-----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, K2HeAPuK59vJVyhytlEq0WS6QPV00iThJv4yVSi8NZnPKvEo5uMEKmsQmN09Oocz mTp9zRDL88tX24x/6gsrmA== 0000899243-97-000471.txt : 19970328 0000899243-97-000471.hdr.sgml : 19970328 ACCESSION NUMBER: 0000899243-97-000471 CONFORMED SUBMISSION TYPE: 10-K405 PUBLIC DOCUMENT COUNT: 8 CONFORMED PERIOD OF REPORT: 19961231 FILED AS OF DATE: 19970327 SROS: NASD 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: 1934 Act SEC FILE NUMBER: 001-12640 FILM NUMBER: 97564585 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-K - ------------------------------------------------------------------------------- - ------------------------------------------------------------------------------- SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 ---------------- FORM 10-K ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE FISCAL YEAR ENDED DECEMBER 31, 1996 COMMISSION FILE NUMBER 0-5426 ---------------- THE WISER OIL COMPANY A DELAWARE CORPORATION ---------------- I.R.S. EMPLOYER IDENTIFICATION NO. 55-0522128 8115 PRESTON ROAD, SUITE 400 DALLAS, TEXAS 75225 TELEPHONE: (214) 265-0080 SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT TITLE OF EACH CLASS COMMON STOCK--PAR VALUE, $3.00 PER SHARE PREFERRED STOCK PURCHASE RIGHTS NAME OF EXCHANGE ON WHICH REGISTERED NEW YORK STOCK EXCHANGE Indicate by check mark whether registrant has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months, and has been subject to such filing requirements for the past 90 days. [X] Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation 5-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [X] As of February 28, 1997, registrant had outstanding 8,948,840 shares of common stock, $3.00 par value ("Common Stock"), which is registrant's only class of common stock. The aggregate market value of registrant's Common Stock held by non- affiliates based on the closing price on February 28, 1997 was approximately $168 million. DOCUMENTS INCORPORATED BY REFERENCE (SPECIFIC INCORPORATIONS ARE IDENTIFIED UNDER THE APPLICABLE ITEM HEREIN.) Portions of the registrant's proxy statement furnished to stockholders in connection with the May 19, 1997 Annual Meeting of Stockholders (the "Proxy Statement") are incorporated by reference in Part III of this Report. The Proxy Statement will be filed with the Commission within 120 days of the close of the registrant's fiscal year. - ------------------------------------------------------------------------------- - ------------------------------------------------------------------------------- TABLE OF CONTENTS DESCRIPTION
ITEM PAGE - ---- ---- PART I 1. BUSINESS............................................................. 3 2. PROPERTIES........................................................... 26 3. LEGAL PROCEEDINGS.................................................... 27 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.................. 27 PART II 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED STOCKHOLDER MATTERS.............................................................. 27 6. SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA................... 28 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS................................................ 31 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.......................... 38 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURES................................................ 38 PART III 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT................... 38 11. EXECUTIVE COMPENSATION............................................... 38 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT....... 38 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS....................... 38 PART IV 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K...... 39
2 THE WISER OIL COMPANY PART I ITEM 1. BUSINESS GENERAL Founded in 1905, The Wiser Oil Company is one of the oldest public independent oil and gas companies in the United States. In recent years, the Company has successfully implemented a new business strategy adopted in 1991, emphasizing growth in reserves and production volumes through acquisitions and subsequent development and exploitation of acquired properties. Since its change in strategic direction, the Company's total proved reserves have grown to 50.5 MMBOE (approximately 63% of which were oil and NGLs) at December 31, 1996 from 24.3 MMBOE at December 31, 1991, and its annual net production has grown to 4.7 MMBOE in 1996 from 2.3 MMBOE in 1991. The Company's primary operations, representing approximately 55% of its proved reserves at December 31, 1996, are located in the Permian Basin in West Texas and Southeast New Mexico. Wiser has additional operations in Alberta, Canada, the Appalachian Basin in Kentucky, Tennessee and West Virginia, and the San Juan Basin in New Mexico. Prior to 1991 the Company focused primarily on the acquisition of non-operated interests in oil and gas properties. In 1991 the Company moved its headquarters from Sistersville, West Virginia to Dallas, Texas and began to assemble a team of experienced management with substantial acquisition, exploitation and development expertise. After reviewing the Company's existing property portfolio and refining the new business strategy, the management team began disposing of the Company's non-strategic assets and acquiring and operating properties in new core areas with the potential for increased reserves and production volumes. Pursuant to this strategy, the Company acquired and developed properties in the Permian Basin and Canada, and successfully added reserves and production through workovers, recompletions, waterfloods and CO\\2\\ gas injections, as well as the drilling of exploratory, development and infill wells. A substantial portion of the Company's growth in reserves and production volumes since 1991 has been the result of (i) two successful enhanced oil recovery projects on properties acquired from 1992 to 1995 in the Permian Basin and (ii) the Company's 1994 acquisition and subsequent exploration on and exploitation of properties in Alberta, Canada. From June 1993 through December 1996, the Company completed 113 producing wells on its Maljamar waterflood project in Southeast New Mexico. As a result the Company's average daily net oil production from the three units in this project increased to 2,800 Bbls in December 1996 from 580 Bbls in January 1993 (on a pro forma combined basis, assuming the Company had acquired all three units at January 1, 1993). At its Wellman Unit in West Texas, the Company used CO\\2\\ gas injection to increase average daily net production to 930 Bbls of oil, 440 Bbls of NGLs and 540 Mcf of natural gas in December 1996 from 650 Bbls of oil and no NGLs or natural gas in December 1993. In June 1994 the Company acquired oil and gas properties located primarily in Alberta, Canada for $52.0 million. From the date of their acquisition through December 1996, the Company completed 22 net wells on these properties. As a result, the Company's average daily net Canadian production increased to 3,200 BOE in December 1996 from 1,860 BOE in June 1994. The Company's principal executive offices are located at 8115 Preston Road, Suite 400, Dallas, Texas 75225, and its telephone number is (214) 265-0080. 3 PRINCIPAL OIL AND GAS PROPERTIES The following table summarizes certain information with respect to each of the Company's principal areas of operation at December 31, 1996.
PROVED RESERVES ---------------------------------- 1996 TOTAL TOTAL PERCENT AVERAGE GROSS OIL NATURAL PROVED OF TOTAL NET OIL AND AND NGLS GAS RESERVES PROVED PRODUCTION GAS WELLS (MBBLS) (MMCF) (MBOE) RESERVES (BOE/DAY) --------- -------- ------- -------- -------- ---------- Permian Basin Maljamar.............. 223 14,706 6,248 15,748 31% 2,074 Wellman............... 14 7,067 2,494 7,482 15% 1,594 Dimmitt/Slash Ranch... 59 2,548 12,954 4,707 9% 848 ----- ------ ------- ------ --- ------ Total Permian Basin.............. 296 24,321 21,696 27,937 55% 4,516 Appalachian Basin....... 443 989 31,633 6,260 12% 1,343 San Juan Basin.......... 2,200 48 20,831 3,520 7% 1,104 Other................... 542 2,722 15,386 5,287 11% 2,661 ----- ------ ------- ------ --- ------ Total United States............. 3,481 28,080 89,546 43,004 85% 9,624 Canada.................. 287 3,532 23,831 7,504 15% 3,318 ----- ------ ------- ------ --- ------ Total Company....... 3,768 31,612 113,377 50,508 100% 12,942 ===== ====== ======= ====== === ======
Permian Basin Maljamar. The Company's Maljamar properties are situated in Southeast New Mexico. At December 31, 1996, the Maljamar properties contained 15.7 MMBOE of proved reserves, which represented 31% of the Company's total proved reserves and 30% of the Company's Present Value of total proved reserves. The Maljamar properties consist of three oil producing units acquired by the Company in separate transactions between 1992 and 1995: the Maljamar Grayburg and Caprock Maljamar Units, both of which are in Lea County, New Mexico, and the Skelly Unit in Eddy County, New Mexico. The Maljamar Grayburg Unit produces from the Grayburg and San Andres formations at depths ranging from 3,800 to 4,500 feet, and the Caprock Maljamar Unit produces from the same formations at depths ranging from 4,000 to 5,000 feet. The Skelly Unit is located approximately five miles west of the two Lea County units and produces from the Seven Rivers, Grayburg and San Andres formations at depths ranging from 2,100 to 4,000 feet. The Company has a 100% working interest in each of these units, which have been combined into a single large scale waterflood project encompassing approximately 11,800 gross leasehold acres. Exploitation efforts at the project include recompletions of existing wells and the drilling of infill development wells on 20-acre spacing to create a five-spot water injection pattern of 40 acres. From June 1, 1993 through December 31, 1996, the Company made capital expenditures of $50.1 million and completed 113 producing wells at the project. At December 31, 1996, the project included 223 producing wells and 102 water injection wells, all of which were operated by the Company. During 1996, Wiser placed a total of 68 wells on production, and had 33 additional wells in various stages of drilling or completion at year end. At December 31, 1996, a total of 28 wells remain to be drilled at the project, all of which are expected to be drilled in the first half of 1997 as part of a total capital expenditure thereon of $17.4 million. The Company's average daily net production from the Maljamar properties increased to 2,800 Bbls of oil and 1,760 Mcf of natural gas in December 1996 from 580 Bbls of oil and 220 Mcf of natural gas in January 1993 (on a pro forma combined basis, assuming the Company had acquired all three units at January 1, 1993). The Company's net production from the Maljamar properties averaged 1,900 Bbls of oil and 1,044 Mcf of natural gas per day in 1996. The Company's cumulative net production from the Maljamar properties since acquired by the Company has been 1,360 MBbls of oil and 670 MMcf of natural gas through December 31, 1996. 4 Wellman Unit. In 1993 the Company acquired a 62% working interest in and became operator of the Wellman Unit in Terry County, Texas, located in the northwestern edge of the Horseshoe Atoll. At December 31, 1996, the Company's Wellman property contained 7.5 MMBOE of proved reserves, which represented 15% of the Company's total proved reserves and 14% of the Company's Present Value of total proved reserves. The Company owns approximately 2,300 gross (1,400 net) leasehold acres in the Wellman Unit. The Wellman Unit produces oil from the Wolfcamp Reef formation at depths ranging from 9,100 to 10,000 feet through the injection of water and CO\\2\\ into the reservoir. Water injection at the unit began in 1979, and CO\\2\\ injection began in 1983. The unit also includes a gas processing plant, which processes wellhead gas produced from the unit. Wiser's interest in this plant is proportionate to its working interest in the Wellman Unit. Processing at the plant involves subjecting the wellhead gas to high pressure and low temperature treatments that cause the gas to separate into various products, including NGLs, residual natural gas and CO\\2\\. The NGLs and residual natural gas are sold to pipeline companies, and the CO\\2\\ is reinjected into the unit's reservoir. At December 31, 1996, the unit included 14 productive wells, three water injection wells and three CO\\2\\ injection wells, all of which were operated by the Company. The Company's net production from the Wellman Unit averaged 1,051 Bbls of oil, 481 Bbls of NGLs and 374 Mcf of natural gas per day in 1996. The Company's average daily net production from the unit was 930 Bbls of oil, 440 Bbls of NGLs and 540 Mcf of natural gas in December 1996, which was 8% lower on an equivalent unit basis than the average daily net production from the unit in 1996. This reduction was due primarily to weather-related delays in drilling operations and plant processing and shortages of drilling rigs. The Company's cumulative net production from the unit since acquired by the Company has been 1,181 MBbls of oil, 278 MBbls of NGLs and 137 MMcf of natural gas through December 31, 1996. In 1994 the Company began reconditioning the gas processing plant at the Wellman Unit to enhance the extraction of NGLs and residual natural gas from the wellhead gas. The Company completed the reconditioning project in June 1995 at a total cost of approximately $6.0 million. Following completion of this project, average daily net production from the unit increased to 1,180 Bbls of oil and 527 Bbls of NGLs during the six months ended December 31, 1995 from 982 Bbls of oil and no NGLs for the six months ended June 30, 1995. For the year ended December 31, 1996, the gas plant processed an average of 31 MMcf of gross natural gas and CO\\2\\ per day and recovered an average of 882 Bbls of NGLs and 685 Mcf of residual natural gas per day. The plant currently operates at 95% of its maximum capacity of 35 MMcf of gas per day. Dimmitt/Slash Ranch Fields. The Company's Dimmitt/Slash Ranch properties are situated in Loving County, Texas, 80 miles west of Midland, Texas. At December 31, 1996, the Dimmitt/Slash Ranch properties contained 4.7 MMBOE of proved reserves, which represented 9% of the Company's total proved reserves and 11% of the Company's Present Value of total proved reserves. The Company owns approximately 5,400 gross (4,100 net) leasehold acres in the Dimmitt Field, and has working interests in this acreage ranging from 50% to 100%. The Company acquired its initial interest in and became operator of the field in 1993. The Dimmitt Field produces oil and gas from the Cherry Canyon and Bell Canyon formations at depths ranging from 4,700 to 6,700 feet. At December 31, 1996, the field included 56 productive wells. The Company completed three wells in the Cherry Canyon formation and performed recompletions on seven producing wells in the Bell Canyon formation in 1996. The Company plans to drill three additional development wells in the Cherry Canyon formation and to recomplete 13 additional Bell Canyon wells during the next two years for an estimated total capital expenditure of approximately $2.0 million. The Company's net production from the Dimmitt Field averaged 374 Bbls of oil and 1,172 Mcf of natural gas per day in 1996. The Slash Ranch Field is a natural gas field that underlies the Dimmitt Field. The Company owns approximately 2,600 gross (1,800 net) leasehold acres in the Slash Ranch Field. The Slash Ranch Field produces from the Atoka, Fusselman and Ellenburger formations at depths ranging from 15,000 to 20,000 feet. At December 31, 1996, the field included three producing wells, all of which were operated by the Company. The 5 Company's working interests in these wells range from 34% to 100%. The Company's net production from the Slash Ranch Field averaged 1,672 Mcf of natural gas per day in 1996. The Company has identified several exploratory prospects in this field and intends to further define these prospects with 3-D seismic in 1997. See "--Exploration Activities--United States--West Texas." The Company's net production from the Dimmitt/Slash Ranch properties averaged 374 Bbls of oil and 2,844 Mcf of natural gas per day in 1996. The Company's cumulative net production from the properties since acquired by the Company has been 300 MBbls of oil and 3.4 Bcf of natural gas through December 31, 1996. Appalachian Basin The Company's Appalachian Basin properties are situated in Kentucky, Tennessee and West Virginia. At December 31, 1996, these properties contained 6.3 MMBOE of proved reserves, which represented 12% of the Company's total proved reserves and 12% of the Company's Present Value of total proved reserves. The Appalachian Basin reserves are long-lived reserves (generally, over 40 years) characterized by gradual decline rates. The Company has operated in Kentucky and Tennessee since 1917 and owns approximately 123,000 gross (108,000 net) leasehold acres in 22 shallow natural gas fields in southeastern Kentucky and northeastern Tennessee. The Company's working interests in this acreage range from 33% to 100%. The Company has a 100% working interest in approximately 90% of the total acreage. The primary producing formations in these fields are the Maxon, Big Lime and Corniferous at a maximum depth of less than 3,000 feet. At December 31, 1996, the Company owned 368 gross (309 net) productive wells in these fields, of which approximately 98% were operated by the Company. Although daily production from individual wells in the fields is low (on average, 30 Mcf per day), the production generally receives a higher sales price than the Company's other natural gas production because of the proximity of the fields to the northeastern United States gas markets. The Company completed four development wells in Kentucky and Tennessee in 1996, three development wells in early 1997 and plans to drill an additional four development wells later this year. The Company expects to spend approximately $500,000 on development drilling activities in Kentucky and Tennessee in 1997. The Company's net production from its Kentucky and Tennessee properties averaged 5,346 Mcf of natural gas per day in 1996. The Company owns approximately 20,000 gross (14,000 net) leasehold acres in the Blue Creek Field in Clay and Kanawha Counties, West Virginia. The Company has an average 70% working interest in this acreage, which it acquired in February 1995. The Blue Creek Field produces from the Rosedale, Injun, Keener and Weir formations, ranging from depths of 1,200 to 2,800 feet. At December 31, 1996, the Company owned 75 gross (48 net) productive gas wells in this field, all of which were operated by another company. During 1996, the Company participated in the drilling of 12 gross (nine net) development wells in the Blue Creek Field. The Company has identified 35 exploratory drilling locations in the field and plans to drill 20 of these locations in 1997 for an estimated total capital expenditure of $2.5 million. The Company's net production from its West Virginia properties averaged 913 Mcf of natural gas, 107 Bbls of oil and 193 Bbls of NGLs per day in 1996. The Company owns and operates an extensive natural gas gathering and transportation system located in its producing areas of Kentucky and Tennessee. The system consists of approximately 340 miles of gas gathering pipelines, 16 gas compressor stations, two gas processing plants and two gas storage reservoirs. The pipelines have a throughput capacity of approximately 20 MMcf of natural gas per day. During the year ended December 31, 1996, the pipelines gathered an average of 10.8 MMcf of natural gas per day. The two processing plants have a total capacity of 16 MMcf of natural gas per day. During the year ended December 31, 1996, the plants processed an average of 10.8 MMcf of natural gas per day and recovered an average of 193 Bbls of NGLs per day. See "--Marketing of Production." The Company's net production from its Appalachian Basin properties averaged 6,259 Mcf of natural gas, 107 Bbls of oil and 193 Bbls of NGLs per day in 1996. 6 San Juan Basin The Company's San Juan Basin properties are located in Rio Arriba County in northwestern New Mexico. At December 31, 1996, the San Juan Basin properties contained 3.5 MMBOE of proved reserves, which represented 7% of the Company's total proved reserves and 7% of the Company's Present Value of total proved reserves. The Company owns approximately 11,100 gross (5,300 net) leasehold acres in the San Juan Basin. The Company's average 48% working interest in the acreage was contributed in connection with a unitization of the wells in the San Juan Basin fields in the 1950's, resulting in the ownership by the Company of small non-operated working interests in the wells. At December 31, 1996, the Company owned working interests in 2,200 producing gas wells in the San Juan Basin, which working interests ranged from 0.21% to 4.2% and averaged approximately 1.8%. The Company's San Juan Basin properties produce from multiple formations ranging from depths of 3,500 feet to 8,000 feet. The Company's net production from these properties averaged 6,539 Mcf of natural gas and 14 Bbls of oil per day in 1996. During the year ended December 31, 1996, approximately 60% of the Company's net production from these properties was from the Fruitland Coal seams. Such production generates nonconventional fuels income tax credits for Wiser under Section 29 of the Internal Revenue Code of 1986, as amended. See "Management's Discussion and Analysis of Financial Condition and Results of Operations--Results of Operations." In 1996 production from the San Juan Basin properties was diminished as a result of a five-month curtailment due to a pipeline rupture. The Company expects that future development of the properties will depend on natural gas prices, and that its share of the costs of any such future development activities will not be significant. Other U.S. Properties The Company's other United States properties include properties located in the Anadarko Basin in Texas and Oklahoma, the Gulf Coast onshore region and Michigan. The Company intends to develop its Anadarko Basin and Gulf Coast properties as new core operating areas if certain exploration projects it is currently pursuing prove successful. See "--Exploration Activities--United States." The Company has entered into a contract to sell its Michigan properties, and expects the sale to occur in April 1997. The Company's net production from its Michigan properties averaged 386 Bbls of oil and 555 Mcf of natural gas per day in 1996. Canada In June 1994, Wiser established an important new core area with the completion of a $52.0 million acquisition of Canadian oil and gas properties from Eagle Resources, Ltd. The purchase included 7.2 MMBOE of proved reserves and 2.8 MMBOE of probable reserves, approximately 127,000 net undeveloped acres, seven exploration prospects and an existing staff of 23 persons. At December 31, 1996, the Company's Canadian properties contained 7.5 MMBOE of proved reserves, which represented 15% of the Company's total proved reserves and 15% of the Present Value of the Company's total proved reserves. The following table summarizes certain information with respect to each of the Company's principal Canadian areas of operation at December 31, 1996:
PROVED RESERVES --------------------------------- PERCENT OF TOTAL TOTAL PERCENT OF 1996 AVERAGE TOTAL GROSS PROVED CANADIAN TOTAL COMPANY NET OIL AND RESERVES PROVED PROVED PRODUCTION GAS WELLS (MBOE) RESERVES RESERVES (BOE/DAY) ----------- -------- ---------- ------------- ------------ Evi................. 15 1,224 16% 2.4% 825 Provost............. 46 616 8% 1.2% 742 Grande Prairie...... 16 884 12% 1.8% 239 Leahurst............ 16 355 5% 0.7% 356 Pine Creek.......... 5 420 6% 0.8% 239 Other............... 189 4,005 53% 8.0% 917 --- ----- --- ---- ----- Total Canada...... 287 7,504 100% 14.9% 3,318 === ===== === ==== =====
7 Evi. The Company's Evi Field is located approximately 400 miles north of Calgary. At December 31, 1996, the Evi Field contained 1,224 MBOE of proved reserves, which represented 16% of the Company's total Canadian proved reserves and 35% of the Present Value of the Company's total Canadian proved reserves. The Company owns approximately 5,440 gross (1,870 net) leasehold acres in the Evi Field, and has an average 34% working interest in this acreage. The Evi Field produces oil from the Granite Wash formation at depths ranging from 4,900 to 5,000 feet. The Company's net production from the Evi Field averaged 825 Bbls of oil per day in 1996. At December 31, 1996, the Company owned 15 gross (3.2 net) productive wells and two gross (0.4 net) water disposal wells in the field, of which 12 productive wells and both water disposal wells were operated by Wiser. Provost. The Company's Provost properties are located approximately 210 miles northeast of Calgary. At December 31, 1996, the Provost properties contained 616 MBOE of proved reserves, which represented 8% of the Company's total Canadian proved reserves and 11% of the Present Value of the Company's total Canadian proved reserves. The Company owns approximately 9,280 gross (6,300 net) leasehold acres in the Provost properties, and has an average 68% working interest in this acreage. The Provost properties produce mainly from the Dina formation at depths of 3,070 to 3,170 feet. The Provost Dina 'X' Pool is the Company's main producing pool in these properties. Water injection in this pool began in 1990. The Company drilled 12 infill wells in the Dina 'X' Pool in 1996. This increased the Company's average daily net production from the pool to 630 Bbls of oil in December 1996 from 150 Bbls of oil in January 1996. The Company plans to drill two additional infill wells in the pool in 1997. The Company's net production from the Provost properties averaged 679 Bbls of oil and 380 Mcf of natural gas per day in 1996. At December 31, 1996, the Company owned 46 gross (35.8 net) productive wells and two gross (two net) water injection wells on the properties, of which 29 gross productive wells and both water injection wells were operated by the Company. The Company has a 100% working interest in 22 of the productive wells and a 92% working interest in one of the others. Grande Prairie. The Company's Grande Prairie properties are located approximately 380 miles northwest of Calgary. At December 31, 1996, the Grande Prairie properties contained 884 MBOE of proved reserves, which represented 12% of the Company's total Canadian proved reserves and 11% of the Present Value of the Company's total Canadian proved reserves. The Company owns approximately 8,320 gross (2,260 net) leasehold acres in the Grande Prairie properties, and has an average 27% working interest in this acreage. The Grande Prairie properties produce from the Halfway formation at depths of 6,200 to 6,300 feet. At December 31, 1996, the Company owned 16 gross (3.9 net) productive wells and one gross (0.23 net) gas injection well at Grande Prairie, all of which were operated by Wiser. All but one well has been unitized in the Grande Prairie Halfway 'A' Unit, in which the Company has a 22.9% working interest. Gas re-injection in the unit began in 1989 to enhance oil recovery. The Company's net production from the Grande Prairie properties averaged 158 Bbls of oil and 487 Mcf of natural gas per day in 1996. Leahurst. The Company's Leahurst properties are located approximately 180 miles northeast of Calgary. At December 31, 1996, the Leahurst properties contained 355 MBOE of proved reserves, which represented 5% of the Company's total Canadian proved reserves and 8% of the Present Value of the Company's total Canadian proved reserves. The Company owns approximately 880 gross (560 net) leasehold acres in the Leahurst properties, and has an average 63% working interest in this acreage. The Leahurst properties produce from the Glauconite formation at depths of 4,150 to 4,250 feet. At December 31, 1996, the Company owned 16 gross (2.6 net) productive wells and two gross (0.63 net) water injection wells on the Leahurst properties. All of the wells in the properties have 8 been unitized in the Leahurst Glauconite 'B' Unit, in which the Company has a 16% working interest. The unit is operated by a third party. Water injection in the unit began in 1994 to enhance oil recovery. The Company is currently participating in a six-well infill drilling program at the unit. Five of these wells have proved undeveloped reserves assigned to them. The Company's net production from the Leahurst properties averaged 334 Bbls of oil and 130 Mcf of natural gas per day in 1996. Pine Creek. The Company's Pine Creek Field is located approximately 240 miles northwest of Calgary. At December 31, 1996, the Pine Creek Field contained 420 MBOE of proved reserves, which represented 6% of the Company's total Canadian proved reserves and 4% of the Present Value of the Company's total Canadian proved reserves. The Company owns approximately 8,000 gross (2,100 net) leasehold acres in the Pine Creek Field, and has a 26% working interest in this acreage. The Pine Creek Field produces gas from the Bluesky and Gething formations at depths of 8,000 to 8,200 feet. At December 31, 1996, the Company owned five gross (1.3 net) productive wells in the Pine Creek Field, all of which were operated by a third party. The Company's net production from the Pine Creek Field averaged 967 Mcf of natural gas and 78 Bbls of NGLs per day in 1996. Other Canadian Properties. The Company owns interests in approximately 30 other Canadian properties, primarily located in its principal areas of operation. For the year ended December 31, 1996, these properties individually represented less than 5%, and in the aggregate represented approximately 28%, of the Company's average daily net Canadian production. EXPLORATION ACTIVITIES United States. Wiser's domestic exploration program seeks to maintain a balanced portfolio of drilling opportunities that range from lower risk field extension wells to higher risk, high reserve potential prospects. The Company focuses primarily on exploration opportunities that can benefit from advanced technologies, including 3-D seismic, designed to reduce risks and increase success rates. Prospects are developed in-house and through strategic alliances with exploration companies that have expertise in specific target areas. In addition, the Company evaluates some externally generated prospects and participates in farm-ins to enhance its portfolio. In 1996, Wiser participated in three gross (two net) domestic exploration wells, compared with 19 gross (six net) wells in 1995, spending $0.9 million in 1996 and $2.0 million in 1995 on domestic exploration. The Company has budgeted $7.9 million for its 1997 domestic exploration program. The Company is currently focusing its domestic exploration activities in the following geographical areas: West Texas. The Company has identified deep exploratory prospects in the Slash Ranch Field in Loving County where it is currently producing at shallower depths. The Company intends to define these prospects further with 3-D seismic. In Pecos County, Wiser has a 23.5% working interest in both the Indian Mesa and Panther Bluff prospects. The Company has completed 3-D seismic on the Indian Mesa prospect and intends to drill an exploratory well on this prospect in the second quarter of 1997. The Company will be carried at no cost to casing point in the well and will have a 23.5% working interest after casing point. The Company has identified unproven drilling potential in the Panther Bluff prospect to be defined further with 3-D seismic data. The Company is in the process of obtaining necessary permits to commence exploration of this prospect. Gulf Coast. The Company plans to develop exploration projects in the Gulf Coast onshore region. The Company intends to seek a mix of moderate risk, moderate cost prospects and some higher cost, higher potential prospects. Wiser is currently involved in discussions with other companies regarding participation in 3-D seismic projects for multiple prospects, and is investigating self-generation of prospects in certain other locations. Wiser owns approximately 2,300 gross (540 net) leasehold acres in the South Lakeside prospect in Cameron Parish, Louisiana, and has acquired extensive 2-D seismic over this area. The Company considers this prospect to be a very high risk project with potential for substantial reserves. Spudding of a well on the prospect occurred in March 1997. The well is being drilled under a turnkey contract. The Company will pay 12.5% of the drilling costs of the well to casing point and will have a 23.4% working interest after casing point. 