $4.96 and a weighted average remaining contractual life of 9.3 years. All of the $3.50 to $5 options are currently exercisable with a weighted average exercise price of $4.96. 647,250 of the options outstanding at December 31, 1999 have exercise prices between $11 and $15, with a weighted average exercise price of $14.40 and a weighted average remaining contractual life of 6.7 years. 629,875 of the $11 to $15 options are currently exercisable with a weighted average exercise price of $14.29. The remaining 347,500 options have exercise prices between $15 and $20, with a weighted average exercise price of $17.95 and a weighted average contractual life of 5.3 years. 283,750 of the $15 to $20 options are currently exercisable with a weighted average exercise price of $17.56. The fair value of each option grant is estimated on the date of grant using the Black-Scholes option pricing model with the following weighted-average assumptions used for grants for both the Incentive Plan and the Directors' Plan:
1999 1998 1997 ------ ------ ------ Risk free interest rate............ 5.71% 5.58% 6.29% Expected dividend yields........... 0.00% 1.01% .64% Expected lives, in years........... 5.00 5.00 5.06 Expected volatility................ 48.11% 25.99% 23.66%
F-19 THE WISER OIL COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued) December 31, 1999, 1998 and 1997 Had compensation cost been determined consistent with SFAS No. 123, the Company's net income and basic earnings per share would have been reduced to the following pro forma amounts:
1999 1998 1997 ---------- ---------- ------- Net income (loss) - as reported (in thousands)....... $(14,856) $(24,466) $3,319 Net income (loss) - pro forma (in thousands)......... (15,186) (24,685) 2,256 Earnings (loss) per share - as reported.............. $ (1.66) (2.73) 0.37 Earnings (loss) per share - pro forma................ (1.70) (2.76) 0.25
Because the SFAS No. 123 method of accounting has not been applied to options granted prior to January 1, 1995, the resulting pro forma compensation cost may not be representative of compensation cost to be expected in future years. Share Appreciation Rights Plan The Company has a share appreciation rights ("SARs") plan which authorizes the granting of SARs to employees of the Company. Upon exercise, SARs allow the holder to receive the difference between the SARs exercise price and the fair market value of the Company's common stock covered by the SARs on the exercise date. At December 31, 1999, 47,175 SARs were outstanding with an exercise price of $5.00 per share and 4,000 SARs were outstanding with an exercise price of $14.63 per share. The $5.00 SARs fully vested on November 19, 1999 and the $14.63 SARs vest at 25% per year. All SARs expire at the earlier of 5 years or termination of employment. 11. Preferred Stock In addition to Common Stock, the Company is authorized to issue 300,000 shares of Preferred Stock with a par value of $10 per share, none of which has been issued. 12. Earnings Per Share The Company accounts for earnings per share ("EPS") in accordance with SFAS No. 128, "Earnings Per Share". Under SFAS No. 128, basic EPS is computed by dividing net income by the weighted average common shares outstanding without including any potentially dilutive securities. Diluted EPS is computed by dividing net income by the weighted average common shares outstanding plus, when their effect is dilutive, common stock equivalents consisting of stock options. Previously reported EPS were equivalent to the diluted EPS calculated under SFAS No. 128. Following are the weighted average common shares outstanding used in the computation of basic EPS and diluted EPS for the years ended December 31, 1999, 1998 and 1997 (000's):
1999 1998 1997 ----- ----- ----- Basic EPS shares.... 8,952 8,952 8,949 ===== ===== ===== Diluted EPS shares.. 8,952 8,952 8,982 ===== ===== =====
F-20 THE WISER OIL COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued) December 31, 1999, 1998 and 1997 13. Subsequent Event On December 13, 1999, the Board of Directors approved the sale of not less than 600,000 shares of convertible preferred stock and not more than 1,000,000 shares of convertible preferred stock through a private placement to Wiser Investment Company, LLC ("WIC") for $25 million. The convertible preferred stock will be convertible at the option of the holder into shares of the Company's common stock at a conversion price of $4.25 per common share, subject to customary adjustments. The convertible preferred stock will pay dividends in cash or in shares of the Company's common stock, at the option of the Company, at an annual rate of 7%. The holders of the convertible preferred stock will have the same voting rights as the holders of the Company's common stock with each share of the convertible preferred stock having one vote for each share of common stock into which it is convertible. Any shares of convertible preferred stock not previously