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.
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.
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.
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
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.
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:
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
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.
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.
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
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.
OIL AND GAS RESERVES
The following table sets forth the proved developed and undeveloped reserves of the Company at December 31, 1996:
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:
- -------- (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."
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.
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.
- -------- (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."
PRODUCTIVE WELLS AND ACREAGE
Productive Wells
The following table sets forth the Company's domestic and Canadian productive wells at December 31, 1996:
- -------- (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.
- -------- (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.
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:
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.
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.
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
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
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.
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
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.
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.
"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.
(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.

ITEM 2. PROPERTIES
The information required by this Item is contained in Item 1. Business, and is incorporated herein by reference.
ITEM 3.

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.

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.

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:
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.
ITEM 6.

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.
(See footnotes on following pages)
- -------- (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.
(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.
ITEM 7.

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.
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.
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.
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.
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
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:
- -------- (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,
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.
ITEM 8.

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 through of this Report and are incorporated herein by reference.
ITEM 9.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURES
Not applicable.
PART III
ITEM 10.

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.

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.

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.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information required by this Item, if any, will be contained in the Proxy Statement under the heading "Executive Compensation" and is incorporated herein by reference.
PART IV
ITEM 14

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
- -------- * 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
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)
THE WISER OIL COMPANY
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
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
THE WISER OIL COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND RETAINED EARNINGS FOR THE YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994
The accompanying notes are an integral part of these financial statements.
THE WISER OIL COMPANY
CONSOLIDATED BALANCE SHEETS DECEMBER 31, 1996, 1995 AND 1994
The accompanying notes are an integral part of these financial statements.
THE WISER OIL COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994
The accompanying notes are an integral part of these financial statements.
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.
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:
- -------- (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
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.
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):
The annual requirements for reduction of principal of long term debt outstanding as of December 31, 1996 are estimated as follows (000's):
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):
- -------- (1) The pro forma results exclude the gain of $1.9 million of property sales recognized in 1994.
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):
A reconciliation of the statutory federal income tax rate to the Company's effective tax rate follows:
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):
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):
THE WISER OIL COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 1996, 1995 AND 1994
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):
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):
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.
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.
THE WISER OIL COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 1996, 1995 AND 1994
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.
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:
- -------- (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:
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:
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.
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.
Following is a reconciliation of the Company's estimated net quantities of proved oil and gas reserves, as estimated by independent petroleum consultants.
- -------- (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.
The following are the Company's estimated standardized measure of discounted future net cash flows from proved reserves (000's):
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.
- -------- (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.
INDEX TO EXHIBITS
- -------- * 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