9 Anadarko Basin. The Company owns approximately 6,500 gross (1,300 net) leasehold acres and has a 20% working interest in the Mustang prospect, where it participated in a 35-mile 3-D seismic program targeting the Upper Morrow and Hunton formations. The Company has commenced drilling the Mustang prospect. Wiser is currently evaluating two other exploratory projects in Oklahoma. The Company is investigating the possibility of conducting 3-D seismic on these two projects to delineate exploratory prospects. Canada. Wiser focuses its Canadian exploration activities in specific regions within the Western Canadian Sedimentary Basin in close proximity to known producing horizons where the potential for significant reserves exists. The Company's technical personnel have considerable experience in this focus area. From the date of the Company's acquisition of its Canadian properties through December 31, 1996, the Company's Canadian exploration activities have resulted in the successful completion of five net wells (out of 14 net wells drilled). The Company has budgeted $4.3 million for its 1997 Canadian exploration program. The Company is currently focusing its Canadian exploration activities in the following geographical areas: Northeast British Columbia. The Company owns approximately 2,760 gross (1,380 net) leasehold acres in the Beatton River/Elm area, and has an average 50% working interest in this acreage. This project targets the Gething formation at 4,000 feet and the Triassic Halfway formation located directly beneath the Gething formation. In the fourth quarter of 1996, the Company drilled an exploratory well on this acreage. This well has been cased and production tested and is currently undergoing pressure build-up analysis to determine the optimum rate of recovery. Based on an analysis of the final flow rates, the Company believes this well has significant reserve potential. If successful, this well will qualify under a provincial program encouraging exploration activity which would exempt the Company from paying royalties on production to the provincial government for a period of 36 months. Another exploratory well and a development well are planned for 1997 to further delineate this field. The Company is currently negotiating an off-setting opportunity for this prospect. Northern Alberta. The Company's Gage project is presently undergoing land assembly as an oil prospect targeting the deeper Triassic formation at approximately 4,000 feet. A number of wells drilled by others in this area have previously tested oil and gas, but have never produced because of a lack of pipelines in the area. The Company is engaged in a shallower competitive venture in this area to determine whether there are sufficient natural gas reserves to justify the construction of production facilities. The Company owns approximately 5,440 gross (3,560 net) leasehold acres in the Gage project and has working interests in the gas rights ranging from 50% to 100%. The Company has purchased and intends to continue to purchase the oil rights to this project in private sales from the Province of Alberta. An exploratory well is planned upon completion of land assembly activities. The Company is also developing the Evi West project, targeting the Granite Wash sands located in an area near certain of the Company's production facilities. The Company has completed a detailed 2-D seismic analysis which revealed sands draped over a Precambrian structure at a depth of approximately 5,000 feet. The Company owns a 100% working interest in approximately 640 gross leasehold acres on this project. West Central Alberta. The Company owns approximately 16,000 gross (7,050 net) leasehold acres in the Bronson project with working interests ranging from 50% to 100%. An exploratory well on this acreage has been drilled and cased for further evaluation. The Company has obtained a license to drill another exploratory well and is waiting for a drilling rig to commence drilling. Wiser is also producing gas from the shallower Cardium formation. The Company owns approximately 1,920 gross (960 net) leasehold acres in the Ferrier prospect, and has a 50% working interest in this acreage. Based on a 2-D seismic analysis of this area, the Company intends to drill an exploratory well through the Cretaceous and into the Mississippian formations at a depth of approximately 10,000 feet. The Company recently obtained a license to drill the test well and a drilling rig is on location. In addition, the Company has secured a five section farm-in of adjacent acreage. Plant capacity and infrastructure are currently available in the area. 10 The Company owns approximately 640 gross (213 net) leasehold acres and has a 33% working interest with two equal partners in the Windfall project. A shallow natural gas target has been confirmed, and Wiser is currently interpreting 2-D seismic on a second, deeper target. An exploratory test well is expected to spud during the third quarter of 1997. The Company has secured a farm-in of 480 acres of land in the Provost area. An exploratory well targeting the Cretaceous formation at approximately 4,200 feet is expected to spud in the second quarter of 1997. The Company is waiting for a drilling rig to commence drilling on this location. MARKETING OF PRODUCTION The Company markets its production of oil, natural gas and NGLs to a variety of purchasers, including large refiners and resellers, pipeline affiliate marketers, independent marketers, utilities and industrial end-users. To help manage the impact of potential price declines, Wiser has developed a portfolio of long- and short-term contracts with prices that are either fixed or related to market conditions in varying degrees. Most of the Company's production is sold pursuant to contracts that provide for market-related pricing for the areas in which the production is located. During the year ended December 31, 1996, revenues from the sale of production to Highland Energy Company, Koch Oil Co. Ltd. and Texaco Trading and Transportation represented approximately 35%, 18% and 15%, respectively, of the Company's total oil and gas revenues. The sales to Koch Oil Co. Ltd. accounted for approximately 75% of the Company's revenues from sales of its Canadian production in 1996. The Company believes it would be able to locate alternate purchasers in the event of the loss of any one or more of these purchasers, and that any such loss would not have a material adverse effect on the Company's financial condition or results of operations. Crude Oil. The Company sells its crude oil and condensate to various refiners and resellers in the United States and Canada at posting-related and spot-related prices that also depend on factors such as well location, production volume and product quality. The Company typically sells its crude oil and condensate production at or near the well site, although in some cases it is gathered by the Company or others and delivered to a central point of sale. The Company's crude oil and condensate production is transported by truck or by pipeline and is typically committed to arrangements having a term of one year or less. The Company has not engaged in crude oil trading activities. Revenue from the sale of crude oil and condensate totaled $45.6 million for the year ended December 31, 1996 and represented 63% of the Company's total oil and gas revenues for that period. From time to time, the Company enters into crude oil price hedges to reduce its exposure to commodity price fluctuation. At December 31, 1996, approximately 41% of the Company's total expected crude oil production through December 1997 was hedged under such arrangements at a weighted average volume of 3,496 Bbls of oil per day and at a weighted average hedge floor price of $16.39 and hedge ceiling price of $19.06 per Bbl. See "Management's Discussion and Analysis of Financial Condition and Results of Operations--Other Matters" and Note 1 to the Company's Consolidated Financial Statements included elsewhere in this Report. Natural Gas. The Company sells its produced natural gas and gathered gas to utilities, marketers, processor/resellers and industrial end-users primarily under market-sensitive, long-term contracts or daily, monthly or multi-month spot agreements. An insignificant amount of the Company's natural gas is committed to long-term, fixed-price sales agreements. To accomplish the delivery and sale of certain of its natural gas, the Company has entered into long-term agreements with various natural gas gatherers that deliver its gas to points of sale on major transmission pipelines. In Kentucky and Tennessee, the Company owns and operates an extensive natural gas gathering and transportation system consisting of approximately 340 miles of pipeline, 16 gas compressor stations, two gas processing plants and two gas storage reservoirs. The Company utilizes this system to procure, aggregate and deliver natural gas produced from over 260 wells that are owned and operated by the Company, comprising most 11 of its Appalachian Basin natural gas production, together with natural gas produced from wells owned and operated by others, in meeting its delivery obligations under a sales contract with a local utility. This sales contract, which expires on October 31, 1999, provides for market-related pricing plus payment of a stated standby demand charge based on an established peak-day delivery obligation. The maximum daily volume of natural gas that the utility may demand is subject to annual adjustment (never to exceed 12,000 Mcf per day) and currently is fixed at 11,000 Mcf per day. For the year ended December 31, 1996, approximately 10% of the Company's total natural gas production was sold under this sales contract. The Company also utilizes its Kentucky/Tennessee gathering and transportation system to transport natural gas on behalf of third parties and natural gas purchased from third parties for resale. The Company believes that it has sufficient production from its properties, and from those of others tied to its gathering and transportation system, to meet the Company's delivery obligations under its existing natural gas sales contracts. Although the Company has not entered into financial transactions to hedge the price of its estimated future natural gas production for 1997 or beyond, it may consider various hedging arrangements in the future. NGLs. From its natural gas processing plants in West Texas and Kentucky, the Company sells NGLs to independent marketers for resale. A direct pipeline connection to the Texas Gulf Coast market area facilitates the sale of NGLs from the Company's Wellman Unit, and enables the Company to receive prices that are representative of the daily market value of NGLs on the Texas Gulf Coast, less transportation and fractionation costs. The market for NGLs in Kentucky is less competitive with higher transportation costs in that region due to the absence of product pipelines. The Company's average price in 1996 for NGLs sold from Company-operated plants or under processing agreements with others was $13.36 per Bbl. At December 31, 1996, approximately 40% of the Company's total expected NGL production from January 1 through March 31, 1997 was hedged at a weighted average swap price of $18.76 per Bbl. Prices for NGLs attributable to natural gas sold to plants operated by others are generally included in the prices reported by the Company for the sale of its natural gas. Price Considerations. Crude oil prices are established in a highly liquid, international market, with average crude oil prices received by the Company generally fluctuating with changes in the futures price established on the NYMEX for West Texas Intermediate Crude Oil ("NYMEX-WTI"). The average crude oil price per Bbl received by the Company in 1996 was $18.81, compared to an average price per Bbl of $20.86 that would have been received before the effects of the Company's hedging activities. The average NYMEX-WTI closing price per Bbl for 1996 was $22.01. Natural gas prices in each of the geographical areas in which the Company operates are closely tied to established price indices which are heavily influenced by national and regional supply and demand factors and the futures price per MMBtu for natural gas delivered at Henry Hub, Louisiana established on the NYMEX ("NYMEX-Henry Hub"). At times, these indices correlate closely with the NYMEX-Henry Hub price, but often, as in early 1996, there are significant variances between the NYMEX-Henry Hub price and the indices used to price the Company's natural gas. Average natural gas prices received by Wiser in each of its operating areas generally fluctuate with changes in these established indices. The average natural gas price per Mcf received by the Company in 1996 was $1.77, compared to an average price per Mcf of $1.92 that would have been received before the effects of the Company's hedging activities. The NYMEX-Henry Hub price per MMBtu for 1996, as represented by the annual average of the closing price on the last three trading days for the prompt month NYMEX natural gas futures contract applicable to each month in 1996, was $2.55. The average natural gas price received by the Company in 1996 was lower than such 1996 NYMEX-Henry Hub price as a result of pricing differentials determined by the location of the Company's natural gas production relative to the Henry Hub trading point, lower natural gas prices generally applicable to Canadian natural gas production relative to U.S. production and the Company's hedging activities. 12 OIL AND GAS RESERVES The following table sets forth the proved developed and undeveloped reserves of the Company at December 31, 1996:
OIL AND NGLS (MBBLS) NATURAL GAS (MMCF) TOTAL RESERVES (MBOE) ---------------------------- ----------------------------- ---------------------------- DEVELOPED UNDEVELOPED TOTAL DEVELOPED UNDEVELOPED TOTAL DEVELOPED UNDEVELOPED TOTAL --------- ----------- ------ --------- ----------- ------- --------- ----------- ------ Permian Basin Maljamar............... 11,914 2,792 14,706 5,266 982 6,248 12,792 2,956 15,748 Wellman................ 7,067 -- 7,067 2,494 -- 2,494 7,482 -- 7,482 Dimmitt/Slash Ranch.... 2,191 357 2,548 12,276 678 12,954 4,237 470 4,707 ------ ----- ------ ------- ------ ------- ------ ----- ------ Total Permian Basin.... 21,172 3,149 24,321 20,036 1,660 21,696 24,511 3,426 27,937 Appalachian Basin....... 967 22 989 26,173 5,460 31,633 5,328 932 6,260 San Juan Basin.......... 48 -- 48 20,358 473 20,831 3,442 78 3,520 Other................... 2,705 17 2,722 14,085 1,301 15,386 5,053 234 5,287 ------ ----- ------ ------- ------ ------- ------ ----- ------ Total United States.... 24,892 3,188 28,080 80,652 8,894 89,546 38,334 4,670 43,004 Canada.................. 3,225 307 3,532 22,477 1,354 23,831 6,971 533 7,504 ------ ----- ------ ------- ------ ------- ------ ----- ------ Total Company.......... 28,117 3,495 31,612 103,129 10,248 113,377 45,305 5,203 50,508 ====== ===== ====== ======= ====== ======= ====== ===== ======
The following table summarizes the Company's proved reserves, the estimated future net revenues from such proved reserves and the Present Value and Standardized Measure of Discounted Future Net Cash Flows attributable thereto at December 31, 1996, 1995 and 1994:
AT DECEMBER 31, ----------------------------- 1996 1995 1994 --------- --------- --------- (DOLLARS IN THOUSANDS, EXCEPT FOR WEIGHTED AVERAGE SALES PRICES) Proved reserves: Oil and NGLs (MBbl)........................ 31,612 32,208 23,430 Natural gas (MMcf)......................... 113,377 109,915 107,920 Oil equivalents (MBOE).................... 50,508 50,527 41,417 Estimated future net revenues before income taxes..................................... $ 705,723 $ 401,037 $ 272,776 Present Value.............................. $ 414,314 $ 235,416 $ 160,804 Standardized Measure of Discounted Future Net Cash Flows(1)......................... $ 317,180 $ 194,602 $ 142,032 Proved developed reserves: Oil and NGLs (MBbl)........................ 28,117 21,556 18,799 Natural gas (MMcf)......................... 103,129 102,026 98,370 Oil equivalents (MBOE).................... 45,305 38,560 35,194 Estimated future net revenues before income taxes..................................... $ 631,406 $ 310,034 $ 251,003 Present Value.............................. $ 381,169 $ 195,439 $ 155,642 Weighted average sales prices: Oil (per Bbl).............................. $ 24.63 $ 18.19 $ 16.11 Natural gas (per Mcf)...................... 3.45 1.84 1.57 NGLs (per Bbl)............................. 19.79 12.87 9.80
- -------- (1) The Standardized Measure of Discounted Future Net Cash Flows prepared by the Company represents the present value (using an annual discount rate of 10%) of estimated future net revenues from the production of proved reserves, after giving effect to income taxes. See the Supplemental Financial Information attached to the Consolidated Financial Statements of the Company included elsewhere in this Report for additional information regarding the disclosure of the Standardized Measure information in accordance with the provisions of Statement of Financial Accounting Standards No. 69, "Disclosures about Oil and Gas Producing Activities." 13 All information set forth in this Report relating to the Company's proved reserves, estimated future net revenues and Present Values is taken from reports prepared by DeGolyer and MacNaughton (with respect to the Company's United States properties) and Gilbert Lausten Jung Associates Ltd. (with respect to the Company's Canadian properties), each of which is a firm of independent petroleum engineers. The estimates of these engineers were based upon review of production histories and other geological, economic, ownership and engineering data provided by the Company. No reports on the Company's reserves have been filed with any federal agency. In accordance with guidelines of the Securities and Exchange Commission ("SEC"), the Company's estimates of proved reserves and the future net revenues from which Present Values are derived are made using year end oil and gas sales prices held constant throughout the life of the properties (except to the extent a contract specifically provides otherwise). The prices of oil and gas at December 31, 1996 used to estimate the Company's proved reserves and the future net revenues from which Present Value is derived were substantially higher than the prices used in previous years to make such estimates and substantially higher than oil and gas prices at February 28, 1997. The closing price on the NYMEX for the prompt month futures contract for delivery of West Texas Intermediate Crude Oil on December 31, 1996 and February 28, 1997 was $25.92 and $20.30 per Bbl, respectively. The closing price on the NYMEX for the prompt month futures contract for natural gas delivered at Henry Hub, Louisiana on December 31, 1996 and February 28, 1997 was $2.76 and $1.82 per MMBtu, respectively. A decline in prices relative to year end 1996 could cause a significant decline in the Present Value attributable to the Company's proved reserves at December 31, 1996. For example, a $1.00 decline in oil and NGL prices, holding all other variables constant, would decrease such Present Value by 4%, or $14.8 million, and a $0.10 decline in natural gas prices, holding all other variables constant, would decrease such Present Value by 1%, or $5.1 million. Operating costs, development costs and certain production- related taxes were deducted in arriving at estimated future net revenues, but such costs do not include debt service, general and administrative expenses and income taxes. There are numerous uncertainties inherent in estimating oil and gas reserves and their values, including many factors beyond the Company's control. The reserve data set forth in this Report represents estimates only. Reservoir engineering is a subjective process of estimating the sizes of underground accumulations of oil and gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation, and judgment. As a result, estimates of different engineers, including those used by the Company, may vary. In addition, estimates of reserves are subject to revision based upon actual production, results of future development, exploitation and exploration activities, prevailing oil and gas prices, operating costs and other factors, which revisions may be material. Accordingly, reserve estimates are often different from the quantities of oil and gas that are ultimately recovered and are highly dependent upon the accuracy of the assumptions upon which they are based. There can be no assurance that these estimates are accurate predictions of the Company's oil and gas reserves or their values. Estimates with respect to proved reserves that may be developed and produced in the future are often based upon volumetric calculations and upon analogy to similar types of reserves rather than actual production history. Estimates based on these methods are generally less reliable than those based on actual production history. Subsequent evaluation of the same reserves based upon production history will result in variations, which may be substantial, in the estimated reserves. 14 NET PRODUCTION, SALES PRICES AND COSTS The following table presents certain information with respect to oil and gas production, prices and costs attributable to all oil and gas property interests owned by the Company for the three-year period ended December 31, 1996.
YEAR ENDED DECEMBER 31, ----------------------- 1996 1995 1994 ------- ------- ------- PRODUCTION VOLUMES: Oil (MBbl) United States........................................ 1,732 1,445 1,794 Canada............................................... 693 635 310 ------- ------- ------- Total Company....................................... 2,425 2,080 2,104 Natural gas (MMcf) United States (1).................................... 9,479 9,418 9,804 Canada............................................... 2,809 2,753 1,272 ------- ------- ------- Total Company (1)................................... 12,288 12,171 11,076 NGLs (MBbl) United States........................................ 301 212 163 Canada............................................... 50 40 10 ------- ------- ------- Total Company....................................... 351 252 173 WEIGHTED AVERAGE SALES PRICES (2): Oil (per Bbl) United States........................................ $ 18.91 $ 17.14 $ 15.48 Canada............................................... 18.55 16.38 16.32 Total Company....................................... 18.81 16.91 15.60 Natural gas (per Mcf) United States (1).................................... $ 1.95 $ 1.46 $ 1.79 Canada............................................... 1.16 1.05 1.23 Total Company (1)................................... 1.77 1.37 1.73 NGLs (per Bbl) United States........................................ $ 12.88 $ 9.67 $ 8.93 Canada............................................... 16.21 12.45 10.15 Total Company....................................... 13.36 10.11 9.00 SELECTED EXPENSES PER BOE (3): Lease operating United States........................................ $ 4.53 $ 4.59 $ 4.74 Canada............................................... 3.04 2.58 3.22 Total Company....................................... 4.14 4.06 4.54 Production taxes (4) United States........................................ $ 0.93 $ 0.78 $ 0.97 Depreciation, depletion and amortization United States........................................ $ 3.36 $ 3.63 $ 4.20 Canada............................................... 6.49 7.37 6.72 Total Company....................................... 4.16 4.62 4.53 General and administrative United States........................................ $ 2.11 $ 1.99 $ 1.58 Canada............................................... 1.61 1.70 1.76 Total Company....................................... 1.98 1.92 1.61
- -------- (1) Calculated giving effect to volumes of natural gas purchased for resale as follows: 1996--605 MMcf, 1995--500 MMcf and 1994--469 MMcf. (2) Reflects results of hedging activities. See "Management's Discussion and Analysis of Financial Condition and Results of Operations--Other Matters." (3) Calculated without giving effect to volumes of natural gas purchased for resale. (4) Canada does not assess production taxes on revenue derived from oil and gas production from Crown lands. However, in Canada, royalties are payable to the provincial governments on production from Crown lands, subject to certain programs that provide for royalty rate reductions, royalty holidays and tax credits for the purpose of encouraging oil and gas exploration and development. See "--Governmental Regulation--Canada." 15 PRODUCTIVE WELLS AND ACREAGE Productive Wells The following table sets forth the Company's domestic and Canadian productive wells at December 31, 1996:
PRODUCTIVE WELLS -------------------------------- OIL GAS TOTAL --------- ------------ --------- GROSS NET GROSS NET GROSS NET ----- --- ----- --- ----- --- United States.................................. 830 514 2,651(1) 355 3,481 869 Canada......................................... 220 57 67 24 287 81 ----- --- ----- --- ----- --- Total........................................ 1,050 571 2,718 379 3,768 950 ===== === ===== === ===== ===
- -------- (1) 2,200 of the Company's gross natural gas wells are located in the San Juan Basin. The Company has non-operated working interests in these wells ranging from 0.21% to 4.2%. Acreage The following table sets forth the Company's undeveloped and developed gross and net leasehold acreage at December 31, 1996. Undeveloped acreage includes leased acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas, regardless of whether or not such acreage contains proved reserves.