converted will convert automatically to common stock three years after the transaction closing date or whenever the market price of the Company's common stock exceeds $10.00 per share for a period of 60 consecutive trading days. In addition, WIC will acquire, for a nominal sum, seven-year warrants to purchase that number of the Company's common stock equal to 741,716 multiplied by a fraction, of which the numerator is the total number of shares of convertible preferred stock purchased at the closing and any option closing and the denominator is 1,000,000, at a purchase price of $0.02 per warrant. The strike price of the warrants issued at closing will be $4.25 per share, subject to adjustment. The transaction is expected to close in the second quarter of 2000 and is subject to stockholders approval and receipt of financing by WIC. The Board of Directors will also be changed to include four of the current directors and three new directors designated by WIC 14. Summary of Guaranties of 9 1/2% Senior Subordinated Notes In May 1997, the Company issued $125 million aggregate principal amount of its 9 1/2% senior Subordinated Notes due 2007 pursuant to an offering exempt from registration under the Securities Act of 1933. The notes are unsecured obligations of the Company, subordinated in right of payment to all existing and any future senior indebtedness of the Company. The notes rank pari passu with any future senior subordinated indebtedness and senior to any future junior subordinated indebtedness of the Company. The notes are fully and unconditionally guaranteed, jointly and severally, on an unsecured, senior subordinated basis by certain wholly owned subsidiaries of the Company (the "Subsidiary Guarantors"). At the time of the initial issuance of the notes, Wiser Oil Delaware, Inc., Wiser Delaware LLC, The Wiser Oil Company of Canada , (collectively "Wiser Canada"), The Wiser Marketing Company and T.W.O.C., Inc. and were the Subsidiary Guarantors (the "Initial Subsidiary Guarantors"). Except for two wholly owned subsidiaries that are inconsequential to the Company on a consolidated basis, the Initial Subsidiary Guarantors comprise all of the Company's direct and indirect subsidiaries. Following is summarized financial information of the Subsidiary Guarantors. The Company has not presented separate financial statements and other disclosures concerning each Subsidiary Guarantor because management has determined that they are not material to investors. There are no significant contractual restrictions on distributions from each of the Subsidiary Guarantors to the Company. F-21 THE WISER OIL COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued) December 31, 1999, 1998 and 1997
Subsidiary Guarantors ---------------------------------------- The Wiser Wiser T.W.O.C. Marketing Combined Canada Inc. Company Total -------- -------- --------- -------- Revenues: For the Year Ended December 31, 1999.. $ 15,405 $ -- $ 523 $ 15,928 For the Year Ended December 31, 1998.. 14,303 1 2,141 16,445 For the Year Ended December 31, 1997.. 16,109 7,687 2,304 26,100 Earnings (Loss) Before Income Taxes: For the Year Ended December 31, 1999.. $ (607) $ -- $ 68 $ (539) For the Year Ended December 31, 1998.. (5,626) (14) 243 (5,397) For the Year Ended December 31, 1997.. (4,262) 7,671 231 3,640 Net Income (Loss): For the Year Ended December 31, 1999.. $ (577) $ -- $ 65 $ (512) For the Year Ended December 31, 1998.. (3,882) (10) 168 (3,724) For the Year Ended December 31, 1997.. (3,947) 7,103 214 3,370 Cash Flows from Operating Activities: For the Year Ended December 31, 1999.. $ 9,139 $ -- $ 65 $ 9,204 For the Year Ended December 31, 1998.. 6,863 (10) 168 7,021 For the Year Ended December 31, 1997.. 8,833 7,103 214 16,150 Cash Flows from Investing Activities: For the Year Ended December 31, 1999.. $ (5,361) $ -- $ -- $ (5,361) For the Year Ended December 31, 1998.. (12,421) -- -- (12,421) For the Year Ended December 31, 1997.. (17,241) -- -- (17,241) Cash Flows from Financing Activities: For the Year Ended December 31, 1999.. $ (2,522) $ -- $ -- $ (2,522) For the Year Ended December 31, 1998.. 6,227 -- -- 6,227 For the Year Ended December 31, 1997.. 7,543 -- -- 7,543 Net Increase (Decrease) in Cash: For the Year Ended December 31, 1999.. $ 1,256 $ -- $ 65 $ 1,321 For the Year Ended December 31, 1998.. 669 (10) 168 827 For the Year Ended December 31, 1997.. (865) 7,103 214 6,452 Current Assets: December 31, 1999..................... $ 5,357 $ 3 $ -- $ 5,360 December 31, 1998..................... 3,782 3 213 3,998 December 31, 1997..................... 4,808 44 165 5,017 Total Assets: December 31, 1999..................... $ 47,953 $ 3 $ -- $ 47,956 December 31, 1998..................... 50,797 3 526 51,326 December 31, 1997..................... 52,083 44 492 52,619
F-22 THE WISER OIL COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued) December 31, 1999, 1998 and 1997
Subsidiary Guarantors --------------------------------------- The Wiser Wiser T.W.O.C. Marketing Combined Canada Inc. Company Total -------- -------- --------- -------- Current Liabilities: December 31, 1999.............. $ 5,116 $-- $ -- $ 5,116 December 31, 1998.............. 4,806 -- 361 5,167 December 31, 1997.............. 6,646 -- 250 6,896 Non-current Liabilities: December 31, 1999.............. $17,851 $-- $ -- $17,851 December 31, 1998.............. 17,846 -- -- 17,846 December 31, 1997.............. 9,474 -- -- 9,474 Stockholders' Equity (Deficit): December 31, 1999.............. $24,986 $ 3 $ -- $24,989 December 31, 1998.............. 28,145 3 165 28,313 December 31, 1997.............. 35,963 44 242 36,249
F-23 THE WISER OIL COMPANY Supplemental Financial Information For the years ended December 31, 1999, 1998 and 1997 (Unaudited) The following pages include unaudited supplemental financial information as currently required by the Securities and Exchange Commission (SEC) and the Financial Accounting Standards Board. 15. Estimated Quantities of Oil and Gas Reserves (Unaudited) Proved reserves are the estimated quantities of crude oil, natural gas and natural gas liquids, which upon analysis of geological and engineering data appear with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are proved reserves which can be expected to be recovered through existing wells with existing equipment and under existing operating conditions. The estimation of reserves requires substantial judgment on the part of petroleum engineers and may result in imprecise determinations, particularly with respect to new discoveries. Accordingly, it is expected that the estimates of reserves will change as future production and development information becomes available and that revisions in these estimates could be significant. Following is a reconciliation of the Company's estimated net quantities of proved oil and gas reserves, as estimated by independent petroleum consultants.
Oil (MBbls) Gas (MMcf) ------------------------------- ---------------------------------- U.S. Canada Total U.S. Canada Total ------- ----------- ------- -------- ---------- -------- Balance December 31, 1996..................... 28,080 3,532 31,612 89,546 23,831 113,377 Revisions of previous estimates............. (2,614) 274 (2,340) 1,208 1,988 3,196 Properties sold and abandoned............... (810) (344) (1,154) (902) (2,606) (3,508) Reserves purchased in place................. 1,493 1,013 2,506 8,961 -- 8,961 Extensions and discoveries.................. 1,205 653 1,858 7,601 2,667 10,268 Production.................................. (2,037) (724) (2,761) (9,466) (2,734) (12,200) ------- ------- -------- --------- -------- --------- Balance December 31, 1997..................... 25,317 4,404 29,721 96,948 23,146 120,094 Revisions of previous estimates............. (2,773) 689 (2,084) (4,001) 1,362 (2,639) Properties sold and abandoned............... (215) (118) (333) (237) (882) (1,119) Reserves purchased in place................. 2,686 -- 2,686 319 -- 319 Extensions and discoveries.................. 407 306 713 12,971 4,111 17,082 Production.................................. (1,837) (878) (2,715) (10,535) (3,221) (13,756) ------- ------- -------- --------- -------- --------- Balance December 31, 1998..................... 23,585 4,403 27,988 95,465 24,516 119,981 Revisions of previous estimates............. 358 (164) 194 (3,070) (2,951) (6,021) Properties sold and abandoned............... (1,928) (20) (1,948) (41,235) (352) (41,587) Reserves purchased in place................. 461 -- 461 39 -- 39 Extensions and discoveries.................. 277 391 668 2,150 5,532 7,682 Production.................................. (1,257) (676) (1,933) (7,186) (2,915) (10,101) ------- ------- -------- --------- -------- --------- Balance December 31, 1999..................... 21,496 3,934 25,430 46,163 23,830 69,993 ======= ======= ======== ========= ======== ========= Proved Developed Reserves at December 31, (1): 1996........................................ 24,892 3,225 28,117 80,652 22,477 103,129 1997........................................ 23,798 4,404 28,202 87,688 21,771 109,459 1998........................................ 22,701 4,253 26,954 86,610 23,736 110,346 1999........................................ 20,327 3,719 24,046 43,771 22,813 66,584