UNDEVELOPED ACRES DEVELOPED ACRES TOTAL ACRES(1) ----------------- --------------- --------------- GROSS NET GROSS NET GROSS NET ----------------- ------- ------- ------- ------- Permian Basin Maljamar.................... 0 0 11,773 11,761 11,773 11,761 Wellman..................... 0 0 2,280 1,432 2,280 1,432 Dimmitt/Slash Ranch......... 480 440 7,487 5,457 7,967 5,897 -------- -------- ------- ------- ------- ------- Total Permian Basin....... 480 440 21,540 18,650 22,020 19,090 Appalachian Basin............. 26,846 21,195 116,330 100,695 143,176 121,890 San Juan Basin................ 0 0 11,140 5,281 11,140 5,281 Other......................... 62,365 10,939 71,856 24,552 134,221 35,491 -------- -------- ------- ------- ------- ------- Total United States....... 89,691 32,574 220,866 149,178 310,557 181,752 Canada........................ 166,487 74,595 56,919 21,051 223,406 95,646 -------- -------- ------- ------- ------- ------- Total Company............. 256,178 107,169 277,785 170,229 533,963 277,398 ======== ======== ======= ======= ======= =======
- -------- (1) Excluded is acreage in which the Company's interest is limited to a mineral or royalty interest. At December 31, 1996, the Company held mineral or royalty interests in 227,180 gross (31,465 net) developed acres and 1,371,809 gross (203,346 net) undeveloped acres. 16 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:
ACRES EXPIRING --------------- GROSS NET ------- ------- Twelve Months Ending: December 31, 1997.......................................... 35,579 10,840 December 31, 1998.......................................... 30,874 8,657 Thereafter................................................. 189,725 87,672 ------- ------- Total.................................................... 256,178 107,169 ======= =======
As is customary in the industry, the Company generally acquires oil and gas acreage without any warranty of title except as to claims made by, through or under the transferor. Although the Company has title to developed acreage examined prior to acquisition in those cases in which the economic significance of the acreage justifies the cost, there can be no assurance that losses will not result from title defects or from defects in the assignment of leasehold rights. In many instances, title opinions may not be obtained if in the Company's judgment it would be uneconomical or impractical to do so. DRILLING ACTIVITY The following table sets forth for the three-year period ended December 31, 1996 the number of exploratory and development wells drilled by or on behalf of the Company.
YEAR ENDED DECEMBER 31, ----------------------------- 1996 1995 1994 --------- --------- --------- GROSS NET GROSS NET GROSS NET ----- --- ----- --- ----- --- Exploratory Wells: United States Producing.................................. 1 1 9 3 4 1 Dry........................................ 2 1 10 3 7 2 Canada Producing.................................. 1 1 3 2 3 2 Dry........................................ 6 4 4 2 7 3 Development Wells: United States Producing.................................. 93 85 48 27 34 15 Dry........................................ 2 1 2 2 6 2 Canada Producing.................................. 21 15 4 2 1 0 Dry........................................ 5 3 2 2 1 0 Total Wells: Producing.................................. 116 102 64 34 42 18 Dry........................................ 15 9 18 9 21 7 --- --- --- --- --- --- Total.................................... 131 111 82 43 63 25 === === === === === ===
17 OPERATIONS The Company generally seeks to be named as operator for wells in which it has acquired a significant interest, although, as is common in the industry, this typically occurs only when the Company owns the major portion of the working interest in a particular well or field. At December 31, 1996, the Company operated 100% of its properties in the Permian Basin, comprising approximately 55% of the Company's total proved reserves, including Maljamar (223 gross wells), Wellman (14 gross wells) and Dimmitt/Slash Ranch (59 gross wells). At December 31, 1996, the Company owned 368 gross wells on its Kentucky and Tennessee properties, of which approximately 98% were operated by the Company. At that same date, the Company also operated 82 (out of a total of 287) gross wells on its Canadian properties. As operator, the Company is able to exercise substantial influence over the development and enhancement of a well and to supervise operation and maintenance activities on a daily basis. The Company does not conduct the actual drilling of wells on properties for which it acts as operator, but engages independent contractors who are supervised by the Company. The Company employs petroleum engineers, geologists and other operations and production specialists who strive to improve production rates, increase reserves and/or lower the cost of operating its oil and gas properties. Oil and gas properties are customarily operated under the terms of a joint operating agreement, which provides for reimbursement of the operator's direct expenses and monthly per-well supervision fees. Per-well supervision fees vary widely depending on the geographic location and producing formation of the well, whether the well produces oil or gas and other factors. Such fees received by the Company in 1996 ranged from $95 to $870 per well per month. COMPETITION The oil and gas industry is highly competitive. The Company encounters competition from other oil and gas companies in all areas of its operations, including the acquisition of producing properties. The Company's competitors include major integrated oil and gas companies and numerous independent oil and gas companies, individuals and drilling and income programs. Many of its competitors are large, well established companies with substantially larger operating staffs and greater capital resources than the Company. Such companies may be able to pay more for productive oil and gas properties and exploratory prospects and to define, evaluate, bid for and purchase a greater number of properties and prospects than the Company's financial or human resources permit. The Company's ability to acquire additional properties and to discover reserves in the future will depend upon its ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. DRILLING AND OPERATING RISKS Drilling activities are subject to many risks, including the risk that no commercially productive oil or gas reservoirs will be encountered. There can be no assurance that new wells drilled by the Company will be productive or that the Company will recover all or any portion of its investment. Drilling for oil and gas may involve unprofitable efforts, not only from dry wells, but from wells that are productive but do not produce sufficient net revenues to return a profit after drilling, operating and other costs. The cost of drilling, completing and operating wells is often uncertain. The Company's drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, many of which are beyond its control, including economic conditions, mechanical problems, pressure or irregularities in formations, title problems, weather conditions, compliance with governmental requirements and shortages in or delays in the delivery of equipment and services. Such equipment shortages and delays sometimes involve drilling rigs, especially in Canada, where weather conditions result in a short drilling season, causing a high demand for rigs by a large number of companies during a relatively short period of time. The Company's future drilling activities may not be successful. Lack of drilling success could have a material adverse effect on the Company's financial condition and results of operations. 18 In addition, the Company's use of 3-D seismic requires greater pre-drilling expenditures than traditional drilling strategies. Although the Company believes that its use of 3-D seismic will increase the probability of success of its exploratory wells and should reduce average finding costs through the elimination of prospects that might otherwise be drilled solely on the basis of 2-D seismic and other traditional methods, unsuccessful wells are likely to occur. The Company's operations are subject to all the hazards and risks normally incident to the development, exploitation, production and transportation of, and the exploration for, oil and gas, including unusual or unexpected geologic formations, pressures, downhole fires, mechanical failures, blowouts, cratering, explosions, uncontrollable flows of oil, gas or well fluids and pollution and other environmental risks. These hazards could result in substantial losses to the Company due to injury and loss of life, severe damage to and destruction of property and equipment, pollution and other environmental damage and suspension of operations. The Company maintains comprehensive insurance coverage, including a $1.0 million general liability insurance policy and a $20.0 million excess liability policy. The Company believes that its insurance is adequate and customary for companies of a similar size engaged in comparable operations, but losses could occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. TITLE TO PROPERTIES The Company's land department and contract land professionals have reviewed title records or other title review materials relating to substantially all of its producing properties. The title investigation performed by the Company prior to acquiring undeveloped properties is thorough, but less rigorous than that conducted prior to drilling, consistent with industry standards. The Company believes it has satisfactory title to all its producing properties in accordance with standards generally accepted in the oil and gas industry. The Company's properties are subject to customary royalty interests, liens incident to operating agreements, liens for current taxes and other inchoate burdens which the Company believes do not materially interfere with the use of or affect the value of such properties. At December 31, 1996, the Company's leaseholds for approximately 61% of its net acreage were being kept in force by virtue of production on that acreage in paying quantities. The remaining net acreage was held by lease rentals and similar provisions and requires production in paying quantities prior to expiration of various time periods to avoid lease termination. The Company expects to make acquisitions of oil and gas properties from time to time. In making an acquisition, the Company generally focuses most of its title and valuation efforts on the more significant properties. It is generally not feasible for the Company to review in-depth every property it purchases and all records with respect to such properties. However, even an in-depth review of properties and records may not necessarily reveal existing or potential problems, nor will it permit the Company to become familiar enough with the properties to assess fully their deficiencies and capabilities. Evaluation of future recoverable reserves of oil and gas, which is an integral part of the property selection process, is a process that depends upon evaluation of existing geological, engineering and production data, some or all of which may prove to be unreliable or not indicative of future performance. To the extent the seller does not operate the properties, obtaining access to properties and records may be more difficult. Even when problems are identified, the seller may not be willing or financially able to give contractual protection against such problems, and the Company may decide to assume environmental and other liabilities in connection with acquired properties. GOVERNMENTAL REGULATION The Company's operations are affected from time to time in varying degrees by political developments and federal, state, provincial and local laws and regulations. In particular, oil and gas production and related operations are or have been subject to price controls, taxes and other laws and regulations relating to the oil and gas industry. Failure to comply with such laws and regulations can result in substantial penalties. The regulatory burden on the oil and gas industry increases the Company's cost of doing business and affects its profitability. Although the Company believes it is in substantial compliance with all applicable laws and regulations, because 19 such laws and regulations are frequently amended or reinterpreted, the Company is unable to predict the future cost or impact of complying with such laws and regulations. United States. Sales of natural gas by the Company are not regulated and are generally made at market prices. However, the Federal Energy Regulatory Commission ("FERC") regulates interstate natural gas transportation rates and service conditions, which affect the marketing of natural gas produced by the Company, as well as the revenues received by the Company for sales of such production. Although maximum selling prices of natural gas were formerly regulated, on July 26, 1989, the Natural Gas Wellhead Decontrol Act ("Decontrol Act") was enacted, completely removing by January 1, 1993, price and non-price controls for all "first sales" of natural gas, which include all sales by the Company of its own production; consequently, sales of the Company's natural gas currently may be made at uncontrolled market prices, subject to applicable contract provisions. The FERC's jurisdiction over natural gas transportation was unaffected by the Decontrol Act. While sales by producers of natural gas, and all sales of crude oil, condensate and NGLs, can currently be made at uncontrolled market prices, Congress could re-enact prices controls in the future. Since the mid-1980's, the FERC has issued a series of orders, culminating in Order Nos. 636, 636-A and 636-B ("Order 636"), that have significantly altered the marketing and transportation of natural gas. Order 636 mandates a fundamental restructuring of interstate pipeline sales and transportation service, including the unbundling by interstate pipelines of the sale, transportation, storage and other components of the city-gate sales services such pipelines previously performed. One of the FERC's purposes in issuing the orders is to increase competition within all phases of the natural gas industry. Order 636 and subsequent FERC orders issued in individual pipeline restructuring proceedings have been the subject of appeals, the results of which have generally been supportive of the FERC's open-access policy. Last year the United States Court of Appeals for the District of Columbia largely upheld Order No. 636. Because further review of certain of these orders is still possible, and other appeals remain pending, it is difficult to predict the ultimate impact of the orders on the Company and its natural gas marketing efforts. Generally, Order 636 has eliminated or substantially reduced the interstate pipelines' traditional role as wholesalers of natural gas, and has substantially increased competition and volatility in natural gas markets. While significant regulatory uncertainty remains, Order 636 may ultimately enhance the Company's ability to market and transport its natural gas, although it may also subject the Company to greater competition, more restrictive pipeline imbalance tolerances and greater associated penalties for violation of such tolerances. The FERC has announced several important transportation-related policy statements and proposed rule changes, including the appropriate manner in which interstate pipelines release capacity under Order 636 and, more recently, the price which shippers can charge for their released capacity. In addition, in 1995, the FERC issued a policy statement on how interstate natural gas pipelines can recover the costs of new pipeline facilities. In January 1996, the FERC issued a policy statement and a request for comments concerning alternatives to its traditional cost-of-service ratemaking methodology. A number of pipelines have obtained FERC authorization to charge negotiated rates as one such alternative. While any additional FERC action on these matters would affect the Company only indirectly, these policy statements and proposed rule changes are intended to further enhance competition in natural gas markets. The Company cannot predict what action the FERC will take on these matters, nor can it predict whether the FERC's actions will achieve its stated goal of increasing competition in natural gas markets. However, the Company does not believe that it will be treated materially differently than other natural gas producers and marketers with which it competes. Commencing in May 1994, the FERC issued a series of orders in individual cases that delineate its new gathering policy. Among other matters, the FERC slightly narrowed its statutory tests for establishing gathering status and reaffirmed that, except in situations in which the gatherer acts in concert with an interstate pipeline affiliate to frustrate the FERC's transportation policies, it does not generally have jurisdiction over natural gas gathering facilities and services, and that such facilities and services located in state jurisdictions are properly regulated by state authorities. In addition, the FERC has approved numerous transfers by interstate pipelines of gathering facilities to unregulated independent or affiliated gathering companies, subject to the transferee 20 providing service for two years from the date of transfer to the pipeline's existing customers pursuant to a default contract or pursuant to mutually agreeable terms. In August 1996, the United States Court of Appeals for the District of Columbia largely upheld the FERC's new gathering policy, but remanded the FERC's default contract condition. The FERC has not yet issued an order on remand. This new gathering policy may tend to increase competition among gatherers, like the Company. This policy may also result in increased state regulation of the Company's gathering facilities. However, the Company does not believe that it will be affected materially differently by this policy than other producers, gatherers and marketers with which it competes. The Company's gathering operations are subject to safety and operational regulations relating to the design, installation, testing, construction, operation, replacement and management of facilities. Pipeline safety issues have recently been the subject of increasing focus in various political and administrative arenas at both the state and federal levels. The Company believes its operations, to the extent they may be subject to current gas pipeline safety requirements, comply in all material respects with such requirements. The Company cannot predict what effect, if any, the adoption of this or other additional pipeline safety legislation might have on its operations, but the industry could be required to incur additional capital expenditures and increased costs depending upon future legislative and regulatory changes. The price the Company receives from the sale of oil and NGLs is affected by the cost of transporting such products to market. Effective January 1, 1995, the FERC implemented regulations establishing an indexing system for transportation rates for oil pipelines, which, generally, would index such rates to inflation, subject to certain conditions and limitations. These regulations could increase the cost of transporting oil and NGLs by interstate pipelines, although the most recent adjustment generally decreased rates. These regulations have generally been approved on judicial review. The Company is not able to predict with certainty the effect, if any, of these regulations on its operations. However, the regulations may increase transportation costs or reduce wellhead prices for oil and NGLs. The State of Texas and many other states require permits for drilling operations, drilling bonds and reports concerning operations and impose other requirements relating to the exploration for and production of oil and gas. Such states also have statutes or regulations addressing conservation matters, including provisions for the unitization or pooling of oil and gas properties, the establishment of maximum rates of production from wells and the regulation of spacing, plugging and abandonment of such wells. The statutes and regulations of certain states limit the rate at which oil and gas can be produced from the Company's properties. However, the Company does not believe it will be affected materially differently by these statutes and regulations than any other similarly situated oil and gas company. Canada. In Canada producers of oil negotiate sales contracts directly with oil purchasers, with the result that sales of oil are generally made at market prices. The price of oil received by the Company depends in part on oil quality, prices of competing fuels, distance to market, the value of refined products and the supply/demand balance. Oil exports may be made pursuant to export contracts with terms not exceeding one year in the case of light crude, and not exceeding two years in the case of heavy crude, provided that an order approving any such export has been obtained from the National Energy Board ("NEB"). Any oil export to be made pursuant to a contract of a longer duration requires an exporter to obtain an export license from the NEB and the issue of such license requires the approval of the Governor General in Counsel. In Canada the price of natural gas sold is determined by negotiation between buyers and sellers. Natural gas exported from Canada is subject to regulation by the NEB and the government of Canada. Exporters are free to negotiate prices and other terms with purchasers, provided that export contracts in excess of two years must continue to meet certain criteria prescribed by the NEB and the government of Canada. As is the case with oil, natural gas exports for a term of less than two years must be made pursuant to an NEB order, or, in the case of exports for a longer duration, pursuant to an NEB license and Governor General in Council approval. The government of Alberta also regulates the volume of natural gas that may be removed from Alberta for consumption elsewhere based on such factors as reserve availability, transportation arrangements and marketing considerations. 21 In addition to Canadian federal regulation, Alberta and certain other provinces have legislation and regulations that govern royalties payable on production from Crown lands. The royalty regime that is in place at a particular time or location is a significant factor in the profitability of oil and gas production. Royalties payable on production from lands other than Crown lands are determined by negotiations between the mineral owner and the lessee. Crown royalties are determined by governmental regulation and are generally calculated as a percentage of the value of the gross production. The rate of royalties payable generally depends in part on prescribed reference prices, well productivity, geographical location, field discovery date and the type and quality of the petroleum product produced. From time to time the government of Alberta has established incentive programs that have included royalty rate reductions, royalty holidays and tax credits for the purpose of encouraging oil and gas exploration or enhanced production projects. For example, a producer of oil or gas is entitled to a credit against the royalties payable to the Crown by virtue of the Alberta Royalty Tax Credit ("ARTC") program. The ARTC program provides a rebate on Crown royalties paid in respect of eligible producing properties. The ARTC program is based on a price-sensitive formula, and the ARTC rate currently varies between 25% and 75% of the royalty otherwise payable on production. The ARTC rate is currently applied to a maximum of $2.0 million of Alberta Crown royalties otherwise payable by each producer or associated group of producers in each tax year. The rate is established quarterly based on average "par price," as determined by the Alberta Department of Energy for the previous quarterly period. Producing properties acquired from corporations claiming maximum entitlement to ARTC will generally not be eligible for ARTC. ENVIRONMENTAL MATTERS The Company's operations and properties are subject to extensive and changing federal, state, provincial and local laws and regulations relating to environmental protection, including the generation, storage, handling and transportation of oil and gas and the discharge of materials into the environment, and relating to safety and health. The recent trend in environmental legislation and regulation generally is toward stricter standards, and this trend will likely continue. These laws and regulations may require the acquisition of a permit or other authorization before construction or drilling commences and for certain other activities; limit or prohibit construction, drilling and other activities on certain lands lying within wilderness and other protected areas; and impose substantial liabilities for pollution resulting from the Company's operations. The permits required for various of the Company's operations are subject to revocation, modification and renewal by issuing authorities. Governmental authorities have the power to enforce compliance with their regulations, and violations are subject to fines, penalties or injunctions. In the opinion of management, the Company is in substantial compliance with current applicable environmental laws and regulations, and the Company has no material commitments for capital expenditures to comply with existing environmental requirements. Nevertheless, changes in existing environmental laws and regulations or in interpretations thereof could have a significant impact on the Company. The impact of such changes, however, would not likely be any more burdensome to the Company than to any other similarly situated oil and gas company. The Comprehensive Environmental Response, Compensation, and Liability Act ("CERCLA"), also known as the "Superfund" law, and similar state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a "hazardous substance" into the environment. These persons include the owner or operator of the disposal site or sites where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at the site. Persons who are or were responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources. Furthermore, neighboring landowners and other third parties may file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. The Company generates typical oil and gas field wastes, including hazardous wastes, that are subject to the federal Resources Conservation and Recovery Act and comparable state statutes. The United States 22 Environmental Protection Agency and various state agencies have limited the approved methods of disposal for certain hazardous and nonhazardous wastes. Furthermore, certain wastes generated by the Company's oil and gas operations that are currently exempt from regulation as "hazardous wastes" may in the future be designated as "hazardous wastes," and therefore be subject to more rigorous and costly operating and disposal requirements. The Oil Pollution Act ("OPA") imposes a variety of requirements on responsible parties for onshore and offshore oil and gas facilities and vessels related to the prevention of oil spills and liability for damages resulting from such spills in waters of the United States. The "responsible party" includes the owner or operator of an onshore facility or vessel or the lessee or permittee of, or the holder of a right of use and easement for, the area where an onshore facility is located. OPA assigns liability to each responsible party for oil spill removal costs and a variety of public and private damages from oil spills. Few defenses exist to the liability for oil spills imposed by OPA. OPA also imposes financial responsibility requirements. Failure to comply with ongoing requirements or inadequate cooperation in a spill event may subject a responsible party to civil or criminal enforcement actions. The Company's Canadian operations are also subject to environmental regulation pursuant to local, provincial and federal legislation. Canadian environmental legislation provides for restrictions and prohibitions on releases or emissions of various substances produced in association with certain oil and gas industry operations and can affect the location of wells and facilities and the extent to which exploration and development is permitted. In addition, legislation requires that well and facilities sites be abandoned and reclaimed to the satisfaction of provincial authorities. In most cases, an environmental assessment and review is required prior to initiating exploration or development projects or undertaking significant changes to existing projects. A breach of such legislation may result in the imposition of fines and issuance of clean-up orders. Environmental legislation in Alberta has recently undergone a major revision and has been consolidated in the Environmental Protection and Enhancement Act. Under the new Act, environmental standards and compliance for releases, clean-up and reporting are stricter. Also, the range of enforcement actions available and the severity of penalties have been significantly increased. These changes will have an incremental effect on the cost of conducting operations in Alberta. The Company owns, leases or operates numerous properties that for many years have produced or processed oil and gas. The Company also owns and operates natural gas gathering, transportation and processing systems. It is not uncommon for such properties to be contaminated with hydrocarbons or polychlorinated biphenyls. Although the Company or previous owners of these interests may have used operating and disposal practices that were standard in the industry at the time, hydrocarbons, polychlorinated biphenyls or other wastes may have been disposed of or released on or under the properties or on or under other locations where such wastes have been taken for disposal. These properties may be subject to federal or state requirements that could require the Company to remove any such wastes or to remediate the resulting contamination. In addition, some of the Company's properties are operated by third parties over whom the Company has no control. Notwithstanding the Company's lack of control over properties operated by others, the failure of the previous owners or operators to comply with applicable environmental regulations may, in certain circumstances, adversely impact the Company. ABANDONMENT COSTS The Company is responsible for payment of plugging and abandonment costs on its oil and gas properties pro rata to its working interest. Based on its experience, the Company anticipates that the ultimate aggregate salvage value of lease and well equipment located on its properties will exceed the costs of abandoning such properties. There can be no assurance, however, that the Company will be successful in avoiding additional expenses in connection with the abandonment of any of its properties. In addition, abandonment costs and their timing may change due to many factors, including actual production results, inflation rates and changes in environmental laws and regulations. 23 EMPLOYEES At February 28, 1997, the Company employed 148 full-time employees, of whom five were executive officers, 29 were technical personnel, 61 were field personnel and 53 were administrative personnel. Of the total employees, 121 were located in the United States and 27 were located in Canada. At February 28, 1997, except for nine employees of the Company associated with its Michigan properties, which properties are currently under contract to be sold, none of the Company's employees was represented by a labor union. The Company considers its relations with its employees to be good. FACILITIES The Company's principal executive and administrative offices are located at 8115 Preston Road, Suite 400, Dallas, Texas. The offices contain approximately 21,000 square feet of space and are leased through December 31, 2001. Rental payments are approximately $33,500 per month. The Company also maintains a regional office in Corbin, Kentucky consisting of a one-story building containing approximately 7,400 square feet of office space. The Company owns this building. The office of the Company's Canadian subsidiary, The Wiser Oil Company of Canada, is located at 645 7th Avenue, S.W., Suite 2550, Calgary, Alberta. This office contains approximately 14,000 square feet of space and is leased through June 30, 1999. Rental payments are approximately $12,500 per month. GLOSSARY OF OIL AND GAS TERMS The following are abbreviations and definitions of terms commonly used in the oil and gas industry that are used in this Report. "BBL" means a barrel of 42 U.S. gallons. "BCF" means billion cubic feet. "BOE" means barrels of oil equivalent, converting volumes of natural gas to oil equivalent volumes using a ratio of six Mcf of natural gas to one Bbl of oil. "COMPLETION" means the installation of permanent equipment for the production of oil or gas. "DEVELOPMENT WELL" means a well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive. "DRY HOLE" OR "DRY WELL" means a well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes. "EXPLORATORY WELL" means a well drilled to find and produce oil or gas reserves not classified as proved, to find a new production reservoir in a field previously found to be productive of oil or gas in another reservoir or to extend a known reservoir. "FARM-IN" means an agreement pursuant to which the owner of a working interest in an oil and gas lease assigns the working interest or a portion thereof to another party who desires to drill on the leased acreage. Generally, the assignee is required to drill one or more wells in order to earn its interest in the acreage. The assignor usually retains a royalty or reversionary interest in the lease. The interest received by an assignee is a "farm-in." "GROSS" when used with respect to acres or wells, refers to the total acres or wells in which the Company has a working interest. "INFILL DRILLING" means drilling of an additional well or wells provided for by an existing spacing order to more adequately drain a reservoir. "MBBL" means thousand Bbls. "MBOE" means thousand BOE. 24 "MCF" means thousand cubic feet. "MMBOE" means million BOE. "MMBTU" means one million British Thermal Units. British Thermal Unit means the quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit. "MMCF" means million cubic feet. "NET" when used with respect to acres or wells, refers to gross acres or wells multiplied, in each case, by the percentage working interest owned by the Company. "NET PRODUCTION" means production that is owned by the Company less royalties and production due others. "NGL" means natural gas liquid. "OPERATOR" means the individual or company responsible for the exploration, development and production of an oil or gas well or lease. "PRESENT VALUE" when used with respect to oil and gas reserves, means the estimated future gross revenues to be generated from the production of proved reserves calculated in accordance with the guidelines of the SEC, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation (except to the extent a contract specifically provides otherwise), without giving effect to non- property related expenses such as general and administrative expenses, debt service, future income tax expense and depreciation, depletion and amortization, and discounted using an annual discount rate of 10%. "PRODUCTIVE WELLS" OR "PRODUCING WELLS" consist of producing wells and wells capable of production, including wells waiting on pipeline connections. "PROVED DEVELOPED RESERVES" means reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery will be included as "proved developed reserves" only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved. "PROVED RESERVES" means the estimated quantities of crude oil, natural gas and NGLs which upon analysis of geological and engineering data appear with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions. (i) Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation tests. The area of a reservoir considered proved includes (A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and (B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir. (ii) Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the "proved" classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based. 25 (iii) Estimates of proved reserves do not include the following: (A) oil that may become available from known reservoirs but is classified separately as "indicated additional reserves"; (B) crude oil, natural gas and NGLs, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics or economic factors; (C) crude oil, natural gas, and NGLs, that may occur in undrilled prospects; and (D) crude oil, natural gas and NGLs that may be recovered from oil shales, coal, gilsonite and other such resources. "PROVED UNDEVELOPED RESERVES" means reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for completion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir. "RECOMPLETION" means the completion for production of an existing well bore in another formation from that in which the well has been previously completed. "RESERVES" means proved reserves. "RESERVOIR" means a porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs. "ROYALTY" means an interest in an oil and gas lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner's royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner. "2-D SEISMIC" means an advanced technology method by which a cross-section of the earth's subsurface is created through the interpretation of reflecting seismic data collected along a single source profile. "3-D SEISMIC" means an advanced technology method by which a three dimensional image of the earth's subsurface is created through the interpretation of reflection seismic data collected over surface grid. 3-D seismic surveys allow for a more detailed understanding of the subsurface than do conventional surveys and contribute significantly to field appraisal, development and production. "WORKING INTEREST" means an interest in an oil and gas lease that gives the owner of the interest the right to drill for and produce oil and gas on the leased acreage and requires the owner to pay a share of the costs of drilling and production operations. The share of production to which a working interest owner is entitled will always be smaller than the share of costs that the working interest owner is required to bear, with the balance of the production accruing to the owners of royalties. "WORKOVER" means operations on a producing well to restore or increase production. ITEM 2. PROPERTIES The information required by this Item is contained in Item 1. Business, and is incorporated herein by reference. 26 ITEM 3. LEGAL PROCEEDINGS The Company and its subsidiaries and affiliates are named defendants in lawsuits and are involved in governmental proceedings from time to time, all arising in the ordinary course of business. Although the outcome of these lawsuits and proceedings cannot be predicted with certainty, management does not expect these matters to have a material adverse effect on the financial position of the Company. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS No matters were submitted to security holders during the fourth quarter of the year ended December 31, 1996. PART II ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED STOCKHOLDER MATTERS The Common Stock is traded on the New York Stock Exchange under the symbol WZR. The quarterly high and low sales prices and dividends per share of Common Stock during the three years ended December 31, 1996, were as follows:
HIGH LOW DIVIDENDS ------ ------ --------- 1996 1st Quarter........................................ $13.38 $11.00 $.03 2nd Quarter........................................ 14.00 12.25 .03 3rd Quarter........................................ 15.50 12.88 .03 4th Quarter........................................ 21.13 14.38 .03 1995 1st Quarter........................................ 14.75 13.38 .10 2nd Quarter........................................ 15.00 13.13 .10 3rd Quarter........................................ 14.38 13.00 .10 4th Quarter........................................ 13.75 10.88 .10 1994 1st Quarter........................................ 18.88 15.75 .10 2nd Quarter........................................ 16.63 15.00 .10 3rd Quarter........................................ 17.38 15.75 .10 4th Quarter........................................ 17.75 13.13 .10
At February 28, 1997, there were 8,948,840 shares of Common Stock outstanding held by approximately 1,092 shareholders of record and approximately 3,900 beneficial owners. Each share of Common Stock also represents one preferred stock purchase right which entitles the holder thereof to purchase from the Company one-one thousandth of a share (a "Unit") of Series B Preferred Stock of par value $10.00 per share, at an exercise price of $72.00 per Unit. Although the Company does not have a written dividend policy, it has paid cash dividends on the Common Stock for the previous 105 quarters. Dividends on the Common Stock are reviewed by the Board of Directors of the Company each quarter, and no assurances can be given that such cash dividends will continue in the future or, if such dividends are paid, as to the amount of such dividends. In addition, under the terms of the Credit Agreement (as such term is defined in "Management's Discussion and Analysis of Financial Condition and Results of Operations--Liquidity and Capital Resources"), the payment of dividends in any year is limited to the greater of (i) 80% of the Company's adjusted consolidated net income (as defined in the Credit Agreement) for such year (which excludes gains from sales of marketable securities) and (ii) $4.5 million. 27 ITEM 6. SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA The following selected consolidated financial data of the Company are derived from information contained in the Company's consolidated financial statements. The selected consolidated financial and operating data presented below should be read in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations" and the Company's Consolidated Financial Statements and notes thereto included elsewhere in this Report.