(1) Reserve volumes as assigned by third party engineers have been increased to reflect the effect of the Alberta Royalty Tax Credit refund. Total proved and proved developed reserves were increased by 364 MBBL and 1,914 MMCF for 1997, 389 MBBL and 2,088 MMCF for 1998 and 136 MBBL and 826 MMCF for 1999. Standardized Measure of Discounted Future Net Cash Flows of Proved Oil and Gas Reserves (Unaudited) The Company has estimated the standardized measure of discounted future net cash flows and changes therein relating to proved oil and gas reserves in accordance with the standards established by the Financial Accounting Standards Board through its Statement No. 69. The estimates of future cash inflows are based year-end prices. F-24 THE WISER OIL COMPANY Supplemental Financial Information For the years ended December 31, 1999, 1998 and 1997 (Unaudited) Estimated future production of proved reserves and estimated future production and development costs of proved reserves are based on year-end costs and economic conditions. Estimated future income tax expense is calculated by applying year-end statutory tax rates (adjusted for permanent differences and tax credits) to estimated future pretax net cash flows related to proved oil and gas reserves, less the tax basis of the properties involved. This standardized measure of discounted future net cash flows is an attempt by the Financial Accounting Standards Board to provide the users of financial statements with information regarding future net cash flows from proved reserves. However, the users of these financial statements should use extreme caution in evaluating this information. The assumptions required to be used in these computations are subjective and arbitrary. Had other equally valid assumptions been used, significantly different results of discounted future net cash flows would result. Therefore, these estimates do not necessarily reflect the current value of the Company's proved reserves or the current value of discounted future net cash flows for the proved reserves. The following are the Company's estimated standardized measure of discounted future net cash flows from proved reserves (000's):
U.S. Canada Total ---------- ---------- ---------- December 31, 1999: ------------------ Future cash flows....................................... $ 595,402 $141,011 $ 736,413 Future production and development costs................. (277,756) (38,989) (316,745) Future income tax expense............................... (76,024) (17,816) (93,840) --------- -------- --------- Future net cash flows................................... 241,622 84,206 325,828 10% Annual discount for estimated timing of cash flows.. (114,440) (34,472) (148,912) --------- -------- --------- Standardized measure of discounted cash flows............ $ 127,182 $ 49,734 $ 176,916 ========= ======== ========= December 31, 1998: ------------------ Future cash flows....................................... $ 440,715 $ 87,869 $ 528,584 Future production and development costs................. (278,468) (31,147) (309,615) Future income tax expense............................... (15,091) (5,063) (20,154) --------- -------- --------- Future net cash flows................................... 147,156 51,659 198,815 10% Annual discount for estimated timing of cash flows.. (67,065) (18,518) (85,583) --------- -------- --------- Standardized measure of discounted cash flows.......... $ 80,091 $ 33,141 $ 113,232 ========= ======== ========= December 31, 1997: ------------------ Future cash flows....................................... $ 650,810 $ 98,143 $ 748,953 Future production and development costs................. (357,598) (32,062) (389,660) Future income tax expense............................... (60,477) (6,512) (66,989) --------- -------- --------- Future net cash flows................................... 232,735 59,569 292,304 10% Annual discount for estimated timing of cash flows.. (97,116) (20,699) (117,815) --------- -------- --------- Standardized measure of discounted cash flows.......... $ 135,619 $ 38,870 $ 174,489 ========= ======== =========
F-25 THE WISER OIL COMPANY Supplemental Financial Information For the years ended December 31, 1999, 1998 and 1997 (Unaudited) The following are the sources of changes in the standardized measure of discounted net cash flows (000's):
1999 1998 1997 ------ ------ ------ Standardized measure, beginning of year................. $113,232 $174,489 $ 317,180 Sales, net of production costs.......................... (26,248) (31,445) (47,959) Net change in price and production costs................ 151,018 (78,321) (204,859) Reserves purchased in place............................. 2,503 1,817 30,570 Extensions, discoveries and improved recoveries......... 13,208 11,259 11,751 Change in future development costs...................... (355) 9,316 16,339 Revisions of previous quantity estimates and disposals.. (6,576) (4,846) (6,992) Sales of reserves in place.............................. (27,429) (1,698) (10,756) Accretion of discount................................... 12,383 21,007 41,431 Changes in timing and other............................. (19,794) (13,327) (33,752) Net change in income taxes.............................. (35,026) 24,981 61,536 -------- -------- --------- Standardized measure, end of year....................... $176,916 $113,232 $ 174,489 ======== ======== =========
16. Unaudited Quarterly Financial Data The supplementary financial data in the table below for each quarterly period within the years ended December 31, 1999 and 1998 are derived from the unaudited consolidated financial statements of the Company.
Net Earnings Income (Loss) Revenues (Loss) Per Share --------- --------- ---------- (000's) (000's) 1999: First quarter........ $11,871 $(4,358) $(0.49) Second quarter....... 13,978 (1,055) (0.12) Third quarter........ 12,710 (5,391) (0.60) Fourth quarter....... 14,235 (4,052) (0.45) 1998: First quarter........ $17,415 $(3,556) $(0.40) Second quarter....... 16,019 (4,675) (0.52) Third quarter........ 13,833 (8,153) (0.91) Fourth quarter....... 14,141 (8,082) (0.90)
F-26 EX-10.14 2 1997 SHARE APPRECIATION RIGHTS PLAN Exhibit 10.14 THE WISER OIL COMPANY 1997 SHARE APPRECIATION RIGHTS PLAN PREAMBLE THIS 1997 SHARE APPRECIATION RIGHTS PLAN (the "Plan"), made and executed at Dallas, Texas, by THE WISER OIL COMPANY, a Delaware corporation (the "Company"), is being established to promote the interests of the Company and its shareholders by more closely aligning the interests of certain key employees of the Company and its subsidiaries with the interests of the shareholders of the Company. The Plan is designed to allow eligible employees to share in the increase in the value of the shares of the Common Stock, $3.00 par value, of the Company (the "Common Stock") through the grant of stock appreciation rights ("SARs") with respect to Common Stock, and is intended to enable the Company and its subsidiaries to attract, retain and motivate employees who can make significant contributions to the success of the Company and its subsidiaries. ARTICLE I ADMINISTRATION Section 1.1 Committee. The Plan shall be administered by a committee (the --------- "Committee") appointed by the Board of Directors of the Company (the "Board") and consisting of two or more members of the Board who, at the time of their appointment to the Committee and at all times during their service as members of the Committee, are both "non-employee directors" within the meaning of Rule 16b-3 promulgated under the Securities Exchange Act of 1934, as amended (or any successor rule), and "outside directors" within the meaning of section 162(m) of the Internal Revenue Code of 1986, as amended (the "Code"). The Committee shall have discretionary and final authority to interpret and implement the provisions of the Plan. The Committee shall act by a majority of its members at the time in office and such action may be taken either by a vote at a meeting or in writing without a meeting. The Committee may adopt such rules and procedures for the administration of the Plan as are consistent with the terms hereof and shall keep adequate records of its proceedings and acts. Every interpretation, choice, determination or other exercise by the Committee of any power or discretion given either expressly or by implication to it shall be conclusive and binding upon all parties having or claiming to have an interest under the Plan or otherwise directly or indirectly affected by such action, without restriction, however, on the right of the Committee to reconsider and redetermine such action. The Company shall indemnify and hold harmless each member of the Committee against any claim, cost, expense (including reasonable attorneys' fees), judgment or liability (including any sum paid in settlement of a claim with the approval of the Board) arising out of any act or omission to act as a member of the Committee, except in the case of willful misconduct. 1 ARTICLE II ELIGIBILITY Section 2.1 Eligibility. Awards of SARs under the Plan may be made by the ----------- Committee to those employees of the Company or a parent or subsidiary corporation of the Company within the meaning of section 424(e) and (f) of the Code (the Company and each such parent or subsidiary corporation an "Employer" and together the "Employers") who, in the sole opinion of the Committee, have made or are in a position to make significant contributions to the success of the Employers. In determining the eligibility of any employee of an Employer for an award of SARs, and in determining the terms and conditions of such award, the Committee shall take into account the position and responsibilities of the employee being considered, the nature and value of the services being rendered by such employee, the current and potential contributions of such employee to the success of the Employers, and such other factors as the Committee in its discretion may deem relevant. Awards may be made under the Plan to the same individual on more than one occasion. "Awardee" means an employee who has been awarded an SAR pursuant to the Plan and who has executed such written agreement evidencing such award (an "SAR Agreement") as may be prescribed by the Committee in its discretion. ARTICLE III AWARDS Section 3.1 Nature of SARs. Awards made under the Plan shall be in the -------------- form of SARs. Each SAR (i) is a fictional deferred compensation unit used solely for the accounting purposes of this Plan to determine an amount of compensation to be paid in cash to or with respect to an Awardee pursuant to the Plan, (ii) shall be deemed to be equivalent in value to one share of Common Stock, and (iii) shall be evidenced by an SAR Agreement containing such terms and conditions not inconsistent with the provisions of the Plan as may be approved by the Committee in its discretion. SARs shall not entitle an Awardee to any dividend, voting rights or other rights of a holder of shares of Common Stock. 