YEAR ENDED DECEMBER 31, ------------------------------------------------------- 1996 1995 1994 1993 1992 ---------- ---------- ---------- ---------- ---------- (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS AND RATIOS) INCOME STATEMENT DATA: Revenues: Oil and gas sales..... $ 72,012 $ 54,400 $ 53,559 $ 40,329 $ 37,157 Dividends and interest............. 683 1,241 1,641 1,855 2,000 Marketable security sales gains.......... 12,977 13,101 7,475 -- -- Other................. 1,017 2,939 2,681 737 1,025 ---------- ---------- ---------- ---------- ---------- Total revenues...... 86,689 71,681 65,356 42,921 40,182 ---------- ---------- ---------- ---------- ---------- Costs and expenses: Production and operating............ 23,970 20,690 22,313 17,864 15,083 Purchased natural gas.................. 1,462 727 759 1,182 993 Depreciation, depletion and amortization......... 19,653 19,778 18,313 14,659 13,803 Property impairments.. 12,112 4,893 -- 693 -- Exploration........... 4,176 5,801 4,130 3,639 6,308 General and administrative....... 9,364 8,193 6,502 5,429 4,199 Interest expense...... 5,452 5,618 3,907 530 31 ---------- ---------- ---------- ---------- ---------- Total costs and expenses........... 76,189 65,700 55,924 43,996 40,417 ---------- ---------- ---------- ---------- ---------- Income (loss) before income taxes.......... 10,500 5,981 9,432 (1,075) (235) Income tax expense (benefit)............. 4,072 3,788 444 (2,091) (712) ---------- ---------- ---------- ---------- ---------- Net income............. $ 6,428 $ 2,193 $ 8,988 $ 1,016 $ 477 ========== ========== ========== ========== ========== Average outstanding shares (1)............ 8,954 8,939 8,941 8,939 8,938 Per share data: Net income per share.. $ 0.72 $ 0.25 $ 1.01 $ 0.11 $ 0.05 Cash dividends per share................ $ 0.12 $ 0.40 $ 0.40 $ 0.40 $ 0.40 OTHER FINANCIAL DATA: EBITDAX (2)............ $ 38,233 $ 27,729 $ 26,666 $ 16,591 $ 17,907 Operating cash flow.... 33,228 19,239 23,134 16,777 17,653 Capital expenditures (3)................... 46,231 31,052 73,186 72,321 17,218 BALANCE SHEET DATA (END OF PERIOD): Cash and cash equivalents........... $ 5,870 $ 1,397 $ 2,714 $ 3,499 $ 14,525 Working capital (4).... 3,493 1,034 2,313 6,454 16,401 Marketable securities.. 7,176 19,592 27,337 34,781 3,845 Net property, plant and equipment............. 179,718 169,089 167,371 127,708 75,697 Total assets........... 208,617 203,407 210,791 177,782 102,340 Long-term debt......... 78,654 74,171 78,013 46,777 135 Stockholders' equity... 99,262 101,132 105,427 105,116 87,241
(See footnotes on following pages) 28
YEAR ENDED DECEMBER 31, -------------------------------------------- 1996 1995 1994 1993 1992 -------- -------- -------- -------- -------- RESERVE AND OPERATING DATA: Production volumes: Oil and NGLs (MBbl)............. 2,776 2,332 2,277 1,468 1,298 Natural gas (MMcf)(5)........... 12,288 12,171 11,076 8,296 6,996 Oil equivalents (MBOE)(5)...... 4,824 4,361 4,123 2,851 2,464 Weighted average sales prices(6): Oil (per Bbl)................... $ 18.81 $ 16.91 $ 15.60 $ 16.44 $ 19.07 Natural gas (per Mcf)(5) 1.77 1.37 1.73 2.07 1.95 NGLs (per Bbl).................. 13.36 10.11 9.00 9.42 10.11 Oil equivalents (per BOE)(5)... 14.93 12.47 12.99 14.15 15.08 Selected expenses per BOE(7): Lease operating................. $ 4.14 $ 4.06 $ 4.54 $ 5.80 $ 5.63 Production taxes................ 0.93 0.78 0.97 0.72 0.75 Depreciation, depletion and amortization................... 4.16 4.62 4.53 5.35 5.24 General and administrative...... 1.98 1.92 1.61 1.98 1.78 Proved reserves (end of period)(8): Oil and NGLs (MBbl)............. 31,612 32,208 23,430 21,242 11,756 Natural gas (MMcf).............. 113,377 109,915 107,920 103,317 70,034 Oil equivalents (MBOE)......... 50,508 50,527 41,417 38,462 23,428 Estimated future net revenues before income taxes (in thousands)..................... $705,723 $401,037 $272,776 $241,251 $210,591 Present Value (in thousands).... $414,314 $235,416 $160,804 $137,149 $116,611 Standardized Measure of Discounted Future Net Cash Flows (in thousands)(9)........ $317,180 $194,602 $142,032 $112,423 $ 86,559 Weighted average sales prices (end of period)(8)(10): Oil (per Bbl)................... $ 24.63 $ 18.19 $ 16.11 $ 13.35 $ 17.29 Natural gas (per Mcf)........... $ 3.45 $ 1.84 $ 1.57 $ 2.34 $ 2.36 NGLs (per Bbl).................. $ 19.79 $ 12.87 $ 9.80 $ 9.07 $ 8.04
- -------- (1) Calculated using the treasury stock method. Under this method, average outstanding shares for the year ended December 31, 1996 exclude 864,582 shares issuable pursuant to the Company's stock incentive plans at that date. (2) EBITDAX is not a generally accepted accounting measure, but is presented as a supplemental financial indicator of the Company's ability to service or incur debt. EBITDAX is calculated by adding interest expense, income tax expense, depreciation, depletion and amortization, property impairment costs and exploration costs to net income (excluding marketable security sales gains and dividends and interest). EBITDAX should not be considered in isolation or as a substitute for net income, operating cash flows or any other measure of financial performance prepared in accordance with generally accepted accounting principles or as a measure of the Company's profitability or liquidity. (3) Consist of costs incurred by the Company in connection with its oil and gas acquisition, development and exploration activities, and, in certain years, costs relating to the reconditioning of its gas plants. See Note 6 to the Company's Consolidated Financial Statements included elsewhere in this Report. (4) Working capital represents the difference between current assets and current liabilities. (5) Calculated giving effect to volumes of natural gas purchased for resale as follows: 1996--605 MMcf, 1995--500 MMcf, 1994--469 MMcf, 1993--666 MMcf and 1992--600 MMcf. (6) Reflects results of hedging activities. See "Management's Discussion and Analysis of Financial Condition and Results of Operations--Other Matters." (7) Calculated without giving effect to volumes of natural gas purchased for resale. 29 (8) Estimates of proved reserves and future net revenues from which Present Values are derived are based on year end prices of oil and gas held constant (except to the extent a contract specifically provides otherwise) in accordance with SEC regulations. The prices of oil and gas at December 31, 1996 used to estimate the Company's proved reserves and future net revenues from which Present Values are derived were substantially higher than the prices used in previous years to make such estimates and substantially higher than oil and gas prices at February 28, 1997. (9) The Standardized Measure of Discounted Future Net Cash Flows prepared by the Company represents the present value (using an annual discount rate of 10%) of estimated future net revenues from the production of proved reserves, after giving effect to income taxes. See the Supplemental Financial Information attached to the Company's Consolidated Financial Statements included elsewhere in this Report for additional information regarding the disclosure of the Standardized Measure of Discounted Future Net Cash Flows. (10) Year end prices used to estimate proved reserves and future net revenues from which Present Values are derived. See footnote 8 above. 30 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following discussion is intended to assist in an understanding of the Company's historical financial position and results of operations for each year in the three-year period ended December 31, 1996. The Company's Consolidated Financial Statements and notes thereto included elsewhere in this Report contain detailed information that should be referred to in conjunction with the following discussion. GENERAL The Company's results of operations have been significantly affected by its Maljamar waterflood project, Wellman Unit CO/2/ gas injection project and 1994 acquisition and subsequent development, exploitation and exploration of its Canadian oil and gas properties. The Company has achieved increases in its oil and gas production primarily as a result of these activities. The Company owns certain marketable securities and, in connection with its change in business strategy, has been liquidating portions thereof in order to fund a portion of the Company's capital expenditures. The Company recognized pretax gains from the sale of marketable securities of $13.0 million, $13.1 million and $7.5 million in 1996, 1995 and 1994, respectively. In the absence of such gains, the Company would have reported net losses in 1996 and 1995, and its net income in 1994 would have been reduced. The Company plans to liquidate the remainder of its marketable securities (valued at $7.2 million at December 31, 1996) in 1997. Accordingly, the positive impact that sales of marketable securities have had on the Company's net income is not expected to continue, and sales of marketable securities will no longer be a source of funds, beyond 1997. During 1995, the Company adopted SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of," which requires the Company to assess the need for an impairment of capitalized costs of oil and gas properties on a property-by-property (rather than a company-wide) basis. Applying SFAS No. 121, the Company recognized non-cash property impairment charges of $12.1 million in 1996 and $4.9 million in 1995. The Company's future results of operations and growth are substantially dependent upon (i) its ability to acquire or find and successfully develop additional oil and gas reserves and (ii) the prevailing prices for oil and gas. At December 31, 1996, the Company's proved reserves were comprised of approximately 90% proved developed reserves, and the Company does not have a large inventory of development drilling locations or enhanced recovery projects to pursue after 1997. If the Company is unable to economically acquire or find significant new reserves for development and exploitation, the Company's oil and gas production, and thus its revenues, would likely decline gradually as its reserves are produced. In addition, oil and gas prices are dependent upon numerous factors beyond the Company's control, such as economic, political and regulatory developments and competition from other sources of energy. The oil and gas markets have historically been very volatile, and any significant and extended decline in the price of oil or gas would have a material adverse effect on the Company's financial condition and results of operations, and could result in a reduction in the carrying value of the Company's proved reserves and adversely affect its access to capital. The Company follows the successful efforts method of accounting for oil and gas producing activities. Under this method, the Company capitalizes all costs incurred to acquire interests in oil and gas properties, to drill and equip exploratory wells in which proved reserves are discovered and to drill and equip development wells. Geological and geophysical costs, delay rentals and technical support costs are expensed as incurred. The costs of drilling and equipping exploratory wells in which proved reserves are not discovered are expensed upon a determination that a well does not justify commercial development. The capitalized costs of producing oil and gas properties are depreciated and depleted using the units-of-production method based on estimated proved reserves. Unproved oil and gas properties are periodically assessed for impairment of value, and if an impairment is determined to exist, such impairment is expensed. The successful efforts method of accounting could affect the Company's income from operations depending upon the Company's level of drilling activities and the results of such drilling in any year. 31 RESULTS OF OPERATIONS Production information presented below includes volumes of natural gas purchased for resale; however, per unit of production information with respect to production and operating expenses, depreciation, depletion and amortization and general and administrative costs is calculated without giving effect to such volumes. Such volumes were 605 MMcf in 1996, 500 MMcf in 1995 and 469 MMcf in 1994. Comparison of 1996 to 1995 Income Before Income Taxes and Net Income. Income before income taxes increased 75% to $10.5 million for 1996 from $6.0 million in 1995. Net income increased 191% to $6.4 million in 1996 from $2.2 million in 1995. The improvement in income before income taxes and net income was attributable primarily to higher production and higher net realized prices during 1996. Production. The Company's net oil production rose 17% to 2,425 MBbls in 1996 from 2,080 MBbls in 1995. Net natural gas production increased 1% to 12,288 MMcf in 1996 from 12,171 MMcf in 1995. On an equivalent unit basis, net production increased 11% to 4,824 MBOE in 1996 from 4,361 MBOE in 1995. The increase in production was primarily attributable to development activities which resulted in the addition of 102 net producing wells in 1996. Revenues. Total revenues increased 21% to $86.7 million in 1996 from $71.7 million in 1995, primarily because of higher production and higher net realized prices during 1996. Average net realized oil prices rose 11% to $18.81 per Bbl in 1996 from $16.91 per Bbl in 1995. Average net realized natural gas prices rose 29% to $1.77 per Mcf in 1996 from $1.37 per Mcf in 1995. Average net realized NGL prices rose 32% to $13.36 per Bbl in 1996 from $10.11 per Bbl in 1995. The average net realized oil, gas and NGL prices received in 1996 of $18.81 per Bbl, $1.77 per Mcf and $13.36 per Bbl, respectively, compared to average prices of $20.86 per Bbl, $1.92 per Mcf and $13.64 per Bbl, respectively, which would have been received before the effects of the Company's hedging activities, which activities resulted in a reduction of $6.9 million in the Company's oil and gas sales for 1996. Effects of hedging activities were not significant in 1995. Dividends and interest decreased 42% to $0.7 million in 1996 from $1.2 million in 1995, primarily as a result of sales of marketable securities in 1996 and 1995. The Company recognized a pretax gain of $13.0 million from marketable security sales in 1996, compared with a pretax gain of $13.1 million from similar sales in 1995. Other revenues of the Company decreased 66% to $1.0 million in 1996 from $2.9 million in 1995, primarily as a result of fewer sales of non-strategic properties in 1996. Production and Operating Expenses. Production and operating expenses increased 16% to $24.0 million in 1996 from $20.7 million in 1995, primarily due to higher production taxes resulting from higher revenues from sales of oil and gas. On an equivalent unit of production basis, such expenses increased 5% to $5.07 per BOE in 1996 from $4.84 per BOE in 1995. Depreciation, Depletion and Amortization ("DD&A"). DD&A decreased 1% to $19.7 million in 1996 from $19.8 million in 1995. The DD&A rate per BOE decreased 10% to $4.16 in 1996 from $4.62 in 1995. The decrease in the DD&A rate per BOE in 1996 was due primarily to upward revisions of previous estimates of the Company's proved reserves attributable to certain of its properties in the Permian Basin and Canada during 1996, while capitalized costs relating to such properties remained relatively constant. Property Impairment Charges. The Company recognized non-cash property impairment charges of $12.1 million in 1996 and $4.9 million in 1995 as a result of applying the provisions of SFAS No. 121. The impairment charge for 1996 resulted from a downward revision of previous estimates of the Company's proved reserves attributable to certain of its properties in Michigan and Canada. The impairment charge for 1995 resulted from a downward revision of previous estimates of the Company's proved reserves attributable to certain of its Canadian properties. 32 Exploration Costs. Exploration costs decreased 28% to $4.2 million in 1996 from $5.8 million in 1995, primarily as a result of a temporary reduction by the Company in its 1996 domestic exploration activities due to a redirection of its exploration program in the fourth quarter of 1996. General and Administrative Costs. General and administrative costs increased 15% to $9.4 million in 1996 from $8.2 million in 1995, primarily as a result of higher compensation costs and professional fees relating to acquisition and tax matters. On an equivalent unit of production basis, general and administrative costs increased 3% to $1.98 per BOE in 1996 from $1.92 per BOE in 1995. Interest Expense. Interest expense decreased 2% to $5.5 million in 1996 from $5.6 million in 1995. Effective Tax Rate. The Company's effective tax rate decreased to 39% in 1996 from 63% in 1995. This decrease was due primarily to a decrease in 1996 in the amount of tax loss attributable to the Company's Canadian operations that was not deductible for purposes of United States federal income taxes. In addition, the Company's Internal Revenue Code Section 29 income tax credits relating to its San Juan Basin properties increased 15% to $1.5 million in 1996 from $1.3 million in 1995. Comparison of 1995 to 1994 Income Before Income Taxes and Net Income. Income before income taxes decreased 36% to $6.0 million in 1995 from $9.4 million in 1994. Net income decreased 76% to $2.2 million in 1995 from $9.0 million in 1994. The decrease in income before income taxes was due primarily to a non-cash property impairment charge of $4.9 million against 1995 income, all of which related to impairments of certain of Wiser's Canadian properties, compared with no such charge in 1994. The decrease in net income was due primarily to (i) such property impairment charge and (ii) an increase in income tax expense to $3.8 million in 1995 from $0.4 million in 1994, due principally to a decrease in the deferred tax asset valuation reserve in 1994 which did not occur in 1995. The property impairment charge and the increase in income tax expense in 1995 were partially offset by a pretax gain of $13.1 million from the sale by the Company of a portion of its marketable securities portfolio in 1995, compared with a pretax gain of $7.5 million from similar sales in 1994. Production. Net oil production decreased 1% to 2,080 MBbls in 1995 from 2,104 MBbls in 1994, while net natural gas production increased 10% to 12,171 MMcf in 1995 from 11,076 MMcf in 1994. The Company's total net equivalent production increased 6% to 4,361 MBOE in 1995 from 4,123 MBOE in 1994, primarily as a result of 34 net producing wells completed in 1995. Revenues. Total revenues increased 10% to $71.7 million in 1995 from $65.4 million in 1994, primarily because of an increase of $5.6 million in pretax gains from the sale by the Company of marketable securities in 1995 compared with pretax gains from similar sales in 1994. Oil and gas revenues for 1995 remained relatively constant, increasing 1% to $54.4 million in 1995 from $53.6 million in 1994. This increase was due primarily to higher production in 1995, partially offset by a 4% decrease in 1995 in average net realized prices on an oil equivalent basis. Average net realized oil prices rose 8% to $16.91 per Bbl in 1995 from $15.60 per Bbl in 1994, while average net realized natural gas prices declined 21% to $1.37 per Mcf in 1995 from $1.73 per Mcf in 1994. Average net realized NGL prices rose 12% to $10.11 per Bbl in 1995 from $9.00 per Bbl in 1994. Production and Operating Expenses. Production and operating expenses decreased 7% to $20.7 million in 1995 from $22.3 million in 1994, primarily as a result of sales by the Company of non-strategic properties in late 1994. On an equivalent unit of production basis, such expenses decreased 12% to $4.84 per BOE in 1995 from $5.51 per BOE in 1994. Depreciation, Depletion and Amortization. DD&A increased 8% to $19.8 million in 1995 from $18.3 million in 1994, primarily as a result of an additional $4.8 million in DD&A attributable to a full year of ownership of the Company's Canadian properties in 1995, partially offset by a decrease of $3.2 million in DD&A due to sales by the Company in late 1994 of certain non-strategic properties with high DD&A rates. The DD&A rate per BOE increased 2% to $4.62 in 1995 from $4.53 in 1994. 33 Exploration Costs. Exploration costs increased 41% to $5.8 million in 1995 from $4.1 million in 1994, primarily as a result of higher dry hole costs in 1995. General and Administrative Costs. General and administrative costs increased 26% to $8.2 million in 1995 from $6.5 million in 1994. Of this increase, $1.0 million was due to the inclusion in 1995 operating results of a full year of Canadian operations and $0.7 million was attributable to higher legal expenses. On an equivalent unit of production basis, general and administrative costs increased 19% to $1.92 per BOE in 1995 from $1.61 per BOE in 1994. Interest Expense. Interest expense increased 44% to $5.6 million in 1995 from $3.9 million in 1994. This increase was due primarily to the inclusion in 1995 operating results of a full year's interest expense related to the $52.0 million of bank debt incurred in connection with the Company's purchase of its Canadian properties in 1994. Effective Tax Rate. The Company's effective tax rate increased to 63% in 1995 from 5% in 1994. The increase was due primarily to an increase in net operating losses attributable to the Company's Canadian operations for which no current U.S. federal income tax benefit was available and benefits realized in 1994 from the recognition of previously reserved deferred tax assets which were not available in 1995. LIQUIDITY AND CAPITAL RESOURCES General Working capital at December 31, 1996 was $3.5 million, representing a $2.5 million increase over the corresponding amount at December 31, 1995. At December 31, 1996, the Company had $5.9 million in cash and cash equivalents and $208.6 million of total assets. During 1996, long-term debt rose to $78.7 million from $74.2 million in 1995. At December 31, 1996, capitalization totaled $177.9 million, of which approximately 56% was represented by stockholders' equity and 44% by long-term debt. At that date, approximately $58.0 million of the long-term debt was comprised of borrowings under the Credit Agreement, and the remaining $20.7 million was comprised of indebtedness under the Maljamar Credit Facility. See Note 3 to the Company's Consolidated Financial Statements included elsewhere in this Report. Capital Sources Funding for the Company's business activities has been provided by cash flow from operations, bank financing and sales of marketable securities. The Company anticipates liquidating the remainder of its marketable securities during 1997. Accordingly, this source of funds is not expected to be available after 1997. While the Company regularly engages in discussions relating to potential acquisitions of oil and gas properties (some of which may be material to the Company), the Company has no current agreement or commitment with respect to any such acquisition, other than relatively minor acquisitions of oil and gas properties and interests in its normal course of business. Any future acquisitions may require additional financing and will be dependent upon financing arrangements available at the time. The Company believes that funds provided by internally generated cash flows, including the sale of its remaining marketable securities, will be sufficient to meet anticipated operating and capital expenditure requirements (excluding any property acquisitions) in 1997. If the Company's internally generated cash flows are less than anticipated or its capital needs are greater than anticipated, the Company may borrow funds under the Credit Agreement (as defined below). If the Company's cash flow from operations and the availability under the Credit Agreement are not sufficient to satisfy its cash requirements, there can be no assurance that additional equity or debt financing will be available to meet such requirements. 