2 Section 3.2 Available SARs. Subject to any increasing or decreasing -------------- adjustment made pursuant to this Section, the total number of SARs that may be awarded pursuant to the Plan shall not exceed 90,000, and the total number of SARs that may be awarded to any one person during any calendar year shall not exceed 10,000. If any SAR awarded under the Plan expires or terminates prior to its exercise, such SAR shall again be available to be awarded under the Plan. If the Company effects a split of shares of Common Stock or pays a dividend in the form of shares of Common Stock, or if the outstanding shares of Common Stock are combined into a smaller number of shares, the total number of SARs that may be awarded pursuant to the Plan and the total number of SARs that may be awarded to any one person during any calendar year shall be increased or decreased to reflect proportionately the increase or decrease in the number of outstanding shares of Common Stock resulting from such split, dividend or combination. In the event of a reclassification of shares of Common Stock not covered by the foregoing, or in the event of a liquidation, separation or reorganization (including, without limitation, a merger, consolidation, spinoff or sale of assets involving the Company), the Committee shall make such adjustments, if any, to the total number of SARs that may be awarded pursuant to the Plan and the total number of SARs that may be awarded to any one person during any calendar year as the Committee in its discretion may deem appropriate. 3.3 Award of SARs. From time to time while the Plan is in effect, the ------------- Committee may award SARs to employees of an Employer who are deemed by the Committee in its discretion to satisfy the eligibility requirements of Section 2.1. Each award under the Plan shall specify the number of SARs being awarded, the award value of each SAR (which shall not be less than the fair market value of one share of Common Stock on the date of such award), the term during which such award may be exercised (which term shall not extend for any period beyond the earlier of (i) the expiration of three months following the date as of which the Awardee is no longer an employee of any Employer, or (ii) the expiration of five years following the date of such award), and such other terms and conditions not inconsistent with the provisions of the Plan as the Committee shall determine in its discretion. Subject to the limitations specified in the Plan, the Committee shall have the right and power to amend the terms and conditions of any outstanding award of SARs; provided, however, that no such amendment shall adversely affect the rights of an Awardee under any outstanding award of SARs without the consent of the affected Awardee. Section 3.4 Exercise of SARs. Each SAR shall become exercisable and shall ---------------- be exercised in accordance with the terms and conditions of the SAR Agreement awarding such SAR. Upon the exercise of an SAR, the Employer who is or was the last employer of the Awardee of such SAR shall pay to such Awardee an amount in cash equal to the excess of the fair market value of one share of Common Stock on the date of the exercise of such SAR over the award value of such SAR, and such SAR shall be canceled. 3 ARTICLE IV AMENDMENT AND TERMINATION Section 4.1 Amendment and Termination. The Board shall have the right and ------------------------- power at any time and from time to time to amend this Plan, in whole or in part, on behalf of all Employers, and at any time to terminate this Plan or the participation of any Employer hereunder; provided, however, that no such amendment or termination shall adversely affect the rights of an Awardee under any outstanding award of SARs without the consent of the affected Awardee. ARTICLE V MISCELLANEOUS PROVISIONS Section 5.1 Nonassignability. No SAR or right or interest of any Awardee ---------------- under this Plan or an SAR Agreement may be assigned, transferred or alienated, in whole or in part, except by will or by the laws of descent and distribution. An SAR awarded under the Plan to an Awardee shall be exercisable during the lifetime of such Awardee only by him or her. Section 5.2 Employment Noncontractual. The establishment of this Plan and ------------------------- the award of SARs hereunder to an Awardee shall not enlarge or otherwise affect the terms of such Awardee's employment with the Employer which employs such Awardee, and such Employer may terminate the employment of such Awardee as freely and with the same effect as if this Plan had not been established. Section 5.3 Tax Withholding. An Employer making a payment to or with --------------- respect to an Awardee in connection with the exercise of an SAR shall withhold from any such payment, and shall remit to the appropriate governmental authority, any income, employment or other tax such Employer is required by applicable law to so withhold and remit on behalf of the payee. 4 Section 5.4 Fair Market Value of Common Stock. For purposes of the Plan, --------------------------------- the "fair market value" of the Common Stock means the fair market value per share of Common Stock as determined by the Committee in good faith; provided, however, that so long as the Common Stock is listed on the New York Stock Exchange, the fair market value per share of Common Stock shall be the average of the reported high and low sales prices on the date in question (or if there was no reported sale on such date, on the last preceding date on which any reported sale occurred) on the New York Stock Exchange, or if the Common Stock is listed or admitted to trading on a securities exchange registered under the Securities Exchange Act of 1934 other than the New York Stock Exchange, the fair market value per share of Common Stock shall be the average of the reported high and low sales prices on the date in question (or if there was no reported sale on such date, on the last preceding date on which any reported sale occurred) on the principal securities exchange on which the Common Stock is listed or admitted to trading, or if the Common Stock is not listed or admitted to trading on any such exchange but is listed as a national market security on the National Association of Securities Dealers, Inc. Automated Quotations System ("NASDAQ") or any similar system then in use, the fair market value per share of Common Stock shall be the average of the reported high and low sales prices on the date in question (or if there was no reported sale on such date, on the last preceding date on which any reported sale occurred) on such system, or if the Common Stock is not listed or admitted to trading on any such exchange and is not listed as a national market security on NASDAQ but is quoted on NASDAQ or any similar system then in use, the fair market value per share of Common Stock shall be the average of the closing high bid and low asked quotations on such system for such share on the date in question. Section 5.5 Outstanding SAR Adjustments. If the Company effects a --------------------------- split of shares of Common Stock or pays a dividend in the form of shares of Common Stock, or if the outstanding shares of Common Stock are combined into a smaller number of shares, the number of unexercised SARs subject to an outstanding award made under the Plan shall be increased or decreased proportionately and the award value of such SARs shall be decreased or increased proportionately so that the aggregate award value of such SARs shall remain the same as immediately prior to such split, dividend or combination. In the event of a reclassification of shares of Common Stock not covered by the foregoing, or in the event of a liquidation, separation or reorganization (including, without limitation, a merger, consolidation, spinoff or sale of assets involving the Company), the Committee shall make such adjustments, if any, to the number and award value of unexercised SARs subject to an outstanding award made under the Plan as the Committee in its discretion may deem appropriate. IN WITNESS WHEREOF, this Plan has been executed to be effective as of August 19, 1997. THE WISER OIL COMPANY By /s/ Andrew J. Shoup, Jr. -------------------------------------------- Title: President and Chief Executive Officer 5 EX-10.14A 3 AMENDED 1997 SHARE APPRECIATON Exhibit 10.14a AMENDMENT TO THE WISER OIL COMPANY 1997 SHARE APPRECIATION RIGHTS PLAN Pursuant to the provisions of Section 4.1 of The Wiser Oil Company 1997 Share Appreciation Rights Plan (the "Plan"), the Plan is hereby amended, effective as of May 18, 1999, to restate the first sentence of Section 3.2 of the Plan in its entirety to read as follows: "Subject to any