34 Long-Term Debt On June 23, 1994, the Company entered into a credit agreement with NationsBank of Texas, N.A. as agent (the "Credit Agreement") which currently provides for a term loan to the Company's Canadian subsidiary and a revolving credit facility to the Company. At December 31, 1996, the outstanding principal balance of indebtedness under the Credit Agreement was $58.0 million, all of which was bearing interest at 6.31% per annum. These borrowings were used by the Company to finance property acquisitions and for other general corporate purposes. The average interest rate paid by the Company on borrowings under the Credit Agreement during 1996 was 6.04% per annum. On November 29, 1995, the Company entered into a credit agreement with NationsBank of Texas, N.A. as agent (the "Maljamar Credit Facility"). The Maljamar Credit Facility provides the Company with up to a $50.0 million nonrecourse facility to develop the Maljamar project area. At December 31, 1996, indebtedness under the Maljamar Credit Facility was approximately $20.7 million. The average interest rate paid by the Company on borrowings under the Maljamar Credit Facility during 1996 was 7.5% per annum. See Note 3 to the Company's Consolidated Financial Statements included elsewhere in this Report for additional information regarding the Credit Agreement and the Maljamar Credit Facility. Cash Flow Analysis Cash Flows from Operating Activities. Cash flows from operating activities were $33.2 million in 1996, $19.2 million in 1995 and $23.1 million in 1994. The increase in cash flows from operating activities for 1996 was due primarily to higher production and higher net realized prices in 1996. The decrease in cash flows for 1995 compared to 1994 was due primarily to higher interest expense and income taxes paid in 1995. Cash Flows from Investing Activities. Cash flows used in investing activities increased to $31.0 million in 1996 from $13.1 million in 1995. This increase was caused primarily by an increase in capital expenditures. Capital expenditures were $46.2 million in 1996 compared with $31.1 million in 1995. Cash flows used in investing activities decreased to $13.1 million in 1995 from $51.6 million in 1994. Cash flows used in investing activities in 1994 included $52.0 million for the acquisition by the Company of Canadian oil and gas properties in June 1994. Cash flows from investing activities in 1996, 1995 and 1994 included $14.0 million, $14.5 million and $8.3 million, respectively, in proceeds from marketable security sales. At December 31, 1996, the Company's marketable securities portfolio had been reduced to $7.2 million in value. The Company anticipates liquidating the remainder of its marketable securities during 1997. Cash Flows from Financing Activities. Cash flows from financing activities were $2.2 million in 1996 compared to $7.5 million used in financing activities in 1995. During 1996, the Company increased its total long-term debt by $4.5 million in connection with financing development activities in the Maljamar area. The Company also reduced its cash dividends to $1.1 million in 1996 from $3.6 million in 1995. During 1995, the Company reduced its total long-term debt by $3.8 million. Cash flows used in financing activities were $7.5 million in 1995 compared with $27.7 million in cash flows from financing activities in 1994. During 1994, total long-term debt increased $31.2 million as a result of financing the acquisition of the Canadian oil and gas properties. Capital Expenditures The Company requires capital primarily for the acquisition, development and exploitation of, and the exploration for, oil and gas properties, the repayment of indebtedness and general working capital needs. Capital expenditures of the Company increased approximately 49% to $46.2 million in 1996 from $31.1 million in 1995, primarily as a result of an increase in capital expenditures related to the Company's Maljamar waterflood project. Capital expenditures decreased approximately 58% to $31.1 million in 1995 from $73.2 million in 1994. Capital expenditures in 1994 included $52.0 million for the purchase of certain Canadian oil and gas properties in June 1994. Excluding the 1994 Canadian acquisition, capital expenditures increased approximately 47% to $31.1 million in 1995 from $21.2 million in 1994. The increase reflected a full year of 35 capital expenditures in Canada, the completion of modifications to a gas processing plant at the Company's Wellman Unit and an increase in capital expenditures related to the Company's Maljamar waterflood project. During 1997, subject to market conditions and drilling and operating results, the Company expects to spend approximately $44.3 million on development, exploitation and exploration activities. Of this amount, the Company has budgeted $31.3 million for development and exploitation activities and $13.0 million for exploration activities. OTHER MATTERS Hedging Activities The Company has entered into and may in the future enter into hedging arrangements with respect to portions of its oil, natural gas and NGL production to reduce its sensitivity to volatile commodity prices. The Company believes that hedging, although not free of risk, allows the Company to achieve a more predictable cash flow and to reduce exposure to price fluctuations. However, hedging arrangements limit the benefit to the Company of increases in the prices of the hedged commodity. Moreover, the Company's hedging arrangements apply only to a portion of its production and provide only partial price protection against declines in prices. Such arrangements may expose the Company to risk of financial loss in certain circumstances. The Company adjusts the price received for the hedged production during the period the hedged transactions occur. Adjustments to oil and gas sales from the Company's hedging activities resulted in a reduction of $6.9 million in the Company's revenues for the year ended December 31, 1996. Hedging activities in 1995 and 1994 did not result in any material increase or decrease in oil and gas revenues. The Company expects that the amount of production it hedges will vary from time to time. The Company continuously reevaluates its hedging program in light of market conditions, commodity price forecasts, capital spending and debt service requirements. At December 31, 1996, approximately 41% of the Company's total expected oil production through December 1997 was hedged under collar arrangements as follows:
DAILY VOLUME FLOOR PRICE CEILING PRICE BEGINNING DATE ENDING DATE (BBLS) (PER BBL) (PER BBL) -------------- ----------- ------------ ----------- ------------- January 1, 1997 December 31, 1997 1,000 $16.00 $18.85 January 1, 1997 December 31, 1997 1,000 21.80(1) 25.55(1) January 1, 1997 March 31, 1997 2,000 16.00 19.41 April 1, 1997 June 30, 1997 2,000 17.00 19.00 July 1, 1997 September 30, 1997 2,000 17.00 19.00
- -------- (1) Canadian dollars. At December 31, 1996, approximately 40% of the Company's total expected NGL production from January 1 through March 31, 1997 was hedged at a weighted average swap price of $18.76 per Bbl. See Note 1 to the Company's Consolidated Financial Statements included elsewhere in this Report. Effects of Fluctuations in Exchange Rates The Company receives a substantial portion of its revenue in Canadian dollars. As a result, fluctuations in the exchange rates of the Canadian dollar with respect to the U.S. dollar could have an adverse effect on the Company's financial condition and results of operations. Historically, exchange rate fluctuations have not been material to the Company. Environmental and Other Regulatory Matters The Company's business is subject to certain federal, state, provincial and local laws and regulations relating to the development, exploitation, production and gathering of, and the exploration for, oil and gas, 36 including those relating to the protection of the environment. Many of these laws and regulations have become more stringent in recent years, often imposing greater liability on a larger number of potentially responsible parties. Although the Company believes it is in substantial compliance with all applicable laws and regulations, the requirements imposed by laws and regulations are frequently changed and subject to interpretation, and the Company is unable to predict the ultimate cost of compliance with these requirements or their effect on its operations. Although significant expenditures may be required to comply with governmental laws and regulations applicable to the Company, compliance has not had a material adverse effect on the earnings or competitive position of the Company. DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS This Report includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements other than statements of historical facts included in this Report, including without limitation statements in this "Management's Discussion and Analysis of Financial Condition and Results of Operations" and under "Business" and "Properties" regarding proved reserves, estimated future net revenues, Present Values, planned capital expenditures (including the amount and nature thereof), increases in oil and gas production, the number of wells anticipated to be drilled in 1997 and thereafter and the Company's financial position, business strategy and other plans and objectives for future operations, are forward-looking statements. Although the Company believes that the expectations reflected in such forward- looking statements are reasonable, there can be no assurance that the actual results or developments anticipated by the Company will be realized or, even if substantially realized, that they will have the expected consequences to or effects on its business or operations. Among the factors that could cause actual results to differ materially from the Company's expectations are the volatility of oil and gas prices, the ability to acquire or find and successfully develop additional oil and gas reserves, the uncertainty of estimates of reserves and future net revenues, risks relating to acquisitions of producing properties, drilling and operating risks, general economic conditions, competition, domestic and foreign government regulations and other factors which are beyond the Company's control. All subsequent written and oral forward-looking statements attributable to the Company or persons acting on its behalf are expressly qualified in their entirety by such factors. The Company assumes no obligation to update any such forward-looking statements. 37 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA The Report of Independent Accountants, Consolidated Financial Statements and supplementary financial data required by this Item are set forth on pages F-1 through F-20 of this Report and are incorporated herein by reference. ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURES Not applicable. PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT The information required by this Item will be contained in the Proxy Statement under the headings "Election of Directors" and "Executive Officers" and is incorporated herein by reference. ITEM 11. EXECUTIVE COMPENSATION The information required by this Item will be contained in the Proxy Statement under the heading "Executive Compensation" and is incorporated herein by reference. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT The information required by this Item will be contained in the Proxy Statement under the heading "Beneficial Ownership of Common Stock" and is incorporated herein by reference. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS The information required by this Item, if any, will be contained in the Proxy Statement under the heading "Executive Compensation" and is incorporated herein by reference. 38 PART IV ITEM 14 EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K A. FINANCIAL STATEMENTS The following documents are filed as part of this Report: 1. Report of Independent Accountants Consolidated Statements of Income and Retained Earnings Consolidated Balance Sheets Consolidated Statements of Cash Flows Notes to Consolidated Financial Statements 2. Schedules are omitted because of the absence of conditions under which they are required or because the required information is given in the financial statements or notes thereto. B. NO REPORTS ON FORM 8-K WERE FILED DURING THE LAST QUARTER OF THE YEAR COVERED BY THIS ANNUAL REPORT. C. EXHIBITS
EXHIBIT NUMBERS ------- (3.1) Certificate of Incorporation, as amended, incorporated by reference to Exhibit 4.2 to the Company's report on Form 8-K (Commission File No. 0-5426), dated November 9, 1993 (Date of Event: October 25, 1993). (3.2) Bylaws of the Company, as amended, incorporated by reference to Exhibit 4.3 to the Company's report on Form 8-K (Commission File No. 0-5426), dated November 9, 1993 (Date of Event: October 25, 1993). (4) Rights Agreement dated as of October 25, 1993 by and between the Company and The Chase Manhattan Bank (as successor to Chemical Bank, as Rights Agent, which includes as Exhibit 2 thereto the Form of Rights Certificate, incorporated by reference to Exhibit 4.1 to the Company's report on Form 8-K (Commission File No. 0-5426), dated November 9, 1993 (Date of Event: October 25, 1993). (10.1) Credit Agreement dated June 23, 1994 among The Wiser Oil Company and The Wiser Oil Company of Canada, as Borrowers, and Nations Bank of Texas, N.A., as Agent, and Certain Financial Institutions Listed on the Signature Pages Thereto, as Banks, incorporated by reference to the Exhibit 10.1 to the report on Form 8-K dated July 11, 1994 as amended August 17, 1994. (10.2) Credit Agreement dated November 29, 1995 among The Wiser Oil Company and Maljamar Development Partnership, L.P. as Borrowers, and Nations Bank of Texas, N.A., as Agent, and Certain Financial Institutions Listed on the Signature Pages thereto, as Banks. (10.3) Purchase and Sale Agreements made as of May 31, 1994 among Eagle Resources Ltd., Caneagle Resources Corporation, The Erin Mills Investment Corporation and The Wiser Oil Company, incorporated by reference to Exhibit 10 to the report on Form 8-K dated July 11, 1994 as amended August 17, 1994. (10.4)* Employment Agreement dated August 1, 1994 between the Company and Allen J. Simus, incorporated by reference to Exhibit 10(d) to the Company's Annual Report on Form 10-K for the year ended December 31, 1994. (10.5)* Employment Agreement dated July 1, 1991 between the Company and Andrew J. Shoup, Jr., incorporated by reference to Exhibit 10(a) to the Company's Annual Report on Form 10-K for the year ended December 31, 1993.
39
(10.6)* The Wiser Oil Company 1991 Stock Incentive Plan, as amended, incorporated by reference to Exhibit 4.1 to the Company's Registration Statement on Form S-8 (Commission File No. 33-62441), filed on September 8, 1995. (10.7)* The Wiser Oil Company 1991 Non-employee Directors' Stock Option Plan, as amended, incorporated by reference to Exhibit 99.1 to the Company's Registration Statement on Form S-8 (Commission File No. 333-22525), filed on February 28, 1997. (10.8)* Employment Agreement dated November 1, 1993 between the Company and Lawrence J. Finn, incorporated by reference to Exhibit 10(b) to the Company's Annual Report on Form 10-K for the year ended December 31, 1993. (10.9)* Employment Agreement dated January 24, 1994 between the Company and A. Wayne Ritter, incorporated by reference to Exhibit 10(c) to the Company's Annual Report on Form 10-K for the year ended December 31, 1993. (10.10)*+ Employment Agreement dated September 30, 1996 between the Company and Kent E. Johnson. (10.11)*+ The Wiser Oil Company Equity Compensation Plan For Non-Employee Directors. (21)+ Subsidiaries of registrant (23.1)+ Consent of Independent Public Accountants (23.2)+ Consent of DeGolyer and MacNaugton, Independent Petroleum Engineers (23.3)+ Consent of Gilbert Lausten Jung Associates Ltd., Independent Petroleum Engineers (27)+ Financial Data Schedule
- -------- * The documents filed or incorporated by reference as Exhibits 10.4, 10.5, 10.6, 10.7, 10.8 and 10.9, 10.10 and 10.11 represent management compensatory plans or agreements. + Filed herewith 40 PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED ON ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED, ON THE 26TH DAY OF MARCH 1997. The Wiser Oil Company /s/ Andrew J. Shoup, Jr. By: _________________________________ ANDREW J. SHOUP, JR. PRESIDENT AND CHIEF EXECUTIVE OFFICER PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS REPORT IS SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE REGISTRANT AND IN THE CAPACITIES AND ON THE DATES INDICATED. THE SIGNATURES BELOW ARE FOR THE FORM 10-K ANNUAL REPORT FOR CALENDAR YEAR 1994. SIGNATURE TITLE DATE /s/ Andrew J. Shoup, Jr. President, Chief March 26, 1997 - ------------------------------------- Executive Officer and Director (Principal Executive Officer) /s/ Paul D. Neuenschwander Director March 26, 1997 - ------------------------------------- /s/ C. Frayer Kimball, III Director March 26, 1997 - ------------------------------------- /s/ Howard G. Hamilton Director March 26, 1997 - ------------------------------------- /s/ A. W. Schenck, III Director March 26, 1997 - ------------------------------------- /s/ John W. Cushing, III Director March 26, 1997 - ------------------------------------- /s/ Jon L. Mosle, Jr. Director March 26, 1997 - ------------------------------------- /s/ Lorne H. Larson Director March 26, 1997 - ------------------------------------- /s/ Lawrence J. Finn Vice President and March 26, 1997 - ------------------------------------- Chief Financial Officer (Principal Financial and Accounting Officer) 41 THE WISER OIL COMPANY INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
PAGE ---- Report of Independent Public Accountants................................... F-2 Consolidated Statements of Income and Retained Earnings.................... F-3 Consolidated Balance Sheets................................................ F-4 Consolidated Statements of Cash Flows...................................... F-5 Notes to Consolidated Financial Statements................................. F-6
F-1 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Shareholders of The Wiser Oil Company: We have audited the accompanying consolidated balance sheets of The Wiser Oil Company (a Delaware corporation) and subsidiaries as of December 31, 1996, 1995 and 1994 and the related consolidated statements of income and retained earnings and cash flows for the years then ended. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of The Wiser Oil Company and subsidiaries as of December 31, 1996, 1995 and 1994 and the results of their operations and their cash flows in conformity with generally accepted accounting principles. As discussed in Note 1 to the consolidated financial statements, during 1995, the Company changed its method of accounting for the impairment of long- lived assets. ARTHUR ANDERSEN LLP Dallas, Texas, February 18, 1997 F-2 THE WISER OIL COMPANY CONSOLIDATED STATEMENTS OF INCOME AND RETAINED EARNINGS FOR THE YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994
1996 1995 1994 --------- --------- --------- (000'S EXCEPT PER SHARE DATA) Revenues: Oil and gas sales............................ $72,012 $54,400 $53,559 Dividends and interest....................... 683 1,241 1,641 Marketable security sales gains.............. 12,977 13,101 7,475 Other........................................ 1,017 2,939 2,681 --------- --------- --------- 86,689 71,681 65,356 --------- --------- --------- Costs and Expenses: Production and operating..................... 23,970 20,690 22,313 Purchased natural gas........................ 1,462 727 759 Depreciation, depletion and amortization..... 19,653 19,778 18,313 Property impairments......................... 12,112 4,893 -- Exploration.................................. 4,176 5,801 4,130 General and administrative................... 9,364 8,193 6,502 Interest expense............................. 5,452 5,618 3,907 --------- --------- --------- 76,189 65,700 55,924 --------- --------- --------- Income Before Income Taxes..................... 10,500 5,981 9,432 Income Tax Expense............................. 4,072 3,788 444 --------- --------- --------- NET INCOME..................................... 6,428 2,193 8,988 Retained Earnings, beginning of year........... 61,030 62,414 57,002 Dividends Paid................................. (1,073) (3,577) (3,576) --------- --------- --------- Retained Earnings, end of year................. $ 66,385 $ 61,030 $ 62,414 ========= ========= ========= Average Outstanding Shares..................... 8,954 8,939 8,941 ========= ========= ========= Earnings Per Share............................. $ .72 $ .25 $ 1.01 ========= ========= ========= Cash Dividends Per Share....................... $ .12 $ .40 $ .40 ========= ========= =========
The accompanying notes are an integral part of these financial statements. F-3 THE WISER OIL COMPANY CONSOLIDATED BALANCE SHEETS DECEMBER 31, 1996, 1995 AND 1994
1996 1995 1994 --------- --------- -------- (000'S) ASSETS Current Assets: Cash and cash equivalents.................... $ 5,870 $ 1,397 $ 2,714 Accounts receivable.......................... 14,091 10,426 10,900 Inventories.................................. 1,289 1,517 1,144 Prepaid expenses............................. 473 833 852 --------- --------- -------- Total current assets....................... 21,723 14,173 15,610 --------- --------- -------- Marketable Securities.......................... 7,176 19,592 27,337 Property, Plant and Equipment, at cost: Oil and gas properties (successful efforts method)..................................... 306,716 265,692 250,156 Other properties............................. 4,974 4,422 5,443 --------- --------- -------- 311,690 270,114 255,599 Accumulated depreciation and depletion....... (131,972) (101,025) (88,228) --------- --------- -------- Net Property, Plant and Equipment.............. 179,718 169,089 167,371 Other Assets................................... -- 553 473 --------- --------- -------- $ 208,617 $ 203,407 $210,791 ========= ========= ======== LIABILITIES AND STOCKHOLDERS' EQUITY Current Liabilities: Accounts payable............................. $ 14,996 $ 10,143 $ 9,562 Accrued income taxes......................... 1,697 1,527 1,518 Accrued liabilities.......................... 1,537 1,449 2,139 Current portion of long term debt............ -- 20 78 --------- --------- -------- Total current liabilities.................. 18,230 13,139 13,297 --------- --------- -------- Long Term Debt................................. 78,654 74,171 78,013 Deferred Benefit Cost.......................... 1,496 1,120 1,052 Deferred Income Taxes.......................... 10,975 12,699 13,002 Other Long Term Liabilities.................... -- 1,146 -- Stockholders' Equity: Common stock--$3 par value 20,000,000 shares authorized; 9,115,572 shares issued; 8,939,368 shares outstanding................ 27,347 27,347 27,347 Paid-in capital.............................. 3,078 3,078 3,078 Retained earnings............................ 66,385 61,030 62,414 Marketable securities valuation adjustment... 4,328 11,684 16,013 Foreign currency translation................. 853 722 (696) Treasury stock; 176,204 shares, at cost at December 31, 1996, 1995 and 1994............ (2,729) (2,729) (2,729) --------- --------- -------- Total stockholders' equity................. 99,262 101,132 105,427 --------- --------- -------- $ 208,617 $ 203,407 $210,791 ========= ========= ========
The accompanying notes are an integral part of these financial statements. F-4 THE WISER OIL COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994