increasing or decreasing adjustment made pursuant to this Section, the total number of SARs that may be awarded pursuant to the Plan shall not exceed 90,000, and the total number of SARs that may be awarded to any one person during any calender year shall not exceed 12,750." THE WISER OIL COMPANY By: /s/ Andrew J. Shoup, Jr. --------------------------------- Name: Andrew J. Shoup, Jr. Title: President and Chief Executive Officer Dated as of May 18, 1999 1 EX-21 4 SUBSIDIARIES EXHIBIT 21 SUBSIDIARIES OF THE WISER OIL COMPANY T.W.O.C., Inc. The Wiser Oil Company of Canada Wiser Delaware LLC EX-23.1 5 CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS Exhibit 23.1 CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS As independent public accountants, we hereby consent to the incorporation by reference in the Registration Statements on Form S-8 relating to the stock incentive plans of The Wiser Oil Company (Nos. 33-44171, 33-62441, 33-44172, 333-22525 and 333-15083) of our report dated February 24, 2000 appearing on page F-2 of this Annual Report on Form 10-K. /s/ ARTHUR ANDERSEN LLP Arthur Andersen LLP Dallas, Texas, February 24, 2000 EX-23.2 6 CONSENT OF DEGOLYER & MACNAUGHTON Exhibit 23.2 CONSENT OF PETROLEUM ENGINEERS April 11, 2000 The Wiser Oil Company 8115 Preston Road, Suite 400 Dallas, Texas 75225 Gentlemen: We hereby consent to the incorporation by reference in the Registration Statements on Form S-8 (Nos. 33-44171, 33-62441, 33-44172, 333-22525, and 333-15083) relating to the stock incentive plans of The Wiser Oil Company (the Company) of our reserves estimates included in the Annual Report on Form 10-K (the Annual Report) of the Company for the year ended December 31, 1999, and to the references to our firm included in the Annual Report. Our estimates of the oil, condensate, natural gas liquids (shown collectively as "Oil and NGL"), and natural gas reserves of certain properties owned by the Company are contained in our reports entitled "Appraisal Report as of December 31, 1999 on Certain Properties owned by the Wiser Oil Company-Proved Reserves". Reserves estimates from our reports are included in the sections "Principal Oil and Gas Properties," "Oil and Gas Reserves," and "Supplemental Financial Information for the years ending December 31, 1999, 1998 and 1997 (unaudited)-Oil and Gas Reserves." Also included in the third section mentioned above are reserves estimates from our "Appraisal Report as of December 31, 1999 on Certain Properties owned by the Wiser Oil Company-Proved Reserves." In the sections "Summary Reserve and Operating Data" and "Oil and Gas Reserves," estimates of reserves, revenue, and discounted present worth set forth in our above mentioned reports have been combined with estimates of reserves, revenue, and discounted present worth prepared by another petroleum consultant. We are necessarily unable to verify the accuracy of the reserves, revenue, and present worth values contained in the Annual Report when our estimates have been combined with those of another firm. Very truly yours, /S/ DEGOLYER AND MACNAUGHTON DeGOLYER and MacNAUGHTON EX-23.3 7 CONSENT OF GILBERT LAUSTEN JUNG ASSOCIATES EXHIBIT 23.3 LETTER OF CONSENT CONSENT OF PETROLEUM ENGINEERS As independent petroleum engineers, we hereby consent to the incorporation by reference in the Registration Statements on Form S-8 relating to the stock incentive plans of The Wiser Oil Company (the "Company"), (Nos. 33-44171, 33- 62441, 33-44172, 333-22525 and 333-15083), of certain data from our report entitled "The Wiser Oil Company Canada Ltd. Reserve Appraisal and Economic Evaluation effective January 1, 2000" with respect to the oil and gas reserves of the Company, the future net revenues therefrom and present values attributable to these reserves included in this Annual Report on Form 10-K, and to all references to our firm included in this Annual Report. Yours very truly, GILBERT LAUSTSEN JUNG ASSOCIATES LTD. /s/ Wayne W. Chow, P. Eng. Vice-President April 11, 2000 Calgary, Canada EX-27 8 FINANCIAL DATA SCHEDULE
5 THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM ANNUAL REPORT ON FORM 10-K AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS. 1,000 3-MOS YEAR DEC-31-1999 DEC-31-1999 OCT-01-1999 JAN-01-1999 DEC-31-1999 DEC-31-1999 22,439 22,439 0 0 9,565 9,565 0 0 335 335 32,718 32,718 278,541 278,541 118,568 118,568 119,726 196,726 14,843 14,843 124,526 124,526 0 0 0 0 27,385 27,385 29,756 29,756 196,726 196,726 12,934 47,602 14,235 52,794 6,184 21,447 18,287 68,509 0 0 0 0 3,148 13,310 (4,052) (15,715) 0 (859) (4,052) (14,856) 0 0 0 0 0 0 (4,052) (14,856) (0.45) (1.66) (0.45) (1.66)
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