1996 1995 1994 -------- -------- -------- (000'S) Cash Flows From Operating Activities: Net income...................................... $ 6,428 $ 2,193 $ 8,988 Adjustments to reconcile net income to operating cash flows: Depreciation, depletion and amortization...... 19,653 19,778 18,313 Deferred income taxes......................... 2,056 1,914 (1,145) Marketable securities & property sale gains... (13,099) (14,092) (9,367) Foreign currency translation.................. (2) (34) 87 Property impairments and abandonments......... 15,229 9,392 2,930 Other Changes-- Accounts receivable......................... (3,665) 474 (1,473) Inventories................................. 228 (373) (344) Prepaid expenses............................ 360 19 (204) Other assets................................ 553 (80) 11 Accounts payable............................ 4,853 661 3,438 Accrued income taxes........................ 170 9 1,516 Accrued liabilities......................... 88 (690) 424 Deferred benefits cost...................... 376 68 (40) -------- -------- -------- Operating Cash Flows...................... 33,228 19,239 23,134 -------- -------- -------- Cash Flows From Investing Activities: Additions to property, plant and equipment.... (46,056) (28,851) (73,410) Proceeds from sales of property, plant and equipment.................................... 1,022 1,280 13,581 Proceeds from marketable security sales....... 14,035 14,492 8,250 -------- -------- -------- Investing Cash Flows........................ (30,999) (13,079) (51,579) -------- -------- -------- Cash Flows From Financing Activities: Long term debt issued......................... 25,508 11,170 55,600 Payments on long term debt and other liabili- ties......................................... (22,191) (15,070) (24,364) Dividends paid................................ (1,073) (3,577) (3,576) -------- -------- -------- Financing Cash Flows........................ 2,244 (7,477) 27,660 -------- -------- -------- Net Increase (Decrease) In Cash................. 4,473 (1,317) (785) Cash and Cash Equivalents, beginning of year.... 1,397 2,714 3,499 -------- -------- -------- Cash and Cash Equivalents, end of year.......... $ 5,870 $ 1,397 $ 2,714 ======== ======== ========
The accompanying notes are an integral part of these financial statements. F-5 THE WISER OIL COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1996, 1995 AND 1994 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES a. Principles of Consolidation--The consolidated financial statements include the accounts of The Wiser Oil Company (Company), a Delaware corporation, and its wholly owned subsidiaries: T.W.O.C., Inc., The Wiser Marketing Company, Maljamar Wiser Inc., Maljamar Development Partnership, L.P., and The Wiser Oil Company of Canada (Wiser Canada). T.W.O.C., Inc. is a Delaware holding company responsible for the management of investment activities. The Wiser Marketing Company functions as a natural gas marketer and broker. Maljamar Wiser Inc. was formed in 1995 and is a wholly owned subsidiary of the Company. It was formed in order for the Company to fund its $53,000,000 development of the Maljamar area with the use of nonrecourse debt. The Maljamar Development Partnership, L.P. was formed in 1995 for the same reason. The Company is the limited partner of the Maljamar Development Partnership, L.P. and owns 99% of the partnership. Maljamar Wiser Inc. owns 1% of the Maljamar Development Partnership, L.P. as a general partner. Wiser Canada was formed in 1994 to conduct the Company's Canadian activities. Prior to the formation of Wiser Canada, the Company's oil and gas operations were conducted primarily in the United States. Intercompany accounts and transactions have been eliminated. Certain reclassifications have been made to conform prior years' amounts to current presentation. b. Risks and Uncertainties--The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. c. Oil and Gas Properties--The Company is engaged in the exploration and development of oil and gas in the United States and Canada. The Company follows the "successful efforts" method of accounting for its oil and gas properties. Under this method of accounting, all costs of property acquisitions and exploratory wells are initially capitalized. If an exploratory well is unsuccessful, the capitalized costs of drilling the well, net of any salvage value, are charged to expense. The capitalized costs of unproven properties are periodically assessed to determine whether their value has been impaired, and if such impairment is indicated, a loss is recognized. Geological and geophysical costs and the costs of retaining undeveloped properties are expensed as incurred. Expenditures for maintenance and repairs are charged to expense, and renewals and betterments are capitalized. Upon disposal, the asset and related accumulated depreciation, depletion and amortization are removed from the accounts, and any resulting gain or loss is reflected currently in income. Prior to 1995, the Company evaluated the carrying value of its oil and gas properties based on undiscounted future net revenues on a company wide basis. During 1995, the Company adopted Statement of Financial Accounting Standards ("SFAS") No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of". SFAS No. 121 requires the Company to assess the need for an impairment of capitalized costs of oil and gas properties on a property-by-property basis. If an impairment is indicated based on undiscounted expected future cash flows, then an impairment is recognized to the extent that net capitalized costs exceed discounted future cash flows. During 1996 and 1995, the Company provided impairments of $12,112,000 and $4,893,000, respectively. Management's estimate of future cash flows is based on their estimate of reserves and prices. It is reasonably possible that a change in reserve or price estimates could occur in the near term and adversely impact management's estimate of future cash flows and consequently the carrying value of properties. F-6 THE WISER OIL COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) DECEMBER 31, 1996, 1995 AND 1994 d. Depreciation and Depletion--Depreciation and depletion of the capitalized costs of producing oil and gas properties are computed for individual properties using the units-of-production method based on total proved reserves. Depreciation of transportation, office and other properties is computed generally using the straight-line method over the estimated useful lives of these assets. e. Cash and Cash Equivalents--Cash equivalents generally consist of short- term investments maturing in three months or less from the date of acquisition. These investments of $3,801,000 in 1996, $504,000 in 1995 and $1,662,000 in 1994 are recorded at cost plus accrued interest, which approximates market. f. Inventories--Oil and gas product inventories are recorded at the average cost of production. Materials and supplies are recorded at the lower of average cost or market. g. Accrued Liabilities--Accrued liabilities include accrued vacation and payroll of $576,000 in 1996, $535,000 in 1995 and $519,000 in 1994. h. Postretirement Benefits--SFAS No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions", has no significant impact on the Company. The Company has no significant liabilities for postretirement benefits, other than pensions, and has historically recognized such liabilities as they are incurred. i. Gas Imbalances--Gas imbalances are accounted for using the sales method. The Company's net imbalance position is not material at December 31, 1996, 1995 and 1994. j. Hedging Arrangements--During 1995 and 1996, the Company entered into numerous oil price collar agreements to hedge against price fluctuations during 1997. The Company is exposed to losses in the event of nonperformance by the counter parties to its hedging agreements. These arrangements are summarized as follows:
DAILY VOLUME FLOOR PRICE CEILING PRICE BEGINNING DATES ENDING DATE (BBLS) (PER BBL) (PER BBL) - --------------- ----------- ------------ ----------- ------------- January 1, 1997 December 31, 1997 1,000 $16.00 $18.85 January 1, 1997 December 31, 1997 1,000 21.80(1) 25.55(1) January 1, 1997 March 31, 1997 2,000 16.00 19.41 April 1, 1997 June 30, 1997 2,000 17.00 19.00 July 1, 1997 September 30, 1997 2,000 17.00 19.00
- -------- (1)Canadian Dollars In addition, the Company has hedged 367 barrels per day of natural gas liquids production from January 1, 1997 to March 31, 1997 at a weighted average price of $18.76 per barrel. Gains or losses from hedging transactions are recognized as oil and gas sales in the accompanying Consolidated Statements of Income and Retained Earnings as the underlying hedged production is sold. As of December 31, 1994, the Company had deferred $135,017 in net gains related to hedging activities. As of December 31, 1996 and 1995, the Company had no deferred net gains or net losses related to hedging activities. During 1996, revenues from oil and gas F-7 THE WISER OIL COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) DECEMBER 31, 1996, 1995 AND 1994 production were reduced $6,923,000 as a result of hedging activities. The Company did not incur any material hedging gains or losses in 1995 or 1994. k. Foreign Currency Translation--The functional currency of Wiser Canada is the Canadian dollar. In accordance with SFAS No. 52, "Foreign Currency Translation", Wiser Canada's financial statements have been translated from Canadian dollars to U.S. dollars with the cumulative translation adjustment gain of $853,000 for 1996, $722,000 for 1995 and a loss of $696,000 for 1994 classified in Stockholders' Equity. 2. MARKETABLE SECURITIES During 1993, the Company adopted the accounting procedures as established by SFAS No. 115, "Accounting for Certain Investments in Debt and Equity Securities". Under SFAS No. 115, marketable securities, such as those owned by the Company, are classified as available-for-sale securities and are to be reported at market value, with unrealized gains and losses, net of income taxes, excluded from earnings and reported as a separate component of stockholders' equity. The market value of these securities at December 31, 1996, 1995 and 1994 were $7,176,000, $19,592,000 and $27,337,000 respectively. The Company liquidated a portion of its marketable securities portfolio and recognized a pretax gain of $12,977,000, $13,101,000 and $7,475,000 for 1996, 1995 and 1994 respectively. 3. LONG TERM DEBT On June 23, 1994, the Company entered into a Credit Agreement with NationsBank of Texas, N. A. as agent, which provides for a term loan to the Company's Canadian subsidiary and a revolving credit facility to the Company. The Credit Agreement provides the Company with up to a $150 million line of credit through September 30, 2000. The amounts available for borrowing are determined under formulas related to oil and gas reserves. The Company's borrowing base at December 31, 1996 was $80,000,000. The indebtedness outstanding under the Credit Agreement is secured by a pledge of 66% of the Company's ownership interests in its Canadian subsidiary (Wiser Canada). Available loan and interest options are base rate loans, at the bank's prime interest rate and one to six month term loans with fixed interest at either the LIBOR or CD rate plus 0.625%. The average interest rate during 1996 under the Credit Agreement was 6.04%. A 0.25% commitment fee is paid on the unused borrowing base. The Credit Agreement requires the Company to, among other things, maintain certain minimum net worth and current ratio requirements as well as certain restrictions on sales of assets, payment of dividends, incurrence of indebtedness and hedged transactions. On November 29, 1995, the Company entered into a credit agreement with NationsBank of Texas, N.A. as agent (the "Maljamar Credit Facility"). The Maljamar Credit Facility provides the Company with up to a $50 million nonrecourse facility to develop the expanded Maljamar project area. The amounts available for borrowing are determined under formulas related to oil and gas reserves and capital spent on the Maljamar area properties offset by net operating income from these same properties. The Company's borrowing base at December 31, 1996 was $40,000,000. Available loan and interest options are base rate loans, at the bank's prime interest rate and one to six month term loans with fixed interest at LIBOR plus 2.0%. The average interest rate during 1996 under the Maljamar Credit Facility was 7.51%. A 0.375% commitment fee is paid on the unused borrowing base. The Maljamar Credit Facility requires the Company to, among other things, maintain certain minimum collateral value requirements as well as certain restrictions on sales of assets, payment of dividends and incurrence of indebtedness. In addition, the credit agreement also requires the Company to hedge a portion of its crude oil production. The Company paid $4,971,000 in interest during 1996, $5,618,000 during 1995, and $3,889,000 during 1994. F-8 THE WISER OIL COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) DECEMBER 31, 1996, 1995 AND 1994 Long term debt consists of the following (000's):
DECEMBER 31, ------------------------ 1996 1995 1994 ------- ------- ------- Maljamar Credit Facility--7.63% and 7.94% interest rate at December 31, 1996 and 1995, respectively.... $20,654 $ 1,171 $ -- Credit Agreement--6.31%, 6.38% and 6.56% interest rate at December 31, 1996, 1995 and 1994, respectively ....................................... 58,000 73,000 78,000 Other, at 11.00%..................................... -- 20 91 ------- ------- ------- 78,654 74,191 78,091 Less current maturities.............................. -- (20) (78) ------- ------- ------- $78,654 $74,171 $78,013 ======= ======= =======
The annual requirements for reduction of principal of long term debt outstanding as of December 31, 1996 are estimated as follows (000's): 1997...................................... $ -- 1998...................................... 20,654 1999...................................... 7,998 2000...................................... 10,664 Thereafter................................ 39,338 ------- $78,654 =======
4. PROPERTY ACQUISITIONS AND SALES During 1995, the Company traded some of its Permian Basin properties for properties located mainly in New Mexico (The Skelly Unit) and West Virginia. The acquisition of these properties was accounted for as an exchange of similar assets. As a result of these trades, Wiser's total proved reserves as of December 31, 1995 increased by 5,846,000 BOE. On June 24, 1994, the Company acquired the Eagle Properties, which consist of certain oil and gas properties located in Alberta, Canada, for $52 million dollars. The purchase was funded through the Company's Credit Agreement, see Note 3, and with existing cash and cash equivalents. The purchase method of accounting was followed. Unaudited pro forma results of operations, as if the 1994 acquisition of the Eagle properties took place at January 1, 1994, are as follows (000's):
1994(1) ------- Revenues.................................. $63,888 Expenses.................................. 57,341 ------- Net Income................................ $ 6,547 ======= Earnings per share........................ $ .73 =======
- -------- (1) The pro forma results exclude the gain of $1.9 million of property sales recognized in 1994. F-9 THE WISER OIL COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) DECEMBER 31, 1996, 1995 AND 1994 5. INCOME TAXES The Company provides deferred income taxes for differences between the tax reporting basis and the financial reporting basis of assets and liabilities. The Company follows the accounting procedures as established by SFAS No. 109, "Accounting for Income Taxes". The Company paid $900,000 in 1996, $1,967,000 in 1995 and $0 income taxes in 1994. Income tax expense (benefit) for the three years ended December 31, 1996 were as follows (000's):
1996 1995 1994 ------ ------ ------- Current: Federal............................................. $1,911 $1,607 $ 1,473 State............................................... 105 150 116 ------ ------ ------- 2,016 1,757 1,589 ------ ------ ------- Deferred: Federal............................................. 1,919 1,934 1,085 State............................................... 137 97 107 Reversal of valuation allowance..................... -- -- (2,337) ------ ------ ------- 2,056 2,031 (1,145) ------ ------ ------- Total income tax expense.............................. $4,072 $3,788 $ 444 ====== ====== =======
A reconciliation of the statutory federal income tax rate to the Company's effective tax rate follows:
1996 1995 1994 ----- ----- ----- Statutory federal income tax rate....................... 34.0% 34.0% 34.0% Statutory depletion in excess of cost basis............. (2.0) (1.7) (2.2) Non-deductibility of foreign operating loss............. 22.6 55.4 8.6 Reversal of tax credit valuation allowance.............. -- -- (24.8) State taxes net of FIT benefits......................... 1.5 1.6 2.0 Dividends received credit............................... (1.2) (4.4) (3.8) Nonconventional fuels credit............................ (14.6) (22.4) (14.1) Other, net.............................................. (1.5) 0.8 5.0 ----- ----- ----- Effective tax rate...................................... 38.8% 63.3% 4.7% ===== ===== =====
F-10 THE WISER OIL COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) DECEMBER 31, 1996, 1995 AND 1994 The deferred tax liabilities and assets for the three years ended December 31, 1996 were as follows (000's):
1996 1995 1994 ------- ------- ------- Deferred tax liabilities (assets): Intangible drilling and development cost............. $12,998 $ 9,203 $ 7,052 Marketable securities valuation adjustment........... 2,229 6,015 8,241 Deferred pensions and compensation................... (579) (527) (520) Alternative minimum tax credit carry forwards........ (2,318) (2,429) (2,010) Property impairment reserve.......................... (1,767) (277) -- Excess property basis on Wiser Canada................ (4,051) (3,930) (3,978) Valuation allowance.................................. 4,600 4,479 3,978 Other................................................ (137) 165 239 ------- ------- ------- $10,975 $12,699 $13,002 ======= ======= =======
The Company will only realize the benefits of alternative minimum tax credit carryforwards by generating future regular tax liability in excess of alternative minimum tax liability. Prior to 1994, a valuation allowance was provided due to uncertainty of realizing these tax credits. Due to the Company's sale of a portion of its marketable securities portfolio during 1996, 1995 and 1994, and the Company's plans relating to its remaining marketable securities, the Company believes it is more likely than not that the alternative minimum tax credits will be fully realized. Accordingly, during 1994 the valuation allowance was reversed. As of December 31, 1996, a valuation allowance has been provided against Canadian net deferred tax assets of $4,051,000 and United States deferred tax assets of $549,000. 6. OIL AND GAS PRODUCING ACTIVITIES Set forth below is certain information regarding the aggregate capitalized costs of oil and gas properties and costs incurred in oil and gas property acquisitions, exploration and development activities (000's):
U.S. CANADA TOTAL --------- -------- --------- DECEMBER 31, 1996: Capitalization Costs: Proved properties............................ $ 226,411 $ 62,937 $ 289,348 Unproved properties.......................... 9,659 7,709 17,368 --------- -------- --------- 236,070 70,646 306,716 Accumulated depreciation, depletion and amortization................................. (100,016) (29,094) (129,110) --------- -------- --------- Net capitalized costs......................... $ 136,054 $ 41,552 $ 177,606 ========= ======== ========= Costs Incurred during 1996: Property acquisition......................... $ 1,782 $ 1,054 $ 2,836 Exploration.................................. 875 1,888 2,763 Development.................................. 33,994 6,230 40,224 Gas plants................................... 408 -- 408
F-11 THE WISER OIL COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) DECEMBER 31, 1996, 1995 AND 1994
U.S. CANADA TOTAL -------- -------- -------- DECEMBER 31, 1995: Capitalization Costs: Proved properties.............................. $191,567 $ 56,427 $247,994 Unproved properties............................ 10,110 7,588 17,698 -------- -------- -------- 201,677 64,015 265,692 Accumulated depreciation, depletion and amortization................................... (81,561) (16,766) (98,327) -------- -------- -------- Net capitalized costs........................... $120,116 $ 47,249 $167,365 ======== ======== ======== Costs Incurred during 1995: Property acquisition........................... $ 3,027 $ 3,210 $ 6,237 Exploration.................................... 2,753 2,270 5,023 Development.................................... 12,477 4,123 16,600 Gas plants..................................... 3,192 -- 3,192 DECEMBER 31, 1994: Capitalization Costs: Proved properties.............................. $183,978 $ 47,629 $231,607 Unproved properties............................ 11,427 7,122 18,549 -------- -------- -------- 195,405 54,751 250,156 Accumulated depreciation, depletion and amortization................................... (80,189) (3,555) (83,744) -------- -------- -------- Net capitalized costs........................... $115,216 $ 51,196 $166,412 ======== ======== ======== Costs Incurred during 1994: Property acquisition........................... $ 2,544 $ 52,988 $ 55,532 Exploration.................................... 2,036 2,057 4,093 Development.................................... 11,059 1,727 12,786 Gas plants..................................... 775 -- 775
7. EMPLOYEE PENSION PLAN The Company has a noncontributory defined benefit pension plan, which covers substantially all full-time employees. Plan participants become fully vested after five years of continuous service. The retirement benefit formula is based on the employee's earnings, length of service and age at retirement. Contributions required to fund plan benefits are determined according to the Projected Unit Credit Method. The assets of the plan are primarily invested in equity and debt securities. The net periodic pension costs were determined as follows (000's):
1996 1995 1994 ------- ------- ----- Current service cost................................... $ 381 $ 368 $ 362 Interest cost on projected benefit obligation.......... 824 802 779 Actual return on assets................................ 1,890 (1,575) (37) Net amortization and deferral.......................... (2,652) 932 (648) ------- ------- ----- Net periodic pension cost.............................. $ 443 $ 527 $ 456 ======= ======= =====
F-12 THE WISER OIL COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) DECEMBER 31, 1996, 1995 AND 1994 The principal assumptions for 1996, 1995 and 1994 utilized in computing pension expense include an 8.0% discount rate and a 5.0% rate of increase in compensation levels. The assumed rate of return on plan assets was 9% for 1996 and 8.5% for 1995 and 1994. An amendment to the pension plan, effective January 1, 1993, reduced the normal retirement age from 65 years to 62 years. The following table presents the actuarial valuation of the plan's funded status, as of December 31 (000's):
1996 1995 1994 ------ ------- ------- Actuarial present value of pension benefits obliga- tions: Vested............................................. $8,155 $ 9,817 $ 9,369 Nonvested.......................................... 415 354 172 ------ ------- ------- Accumulated........................................ 8,570 10,171 9,541 Projected salary increases......................... 751 705 1,069 ------ ------- ------- Projected benefits obligations..................... 9,321 10,876 10,610 Plan assets at fair value.......................... 8,010 10,247 9,315 ------ ------- ------- Plan assets less than projected benefits obligations....................................... $1,311 $ 629 $ 1,295 ====== ======= ======= Items not yet recognized: Unrecognized net gain.............................. $ 473 $ 1,169 $ 490 Unamortized transition amount...................... 121 208 241 Unamortized prior service cost..................... (957) (1,106) (1,254) ------ ------- ------- Net pension liability.............................. $ 948 $ 900 $ 772 ====== ======= =======
8. EMPLOYEE SAVINGS PLAN The Company has a qualified Savings Plan available to all employees. An employee may elect to have up to 15% of the employee's base monthly compensation, exclusive of other forms of special or extra compensation, withheld and placed in the Savings Plan account. On a monthly basis, the Company contributes to this account an amount equal to 50% of the employee's contribution, limited to 3% of the employee's base compensation. Company contributions to the Savings Plan were $126,000, $122,000 and $116,000, in 1996, 1995 and 1994, respectively. F-13 THE WISER OIL COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) DECEMBER 31, 1996, 1995 AND 1994 9. BUSINESS SEGMENT INFORMATION The Company operates in one industry segment, the exploration for and production of reserves of oil and gas, with sales made to domestic and Canadian energy customers. The following table summarizes the activity of the Company by geographic area for 1996, 1995 and 1994.
U.S. CANADA TOTAL -------- -------- -------- YEAR ENDED DECEMBER 31, 1996: Total revenues..................................... $ 69,595 $ 17,094 $ 86,689 Cost and expenses: Production and operating.......................... 20,288 3,682 23,970 Purchased natural gas............................. 1,462 -- 1,462 Exploration....................................... 1,837 2,339 4,176 Depreciation, depletion and amortization.......... 11,783 7,870 19,653 Property impairments.............................. 7,276 4,836 12,112 Other operating .................................. 9,475 5,341 14,816 -------- -------- -------- 52,121 24,068 76,189 -------- -------- -------- Pretax income (loss)............................... 17,474 (6,974) 10,500 Income tax expense................................. 4,072 -- 4,072 -------- -------- -------- Results of operations.............................. $ 13,402 $ (6,974) $ 6,428 ======== ======== ======== Identifiable assets................................ $161,687 $ 46,930 $208,617 ======== ======== ======== YEAR ENDED DECEMBER 31, 1995: Total revenues..................................... $ 57,839 $ 13,842 $ 71,681 Cost and expenses: Production and operating.......................... 17,555 3,135 20,690 Purchased natural gas............................. 727 -- 727 Abandonments...................................... 4,173 1,628 5,801 Exploration....................................... 11,418 8,360 19,778 Depreciation, depletion and amortization.......... -- 4,893 4,893 Other operating................................... 8,250 5,561 13,811 -------- -------- -------- 42,123 23,577 65,700 -------- -------- -------- Pretax income (loss)............................... 15,716 (9,735) 5,981 Income tax expense................................. 3,788 -- 3,788 -------- -------- -------- Results of operations.............................. $ 11,928 $ (9,735) $ 2,193 ======== ======== ======== Identifiable assets................................ $152,710 $50,034 $202,744 ======== ======== ========
F-14 THE WISER OIL COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) DECEMBER 31, 1996, 1995 AND 1994
U.S. CANADA TOTAL -------- ------- -------- YEAR ENDED DECEMBER 31, 1994: Total revenues...................................... $ 58,586 $ 6,770 $ 65,356 Cost and expenses: Production and operating........................... 20,598 1,715 22,313 Purchased natural gas.............................. 759 -- 759 Exploration........................................ 2,757 1,373 4,130 Depreciation, depletion and amortization........... 14,737 3,576 18,313 Other operating ................................... 7,921 2,488 10,409 -------- ------- -------- 46,772 9,152 55,924 -------- ------- -------- Pretax income (loss)................................ 11,814 (2,382) 9,432 Income tax expense.................................. 444 -- 444 -------- ------- -------- Results of operations............................... $ 11,370 $(2,382) $ 8,988 ======== ======= ======== Identifiable assets................................. $157,498 $54,075 $211,573 ======== ======= ========
Annually, four or five of the Company's purchasers of oil and natural gas individually account for 10% to 35% of gross revenues. In Canada, one purchaser accounts for approximately 75% of Wiser Canada's sales. However, due to the nature of the oil and natural gas industry, the Company is not dependent upon any of these purchasers. The loss of any major purchaser would not have a material adverse impact on the Company's business. 10. STOCK OPTION PLANS SFAS No. 123, "Accounting for Stock-Based Compensation," encourages but does not require companies to record compensation cost for stock-based employee compensation plans at fair value. During 1996, the Company adopted the disclosure provisions of SFAS No. 123. The Company continues to apply the accounting provisions of APB Opinion 25, "Accounting for Stock Issued to Employees," and related interpretations to account for stock-based compensation. Accordingly, compensation cost for stock options is measured as the excess, if any, of the quoted market price of the Company's stock at the date of the grant over the amount an employee must pay to acquire the stock. The Company has two stock option plans, the 1991 Stock Incentive Plan ("1991 Incentive Plan") and the 1991 Non-Employee Directors' Stock Option Plan ("1991 Directors' Plan"). The 1991 Incentive Plan provides for the issuance of ten year options with a variable vesting period and a grant price equal to fair market value. The 1991 Directors' Plan provides for the issuance of five year options with a six month vesting period and a grant price equal to or above market value. F-15 THE WISER OIL COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) DECEMBER 31, 1996, 1995 AND 1994 A summary of the status of the Company's two stock option plans at December 31, 1996, 1995 and 1994 and changes during the years then ended follows:
1996 1995 1994 ------------------ ------------------ ---------------- EXERCISE EXERCISE EXERCISE SHARES PRICE(1) SHARES PRICE(1) SHARES PRICE(1) -------- -------- -------- -------- ------- -------- Outstanding at beginning of year................ 254,500 $16.88 253,500 $17.20 95,750 $15.95 Granted................. 647,250 14.35 16,000 13.81 157,750 17.36 Exercised............... -- -- -- -- -- -- Expired and cancelled... (22,250) 16.88 (15,000) 17.36 -- -- -------- ------ -------- ------ ------- ------ Outstanding at end of year................... 879,500 $15.02 254,500 $16.88 253,500 $17.20 ======== ====== ======== ====== ======= ====== Exercisable at end of year................... 145,650 $16.47 56,725 $16.59 60,000 $16.70 ======== ====== ======== ====== ======= ====== Fair value of options granted(1)............. $ 4.30 $ 4.08 ======== ========
- -------- (1) Weighted average per option granted. 657,500 of the 879,500 options outstanding at December 31, 1996 have exercise prices between $11 and $15, with a weighted average exercise price of $14.35 and a weighted average remaining contractual life of 9.6 years. 14,500 of these options are exercisable with a weighted average exercise price of $13.70. The remaining 222,000 options have exercise prices betwen $15 and $19, with a weighted average exercise price of $17.02 and a weighted average contractual life of 6.6 years. 131,150 of these options are exercisable with a weighted average exercise price of $16.78. The fair value of each option grant is estimated on the date of grant using the Black-Scholes option pricing model with the following weighted-average assumptions used for grants in 1996 and 1995 for both the 1991 Incentive Plan and the 1991 Directors' Plan:
1996 1995 ----- ----- Risk free interest rate.................................... 6.36% 6.01% Expected dividend yields................................... .84% .87% Expected lives, in years................................... 4.85 5.00 Expected volatility........................................ 22.22% 22.05%
Had compensation cost been determined consistent with SFAS No. 123, the Company's net income and earnings per share would have been reduced to the following pro forma amounts:
1996 1995 ------ ------ Net income--as reported (000's)........................... $6,428 $2,193 Net income--pro forma (000's)............................. 5,576 2,179 Earnings per share--as reported........................... $ .72 $ .25 Earnings per share--pro forma............................. .62 .24
Because the SFAS No. 123 method of accounting has not been applied to options granted prior to January 1, 1995, the resulting pro forma compensation cost may not be representative of that to be expected in future years. 11. PREFERRED STOCK In addition to Common Stock, the Company is authorized to issue 300,000 shares of Preferred Stock with a par value of $10 per share, none of which has been issued. F-16 THE WISER OIL COMPANY SUPPLEMENTAL FINANCIAL INFORMATION FOR THE YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994 (UNAUDITED) The following pages include unaudited supplemental financial information as currently required by the Securities and Exchange Commission (SEC) and the Financial Accounting Standards Board. 12. OIL AND GAS RESERVES ESTIMATED QUANTITIES OF OIL AND GAS RESERVES (UNAUDITED) Proved reserves are the estimated quantities of crude oil, natural gas and natural gas liquids, which upon analysis of geological and engineering data appear with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are proved reserves which can be expected to be recovered through existing wells with existing equipment and under existing operating conditions. The estimation of reserves requires substantial judgment on the part of petroleum engineers and may result in imprecise determinations, particularly with respect to new discoveries. Accordingly, it is expected that the estimates of reserves will change as future production and development information becomes available and that revisions in these estimates could be significant. F-17 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, 1993..... 21,242 -- 21,242 103,317 -- 103,317 Revisions of previous estimates.................. 1,801 -- 1,801 (2,205) -- (2,205) Properties sold and abandoned.................. (1,513) -- (1,513) (7,031) -- (7,031) Reserves purchased in place...................... 97 3,666 3,763 314 21,395 21,709 Extensions, discoveries and other additions............ 343 71 414 1,488 1,249 2,737 Production.................. (1,957) (320) (2,277) (9,335) (1,272) (10,607) ------ ----- ------ ------- ------ ------- Balance December 31, 1994..... 20,013 3,417 23,430 86,548 21,372 107,920 Revisions of previous estimates.................. 4,322 563 4,885 4,912 (1,140) 3,772 Properties sold and abandoned.................. (187) -- (187) (333) -- (333) Reserves purchased in place...................... 5,825 307 6,132 695 1,132 1,827 Extensions, discoveries and other additions............ 124 157 281 2,046 6,354 8,400 Production.................. (1,657) (676) (2,333) (8,918) (2,753) (11,671) ------ ----- ------ ------- ------ ------- Balance December 31, 1995..... 28,440 3,768 32,208 84,950 24,965 109,915 Revisions of previous estimates.................. (301) (25) (326) 2,738 (535) 2,203 Properties sold and abandoned.................. (78) -- (78) (72) -- (72) Reserves purchased in place...................... 12 -- 12 17 505 522 Extensions, discoveries and other additions............ 2,040 533 2,573 10,787 1,705 12,492 Production.................. (2,033) (744) (2,777) (8,874) (2,809) (11,683) ------ ----- ------ ------- ------ ------- Balance December 31, 1996..... 28,080 3,532 31,612 89,546 23,831 113,377 ====== ===== ====== ======= ====== ======= Proved Developed Reserves: Balance, December 31, 1993.. 17,112 -- 17,112 96,069 -- 96,069 Balance, December 31, 1994 (1)........................ 15,950 3,209 19,159 84,715 13,655 98,370 Balance, December 31, 1995 (1)........................ 17,939 3,617 21,556 77,915 24,111 102,026 Balance, December 31, 1996 (1)........................ 24,892 3,225 28,117 80,652 22,477 103,129
- -------- (1) Canadian reserve volumes as assigned by third party engineers have been increased to reflect the effect of the Alberta Royalty Tax Credit refund. Total proved and proved developed reserves were increased by 364 MBbl and 2,323 MMcf for 1994, 397 MBbl and 2,744 MMcf for 1995 and 186 MBbl and 1,258 MMcf for 1996. STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS OF PROVED OIL AND GAS RESERVES (UNAUDITED) The Company has estimated the standardized measure of discounted future net cash flows and changes therein relating to proved oil and gas reserves in accordance with the standards established by SFAS No. 69, "Disclosure About Oil and Gas Producing Activities". The estimates of future cash inflows and future production and development costs are based on current year end sales prices for oil and gas, estimated future production of proved reserves and estimated future production and development costs of proved reserves based on current costs and economic conditions. This standardized measure of discounted future net cash flows is an attempt by the Financial Accounting Standards Board to provide the users of financial statements with information regarding future net cash flows from proved reserves. However, the users of these financial statements should use extreme caution in evaluating this information. The assumptions required to be used in these computations are subjective and arbitrary. Had other equally valid assumptions been used, significantly different results of discounted future net cash flows would result. Therefore, these estimates do not necessarily reflect the current value of the Company's proved reserves or the current value of discounted future net cash flows for the proved reserves. F-18 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, 1996: Future cash flows........................... $1,029,971 $116,203 $1,146,174 Future production and development costs..... (415,276) (25,175) (440,451) Future income tax expense................... (172,024) -- (172,024) ---------- -------- ---------- Future net cash flows....................... 442,671 91,028 533,699 10% Annual discount for estimated timing of cash flows................................. (187,332) (29,187) (216,519) ---------- -------- ---------- Standardized measure of discounted future net cash flows............................. $ 255,339 $ 61,841 $ 317,180 ========== ======== ========== December 31, 1995: Future cash flows........................... $ 679,754 $ 90,978 $ 770,732 Future production and development costs..... (343,867) (25,828) (369,695) Future income tax expense................... (74,433) -- (74,433) ---------- -------- ---------- Future net cash flows....................... 261,454 65,150 326,604 10% Annual discount for estimated timing of cash flows................................. (111,193) (20,809) (132,002) ---------- -------- ---------- Standardized measure of discounted future net cash flows............................. $ 150,261 $ 44,341 $ 194,602 ========== ======== ========== December 31, 1994: Future cash flows........................... $ 449,797 $ 79,208 $ 529,005 Future production and development costs..... (234,189) (22,040) (256,229) Future income tax expense................... (34,690) -- (34,690) ---------- -------- ---------- Future net cash flows....................... 180,918 57,168 238,086 10% Annual discount for estimated timing of cash flows................................. (77,178) (18,876) (96,054) ---------- -------- ---------- Standardized measure of discounted future net cash flows............................. $ 103,740 $ 38,292 $ 142,032 ========== ======== ========== The following are the sources of changes in the standardized measure of discounted net cash flows (000's): 1996 1995 1994 ---------- -------- ---------- Standardized measure, beginning of year...... $ 194,602 $142,032 $ 112,423 Sales, net of production costs............... (46,580) (32,907) (29,949) Net change in price and production cost...... 142,806 19,536 6,471 Reserves purchased in place.................. 581 26,087 46,169 Extensions, discoveries and improved recoveries.................................. 42,582 9,297 4,543 Change in future development cost............ 27,080 12,652 (14,265) Revision of previous quantity estimates and disposals................................... 314 26,525 5,080 Sales of reserves in place................... (987) (798) (9,562) Accretion of discount........................ 23,542 16,081 13,715 Changes in timing and other.................. (10,440) (1,863) 1,455 Net change in income taxes................... (56,320) (22,040) 5,952 ---------- -------- ---------- Standardized measure, end of year............ $ 317,180 $194,602 $ 142,032 ========== ======== ==========
F-19 13. QUARTERLY FINANCIAL DATA The supplementary financial data in the table below for each quarterly period within the years ended December 31, 1996 and 1995 are derived from the unaudited consolidated financial statements of the Company.
NET INCOME EARNINGS REVENUES (LOSS) (LOSS)PER SHARE -------- ------- --------------- (DOLLARS IN THOUSANDS, EXCEPT PER SHARE DATA) 1996: First.................................. $18,567 $ 1,511 $ .17 Second (1)............................. 21,363 (5,368) (.60) Third.................................. 19,468 2,444 .27 Fourth................................. 27,291 7,841 .88 1995: First.................................. $16,247 $1,238 $ .14 Second................................. 14,583 (720) (.08) Third.................................. 18,265 1,854 .21 Fourth................................. 22,586 (179) (.02)
- -------- (1) During the second quarter of 1996, the Company recognized an impairment write-down of oil and gas properties of $12,112,000 before income taxes. F-20 INDEX TO EXHIBITS
EXHIBIT NUMBER ------- (3.1) Certificate of Incorporation, as amended, incorporated by reference to Exhibit 4.2 to the Company's report on Form 8-K (Commission File No. 0-5426), dated November 9, 1993 (Date of Event: October 25, 1993). (3.2) Bylaws of the Company, as amended, incorporated by reference to Exhibit 4.3 to the Company's report on Form 8-K (Commission File No. 0-5426), dated November 9, 1993 (Date of Event: October 25, 1993). (4) Rights Agreement dated as of October 25, 1993 by and between the Company and The Chase Manhattan Bank (as successor to Chemical Bank), as Rights Agent, which includes as Exhibit 2 thereto the Form of Rights Certificate, incorporated by reference to Exhibit 4.1 to the Company's report on Form 8-K (Commission File No. 0-5426), dated November 9, 1993 (Date of Event: October 25, 1993). (10.1) Credit Agreement dated June 23, 1994 among The Wiser Oil Company and The Wiser Oil Company of Canada, as Borrowers, and Nations Bank of Texas, N.A., as Agent, and Certain Financial Institutions Listed on the Signature Pages Thereto, as Banks, incorporated by reference to the Exhibit 10.1 to the report on Form 8-K dated July 11, 1994 as amended August 17, 1994. (10.2) Credit Agreement dated November 29, 1995 among The Wiser Oil Company and Maljamar Development Partnership, L.P. as Borrowers, and Nations Bank of Texas, N.A., as Agent, and Certain Financial Institutions Listed on the Signature Pages thereto, as Banks. (10.3) Purchase and Sale Agreements made as of May 31, 1994 among Eagle Resources Ltd., Caneagle Resources Corporation, The Erin Mills Investment Corporation and The Wiser Oil Company, incorporated by reference to Exhibit 10 to the report on Form 8-K dated July 11, 1994 as amended August 17, 1994. (10.4)* Employment Agreement dated August 1, 1994 between the Company and Allen J. Simus, incorporated by reference to Exhibit 10(d) to the Company's Annual Report on Form 10-K for the year ended December 31, 1994. (10.5)* Employment Agreement dated July 1, 1991 between the Company and Andrew J. Shoup, Jr., incorporated by reference to Exhibit 10(a) to the Company's Annual Report on Form 10-K for the year ended December 31, 1993. (10.6)* The Wiser Oil Company 1991 Stock Incentive Plan, as amended, incorporated by reference to Exhibit 4.1 to the Company's Registration Statement on Form S-8 (Commission File No. 33-62441), filed on September 8, 1995. (10.7)* The Wiser Oil Company 1991 Non-employee Directors' Stock Option Plan, as amended, incorporated by reference to Exhibit 99.1 to the Company's Registration Statement on Form S-8 (Commission File No. 333-22525), filed on February 28, 1997. (10.8)* Employment Agreement dated November 1, 1993 between the Company and Lawrence J. Finn, incorporated by reference to Exhibit 10(b) to the Company's Annual Report on Form 10-K for the year ended December 31, 1993. (10.9)* Employment Agreement dated January 24, 1994 between the Company and A. Wayne Ritter, incorporated by reference to Exhibit 10(c) to the Company's Annual Report on Form 10-K for the year ended December 31, 1993. (10.10)*+ Employment Agreement dated September 30, 1996 between the Company and Kent E. Johnson. (10.11)*+ The Wiser Oil Company Equity Compensation Plan For Non-Employee Directors. (21)+ Subsidiaries of registrant (23.1)+ Consent of Independent Public Accountants (23.2)+ Consent of DeGolyer and MacNaughton, Independent Petroleum Engineers (23.3)+ Consent of Gilbert Lausten Jung Associates Ltd., Independent Petroleum Engineers (27)+ Financial Data Schedule
- -------- * The documents filed or incorporated by reference as Exhibits 10.4, 10.5, 10.6, 10.7, 10.8 and 10.9, 10.10 and 10.11 represent management compensatory plans or agreements. + Filed herewith EX-10.10 2 EXHIBIT 10.10 EXHIBIT 10.10 EMPLOYMENT AGREEMENT THIS EMPLOYMENT AGREEMENT, made as of the 30th day of September, 1996, by and between THE WISER OIL COMPANY, a Delaware corporation (the "Company"), and Kent E. Johnson, of 6907 Hickory Creek Lane, Dallas, Texas 75252 ("Employee"). W I T N E S S E T H: WHEREAS, the Company is an independent non-integrated company engaged in exploration, development, production and acquisition of crude oil and natural gas reserves in the United States; WHEREAS, Employee possesses valuable knowledge and skills that will contribute to the successful operation of the Company's business; and WHEREAS, the Company desires to procure the services of Employee, and Employee hereby agrees to be employed by the Company, upon the terms and subject to the conditions hereinafter set forth; NOW, THEREFORE, intending to be legally bound, the Company agrees to employ Employee, and Employee hereby agrees to be employed by the Company, upon the following terms and conditions: ARTICLE I EMPLOYMENT 1.01. Office. Employee is hereby employed as Vice President of ------ Exploration of the Company and in such capacity shall use his best energies and abilities in the performance of his duties hereunder and in the performance of such other duties as may be assigned to him from time to time by the Board of Directors of the Company (the "Board") and the Chief Executive Officer of the Company. 1.02. Term. Subject to the terms and provisions of Article II hereof, ---- Employee shall be employed by the Company for a period of two (2) years, commencing on the date of this Employment Agreement. 1.03. Base Salary. During the term of Employee's employment hereunder, ----------- compensation shall be paid to Employee by the Company at a rate of $160,000 per annum (the "Base Salary"), payable bi-weekly. The rate of compensation to be paid to Employee may be increased by the Board at any time based upon Employee's contribution to the success of the Company and on such other factors as the Board shall deem appropriate. 1.04. Employee Benefits. At all times during the term of Employee's ----------------- employment hereunder, Employee shall; (a) be covered by such major medical or health benefit plans and pensions and other employee benefit plans and other fringe benefits as are available generally to other executive employees of the Company; (b) receive reimbursement for all properly substantiated business expenses; and (c) be entitled to paid vacation each year and such holidays and sick days as are available to other executive employees of the Company. The compensation provided to Employee hereunder shall not affect his right to participate in the pension plan, the savings plan, and similar plans or any other employee benefit plans of Wiser if under the terms thereof Employee could be eligible without regard to this Agreement. 1.05. Change in Control. (a) If Employee's employment with the Company is ----------------- terminated by the Company or by Employee for any reason other than illness, disability or death of Employee within twelve months following a Change in Control of the Company, Employee shall be paid, within 30 days following such termination, an amount in cash equal to one year's Base Salary of the Employee at the time of his termination plus the value of one year of benefits provided to Employee by the Company in his capacity as an employee during the one year preceding his termination. (a) For purposes of this Section 1.05, the following terms shall have the following meanings: (1) The term "Person" shall be used as that term if used in Section 13(d) and 14(d) of the Securities Exchange Act of 1934 as amended (the "1934 Act"). (2) "Beneficial Ownership" shall be determined as provided in Rule 13d-3 under the 1934 Act as in effect on the effective date of this Agreement. (3) "Voting Shares" shall mean all securities of a company entitling the holders thereof to vote in an annual election of Directors (without consideration of the rights of any class of stock other than the Common Stock to elect Directors by a separate class vote); and a specified percentage of "Voting Power" of a company shall mean such number of the Voting Shares as shall enable the holders thereof to cast such percentage of all the votes which could be cast in an annual election of directors (without consideration of the rights of any class of stock other than the Common Stock to elect Directors by a separate class vote). (4) "Tender Offer" shall mean a tender offer or exchange offer to acquire securities of the Company (other than such an offer made by the Company or any subsidiary), whether or not such offer is approved by or opposed by the Board. (5) "Change in Control" shall mean the date upon which any of the following events occurs: (A) The Company acquires actual knowledge that any Person other than the Company, a subsidiary or any employee benefit plan(s) sponsored by the Company has acquired the Beneficial Ownership, directly or indirectly, of securities of the Company entitling such Person to 25% or more of the Voting Power of the Company. (B) A Tender Offer is made to acquire securities of the Company entitling the holders thereof to 50% or more of the Voting Power of the Company, or (ii) Voting Shares are first purchased pursuant to any other Tender Offer; (C) At any time less than 60% of the members of the Board shall be individuals who were either (i) Directors on the effective date of this Agreement or (ii) individuals whose election, or nomination for election, was approved by a vote (including a vote approving a merger or other agreement providing the membership of such individuals on the Board) of at least two-thirds of the Directors then still in office who where Directors on the effective date of this Agreement or who were so approved; (D) The stockholders of the Company shall approve an agreement or plan (a "Reorganization Agreement") providing for the Company to be merged, consolidated or otherwise combined with, or for all or substantially all its assets or stock to be acquired by, another corporation, as a consequence of which the former stockholders of the Company will own, immediately after such merger, consolidation, combination or acquisition, less than a majority of the Voting Power of such surviving or acquiring corporation or the parent thereof; or (E) The stockholders of the Company shall approve any liquidation of all or substantially all of the assets of the Company or any distribution to security holders of assets of the Company having a value equal to 30% or more of the total value of all the assets of the Company. (b) The Company agrees to pay the fees and expenses of counsel for Employee incurred by Employee arising in connection with Employee's enforcement or preservation of his right to collect the Change in Control payment described in Section 1.05(a). ARTICLE II TERMINATION 2.01. Illness, Disability. If during the term of Employee's employment ------------------- hereunder Employee shall be prevented, in the Company's judgment, from effectively performing all his duties hereunder by reason of illness or disability, then the Company may, by written notice to Employee, terminate Employee's employment hereunder. Upon delivery to Employee of such notice, together with payment of any salary accrued under Section 1.03 hereof, Employee's employment and all obligations of the Company under Article I hereof shall forthwith terminate. 2.02. Death. If Employee dies during the term of his employment ----- hereunder, Employee's employment hereunder shall terminate and all obligations of the Company hereunder, other than any obligations with respect to the payment of accrued and unpaid salary under Section 1.03 hereof, shall terminate. 2.03. Company Termination for Cause. If Wiser determines that Employee ----------------------------- has repeatedly failed to perform his duties hereunder after written notice of such failure from Wiser to Employee, has committed a violation of any of the agreements, covenants, terms or conditions hereunder or has engaged in conduct which has injured or would injure the business or reputation of Wiser or otherwise adversely affect its interests, then, and in such event, Wiser may, upon 30 days' prior written notice to Employee, terminate Employee's employment hereunder. Upon such termination, Employee shall be entitled to any Salary accrued under Section 1.03 hereof and any of Wiser's obligations under Article I hereof shall forthwith terminate. 2.04. Employee Benefits. Termination of Employee as provided in this ----------------- Article shall not affect Employee's rights and Employee benefit plans of Wiser if under the terms thereof Employee could be eligible without regard to this agreement. ARTICLE III EMPLOYEE'S COVENANTS AND AGREEMENTS 3.01. Non-Disclosure of Confidential Information. Employee agrees to hold ------------------------------------------ and safeguard Confidential Information in trust for the Company, its successors and assigns and agrees that he shall not, without the prior written consent of the Company, misappropriate or disclose or make available to anyone for use outside the Company's organization at any time, either during his employment with the Company or subsequent to the termination of his employment with the Company for any reason, including without limitation termination by the Company for cause, any of the Confidential Information, whether or not developed by Employee, except as required in the performance of Employee's duties to the Company or as otherwise required by order of Court. "Confidential Information" as used herein includes information concerning the Company's revenues, volume, business methods, proposals, identity of customers and prospective customers, identity of key purchasing personnel in the employ of customers and prospective customers, amount or kind of customer's purchases from the Company, location of reserves and information concerning geology, the Company sources of supply, vendors of equipment and material, the Company's computer programs, system documentation, special hardware, product hardware, related software development, the Company's manuals, formulae, processes, methods, machines, compositions, ideas, improvements, inventions or other confidential or proprietary information belonging to the Company or relating to the Company affairs. 3.02. Duties. Employee agrees to be a loyal employee of the Company. ------ Employee agrees to devote his best efforts full time (subject to the right to receive vacations and subject to absences on account of temporary illnesses as provided herein) to the performance of his duties for the Company, to give proper time and attention to furthering the Company's business, and to comply with all rules, regulations and instruments established or issued by the Company. Employee further agrees that during the term of this Agreement, Employee shall not, directly or indirectly, engage in any business or activity which would detract from Employee's ability to apply his best efforts to the performance of his duties hereunder. Employee also agrees that he shall not usurp any corporate opportunities of the Company. Employee agrees that during Employee's employment hereunder he shall not acquire for his own benefit, any oil and gas royalties or working interests. 3.03. Return of Materials. Upon the termination of Employee's employment ------------------- with the Company for any reason, including without limitation termination by the Company for cause, Employee shall promptly deliver to the Company all correspondence, drawings, blueprints, manuals, letters, memoranda, notes, notebooks, records, reports, flowcharts, programs, proposals and any documents concerning the Company's customers or concerning products or processes used by the Company and, without limiting the foregoing, will promptly deliver to the Company any and all other documents or materials containing or constituting Confidential Information. 3.04. Non-Solicitation of Employees. Employee agrees that, during his ----------------------------- employment with the Company and for two (2) years following termination of Employee's employment with the Company, including without limitation termination by the Company for cause, Employee shall not, directly or indirectly, solicit or induce, or attempt to solicit or induce, any employee of the Company to leave the Company for any reason whatsoever, or hire any employee of the Company. ARTICLE IV MISCELLANEOUS 4.01. Authorization to Modify Restrictions. It is the intention of the ------------------------------------ parties that the provisions of Article III hereof shall be enforceable to the fullest extent permissible under applicable law, but that the unenforceability (or modification to conform to such law) of any provision or provisions hereof shall not render unenforceable, or impair, the remainder thereof. If any provision or provisions hereof shall be deemed invalid or unenforceable, either in whole or in part, this Agreement shall be deemed amended to delete or modify, as necessary, the offending provision or provisions and to alter the bounds thereof in order to render it valid and enforceable. 4.02. Tolling Period. The non-solicitation obligation contained in -------------- Article III hereof shall be extended by the length of time during which Employee shall have been in breach of any of the provisions of such Article III. 4.03. Entire Agreement. This Agreement represents the entire agreement of ---------------- the parties and may be amended only by a writing signed by each of them. 4.04. Governing Law. This Agreement shall be governed by and construed in ------------- accordance with the laws of the State of Texas. 4.05. Agreement Binding. The obligations of employee under this Agreement ----------------- shall continue after the termination of his employment with the Company for any reason, and shall be binding on his heirs, executors, legal representatives and assigns and shall inure to the benefit of any successors and assigns of the Company. 4.06. Counterparts, Section Headings. This Agreement may be executed in ------------------------------ any number of counterparts, each of which shall be deemed to be an original, but all of which together shall constitute one and the same instrument. The section headings of this Agreement are for convenience of reference only and shall not affect the construction or interpretation of any of the provisions hereof. 4.07. Waiver. The failure of either party at any time or times to require ------ performance of any provisions hereof shall in no manner affect the right at a later time to enforce such provisions thereafter. No waiver by either party of the breach of any term or covenant contained in this Agreement, whether by conduct or otherwise, in any one or more instances, shall be deemed to be, or construed as, a further or continuing waiver of any such breach or a waiver of the breach of any other term or covenant contained in this Agreement. 4.08. Notices. All notices and other communications provided for herein ------- shall be in writing and shall be deemed to have been duly given if delivered personally or sent by registered or certified mail, return receipt requested, postage prepaid: (a) If to the Company: The Wiser Oil Company 8115 Preston Road Suite 400 Dallas, Texas 75225 (b) If to Employee: Kent E. Johnson 6907 Hickory Creek Lane Dallas, Texas 75252 Either party may specify a different address by notice in writing to the other as provided in this Section 4.08. IN WITNESS WHEREOF, the parties hereto have executed this Agreement or caused this Agreement to be executed as of the day and year first above written. /s/ Kent E. Johnson -------------------------------- Kent E. Johnson THE WISER OIL COMPANY /s/ Andrew J.Shoup, Jr. -------------------------------- Andrew J. Shoup, Jr. President EX-10.11 3 EXHIBIT 10.11 EXHIBIT 10.11 THE WISER OIL COMPANY EQUITY COMPENSATION PLAN FOR NON-EMPLOYEE DIRECTORS SECTION 1. ESTABLISHMENT AND PURPOSE. The Wiser Oil Company, a Delaware ------------------------- corporation (the "Company"), hereby establishes this Equity Compensation Plan for Non-Employee Directors (the "Plan"). The purposes of the Plan are to promote the long-term success of the Company by creating a long-term mutuality of interests between the non-employee directors and stockholders of the Company, to provide an additional inducement for such directors to remain with the Company and to provide a means through which the Company may attract able persons to serve as directors of the Company. SECTION 2. CERTAIN DEFINITIONS. For purposes of the Plan, the following ------------------- terms shall have the indicated meanings: (a) "Annual Retainer" shall have the meaning specified in Section 5(a) hereof. (b) "Change in Control" shall have the meaning specified in Section 6(b) hereof. (c) "Committee" means a committee appointed by the Board of Directors of the Company to administer the Plan and consisting of not less than two members of the Board of Directors. (d) "Common Stock" means the Common Stock, par value $3.00 per share, of the Company, or any stock or other securities of the Company hereafter issued or issuable in substitution or exchange for the Common Stock. (e) "Fair Market Value" of the Common Stock for any date as of which Fair Market Value is to be determined shall be the mean between the highest and lowest sales prices per share of the Common Stock on the New York Stock Exchange (or, if the Comomn Stock is not then listed or admitted to trading on the New York Stock Exchange, the principal national stock market on which the Common Stock is then listed or admitted to trading) for such date as quoted in the Wall Street Journal (or in such other reliable publication as the Committee, in its discretion, may determine to rely upon). If there are no such sale price quotations for the date as of which Fair Market Value is to be determined but there are such sale price quotations within a reasonable period both before and after such date, then Fair Market Value shall be determined by taking a weighted average of the means between the highest and lowest sales prices per share of the Common Stock as so quoted on the nearest date before and the nearest date after the date as of which Fair Market Value is to be determined. The average shall be weighted inversely by the respective numbers of trading days between the trading dates and the date as of which Fair Market Value is to be determined. If there are no such sale price quotations on or within a reasonable period both before and after the date as of which Fair Market Value is to be determined, then Fair Market Value of the Common Stock shall be the mean between the bona fide bid and asked prices per share of Common Stock as so quoted for such date, or if none, the weighted average of the means between such bona fide bid and asked prices on the nearest trading date before and the nearest trading date after the date as of which Fair Market Value is to be determined, if both such dates are within a reasonable period. The average is to be determined in the manner described above in this Section 2(d). If the Fair Market Value of the Common Stock cannot be determined on the basis set forth in this Section 2(d), the Committee shall in good faith determine the Fair Market Value of the Common Stock using such method as it deems appropriate. (f) "Non-Employee Director" means an individual duly elected or chosen as a director of the Company who is not also an officer or employee of the Company or any of its subsidiaries. (g) "Payment Date" shall have the meaning specified in Section 5(a) hereof. (h) "Phantom Share" means a right, issued pursuant to an election under Section 5(b) hereof and subject to the provisions of this Plan, to receive from the Company a share of Common Stock pursuant to and at the time specified in Section 6(a) hereof. (i) "Plan Year" means each 12-month period commencing on May 1 and ending on and including the next following April 30, commencing on May 1, 1996. SECTION 3. PLAN ADMINISTRATION. The Committee shall be responsible for ------------------- the administration of the Plan. The Committee shall keep records of action taken at its meetings. A majority of the Committee shall constitute a quorum at any meeting, and the acts of a majority of the members present at any meeting at which a quorum is present, or acts approved in writing by a majority of the Committee, shall be the acts of the Committee. The Committee shall interpret the Plan and prescribe such rules, regulations and procedures in connection with the operation of the Plan as it shall deem necessary and advisable for the administration of the Plan consistent with the purposes of the Plan. All questions of interpretation and application of the Plan, or as to Phantom Shares issued under the Plan, shall be subject to the determination of the Committee, which shall be final and binding. Notwithstanding the above, the Committee's authority to administer the Plan shall be limited by the express provisions hereof, including without limitation provisions specifying the persons eligible to receive Annual Retainers and to participate in the Plan and the percentages of Annual Retainers that may be used to obtain Phantom Shares, and the Committee shall not take any action inconsistent with the express provisions hereof. 2 SECTION 4. STOCK SUBJECT TO THE PLAN. ------------------------- (a) Number of Shares. An aggregate of twenty-five thousand (25,000) ---------------- shares of Common Stock are authorized for issuance in exchange for Phantom Shares in accordance with the provisions of the Plan. Shares of Common Stock that are issued under the Plan shall reduce the maximum number of shares of Common Stock remaining available for use under the Plan. Any shares of Common Stock issuable to a Non-Employee Director under the Plan that for any reason are not issued to the Non-Employee Director shall automatically become available for use under the Plan. The Company shall at all times during the term of the Plan retain as authorized and unissued Common Stock at least the number of shares from time to time required under the provisions of the Plan or otherwise assure itself of its ability to perform its obligations hereunder. Shares of Common Stock issued pursuant to the Plan may be shares of original issuance or treasury shares or a combination of the foregoing, as the Board of Directors, in its discretion, shall from time to time determine. (b) Adjustments Upon Changes in Common Stock. In the event the Company ---------------------------------------- shall effect a split of the Common Stock or a dividend payable in Common Stock, or in the event the outstanding Common Stock shall be combined into a smaller number of shares, (i) the maximum number of shares of Common Stock that may be issued under the Plan shall be increased or decreased proportionately and (ii) the Board of Directors shall make appropriate adjustments in the outstanding Phantom Shares that have been issued under the Plan. In the event of a reclassification of the Common Stock not covered by the foregoing, or in the event of a liquidation or reorganization (including a merger, consolidation or sale of assets) of the Company, the Board of Directors shall make such adjustments, if any, as it may deem appropriate in the outstanding Phantom Shares and the number and kind of shares that are authorized for issuance or are issuable pursuant to the Plan. SECTION 5. ISSUANCE OF PHANTOM SHARES. -------------------------- (a) Retainer. The amount of the retainer to be paid to each Non-Employee -------- Director for each Plan Year (the "Annual Retainer") shall be determined by the Board of Directors from time to time, and shall be paid on January 15 of each Plan Year or such other date as the Board of Directors may specify (the "Payment Date"); provided, however, that the Payment Date shall be at least six months after the last date on which Non-Employee Directors may make the election required by Section 5(b) for such Plan Year and (if other than January 15) shall be specified by the Board prior to such last election date. Each Non-Employee Director may elect, in accordance with Section 5(b), to receive his or her Annual Retainer (i) all in cash, (ii) all in Phantom Shares, or (iii) 50% in cash and 50% in Phantom Shares. The cash portion, if any, of a Non-Employee Director's Annual Retainer for each Plan Year shall be payable in a single lump 3 sum on the applicable Payment Date. The Phantom Shares, if any, that a Non- Employee Director elects to receive for each Plan Year will be credited as of the applicable Payment Date to an account established and maintained on the books of the Company to record the Non-Employee Director's interest under this Plan. The Non-Employee Director must be serving as a Non-Employee Director on the applicable Payment Date in order to earn the Annual Retainer for such Plan Year. (b) Elections. A Non-Employee Director must make the election contemplated --------- by Section 5(a) in writing to the Committee prior to the first day of the Plan Year for which the election is made. Notwithstanding the foregoing, a newly elected Non-Employee Director may make such an election within 10 days after the commencement of such Non-Employee Director's initial term of office as a director with respect to the Annual Retainer earned by him or her in the Plan Year of initial election. In no event, however, shall any Non-Employee Director be permitted to make such election less than six months before the next scheduled Payment Date. Unless otherwise determined by the Committee, a separate election must be made for each Plan Year. An election made pursuant to this Section 5(b) for a Plan Year shall be irrevocable from and after the first day of such Plan Year (or from and after the date the election is made in accordance with this Section, if later). Such elections shall be on forms prescribed for this purpose by the Committee. If a Non-Employee Director fails to make a required election for any Plan Year (including a failure occurring because a Non-Employee Director's initial term of office as a director begins less than six months before a scheduled Payment Date), he or she will be deemed to have elected to receive the Annual Retainer for such Plan Year all in cash, and such deemed election will be irrevocable from and after the date by which the election was required to have been made. (c) Phantom Share Accounts. Phantom Shares issued under this Plan shall be ---------------------- credited to an account maintained by the Company in the name of the recipient, which account shall reflect the number of Phantom Shares held, the date of issuance and such other information as the Committee deems necessary. Statements of account shall be provided to holders of Phantom Shares at such times as the Committee deems appropriate. Each holder shall have access to the information in his or her account upon request. Other than such reports, no stock certificates or other instruments shall be issued to evidence Phantom Shares. (d) Number Of Phantom Shares. On the Payment Date for the Annual Retainer ------------------------ for each Plan Year, the account maintained under this Plan for each Non-Employee Director who has elected to receive all or a portion of the Annual Retainer in Phantom Shares shall be credited with a number of Phantom Shares equal to (i) the dollar amount of the portion of the Annual Retainer payable in Phantom Shares pursuant to such election divided by (ii) the Fair Market Value of the Common Stock on such Payment Date, rounded downward to the nearest whole share. No fractional Phantom Shares shall be issued, and the value of any fractional shares that otherwise would be issuable shall be paid in cash on the applicable Payment Date. 4 (e) Rights of Holders. Each Phantom Share shall entitle the holder thereof ----------------- to receive (i) at the time specified in Section 6(a), one share of Common Stock, and (ii) payments in cash or other property equivalent to, and payable concurrently with, all dividends declared by the Board of Directors and payable in cash or other property to a holder of one outstanding share of Common Stock. Such rights shall vest immediately upon issuance of the Phantom Shares. Holders of Phantom Shares shall not have any voting or other rights as shareholders of the Company with respect to such Phantom Shares. Phantom Shares shall not be convertible into shares of Common Stock except in accordance with Section 6(a), and holders of Phantom Shares shall have no right to elect to receive cash or other property in lieu of such shares. (f) Nontransferability. Phantom Shares may not be sold, assigned, ------------------ transferred, pledged or otherwise encumbered by the holders thereof. SECTION 6. ISSUANCE OF COMMON STOCK. ------------------------ (a) Time of Issuance. Each Phantom Share shall automatically be ---------------- converted into one share of Common Stock, and such share of Common Stock shall be issued and delivered, in certificated form, to the holder thereof upon the earlier to occur of (i) the termination of such holder's service as a director of the Company for any reason (including without limitation death, resignation, retirement, failure to stand or to be nominated for reelection, or removal) or (ii) a Change in Control. Upon issuance of such shares of Common Stock, the Phantom Shares in respect of which such shares are issued shall be cancelled and the Non-Employee Director's account under this Plan shall be closed. In the event of the death of a Non-Employee Director, the shares of Common Stock issuable in respect of such Non-Employee Director's Phantom Shares shall be issued to the beneficiary previously designated in writing to the Committee by the Non-Employee Director or, if none has been designated, to his or her heirs or legal representatives in accordance with law. (b) Change in Control. For purposes of the Plan, a "Change in Control" ----------------- shall be deemed to have taken place upon the occurrence of any of the following: (i) The Company acquires actual knowledge that any Person other than the Company, a subsidiary of the Company or any employee benefit plan(s) sponsored by the Company has acquired the Beneficial Ownership, directly or indirectly, of securities of the Company entitling such Person to 25% or more of the Voting Power of the Company; (ii)(A) A Tender Offer is made to acquire securities of the Company entitling the holders thereof to 50% or more of the Voting Power of the Company; or (B) Voting Shares are first purchased pursuant to any other Tender Offer; 5 (iii) At any time less than 60% of the members of the Board of Directors shall be individuals who were either (A) directors on the effective date of the Plan or (B) individuals whose election, or nomination for election, was approved by a vote (including a vote approving a merger or other agreement providing for the membership of such individuals on the Board of Directors) of a least two-thirds of the directors then still in office who were directors on the effective date of the Plan or who were so approved; (iv) The stockholders of the Company shall approve an agreement or plan providing for the Company to be merged, consolidated or otherwise combined with, or for all or substantially all its assets or stock to be acquired by, another entity, as a consequence of which the former stockholders of the Company will own, immediately after such merger, consolidation, combination or acquisition, less than a majority of the Voting Power of such surviving or acquiring entity or the parent thereof; or (v) The stockholders of the Company shall approve any liquidation of all or substantially all of the assets of the Company or any distribution to security holders of assets of the Company having a value equal to 30% or more or the total value of all the assets of the Company. For purposes of this Section 6(b), the following terms shall have the following meanings: (1) The term "Person" shall be used as that term is used in Section 13(d) and 14(d) of the 1934 Act (and shall include a "group," as used therein). (2) "Beneficial Ownership" shall be determined as provided in Rule 13d-3 under the 1934 Act as in effect on the effective date of the Plan. (3) "Voting Shares" shall mean all securities of a company entitling the holders thereof to vote in an annual election of directors (without consideration of the rights of any class of stock other than the Common Stock to elect directors by a separate class vote); and a specified percentage of "Voting Power" of a company shall mean such number of the Voting Shares as shall enable the holders thereof to cast such percentage of all the votes which could be cast in an annual election of directors (without consideration of the rights of any class of stock other than the Common Stock to elect directors by a separate class vote). (4) "Tender Offer" shall mean a tender offer or exchange offer to acquire securities of the Company (other than such an offer made by the Company or any subsidiary), whether or not such offer is approved or opposed by the Board. 6 SECTION 7. PLAN AMENDMENT, MODIFICATION AND TERMINATION. The right to -------------------------------------------- amend the Plan at any time and from time to time and the right to terminate the Plan at any time are hereby specifically reserved to the Board of Directors; provided always that no such termination shall terminate any outstanding Phantom Shares; and provided further that no amendment of the Plan shall (a) be made without stockholder approval if the Company, on the advice of counsel, determines that stockholder approval is necessary or desirable or if stockholder approval of the amendment is at the time required for Phantom Shares and shares of Common Stock issuable under the Plan to qualify for the exemption from Section 16(b) of the 1934 Act provided by Rule l6b-3 or by the rules of the New York Stock Exchange or any other stock exchange or stock market on which the Common Stock may then be listed, or (b) cause Phantom Shares and shares of Common Stock issuable under the Plan not to qualify for the exemption provided by Rule l6b-3. No amendment or termination of the Plan shall, without the written consent of the holder of a Phantom Share theretofore issued under the Plan, adversely affect the rights of such holder with respect thereto. Notwithstanding anything contained in the preceding paragraph or any other provision of the Plan or any agreement, the Board shall have the power to amend the Plan in any manner deemed necessary or advisable for Phantom Shares and shares of Common Stock issuable under the Plan to qualify for the exemption provided by Rule l6b-3 (or any successor rule relating to exemption from Section 16(b) of the 1934 Act), and any such amendment shall, to the extent deemed necessary or advisable by the Board, be applicable to any outstanding Phantom Shares theretofore issued under the Plan. The Plan shall continue in effect until terminated by the Board of Directors. All Phantom Shares issued prior to any termination of the Plan that have not theretofore been converted into shares of Common Stock shall continue to be subject to the terms of the Plan. SECTION 8. PLAN EFFECTIVENESS. The Plan shall be submitted for approval ------------------ by the stockholders of the Company at the 1996 annual meeting of stockholders. The Plan shall become effective as of May 1, 1996 upon its approval by the holders of a majority of the shares of Common Stock present, or represented, and entitled to vote at such annual meeting. If the Plan is not so approved, the Plan shall terminate and all actions hereunder shall be null and void. SECTION 9. GENERAL PROVISIONS. ------------------ (a) No Continuing Right as Director. Neither the adoption or operation of ------------------------------- the Plan, nor the Plan itself or any document describing or relating to the Plan, shall confer upon any Non-Employee Director any right to continue as a director of the Company or interfere in any way with the rights of the shareholders of the Company or the Board of Directors to elect and remove directors. 7 (b) Nature of Phantom Shares. The Phantom Shares a Non-Employee Director ------------------------ elects to receive pursuant to this Plan represent an unfunded and unsecured promise to pay compensation in the form of money or other property in the future, and no provision of this Plan shall be deemed or construed to create a trust fund or security interest of any kind or to grant to a Non-Employee Director an actual interest in any share of Common Stock or other security. Any Phantom Shares credited by the Company to accounts maintained under this Plan are and for all purposes shall continue to be a part of the general unsecured liabilities of the Company, and to the extent that a Non-Employee Director, designated beneficiary, heir or legal representative acquires a right to receive money or other property from the Company pursuant to this Plan, such right shall be no greater than the right of any unsecured general creditor of the Company. (c) Binding Effect. The obligations of the Company under the Plan shall be -------------- binding upon any successor corporation or organization resulting from the merger, consolidation or other reorganization of the Company, or upon any successor corporation or organization succeeding to all or substantially all of the assets and business of the Company. The terms and conditions of the Plan shall be binding upon each Non-Employee Director and his or her heirs, legatees, distributee and legal representatives. (d) No Restriction of Corporate Action. Nothing contained in the Plan ---------------------------------- shall be construed to prevent the Company from taking any corporate action that is deemed by the Company to be appropriate or in its best interest, whether or not such action would have an adverse effect on the Plan or any Phantom Share issued or to be issued under the Plan, subject to the express provisions hereof. No Non-Employee Director or other person shall have any claim against the Company or any affiliate of the Company as a result of such action. (e) Governing Law. The provisions of the Plan, and all agreements ------------- hereunder, shall be governed by and construed in accordance with the laws of the State of Texas. (f) Registration, Listing and Compliance with Law. The obligation of the --------------------------------------------- Company to issue or deliver shares of Common Stock under the Plan shall be subject to (i) the effectiveness of a registration statement under the Securities Act of 1933, as amended, with respect to such shares, if deemed necessary or appropriate by counsel for the Company, (ii) the condition that the shares shall have been listed (or authorized for listing upon official notice of issuance) upon each stock exchange, if any, on which the Common Stock may then be listed and (iii) all other applicable laws, regulations, rules and orders which may then be in effect. 8 EX-21 4 EXHIBIT 21 EXHIBIT 21 SUBSIDIARIES OF THE WISER OIL COMPANY T.W.O.C., Inc. Maljamar Wiser, Inc. Wiser Oil Company of Canada Wiser Delaware LLC Maljamar Development Partnership, L.P. EX-23.1 5 EXHIBIT 23.1 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 18, 1997 appearing on page F-2 of this Annual Report on Form 10-K. /s/ ARTHUR ANDERSEN LLP Arthur Andersen LLP Dallas, Texas, February 18, 1997 EX-23.2 6 EXHIBIT 23.2 EXHIBIT 23.2 [DEGOLYER AND MACNAUGHTON LETTERHEAD APPEARS HERE] March 24, 1997 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, 1996, 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, 1996 on Certain Properties owned by the Wiser Oil Company--Proved Reserves" and "Appraisal Report as of December 31, 1996 on Certain Properties owned by Maljamar Wiser Inc." 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, 1996, 1995 and 1994 (unaudited)--Oil and Gas Reserves." Also included in the third section mentioned above are reserves estimates from our "Appraisal Report as of December 31, 1994 on Proved and Probable Reserves of Certain Properties owned by the Wiser Oil Company" and our "Appraisal Report as of December 31, 1995 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 abovementioned 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 EXHIBIT 23.3 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, 1997" 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 March 24, 1997 Calgary, Canada EX-27 8 FINANCIAL DATA SCHEDULE
5 THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE WISER OIL COMPANY CONSOLIDATED FINANCIAL STATEMENT AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS. 1,000 YEAR DEC-31-1996 JAN-01-1996 DEC-31-1996 5,870 7,176 14,091 0 1,289 21,723 311,690 131,972 208,617 18,230 78,654 0 0 27,347 71,915 208,617 72,012 86,689 25,432 70,737 0 0 5,452 10,500 4,072 6,428 0 0 0 6,428 .72 .72
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